8 - 2017 - Canadian Energy News, Top Headlines, Commentaries, Features & Events

National Energy Board to hold hearings on detailed Trans Mountain pipeline route

August 31, 2017 by The Canadian Press

VANCOUVER — The National Energy Board will hold hearings in British Columbia and Alberta to review proposals by Trans Mountain for its detailed pipeline corridor through the two provinces.

The board will also hold a hearing early next year in Chilliwack, B.C., to review a proposal by Trans Mountain to relocate nearly two kilometres of its pipeline corridor through the city.

Meanwhile, hearings will be held in Spruce Grove, Edson and Hinton in November and December on the first two segments of the pipeline through Alberta.

More hearings are also planned in both provinces in 2018.

The federal government’s approval of the expansion project included a general pipeline corridor from Edmonton to Burnaby, B.C.

The board says the company, a subsidiary of Kinder Morgan Canada, has asked for seven variances that affect about four kilometres of the 1,147-kilometre corridor.

The federal regulator says from April to July, it received 452 statements opposing the detailed route that Trans Mountain is proposing.

On Thursday, the energy board said the project has met conditions required for the expansion of its Westridge Marine Terminal in Burnaby.

Trans Mountain has plans to expand the terminal’s dock to load three tankers, up from one, and increase the number of delivery lines connected to its other Burnaby terminal.

The expanded terminal is part of a $7.4-billion project that would triple the capacity of the pipeline and increase tanker traffic in the Vancouver area.

Peter Watson, chairman and CEO of the National Energy Board, said the route hearings will focus on concerns from landowners and those affected by the pipeline.

“By listening to their concerns, the NEB can ensure that the pipeline is placed in the best possible location,” he said in a statement.

The Canadian Press

2024 National Coalition of Chiefs Energy And Natural Resource Summit

ATB declares Alberta recession over with expected growth of 3.2% this year

September 1, 2017August 31, 2017 by The Canadian Press

CALGARY — ATB Financial has declared Alberta’s worst recession in three decades over with expected economic growth of 3.2 per cent this year.

The provincially-owned bank warns, however, that challenges remain, especially in the energy sector where oil prices have been stuck around the break-even price of US$50 a barrel.

ATB’s financial outlook says the low oil price has led to only modest increases in drilling activity and hiring, while overall the oil and gas sector has at best stabilized this year and not yet returned as a growth engine.

The bank says smaller sectors like agriculture, food processing, tourism, retail and manufacturing are all contributing to modest growth, creating some of the 35,000 jobs added over the past year in a more diversified economy.

But it says those sectors don’t pay as well as oil and gas and that the public sector has driven more job growth.

Overall, ATB says attitudes remain cautious and it will likely be a few years before the province sees a full economic recovery.

The Canadian Press

Birchcliff Energy Ltd. Provides Dividend Rate Notice for Series A and B Preferred Shares

August 31, 2017 by The Canadian Press

FOR: BIRCHCLIFF ENERGY LTD.TSX SYMBOL: BIRDate issue: August 31, 2017Time in: 6:17 PM eAttention:
CALGARY, ALBERTA–(Marketwired – Aug. 31, 2017) – Birchcliff Energy Ltd.
(“Birchcliff”) (TSX:BIR) announces that it has notified the registered holder
of…

Suncor Energy to present at the Barclays CEO Energy-Power Conference 2017

August 31, 2017 by The Canadian Press

FOR: SUNCOR ENERGY INC.TSX SYMBOL: SUNYSE SYMBOL: SUDate issue: August 31, 2017Time in: 5:49 PM eAttention:
CALGARY, ALBERTA–(Marketwired – Aug. 31, 2017) – Steve Williams, president and
chief executive officer, will present at the Barclays CEO Energ…

Birchcliff Energy Ltd. Announces Closing of $100 Million Sale of Worsley Charlie Lake Light Oil Pool

August 31, 2017 by The Canadian Press

FOR: BIRCHCLIFF ENERGY LTD.TSX SYMBOL: BIRDate issue: August 31, 2017Time in: 2:37 PM eAttention:
CALGARY, ALBERTA–(Marketwired – Aug. 31, 2017) – Birchcliff Energy Ltd.
(“Birchcliff”) (TSX:BIR) is pleased to announce that it has closed its
previousl…

Precision Drilling Announces US$100,000 Pledge to U.S. Gulf Coast Relief Efforts and Provides U.S. Operational Update

September 1, 2017August 31, 2017 by The Canadian Press

FOR: PRECISION DRILLING CORPORATIONTSX SYMBOL: PDNYSE SYMBOL: PDSDate issue: August 31, 2017Time in: 2:34 PM eAttention:
CALGARY, ALBERTA–(Marketwired – Aug. 31, 2017) – Precision Drilling
Corporation (TSX:PD)(NYSE:PDS) (“Precision” or “The Company”)…

HELP HOUSTON: Want to Make a Donation to Help Hurricane Harvey Victims? See How HERE

August 31, 2017August 31, 2017 by EnergyNow Media

can As Hurricane Harvey continues to cause devastating flooding in Texas, tens of thousands of people could be driven from their homes. Donations to the Salvation Army and the Red Cross can help provide relief to those affected by the storm. The Better Business Bureau cautions against donating to unvetted campaigns raising disaster-relief funds. Relief … Read more

Houston Will Eventually Recover, But Will It Change? – Conor Sen

August 31, 2017 by EnergyNow Media

August 30, 2017 (Bloomberg View) As Houston continues to grapple with the devastation wrought by Hurricane Harvey, the immediate concern of course is saving lives. But as rainfall slowly draws to a close and attention shifts to recovery, the question needs to be asked: Can Houston simply resume the growth model that has driven it in … Read more

U.S. Gasoline at Two-Year High as Harvey Shuts Largest U.S. Refinery

August 31, 2017 by EnergyNow Media

August 30, 2017 (Bloomberg) Gasoline hit a new a two-year high as investors assess the impact of refinery outages and restarts as Harvey moves away from the Houston area. With the storm sliding farther inland over Southwestern Louisiana, Motiva Enterprises LLC’s Port Arthur refinery, the country’s biggest, began a controlled shutdown. The disruption helped send motor … Read more

Fracking Frenzy Shifts to Thrift as Canadian Producers Take a Step Back

August 31, 2017August 31, 2017 by EnergyNow Media

August 30, 2017 (Bloomberg) After starting the year at a torrid pace, the explorers of Canada’s shale riches are taking a step back, much like their peers in the Permian Basin south of the border. As oil’s rebound stalls and tight-rock operations in Alberta and British Columbia gush enough crude and natural gas to meet targets … Read more

Five Things World Business Will be Talking About Today

August 31, 2017 by EnergyNow Media

August 30, 2017 (Bloomberg) Blowout earnings for Chinese banks, a huge day of data, and it might be morning in America again. Here are some of the things people in markets are talking about. Chinese Banks Beat The four largest Chinese banks are poised for a big day after reporting better than expected second-quarter net income … Read more

Key US gasoline pipeline aims to carry more fuel by Sunday

August 31, 2017August 31, 2017 by The Canadian Press

ATLANTA — The operator of a major gasoline pipeline estimates it can resume carrying fuel in the Houston area by Sunday, potentially avoiding a lengthy shutdown that would intensify gasoline shortages.

The Colonial Pipeline provides nearly 40 per cent of the South’s gasoline. It runs underground and is now under water in many parts of Texas, where inspections are needed before it can be fully operational again, Colonial spokesman Steve Baker said Thursday.

The Georgia-based company remains able to operate its pipeline from Louisiana to states east and northeast of there, though deliveries will be “intermittent,” the company said.

Huge challenges remain for the nation’s system of getting gasoline to the pumps of service stations, since Hurricane Harvey forced the shutdown of at least eight Texas refineries, according to AAA.

Pump prices have surged — the average for a gallon of regular gasoline rose from about $2.35 a week ago to $2.45 now, AAA reported. The price spike is more dramatic in some states such as Georgia, where the average cost per gallon of regular gas has climbed from $2.22 a week ago to $2.39 now.

Nearly one-third of the nation’s refining capacity is along the Gulf Coast from Corpus Christi, Texas, to the Lake Charles, Louisiana area, and about one-quarter of the Gulf Coast’s oil refining capacity was taken offline, according to the Oil Price Information Service.

The supply crunch is already being felt in Dallas-Fort Worth, where QuikTrip, one of the nation’s largest convenience store chains, is temporarily halting gasoline sales at about half of its 135 stores in the area.

The company is instead directing gasoline deliveries to designated stores across all parts of the metro area, QuikTrip spokesman Mike Thornbrugh said. And while only half the Dallas-Forth Worth area stores will have gasoline, all will remain open, he said.

“Supply is way, way off,” Thornbrugh said Thursday.

The Oklahoma-based company diverted gasoline deliveries in a similar way last year in metro Atlanta, where it has about 133 stores, after the Alabama pipeline spill.

The Colonial Pipeline, a crucial artery in the nation’s fuel supply network, runs from the Houston area to New York harbour and includes more than 5,500 miles of pipeline, most of it underground. It closed in September 2016 after a leak and gas spill in Alabama, leading to days of empty gas station pumps and higher prices in Alabama, Georgia, Tennessee and the Carolinas.

Jeff Martin, The Associated Press

AltaGas Ltd. Provides Notice of Series C Shares Conversion Right and Announces Reset Dividend Rates

August 31, 2017 by The Canadian Press

FOR: ALTAGAS LTD.TSX SYMBOL: ALADate issue: August 31, 2017Time in: 11:52 AM eAttention:
CALGARY, ALBERTA–(Marketwired – Aug. 31, 2017) – AltaGas Ltd. (“AltaGas”)
(TSX:ALA) announced today that it does not intend to exercise its right to
redeem its c…

Enbridge Gas Distribution Announces Sale of St. Lawrence Gas Business

August 31, 2017 by The Canadian Press

FOR: ENBRIDGE GAS DISTRIBUTION INC.

Date issue: August 31, 2017
Time in: 8:00 AM e

Attention:

TORONTO, ONTARIO–(Marketwired – Aug. 31, 2017) – Enbridge Gas Distribution
Inc. (“Enbridge Gas Distribution”) announced today that it has entered into a
definitive agreement for the sale of St. Lawrence Gas Company, Inc. (“St.
Lawrence Gas”) and its subsidiaries to Liberty Utilities Co. (“Liberty
Utilities”), a wholly owned subsidiary of Algonquin Power & Utilities Corp.,
for a cash sale price of U.S. $70 million, minus total third-party debt of St.
Lawrence Gas at closing, and subject to customary working capital adjustments.
Closing of the transaction remains subject to certain required regulatory
approvals and other customary closing conditions, and is expected to occur in
2018.

“The sale of St. Lawrence Gas aligns with our strategic priorities and enhances
our competitiveness, while helping maintain a sustainable foundation upon which
we can deliver our long-term growth plans,” said Jim Sanders, president,
Enbridge Gas Distribution.

Employees, customers and suppliers of St. Lawrence Gas can expect business as
usual as Enbridge Gas Distribution works with Liberty Utilities to successfully
complete the transition of ownership.

St. Lawrence Gas operates and maintains 685 miles of natural gas distribution
pipeline in St. Lawrence, Lewis and Franklin counties in New York State, to
serve its 16,003 customers.

About Enbridge Gas Distribution Inc.
Enbridge Gas Distribution Inc. has a more than 165-year history and is Canada’s
largest natural gas distribution company. It is owned by Enbridge Inc., a
Canadian-based leader in energy transportation and distribution. Enbridge Gas
Distribution distributes natural gas to over two million customers in Ontario.

– END RELEASE – 31/08/2017

For further information:
Enbridge Gas Distribution Media
Toll Free: 1-855-884-5112
enbridgegasmedia@enbridge.com
OR
Investor Relations
Toll Free: 1-855-481-2804
investor.relations@enbridge.com

COMPANY:
FOR: ENBRIDGE GAS DISTRIBUTION INC.

INDUSTRY: Energy and Utilities – Oil and Gas
RELEASE ID: 20170831CC0008

Press Release from Marketwired 1-866-736-3779

All press releases are written by the client and have NO affiliation with the news copy written by The Canadian Press. Any questions that arise due to the content or information provided in the press release should be directed to the company/organization
issuing the release, not to The Canadian Press.

National Energy Board says Trans Mountain meets conditions for B.C. terminal

August 31, 2017August 30, 2017 by The Canadian Press

VANCOUVER — The National Energy Board says the Trans Mountain pipeline project has met conditions required for the expansion of its Westridge Marine Terminal in Burnaby, B.C.

Trans Mountain, a subsidiary of Kinder Morgan Canada, has plans to expand the terminal’s dock to load three tankers, up from one, and increase the number of delivery lines connected to its other Burnaby terminal.

The expanded terminal is part of a $7.4-billion project that would triple the capacity of an Alberta-to-B.C. pipeline and increase tanker traffic in the Vancouver area.

The board says in a letter to Kinder Morgan published on its website Wednesday that there are 157 conditions imposed on the project overall and the pre-construction conditions specifically pertaining to the terminal have now been satisfied.

Trans Mountain refiled its environmental protection plans for the terminal on Aug. 17, which the board said included details for mitigating previously raised issues about the project and evidence that it held additional public consultations.

Trans Mountain couldn’t immediately be reached for comment, but the company’s website says terminal construction was set to begin in September.

British Columbia’s NDP government recently announced it would join the legal fight against the pipeline expansion and was granted intervener status this week in a legal challenge brought by several First Nations and municipalities objecting to Ottawa’s approval of the project.

The new provincial government also warned the company earlier this month that it can’t begin work on public land until it gets final approval from the province.

Premier John Horgan promised in the provincial election this spring to use “every tool in the toolbox” to stop the expansion by Trans Mountain.

B.C.’s former Liberal government issued an environmental certificate for the project earlier this year.

B.C. Environment Minister George Heyman has said the storage facility and marine terminal in Burnaby are on private property, but the majority of the pipeline either passes through First Nations territory or public land.

The Canadian Press

Harvey knocks out more refineries, shifting global oil flows

August 31, 2017August 30, 2017 by The Canadian Press

DALLAS — Hurricane Harvey is sending pump prices higher for U.S. motorists and causing temporary shifts in the flow of oil and gasoline around the world after taking down a huge chunk of U.S. refining capacity.

It will be days or even weeks before the energy sector in the southeast Texas Gulf Coast is back to normal operations as it deals with flooding in the aftermath of Harvey, which has been downgraded to a tropical storm. The region from Corpus Christi, Texas, where Harvey made landfall, to the Louisiana state line accounts for about 3 per cent of the U.S. economy and is a crucial export market for oil and chemicals.

Wednesday brought news that the nation’s biggest refinery, which was already running below half-speed, had begun a complete shutdown. The Motiva Enterprises plant in Port Arthur, Texas, run by a unit of the state-owned oil company of Saudi Arabia, was the latest domino to fall among Gulf Coast refineries.

With that, gasoline futures headed higher for a third straight day. By afternoon, they had climbed 9 cents to $1.87 a gallon.

Retail prices climbed, too, up 2 cents on Wednesday and 7 cents in the past week, to a national average price of $2.42 per gallon, according to Gasbuddy.

“In terms of product price increases, it might get worse before it gets better,” said Rob Smith, an energy analyst with IHS Markit.

It could take two weeks or longer before big refineries in the Houston area can recover from a record-setting deluge and resume normal operations. That assumes they didn’t suffer serious damage, which is still unknown.

Harvey isn’t the first big storm to hit the refinery-rich Gulf Coast, but the oil industry has undergone big changes since the last major interruption from Hurricane Ike in 2008.

The so-called shale revolution has led to a surge in oil production in the U.S., increasing the nation’s exports of crude oil and gasoline to Mexico and other places in Latin America and diesel to Europe.

When the U.S. can’t produce enough gasoline or diesel to meet export demands, other regions are forced to look for replacement supplies “and the backfill has to come from further away,” said Richard Joswick, an analyst with S&P Global Platts. “It has to come from Asia even.”

The result will be higher prices, but it should be just a one- or two-week problem, Joswick said.

Patrick DeHaan, an analyst for GasBuddy, predicts that U.S. gasoline prices will top out around $2.50 or $2.55 a gallon, an increase of up to 20 cents since Harvey hit, with bigger spikes closer to the Gulf.

The recovery from Harvey will mimic the storm’s path from west to east. Flint Hill Resources’ refinery in Corpus Christi, where Harvey made landfall as a Category 4 hurricane, could begin to restart — a process that takes days — as early as Wednesday. Other refineries in the area are likely to do the same later this week.

“It takes some time to start up a refinery under normal circumstances, and it wouldn’t be surprising if they run into hiccups,” said Smith, the HIS Markit analyst. “It could be a week if not longer before Corpus Christi is at normal operations.”

Exxon, Shell and other companies have reported to Texas regulators that some of their storage tanks and other facilities near Houston were damaged by the torrential rains and flooding. Most of the reports seem to indicate relatively minor damage, but still it could be days before crews can assess matters and make repairs.

Even once the refineries are running, pipelines and ports are needed to carry their gasoline, diesel and other fuels to consumers.

A major pipeline supplying the East Coast with gasoline remains shut down — partly because with refineries closed, there is nothing to ship, but also because of damage in at least three areas. Another pipeline that carries crude from the big Permian Basin field in Texas to Houston-area refineries is also closed.

Other sectors are also slowly emerging from Harvey’s mess.

—INSURANCE: Damage estimates from wind, storm surges and flooding are soaring, with Moody’s Analytics putting them between $51 billion and $75 billion. RMS, a company that advises insurers, estimates the cost at $70 billion to $90 billion. TD Economics said Harvey will cut 0.1 to 0.4 points from U.S. third-quarter economic growth.

— SHIPPING: In a hopeful sign, port officials in Corpus Christi say that an initial check turned up some damage from Harvey’s landfall over the weekend, but they hope to restart shipping on Monday. First, however, the Coast Guard will have to declare the shipping lanes clear, and boat pilots will have to be satisfied it’s safe.

All four ports in the Houston area remain closed and aren’t likely to reopen for several days.

— TRAVEL: Houston Mayor Sylvester Turner said Houston’s two airports would resume limited service late Wednesday afternoon.

United Airlines planned to operate three departures and three arrivals Wednesday night at Bush Intercontinental Airport, a spokesman said. Other carriers, such as American Airlines, planned to wait until Thursday. Southwest Airlines is the main carrier at Hobby Airport.

More than 1,600 U.S. flights had been cancelled by afternoon, most of them at the Houston airports, according to tracking service FlightAware.

David Koenig, The Associated Press

RPS-PEICE Save 15% on upcoming Petroleum Engineering for Non-Engineers (2 Day) Course With Saad Ibrahim

September 4, 2017August 30, 2017 by EnergyNow Media

Increase your skills by joining RPS-PEICE 2 day Petroleum Engineering for Non-Engineers September 6-7 in Calgary. This course will be taught by Saad Ibrahim who has designed the course to provide non-engineering petroleum industry technical and non-technical professionals with a thorough overview of most key aspects of petroleum engineering technology and its applications. The course … Read more

Canadian-owned refineries expected to register higher profits amid Gulf Coast disruption

August 31, 2017August 30, 2017 by The Canadian Press

CALGARY — Canadian-owned refineries are expected to register higher profits as more U.S. Gulf Coast facilities are shut down due to ongoing extensive flooding from what’s left of Hurricane Harvey.

And some analysts say refinery outages in Texas that have already sparked higher gasoline prices in the United States and Canada will likely continue to affect North American fuel markets for months.

“Gasoline prices moving higher, it does help all of the refiners,” said Randy Ollenberger, managing director of oil and gas equity research for BMO Capital Markets in Calgary.

“Cenovus and Husky, because they have Midwest refining assets — as does Suncor in Denver — they’ll probably see more of the strength in product prices than we’ll see in Ontario or Alberta (refineries).”

According to a report from AltaCorp Capital in Calgary, mid-continent refining profit margins have jumped by about 20 per cent this week, a development it said will boost the bottom lines of Calgary-based Husky (TSX:HSE) and Cenovus (TSX:CVE).

Husky owns one refinery and partners with BP in another in Ohio, while Cenovus owns a 50 per cent stake in Phillips 66 refineries in Illinois and northern Texas. All are well removed from Harvey’s path.

AltaCorp analyst Nick Lupick said Canadian refinery product pricing is up slightly “but nothing compared to what we have seen in the U.S.”

Ollenberger said the situation is more complicated for Canadian oil producers. The storm is preventing ocean tankers from delivering competing loads of imported foreign crudes in Houston but it is also interfering with some of the 400,000 barrels of Canadian crude normally delivered daily to the Gulf Coast, about 11 per cent of Canada’s total oil exports.

That could translate into more oil going into storage in the U.S. Midwest, which could mean temporarily lower prices.

On Wednesday, Calgary-based Encana (TSX:ECA) reported it has restarted production and drilling at its Eagle Ford oil fields in southern Texas. It shut them down last Friday as a precautionary measure.

“Our Eagle Ford assets did not incur any damage. We were well prepared for the hurricane and successfully limited any impacts to four days between Friday and Monday,” said spokesman Jay Averill.

Research director Jackie Forrest of ARC Financial in Calgary said she expects Harvey’s effect on the gasoline market could match that of Katrina 12 years ago and result in higher fuel prices in the U.S. and Canada that last well into November.

“Katrina did cause prices across the continent to increase, not just in the Gulf Coast … Those elevated gasoline prices did stick around for almost three months until those refineries were back on line,” she said.

IHS Markit says about 30 per cent of U.S. Gulf of Mexico refinery output is expected to be idled as the storm makes its way eastward toward the Port Arthur/Lake Charles refining hub on the Texas-Louisiana border.

Follow @HealingSlowly on Twitter.

The Canadian Press

Texas Refiners Spared by Harvey Now Sweat Storm’s Second Round

August 30, 2017August 30, 2017 by EnergyNow Media

Aug 29, 2017 (Bloomberg) Just as refiners in South Texas are starting to recover from Harvey, forecasters have the storm gearing up for a second landfall in an area further east that includes the nation’s largest refinery. As the storm moves toward the Texas-Louisiana border from its present location over the Gulf of Mexico, Motiva Enterprises … Read more

Five Things World Business Will be Talking About Today

August 30, 2017 by EnergyNow Media

Aug 30, 2017 (Bloomberg) Harvey damages rise by the hour, Kim issues missile warning, and the euro might be getting too strong for Draghi. Here are some of the things people in markets are talking about today. Apocalyptic flooding Analysts are struggling to keep their estimates of the damage from Harvey up to date as the effects … Read more

Help Your First Line Maintenance Supervisor Improve Productivity – T.A. Cook

September 25, 2017August 29, 2017 by EnergyNow Media

Mark Rigdon, Manager, CMRP T.A. Cook Consultants, Inc. Often, the Front Line Supervisor (FLS) has to walk a tightrope when it comes to productivity. He is responsible for completing work according to schedule, but the organizational structure he needs to be successful is rarely in place. Roles and responsibilities can be blurred and often, FLS’ … Read more

Court rules B.C. will have intervener status in Trans Mountain pipeline case

August 30, 2017August 29, 2017 by The Canadian Press

OTTAWA — The Federal Court of Appeal is allowing British Columbia to be an intervener in a legal fight against the Trans Mountain pipeline expansion, but with some conditions.

Several First Nations and municipalities filed legal challenges against Ottawa’s approval of the $7.4-billion project that would triple the capacity of the Alberta-to-B.C. pipeline and increase tanker traffic from the Vancouver area to the south portion of Vancouver Island.

B.C.’s new NDP government, which has been opposed to the project, applied to be an intervener on Aug. 22, missing the initial deadline of April 13 that fell before the May provincial election.

Justice David Stratas said in the ruling that while B.C.’s involvement in the case comes late, the hearings set for Oct. 2 to 13 will go ahead as scheduled.

That means the province must meet the same Sept. 1 deadline to submit a 15-page document of facts that the Alberta government, which is also an intervener, has had months to prepare.

B.C.’s Environment Minister George Heyman says the government welcomes the decision that will allow officials to represent the province’s interests in court.

“We will continue to defend B.C.’s coast and the economic and environmental interests that are so important to British Columbians,” he says in a news release.

The court has prohibited B.C. from introducing new issues or evidence at the hearing and ruled the province must pay $7,500 to Trans Mountain, a subsidiary of Kinder Morgan Canada, for having to prepare a late response to the arguments.

The Canadian Press

Tribes say Dakota Access pipeline overstates shutdown impact

August 29, 2017August 29, 2017 by The Canadian Press

BISMARCK, N.D. — American Indian tribes hoping to persuade a federal judge to turn off the Dakota Access oil pipeline maintain in last-minute court filings that the project’s developer has overstated the potential impacts of a shutdown.

Standing Rock Sioux attorney Jan Hasselman and Cheyenne River Sioux attorney Nicole Ducheneaux also argue that Texas-based Energy Transfer Partners brought potential problems on itself by forging ahead with construction despite the uncertainty of final federal approval.

ETP “made reckless choices, and it must accept the consequences,” the attorneys wrote in documents filed Monday, the deadline for arguments imposed by U.S. District Judge James Boasberg in Washington, D.C.

The $3.8 billion pipeline began moving North Dakota oil through South Dakota and Iowa to Illinois on June 1, after President Donald Trump pushed for its completion. The Army Corps of Engineers, which permitted the project, had decided to do more environmental study, but dropped that plan after Trump took office.

The judge ruled in June that the Corps didn’t adequately consider how an oil spill under Lake Oahe in the Dakotas might affect the Standing Rock Sioux, one of four tribes that have challenged the pipeline in court. He ordered the Corps to reconsider certain areas of its environmental analysis, and could decide to shut down the 1,200-mile pipeline while this work is done over the next several months.

ETP has maintained in court documents that a shutdown would cost it $90 million monthly, and significantly disrupt the broader energy industry as well as state and local government tax revenue.

“There is no legitimate basis for arguing that suspending DAPL will cause havoc,” Hasselman and Ducheneaux wrote. “Suspension of DAPL undoubtedly will have some impacts, but they will be more modest and manageable than DAPL contends.”

Company spokeswoman Vicki Granado on Monday declined comment, citing the ongoing litigation.

Some energy trade groups including The American Petroleum Institute, which the judge on Monday granted a say in the dispute, said a shutdown “would result in substantial financial loss and uncertainty for upstream producers, shippers, downstream refiners, manufacturers, retailers and consumers.”

The amount of oil being shipped through the pipeline each day is worth more than $20 million, and “if DAPL were to be taken out of service for even six months, the direct financial impact of the stalled crude deliveries would be staggering,” attorney David Coburn wrote.

The tribal attorneys question the seriousness of a shutdown impact, noting that the pipeline has been operating only a short time but that Energy Transfer Partners “claimed that the oil industry is already dependent on its continued operation.”

“One can only imagine the arguments that DAPL would try to make if operations continued for an extended period,” they said.

___

Follow Blake Nicholson on Twitter at: http://twitter.com/NicholsonBlake

Blake Nicholson, The Associated Press

North Dakota tribe levies higher tax on oil drillers

August 29, 2017 by The Canadian Press

BISMARCK, N.D. — An American Indian tribe whose reservation accounts for a fifth of North Dakota’s oil production has imposed a higher tax rate for drillers, a move the governor and the state tax commissioner believes is improper and industry officials fear may slash production.

The Three Affiliated Tribes this month notified the more than 30 companies drilling on the Fort Berthold Reservation that it is seeking the tax rate that tribal Chairman Mark Fox says it needs to pay for additional law enforcement, road repairs and other consequences of oil development on the reservation. It’s home to the Mandan, Hidatsa and Arikara tribes.

Taxe Commissioner Ryan Rauschenberger responded with a letter to the companies saying the state has nothing to do with the increase, which he said is “inconsistent with current state law.”

Gov. Doug Burgum also called the move “inconsistent” with a tax accord between the state and the tribes. He said the dispute creates regulatory uncertainty that has the potential t “quell or squash investment” in the state.

Burgum is schedule to meet with legislative and tribal leaders Thursday at the Capitol to discuss the matter, along with others that face tribes across the state under a newly formed Tribal Taxation Issues Committee.

The Three Affiliated Tribes and the state have long been at odds over shared tax revenue from drilling on the oil-rich reservation in western North Dakota. It accounts for about 20 per cent of the state’s 1 million barrel-per-day oil production.

The agreement between the tribes and the state was authorized by the 2007 Legislature after oil companies said it would help promote reservation investment by setting up stable tax rates and rules. Before the agreement, only one well was drilled on the reservation, state and tribal data show. That’s grown to more than 1,600 wells since the agreement was signed.

Tax Department data show that since the agreement was adopted, the state has collected more than $1 billion in oil revenue, with the tribe getting $934 million. The state’s share of oil taxes from reservation land is divided among counties, cities, school districts and several state funds and programs.

Two years ago, the Legislature passed a measure that abolishes some price-based incentives in exchange for lowering the overall tax rate from 11.5 per cent to 10 per cent, including from wells on the reservation.

Fox said it never agreed to the change and the tribe still wants its share, which is half of the 1.5 per cent rate that was forgiven by lawmakers. He estimated the sum to be about $17 million.

“Our expectation is for them to pay what is due under the mutual tax agreement with the state,” Fox told The Associated Press.

North Dakota Petroleum Council President Ron Ness said an increased tax rate on the reservation creates uncertainty, increases costs and discourages investment — all of which hampers drilling.

“We certainly do not want dual taxation,” Ness said.

Denver-based Whiting Petroleum Corp., which historically has been North Dakota’s top oil producer, announced this month that it is selling all its holdings within the reservation for $500 million, and will use the profits from the deal to repay bank debt.

Neither Ness nor the company would comment on whether the tribe’s desire to collect more taxes had anything to do with the sale.

Fox, who is an attorney and a former Marine, said the tribes would work with companies on the additional tax collections.

“We just want to get paid what is owed the tribe,” Fox said.

He doesn’t expect companies to leave the reservation, which is considered one of the hottest drilling spots in North Dakota’s oil patch.

“If they leave, that’s going to be their choice,” Fox said. “If they do, the oil is still in the ground.”

James MacPherson, The Associated Press

United Conservative candidate urges Alberta buy Churchill port for oil sales

August 29, 2017August 29, 2017 by The Canadian Press

EDMONTON — A candidate to lead Alberta’s new United Conservative Party says one way to jump-start the province’s lagging oil industry may be to buy a piece of Manitoba.

Jeff Callaway says the province should look at buying the port of Churchill on Hudson Bay and shipping oil there by pipeline.

“This has so many benefits not just for Alberta, but for Western Canada and Canada broadly,” Callaway said at the legislature Tuesday.

He says tankers in Churchill could carry oil abroad and fetch a better price for Alberta, which has been running multibillion-dollar deficits in recent years.

“It’s a small, small investment to make for prosperity in Western Canada.”

The province would have to buy the port from its private owners, fix the railway going to it and build a pipeline as well, he said.

A road would also have to be built to the remote community, Callaway added.

Spring floods washed out the rail line to Churchill and the owner of the port, Denver-based Omnitrax, has suspended operations at the grain terminal and is looking to sell.

Omnitrax also owns the rail line and has stated it isn’t interested in putting up the $20 million to $60 million needed to repair the track.

Callaway is also promising to end Alberta’s current tax on carbon for home and business owners if he becomes the United Conservative leader.

The levy is used to fund green projects ranging from household devices to large-scale infrastructure such as rapid transit.

The Canadian Press

Harvey threatens more U.S. oil refineries after heavy rains

August 29, 2017 by EnergyNow Media

August 29, 2017 Reuters HOUSTON (Reuters) – Heavy rains and flooding from Tropical Storm Harvey threatened more oil refineries along the Louisiana coast after hammering plants in Texas, forcing Exxon Mobil Corp and Citgo Petroleum to consider shutdowns. The storm dropped back over the Gulf of Mexico on Monday, sending heavy rains from Houston through to … Read more

Five Things World Business Will be Talking About Today

August 29, 2017 by EnergyNow Media

August 29, 2017 (Bloomberg) North Korean missile launch rattles markets, Harvey’s effects are far from over, and Brexit talks didn’t get off to the best start. Here are some of the things people in markets are talking about today. Missile launchGeopolitical tensions were rekindled after North Korea launched a missile that flew over Japan before crashing into … Read more

Crude Gives Up Gains as Traders Assess Supply Position from Harvey

August 30, 2017August 29, 2017 by EnergyNow Media

August 29, 2017 (Bloomberg) U.S. gasoline prices fell after five consecutive days of gains and crude traded below $47 a barrel as traders assess the risk to refineries and supply following flooding from Tropical Storm Harvey. Motor fuel prices fell 0.7 percent in New York, while crude futures slipped from the lowest closing level in five … Read more

Craig’s Corner – Equipment Valuation and Utilization

September 4, 2017August 29, 2017 by EnergyNow Media

One of the biggest hurdles I find in Oil & Gas Insurance is Equipment Valuations in this economy. Business owners all ask the same question… “What’s the machinery and equipment really worth?” Is there goodwill? Do only the tangible assets of the business have value? What if I am not using the equipment right now? … Read more

Fraser Institute News Release: Political and policy uncertainty in B.C. threatens investment and economic prosperity

August 29, 2017August 29, 2017 by The Canadian Press

Pacific Northwest LNG mega-project not going ahead

FOR: THE FRASER INSTITUTE
Date issue: August 29, 2017Time in: 8:00 AM eAttention:
VANCOUVER, BC –(Marketwired – August 29, 2017) – The tenuous nature of the
recent election in British Columbia has increased political and policy
uncertainty to the hi…

Canadian gasoline future prices jump in Harvey’s wake due to refinery disruptions

August 29, 2017August 28, 2017 by The Canadian Press

CALGARY — Canadian gasoline prices are expected to rise this week after widespread flooding from tropical storm Harvey forced many refineries on the Texas Gulf Coast to shut down.

Wholesale gasoline prices in the country will likely rise by an average of two to four cents per litre by Thursday, said GasBuddy senior petroleum analyst Dan McTeague, but consumers in certain markets could see much higher price increases.

McTeague explained that retail operators in markets like Calgary, Montreal and Ottawa are barely breaking even now and could use the wholesale price increase as an excuse to raise prices by as much as another 10 cents per litre to boost profit margins.

“Traders are taking a wait and see approach and I think that’s really why you’re going to see very little, for now at least, in the way of any major spikes until at least Thursday or Friday,” he said.

Canadian gasoline prices shown on the GasBuddy.com website were little changed on Monday.

U.S. prices are expected to spike over the next week or more as about 10 refineries representing more than 15 per cent of the nation’s refining capacity are closed, including ExxonMobil, Shell and Phillips 66 operations.

When water recedes, prices will fall more slowly than after other storms that hit the refinery-rich Gulf Coast, like Hurricane Ike in 2008, said Rick Joswick, an analyst with S&P Global Platts’ PIRA Energy.

Nearly three billion barrels of the 18 billion U.S. daily refining capacity had been knocked out. Most of the shut-downs have been precautionary, with only a few reports of minor flooding.

But the slow-moving nature of the storm means it could cause shutdowns to linger and leave more-lasting damage, said Goldman Sachs analyst Damien Courvalin.

“The damage could worsen if continued rains extend the flooding,” agreed BMO Capital Markets economist Sal Guatieri.

Meanwhile, Canadian companies with assets in the Gulf Coast area joined their American counterparts in closing offices and hunkering down to wait out the storm.

Precision Drilling (TSX:PD) CEO Kevin Neveu, who splits his time between Alberta and Texas, said his house in the Houston suburbs is dry so far but flooding has damaged the homes of at least five of his company’s 300 Houston-area employees.

“Our number one priority right now is make sure our employees are safe and sound and their houses aren’t damaged,” he said from Precision’s Calgary headquarters.

“Number two priority is to watch the civil infrastructure and see how that responds. When the streets are safe and the power is up and running and gasoline is available, that’s when we’ll expect people to start coming back to work.”

He said Precision’s main Houston offices and three field support operations are closed but 10 drilling rigs in the “rain zone” along the Gulf Coast are continuing to operate.

Calgary-based producer Baytex Energy (TSX:BTE) announced it had suspended production (averaging about 37,000 barrels of oil equivalent per day) and exploration on its Texas Eagle Ford operations and closed its Houston office.

It said the moves were made to safeguard employees and because the markets it normally supplies with oil are closed or curtailed. It added it will restart operations gradually as market access improves.

Calgary-based pipeline company Enbridge (TSX:ENB), which bought Houston-headquartered Spectra Energy earlier this year, said Monday it had closed its Houston offices and has removed all but essential staff from its natural gas gathering and processing facilities in the Gulf of Mexico.

Follow @HealingSlowly on Twitter.

Dan Healing, The Canadian Press

WATCH: Dynacorp Fabricators Feature Introductory Video by EnergyNow.ca

September 4, 2017August 28, 2017 by EnergyNow Media

NEW!! Energy Dialogues Podcast Series: Feature Guest: Specialized Desanders with Host David Yager

September 4, 2017August 28, 2017 by EnergyNow Media

Five Things World Business Will be Talking About Today

August 28, 2017 by EnergyNow Media

Aug 28, 2017 (Bloomberg) Harvey hits Houston, May under pressure as Brexit talks resume, and it’s a huge week for eco data. Here are some of the things people in markets are talking about today. Harvey While the winds have subsided, rainfall from tropical storm Harvey is expected to reach as much as 50 inches over … Read more

Petrolia Announces Closing of the Pieridae Private Placement and Third Amendment to Arrangement Agreement

August 28, 2017 by The Canadian Press

FOR: PETROLIA INC.TSX VENTURE SYMBOL: PEADate issue: August 28, 2017Time in: 1:29 PM eAttention:
QUEBEC CITY, QUEBEC–(Marketwired – Aug. 28, 2017) – Petrolia Inc. (TSX
VENTURE:PEA ) (“Petrolia” or the “Company”) is pleased to announce that
Pieridae E…

Your Salespeople Unintentionally Kill Their Credibility When They Say……- Sandler Training

September 4, 2017August 28, 2017 by EnergyNow Media

Written by Hamish Knox; President of Sandler in Calgary, Canada Creating accountable, sales focused organizations in Calgary In sales you don’t have to be dramatically different than your competition to win, only slightly different. Unfortunately, slight differences can also cause your salespeople to lose business by unintentionally killing their credibility with their … Read more

Sunshine Oilsands Ltd.: Clarification Announcement Regarding the Lapse of Subscription Agreement

August 28, 2017 by The Canadian Press

FOR: SUNSHINE OILSANDS LTD.HKSE SYMBOL: 2012Date issue: August 28, 2017Time in: 6:20 AM eAttention:
CALGARY, ALBERTA and HONG KONG, CHINA–(Marketwired – Aug. 28, 2017) – The
Board of Directors of Sunshine Oilsands Ltd. (the “Corporation” or “Sunshine…

Uber Said to Pick Expedia CEO to Lead Company Out of Crisis

August 27, 2017 by EnergyNow Media

August 27, 2017 (Bloomberg) Uber Technologies Inc. will appoint Expedia Inc.’s Dara Khosrowshahi as chief executive officer of the global ride-hailing leviathan, two people familiar with the matter said. He’ll succeed co-founder Travis Kalanick, who grew Uber into a $20 billion annual booking business last year before scandals forced him out. A spokeswoman for Uber directors … Read more

Oil Holds Near $48 as Harvey Shuts Refineries

August 28, 2017August 27, 2017 by EnergyNow Media

August 27, 2017 (Bloomberg) Gasoline surged to the highest in two years and oil was steady as flooding from Tropical Storm Harvey inundated refining centers along the Texas coast, shutting more than 10 percent of U.S. fuel-making capacity. Motor fuel prices rose as much as 6.8 percent, while oil held gains near $48 a barrel. Harvey, … Read more

American federal agency OKs gas pipeline project fought by residents

August 27, 2017 by The Canadian Press

CLEVELAND — A federal agency in the U.S. has approved the construction of a high-pressure natural gas pipeline that’s drawn intense opposition from some Ohio residents concerned about safety and property rights.

The Federal Energy Regulatory Commission in Washington on Friday granted a partnership between Calgary, Alberta-based Enbridge and Detroit-based DTE Energy a certificate of public convenience and necessity for the project.

The $2 billion NEXUS Gas Transmission pipeline is designed to carry gas from shale fields in Appalachia across northern Ohio and into Michigan and Ontario, Canada.

The 402-kilometre-long pipeline will be capable of carrying 42.5 million cubic meters of gas per day.

A NEXUS official says the approval is a “testament” to the company’s “strong history of consultation.”

An opposition leader says the fight isn’t over.

The Associated Press

Harvey Hits U.S. Oil Hub With Massive Winds, Torrential Rain

August 26, 2017 by EnergyNow Media

August 26, 2017 (Bloomberg) Harvey became the strongest hurricane to hit Texas in more than 50 years, making landfall in the heart of the U.S. energy sector and bringing the danger of a life-threatening storm surge. Harvey came ashore as a Category 4 storm between Port Aransas and Port O’Connor, Texas, packing gusts strong enough to … Read more

US rig count decreases by 6 last week to 940

August 28, 2017August 25, 2017 by The Canadian Press

HOUSTON — The number of rigs exploring for oil and natural gas in the U.S. decreased by six this week to 940.

A year ago, just 489 rigs were active.

Houston oilfield services company Baker Hughes said Friday that 759 rigs sought oil and 180 explored for natural gas this week. One was listed as miscellaneous.

Among major oil- and gas-producing states, Louisiana, North Dakota and Ohio each added one rig.

Pennsylvania and Texas each lost three rigs. Alaska, Oklahoma and Utah were down by one apiece.

Arkansas, California, Colorado, New Mexico, West Virginia and Wyoming were all unchanged.

The U.S. rig count peaked at 4,530 in 1981. It bottomed out in May of 2016 at 404.

The Associated Press

Bangladesh court orders seizure of Canadian oil and gas firm’s assets

August 28, 2017August 25, 2017 by The Canadian Press

Calgary-based Niko Resources says the Supreme Court of Bangladesh has ordered the seizure of its assets in the country and ruled that its production agreements are no longer valid, the latest setback in a dispute that has dragged on for a dozen years.

It says the court agreed with a petitioner who asked that the assets be held until Niko provides “adequate” compensation for two natural gas releases in 2005 in northeastern Bangladesh that resulted in fires that damaged trees and crops.

Niko didn’t say why its production agreements with two national oil companies were set aside but Bangladesh media reports online reported that the court said it voided the agreements because they were obtained by corruption.

In 2011, Niko pleaded guilty in a Calgary courtroom to bribing a Bangladeshi government minister with a luxury SUV and trips to New York and Calgary in the wake of the 2005 blowout. The company agreed to pay a $9.5-million fine.

Niko didn’t immediately respond to a request for comment on Friday. In a statement, however, it said it will continue to “vigorously pursue its rights” in Bangladesh.

The company recently reported it was owed $37 million as of June 30 in withheld payments from its 60 per cent interest in the Bangladesh gas fields.

It also reported a “critical” liquidity shortage that threatened its ability to continue in business.

The Canadian Press

Oil Slumps as Harvey Heads Toward Refineries on Texas Gulf Coast

August 25, 2017August 25, 2017 by EnergyNow Media

August 24, 2017 (Bloomberg) Hurricane Harvey sent oil tumbling and gasoline margins soaring as it approaches the refining hub on the Gulf Coast of Texas. Harvey has forced workers off some energy platforms in the Gulf of Mexico, closed marine terminals and threatens to flood refineries in Houston and Corpus Christi. With the storm “you … Read more

It’s a Gas. Why PetroChina’s Energy Shift Is Great News: Gadfly

August 25, 2017August 25, 2017 by EnergyNow Media

August 24, 2017 (Bloomberg Gadfly) You think Royal Dutch Shell Plc, which paid $54 billion to buy gas producer BG Group Plc, is Big Oil’s biggest advocate of a shift to lighter hydrocarbons. Think again: PetroChina Co., China’s biggest oil producer, is also turning its back on the black stuff in favor of natural gas production, … Read more

Five Things World Business Will be Talking About Today

August 25, 2017 by EnergyNow Media

Aug 25, 2017 (Bloomberg) Draghi and Yellen at Jackson Hole, hurricane Harvey to hit Texas, and German economy remains robust ahead of election. Here are some of the things people in markets are talking about today. Thriller?While Mario Draghi’s speech later today at the Jackson Hole conference in Wyoming will be closely watched for any policy signals, it’s … Read more

First-Half 2017 Exploration and Drilling Activity – See the Key Resource Plays, Who’s Drilling and Opportunities – MNP

August 25, 2017August 25, 2017 by EnergyNow Media

Stronger and more stable oil prices combined with cold weather and a good freeze to boost oil and gas activity in Western Canada during the first half of 2017. While the relatively new East Shale Basin attracted attention in late June lease bids, the Viking and the Montney plays continued to lead drilling activity in … Read more

Orphan oil and gas wells adopted by rookie Alberta energy company founder

August 28, 2017August 25, 2017 by The Canadian Press

CALGARY — Where some see only a jumble of rusted pipes and black tanks jutting from a weed-infested yard in a prairie grain field, Tyler Visscher sees opportunity.

The 31-year-old Red Deer, Alta., electrician is trying to build an oil and gas company the hard way, by scouring the Orphan Well Association’s list of parentless wells in Alberta in hopes of picking out a few winners.

He “adopted” his first well two years ago — bought it, actually — and is now wading through a “whack of paperwork” to buy a second.

“Oh, yeah, it’s a gamble for sure,” says the budding oilman. “With everything, there’s a risk, right?”

The crash in commodity prices of the past three years has been linked to a dramatic increase in orphans — oil and gas wells assigned to the OWA because there’s no owner financially able to seal the wells, remove equipment and restore the land when their productive life ends.

In the fiscal year ended March 31, the OWA had 1,391 wells on its list designated for abandonment, up from 768 a year earlier.

As of July 6, the list had climbed to 1,438.

That number doesn’t include 1,380 wells the regulator assigned to the OWA in an unprecedented move early this year after owner Lexin Resources was accused of ignoring AER orders and regulations. The former Lexin assets are being marketed as a package by its receiver in a process expected to wrap up this fall.

Many assume orphan wells and related assets are all liability with no value but the Alberta Energy Regulator says that’s not the case.

“Recently, many wells, pipelines and facilities have been deemed orphans because their owners have gone bankrupt, despite the fact that they are still capable of producing, transporting or processing oil or gas,” said AER spokesman Ryan Bartlett.

In an effort to place those assets with responsible new owners, the AER has provided a database on the OWA website that gives orphan well locations and history — information designed to attract potential buyers.

“It’s very time-consuming because you have to scour these wells and you have to figure out, ‘OK, why is this well on the list?'” said Visscher.

“Was it bad management and the company went bankrupt and now this well is in the orphan well list? Or is the well a poor well? Was it not completed properly? Was it not operated properly? You have to go through, kinda like a detective.”

To take over the well’s production — and responsibility for its environmental liability — the buyer must acquire the underground mineral rights and surface access rights before applying for a licence transfer from the AER.

Not many bother. The AER says the number of licence transfer applications it has handled has increased from four in 2013 to 20 in 2016.

Visscher said it took several months to buy his first well east of Calgary. And many hours of work to clean it up after years of neglect.

The Crown lease had been returned to the province so he nominated it for public auction and filed the successful bid to buy the mineral rights. He then negotiated an agreement with the landowner, a farmer who hadn’t been paid rent by the previous insolvent owner in four or five years, to gain surface access.

To complete the licence transfer, he then had to pay a $10,000 fee to the OWA. To ensure the wellsite will eventually be reclaimed, he has also had to post a $100,000 bond with the AER.

In all, he says it cost about $50,000 to buy the well which is daily producing some 90,000 cubic feet of natural gas (enough to heat an average single detached home in Canada for one year) plus two barrels of oil. He figures the decade-old well originally cost about $1 million to drill.

Visscher has equipped the well with solar-powered pumps and automated controls designed by his electrical company, Blue Star Electrical, and is using it to demonstrate those products for potential buyers.

He said he’s excited about his second well which is awaiting AER licence transfer. It comes with about 260 hectares of Crown drilling rights which means he will have room to drill more wells if he can find the financial backing to do so.

OWA chairman Brad Herald says “the clock is ticking” for entrepreneurs like Visscher who want to buy orphan wells because a big acceleration in well site cleanups is expected to start this fall.

That’s when a $30-million grant announced in the last federal budget is expected to arrive, allowing the province to go ahead with its plan to offer $235 million in loans for OWA projects.

OWA’s annual spending is usually restricted to its $30 million per year industry levy.

Follow @HealingSlowly on Twitter.

Dan Healing, The Canadian Press

Point Loma Resources Announces Second Quarter Financial and Operating Results

August 25, 2017 by The Canadian Press

FOR: POINT LOMA RESOURCES LTD

Date issue: August 25, 2017
Time in: 8:00 AM e

Attention:

CALGARY, AB –(Marketwired – August 25, 2017) – Point Loma Resources Ltd.
(TSX VENTURE: PLX) (the “Corporation” or “Point Loma”) is pleased to report
financial and operating results for the three and six months ended June 30,
2017. Highlights of the periods and additional updates are summarized below:

HIGHLIGHTS

/T/

——————————————————- ——————-
Financial Three Months ended Six Months ended
June 30, 2017 June 30, 2017(1)
——————————————————- ——————-
($ thousands, except share amounts)

Gross revenue 1,183 2,698
Cash fused in operating activities (513) (173)
Funds used in operations(2)(3) (576) (637)
Per share – basic(3) (0.02) (0.02)
Net income (loss) 421 (351)
Per share – basic 0.01 (0.01)
Capital expenditures 332 460
Working Capital 5,305 5,305
Convertible debentures 1,760 1,760
Share capital
Weighted average shares
outstanding for period 35,299,813 32,435,027
Outstanding shares at end of
period 42,078,907 42,078,907

Operations

Daily average production
————————————

Crude oil and liquids (bbls/d) 131 167
Natural gas (mcf/d) 2,611 2,434
Total production (boe/d at 6:1) 566 573

Average sales price
————————————

Crude oil and liquids ($/bbl) 48.66 50.62
Natural gas ($/mcf) 2.53 2.63
Equivalent ($/boe) 22.93 25.46
Netback(3)
Revenues ($/boe) 22.93 25.46
Royalties ($/boe) (3.96) (3.81)
Operating expense ($/boe) (19.17) (18.23)
Transportation expense ($/boe) (0.70) (0.87)
—————— ——————
Netback ($/boe)(3) (0.90) 2.55
—————— ——————

/T/

(1) Six months ended June 30, 2017 includes four months of Judy Creek
acquisition production and reflects the sale of 20% of the oil and gas assets
to Salt Bush Energy Ltd. (“Salt Bush”) effective April 1, 2017
(2) Funds used in operations is cash flow used in operating activities less
changes in non-cash working capital and transaction costs paid.
(3) Funds from (used) in operations and netback are non-GAAP measures; see
“Non-GAAP Measures” below.

Second Quarter Summary

The second quarter of 2017 was an active period for Point Loma with the
closing of two transactions that capitalize the 2017 drilling program and the
re-activation of previously suspended production.

As previously announced, the Salt Bush asset disposition and joint venture
agreement brings capital and a key partner to Point Loma. The deal closed May
23, 2017 for total capital commitment of $5.0 million in exchange for 20% of
Point Loma’s oil and gas assets.

On June 21, 2017, Point Loma closed a private placement with Evenergy Company
Limited (“Evenergy”) for the issuance of 8,375,000 common shares of Point Loma
for cash proceeds of $4.0 million representing a purchase price of $0.48 per
common share.

Operating costs in the second quarter include property taxes for the year to
date which combined with wet field conditions resulted in higher than expected
operating costs per boe. Field interruptions at Thornbury, a winter-only
access area, also reduced production volumes by an approximate average of 70
boe per day.

Third Quarter Operational Plans

With the injection of the additional capital outlined above, Point Loma is
planning to undertake a busy drilling and facilities program this fall. The
Corporation has approved a capital budget for the second half of the year that
will see approximately $3.5 million of planned activity in the third quarter,
including the drilling of two horizontal wells and the startup of a recently
acquired horizontal well in our Paddle River Ostracod A pool that had
previously never been placed on production.

With the Tidewater Midstream and Infrastructure Ltd. (“Tidewater”) purchase
and re-activation of a significant gas processing facility, Point Loma’s plans
are now underway to re-activate production of 16 area wells that had a
previous combined producing rate of approximately 2.0 mmcfd (net) with
associated liquids. The deep cut facility is anticipated to improve the
revenue per boe as well.

Looking forward into 2018, Point Loma has also completed plans to re-establish
production in the Thornbury area. Potentially, the re-connect and optimize
facilities could place another 1,500 mcfd (net) back on production in the area
through company operated infrastructure.

“Point Loma is anticipating a strong growth phase largely driven by low risk
re-activation activities.” said Terry Meek, President and CEO of Point Loma.
“The combination of new drilling, continued tuck-in acquisition opportunities
and re-activation of key infrastructure in our core area provides the impetus
for a step change.”

Additional Information

Point Loma has filed its second quarter financial statements and Management’s
Discussion and Analysis (MD&A) for the three and six months ended June 30,
2017 with Canadian securities regulators. These filings, and additional
information including the Corporation’s recently updated corporate
presentation can be found on Point Loma’s website at www.pointloma.ca or at
Point Loma’s profile on the System for Electronic Document Analysis and
Retrieval website at www.sedar.com.

About Point Loma

Point Loma is a public oil and gas development and exploration company focused
on horizontally exploiting conventional oil and gas reservoirs in west central
Alberta. Point Loma’s business plan is to utilize its experience to drill,
develop and acquire accretive assets with potential for implementation of
horizontal multi-stage frac technology and exploit opportunities for secondary
recovery.

A Note Regarding Forward-Looking Information

This press release contains forward-looking statements and forward-looking
information within the meaning of applicable securities laws, including
without limitation, statements pertaining to Point Loma’s expectations as to
production and future potential production increases, as well as increases in
cash flow and the timing thereof; future gas processing rates; Point Loma’s
expectations as to future prices of oil and natural gas; the focus of Point
Loma’s management team and go-forward strategy.

The use of any of the words “will”, “expects”, “believe”, “plans”, “potential”
and similar expressions are intended to identify forward-looking statements or
information. Although Point Loma believes that the expectations and
assumptions on which such forward-looking statements and information are based
are reasonable, undue reliance should not be placed on the forward-looking
statements and information because Point Loma cannot give assurance that they
will prove to be correct.

Since forward-looking statements and information address future events and
conditions, by their very nature they involve inherent risks and
uncertainties. Actual results could differ materially from those currently
anticipated due to a number of factors and risks. These include, but are not
limited to, the risks associated with the oil and gas industry in general such
as operational risks in development, exploration and production; delays or
changes in plans with respect to exploration or development projects or
capital expenditures; the uncertainty of reserve and resource estimates; the
inability of Point Loma to bring additional production on stream or in the
anticipated quantities disclosed herein; the uncertainty of estimates and
projections relating to reserves, resources, production, costs and expenses;
health, safety and environmental risks; commodity price and exchange rate
fluctuations; marketing and transportation; loss of markets; environmental
risks; competition; incorrect assessment of the value of acquisitions; failure
to realize the anticipated benefits of acquisitions; ability to access
sufficient capital from internal and external sources; changes in legislation,
including but not limited to tax laws, royalties and environmental
regulations, actual production from the acquired assets may be greater or less
than estimates. Management has included the above summary of assumptions and
risks related to forward-looking information provided in this press release in
order to provide security holders with a more complete perspective on Point
Loma’s future operations and such information may not be appropriate for other
purposes.

The forward-looking statements and information contained in this press release
are made as of the date hereof and Point Loma does not undertake any
obligation to update publicly or revise any forward-looking statements or
information, whether as a result of new information, future events or
otherwise, unless so required by applicable securities laws.

Oil and Gas Information

“BOEs” may be misleading, particularly if used in isolation. A BOE conversion
ratio of six thousand cubic feet of natural gas to one barrel of oil
equivalent (6 Mcf: 1 bbl) is based on an energy equivalency conversion method
primarily applicable at the burner tip and does not represent a value
equivalency at the wellhead. As the value ratio between natural gas and crude
oil based on the current prices of natural gas and crude oil is significantly
different from the energy equivalency of 6:1, utilizing a conversion on a 6:1
basis may be misleading as an indication of value.

Non-GAAP Measures

The Corporation utilizes certain measurements that do not have a standardized
meaning or definition as prescribed by IFRS and therefore may not be
comparable with the calculation of similar measures by other entities,
includingfunds from (used) in operations and netback. Readers are referred to
advisories and further discussion on non-GAAP measurements contained in the
Corporation’s MD&A.

– END RELEASE – 25/08/2017

For further information:

For further information, please contact:

Terry Meek
President and CEO
Telephone: (403) 705-5051 ext.101
tmeek@pointloma.ca

Kevin Angus
Executive Vice-President Business Development
Telephone: (403) 705-5051 ext. 103
kangus@pointloma.ca

Randall Boyd
Vice President Finance and CFO
Telephone: (403) 705-5051 ext. 105
rboyd@pointloma.ca

COMPANY:
FOR: POINT LOMA RESOURCES LTD

INDUSTRY: Energy and Utilities – Oil and Gas
RELEASE ID: 20170825CC001

Press Release from Marketwired 1-866-736-3779

Eco (Atlantic) Oil and Gas Ltd Announces First Quarter Results for the three months ended 31 June 2017 and Operational Update

August 24, 2017 by The Canadian Press

FOR: ECO (ATLANTIC) OIL AND GAS LTD
TSX VENTURE SYMBOL: EOG
AIM SYMBOL: ECO

Date issue: August 25, 2017
Time in: 2:00 AM e

Attention:

TORONTO, ON–(Marketwired – August 24, 2017) – Eco (Atlantic) Oil and Gas Ltd
(TSX VENTURE: EOG) (AIM: ECO)

TSXV: EOG; AIM: ECO

25 August 2017

ECO (ATLANTIC) OIL & GAS LTD.
(“Eco Atlantic”, “Company” or, together with its subsidiaries, the “Group”)

First Quarter Results for the three months ended 31 June 2017 and Operational
Update

Eco (Atlantic) Oil & Gas Ltd. (TSXV: EOG; AIM: ECO), the oil and gas
exploration company with licences in highly prospective regions in South
America and Africa, is pleased to announce it has filed its quarterly financial
and operational results for the three months ended 30 June 2017.

Operational Highlights:

– Nearing completion of a circa 2,550 km2 3D seismic survey on the 1,800km2
Orinduik Block offshore Guyana, together with our Operating Partner, Tullow Oil
plc, almost two years ahead of schedule, thereby de-risking the existing
defined targets located up dip and just a few kilometers from Exxon Mobil
Corporation’s recent Liza, Snoek, and Payara discoveries on the Stabroek block,
estimated to contain oil reserves of between 2.25 and 2.75 billion barrels of
recoverable oil
– Increased presence in the UK financial market following our successful
admission to AIM in February 2017
– Actively engaged in evaluating new assets and potential transactions that
will add value to our already robust portfolio of licences.

Financial Highlights:

– Healthy balance sheet at the end of the period with over CAD$4.9m in cash and
working capital of CAD$5.4m

For more information, please visit www.ecooilandgas.com or contact the
following:

/T/
Eco Atlantic Oil and Gas +1 (416) 250 1955
Gil Holzman, CEO
Colin Kinley, COO
Alan Friedman, VP
Finlay Thomson, UK and IR manager +44 (0) 7976 248471

Strand Hanson Limited (Financial & Nominated Adviser)+44 (0) 20 7409 3494
James Harris
Rory Murphy
James Bellman
Brandon Hill Capital Limited (Joint Broker) +44 (0) 20 3463 5000
Alex Walker
Jonathan Evans
Robert Beenstock
Peterhouse Corporate Finance (Joint Broker) +44 (0) 20 7469 0930
Eran Zucker
Duncan Vasey
Lucy Williams
Yellow Jersey PR +44 (0) 7768 537 739
Felicity Winkles
Harriet Jackson
/T/

Click on, or paste the following link into your web browser, to view the
associated PDF document.

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END

– END RELEASE – 25/08/2017

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RNS
Customer Services
0044-207797-4400
rns@londonstockexchange.com
http://www.rns.com

COMPANY:
FOR: ECO (ATLANTIC) OIL AND GAS LTD
TSX VENTURE SYMBOL: EOG
AIM SYMBOL: ECO

INDUSTRY: Energy and Utilities – Oil and Gas
RELEASE ID: 20170825CC0001

Press Release from Marketwired 1-866-736-3779

Mexico’s oil output falls below 2 million barrels per day

August 24, 2017 by The Canadian Press

MEXICO CITY — Mexico’s crude oil output has fallen below 2 million barrels per day for the first time since comparable records were kept starting in 1990.

State-owned oil company Petroleos Mexicanos reports on its website that average daily output in July was about 14,300 barrels short of the 2 million mark.

Production has fallen steadily after peaking at as much as 3.4 million barrels per day between 2003 and 2005.

The drop is largely due to the company’s inability to find new reserves to replace aging, shallow-water fields.

The company was unable Thursday to provide figures from before 1990, when crude output ran at about 2.5 million barrels per day.

The Associated Press

(Webinar) Deploying an Electronic Logging Device (ELD): What You Need To Know – Assetworks

September 4, 2017August 24, 2017 by EnergyNow Media

Wednesday, August 30, 2017 – 11:00 AM MT / 1:00 PM ET Choosing an electronic logging device for your fleet is no different than other fleet purchases; there must be adequate planning and resource allocation to ensure deployment success. This webinar will highlight how to prepare your organization for both implementation and operation of ELD … Read more

CAODC Condemns NEB Decision to Expand Energy East Review

August 25, 2017August 24, 2017 by EnergyNow Media

August 24, 2017 The Canadian Association of Oilwell Drilling Contractors (CAODC) condemns the National Energy Board’s (NEB) decision to expand the review of the Energy East pipeline project to include upstream and downstream climate change impacts. Late yesterday, the NEB announced it will consider the impact of production and consumption of oil in its assessment … Read more

Frontier oilsands mine panel ordered to consider impact on world heritage site

August 24, 2017 by The Canadian Press

CALGARY — The federal-provincial panel conducting an environmental review of the proposed Frontier oilsands mine project in northern Alberta has been ordered to consider its impact on Wood Buffalo National Park as requested by the UN’s World Heritage Committee.

In a report in March based on a visit to the 45,000-square-kilometre park, a world heritage site since 1983, the UN agency warned of risk from industrial development and said the park could be designated “in danger” if Canada didn’t implement 17 recommendations.

It set a deadline of February 2018 for Canada to show its plan to meet those recommendations and another deadline of December 2018 to show progress.

According to the report, the Frontier project would move oilsands development closer to the southern boundary of the park, increasing the risk that it and its herd of wood bison might be affected by leaks and spills from tailings ponds and other water and air pollution.

The panel is to consider potential environmental effects of the project on the value of the world heritage site, including the Peace-Athabasca Delta, and address it in a separate chapter of its report.

Project proponent Teck Resources (TSX:TECK) has said oil production at the 260,000-barrel-per-day Frontier won’t take place until 2026 at the earliest.

The Canadian Press

It’s Been a Bad Month for Some of America’s Most-Loved Oil Plays

August 24, 2017August 24, 2017 by EnergyNow Media

August 24, 2017 (Bloomberg) The good news for U.S. producers: the chief executive officer of Europe’s second-biggest oil and gas company thinks American shale assets are “quite expensive” following a recovery in the price of crude. The bad news: they’re growing more affordable. Assets tied to shale producers, particularly those in America’s most-coveted oil field, … Read more

Oil Steady as U.S. Crude Stockpiles Drop While Output Rises

August 24, 2017August 24, 2017 by EnergyNow Media

August 24, 2017 (Bloomberg) Oil steadied near $48 a barrel in New York after a further reduction in U.S. crude inventories was tempered by gains in the nation’s production. Futures slipped 0.4 percent after advancing for a second session on Wednesday. Crude stockpiles slid by 3.33 million barrels to the lowest level since January 2016, … Read more

Five Things World Business Will be Talking About Today

August 24, 2017 by EnergyNow Media

August 24, 2017 (Bloomberg) The debt ceiling debate heats up, Jackson Hole begins, and U.K. consumer spending barely grows. Here are some of the things people in markets are talking about today. Wall, ceiling, House President Donald Trump’s threat to shutdown the government if Congress refuses to approve funding for a wall with Mexico could complicate efforts to … Read more

Sunshine Oilsands Ltd.: Voluntary Announcement – Financial Assistance from A Substantial Shareholder

August 24, 2017 by The Canadian Press

FOR: SUNSHINE OILSANDS LTD.HKSE SYMBOL: 2012Date issue: August 24, 2017Time in: 8:58 AM eAttention:
HONG KONG, CHINA and CALGARY, ALBERTA–(Marketwired – Aug. 24, 2017) – The
Board of Directors of Sunshine Oilsands Ltd. (the “Corporation” or “Sunshine…

Marquee Energy Ltd. Announces Second Quarter 2017 Financial and Operating Results and Appointment of Chief Financial Officer

August 23, 2017 by The Canadian Press

FOR: MARQUEE ENERGY LTD.
TSX VENTURE Symbol: MQX

Date issue: August 23, 2017
Time in: 9:10 PM e

Attention:

CALGARY, AB –(Marketwired – August 23, 2017) –

NOT FOR DISTRIBUTION TO U.S. NEWS SERVICES OR FOR DISSEMINATION IN THE UNITED
STATES

Marquee Energy Ltd. (“Marquee” or the “Company”) (TSX VENTURE: MQX) announces
its second quarter operational and financial results for the three and six
months ended June 30, 2017, and the appointment of Mr. Howard Bolinger as
Chief Financial Officer (“CFO”) and Vice President Finance, effective
immediately. The Company’s financial statements and Management’s Discussion
and Analysis (“MD&A”) for the three and six months ended June 30, 2017 are
available on the System for Electronic Document Analysis and Retrieval (SEDAR)
at www.sedar.com and on Marquee’s website at www.marquee-energy.com.

SECOND QUARTER 2017 FINANCIAL AND OPERATING HIGHLIGHTS

/T/

— Successfully brought on production three light oil horizontal Banff

wells drilled in the first quarter 2017 at Michichi;

/T/

— Production averaged 3,024 boe/d (44% liquids) in the second quarter of

2017, up 545 boe/d (22%) from the previous quarter;

/T/

— Closed a $30 million, 5-year subordinated term loan with Crown Capital

Fund IV, LP, an investment fund managed by Crown Capital Partners Inc.
(TSX VENTURE: CRWN) and obtained a $12 million credit facility with
National Bank of Canada to improve financial liquidity on May 30, 2017;

/T/

— Funds flows from operations were $2.4 million in the second quarter, an

increase of $1.3 million from the previous quarter; and

/T/

— Operating netbacks averaged $15.79/boe in Q2 2017, a 21% increase from

the previous quarter.

/T/

FINANCIAL AND OPERATIONAL RESULTS

/T/

——— (thousands of Canadian dollars, except per share and per boe amounts) ——— Financial
Oil and natural gas
sales (1) Funds flow from
operations (2) Per share – basic and
diluted Per boe Net income (loss) Per share – basic and
diluted Capital expenditures $
Net debt (2) Total Assets Weighted average basic
shares outstanding Weighted average diluted
shares outstanding
Operational
Net wells drilled Daily sales volumes
Oil (bbls per day) Heavy Oil (bbls per
day) NGL’s (bbls per day) Natural Gas (mcf per
day) Total (boe per day) % Oil and NGL’s Average realized prices
Light Oil ($/bbl) Heavy Oil ($/bbl) $ NGL’s ($/bbl) Natural Gas ($/mcf) $ Netback
Revenue ($/boe) Royalties ($/boe) Operating and
transportation costs
($/boe) Operating netback
prior to hedging (2) $ Realized hedging gain
(loss) ($/boe) Operating netback
($/boe) (2) ——— ——————————————————————-
Three months ended Six months ended
June 30, June 30,
2017 2016 2017 2016
——————————————————————-
$ 8,989 $ 8,344 $ 16,412 $ 16,093
$ 2,384 $ 31 $ 3,489 $ 1,353
$ 0.01 $ – $ 0.01 $ 0.01
$ 8.66 $ 0.09 $ 7.00 $ 1.81
$ (1,956) $ 1,043 $ (5,618) $ (6,875)
$ 0.00 $ 0.01 $ (0.01) $ (0.03)
1,246 $ 377 $ 7,486 $ 477
$ 22,914 $ 44,275
$ 175,458 $ 182,647
435,772,196 205,686,639 435,772,196 205,686,639
435,772,196 205,686,639 435,772,196 205,686,639
– – 3 –
1,174 1,265 1,088 1,361
– 261 – 334
159 136 146 147
10,141 12,864 9,117 13,657
3,024 3,806 2,754 4,118
44% 44% 45% 45%
$ 52.11 $ 46.92 $ 52.36 $ 38.45
– $ 35.03 $ – $ 24.43
$ 40.71 $ 36.52 $ 41.02 $ 29.75
3.07 $ 1.42 $ 3.04 $ 1.72
$ 32.66 $ 24.09 $ 32.93 $ 21.47
$ (1.90) $ (3.27) $ (2.24) $ (2.23)
$ (16.18) $ (14.21) $ (16.79) $ (15.42)
14.58 $ 6.61 $ 13.90 $ 3.82
$ 1.21 $ (0.13) $ 0.67 $ 3.11
$ 15.79 $ 6.48 $ 14.57 $ 6.94
——————————————————————-

/T/

(1) Before Royalties
(2) Defined under the Non-GAAP Measures section of the Company’s MD&A for the
three months ended June 30, 2017

CORPORATE UPDATE

The three wells from our first quarter 2017 drilling program have been on
production since early April and have exceeded forecasted type curve rates and
cashflow. Over the last thirty days the wells have averaged 150 boe/d (40% oil
and liquids) per well.

The Company resumed its drilling program in early July and has drilled four
wells to date incorporating its new mono-bore design. The wells were drilled
on average in eight days compared to fourteen days previously. The wells are
scheduled to be completed and fracked starting in early September. The Company
will utilize a completion program with increased frack density and intensity,
with the expectation that productivity and reserves recoveries will be
enhanced with minimal change in cost compared to previous drilling. Two of
these wells are expected to satisfy the Company’s remaining flow-through
obligations for 2017.

The Company has built a scalable and sustainable asset base with a proven
fairway containing an attractive inventory of low risk locations, and remains
focused on maximizing long term value of its resource for shareholders.

The Company is pleased to announce the appointment of Howard Bolinger as Chief
Financial Officer (“CFO”) and Vice President Finance, effective immediately.
Mr. Bolinger is Chartered Accountant and brings substantial operational and
capital markets experience, to further strengthen Marquee’s executive team.

ABOUT MARQUEE

Marquee is a Calgary-based, junior energy company focused on light oil
development and production in the Michichi area of eastern Alberta. Marquee’s
shares trade on the TSX Venture Exchange under the trading symbol “MQX”.
Additional information about Marquee may be found on its website
www.marquee-energy.com and in its continuous disclosure documents filed with
Canadian securities regulators on SEDAR at www.sedar.com.

Neither the TSX Venture Exchange nor its Regulation Services Provider (as that
term is defined in the policies of the TSX Venture Exchange) accepts
responsibility for the adequacy or accuracy of this release.

FORWARD-LOOKING STATEMENTS OR INFORMATION

Certain statements included or incorporated by reference in this news release
may constitute forward-looking statements under applicable securities
legislation. Such forward-looking statements or information typically contain
statements with words such as “anticipate”, “believe”, “expect”, “plan”,
“intend”, “estimate”, “propose”, or similar words suggesting future outcomes
or statements regarding an outlook. Forward-looking statements or information
in this news release may include, but are not limited to: reserves estimates
and the net present value of the future net reserves related thereto; the
number and quality of future potential drilling and development opportunities;
anticipated capital budgets and expenditures; average production for 2017 and
beyond; 2017 exit production rates; the Company’s development, drilling and
completion plan; and well performance.

Such forward-looking statements or information are based on a number of
assumptions all or any of which may prove to be incorrect. In addition to any
other assumptions identified in this document, assumptions have been made
regarding, among other things: the ability of the Company to obtain equipment,
services and supplies in a timely manner to carry out its activities; the
ability of the Company to market crude oil, natural gas liquids and natural
gas successfully to current and new customers; the ability to secure adequate
product transportation; the timely receipt of required regulatory approvals;
the ability of the Company to obtain financing on acceptable terms; interest
rates; regulatory framework regarding taxes, royalties and environmental
matters; future crude oil, natural gas liquids and natural gas prices; the
ability to successfully integrate acquisitions into Marquee’s business and
management’s expectations relating to the timing and results of development,
drilling and completions activities.

Forward-looking information is based on current expectations, estimates and
projections that involve a number of risks and uncertainties which could cause
actual results to differ materially from those anticipated by the Company and
described in the forward-looking information. Material risk factors affecting
the Company and its business are contained in Marquee’s Annual Information
Form for the year ended December 31, 2016, which is available under Marquee’s
issuer profile on SEDAR at www.sedar.com.

The forward-looking information contained in this press release is made as of
the date hereof and the Company undertakes no obligation to update publicly or
revise any forward-looking information, whether as a result of new
information, future events or otherwise, unless required by applicable
securities laws. The forward-looking information contained in this press
release is expressly qualified by this cautionary statement.

NON-GAAP FINANCIAL MEASURES

This press release contains the term “operating netbacks prior to hedging” and
“operating netbacks” which do not have standardized meanings prescribed by
IFRS and, therefore, may not be comparable with the calculation of similar
measures presented by other companies. Marquee uses operating netbacks to
analyze operating performance. Marquee believes this benchmark is a key
measure of profitability and overall sustainability for the Company and this
term is commonly used in the oil and natural gas industry. Operating netbacks
are not intended to represent operating profits, net earnings or other
measures of financial performance calculated in accordance with IFRS.

Operating netbacks prior to hedging are calculated by subtracting royalties,
production, and operating and transportation expenses from revenues before
other income/losses. Operating netbacks include realized hedging gain (loss).

This press release also contains the term “funds flow from operations” which
should not be considered an alternative to, or more meaningful than “cash flow
from operating activities”, as determined in accordance with IFRS, as an
indicator of the Company’s performance. “Funds flow from operations” does not
have any standardized meaning prescribed by IFRS and therefore reference to
funds flow from operations or funds flow from operations per share may not be
comparable with the calculation of similar measures presented by other
entities. Management uses funds flow from operations to analyze operating
performance and leverage and considers funds flow from operations to be a key
measure as it demonstrates the Company’s ability to generate cash necessary to
fund future capital investments and to repay debt. Funds flow from operations
per share is calculated using the weighted average number of shares for the
period.

In addition, the press release contains the term “net debt”, which does not
have any standardized meaning under IFRS and therefore may not be comparable
to similar measures presented by other issuers. Net debt is calculated as net
debt, defined as current assets less current liabilities (excluding fair value
of commodity contracts and flow-through share premiums). Management considers
net debt as an important additional measure to monitor debt repayment
requirements and track the financial viability of the Company.

Please see the Company’s MD&A for the year ended December 31, 2016 and the
Company’s MD&A for the three and six months ended June 30, 2017 for a
reconciliation of certain Non-GAAP financial measures used in this press
release to their most directly comparable GAAP or IFRS measures.

ADDITIONAL ADVISORIES

Barrels of oil equivalent (boe) are presented on the basis of one boe for six
Mcf of natural gas. Disclosure provided herein in respect of boe may be
misleading, particularly if used in isolation. A boe conversion ratio of 6
Mcf: 1 bbl is based on an energy equivalency conversion method primarily
applicable at the burner tip and does not represent a value equivalency at the
wellhead. Given that the value ratio based on the current price of crude oil
as compared to natural gas is significantly different from the energy
equivalency of 6:1, utilizing a conversion on a 6:1 basis may be misleading as
an indication of value.

– END RELEASE – 23/08/2017

For further information:

FOR ADDITIONAL INFORMATION PLEASE CONTACT:

Richard Thompson
President & Chief Executive Officer
(403) 817-5561
RThompson@marquee-energy.com

or visit the Company’s website at http://www.marquee-energy.com/

COMPANY:
FOR: MARQUEE ENERGY LTD.
TSX VENTURE Symbol: MQX

INDUSTRY: Energy and Utilities – Oil and Gas
RELEASE ID: 20170823CC015

Press Release from Marketwired 1-866-736-3779

Sluggish oil prices continue to plague Alberta’s bottom line: fiscal update

August 24, 2017August 23, 2017 by The Canadian Press

EDMONTON — Sluggish oil prices are forcing Alberta to dip into its reserve fund and look for more in-house savings to keep its $10.5-billion deficit from sliding further into the red.

In his first-quarter fiscal update, Finance Minister Joe Ceci said the province had expected the West Texas Intermediate benchmark oil price to average out at US$55 a barrel this year.

Instead, it’s hovering below US$49 a barrel and isn’t expected to rise much in the near term.

“The forecast (at budget) in March was based on the best private sector forecasts available. The same is true of the updated forecast,” Ceci said Wednesday. “What it speaks to is a tremendous volatility in world oil markets.”

The province had hoped to bring in $2.5 billion in oilsands royalties this year, but now expects to take in $563 million less.

Ceci said the government will use half of its $500-million contingency fund to keep this year’s deficit from growing.

It also aims to double the amount of money spent on department operations to $400 million from $200 million. The government will continue to consolidate services, streamline IT, reduce travel and maintain hiring restraints while avoiding civil service layoffs.

About $120 million has already been found, he said.

“It’s an ongoing exercise and I know my colleagues in different ministries are up for it.”

Ric McIver, the United Conservative Party finance critic, said taxpayers deserve more details on the savings.

“The minister gave himself a pat on the back for doubling the in-year savings projections, but can’t tell us where these savings are coming from, or why he’s so confident in his double projection,” said McIver.

“One could at least wonder whether the second $200 million wasn’t concocted to make today’s media conference go better for the minister.”

Ceci noted there are bright signs on the horizon. The province expects the economy to grow by 3.1 per cent in 2017, up from the March budget forecast of 2.6 per cent. Employment is also expected to rise by 1.3 per cent, higher than the 0.9 per cent forecast in the budget.

Alberta has been struggling for years with a prolonged trough in oil prices, draining billions of dollars from its bottom line and throwing thousands of people out of work.

Despite the downturn, Premier Rachel Notley’s government has committed to ramped up capital spending and to stay away from deep cuts to operational spending. Notley has said it’s the best approach to catch up on infrastructure and to help keep the economy going in tough times.

“For the time being, we’re going to keep delivering the programs and services Albertans rely on, and for the time being we’re going to keep up the pressure on finding … savings because those are some of the things we can control,” Ceci said Wednesday.

The province has been hit with multiple credit warnings and downgrades in the last two years. The accumulated debt by year’s end is forecast to be $43.3 billion and debt servicing costs will rise slightly to $1.4 billion.

Opposition politicians have said the government needs to do a better job reining in spending to avoid saddling future generations with debilitating debt-interest payments.

“The NDP’s record level of borrowing and debt is seriously concerning, especially without a credible plan to pay it back,” said Liberal Leader David Khan.

“We need to concentrate on controlling operational costs and focus on smart investments in infrastructure instead of borrowing to keep the lights on.”

Alberta Party Leader Greg Clark said the NDP doesn’t have a plan to keep spending in check.

“This government is continuing to cross their fingers and hope the price of oil goes up,” he said. “Hope is not a strategy.”

Dean Bennett, The Canadian Press

Raise Production Inc. Announces Second Quarter 2017 Financial Results and Provides Operations Update

August 23, 2017 by The Canadian Press

FOR: RAISE PRODUCTION INC.
TSX VENTURE SYMBOL: RPC

Date issue: August 23, 2017
Time in: 6:29 PM e

Attention:

CALGARY, ALBERTA–(Marketwired – Aug. 23, 2017) – Raise Production Inc. (TSX
VENTURE:RPC) (“Raise” or the “Company”) has released its financial results for
three and six months ended June 30, 2017.

PRESIDENT’S UPDATE

The Company is pleased to provide an update to its shareholders on recent
activities related to its Horizontal Wellbore Production System (the “System”)
and High Angle Lift Solution (“HALS”).

Horizontal Wellbore Production System

The Company has retrieved the System from the test partner wellbore. The
material retrieved from inside of the pumps gave the Company more relevant
information and confirmed that the System had been operating as designed and
had been producing the fluids that the wellbore was capable of inflowing from
the reservoir. The System works.

The Company has recently developed a unique method to immediately increase
productivity of existing customer wells and evaluate the inflow, flow
characteristics, pressures and temperatures at multiple points while pumping
the build and vertical sections with the Company’s HALS. This information will
ensure proper placement of the System along with increased accuracy in
determining estimated remaining reserves from non-producing and flow restricted
areas of the wellbore. This information can then be utilized to determine the
optimal number of pumps and pump placement along the wellbore and provide a
more accurate estimated optimal recovery of oil and gas for the operator.

Based on this new method and cumulative knowledge gained from installs in the
test partner wellbore, the Company now has a clearly defined methodology to
identify wells for optimal performance.

The Company is excited to partner with third party suppliers to provide the
logging tools, reservoir evaluation (including 3D modelling) and dynamic flow
simulation in addition to the Company’s “in house” production engineering for
the completion design and hardware recommendations for customers.

High Angle Lift Solution (HALS)

The HALS is a high angle lift solution that can have certain downhole tools
added, such as horizontal separation, sand control, velocity flow tubes and
pack off assemblies for flow control. The recently added instrumentation allows
the HALS to be utilized to evaluate the horizontal section while pumping and
producing at optimal rates. The double benefit to E&P’s is maximized
productivity by optimizing vertical and build sections of the wellbore while
gaining insight into flow conditions of the horizontal section.

The Company’s private demonstrations of its products and the recent open house
held at its facility has resulted in confirmed sales, multiple follow up
requests and confirmed the industry’s interest in optimizing horizontal
wellbores. Raise believes that as this product continues to gain traction, the
evolution of horizontal wellbore evaluation will become increasingly attractive
to producers.

RESULTS OF OPERATIONS
Statements of Loss and Comprehensive Loss

/T/

—————————————————————————-
—————————————————————————-

Three months ended June 30 Six months ended June 30
2017 2016 2017 2016
—————————————————————————-

Revenue $ 85,120 $ 105,300 $ 92,520 $ 160,950
Cost of sales 80,887 74,392 87,479 112,863
—————————————————————————-
Gross margin 4,233 30,908 5,041 49,087
—————————————————————————-
Other income 14,133 4,562 16,993 10,525
—————————————————————————-

Expenses:

General and
administration 447,649 382,902 739,947 744,728
Depreciation and
amortization 27,180 35,000 54,399 69,464
Stock-based
compensation 11,024 21,809 23,971 50,253
Finance costs 1,979 4,130 5,000 9,113
Research expenses – 28,812 – 28,812
Asset impairment – 5,867 – 5,867
—————————————————————————-

487,832 478,520 823,317 908,237
—————————————————————————-
Net loss and
comprehensive loss $ (469,466) $ (443,050) $ (801,283) $ (849,625)
—————————————————————————-
—————————————————————————-

—————————————————————————-
Net loss per share
– basic and
diluted $ (0.00) $ (0.00) $ (0.01) $ (0.01)
—————————————————————————-
—————————————————————————-

/T/

About Raise Production Inc.

The Company is an innovative oilfield service company that focuses its efforts
on the production service sector, utilizing its proprietary products to enhance
and increase ultimate production in both conventional and unconventional
horizontal oil and gas wells.

Neither TSX Venture Exchange nor its Regulation Services Provider (as that term
is defined in the policies of the TSX Venture Exchange) accepts responsibility
for the adequacy or accuracy of this news release.

Certain information included in this news release constitutes forward-looking
statements under applicable securities legislation. Forward-looking statements
or information typically contain or can be identified by statements that
include words such as “anticipate”, “assume”, “based”, “believe”, “can”,
“continue”, “depend”, “estimate”, “expect”, “forecast”, “if”, “intend”, “may”,
“plan”, “project”, “propose”, “result”, “upon”, “will”, “within” or similar
words suggesting future outcomes or statements regarding an outlook. Such
forward-looking statements or information are based on a number of assumptions
that may prove to be incorrect. Assumptions have been made regarding, among
other things: the ability of the Company to obtain required capital to continue
to finance its product development, the successful completion of further
product development and testing within predicted timelines or at all, the
ability to commercialize products and operations, the ability to adequately
protect proprietary information and technology from its competitors; the
ability to obtain partnering opportunities; the ability to attract and retain
key personnel and key collaborators; and the ability to successfully compete in
targeted markets.

The forward-looking statements contained in this news release are made as of
the date hereof and the Company does not undertake any obligation to publicly
update or revise any of the included forward- looking statements, except as
required by applicable Canadian securities law. Forward-looking statements are
based upon the current opinions, estimates, projections, assumptions and
expectations of management of the Company as at the effective date of such
statements and, in some cases, information supplied by third parties. Although
the Company believes that the expectations reflected in such forward – looking
statements are based upon reasonable assumptions and that information received
from third parties is reliable, it can give no assurance that those
expectations will prove to have been correct. By its nature, forward-looking
information involves numerous assumptions, known and unknown risks and
uncertainties, both general and specific, that contribute to the possibility
that the predictions, forecasts, projections and other forward-looking
statement will not occur. These risks and uncertainties include, but are not
limited to: the possibility that testing, deployment and commercialization of
the System and Rod Pumps may not be successfully completed for any reason
(including the failure to obtain the required approvals from regulatory
authorities) and regulatory changes. Accordingly, readers should not place
undue reliance upon the forward-looking statements contained in this news
release and such forward- looking statements should not be interpreted or
regarded as guarantees of future performance and actual results or developments
may differ materially from those projected in the forward-looking statements.
For more information on the Company, investors should review the Company’s
continuous disclosure filings that are available at www.sedar.com.

– END RELEASE – 23/08/2017

For further information:
Raise Production Inc.
Eric Laing
President and Chief Executive Officer
(403) 699-7675
elaing@raiseproduction.com
OR
Raise Production Inc.
Susan Scullion
Chief Financial Officer
(403) 699-7675
sscullion@raiseproduction.com
www.raiseproduction.com

COMPANY:
FOR: RAISE PRODUCTION INC.
TSX VENTURE SYMBOL: RPC

INDUSTRY: Energy and Utilities – Oil and Gas , Telecom –
Networking, Telecom – Telecommunication Equipment
RELEASE ID: 20170823CC0041

Press Release from Marketwired 1-866-736-3779

Saskatchewan finance minister says budget update will come Friday

August 23, 2017 by The Canadian Press

REGINA — Saskatchewan Finance Minister Kevin Doherty says he will present a first-quarter budget update on Friday.

Doherty says it’s too soon to know what impact a drought in southwestern Saskatchewan might have on budget numbers.

He says there’s no question the area is in distress, but producers in other regions are reporting better-than-expected yields given the conditions.

Agriculture has been helping the Saskatchewan government’s bottom line in the last couple of years — bumper crops have boosted the books while oil and gas prices fell.

The budget delivered in March was — by Premier Brad Wall’s own description — unpopular with voters because of cuts that were made to help tackle a $1.3-billion deficit.

The government ended up reversing cuts to libraries, community-based organizations and to poor people for funeral services.

The Canadian Press

Poll suggests Albertans want tighter methane rules for energy industry

August 23, 2017August 23, 2017 by The Canadian Press

EDMONTON — As governments and regulators consider new rules for methane, a poll suggests nearly three-quarters of Albertans want tighter controls on the release of a potent greenhouse gas from oil and gas facilities.

The poll, done by EKOS research and funded by Environmental Defence, says 71 per cent of those surveyed want regulations on methane release to be at least as strict as those in the U.S.

“We wanted to demonstrate that people in Alberta, in particular, want to see this issue addressed,” said Tim Gray with Environmental Defence. “The data shows that they do — they care about it a lot.”

Methane, also known as natural gas, is a greenhouse gas at least 20 times more potent over the long term than carbon dioxide. The energy industry is Canada’s largest source and controlling those releases is considered to be one of the most cost-effective ways for the industry to address climate change.

Many American states already have requirements that force companies to inspect more often for leaks and reduce methane venting, Gray said.

The poll says 41 per cent of Albertans think their province should be equally as strict. Another 30 per cent wanted Alberta’s rules to be even tighter.

Fourteen per cent of respondents thought the rules should be more relaxed and 15 per cent didn’t know.

The poll surveyed more than 1,000 people by phone and online over a two-week period ending Aug. 8 and is considered accurate to within three percentage points, 19 times out of 20.

Gray said Albertans have been living with venting and flaring of gas from energy facilities for decades and have a good understanding of the issue.

“People in Alberta have first-hand experience with methane leaks,” he said. “People have had to deal with methane in the form of flaring from a human health perspective. I also think they see it as waste — wasted money, wasted jobs.”

Both the federal government and Alberta’s energy regulator are designing new rules to reduce those emissions.

The proposed federal regulations would force industry to regularly check for gas leaks and install equipment that prevents the gas from venting. They would apply to oil and gas wells and batteries, natural gas processing plants, compressor stations, and supporting pipelines.

Ottawa estimates that its proposed rules would reduce methane emissions by 282 megatonnes by 2035.

The Alberta Energy Regulator is considering how to meet the government’s target of a 45 per cent reduction in methane leaks by 2025. The industry is the province’s largest source of methane.

Regulator spokeswoman Shelley Svetanova says draft requirements will go before the public this fall with final rules expected by next summer.

Chelsie Klassen, spokeswoman for the Canadian Association of Petroleum Producers, said in an email that the association is committed to reducing methane emissions. She said Alberta has already reduced emissions and outperforms reductions in jurisdictions such as North Dakota and California.

Industry figures say 96.4 per cent of gases were conserved in Alberta in 2016, up from 94.1 per cent in 1999. That means about 770 million cubic metres of gases were released last year, the equivalent of 7.5 million tonnes of carbon dioxide.

Gray said industry has resisted legal reduction requirements, arguing instead for guidelines.

“If we go with a much less restrictive approach, the result is going to be much higher methane emissions from Canada than is necessary if we match the approach that’s being done in the U.S.”

— Follow Bob Weber on Twitter at @row1960

Bob Weber, The Canadian Press

Energy East Pipeline review decision greeted as victory by environmentalists

August 24, 2017August 23, 2017 by The Canadian Press

CALGARY — In a decision cheered by environmentalists but considered a setback by the oil industry, Canada’s national energy regulator says it will allow wider discussion of greenhouse gas emission issues in upcoming hearings for the Energy East Pipeline.

The National Energy Board said Wednesday it will for the first time consider the public interest impact of upstream and downstream GHG emissions from potential increased production and consumption of oil resulting from the project.

It says it will also, for the first time, allow discussion at hearings of the effect of meeting government GHG emission targets on the financial viability and need for the 4,500-kilometre pipeline.

Previously, the NEB only considered GHG emissions directly associated with construction and operation of a pipeline.

Alberta’s energy minister expressed disappointment in the decision and said her office would continue to review it.

“Based on our initial analysis, we believe this would be a historic overreach and have concerns about what this means for energy development across Canada,” Margaret McCuaig-Boyd said in a statement Wednesday.

She said deciding the merits of a pipeline on downstream emissions “is like judging transmission lines based on how its electricity will be used.”

But, Ecojustice lawyer Charles Hatt said in a statement the NEB’s decision is “both lawful and sensible.”

“Surely it is now self-evident that a pipeline review must consider all potential greenhouse gas emissions and the risk that the pipeline will become a stranded asset in tomorrow’s economy,” he said.

Nick Schultz, vice-president of pipeline regulation for Canadian Association of Petroleum Producers, said the ruling allows needless duplication of existing federal environmental protections and will create more delays for builders who will have to submit more information.

“It’s the signal about the length and complexity of the regulatory process that is becoming concerning here,” he said.

Widening the scope puts an unfair burden on Canadian projects, said Dirk Lever, an oil and gas infrastructure analyst for Calgary-based AltaCorp Capital.

“It is not like any pipeline company can control the emissions on either side of their pipe,” he said.

Greenpeace Canada energy strategist Keith Stewart welcomed the decision but cautioned that details on how the ruling will affect the pipeline’s ultimate approval or denial are still to be determined.

A spokesman for proponent TransCanada (TSX:TRP) said the company will review the NEB’s permitted issues list before commenting on its potential impact on the $15.7-billion project.

Energy East is designed to carry 1.1 million barrels of crude per day from Alberta and Saskatchewan to refineries in Eastern Canada and an export marine terminal in New Brunswick.

The wider GHG review was opposed by the Alberta government but supported by Ontario in submissions to the NEB.

The NEB list of topics is used during hearings to restrict submissions to those considered to be within the board’s mandate. It said it received 820 submissions after inviting public comment on widening its topic list in May.

The regulator said it will now invite public comment on the completeness of TransCanada’s applications before issuing a hearing schedule.

The original Energy East review was derailed in September 2016 after members of the regulatory panel overseeing the hearings resigned amid questions about a potential conflict of interest.

In January, the NEB invalidated nearly two years of decisions made by the previous panel and a new panel was appointed.

The Energy East review is taking place at the same time that the government considers a sweeping overhaul of the NEB following a report in May that said the system is broken and the NEB should be split into two agencies.

In granting approval to Kinder Morgan’s Trans Mountain pipeline expansion in May 2016, the NEB ordered an unprecedented requirement to account for and offset greenhouse gas emissions related to pipeline construction.

Follow @HealingSlowly on Twitter.

Dan Healing, The Canadian Press

Oil Halts Advance Near $48 on Signs U.S. Fuel Stockpiles Climbed

August 24, 2017August 23, 2017 by EnergyNow Media

August 23, 2017 (Bloomberg) Oil halted gains near $48 a barrel as U.S. industry data showed gasoline stockpiles rose, offsetting a further decline in crude inventories. Futures lost 0.3 percent in New York after rebounding Tuesday from the biggest drop in a week. Motor fuel stockpiles gained by 1.4 million barrels last week, while crude … Read more

Five Things World Business Will be Talking About Today

August 23, 2017 by EnergyNow Media

August 23, 2017 (Bloomberg) Trump threatens a government shutdown, it’s PMI day, and Theresa May crosses a red line. Here are some of the things people in markets are talking about today. Hitting a wall President Donald Trump warned Democratic lawmakers that “one way or the other” the border wall with Mexico would be built, saying … Read more

Canadian Petrochemical Industry Leaders Gather to Provide Insights Into How Canada can Become a Competitive Player on the Global Petrochemical Stage

September 5, 2017August 23, 2017 by EnergyNow Media

With the recent volatility of the oil and gas industry, diversifying Canada’s energy sector is a necessity. The advent of shale gas development has led to a wave of natural gas liquid extraction that has benefitted petrochemical producers across the continent. The US Gulf Coast is developing several petrochemical expansion projects and location initiatives and … Read more

Did You Know there is an Employment Standards Complaint Process in Alberta? – Wendy Ferguson – BHRLR, CPHR

August 23, 2017August 23, 2017 by EnergyNow Media

A Commentary by Wendy Ferguson – BHRLR, CPHR – Ferguson HR Consulting The vast majority of employers in Alberta follow employment standards, however some don’t. That is why it is important for employers and employees alike to understand the legislation that applies to them in the workplace. In Alberta, employees can access a complaint process … Read more

Alberta NDP’s Occupational Health & Safety Review Must Recognize Oilpatch Success – David Yager – Yager Management

August 24, 2017August 22, 2017 by EnergyNow Media

David Yager – Yager Management Ltd. Oilfield Services Executive Advisory – Energy Policy Analyst August 23, 2017 Heads up folks. Alberta’s NDP government is setting out to fix things again. The headline August 16 in the Edmonton Journal and Calgary Herald was innocuous enough reading, “Alberta’s occupational health and safety act under review”. The brief … Read more

B.C. seeks intervener status in court cases against Trans Mountain pipeline

August 23, 2017August 22, 2017 by The Canadian Press

VANCOUVER — The British Columbia government has applied for intervener status in court challenges against the Trans Mountain pipeline expansion.

The NDP government announced earlier this month that it would be joining the legal fight against Ottawa’s approval of the $7.4-billion project and hired former judge Thomas Berger to provide legal advice.

Several First Nations and municipalities have filed legal challenges against the project, which would triple the capacity of the Alberta-to-B.C. pipeline and increase the number of tankers in Vancouver-area waters.

Attorney General David Eby said the majority of the pipeline is in B.C. and the government should be able to represent the interests of people in the province, notably because the Alberta government has already been granted intervener status.

“We clearly have a distinct point of view from the Attorney General of Alberta in terms of the benefits of this project,” Eby said.

Alberta has long argued that it needs a pipeline to get more of its oil to the West Coast and from there to overseas markets.

B.C.’s former Liberal government issued an environmental certificate for the project earlier this year, but Premier John Horgan campaigned in the spring provincial election his party would do everything possible stop it.

Eby said the government’s specific arguments that it will bring forward to the court, if their application is approved, are still being developed.

“Our goal in every process around this pipeline project is to ensure the interests of British Columbians are protected and that will be the aim of our arguments,” he said.

The province expects a decision on its application to come quickly, as the legal challenges are set to be heard this fall, Eby said.

Trans Mountain, a subsidiary of Kinder Morgan Canada, has said construction is set to begin in September, but the B.C. government has said only three of eight environment management plans have been accepted, preventing work from starting.

The Canadian Press

Managing Clubroot Infestation During Oil & Gas Production: What You Need to Know!

August 22, 2017August 22, 2017 by EnergyNow Media

Clubroot is a soil-borne disease that affects canola and vegetable crops in the Brassica family, including cauliflower, broccoli, and cruciferous weeds. Once established, it is tough to eradicate since the resting spores can persist in the soil for up to 20 years. Serious yield loss can occur as well as detrimental effects on oil quality. … Read more

Brazil prosecutors charge ex- Petrobras CEO in graft probe

August 22, 2017 by The Canadian Press

SAO PAULO — Prosecutors in Brazil have filed corruption and money laundering charges against a former CEO of the state oil company Petrobras for allegedly receiving bribes from a construction company.

Prosecutor Athayde Ribeiro Costa told reporters on Tuesday that Aldemir Bendine received the equivalent of more than $950,000 in bribes from construction conglomerate Odebrecht.

Odebrecht is at the centre of a massive kickback scheme that prosecutors say inflated contracts at Petrobras and other state companies.

Bendine was taken into custody late July. He served as Petrobras’ chief executive from 2015 to 2016 and before that was CEO at state-run bank Banco do Brasil from 2009 to 1015.

Costa said that if convicted, Bendine could be sentenced to 25 years in prison.

The Associated Press

Cub Energy Inc. Announces Q2 2017 Financial and Operational Results

August 22, 2017 by The Canadian Press

FOR: CUB ENERGY INC.TSX VENTURE SYMBOL: KUBDate issue: August 22, 2017Time in: 4:33 PM eAttention:
HOUSTON, TEXAS–(Marketwired – Aug. 22, 2017) – Cub Energy Inc. (“Cub” or the
“Company”) (TSX VENTURE:KUB), a Ukraine-focused upstream oil and gas compa…

Five Things World Business Will be Talking About Today

August 22, 2017 by EnergyNow Media

August 22, 2017 (Bloomberg) Trump backs Afghanistan expansion, Provident Financial slumps more than 60 percent, and top funds are doing well. Here are some of the things people in markets are talking about today. Play it again, Uncle Sam President Donald Trump’s new plan in Afghanistan – more troops, more pressure on Taliban supporters – may sound familiar … Read more

Oil Trades Near $47 as U.S. Stockpiles Seen Extending Drop

August 23, 2017August 22, 2017 by EnergyNow Media

August 22, 2017 (Bloomberg) Oil traded near $47 a barrel before data forecast to show a further reduction in U.S. crude inventories, which would signal that a global surplus is receding. Futures in New York were little changed after slumping 2.4 percent Monday. Inventories probably dropped by about 3.5 million barrels last week, according to … Read more

Efficiency gains fail to boost bottom line for Canadian oil and gas drillers

August 22, 2017August 21, 2017 by The Canadian Press

CALGARY — A new report suggests western Canadian oil and gas drillers are their own worst enemies because they have greatly increased drilling efficiency while revenues have fallen.

Analysts at GMP FirstEnergy say rigs are drilling more than a third deeper in an average day in 2017 than they were in 2014 but their average earnings per day has actually fallen by a quarter, from more than $26,000 in 2014 to less than $20,000 now.

The research represents more bad news for the industry because it suggests fewer rigs will be needed in the future, translating into fewer jobs and more rig retirements.

Mark Scholz, president of the Canadian Association of Oilwell Drilling Contractors, says the sector continues to struggle with poor drilling activity because of volatile oil prices that are stuck below US $50 per barrel.

He says so many skilled workers have quit the job since oil fell from over $100 per barrel in 2014 that hiring remains challenging.

The association reports there were only 234 rigs working on Monday out of a western Canadian fleet of more than 600. Each rig directly employs between 20 and 25 staff.

The Canadian Press

Oil Holds Near One-Week High as Libya’s Largest Field Disrupted

August 22, 2017August 21, 2017 by EnergyNow Media

August 21, 2017 (Bloomberg) Oil traded near the highest closing level in a week as Libya halted its biggest oilfield and Petro-Logistics SA said OPEC crude supply was on track for its biggest drop in five months. Futures fell 0.4 percent in New York after rising 3.7 percent the previous two sessions. Libya declared force … Read more

ACM Facility Safety: See Upcoming Course Schedule

August 21, 2017August 21, 2017 by EnergyNow Media

Today, ACM helps the world’s largest operating and engineering companies as they strive to make the world a safer place. However, our story started more than 40 years ago. Upcoming 2017 ACM Safety Training Courses: Synopsis Why take this course? Learn More Understand the implications and changes to the IEC 61511 international standard. F.S. ENG. … Read more

Introducing Drillform Technical Service’s Innovative Drilling Equipment: See Their EnergyNow SHOWCASE Video

August 21, 2017 by EnergyNow Media

Five Things World Business Will be Talking About Today

August 21, 2017 by EnergyNow Media

August 21, 2017 (Bloomberg) Total to buy Maersk oil assets, U.K. ups the Brexit rhetoric, and Trump to give an update on Afghanistan. Here are some of the things people in markets are talking about today. Monday deals Total SA agreed to purchase the oil and gas unit of A.P. Moller-Maersk A/S for $4.95 billion in shares. … Read more

NEW!! Energy Dialogues Podcast Series: Feature Guest: MNP LLP with Host David Yager

August 21, 2017 by EnergyNow Media

Sunshine Oilsands Ltd.: Voluntary Announcement – Increase in Shareholding in the Corporation by Non-Executive Vice Chairman

August 20, 2017 by The Canadian Press

FOR: SUNSHINE OILSANDS LTD.HKSE SYMBOL: 2012Date issue: August 21, 2017Time in: 5:29 AM eAttention:
CALGARY, ALBERTA and HONG KONG, CHINA–(Marketwired – Aug. 21, 2017) – The
Board of Directors of Sunshine Oilsands Ltd. (the “Corporation” or “Sunshine…

B.C. premier and jobs minister sued by fired LNG advocate claiming $5 million in damages

August 21, 2017August 18, 2017 by The Canadian Press

VANCOUVER — British Columbia’s fired liquefied natural gas advocate is suing Premier John Horgan, the province’s jobs minister and a New Democrat MP in a lawsuit claiming $5 million in damages.

Gordon Wilson alleges in a statement of claim filed in B.C. Supreme Court that Horgan made defamatory statements to news media earlier this month by saying there’s no evidence of any written reports or briefings to back up his salary.

The statement of claim says Jobs Minister Bruce Ralston told a media outlet Wilson’s contract was terminated because an internal review uncovered no documents to support $550,000 in payments since 2013.

Wilson also quotes in the claim a Facebook post by British Columbia MP Rachel Blaney in which she implies taxpayers money could have been used to meet other needs, such as housing.

Wilson says in his claim that information detailing his work on LNG was available on a government website but was negligently or wilfully overlooked and neither Horgan nor Ralston discussed any employment issues with him.

Horgan cited the court case in declining comment, Ralston wasn’t available for comment and Blaney could not be reached on Friday.

Ralston and Blaney say in separate Facebook posts their claims about there being no written reports were inaccurate, they regretted making the statements and apologize to Wilson.

No statements of defence have been filed and none of the allegations made in the statement of claim have been tested in court.

Wilson asserts that his termination soon after the NDP’s election victory was “political payback” for his support of former premier Christy Clark, who appointed him as LNG advocate.

The statement of claim alleges Wilson has been seriously injured in character, credit and reputation and the comments have negatively affected his ability to obtain employment as a government or industry consultant or advocate.

The Canadian Press

Oil Sands Trade Show returns to Fort McMurray for 2017

August 18, 2017 by EnergyNow Media

Oil Sands Trade Show and Conference (OSTS) is returning to Fort McMurray and will offer attendees expertise and insights from all aspects of the oil sands industry in one setting. This premier oil sands event takes place Tuesday, September 12 to Wednesday, September 13 at the Suncor Community Leisure Centre in Fort McMurray. OSTS will focus … Read more

The False Fear That Stops Leaders from Firing Bad Fit Employees – Sandler Training

August 21, 2017August 18, 2017 by EnergyNow Media

Written by Hamish Knox; President of Sandler in Calgary, Canada Creating accountable, sales focused organizations in Calgary One of the guarantees I give my prospects is, “you will have turnover if we work together.” In fact one of my clients several years ago had 100% turnover in the first 12 months of … Read more

To Obtain and Keep Customers, Create Emotional Connections

August 19, 2017August 18, 2017 by EnergyNow Media

Today’s energy industry is dynamic. Amidst fluctuating economies, those operating in the oil and gas sector are having to focus more on business, and less on consumers. What smart businesses recognize, though, is that behind every coalition, partnership, and purchase, are people. Connecting with consumers and clients in both a B2B and B2C context is … Read more

CPPIB part of group buying US power producer Calpine Corp. for US$5.6B

August 18, 2017 by The Canadian Press

TORONTO — The Canada Pension Plan Investment Board is part of a group of investors buying U.S. power producer Calpine Corp. for US$5.6 billion.

The board said the all cash transaction, for which it’s putting up US$750 million, helps add power and renewable assets to its expanding natural resources portfolio.

The deal, advised by Energy Capital Partners, will give CPPIB a stake in Houston-based Calpine, which has 80 power plants in operation or under construction and enough natural gas and renewable capacity to power about 20 million homes.

Calpine has operations in 18 states, including 13 geothermal geyser assets in northern California, as well as a partial interest in two generation stations in southwestern Ontario.

The Canadian Press

NAFTA’s environmental arm demands Canada explain oilsands tailings leaks

August 21, 2017August 18, 2017 by The Canadian Press

OTTAWA — The environmental arm of NAFTA is demanding Canada explain what it is doing to stop oilsands tailings ponds from leaking into Alberta waterways.

The request comes in a decision by the Commission for Environmental Co-operation, which oversees the environmental pact Canada, the United States and Mexico signed as a parallel agreement to NAFTA.

Canada has until Sept. 28 to officially respond to allegations it is failing to enforce the Fisheries Act by allowing contaminants from the ponds to leak into water without forcing the companies involved to fix the problem.

The complaint was made in June by Canada’s Environmental Defence group and the Natural Resources Defense Council based in the United States.

Environmental Defence executive director Tim Gray says studies have suggested as much as 11 million litres of tailings water containing substances like benzene, arsenic and cyanide leaks into the Athabasca River every day.

The government’s response will be studied by a commission panel made up of members from the three countries and if they decide Canada is violating the law Gray says the next step would be to go to court to force Canada to act.

The Canadian Press

Five Things World Business Will be Talking About Today

August 18, 2017 by EnergyNow Media

August 18, 2018 (Bloomberg) Terror attacks hit Spain, risk aversion spikes in markets, and key Republicans increase the pressure on Trump. Here are some of the things people in markets are talking about today. Terror attacks A terrorist rammed a vehicle into tourists in the Spanish city of Barcelona yesterday in an attack that killed 13 people … Read more

Oil Set for Third Weekly Drop as Rising U.S. Output Blunts Cuts

August 18, 2017August 18, 2017 by EnergyNow Media

August 18, 2017 (Bloomberg) Oil headed for a third weekly drop as U.S. crude output rose to a two-year high and Chinese refining slowed, signs that the world’s two biggest consumers may stymie OPEC-led efforts to trim a global glut. Futures were little changed in New York, down 3.3 percent for the week. U.S. production … Read more

Do You Have it? The Defining Characteristic of Great Business Owners & Leaders: Read More HERE

August 18, 2017August 17, 2017 by EnergyNow Media

Courageous leaders inspire employees, energize customers, and position their companies on the front lines of societal change. Bill George explains why there aren’t more of them. by Bill George Courage is the quality that distinguishes great business owners and leaders from excellent managers. Over the past decade, I have worked with and studied more than 200 CEOs of … Read more

Alberta trade minister says NAFTA talks no threat to oil and gas industry

August 17, 2017August 17, 2017 by The Canadian Press

CALGARY — Alberta’s minister of trade says Canada’s oil and gas industry has little to worry about as wide-ranging North American trade negotiations get underway.

Speaking Thursday after a conference of state governments in Tacoma, Wash., Minister Deron Bilous said U.S. lawmakers recognize the importance of an integrated energy market.

He said Alberta government representatives have been meeting with U.S. counterparts regularly to emphasize the importance of market access and open borders, and he’s been encouraging industry members to do the same.

Bilous said efforts in recent months were helpful in effectively killing the proposal for a border adjustment tax, which could have set tariffs for oil and gas imports from Canada and presented one of the biggest trade threats to the industry.

He said the provincial government is also pushing for more open borders for agriculture and other products, and the need to harmonize regulations to speed up the flow of goods.

The minister’s comments come a day after NAFTA trade negotiations kicked off in Washington, D.C., with dozens of topics set to be covered in the talks.

The Canadian Press

Enbridge Announces Conversion Results for Series L Preferred Shares

August 17, 2017 by The Canadian Press

FOR: ENBRIDGE INC.TSX SYMBOL: ENBNYSE SYMBOL: ENBDate issue: August 17, 2017Time in: 6:55 PM eAttention:
CALGARY, ALBERTA–(Marketwired – Aug. 17, 2017) – Enbridge Inc. (TSX:ENB)
(NYSE:ENB) (Enbridge or the Company) announced today that after having t…

Five Things World Business Will be Talking About Today

August 17, 2017 by EnergyNow Media

August 16, 2017 (Bloomberg) Metals soar, Alibaba reports, and it’s jobs day in Australia. Here are some of the things people in markets are talking about. Turn Up the Base An index of primary metals hit its highest level since November 2014 on Wednesday, with zinc rising above $3,000 per metric ton. As such, materials stocks … Read more

Shale Will Beat OPEC as U.S. Oil Thrives at $40, Citigroup Says

August 17, 2017August 17, 2017 by EnergyNow Media

August 15, 2017 (Bloomberg) U.S. shale oil will prevail over OPEC as the two rivals compete in an oversupplied world market, Citigroup Inc.’s head of research said. The Organization of Petroleum Exporting Countries and its allies may have boosted oil prices by cutting production, but they’re losing revenue in the process and their position “is … Read more

Canadian Home Prices Tumble Most Since 2008 Recession on Toronto

August 17, 2017 by EnergyNow Media

August 15, 2017 (Bloomberg) Canada’s benchmark home price fell by the most in nearly a decade last month as Toronto led a fourth-straight decline in sales. The nationwide benchmark home price declined 1.5 percent from June, the Canadian Real Estate Association said Tuesday, the largest drop since the previous recession. In Toronto, the country’s largest … Read more

Worst May Be Behind for Energy Borrowers Facing Loan Renewals

August 18, 2017August 17, 2017 by EnergyNow Media

August 16, 2017 (Bloomberg) Don’t expect too much bad news when banks complete their assessment in October of the amount of credit they will continue offering to distressed energy companies. About six to 12 E&P and oilfield-services firms may file for bankruptcy during the rest of the year, projects Haynes & Boone partner Buddy Clark, … Read more

Five Things World Business Will be Talking About Today

August 17, 2017 by EnergyNow Media

Oil Holds Near 3-Week Low as U.S. Output Climbs to Two-Year High

August 18, 2017August 17, 2017 by EnergyNow Media

August 17, 2017 (Bloomberg) Oil held losses near the lowest close in more than three weeks as investors weighed expanding U.S. crude output against an extended decline in stockpiles during a period of strong seasonal demand. Futures were 0.4 percent lower in New York after falling 4.2 percent the previous three sessions. U.S. production had its biggest weekly … Read more

Hazloc Heaters Introduces New Models and Options on the AEU1 Explosion-Proof Electric Air Heaters

September 4, 2017August 16, 2017 by EnergyNow Media

Calgary, Alberta, Canada: August 16, 2017 Hazloc HeatersTM, a leading manufacturer of industrial unit heaters for hazardous and severe-duty locations, is pleased to announce the introduction of new 230V models, built-in thermostats, built-in disconnect switch and continuous fan options available on the AEU1 series of Explosion-Proof Electric Air Heaters. The AEU1 series of unit heaters … Read more

Oilfield Services Recovery Underway for the First Half of 2017, At Least for Revenue – David Yager – Yager Management

August 17, 2017August 16, 2017 by EnergyNow Media

David Yager – Yager Management Ltd. Oilfield Services Executive Advisory – Energy Policy Analyst August 16, 2017 It doesn’t feel that great. Based on the share prices for most of the publicly traded oilfield service (OFS) companies it doesn’t look that great either. But at least as measured by revenue, the financial performance of 16 … Read more

Want to Attract (and Keep) New Employees? You’ve Only Got One Chance for a Great First Impression – Wendy Ferguson – BHRLR, CPHR

July 20, 2022August 16, 2017 by EnergyNow Media

A Commentary by Wendy Ferguson – BHRLR, CPHR – Ferguson HR Consulting Creating a positive first impression through the use of an effective and engaging new orientation program is critical to your organization. For many new hires, what they experience the first day on the job will remain with them throughout the duration of their … Read more

Five Things World Business Will be Talking About Today

August 16, 2017 by EnergyNow Media

August 16, 2017 (Bloomberg) U.K. unemployment, European growth and Fed minutes. Here are some of the things people in markets are talking about today. 42-year low Unemployment in the United Kingdom fell to 4.4 percent in the second quarter, the lowest since 1975, with basic wages rising 2.1 percent — more than economists had forecast. While the … Read more

Freeland Says Canada Won’t Take Just Any Deal in Nafta Talks

August 16, 2017August 16, 2017 by EnergyNow Media

August 14, 2017 (Bloomberg) Foreign Affairs Minister Chrystia Freeland laid out Canada’s core objectives for North American Free Trade Agreement negotiations that begin this week and signaled the country won’t accept “just any deal.’’ Speaking Monday in Ottawa, Freeland said she hopes the three sides — the U.S., Canada and Mexico — can keep what is … Read more

Oil Halts Slide Near $48 on Signs U.S. Stockpiles Extended Drop

August 16, 2017August 16, 2017 by EnergyNow Media

August 16, 2017 (Bloomberg) Oil halted its slide near $48 a barrel as industry data showed U.S. crude stockpiles declined again, further trimming an inventory surplus. Futures rose 0.3 percent in New York after slipping a second session Tuesday. Inventories dropped by 9.2 million barrels last week, the American Petroleum Institute was said to report. If that … Read more

Deal: Mocoat Solutions Acquires FRP Manufacturing – Effective Immediately

August 16, 2017August 16, 2017 by EnergyNow Media

August 16, 2017 Mocoat Solutions is pleased to announce that it has acquired FRP Manufacturing Ltd, a fibreglass storage tank fabrication company based in Asquith, Saskatchewan. The deal is effective immediately. “Our acquisition of FRP Manufacturing allows us better control over the manufacturing process and gives us the ability to leverage that into significant growth … Read more

Strategic Oil & Gas Ltd. Announces Second Quarter 2017 Financial Results and Provides Operations Update

August 16, 2017August 16, 2017 by The Canadian Press

FOR: STRATEGIC OIL & GAS LTD
TSX VENTURE SYMBOL: SOG

Date issue: August 16, 2017
Time in: 6:00 AM e

Attention:

CALGARY, ALBERTA–(Marketwired – Aug. 16, 2017) – Strategic Oil & Gas Ltd.
(“Strategic” or the “Company”) (TSX VENTURE:SOG in Strategic’s interim
unaudited consolidated financial statements and related Management’s Discussion
and Analysis (“MD&A”) which will be available through the Company’s website at
www.sogoil.com and on SEDAR at www.sedar.com.

Highlights for the second quarter include:

/T/

— Completed and placed five new Muskeg horizontal wells on production,

increasing average production volumes by 17% from the first quarter of
2017;
— Funds from operations increased 26% to $3.0 million from $2.4 million
for the first quarter of 2017;
— Maintained a strong cash position with $29.0 million in adjusted working
capital at June 30, 2017;
— Fracked Muskeg well 15-34 in the third quarter. Initial results are
encouraging; the well will be tied in and placed on production in August
2017;
— Drilled two additional horizontal wells as a part of the summer drilling
program. The two new wells are expected to be fracture stimulated in
September.

/T/

FINANCIAL AND OPERATIONAL SUMMARY

/T/

Three months ended Six months ended
June 30 June 30
—————————————————————————-
Financial ($thousands,
except per share % %
amounts) 2017 2016 change 2017 2016 change
—————————————————————————-
Oil and natural gas
sales 10,312 5,974 73 19,200 10,679 80
Funds from (used in)
operations (1) 2,991 440 580 5,374 (1,740) –
Per share basic (1)
(3) 0.06 0.02 200 0.12 (0.06) –
Cash provided by (used
in) operating
activities 1,828 3,820 (52) 1,879 2,345 (20)
Per share basic (3) 0.04 0.14 (71) 0.04 0.09 (67)
Net loss (2) (7,020) (5,800) 21 (11,460) (9,283) 23
Per share basic (3) (0.15) (0.21) (29) (0.25) (0.34) (26)
Net capital
expenditures 12,784 1,152 1,010 30,851 9,449 227
Adjusted working
capital (comparative
figure is as of
December 31, 2016)
(1) 29,045 49,956
(42) 29,045 49,956 (42)
Net debt (comparative
figure is as of
December 31, 2016)
(1) 75,875 51,141 48 75,875 51,141 48
—————————————————————————-
Operating
—————————————————————————-
Average daily
production
Crude oil (bbl per
day) 1,942 1,396 39 1,786 1,471 21
Natural gas (mcf per
day) 4,317 2,598 66 4,096 2,566 60
Barrels of oil
equivalent (boe per
day) 2,661 1,829 46 2,468 1,899 30
Average prices
Oil & NGL ($ per
bbl) 51.69 44.27 17 52.68 36.89 43
Natural gas ($ per
mcf) 3.00 1.48 103 2.93 1.72 70
Operating netback ($
per boe) (1)
Oil and natural gas
sales 42.58 35.89 19 42.97 30.90 39
Royalties (4.61) (4.27) 8 (5.03) (3.83) 31
Operating expenses (19.05) (21.45) (11) (18.83) (21.96) (14)
Transportation
expenses (0.94) (0.78) 21 (1.17) (0.75) 56
—————————————————————————-
Operating Netback (1) 17.98 9.39 92 17.94 4.36 311
—————————————————————————-
Common Shares
(3)(thousands)
—————————————————————————-
Common shares
outstanding, end of
period 46,388 27,116 71 46,388 27,116 71
Weighted average
common shares (basic
& diluted) 46,384 27,116 71 45,969 27,116 70
—————————————————————————-
—————————————————————————-
(1) Funds from operations, adjusted working capital, net debt and operating
netback are Non-GAAP measures; see “Non-GAAP measures” in the Company’s
MD&A.
(2) The comparative condensed statement of loss for the six months ended
June 30, 2016 has been adjusted to reflect a $3.8 million adjustment to
deferred tax recovery related to the issuance of convertible
debentures.
(3) Adjusted for the share consolidation on a 20:1 basis announced on March
6, 2017.

/T/

QUARTERLY SUMMARY

/T/

— Capital expenditures of $12.7 million were incurred in the quarter,

primarily on completion and related surface equipping costs for five
horizontal Muskeg wells and drilling the 15-34 horizontal Muskeg well at
north Marlowe.

— Average daily production increased 46% from the second quarter of 2016,

and 17% from the first quarter of 2017 to 2,661 boe/d for the three
months ended June 30, 2017, primarily due to new production from the
winter Muskeg drilling program. Average daily production increased 30%
from 1,899 boe/d for the six months ended June 30, 2016 to 2,468 boe/d
the six months ended June 30,
2017 due to production from the Company’s fall 2016 and winter 2017
drilling programs coming online.

— Funds from operations increased significantly to $3.0 million and $5.4

million for the three and six months ended June 30, 2017 from funds from
operations of $0.4 million for the second quarter of 2016 and funds used
in operations of $1.7 million for the six months ended June 30, 2016, as
higher commodity prices and production led to a $4.3 million increase in
revenues for the quarter and $8.5 million increase in revenues for the
six months ended June 30, 2017.

— New oil volumes coming online from the five-well drilling program

contributed to lower operating costs on a per boe basis. Unit operating
costs decreased to $19.05/boe and $18.83/boe for the three and six
months ended June 30, 2017 from $21.45/boe and $21.96/boe for the
comparable periods in 2016. These reductions were partially offset by
higher transportation costs due to increased natural gas production and
oil trucking charges caused by a temporary shutdown of the Rainbow
pipeline. Unit general and administrative costs also decreased to
$5.48/boe and $5.83/boe for the three and six months ended June 30, 2017
from $7.09/boe and $7.52/boe for the comparable periods in 2016 due to
increased production.

— Strategic maintained capital discipline in the current uncertain oil

pricing environment, as capital expenditures approximated guidance for
the first half of 2017 despite some escalation in service costs during
the period. At June 30, 2017, the Company had $29.7 million in cash and
$29.0 million in adjusted working capital.

— Operating netbacks increased to $17.98/boe and $17.94/boe for the three

and six months ended June 30, 2017 compared to $9.38/boe and $4.36/boe
for the comparable periods in 2016 primarily due to higher commodity
prices and production levels, combined with lower unit operating
expenses.

— As a result of higher production levels, unit operating costs decreased

11% for the second quarter of
2017 compared to the second quarter of 2016. General and administrative
(“G&A”) expenses per boe fell by 23% for the same time period.

/T/

PERFORMANCE OVERVIEW, STRATEGY AND OUTLOOK

During the second quarter, Strategic continued to execute its first half
capital program which included drilling six horizontal Muskeg wells and the
construction of a four kilometre pipeline to tie-in the 14-35 Muskeg well. The
Company spent $30.9 million to drill six and complete five wells during the
first half as compared to the budget of $30 million to drill and complete six
wells. Five of the six wells drilled during the first quarter were fracture
stimulated and tied-in midway through the second quarter and the sixth well was
completed in the third quarter.

Like many operators in western Canada, Strategic was unable to secure frac
services in the first quarter of 2017 resulting in significant delays in adding
new production volumes during the first half of 2017. Even with the production
growth limited to the latter part of the second quarter, the Company did
achieve a 17% increase in production from the first quarter.

With five of the six wells fracked and tied in production peaked over 4,000
boe/d in the second quarter. Simultaneous flow-back of five new wells increased
pipeline pressure, which curtailed the peak rates from the new Muskeg wells and
also backed out some existing base production. Further, due to maintenance and
upgrades on Alberta’s main natural gas sales pipeline, Strategic had to shut in
600 boe/d of production by shutting in certain oil and gas wells for nearly two
weeks in June.

Initial production rates for eight recent Muskeg wells are as follows:

/T/

—————————————————————————-
—————————————————————————-

IP30 IP60
—————————————————————————-
—————————————————————————-
Well Date BOPD BOEPD % Oil BOPD BOEPD % Oil
—————————————————————————-
—————————————————————————-
2-13 Q4-16 397 712 56% 294 529 56%
—————————————————————————-
14-12 Q4-16 294 340 86% 247 309 80%
—————————————————————————-
14-35 Q1-17 379 794 48% 275 614 45%
—————————————————————————-
5-12 Q2-17 118 127 93% 120 130 92%
—————————————————————————-
11-12 Q2-17 133 143 93% 152 177 86%
—————————————————————————-
13-01 Q2-17 221 257 86% 190 250 76%
—————————————————————————-
02/13-01 Q2-17 198 238 83% 177 234 76%
—————————————————————————-
16-35 Q2-17 241 248 97% 221 268 82%
—————————————————————————-
—————————————————————————-
Average 248 357 69% 210 314 67%
—————————————————————————-
—————————————————————————-

(1) Includes producing days only.
(2) Five Muskeg wells were brought on production during May due to delays
in obtaining frac services during the first quarter of 2017. The
initial peak production of the five wells 5-12, 11-12, 13-01, 02/13-
01 and 16-35 was somewhat affected by pipeline pressures which spiked
up during May and June due to simultaneous flow-back of five new
wells.

/T/

A graph of the average production from the wells drilled in 2016 (on-stream in
the fourth quarter of 2016 and the first quarter of 2017) and the wells drilled
in 2017 and brought on-stream in the second quarter is as follows:

http://www.marketwire.com/library/20170816-1100964-Graph-gr.png

Strategic’s capital expenditure plan for 2017 had contemplated bringing two new
wells on-stream per month from March to May 2017 in order to manage pipeline
pressures and maximize average production volumes for the second quarter. Due
to delays in completions all five new wells were brought online in May 2017 and
the flow back of the five new wells resulted in an increase in line pressures
which had an adverse impact on initial production volumes from all wells on the
west Marlowe pipeline. The Company intends to use higher capacity pumps on
future wells. In addition, Strategic installed temporary field compression on
one of its pads at west Marlowe and the system installed was effective at
reducing casing pressures and significantly increasing oil and gas production
from the related well to volumes consistent with the 2016 wells. These efforts,
while causing additional well downtime and higher operating costs in this
quarter, should enhance productivity on future drilling programs.

The Company is actively developing its asset base in the third quarter and has
recently executed a 40 stage completion on the Muskeg well drilled during the
second quarter. This well is located in north Marlowe where pipeline pressures
are lower compared to west Marlowe. Initial results are encouraging; the well
will be tied in and placed on production in August 2017. The Company drilled
two other horizontal wells in July, which will also be completed and tied in
during the third quarter of 2017.

Corporate production at the end of the second quarter was approximately 3,000
boe/d. The Company has experienced ongoing production curtailments totaling 17
days in July and August. Strategic has been notified of additional third party
restrictions due to pipeline maintenance of up to 15 days in September. As a
result of these restrictions and a scheduled 8-day plant turnaround, corporate
production volumes for the third quarter of 2017 are estimated to be 2,400
boe/d. Production is expected to be 3,500 boe/d once the curtailments have been
lifted and all wells are brought back online. Given the external limitations on
corporate sales volumes, Strategic elected to defer the last two wells in its
summer drilling program and reduced estimated capital spending for the third
quarter from $24 million to $16 million.

About Strategic

Strategic is a junior oil and gas company committed to becoming a premier
northern oil and gas operator by exploiting its light oil assets primarily in
northern Alberta. The Company relies on its extensive subsurface and reservoir
experience to develop its asset base and grow production and cash flows while
managing risk. The Company maintains control over its resource base through
high working interest ownership in wells, construction and operation of its own
processing facilities and a significant undeveloped land and opportunity base.
Strategic’s primary operating area is at Marlowe, Alberta. Strategic’s common
shares trade on the TSX Venture Exchange under the symbol SOG.

ADDITIONAL INFORMATION

Additional information is also available at www.sogoil.com and at www.sedar.com.

Reader Advisories

Any references in this news release to initial production or test rates are
useful in confirming the presence of hydrocarbons, however, such rates are not
necessarily determinative of the rates at which such wells will continue
production. These flow-back, initial production or test results are quoted on a
raw basis before shrinkage on natural gas volumes and may not be indicative of
long-term well performance or ultimate recovery. While encouraging, readers are
cautioned not to place reliance on such rates in estimating the aggregate
production for the Company. Total corporate production volumes include natural
gas shrinkage.

Forward-Looking Statements

This news release includes certain information, with management’s assessment of
Strategic’s future plans and operations, and contains forward-looking
statements which may include some or all of the following: (i) anticipated
production rates and productivity of future drilling programs; (ii) expected
operating costs and the impact of production levels on unit operating and G&A
costs; (iii) expected capital spending and wells to be drilled; (iv) the
Company’s financial strength and capitalization; (v) estimates of timing for
pipeline maintenance and turnarounds and their effect on production; which are
provided to allow investors to better understand the Company’s business. By
their nature, forward-looking statements are subject to numerous risks and
uncertainties; some of which are beyond Strategic’s control, including the
impact of general economic conditions, industry conditions, volatility of
commodity prices, currency fluctuations, imprecision of reserve estimates,
environmental risks, changes in environmental tax and royalty legislation,
competition from other industry participants, the lack of availability of
qualified personnel or management, stock market volatility and ability to
access sufficient capital from internal and external sources, and other risks
and uncertainties described under the heading ‘Risk Factors’ and elsewhere in
the Company’s Annual Information

Form for the year ended December 31, 2016 and other documents filed with
Canadian provincial securities authorities, available to the public at
www.sedar.com. Readers are cautioned that the assumptions used in the
preparation of such information, although considered reasonable at the time of
preparation, may prove to be imprecise and, as such, undue reliance should not
be placed on forward -looking statements. The principal assumptions Strategic
has made includes security of land interests; drilling cost stability; royalty
rate stability; oil and gas prices to remain in their current range; finance
and debt markets continuing to be receptive to financing the Company and
industry standard rates of geologic and operational success. Actual results
could differ materially from those expressed in, or implied by, these
forward-looking statements. Strategic disclaims any intention or obligation to
update or revise any forward-looking statements, whether as a result of new
information, future events or otherwise, except as required by law.

Basis of Presentation

This discussion and analysis of Strategic’s oil and natural gas production and
related performance measures is presented on a working-interest, before
royalties basis. For the purpose of calculating unit information, the Company’s
production and reserves are reported in barrels of oil equivalent (boe) and boe
per day (boed). Boe may be misleading, particularly if used in isolation. A boe
conversion ratio for natural gas of 6 Mcf: 1 boe has been used, which is based
on an energy equivalency conversion method primarily applicable at the burner
tip and does not necessarily represent a value equivalency at the wellhead. As
the value ratio between natural gas and crude oil based on the current prices
of natural gas and crude oil is significantly different from the energy
equivalency of 6:1, utilizing a conversion on a 6:1 basis may be misleading as
an indication of value.

Non-GAAP Measurements

The Company utilizes certain measurements that do not have a standardized
meaning or definition as prescribed by IFRS and therefore may not be comparable
with the calculation of similar measures by other entities, including net debt,
operating netback and funds from operations. Readers are referred to advisories
and further discussion on non-GAAP measurements contained in the Company’s MD&A.

– END RELEASE – 16/08/2017

For further information:
Strategic Oil & Gas Ltd.
Gurpreet Sawhney, P. Eng
President and CEO
403.767.2949
403.767.9122 (FAX)
OR
Strategic Oil & Gas Ltd.
Aaron Thompson, CPA, CA
CFO
403.767.2952
403.767.9122 (FAX)
www.sogoil.com

COMPANY:
FOR: STRATEGIC OIL & GAS LTD
TSX VENTURE SYMBOL: SOG

INDUSTRY: Energy and Utilities – Oil and Gas
RELEASE ID: 20170816CC0002

Press Release from Marketwired 1-866-736-3779

NAFTA energy clause draws criticism from Canadian voices on the right and left

August 16, 2017August 15, 2017 by The Canadian Press

CALGARY — As NAFTA 2.0 negotiations begin, an old trade issue with a strange name has emerged to create unlikely allies across the political spectrum and staunch defenders in the oilpatch.

The “proportionality clause” originally appeared in the Canada-U.S. Free Trade Agreement of 1988 and became a major issue in that year’s federal election that returned Prime Minister Brian Mulroney to office. It was replicated six years later in the North American Free Trade Agreement (although Mexico won an exemption).

The clause can be invoked if a government in Canada reduces U.S. access to Canadian oil, natural gas, coal, electricity and refined petroleum products without a corresponding reduction in domestic access to those products — in other words, the ratio of energy exports versus supply must remain consistent, or proportional.

The left-leaning Council of Canadians says the clause erodes sovereignty and gives the U.S. too much control over Canadian energy production.

The business-friendly Conference Board of Canada says the clause is an outdated restriction that isn’t needed in today’s energy-rich world and should be cast aside.

“What happened with NAFTA is that Canadian oil and gas became North American oil and gas and we have very little control of it,” said Maude Barlow, honorary chair of the Council of Canadians, in an interview.

“We feel very strongly this is a chance to reopen what should never have been signed in the first place.”

She said the proportionality clause could allow the U.S. to prevent Canada from choking back oilsands production to meet its international environmental commitments, for instance, or to interfere if Canada tries to keep more oil and gas for domestic use during an energy shortage.

Michael Burt, a director with the Conference Board, said the clause isn’t fair because it doesn’t cover Mexico, whose energy industry is being opened to private investment after decades of government ownership.

“Evidence would suggest that it hasn’t really been a binding constraint at any point in the 25 years of NAFTA,” he added.

“It’s not really adding any value and it’s taking away potential future flexibility in terms of policy responses, whether it’s to a crisis or to climate change mediation.”

While the Canadian think-tanks oppose the clause in submissions to the federal government, the energy industry itself prefers it to an alternative that could include government meddling in energy markets.

“It was put in there basically as a ‘good neighbour’ clause,” said Nick Schultz, vice-president and general counsel at the Canadian Association of Petroleum Producers, who was involved in free trade negotiations in the 1980s as an Ottawa trade lawyer.

“It’s not the evil thing that people have long tried to characterize it as. It’s simply saying … treat your customers fairly.”

He said the clause was created following global oil supply crises in the 1970s and the imposition of the National Energy Program in Canada in 1980. The NEP aimed to promote Canadian energy security by favouring domestic over export markets but was blamed for throwing Canada’s energy industry into a deep downturn.

Schultz pointed out that proportionality protects energy consumers on both sides of the border — as more U.S. oil products and natural gas replace western Canadian and offshore supplies in Eastern Canada, it will protect Canadian importers from arbitrary U.S. export cuts.

In U.S. President Donald Trump’s list of objectives for the NAFTA talks released in July, there’s no mention of proportionality. The one paragraph on energy policy lists general goals, including North American energy security and strong markets.

The clause is receiving very little attention in the U.S., said Robert Holleyman, the CEO of trade consulting firm C&M International and a former U.S. trade negotiator in the Obama administration.

But that doesn’t mean it’s not important, he said.

“It ensures a certain level of North American market security because it ensures that U.S. dependence and reliance on Canada to supply some of our energy needs is largely predictable,” he said.

“I suspect the U.S. will not want to give this up.”

He said if Canada wants to drop the clause, it would likely have to offer substantial trade-offs in negotiations. The clause seems to be working and, therefore, should probably not be removed, he added.

Canada’s position on proportionality is unclear. It wasn’t one of the priorities mentioned by Foreign Affairs Minister Chrystia Freeland in a statement Monday.

Her office did not immediately respond to a request Tuesday to clarify Canada’s stance.

Follow @HealingSlowly on Twitter.

Dan Healing, The Canadian Press

Detecting Fraud in the Time of $45 Oil – MNP LLP

August 16, 2017August 15, 2017 by EnergyNow Media

Oilfield Service News August 15, 2017 Executives in the oil and gas industry looking for savings on their bottom line in the wake of lower crude oil prices may be surprised to find evidence of fraud in their companies. However, Michael McCormack, MNP Senior Manager, Investigative and Forensic Services, says a lot can be done … Read more

Government gives OK, but companies must actually build pipelines: minister

August 15, 2017 by The Canadian Press

OTTAWA — Natural Resources Minister Jim Carr defended on Tuesday his government’s ability to get major resource projects moving, saying the government has approved a number of proposals and it’s up to their proponents to get them built.

Carr was speaking at the end of a meeting of federal and provincial energy ministers in New Brunswick, where TransCanada’s Energy East pipeline project was an unofficial topic of discussion.

It has been almost a year since the first round of National Energy Board hearings on Energy East collapsed after protesters shut down Montreal hearings and accused the panellists of bias in favour of the oil industry.

In January the board started the whole review process from scratch and appointed a new, three-member panel to conduct the hearings. New hearings haven’t yet been scheduled as the NEB is still designing how the new hearing process will work.

Energy East is a 4,500-km pipeline to carry 1.1 million barrels of oil a day from Alberta and Saskatchewan to refineries in Montreal and New Brunswick. The project includes converting an existing natural gas pipeline to carry crude and building new segments of pipeline to complete the route.

Carr said the government has now provided certainty to the review process.

“We’ve given the NEB the resources it needs. We have appointed new commissioners. They’re in their midst now, we’ll wait until they make their recommendations. That’s restoring confidence among Canadians that the process is working.”

He denied that the government’s requirement to balance the economics of oil and gas development with environmental protections and indigenous consultation was grinding things to a halt.

He listed five projects the Liberal government approved or has supported since taking office, including the Pacific Northwest Liquefied Natural Gas pipeline and terminal in B.C., Kinder Morgan’s TransMountain pipeline expansion between Alberta and B.C., Enbridge’s Line 3 replacement, expanding TransCanada’s Nova Gas Transmission gathering system in Alberta and the Keystone pipeline proposal awaiting approval in the U.S.

He said the government believes all of them are “good for Canada.”

“We believe we made those decisions in the balance of interests for Canada,” he said. “We stand by those decisions. It’s now up to the proponents to determine the timing of construction and eventually what will flow through the infrastructure.”

However three of the five projects he listed have either fallen apart or face significant hurdles.

Earlier this summer, Malaysian energy giant Petronas pulled up stakes on its planned liquefied natural gas pipeline and terminal in British Columbia, citing poor market conditions.

Kinder Morgan’s TransMountain pipeline expansion between Alberta and British Columbia was given the green light in the fall of 2016 and was supposed to start construction next month. However the new NDP government in B.C. moved last week to join legal challenges against the pipeline, after campaigning on a pledge to do whatever it took to stop the project.

Nebraska is currently holding hearings to determine if it will allow Keystone to proceed across its territory.

Battles over pipelines in Canada are largely at the provincial level. B.C. and Alberta are on opposite sides when it comes to the TransMountain project. Ontario and Quebec don’t support the Energy East pipeline, which is backed by Alberta, Saskatchewan and New Brunswick.

New Brunswick Energy Minister Rick Doucet said Energy East was on his mind at the meeting and he raised it with a number of his provincial colleagues.

“This is a nation-builder. This pipeline is an opportunity for all of Canada and we all understand the importance of this project,” said Doucet.

-follow @mrabson on Twitter.

Mia Rabson, The Canadian Press

Storm Resources Ltd. is Pleased to Announce Its Financial and Operating Results for the Three and Six Months Ended June 30, 2017

August 15, 2017August 15, 2017 by The Canadian Press

FOR: STORM RESOURCES LTD.
TSX VENTURE SYMBOL: SRX

Date issue: August 15, 2017
Time in: 7:32 PM e

Attention:

CALGARY, ALBERTA–(Marketwired – Aug. 15, 2017) – Storm Resources Ltd. (TSX
VENTURE:SRX)

Storm has also filed its unaudited condensed interim consolidated financial
statements as at June 30, 2017 and for the three and six months then ended
along with Management’s Discussion and Analysis (“MD&A”) for the same period.
This information appears on SEDAR at www.sedar.com and on Storm’s website at
www.stormresourcesltd.com.

Selected financial and operating information for the three and six months ended
June 30, 2017 appears below and should be read in conjunction with the related
financial statements and MD&A.

Highlights

/T/

Three Three Six Months
Thousands of Cdn$, except Months to Months to Six Months to
volumetric and June 30, June 30, to June June 30,
per-share amounts 2017 2016 30, 2017 2016
—————————————————————————-
FINANCIAL
Revenue from product
sales(1) 27,317 13,870 64,362 29,992
—————————————————————————-
Funds flow 11,629 5,781 29,587 13,636
Per share – basic and
diluted ($) 0.10 0.05 0.24 0.11
—————————————————————————-
Net income (loss) 9,752 (20,493) 30,383 (25,477)
Per share – basic and
diluted ($) 0.08 (0.17) 0.25 (0.21)
—————————————————————————-
Operations capital
expenditures(2) 4,307 613 31,664 24,559
—————————————————————————-
Debt including working
capital deficiency(2)(3) 90,582 71,254 90,582 71,254
—————————————————————————-
Common shares (000s)
Weighted average – basic 121,557 119,929 121,500 119,761
Weighted average – diluted 121,682 119,929 121,702 119,761
Outstanding end of period
– basic 121,557 120,179 121,557 120,179
—————————————————————————-
—————————————————————————-
OPERATIONS
(Cdn$ per Boe)
Revenue from product
sales(1) 21.45 11.86 23.00 12.55
Royalties (1.47) (0.19) (1.69) (0.48)
Production (6.74) (6.76) (6.25) (6.73)
Transportation (1.08) (0.33) (0.86) (0.43)
—————————————————————————-
Field operating netback(2) 12.16 4.58 14.20 4.91
Realized (loss) gain on
hedging (1.10) 2.24 (1.76) 2.64
General and administrative (1.17) (1.19) (1.13) (1.22)
Interest and finance costs (0.76) (0.68) (0.73) (0.62)
—————————————————————————-
Funds flow per Boe 9.13 4.95 10.58 5.71
—————————————————————————-
—————————————————————————-
Barrels of oil equivalent
per day (6:1) 13,991 12,852 15,461 13,135
—————————————————————————-
Natural gas production
Thousand cubic feet per
day 68,308 63,800 76,157 64,906
Price (Cdn$ per Mcf)(1) 2.81 1.28 3.04 1.45
—————————————————————————-
Condensate production
Barrels per day 1,468 1,172 1,612 1,312
Price (Cdn$ per barrel)(1) 57.65 50.05 61.31 45.34
—————————————————————————-
NGL production
Barrels per day 1,138 1,047 1,156 1,006
Price (Cdn$ per barrel)(1) 20.45 11.63 21.78 11.06
—————————————————————————-
Wells drilled (100% working
interest) – – 6.0 7.0
Wells completed (100%
working interest) – – 4.0 2.0
—————————————————————————-
—————————————————————————-
(1) Excludes gains and losses on commodity price contracts.
(2) Certain financial amounts shown above are non-GAAP measurements,
including field operating netback, operations capital expenditures, debt
including working capital deficiency and all measurements per Boe. See
discussion of Non-GAAP Measurements on page 25 of the MD&A.
(3) Excludes the fair value of commodity price contracts.

/T/

PRESIDENT’S MESSAGE

2017 SECOND QUARTER HIGHLIGHTS

/T/

— Production averaged 13,991 Boe per day, a per-share increase of 8% from

the second quarter of last year. The year-over-year increase was
achieved in spite of approximately 80% of production being shut in for
25 days in June for a planned maintenance turnaround at the McMahon Gas
Plant (April and May averaged 18,306 Boe per day).

— Condensate and NGL production totaled 2,606 barrels per day which was

19% of total production and represented 36% of total revenue.

— At the end of the quarter, there was an inventory of nine Montney

horizontal wells (9.0 net) at Umbach that had not started producing
which includes one completed well. One horizontal well (1.0 net) started
production in the quarter and six horizontal wells (6.0 net) started
production in the first half of the year.

— To date in 2017, four Montney horizontal wells (4.0 net) have been

completed and the three with enough production history have averaged 4.8
Mmcf per day gross raw gas plus 175 barrels per day of field condensate,
or 960 Boe per day sales, over the first 90 calendar days (only 75
producing days as a result of the McMahon Gas Plant turnaround). These
wells are approximately 25% longer than wells completed during 2014 to
2016 and are further south in the oil window which increases the field
condensate rate (115% higher than the average from all of Storm’s wells
at Umbach).

— Controllable cash costs (production, general and administrative,

interest and finance) were $8.67 per Boe which is an increase from $7.65
per Boe in the prior quarter. The increase is primarily due to
production being reduced by the scheduled maintenance turnaround at the
McMahon Gas Plant which increased production costs by $0.90 per Boe.
Costs are expected to resume trending lower in the second half of 2017.

— Funds flow was $11.6 million ($9.13 per Boe), an increase of 100% from a

year ago. The increase was driven by an 81% increase in revenue per Boe
and a 9% increase in production volumes which was partially offset by a
realized hedging loss of $1.4 million, or $1.10 per Boe.

— Net income was $9.8 million or $0.08 per share which includes an

unrealized hedging gain of $9.5 million (mark to market non-cash gain).
Hedging continues to have a significant recurring impact on quarterly
earnings. Excluding the unrealized and realized hedging gains or losses,
net income would be $1.7 million, or $0.01 per share.

— Capital investment was $4.3 million with most of this being invested in

infrastructure at Umbach (pipelined and equipped a second water disposal
well and added a second fuel gas conditioning unit). This was less than
the original forecast of $13 to $18 million as the planned completions
of four to six wells were delayed by spring road bans being extended
into mid-July.

— Debt including working capital deficiency was reduced to $90.6 million

from $97.9 million at the end of the prior quarter. This is 1.9 times
annualized second quarter funds flow, an increase from 1.4 times at the
end of the previous quarter as a result of production and funds flow
being reduced by the McMahon Gas Plant turnaround. The bank credit
facility is $165 million.

— Commodity price hedges continue to be added and currently protect

approximately 45% of forecast production for the second half of 2017.

/T/

OPERATIONS REVIEW

Umbach, Northeast British Columbia

Storm’s land position at Umbach is prospective for liquids-rich natural gas
from the Montney formation and currently totals 109,000 net acres (155 net
sections). To date, Storm has drilled 59 horizontal wells (55.4 net).

Production in the second quarter was 13,703 Boe per day and liquids recovery
was 39 barrels per Mmcf sales with 56% being higher priced condensate.

Activity in the second quarter included pipelining and equipping a second water
disposal well and adding a second fuel gas conditioning unit which is required
for the future expansion of the third field compression facility. One
horizontal well (1.0 net) started production. At the end of the quarter, there
was an inventory of nine horizontal wells (9.0 net) that had not started
producing which included one completed well.

There are three field compression facilities with current capacity totaling 115
Mmcf per day raw gas and throughput in the second quarter averaged 69 Mmcf per
day raw gas (92 Mmcf per day in April and May). Capacity at the third facility
can be increased by 35 Mmcf per day by adding a second compressor for $7
million. Delivery of the second compressor is scheduled for the fourth quarter
of 2017 with installation planned for the first half of 2018, possibly as early
as January depending on commodity prices and well results. This increases total
field compression to 150 Mmcf per day and supports growth in corporate
production to approximately 27,000 Boe per day.

Storm’s produced natural gas is sour (approximately 1.2% H2S) and is directed
to the McMahon and Stoddart Gas Plants where firm processing commitments total
80 Mmcf per day raw gas for the second half of 2017. At the McMahon Gas Plant,
a new processing arrangement began in January 2017 and has a commitment
totaling 65 Mmcf per day of raw gas for 5 to 15 years. The arrangement reduced
corporate production costs by approximately 15%, supports future growth with an
option to add up to 35 Mmcf per day, and provides access to three sales
pipelines. Most importantly, the arrangement will result in accelerated
corporate growth as more capital can be directed to drilling and completing
horizontal wells which offer a higher rate of return than building a sour gas
plant.

A summary of horizontal well performance and costs is provided below. Calendar
day rates for the 2016 and 2017 horizontal wells were reduced by the McMahon
Gas Plant turnaround from June 5 to July 14. For example, the three 2017 wells
produced for an average of 75 days out of the first 90 calendar days. Future
horizontal wells will have completed lengths of 1,700 to 2,100 metres with 30
to 36 frac stages and the increased length is expected to improve production
rates.

/T/

Actual Drill IP180 Cal IP365 Cal
Year of Frac Completed & Complete IP90 Cal Day Day Day
Completion Stages Length Cost Mmcf/d Raw Mmcf/d Raw Mmcf/d Raw
—————————————————————————-
2013 17 1,190 m $4.6 million 3.5 Mmcf/d 2.9 Mmcf/d 2.2 Mmcf/d
6 hz’s $270 K/stage 6 hz’s 6 hz’s 6 hz’s
—————————————————————————-
2014 19 1,170 m $4.6 million 4.9 Mmcf/d 4.4 Mmcf/d 3.5 Mmcf/d
12 hz’s(1) $240 K/stage 12 hz’s 12 hz’s 12 hz’s
—————————————————————————-
2015 22 1,360 m $4.4 million 4.7 Mmcf/d 4.2 Mmcf/d 3.3 Mmcf/d
11hz’s $200 K/stage 11 hz’s 11 hz’s 11 hz’s
—————————————————————————-
2016 25 1,300 m $3.7 million 5.1 Mmcf/d 4.2 Mmcf/d 3.7 Mmcf/d
10 hz’s $148 K/stage 10 hz’s 10 hz’s 2 hz’s
—————————————————————————-
2017 35 1,670 m $4.3 million 4.8
4 hz’s $123 K/stage Mmcf/d(2)
3 hz’s
—————————————————————————-
—————————————————————————-
(1) 2014 wells exclude a middle Montney well (this table provides analysis
of upper Montney wells only).
(2) Wells produced for an average of 75 days due to the McMahon maintenance
turnaround June 5 to July 14.

/T/

Horn River Basin, Northeast British Columbia

Storm has a 100% working interest in 119 sections in the Horn River Basin
(78,000 net acres) which are prospective for natural gas from the Muskwa, Otter
Park and Evie/Klua shales. Storm’s one horizontal well averaged 230 Boe per day
in the second quarter and cumulative production to date from this well is 5.7
Bcf raw.

HEDGING AND TRANSPORTATION

Commodity price hedges are used to support longer-term growth by providing some
certainty regarding future revenue and funds flow. The objective is to hedge
50% of most recent quarterly or monthly production for the next 12 months and
25% for 13 to 24 months forward. Anticipated production growth is not hedged.
Note that WTI is hedged as approximately 80% of Storm’s liquids production is
priced in reference to WTI. The current hedge position is summarized below and
approximately 45% of forecast production for the second half of 2017 is
currently hedged.

/T/

—————————————————————————-
Q3 – Q4 2017
—————————————————————————-
Crude Oil 1,200 Bopd WTI Cdn$65.19/Bbl floor,
Cdn$69.90/Bbl ceiling
—————————————————————————-
Natural Gas 38,000 GJ/d (30,400 Mcf/d) AECO Cdn$2.70/GJ ($3.37/Mcf)
—————————————————————————-
12,800 Mmbtu/d (10,800 Mcf/d) Chicago Cdn$4.17/Mmbtu
($4.94/Mcf)(1)
—————————————————————————-
2018
—————————————————————————-
Crude Oil 512 Bopd WTI Cdn$66.45/Bbl floor,
Cdn$70.11/Bbl ceiling
—————————————————————————-
Natural Gas 750 GJ/d (600 Mcf/d) AECO Cdn$2.80/GJ ($3.50/Mcf)
—————————————————————–
18,425 Mmbtu/d (15,600 Mcf/d) Chicago Cdn$4.01/Mmbtu
($4.75/Mcf)(1)
—————————————————————–
2,000 Mmbtu/d (1,700 Mcf/d) Chicago US$2.98/Mmbtu
—————————————————————————-
(1) Hedge price in Chicago does not include the Alliance Pipeline tariff to
Chicago which is approximately Cdn$1.35 per GJ including the cost of
fuel.

/T/

The Company also has natural gas price differential hedges in place (Chicago –
AECO and AECO – Station 2) with details provided in the notes to the condensed
interim consolidated financial statements.

Firm transportation commitments are used to diversify sales points and mitigate
pricing risk. Firm transportation totals 72 Mmcf per day in 2017 and increases
to 102 Mmcf per day in 2018. In addition, preferential interruptible capacity
on the Alliance Pipeline adds up to 14 Mmcf per day in 2017 and up to 15 Mmcf
per day in 2018. Natural gas production exceeding firm commitments is directed
to Chicago and/or Station 2 using interruptible pipeline capacity (sales point
depends on price). Note that Storm’s natural gas marketing arrangements result
in the cost of transportation on the Alliance Pipeline being deducted from
revenue ($5.7 million deducted in the second quarter of 2017). Further
information on pipeline tariffs and price deductions is provided in the
presentation on Storm’s website.

/T/

—————————————————————————-
2017 2018
—————————————————————————-
Alliance Pipeline(1) Alliance Pipeline(1)
51 Mmcf/d Chicago price 55 Mmcf/d Chicago price
5 Mmcf/d ATP price 5 Mmcf/d ATP price
—————————————————————————-
Enbridge T-North Enbridge T-North
16 Mmcf/d Station 2 price 29 Mmcf/d Station 2 price
—————————————————————————-
Enbridge T-North & TCPL NGTL
13 Mmcf/d AECO price
—————————————————————————-
(1) Interruptible capacity on the Alliance Pipeline adds up to 25% of
contracted capacity.

/T/

OUTLOOK

For the third quarter of 2017, production is anticipated to be 15,500 to 17,000
Boe per day which includes the effect of the maintenance turnaround at the
McMahon Gas Plant from June 5 to July 14. Approximately 80% of production was
shut in for 14 days in the third quarter. The duration of the turnaround was 39
days which was longer than the original expectation of 21 days. Capital
investment in the third quarter is expected to be $28 million and includes
drilling four horizontal wells plus completing six horizontal wells at Umbach.

The third quarter has seen Western Canadian natural gas prices weaken as a
result of continued production growth and maintenance restrictions on the TCPL
NGTL system and the Enbridge T-South pipeline. To date in the third quarter,
AECO daily has averaged $1.59 per GJ (versus $2.64 per GJ in the second
quarter) while Station 2 daily has averaged $1.06 per GJ (versus $2.21 per GJ
in the second quarter). The weakness is likely to continue until September for
AECO and October for Station 2 when the maintenance restrictions are expected
to end. Based on field estimates, Storm’s production in July was 12,200 Boe per
day and to date in August has averaged 17,300 Boe per day. Until the Station 2
price improves, production will not be increased and volumes sold at Station 2
will be minimized to meet firm transportation commitments. Approximately 20% of
current natural gas sales are at Station 2.

Updated guidance for 2017 is summarized below. Operations capital is forecast
to be $75 to $95 million (previously $75 to $80 million) depending on both well
results and commodity prices meeting Storm’s forecast for the second half of
2017. Capital investment at the high end of the range ($95 million) would
accelerate growth in 2018 by drilling and completing additional wells in the
fourth quarter of 2017 (minimal impact on forecast production for 2017). This
includes installing a second compressor at the third Umbach facility in January
2018. Should commodity prices be lower than forecast, capital investment would
be reduced to the low end of the range ($75 million) by deferring the
additional activity. Forecast commodity prices reflect actual year-to-date
pricing plus the approximate forward strip for the remainder of 2017.

2017 Guidance

/T/

Updated
May 15, 2017 August 15, 2017
—————————————————————————-
$Cdn/$US exchange rate 0.75 0.775
—————————————————————————-
Chicago daily natural
gas (US$/Mmbtu) $3.00 $2.90
—————————————————————————-
AECO daily natural gas
(Cdn$/GJ) $2.50 $2.45
—————————————————————————-
Station 2 daily natural
gas (Cdn$/GJ) $2.10 $2.00
—————————————————————————-
Edmonton light oil
(Cdn$/bbl) $62.00 $60.00
—————————————————————————-
Estimated average
operating costs ($/Boe) $5.50 – $6.00 $5.75 – $6.00
—————————————————————————-
Estimated average
royalty rate
(% production revenue
before hedging) 7% – 10% 6% – 8%
—————————————————————————-
Estimated operations
capital ($ million)
(excluding acquisitions
& dispositions) $75.0 – $80.0 $75.0 – $95.0
—————————————————————————-
Estimated cash G&A – $
million $5.3 $6.0 – $6.5
– $/Boe $0.85 $0.95 – $1.05
—————————————————————————-
Forecast fourth quarter
production (Boe/d) 19,000 – 21,000 19,000 – 21,000
% condensate and NGL 17% 17%
—————————————————————————-
Forecast annual
production (Boe/d) 17,000 – 18,000 16,500 – 18,000
% condensate and NGL 17% 17%
—————————————————————————-
Umbach horizontal wells
drilled
Umbach horizontal wells
completed 12 gross (12.0 net) 12 – 15 gross (12.0 – 15.0 net)
Umbach horizontal wells 14 gross (14.0 net) 10 – 16 gross (10.0 – 16.0 net)
connected 15 gross (15.0 net) 13 – 16 gross (13.0 – 16.0 net)
—————————————————————————-
—————————————————————————-

/T/

2017 Guidance History

/T/

Forecast
Estimated Fourth Forecast
Chicago Station 2 AECO Operations Quarter Annual
Daily Daily Daily Capital Production Production
(US$/Mmbtu) (Cdn$/GJ) (Cdn$/GJ) ($ million) (Boe/d) (Boe/d)
—————————————————————————-
September $75.0 – 18,000 – 16,500 –
7, 2016 $3.00 $2.25 $2.65 $80.0 20,000 18,000
—————————————————————————-
November $75.0 – 18,000 – 16,500 –
15, 2016 $3.00 $2.20 $2.65 $80.0 20,000 18,000
—————————————————————————-
March 2, $75.0 – 18,000 – 16,500 –
2017 $3.00 $2.00 $2.50 $80.0 20,000 18,000
—————————————————————————-
May 15, $75.0 – 19,000 – 17,000 –
2017 $3.00 $2.10 $2.50 $80.0 21,000 18,000
—————————————————————————-
August 15, $75.0 – 19,000 – 16,500 –
2017 $2.90 $2.00 $2.45 $95.0 21,000 18,000
—————————————————————————-
—————————————————————————-

/T/

Capital investment assumes the cost to drill and complete a horizontal well at
Umbach is $4.7 million, an increase of 27% from the actual cost in 2016 with
half of the increase from adding length and frac stages and half of the
increase as a result of service cost inflation.

Planned growth through 2018 is supported by forecast commodity prices as well
as the expected improvement in rates, reserves, and capital efficiencies from
future Montney horizontal wells at Umbach which are planned to be approximately
50% longer than the 2014 to 2016 wells. In 2017, average production is forecast
to increase by approximately 30% year over year by investing $75 to $95 million
which will result in year-end net debt of approximately $100 to $120 million.
For 2018, assuming commodity prices are approximately equal to forecast prices
for 2017, the preliminary plan is to invest $95 to $110 million for a further
30% to 40% increase in production with forecast fourth quarter production of
25,000 to 27,000 Boe per day. Growth in 2018 requires an investment of $7
million in infrastructure at Umbach to add field compression which is planned
for as early as January 2018 and can also be delayed depending on commodity
prices.

Although the upper end of the range for capital investment was increased to
provide the option to accelerate growth in expectation of improving well
results, growth will not be accelerated to the detriment of the balance sheet.
Correspondingly, capital investment has been designed to be flexible and
activity can be adjusted quickly in response to changes in commodity prices.

With a large liquids-rich resource in the Montney at Umbach offering multiple
years of drilling inventory, the objective remains to grow net asset value for
shareholders by converting the resource into production and funds flow growth
on a per-share basis.

Respectfully,

Brian Lavergne,
President and Chief Executive Officer

August 15, 2017

Boe Presentation – For the purpose of calculating unit revenues and costs,
natural gas is converted to a barrel of oil equivalent (“Boe”) using six
thousand cubic feet (“Mcf”) of natural gas equal to one barrel of oil unless
otherwise stated. Boe may be misleading, particularly if used in isolation. A
Boe conversion ratio of six Mcf to one barrel (“Bbl”) is based on an energy
equivalency conversion method primarily applicable at the burner tip and does
not represent a value equivalency at the wellhead. All Boe measurements and
conversions in this report are derived by converting natural gas to oil in the
ratio of six thousand cubic feet of gas to one barrel of oil. Mboe means 1,000
Boe.

Non-GAAP Measures – This document may refer to the terms “debt including
working capital deficiency”, “field operating netbacks”, “field operating
netbacks including hedging”, the terms “cash” and “non-cash”, “cash costs”, and
measurements “per commodity unit” and “per Boe” which are not recognized under
Generally Accepted Accounting Principles (“GAAP”) and are regarded as non-GAAP
measures. These non-GAAP measures may not be comparable to the calculation of
similar amounts for other entities and readers are cautioned that use of such
measures to compare enterprises may not be valid. Non-GAAP terms are used to
benchmark operations against prior periods and peer group companies and are
widely used by investors, analysts and other parties. Additional information
relating to certain of these non-GAAP measures can be found in Storm’s most
recent MD&A which is available on Storm’s SEDAR profile at www.sedar.com and on
Storm’s website at www.stormresourcesltd.com.

Initial Production Rates – Initial production rates (“IP”) provided refer to
actual raw natural gas rates reported to the British Columbia government. IP
rates are not necessarily indicative of long-term performance or of ultimate
recovery.

Forward-Looking Information – This press release contains forward-looking
statements and forward-looking information within the meaning of applicable
securities laws. The use of any of the words “will”, “would”, “expect”,
“anticipate”, “intend”, “believe”, “plan”, “potential”, “outlook”, “forecast”,
“estimate”, “budget” and similar expressions are intended to identify
forward-looking statements or information. More particularly, and without
limitation, this press release contains forward-looking statements and
information concerning: current and future years’ guidance in respect of
certain operational and financial metrics, including, but not limited to,
commodity pricing, estimated average operating costs, estimated average royalty
rate, estimated operations capital, estimated general and administrative costs,
estimated quarterly and annual production and estimated number of Umbach
horizontal wells drilled, completed and connected, capital investment plans,
infrastructure plans, anticipated United States exports, pipeline capacity,
price volatility mitigation strategy and cost reductions. Statements of
“reserves” are also deemed to be forward-looking statements, as they involve
the implied assessment, based on certain estimates and assumptions, that the
reserves described exist in the quantities predicted or estimated and that the
reserves can be profitably produced in the future.

The forward-looking statements and information in this press release are based
on certain key expectations and assumptions made by Storm, including:
prevailing commodity prices and exchange rates; applicable royalty rates and
tax laws; future well production rates; reserve and resource volumes; the
performance of existing wells; success to be expected in drilling new wells;
the adequacy of budgeted capital expenditures to carrying out planned
activities; the availability and cost of services; and the receipt, in a timely
manner, of regulatory and other required approvals. Although the Company
believes that the expectations and assumptions on which such forward-looking
statements and information are based are reasonable, undue reliance should not
be placed on these forward-looking statements and information because of their
inherent uncertainty. In particular, there is no assurance that exploitation of
the Company’s undeveloped lands and prospects will result in the emergence of
profitable operations.

Readers are cautioned that the foregoing list of factors is not exhaustive.
Additional information on these and other factors that could affect the
operations or financial results of the Company are included or are incorporated
by reference in the Company’s Annual Information Form and the MD&A.

The forward-looking statements and information contained in this press release
are made as of the date hereof and the Company undertakes no obligation to
update publicly or revise any forward-looking statements or information,
whether as a result of new information, future events or otherwise, unless so
required by applicable securities laws.

NEITHER THE TSX VENTURE EXCHANGE NOR ITS REGULATION SERVICES PROVIDER (AS THAT
TERM IS DEFINED IN THE POLICIES OF THE TSX VENTURE EXCHANGE) ACCEPTS
RESPONSIBILITY FOR THE ADEQUACY OR ACCURACY OF THIS PRESS RELEASE.

– END RELEASE – 15/08/2017

For further information:
Brian Lavergne
President & Chief Executive Officer
OR
Michael J. Hearn
Chief Financial Officer
OR
Carol Knudsen
Manager, Corporate Affairs
OR
(403) 817-6145
www.stormresourcesltd.com

COMPANY:
FOR: STORM RESOURCES LTD.
TSX VENTURE SYMBOL: SRX

INDUSTRY: Energy and Utilities – Oil and Gas
RELEASE ID: 20170815CC0061

Press Release from Marketwired 1-866-736-3779

Kinder Morgan Canada Limited Closes $300 Million Preferred Share Offering

August 15, 2017 by EnergyNow Media

CALGARY, Aug. 15, 2017 – Kinder Morgan Canada Limited (the “Company”) (TSX: KML) is pleased to announce that it has completed its previously announced offering of cumulative redeemable minimum rate reset preferred shares, Series 1 (the “Series 1 Preferred Shares”). The Company issued 12,000,000 Series 1 Preferred Shares for aggregate gross proceeds of $300 million … Read more

Dundee Energy Limited Announces Subsidiary Filings Of Notice of Intention Under the Bankruptcy and Insolvency Act

August 15, 2017 by The Canadian Press

FOR: DUNDEE ENERGY LIMITED
TSX SYMBOL: DEN

Date issue: August 15, 2017
Time in: 5:52 PM e

Attention:

TORONTO, ONTARIO–(Marketwired – Aug. 15, 2017) – Dundee Energy Limited
(TSX:DEN) (“Dundee Energy” or the “Corporation”) today announced that Dundee
Oil and Gas Limited (“DOGL”) and Dundee Energy Limited Partnership (“DELP”)
(each a wholly owned entity of the Corporation) have commenced reorganization
proceedings by filing a notice of intention to make a proposal under the
Bankruptcy and Insolvency Act (the “BIA”). The reorganization proceedings have
been commenced in response to the notice received on July 21, 2017 from the
lenders under the amended and restated credit agreement dated July 31, 2012, as
amended (the “Credit Agreement”), demanding repayment in full of the
outstanding principal amount under the Credit Agreement (including all accrued
and unpaid interest and expenses payable under the Credit Agreement). The
lenders under the Credit Agreement have entered into a forbearance agreement
and are supporting DOGL and DELP in the reorganization proceedings. DOGL and
DELP are expected to request certain relief under the BIA from the Ontario
Superior Court at a motion to be held in Toronto on August 16, 2017.

As a result of the filing of proposal proceedings under the BIA, the Toronto
Stock Exchange has advised that trading in the common shares of the Corporation
will be suspended immediately.

FORWARD-LOOKING STATEMENTS

Certain information set out in this news release contains forward-looking
statements. Forward-looking statements are statements that are predictive in
nature, depend upon or refer to future events or conditions and may include
words such as “expects”, “anticipates”, “intends”, “plans”, “believes”,
“estimates” or similar expressions. In particular, forward-looking statements
contained in this news release include, but are not limited to, statements with
respect to the anticipated request to be made by DOGL and DELP under the BIA
for relief from the court.

Readers are cautioned that the assumptions used in the preparation of such
information, although considered reasonable at the time of preparation, may
prove to be imprecise and, as such, undue reliance should not be placed on
forward-looking statements. The Corporation’s actual results, performance or
achievement could differ materially from those expressed in, or implied by,
these forward-looking statements and, accordingly, no assurance can be given
that any of the events anticipated by the forward-looking statements will
transpire or occur, or if any of them do so, what benefits the Corporation will
derive from them. The Corporation disclaims any intention or obligation to
update or revise any forward-looking statements, whether as a result of new
information, future events or otherwise, except as required by law.

ABOUT THE CORPORATION

Dundee Energy Limited is a Canadian-based oil and natural gas Corporation with
a mandate to create long-term value for its shareholders through the
exploration, development, production and marketing of oil and natural gas, and
through other high impact energy projects. Dundee Energy holds interests, both
directly and indirectly, in the largest accumulation of producing oil and gas
assets in Ontario and, through a preferred share investment, in certain
exploration and evaluation programs for oil and natural gas offshore Tunisia.
Dundee Energy’s common shares trade on the Toronto Stock Exchange under the
symbol “DEN”.

– END RELEASE – 15/08/2017

For further information:
Dundee Energy Limited
Bruce Sherley
President & CEO
(403) 651-4581
(416) 363-4536 (FAX)
www.dundee-energy.com

COMPANY:
FOR: DUNDEE ENERGY LIMITED
TSX SYMBOL: DEN

INDUSTRY: Energy and Utilities – Oil and Gas
RELEASE ID: 20170815CC0057

Press Release from Marketwired 1-866-736-3779

Peyto Exploration & Development Corp. Confirms Dividends for September 15, 2017

August 15, 2017August 15, 2017 by The Canadian Press

FOR: PEYTO EXPLORATION & DEVELOPMENT CORP.
TSX SYMBOL: PEY

Date issue: August 15, 2017
Time in: 4:30 PM e

Attention:

CALGARY, ALBERTA–(Marketwired – Aug. 15, 2017) – Peyto Exploration &
Development Corp. (“Peyto”) (TSX:PEY) confirms that the monthly dividend with
respect to August 2017 of $0.11 per common share is to be paid on September 15,
2017, for shareholders of record on August 31, 2017. The ex-dividend date is
August 29, 2017.

Dividends paid by Peyto to Canadian residents are eligible dividends for
Canadian income tax purposes.

Shareholders and interested investors are encouraged to visit the Peyto website
at www.peyto.com to learn more about what makes Peyto one of North America’s
most exciting energy companies. The website also includes the President’s
monthly report, which discusses various topics chosen by the President and
includes estimates of monthly capital expenditures and production.

Certain information set forth in this document, including management’s
assessment of Peyto’s future plans and operations, contains forward-looking
statements. By their nature, forward-looking statements are subject to numerous
risks and uncertainties, some of which are beyond these parties’ control,
including the impact of general economic conditions, industry conditions,
volatility of commodity prices, currency fluctuations, imprecision of reserve
estimates, environmental risks, competition from other industry participants,
the lack of availability of qualified personnel or management, stock market
volatility and ability to access sufficient capital from internal and external
sources. Readers are cautioned that the assumptions used in the preparation of
such information, although considered reasonable at the time of preparation,
may prove to be imprecise and, as such, undue reliance should not be placed on
forward-looking statements. Peyto’s actual results, performance or achievement
could differ materially from those expressed in, or implied by, these
forward-looking statements and, accordingly, no assurance can be given that any
of the events anticipated by the forward-looking statements will transpire or
occur, or if any of them do so, what benefits that Peyto will derive therefrom.
The Toronto Stock Exchange has neither approved nor disapproved the information
contained herein.

– END RELEASE – 15/08/2017

For further information:
Darren Gee
President and Chief Executive Officer
(403) 237-8911
(403) 451-4100 (FAX)

COMPANY:
FOR: PEYTO EXPLORATION & DEVELOPMENT CORP.
TSX SYMBOL: PEY

INDUSTRY: Energy and Utilities – Oil and Gas
RELEASE ID: 20170815CC0048

Press Release from Marketwired 1-866-736-3779

PrairieSky Royalty Declares August Dividend

August 15, 2017 by The Canadian Press

FOR: PRAIRIESKY ROYALTY LTD.TSX SYMBOL: PSKDate issue: August 15, 2017Time in: 4:01 PM eAttention:
CALGARY, ALBERTA–(Marketwired – Aug. 15, 2017) – PrairieSky Royalty Ltd.
(“PrairieSky”) (TSX:PSK) announced today that its Board of Directors has
decla…

AltaGas Announces Death of David F. Mackie, Founding Member and Independent Director of AltaGas

August 15, 2017 by The Canadian Press

FOR: ALTAGAS LTD.TSX SYMBOL: ALADate issue: August 15, 2017Time in: 1:32 PM eAttention:
CALGARY, ALBERTA–(Marketwired – Aug. 15, 2017) – AltaGas Ltd. (“AltaGas”)
(TSX:ALA) announced today with profound sadness, that Mr. David F. Mackie, a
founding me…

Five Things World Business will be Talking About Today

August 15, 2017 by EnergyNow Media

August 15, 2017 (Bloomberg) U.K. inflation remains unchanged, Dudley talks up another Fed hike this year, and OPEC’s shale problem is only getting worse. Here are some of the things people in markets are talking about today. Price rises The U.K. inflation rate was unchanged at 2.6 percent in July, slightly below economist forecasts, with the … Read more

OPEC’s Oil-Glut Fight Morphs From Skirmish to Campaign of Years

August 15, 2017August 15, 2017 by EnergyNow Media

August 15, 2017 (Bloomberg) When OPEC and Russia first embarked on their strategy to clear a global oil glut, it was expected to succeed within six months. It now looks like the battle could last for years. The Organization of Petroleum Exporting Countries and its partners plan to wrap up their production cuts next spring, … Read more

Oil Extends Decline as U.S. Sees Shale Output Expanding Further

August 15, 2017August 15, 2017 by EnergyNow Media

August 15, 2017 (Bloomberg) Oil extended its decline after the U.S. forecast record shale output next month and the International Energy Agency said OPEC producers face a long battle with American rivals. Futures slid 0.6 percent in New York after losing 2.5 percent Monday, the biggest drop in more than five weeks. Production at shale fields is … Read more

Crescent Point Energy Confirms August 2017 Dividend

August 15, 2017 by The Canadian Press

FOR: CRESCENT POINT ENERGY CORP.
TSX SYMBOL: CPG
NYSE SYMBOL: CPG

Date issue: August 15, 2017
Time in: 11:06 AM e

Attention:

CALGARY, ALBERTA–(Marketwired – Aug. 15, 2017) – Crescent Point Energy Corp.
(“Crescent Point” or the “Company”) (TSX:CPG)(NYSE:CPG) confirms that the
dividend to be paid on September 15, 2017, in respect of August 2017
production, for shareholders of record on August 31, 2017, will be CDN$0.03 per
share.

These dividends are designated as “eligible dividends” for Canadian income tax
purposes. For U.S. income tax purposes, Crescent Point’s dividends are
considered “qualified dividends.”

Crescent Point is a leading North American light and medium oil producer that
seeks to maximize shareholder return through its total return strategy of
long-term growth plus dividend income.

CRESCENT POINT ENERGY CORP.

Scott Saxberg, President and Chief Executive Officer

Crescent Point shares are traded on the Toronto Stock Exchange and New York
Stock Exchange, both under the symbol CPG.

– END RELEASE – 15/08/2017

For further information:
Crescent Point Energy Corp.
Ken Lamont
Chief Financial Officer
(403) 693-0020 or Toll free (U.S. & Canada): 888-693-0020
(403) 693-0070 (FAX)
OR
Crescent Point Energy Corp.
Brad Borggard
Vice President, Corporate Planning and Investor Relations
(403) 693-0020 or Toll free (U.S. & Canada): 888-693-0020
(403) 693-0070 (FAX)
www.crescentpointenergy.com

COMPANY:
FOR: CRESCENT POINT ENERGY CORP.
TSX SYMBOL: CPG
NYSE SYMBOL: CPG

INDUSTRY: Energy and Utilities – Oil and Gas
RELEASE ID: 20170815CC0036

Press Release from Marketwired 1-866-736-3779

U.S. Oil Drillers Keep Pressure on OPEC With Record Shale Output

August 14, 2017 by EnergyNow Media

August 14, 2017 (Bloomberg) Oil output from major U.S. shale plays is poised to reach a fresh record next month, further complicating OPEC’s efforts to support prices. The Energy Information Administration expanded its monthly forecasts to include the Anadarko shale region spanning 24 Oklahoma and five Texas counties. The region, a well-established oil and gas … Read more

Zedcor Energy Inc. Announces 2017 Second Quarter Results

August 14, 2017 by The Canadian Press

FOR: ZEDCOR ENERGY INC.TSX VENTURE SYMBOL: ZDCDate issue: August 14, 2017Time in: 7:11 PM eAttention:
CALGARY, ALBERTA–(Marketwired – Aug. 14, 2017) – Zedcor Energy Inc. (the
“Company”) (TSX VENTURE:ZDC) today announced its financial and operating
re…

Condor Announces 2017 Second Quarter Results

August 14, 2017 by The Canadian Press

FOR: CONDOR PETROLEUM INC.TSX Symbol: CPIDate issue: August 14, 2017Time in: 6:20 PM eAttention:
CALGARY, AB –(Marketwired – August 14, 2017) – Condor Petroleum Inc.
(“Condor” or the “Company”) (TSX: CPI), a Canadian based oil and gas company
focuse…

Weekly Canadian Oil & Gas Industry Highlights – August 14, 2017

August 15, 2017August 14, 2017 by EnergyNow Media

August 14, 2017 Presented by POIM Consulting Group Major /Interesting Projects Outlier Resources Ltd two compressor Projects KAYBOB SOUTH Vermilion Energy Inc Large compressor upgrade FERRIER Canadian International Oil Operating Corporation two large multi-well batteries KARR TRIPLE FIVE INTERCONTINENTAL GROUP LTD. Large Gas Battery WILLESDEN GREEN Bonavista Energy Corporation Multi Well Pad 06-28-050-17W5 Chevron Canada … Read more

Birchcliff Energy Ltd. Provides Series A Preferred Shares Conversion Privilege Notice

August 14, 2017 by The Canadian Press

FOR: BIRCHCLIFF ENERGY LTD.TSX SYMBOL: BIRDate issue: August 14, 2017Time in: 5:00 PM eAttention:
CALGARY, ALBERTA–(Marketwired – Aug. 14, 2017) – Birchcliff Energy Ltd.
(“Birchcliff”) (TSX:BIR) announces that it does not intend to exercise its
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Pengrowth Closes Significant Asset Sales and Reaches Agreement in Principle on Key Elements of Covenant Relief

August 15, 2017August 14, 2017 by The Canadian Press

FOR: PENGROWTH ENERGY CORPORATION
TSX SYMBOL: PGF
NYSE SYMBOL: PGH

Date issue: August 14, 2017
Time in: 4:05 PM e

Attention:

CALGARY, ALBERTA–(Marketwired – Aug. 14, 2017) – Pengrowth Energy Corporation
(TSX:PGF) (NYSE:PGH) is pleased to announce its second quarter 2017 operating
results, highlighted by additional asset sales, and further reductions to
outstanding debt and cost structures. All of these activities in combination
with an agreement in principle on the key elements of an amendment with a group
of noteholders for covenant relief, significantly improves Pengrowth’s
financial flexibility.

Since the start of 2017, we have closed $827 million of asset sales which, when
combined with the $287 million of cash on hand at year end 2016, represents a
pro forma debt reduction of over $1.1 billion or approximately 66 percent of
December 31, 2016 debt. This was accomplished while only reducing the Company’s
Proved plus Probable reserves as of December 31, 2016 by approximately 18
percent. With the closing of these sales, the Company’s core focus areas are
its flagship 100 percent owned Lindbergh thermal project and its 90 percent
owned Groundbirch Montney play. These two key assets, with their associated
$9.0 billion of low risk, high netback development opportunities represent the
bulk of the remaining 82 percent of the Company’s 2P reserves as at December
31, 2016 and are expected to position the Company for long-term growth in
reserves, production and cash flow.

We have also been in active negotiations with the lenders under our syndicated
bank facility and with the holders of our senior unsecured notes to ensure our
financial flexibility and liquidity. We are pleased to report that Pengrowth
has agreed in principle on the key elements of an amendment with a group of
noteholders who represent the necessary majority of the principal amount of
notes affected for a framework that would result in the relaxation of existing
covenant ratios for a period up to and including the quarter ended September
30, 2019 (the “Waiver Period”). The specific framework of the proposed
amendments includes the elimination of the debt to book capitalization ratio
and the debt to EBITDA ratio for the duration of the Waiver Period as well as
amending the interest coverage covenant to reduce the EBITDA to interest ratio.
The Company and the noteholders are in the process of preparing detailed formal
agreements to effect the proposed amendments. These amendments are expected to
become effective during the third quarter of 2017 and are subject to the
completion of definitive agreements.

Derek Evans, President and CEO of Pengrowth commented “The successful $827
million of closed asset sales in 2017 has been instrumental, not only in
reducing our debt but also in reaching an agreement in principle on the key
elements of an amendment to our covenants with our noteholders. These are the
critical steps that were required to unlock the long term growth potential and
sustainable nature of our key assets.”

2017 Year to Date Highlights:

/T/

— Closed $827 million of asset sales, which are summarized in the

following table:

—————————————-
Gross Proceeds
($ million) Completion Date
—————————————————————————-
Lindbergh GORR $250 January 6, 2017
—————————————————————————-
Bernadet Lands $92 April 11, 2017
—————————————————————————-
Swan Hills (Judy Creek) $185 July 6, 2017
—————————————————————————-
Olds/Garrington $300 August 11, 2017
—————————————————————————-
Total gross proceeds $827
——————————————————–

— Reduced total debt, before working capital by approximately $662

million.

— Agreed in principle on the key elements on an amendment with a group of

noteholders, subject to final legal documentation, that temporarily
relaxes covenants for a period up to and including the period ending
September 30, 2019.

— Following the closing of the Olds/Garrington asset sale, the Company has

approximately $330 million of cash on hand.

/T/

Q2, 2017 Highlights:

/T/

— Achieved average daily production of 49,349 barrels of oil equivalent

(boe) per day during the quarter and 51,143 boe per day during the first
half of the year.

— Generated funds flow from operations of $29.3 million ($0.05 per share)

during the second quarter and $56.2 million ($0.10 per share) for the
first half of 2017.

— Achieved additional expense reductions in the second quarter with

operating and cash general and administrative expenses down $3.7 million
and $2.9 million, respectively, from the second quarter of 2016. Reduced
interest expense by $9 million compared the second quarter of 2016
resulting from debt payments completed in the quarter and thus far in
2017.

— Realized a 28 percent increase in combined operating netbacks before

commodity risk management, of $13.45 per boe compared to $10.53 per boe
in the same period last year.

/T/

Operations

Second quarter average daily production was 49,349 boe per day, compared to
average daily production of 56,735 boe per day in the second quarter of 2016.
The decrease in production year over year is attributed to the absence of
volumes related to sold properties, natural declines, as well as lower volumes
due to maintenance activities on existing properties.

Second quarter production at our Lindbergh thermal project averaged 13,657
barrels (bbl) per day at an average steam oil ratio of 2.8 times. Production in
the quarter was affected by downtime on existing wells that were shut-in to
facilitate the completion and tie-in of the new infill wells. A total of $30.6
million was invested on Lindbergh Phase One optimization activities in the
second quarter. This investment included the drilling of 11 wells (6 producer
and 5 injector wells), in addition to related facility, infrastructure and
engineering work. The two infill wells drilled in the first quarter of 2017 are
now on production at a combined rate of approximately 1,000 bbl per day. In
total, seven new well pairs and two new infills are to be drilled as part of
the optimization program. Once the drilling and completion of the remaining
wells is finished, steaming and circulation activities will commence in the
fourth quarter and it is anticipated that oil production from the new well
pairs will be accretive to overall production in the first quarter of 2018.

In addition to Phase One optimization expenditures and activities, ongoing
engineering and design work relating to the second expansion phase was carried
out in the quarter. Pengrowth anticipates having 70 percent of the engineering
and design work complete by the end of year.

Conventional development continues to be limited, with second quarter capital
spending of $6.1 million spent primarily on partner operated activity and the
safety, maintenance and integrity of existing assets.

Ongoing focus on cost structures allowed us to achieve additional expense
reductions in the quarter with operating costs and cash general and
administrative costs down $3.7 million and $2.9 million, respectively, from the
second quarter of 2016.

Financial Results

The Company delivered second quarter funds flow from operations of $29.3
million ($0.05 per share), compared to funds flow of $89.1 million ($0.16 per
share) for the same period in 2016. The decrease in funds flow year over year
was primarily due to lower realized commodity risk management gains, as a
result of Pengrowth having substantially higher volumes hedged at materially
higher prices in the second quarter of 2016 compared to second quarter of 2017.
Offsetting this were higher realized prices during the second quarter of 2017
compared to the same period in 2016 due to material improvements in both crude
oil and natural gas benchmark prices.

A net loss of $242.4 million was recorded in the second quarter of 2017
compared to a net loss of $173.4 million in the same period last year primarily
due to an impairment charge of $306.3 million (approximately $223 million
after-tax) in the second quarter of 2017 resulting from the Olds/Garrington
disposition coupled with lower funds flow from operations. These were partly
offset by the absence of unrealized commodity risk management losses recorded
in the second quarter of 2016 and lower DD&A expenses.

Financial Resources and Liquidity

In the second quarter, we completed the Bernadet asset sale for total proceeds
of approximately $92 million and also announced additional asset dispositions
that generated total cash proceeds of approximately $485 million, which were
completed subsequent to the end of the quarter. We applied the cash proceeds
from the Bernadet sale along with a minor drawing on our credit facility to
repay the remaining US $100 million of Notes maturing in 2017 on June 2, 2017.
This resulted in our reported total debt at June 30, 2017 being $1.06 billion
compared to $1.68 billion at December 31, 2016.

We subsequently repaid the borrowings under our credit facility with the cash
proceeds from the Judy Creek asset sale. Following the early retirement of the
2017 notes, we currently have no scheduled long-term note maturities until
August 2018.

During the quarter, we remained within our financial covenants with a ratio of
trailing twelve months senior debt to Adjusted EBITDA of 2.7 times compared to
a maximum permitted ratio of 3.5 times. Senior debt to book capitalization
ratio of 50 percent compared to a maximum permitted ratio of 55 percent and an
interest coverage ratio of 4.7 times compared to a minimum required ratio of
4.0 times.

The Company has agreed in principle on the key elements of an amendment with a
group of noteholders who represent the necessary majority of the principal
amount of notes affected by the proposed amendment. The Company and noteholders
are in the process of preparing detailed formal agreements to effect the
amendment. The proposed amendment includes the relaxation of the Company’s
covenants for a period commencing with the third quarter 2017 and up to and
including the period ending September 30, 2019. A waiver of the debt to book
capitalization ratio and a waiver of the total and senior debt to EBITDA
covenant ratios is expected to be in effect during this period. The interest
coverage covenant is expected to be amended to reduce the EBITDA to interest
ratio significantly for the amendment period. In exchange, the noteholders are
expected to receive security over Pengrowth’s assets and a 2.0 percentage point
increase in interest rates, while maturities remain the same. The proposed
amendment is contingent on a similar agreement being reached with the syndicate
of banks providing Pengrowth’s Credit Facility. The agent bank for the Credit
Facility has been approached with a similar proposal that would also see a
reduction in the Credit Facility from $1.0 billion to $400 million with a
further reduction to $330 million pending further asset sales. We anticipate
having final agreements in place with the entire bank syndicate and noteholders
during the third quarter of 2017.

To provide additional financial flexibility beyond September 30, 2019,
Pengrowth is also considering additional asset sales and opportunities to
access the capital markets to replace existing debt with less restrictive high
yield debt.

Dispositions

Since late 2016, the Company has completed a number of transactions, including
the recent sale of its Olds/Garrington assets in central Alberta. The total
proceeds thus far in 2017 from our disposition program amounts to $827 million
and has allowed Pengrowth to materially reduce its outstanding debt.

On July 11, 2017 we announced that we had terminated the sale agreement for the
remaining Swan Hills assets due to the purchaser of the asset package being
unable to complete its financing for the acquisition. The Company is pursuing
the approximate $19 million deposit associated with the sale that is being held
by an independent law firm in trust.

2017 Guidance and Outlook

On July 11, 2017 Pengrowth revised its 2017 Guidance to reflect the impact from
the sales of the Olds/Garrington assets which closed on August 11, 2017, and a
portion of its Swan Hills assets which was completed on July 6, 2017. The
revised annual 2017 production Guidance of 41,500 to 43,500 boe per day and
funds flow from operations of $90 million reflect the reductions related to the
Olds/Garrington and the Judy Creek dispositions. Pengrowth anticipates its
fourth quarter of 2017 average production to be 31,000 to 33,000 boe per day.

A summary of our current 2017 guidance follows:

/T/

———————————–
Current full year H1/2017 Actual
2017 Guidance Results
—————————————————————————-
Average daily production (boe per day) 41,500 to 43,500 51,143
—————————————————————————-
Total capital expenditures ($ millions) 125 56.1
—————————————————————————-
Funds Flow from operations1 ($ millions) 90 56.2
—————————————————————————-
Royalties2 (% of sales) 9.0 10.1
—————————————————————————-
Operating costs3 ($ per boe) 13.00 to 13.50 13.35
—————————————————————————-
Cash G & A3 ($ per boe) 3.50 to 4.00 3.54
—————————————————————————-
1. Based on WTI price of U.S.$50/bbl, AECO natural gas price of Cdn$2.82/Mcf
and an exchange rate of Cdn$1 = U.S.$0.74.
2. Royalties are before impacts of commodity risk management activities
3. Per boe estimates based on high and low ends of production guidance
—————————————————————————-

/T/

With the closing of the Olds/Garrington asset sale, the Company’s cash position
is approximately $330 million.

NYSE Listing

On May 16, 2017, the Corporation received a non-compliance notice from the NYSE
as a result of the 30 day average closing price of its shares falling below US
$1.00. The Board of Directors of the Corporation is currently not considering a
share consolidation proposal to shareholders to regain compliance. If the
Corporation’s share price on the NYSE does not rise above US $1.00 by November
16, 2017 it expects to receive a delisting notice from the NYSE. Such notice
will not impact the Corporation’s TSX listing.

Thank You

We would like to thank our staff who are leaving Pengrowth as a result of the
assets sales that we have completed this year. These people are talented
individuals who were an integral part of the Pengrowth team. They helped to
create significant value for our shareholders and were part of the fabric of
our culture. On behalf of our Board of Directors and our management team, we
thank them for their hard work and dedication and wish them the best in the
future.

Analyst call

Pengrowth will host an analyst call and listen-only audio webcast beginning at
3:00 P.M. Mountain Time (MT) on Monday, August 14, 2017, during which
management will review Pengrowth’s Second quarter results and respond to
questions from the analyst community.

To ensure timely participation in the teleconference, callers are encouraged to
dial in 10 minutes prior to the start of the call to register.

Dial-in numbers:

Toll free: (844) 358-9179 or International: (478) 219-0186

Live listen only audio webcast: http://edge.media-server.com/m/p/dazhk3h5

Pengrowth’s unaudited Financial Statements for the three and six months ended
June 30, 2017 and related Management’s Discussion and Analysis can be viewed on
Pengrowth’s website at www.pengrowth.com. They have also been filed on SEDAR at
www.sedar.com and on EDGAR at www.sec.gov/edgar

About Pengrowth:

Pengrowth Energy Corporation is a Canadian intermediate energy company focused
on the sustainable development and production of oil and natural gas in Western
Canada from its Lindbergh thermal oil property and its Groundbirch Montney gas
property. The Company is headquartered in Calgary, Alberta, Canada and has been
operating in the Western basin for over 28 years. The Company’s shares trade on
both the Toronto Stock Exchange under the symbol “PGF” and on the New York
Stock Exchange under the symbol “PGH”.

PENGROWTH ENERGY CORPORATION

Derek Evans, President and Chief Executive Officer

For further information about Pengrowth, please visit our website
www.pengrowth.com or contact: Investor Relations, E-mail:
investorrelations@pengrowth.com

Currency:

All amounts are stated in Canadian dollars unless otherwise specified.

Caution Regarding Engineering Terms:

When used herein, the term “boe” means barrels of oil equivalent on the basis
of one boe being equal to one barrel of oil or NGLs or 6,000 cubic feet of
natural gas (6 mcf: 1 bbl). Barrels of oil equivalent may be misleading,
particularly if used in isolation. A conversion ratio of six mcf of natural gas
to one boe is based on an energy equivalency conversion method primarily
applicable at the burner tip and does not represent a value equivalency at the
wellhead. All production figures stated are based on Company Interest before
the deduction of royalties.

Caution Regarding Forward Looking Information:

This press release contains forward-looking statements within the meaning of
securities laws, including the “safe harbour” provisions of the Canadian
securities legislation and the United States Private Securities Litigation
Reform Act of 1995. Forward-looking information is often, but not always,
identified by the use of words such as “anticipate”, “believe”, “expect”,
“plan”, “intend”, “forecast”, “target”, “project”, “guidance”, “may”, “will”,
“should”, “could”, “estimate”, “predict” or similar words suggesting future
outcomes or language suggesting an outlook. Forward-looking statements in this
press release include, but are not limited to: agreement in principle and key
elements of proposed amendments with noteholders and bank syndicate; pro forma
reduction of indebtedness; reduction in reserves as a result of dispositions;
$9 billion of low risk, high netback development opportunities at Lindbergh and
Groundbirch; anticipated long term growth in reserves, production and cash
flow; composition of the specific framework of the amendments to note
agreements and credit facility and that such amendments will become effective
in the third quarter of 2017; expected drilling at Lindbergh as well as the
timing of completion and tie-in of the new wells drilled and anticipated
production in early 2018; expectation that 70 percent of engineering and design
work for Lindbergh Phase II will be completed by the end of 2017; anticipated
future reductions in credit facilities; anticipated future asset sales;
anticipated timing of credit facility amendments; anticipated additional
financial flexibility; potential future asset sales and accessing of the
capital markets to replace existing debt with less restrictive high yield debt;
2017 full year guidance; anticipated fourth quarter of 2017 production; and
potential loss of NYSE listing. Forward-looking statements and information are
based on current beliefs as well as assumptions made by and information
currently available to Pengrowth concerning anticipated financial performance,
business prospects, strategies and regulatory developments. Although management
considers these assumptions to be reasonable based on information currently
available to it, they may prove to be incorrect.

By their very nature, forward-looking statements involve inherent risks and
uncertainties, both general and specific, and risks that predictions,
forecasts, projections and other forward-looking statements will not be
achieved. We caution readers not to place undue reliance on these statements as
a number of important factors could cause the actual results to differ
materially from the beliefs, plans, objectives, expectations and anticipations,
estimates and intentions expressed in such forward-looking statements. These
factors include, but are not limited to: changes in general economic, market
and business conditions; the volatility of oil and gas prices; fluctuations in
production and development costs and capital expenditures; the imprecision of
reserve estimates and estimates of recoverable quantities of oil, natural gas
and liquids; Pengrowth’s ability to replace and expand oil and gas reserves;
geological, technical, drilling and processing problems and other difficulties
in producing reserves; environmental claims and liabilities; incorrect
assessments of value when making acquisitions; increases in debt service
charges; the loss of key personnel; the marketability of production; defaults
by third party operators; unforeseen title defects; fluctuations in foreign
currency and exchange rates; fluctuations in interest rates; inadequate
insurance coverage; compliance with environmental laws and regulations; actions
by governmental or regulatory agencies, including changes in tax laws;
Pengrowth’s ability to access external sources of debt and equity capital; the
impact of foreign and domestic government programs and the occurrence of
unexpected events involved in the operation and development of oil and gas
properties. Further information regarding these factors may be found under the
heading “Business Risks” in our most recent management’s discussion and
analysis and under “Risk Factors” in our Annual Information Form dated February
28, 2017.

The foregoing list of factors that may affect future results is not exhaustive.
When relying on our forward-looking statements to make decisions, investors and
others should carefully consider the foregoing factors and other uncertainties
and potential events. Furthermore, the forward-looking statements contained in
this press release are made as of the date of this press release, and Pengrowth
does not undertake any obligation to update publicly or to revise any of the
included forward-looking statements, whether as a result of new information,
future events or otherwise, except as required by applicable laws. The
forward-looking statements contained in this press release are expressly
qualified by this cautionary statement.

Non-GAAP and Operational Measures

In addition to providing measures prepared in accordance with International
Financial Reporting Standards (IFRS), Pengrowth presents additional and
non-GAAP measures including adjusted net income (loss), operating netbacks,
total debt before working capital, total debt including working capital, cash
G&A expenses and funds flow from operations.

These measures do not have any standardized meaning prescribed by GAAP and
therefore are unlikely to be comparable to similar measures presented by other
companies.

These measures are provided, in part, to assist readers in determining
Pengrowth’s ability to generate cash from operations. Pengrowth believes these
measures are useful in assessing operating performance and liquidity of
Pengrowth’s ongoing business on an overall basis.

These measures should be considered in addition to, and not as a substitute
for, net income (loss), cash provided by operations and other measures of
financial performance and liquidity reported in accordance with IFRS. Further
information with respect to these additional and non-GAAP measures can be found
in the MD&A.

– END RELEASE – 14/08/2017

For further information:
Pengrowth
Wassem Khalil
Manager, Investor Relations
(403) 233-0224 or Toll free 1-855-336-8814

COMPANY:
FOR: PENGROWTH ENERGY CORPORATION
TSX SYMBOL: PGF
NYSE SYMBOL: PGH

INDUSTRY: Energy and Utilities – Oil and Gas
RELEASE ID: 20170814CC0065

Press Release from Marketwired 1-866-736-3779

Ottawa, Inuit agree on boundaries for Arctic marine conservation area

August 14, 2017August 14, 2017 by The Canadian Press

POND INLET, Nunavut — Inuit groups say their lobbying and traditional knowledge is behind a huge expansion in the boundaries for what is to become Canada’s largest national marine conservation area.

“Our organizations worked extremely hard to ensure the extended boundary was accepted,” said P.J. Akeeagok, head of the Qikiqtani Inuit Association.

“It was Inuit traditional knowledge that determined the extent and the purpose of how Inuit used this particular very important body of water, and we’re now here celebrating today the expanded boundaries.”

Federal Environment Minister Catherine McKenna joined Akeeagok and other Nunavut leaders in Pond Inlet on Monday to celebrate a deal that will more than double the size of the Lancaster Sound national marine conservation area — now to be known as Tallurutiup Imanga.

The sound, off the north coast of Baffin Island, is a particularly rich area of the Arctic. Its cliff-studded coastline is interspersed with bays, inlets and deep fiords. Most of the world’s narwhal, as well as large numbers of beluga and bowhead whales, swim amongst the icebergs that bob in its waters.

Polynyas — large sections of year-round, ice-free water — make rich habitat for seals and walrus, which in turn attract numerous polar bears. Seabirds flock there in the millions.

For centuries, Inuit have depended on its waters.

“It’s the cultural heart of our region,” said Akeeagok.

Inuit began fighting in the 1960s to have the waters protected.

In 2009, they went to court to block a German research vessel from conducting seismic tests that would have assessed the sound’s potential for oil and gas. The tests were blocked.

Some say the furor over the court case was behind the Harper government’s 2009 decision to launch a study into how big the conservation area should be and where to put its boundaries.

The Harper proposals, which were on the table as late as last year, called for setting aside about 48,000 square kilometres. Monday’s announcement creates an area of about 110,000 square kilometres.

Together with existing adjacent protected areas, more than 130,000 square kilometres of ocean will be protected from mining, energy development, dumping and overfishing.

“(The Inuit association) played a critical role (in the expansion),” said McKenna. Elders and Nunavut communities such as Pond Inlet were also heavily involved.

Shell Canada also helped. Facing a lawsuit over alleged invalid exploration permits it held in the region, the company chose last year to relinquish rights to more than 8,000 square kilometres of ocean.

McKenna said the new marine conservation area — Canada’s fifth — will be governed jointly with local Inuit. An impact-and-benefits agreement, complete with promises on new infrastructure and jobs, is planned for April.

“Inuit will be directly involved in decision-making.”

The talks will be crucial not only for Lancaster Sound, but for future protected areas, said Chris Debicki of The Pew Charitable Trusts Oceans North Canada.

“This is the start of negotiations between Inuit and the federal government that will determine how protection is going to look in the 21st century,” he said.

The Lancaster Sound expansion brings the portion of Canada’s marine waters under some form of protection to 3.5 per cent from 1.5 per cent. McKenna acknowledged that’s still below the government’s promised 10 per cent by 2020.

“We’re working really hard,” she said.

“We need to be doing this in partnership with Indigenous peoples, with different provinces and territories. Environmentalists and businesses are involved.”

— By Bob Weber in Edmonton. Follow him on Twitter at @row1960

The Canadian Press

Note to readers: This is a corrected story. An earlier version said the protected area was called Tallurutiup Tariunga.

NEW!! Energy Dialogues Podcast Series: Feature Guest: Drillform Technical Services with Host David Yager

August 14, 2017 by EnergyNow Media

Husky to buy refinery in Superior, Wis., for US$435 million in cash

August 14, 2017August 14, 2017 by The Canadian Press

CALGARY — A US$435-million deal to buy a refinery in Wisconsin will allow Husky Energy (TSX:HSE) to match processing capacity with its growing heavy oil output while postponing a planned asphalt plant expansion in Alberta.

The 50,000-barrel-per-day refinery in Superior, Wis., is being purchased from Calumet Specialty Products Partners of Indiana in a deal expected to close in the fourth quarter, the companies said Monday.

“Acquiring the Superior refinery will increase Husky’s downstream crude processing capacity, keeping value-added processing in lockstep with our growing production,” Husky CEO Rob Peabody said in a statement.

Husky’s heavy oil production from Alberta and Saskatchewan is currently about 170,000 barrels per day, but that will increase by about 40,000 bpd over the next three years, spokeswoman Kim Guttormson said.

The Superior refinery deal will grow capacity to refine heavy oil to about 205,000 bpd, she said. Overall downstream capacity, including light and medium grade oil refining, is to rise to about 395,000 bpd, with 275,000 bpd in the United States.

Husky owns a heavy oil upgrader and asphalt refinery in Lloydminster, on the Alberta-Saskatchewan border, as well as a light oil refinery in Lima, Ohio, and a 50 per cent stake with partner BP in a heavy oil refinery in Toledo, Ohio.

The Superior refinery produces about 9,000 bpd of asphalt, 17,500 bpd of gasoline and 10,900 bpd of diesel, as well as heavy fuel oils.

Husky has been contemplating an expansion of its asphalt refinery in Lloydminster to double production to about 30,000 bpd of asphalt.

A decision on the Lloydminster expansion, estimated to cost $800 million to $900 million, was expected next year, but will now be delayed until after 2020.

Analysts gave the acquisition passing marks Monday for its effect on Husky’s ability to capitalize on growing asphalt demand from increased infrastructure spending across North America.

Guttormson said asphalt is transported by rail and can easily be moved across the border to where it is in demand.

Husky plans to retain the approximately 180 workers at the refinery, which has direct pipeline connections to the company’s transport terminal in Hardisty, Alta.

Follow @HealingSlowly on Twitter.

Dan Healing, The Canadian Press

Note to readers: This is a corrected story. An earlier version incorrectly stated Husky’s current heavy oil production.

Five Things World Business Will be Talking About Today

August 14, 2017 by EnergyNow Media

August 14, 2017 (Bloomberg) North Korea tensions ease, the U.K. tries to regain Brexit momentum, and bitcoin’s on a massive rally. Here are some of the things people in markets are talking about today. Cooler heads Two top U.S. officials sought to ease concerns over possible nuclear conflict with North Korea in television interviews over the weekend. National … Read more

Energy Inflows May Give Spark to Languishing Canada Stock Market

August 14, 2017August 14, 2017 by EnergyNow Media

August 13, 2017 (Bloomberg) It hasn’t been a pretty year for Canadian stocks but signs are growing that the S&P/TSX Composite Index may be set for a rebound — if investors can move past geopolitical tensions and focus on the fundamentals. After gaining 18 percent in 2016 and hitting a record in February, the S&P/TSX … Read more

Oil Trades Near $49 as Investors Weight Rising Supply Against OPEC Cuts

August 14, 2017August 14, 2017 by EnergyNow Media

August 14, 2017 (Bloomberg) Oil traded near $49 a barrel as Libyan output and exports declined amid security threats and a labor dispute in the port of Zueitina. Futures fell 0.4 percent in New York after Friday’s 0.5 percent gain. Libya’s biggest oil field cut output by more than 30 percent, a person familiar with the … Read more

Spartan Energy Corp. Announces Increased 2017 Production Guidance and Second Quarter Financial and Operating Results

August 14, 2017 by The Canadian Press

FOR: SPARTAN ENERGY CORP.
TSX SYMBOL: SPE

Date issue: August 14, 2017
Time in: 8:00 AM e

Attention:

CALGARY, ALBERTA–(Marketwired – Aug. 14, 2017) – Spartan Energy Corp.
(“Spartan” or the “Company”) (TSX:SPE) is pleased to report its financial and
operating results for the three and six months ended June 30, 2017. Selected
financial and operational information is set out below and should be read in
conjunction with Spartan’s June 30, 2017 interim financial statements and the
related management’s discussion and analysis, which are available for review at
www.sedar.com or on the Company’s website at www.spartanenergy.ca.

UPWARD REVISION TO ANNUAL PRODUCTION GUIDANCE

Spartan is increasing our 2017 annual production guidance to 21,600 boe/d from
21,080 boe/d, representing annual production per share growth of 14%. We are
maintaining our 2017 drilling and maintenance capital budget of $145 million.

SECOND QUARTER FINANCIAL AND OPERATIONAL HIGHLIGHTS

Spartan’s highlights for the second quarter include:

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— Achieved record average production of 22,061 boe/d, comprised of 92% oil

and liquids, representing an increase of 143% (42% per share) over the
second quarter of 2016.
— Drilled 19 (16.7 net) development wells in the second quarter and
brought 23 (20.9 net) wells on production, including 13.3 net wells
drilled in the first quarter.
— Generated adjusted funds flow from operations of $46.1 million ($0.26
per basic share and $0.25 per diluted share), representing an increase
of 184% (63% per basic share and 67% per diluted share) over the second
quarter of 2016.
— Delivered excess cash flow (funds flow from operations less capital
expenditures exclusive of acquisitions, land, seismic and waterflood
capital) in the quarter of approximately $18.8 million.
— Reduced net general and administrative (“G&A”) expenses to $1.13 per
boe, a 49% decrease from the second quarter of 2016.
— Maintained our balance sheet strength, with net debt (exclusive of
finance lease obligations) at the end of the quarter of $204.1 million,
representing 1.1x annualized second quarter adjusted funds flow from
operations, and available liquidity of $145.9 million.

/T/

FINANCIAL RESULTS

/T/

—————————————————————————-
—————————————————————————-
(Cdn$000s except per
boe and per share Three Months Six Months
amounts) Ended June 30 Ended June 30
2017 2016 2017 2016
—————————————————————————-
—————————————————————————-

Average daily
production (boe/d) 22,061 9,080 21,760 9,381

Realized oil and gas
sales price
(excluding
derivatives)
($/boe) 52.65 43.83 53.22 37.61

Production costs
($/boe)(1) 18.47 15.04 18.03 14.86

Royalties ($/boe)(2) 8.78 6.55 8.61 5.51

Operating netback
($/boe)(3) 25.40 22.23 26.59 17.23

Net general and
administrative
expenses ($/boe) 1.13 2.23 1.10 2.11

Interest expense
($/boe) 1.28 0.32 1.33 0.57

Funds flow from
operations(3)(4) 46,142 16,265 95,165 24,869
per share –
basic(6) 0.26 0.16 0.54 0.26
per share –
diluted(6) 0.25 0.15 0.52 0.24

Net loss (9,829) (6,659) (9,585) (19,540)
per share –
basic(6) (0.06) (0.07) (0.05) (0.20)
per share –
diluted(6) (0.06) (0.07) (0.05) (0.20)

Capital
expenditures(5) 32,592 6,869 76,026 23,986

Net debt(3) (233,128) (100,359) (233,128) (100,359)
Net debt exclusive
of finance lease
obligations(3) (204,093) (100,359) (204,093) (100,359)

Bank Facility 350,000,000 150,000,000 350,000,000 150,000,000

Weighted average
shares outstanding

Basic(6) 175,612,037 102,320,614 175,458,342 96,516,401
Diluted(6) 183,244,450 110,215,196 183,700,228 104,006,280

(1) Including transportation costs.
(2) Royalties include the Saskatchewan resource surcharge.
(3) Funds flow from operations, operating netback, net debt and net debt

exclusive of finance lease obligations are non-IFRS measures. See “Non-
IFRS Measures”.
(4) Excluding transaction costs.
(5) Excluding acquisitions.
(6) Prior period numbers restated on a 3 for 1 basis to reflect share
consolidation that occurred on June 20, 2017.

/T/

OPERATIONAL UPDATE

Spartan had an active second quarter of operations due to a shortened break-up
period in southeast Saskatchewan. We re-commenced our drilling program in May,
drilling 19 (16.7 net) wells in the quarter and completing and bringing on
production an additional 16 (13.3 net) wells that were drilled in the first
quarter. We brought a total of 23 (20.9 net) wells on production in the
quarter, consisting of 8 (7.1 net) open-hole wells, 5 (5.0 net) frac Midale
wells, 2 (0.8) Torquay wells and 8 (8.0 net) Viking wells, with 10 (7.2 net)
wells drilled but not on production at the end of the quarter. Total capital
expenditures (excluding acquisitions, land, seismic and waterflood) were $27.3
million in the second quarter, bringing our total to $69.7 million in the first
half of 2017.

Our first half 2017 drilling program was focused on open-hole wells drilled
across our southeast Saskatchewan asset base and frac Midale wells drilled
primarily on our core Alameda property. We continue to operate three rigs in
southeast Saskatchewan drilling open-hole and frac Midale wells. In addition,
in the third quarter we drilled our first operated well on our recently
acquired Torquay acreage and have commenced drilling open-hole Frobisher and
Ratcliffe wells on properties acquired from Arc in late 2016.

Our first half drilling program yielded exceptional results, with average rates
from open-hole and frac Midale wells continuing to outperform internal type
curves. The success of our drilling program resulted in production of 22,061
boe/d in the quarter, up from 21,455 boe/d in the first quarter despite the
impacts of spring break-up. The combined impact of the outperformance of our
drilling program and the accretive acquisitions completed by Spartan in 2016
resulted in second quarter production per share increasing by 42% over the
second quarter of 2016.

Spartan delivered adjusted funds flow from operations in the quarter of $46.1
million ($0.26 per share), representing an increase of 184% (63% per basic
share) over the second quarter of 2016. Adjusted funds flow from operations
exceeded capital expenditures (excluding acquisitions, land, seismic and
waterflood capital) by approximately $18.8 million.

In addition to our successful drilling program, Spartan executed on our
business plan of deploying a portion of our excess cash flow to strategic
future investments, spending approximately $6.4 million on tuck-in
acquisitions, land additions and waterflood infrastructure in the second
quarter. Reservoir modelling is ongoing on waterflood initiatives at our core
Oungre, Winmore and Alameda properties, and we anticipate increased capital
spending on waterflood projects in the second half of the year.

Spartan continues to focus on cost savings to improve netbacks. Net G&A
expenses were $1.13 per boe in the second quarter, a reduction of 49% from the
second quarter of 2016. Production costs in the quarter were $18.47 per boe, up
from $17.56 in the first quarter of 2017. Scheduled turnarounds on acquired
facilities, an increase in rental payments made to surface land owners due to a
large number of leases that came due in the second quarter and an increase in
power costs in southeast Saskatchewan contributed to the increase in production
costs in the quarter. Spartan will continue to work diligently to reduce
production costs through the balance of 2017.

OUTLOOK AND REVISED PRODUCTION GUIDANCE

Spartan remains focused on delivering long term organic production growth
within cash flow while preserving our strong financial position. Due to the
outperformance of our drilling program, Spartan is increasing our 2017 annual
production guidance to 21,600 boe/d from 21,080 boe/d, representing annual
production per share growth of 14%. We are maintaining our 2017 drilling and
maintenance capital budget of $145 million, of which approximately $70 million
was spent in the first and second quarters with $75 million remaining for the
second half of the year. Our capital plan will remain flexible going forward as
we monitor production levels and commodity prices.

In the first half of 2017, Spartan has executed on our business plan of
delivering production growth within a subset of cash flow, while using excess
cash flow to fund strategic future investments. We increased corporate
production from our 2016 exit rate of 20,800 boe/d to 22,061 boe/d in the
second quarter, while delivering excess cash flow of approximately $25.5
million. We invested approximately $14.0 million of our excess cash flow in
tuck-in acquisitions, strategic land purchases and waterflood initiatives, with
an additional $11.5 million available to be deployed in the second half of the
year.

At current commodity prices, we forecast that we will generate excess cash flow
of approximately $10 to $15 million in the second half of 2017, bringing total
2017 unallocated excess cash flow to $21.5 to $26.5 million. We intend to
allocate up to $10 million to advance waterflood projects and will
strategically invest remaining excess cash flow in asset acquisitions, land and
seismic purchases or share buybacks to further enhance shareholder value.

Given our track record of operational execution, the depth of our inventory of
economic locations and the strength of our balance sheet, we believe Spartan
remains well positioned to succeed in a variety of commodity price
environments. We thank our shareholders of their support and we look forward to
the continued execution on our business plan during the remainder of the year.

READER ADVISORY

BOE Disclosure. The term barrels of oil equivalent (“BOE”) may be misleading,
particularly if used in isolation. A BOE conversion ratio of six thousand cubic
feet per barrel (6mcf/bbl) of natural gas to barrels of oil equivalence is
based on an energy equivalency conversion method primarily applicable at the
burner tip and does not represent a value equivalency at the wellhead. All BOE
conversions in the report are derived from converting gas to oil in the ratio
mix of six thousand cubic feet of gas to one barrel of oil.

Forward Looking Statements. Certain information included in this press release
constitutes forward-looking information under applicable securities
legislation. Forward-looking information typically contains statements with
words such as “anticipate”, “believe”, “expect”, “plan”, “intend”, “estimate”,
“propose”, “project” or similar words suggesting future outcomes or statements
regarding an outlook. Forward-looking information in this press release may
include, but is not limited to, planned drilling and completion activities,
planned investment in waterflood projects and land acquisitions, number of
drilling locations and years of drilling inventory, future production levels,
future cash flows at various WTI oil prices, future capital expenditure levels,
potential NCIB purchases and the completion of asset acquisitions.

The forward-looking statements contained in this press release are based on
certain key expectations and assumptions made by Spartan, including
expectations and assumptions concerning the success of future drilling,
development and completion activities, the performance of existing wells, the
performance of new wells, the availability and performance of facilities and
pipelines, the geological characteristics of Spartan’s properties, the
successful application of drilling, completion and seismic technology,
prevailing weather and break-up conditions, commodity prices, royalty regimes
and exchange rates, the application of regulatory and licensing requirements,
the availability of capital, labour and services, the creditworthiness of
industry partners and our ability to source and complete land and asset
acquisitions.

Although Spartan believes that the expectations and assumptions on which the
forward-looking statements are based are reasonable, undue reliance should not
be placed on the forward-looking statements because Spartan can give no
assurance that they will prove to be correct. Since forward-looking statements
address future events and conditions, by their very nature they involve
inherent risks and uncertainties. Actual results could differ materially from
those currently anticipated due to a number of factors and risks. These
include, but are not limited to, risks associated with the oil and gas industry
in general (e.g., operational risks in development, exploration and production;
the uncertainty of reserve estimates; the uncertainty of estimates and
projections relating to production, costs and expenses, and health, safety and
environmental risks), constraint in the availability of services, commodity
price and exchange rate fluctuations, adverse weather or break-up conditions
and uncertainties resulting from potential delays or changes in plans with
respect to exploration or development projects or capital expenditures. These
and other risks are set out in more detail in Spartan’s Annual Information Form
for the year ended December 31, 2016.

The forward-looking information contained in this press release is made as of
the date hereof and Spartan undertakes no obligation to update publicly or
revise any forward-looking information, whether as a result of new information,
future events or otherwise, unless required by applicable securities laws. The
forward looking information contained in this press release is expressly
qualified by this cautionary statement.

Non-IFRS Measures. Certain financial measures referred to in this press
release, such as adjusted funds flow from operations, adjusted funds flow from
operations per share, net debt and net debt excluding finance lease obligations
are not prescribed by IFRS. Adjusted funds flow from operations is calculated
based on cash flows from operating activities before changes in non-cash
working capital, transaction costs and decommissioning obligation expenditures
incurred. Adjusted funds flow from operations per share is calculated using
weighted average shares outstanding consistent with the calculation of net
income (loss) per share. Spartan uses adjusted funds flow from operations to
analyze operating performance and leverage, and considers adjusted funds flow
from operations to be a key measure as it demonstrates the Company’s ability to
generate cash necessary to fund future capital investments and repay debt.
Spartan’s determination of adjusted funds flow from operations, on an absolute
and per share basis, may not be comparable to that reported by other companies.

The following table reconciles adjusted funds flow from operations to cash flow
from operating activities, which is the most directly comparable measure
calculated in accordance with IFRS:

/T/

For the three months
ended June 30,
—————————————————————————-
($ thousands) 2017 2016 % change
—————————————————————————-
Cash flow from operating
activities 61,894 10,815 472
Transaction costs 201 565 (64)
Changes in non-cash
working capital (15,953) 4,885 (427)
—————————————————————————-
Adjusted funds flow from
operations 46,142 16,265 184
—————————————————————————-

For the six months
ended June 30,
—————————————————————————-
($ thousands) 2017 2016 % change
—————————————————————————-
Cash flow from operating
activities 107,174 5,838 1,736
Transaction costs 368 565 (35)
Changes in non-cash
working capital (12,377) 18,466 (167)
—————————————————————————-
Adjusted funds flow from
operations 95,165 24,869 283
—————————————————————————-

/T/

Net debt is calculated as bank debt plus trade and other liabilities plus
finance lease obligations less current assets. The following table reconciles
bank debt (an IFRS measure) to net debt (a non-IFRS measure):

/T/

—————————————————————————-
($ thousands) June 30, 2017 December 31, 2016
—————————————————————————-
Bank debt 176,406 217,921
Trade and other liabilities 64,601 38,546
Finance lease obligations 29,035 31,124
Current assets (36,914) (41,906)
—————————————————————————-
Net debt 233,128 245,685
—————————————————————————-

/T/

Spartan management considers net debt excluding finance lease obligations to be
a meaningful measure of the Company’s leverage and liquidity. The following
table reconciles net debt (a non-IFRS measure) to net debt excluding finance
lease obligations (a non-IFRS measure):

/T/

—————————————————————————-
($ thousands) June 30, 2017 December 31, 2016
—————————————————————————-
Net debt 233,128 245,685
Finance lease obligations (29,035) (31,124)
—————————————————————————-
Net debt excluding finance lease
obligations 204,093 214,561
—————————————————————————-

/T/

This press release also contains other industry benchmarks and terms, including
operating netbacks (calculated on a per unit basis as oil, gas and natural gas
liquids revenues, plus/minus realized derivative contracts, less royalties and
less operating and transportation costs), which are not recognized measures
under IFRS. Management believes that in addition to net income (loss) and cash
flow from (used in) operating activities, adjusted funds flow from operations,
net debt, net debt excluding finance lease obligations, total market
capitalization and operating netbacks are useful supplemental measures as they
provide an indication of Spartan’s operating performance, leverage and
liquidity. Investors should be cautioned, however, that these measures should
not be construed as an alternative to both net income (loss) and cash flow from
(used in) operating activities, which are determined in accordance with IFRS,
as indicators of Spartan’s performance.

– END RELEASE – 14/08/2017

For further information:
Spartan Energy Corp.
Richard (Rick) McHardy
President and Chief Executive Officer
OR
Spartan Energy Corp.
Tim Sweeney
Manager, Business Development
OR
Spartan Energy Corp.
Suite 500, 850 – 2nd Street S.W.
Calgary, Alberta T2P 0R8
403.355.2779 (FAX)
info@spartanenergy.ca

COMPANY:
FOR: SPARTAN ENERGY CORP.
TSX SYMBOL: SPE

INDUSTRY: Energy and Utilities – Oil and Gas
RELEASE ID: 20170814CC0026

Press Release from Marketwired 1-866-736-3779

Canacol Energy Ltd. Completes Testing of the Picoplata 1 Oil Well In Colombia

August 14, 2017 by The Canadian Press

FOR: CANACOL ENERGY LTD.
TSX SYMBOL: CNE
BVC SYMBOL: CNEC
OTCQX SYMBOL: CNNEF

Date issue: August 14, 2017
Time in: 6:30 AM e

Attention:

CALGARY, ALBERTA–(Marketwired – Aug. 14, 2017) – Canacol Energy Ltd.
(“Canacol” or the “Corporation”) (TSX:CNE)(OTCQX:CNNEF)(BVC:CNEC) is pleased to
provide the following update for the Picoplata 1 well in Colombia.

Picoplata 1 Exploration Well

VMM3 Exploration and Exploitation (“E&P”) Additional Contract, Middle Magdalena
Valley Basin

ConocoPhillips Colombia Ventures Ltd. 80% (ConocoPhillips Colombia or
Operator), Canacol Energy Ltd. 20%

The Picoplata 1 well was spud on October 16, 2014 and reached a total depth of
16,406 feet measured depth on January 29th, 2015. The well was designed to test
the petroleum potential of shales and limestones within the Cretaceous La Luna
Formation, and the well encountered over 1200 feet (“ft”) of potential oil
bearing reservoirs. In December of 2016 ConocoPhillips Colombia, the operator
of the contract, commenced completion and testing operations on the Picoplata 1
well. Five discrete formation injection tests and 3 hydraulic stimulations
spanning the entire interval were performed in 3 shale reservoir intervals
within the La Luna. The objective of the testing program was to collect
information on the productive capability of the reservoir, the quality of the
fluids contained within the reservoir, the formation pressure of the reservoir,
and the ability of the reservoir to be hydraulically stimulated.

The operation, completed in July of 2017, was successful with all intervals
that were hydraulically stimulated and tested producing light gravity crude oil
with no indication of formation water. Individual slickwater hydraulic
stimulation size in vertical well sections between 27 and 30 feet thick varied
between 80,000 and 346,000 pounds, with resulting natural flows averaging
between 19 to 120 barrels of oil per day with no formation water, over flow
periods of 3 to 28 days.

The testing program achieved the objective of collecting the post stimulation
production, pressure, and fluid data, as well as confirming the viability of
hydraulically stimulating the reservoirs, and the Picoplata 1 well is currently
being abandoned. Canacol and its partner ConocoPhillips Colombia are evaluating
the technical data collected from this well to plan the next steps towards
further evaluation of the La Luna on the block.

Canacol has 493,386 net acres across 5 blocks (3 operated and 2 non-operated)
in this prospective La Luna shale oil fairway located in the Middle and Upper
Magdalena Valley Basins of Colombia.

The Corporation shall provide further updates as new information becomes
available.

Canacol is an exploration and production company with operations focused in
Colombia, Ecuador, and Mexico. The Corporation’s common stock trades on the
Toronto Stock Exchange, the OTCQX in the United States of America, and the
Colombia Stock Exchange under ticker symbol CNE, CNNEF, and CNE.C, respectively.

This press release contains non-GAAP measures such as EBITDAX, funds from
operations, working capital, operating netback per barrel and realized
contractual gas sales that do not have any standardized meaning under IFRS and
may not be comparable to similar measures presented by other companies.
Management uses these non-GAAP measures for its own performance measurement and
to provide shareholders and investors with additional measurements of the
Corporation’s performance and financial results.

Realized contractual gas sales is defined as gas produced and sold plus gas
revenues received from nominated take or pay contracts.

Boe conversion – The term “boe” is used in this news release. Boe may be
misleading, particularly if used in isolation. A boe conversion ratio of cubic
feet of natural gas to barrels oil equivalent is based on an energy equivalency
conversion method primarily applicable at the burner tip and does not represent
a value equivalency at the wellhead. In this news release, we have expressed
boe using the Colombian conversion standard of 5.7 Mcf: 1 bbl required by the
Ministry of Mines and Energy of Colombia.

– END RELEASE – 14/08/2017

For further information:
Canacol Energy Ltd.
Investor Relations
214-235-4798
IR@canacolenergy.com
www.canacolenergy.com

COMPANY:
FOR: CANACOL ENERGY LTD.
TSX SYMBOL: CNE
BVC SYMBOL: CNEC
OTCQX SYMBOL: CNNEF

INDUSTRY: Energy and Utilities – Oil and Gas
RELEASE ID: 20170814CC0006

Press Release from Marketwired 1-866-736-3779

Sunshine Oilsands Ltd.: Announcement of Results for the Second Quarter ended June 30, 2017

August 13, 2017 by The Canadian Press

FOR: SUNSHINE OILSANDS LTD.
HKSE SYMBOL: 2012

Date issue: August 14, 2017
Time in: 1:10 AM e

Attention:

CALGARY, ALBERTA and HONG KONG, CHINA–(Marketwired – Aug. 14, 2017) – Sunshine
Oilsands Ltd. (the “Corporation” or “Sunshine”) (HKSE:2012) today announced its
financial results for the second quarter ended June 30, 2017. The Corporation’s
condensed consolidated interim financial statements, notes to the condensed
consolidated interim financial statements and management’s discussion and
analysis have been filed on SEDAR (www.sedar.com) and with The Stock Exchange
of Hong Kong Limited (the “Hong Kong Stock Exchange”) (www.hkexnews.hk) and are
available on the Corporation’s website (www.sunshineoilsands.com). All figures
used in this release are in Canadian dollars unless otherwise stated.

MESSAGE TO SHAREHOLDERS

On March 1, 2017, the Corporation achieved a key milestone. The Project
commenced commercial production. Hence, effective March 1, 2017, the
Corporation started recording revenue, expenses and depletion of the West Ells
Project.

Sunshine’s Capital Raising Activities

On April 5, 2017 the Corporation entered into a subscription agreement for a
total of 140,874,000 class “A” common shares at a price of HKD $0.241 per share
(approximately CAD $0.041 per common share), for gross proceeds of HKD $33.95
million (approximately CAD $5.8 million). On April 13, 2017 the Corporation
completed the closing of this subscription agreement.

On May 31, 2017 the Corporation entered into a subscription agreement for a
total of 67,511,000 class “A” common shares at a price of HKD $0.237 per share
(approximately CAD $0.041 per common share), for gross proceeds of HKD $15.88
million (approximately CAD $2.74 million). On June 7, 2017 the Corporation
completed the closing of this subscription agreement. In addition, a placing
commission of HKD $122,314 (approximately CAD $0.02 million), was incurred in
relation to the Closing.

Summary of Financial Figures

2Q17 net loss narrowed to CAD$19.5 million.

For the second quarter of the 2017, the Corporation’s net loss narrowed to CAD
$19.5 million from CAD $21.2 million for 2017 Q1 and from CAD $20.7 million for
2016 Q2, representing a net loss per share of CAD $0.004, CAD $0.004, and CAD
$0.005 for the 2017 Q2 period, 2017 Q1 period and 2016 Q2 period respectively.

The Corporation’s external auditor has not performed a review of the condensed
consolidated interim financial statements for the three and six months ended
June 30, 2017. As at June 30, 2017 and December 31, 2016, the Corporation notes
the following selected balance sheet figures.

/T/

—————————————————————————-
(Canadian $000s) June 30, December 31,
2017 2016
—————————————————————————-
Cash $ 4,544 $ 13,635
Trade and other receivables 4,627 2,654
Prepaid expense and deposits 2,556 5,054
Exploration and evaluation assets 293,281 291,716
Property, plant and equipment 686,688 684,531
Total liabilities 397,876 390,135
Shareholders’ equity 593,820 607,455
—————————————————————————-

/T/

2017 Outlook

Due to the extensive damage associated with the disastrous wild fire in Fort
McMurray in May 2016, start up at West Ells was interrupted and delayed.
Significant progress has been achieved since then. On March 1, 2017, the West
Ells Phase I project commenced commercial production. The West Ells Phase I
project is expected to ramp up to its Phase I designed capacity of 5,000
bbls/day. The Corporation continues to focus on carefully improving production
performance and developing SAGD chambers, which will increase production at
West Ells.

Hong Luo, Chief Executive Officer

Qiping Men, President & Chief Operating Officer

ABOUT SUNSHINE OILSANDS LTD.

The Corporation is a Calgary based public corporation, listed on the Hong Kong
Stock Exchange since March 1, 2012. The Corporation was also listed on the
Toronto Stock Exchange from November 16, 2012 to September 30, 2015, when it
chose to voluntarily delist. The Corporation is focused on the development of
its significant holdings of oil sands and heavy oil leases in the Athabasca oil
sands region. The Corporation owns interests in oil sands and petroleum and
natural gas leases in the Athabasca region of Alberta. The Corporation is
currently focused on executing milestone undertakings in the West Ells project
area. West Ells Phase 1 is operational and has an initial production target of
5,000 barrels per day.

FORWARD LOOKING INFORMATION

This announcement contains forward-looking information relating to, among other
things, (a) the future financial performance and objectives of Sunshine; (b)
the plans and expectations of the Corporation; and (c) the anticipated closings
of the current private placements and the timing thereof. Such forward-looking
information is subject to various risks, uncertainties and other factors. All
statements other than statements and information of historical fact are
forward-looking statements. The use of words such as “estimate”, “forecast”,
“expect”, “project”, “plan”, “target”, “vision”, “goal”, “outlook”, “may”,
“will”, “should”, “believe”, “intend”, “anticipate”, “potential”, and similar
expressions are intended to identify forward-looking statements.
Forward-looking statements are based on Sunshine’s experience, current beliefs,
assumptions, information and perception of historical trends available to
Sunshine, and are subject to a variety of risks and uncertainties including,
but not limited to, those associated with resource definition and expected
reserves and contingent and prospective resources estimates, unanticipated
costs and expenses, regulatory approval, fluctuating oil and gas prices,
expected future production, the ability to access sufficient capital to finance
future development and credit risks, changes in Alberta’s regulatory framework,
including changes to regulatory approval process and land-use designations,
royalty, tax, environmental, greenhouse gas, carbon and other laws or
regulations and the impact thereof and the costs associated with compliance.
Although Sunshine believes that the expectations represented by such
forward-looking statements are reasonable, there can be no assurance that such
expectations will prove to be correct. Readers are cautioned that the
assumptions and factors discussed in this announcement are not exhaustive and
readers are not to place undue reliance on forward-looking statements as the
Corporation’s actual results may differ materially from those expressed or
implied. Sunshine disclaims any intention or obligation to update or revise any
forward-looking statements as a result of new information, future events or
otherwise, subsequent to the date of this announcement, except as required
under applicable securities legislation. The forward-looking statements speak
only as at the date of this announcement and are expressly qualified by these
cautionary statements. Readers are cautioned that the foregoing lists are not
exhaustive and are made as at the date hereof. For a full discussion of the
Corporation’s material risk factors, see the Corporation’s annual information
form for the year ended December 31, 2016 and risk factors described in other
documents we file from time to time with securities regulatory authorities, all
of which are available on the Hong Kong Stock Exchange at www.hkexnews.hk, on
the SEDAR website at www.sedar.com or the Corporation’s website at
www.sunshineoilsands.com.

By Order of the Board of Sunshine Oilsands Ltd.,

Sun Kwok Ping, Executive Chairman

Hong Kong, August 14, 2017

Calgary, August 14, 2017

As at the date of this announcement, the Board consists of Mr. Kwok Ping Sun,
Mr. Hong Luo, Mr. Qiping Men and Ms. Gloria Pui Yun Ho as executive directors;
Mr. Michael John Hibberd, Ms. Linna Liu and Ms. Xijuan Jiang as non-executive
directors; and Mr. Raymond Shengti Fong, Mr. Jeff Jingfeng Liu, Ms. Joanne Yan
and Mr. Yi He as independent non-executive directors.

Hong Kong Exchanges and Clearing Limited and The Stock Exchange of Hong Kong
Limited take no responsibility for the contents of this announcement, make no
representation as to its accuracy or completeness and expressly disclaim any
liability whatsoever for any loss howsoever arising from or in reliance upon
the whole or any part of the contents of this announcement.

This announcement appears for information purpose only and does not constitute
an invitation or offer to acquire, purchase or subscribe for securities of
Sunshine Oilsands Ltd.

(a corporation incorporated under the Business Corporations Act of the Province
of Alberta, Canada with limited liability)

– END RELEASE – 14/08/2017

For further information:
Sunshine Oilsands Ltd.
Mr. Hong Luo
Chief Executive Officer
(1) (403) 930-5677
OR
Sunshine Oilsands Ltd.
Qiping Men
President & Chief Operating Officer
(1) (403) 984-5142
investorrelations@sunshineoilsands.com
www.sunshineoilsands.com

COMPANY:
FOR: SUNSHINE OILSANDS LTD.
HKSE SYMBOL: 2012

INDUSTRY: Energy and Utilities – Oil and Gas
RELEASE ID: 20170814CC0001

Press Release from Marketwired 1-866-736-3779

Oil Caps Weekly Drop Amid Shaky OPEC Compliance, Weaker Demand

August 11, 2017 by EnergyNow Media

August 11, 2017 (Bloomberg) Oil had its worst week in a month as compliance with OPEC’s deal falters and the outlook for demand worsens. While a weaker dollar helped push prices in New York 0.5 percent higher on Friday, erasing earlier losses, futures closed 1.5 percent down for the week. The International Energy Agency reduced demand estimates … Read more

The Difference Between “Activity” and “Opportunity” in Your Sales Funnel

August 13, 2017August 11, 2017 by EnergyNow Media

Written by Hamish Knox; President of Sandler in Calgary, Canada Creating accountable, sales focused organizations in Calgary You’ve vanished the magicians from your sales funnel and your team embraced the mindset of “always be advancing the sale,” yet as you look at your most recent sales funnel report you see a few opportunities hanging around … Read more

Niko Reports Results for the Quarter Ended June 30, 2017

August 11, 2017 by The Canadian Press

FOR: NIKO RESOURCES LTD.
TSX Symbol: NKO

Date issue: August 11, 2017
Time in: 4:30 PM e

Attention:

CALGARY, AB –(Marketwired – August 11, 2017) – Niko Resources Ltd. (“Niko”
or the “Company”) (TSX: NKO) is pleased to report its operating and financial
results for the quarter ended June 30, 2017. The operating results are
effective August 11, 2017. All amounts are in US dollars unless otherwise
indicated and all amounts are reported using International Financial Reporting
Standards unless otherwise indicated.

CHIEF EXECUTIVE OFFICER’S MESSAGE TO THE SHAREHOLDERS

Our efforts continue to monetize the Company’s core assets for the benefit of
all its stakeholders. Market conditions in the industry coupled with our
on-going legal issues in India and Bangladesh make this process challenging.

The Company’s liquidity situation is a critical concern. As a result, the
Company has recently requested consent of its senior lenders to access a
portion of the funds in a reserve account to provide additional liquidity.

No assurance can be made that these efforts will provide a solution on a
timely basis or at all.

We are committed to doing our best for the benefit of all stakeholders and
while we remain hopeful, we acknowledge that much work has to be done.

William Hornaday – Chief Executive Officer, Niko Resources Ltd.

LIQUIDITY AND CAPITAL RESOURCES

Funding of Projected Cash Requirements of the Company

The Company’s cash flow has been negatively impacted by the failure of
Bangladesh Oil, Gas and Mineral Corporation (“Petrobangla”) to comply with its
legal obligations as outlined below. In addition, certain outcomes in respect
of ongoing disputes noted below could have a material adverse impact on cash
flow.

The Company’s cash balances as at June 30, 2017 and projected revenues from
its assets in India are not expected to be sufficient to fund the projected
cash requirements of the Company’s assets in India and its other cash
requirements over the next several months. As a result, in August 2017, the
Company requested consent from the Lenders under its amended and restated
facilities agreement to use a portion of the funds in a restricted cash
reserve account to meet its cash requirements. A decision from the Lenders is
expected before the end of August 2017. An adverse decision from the Lenders
will have a material adverse impact on the Company’s ability to fund its
operations and may lead the Company to take steps which could be adverse to
all stakeholders.

The Company’s cash resources, and therefore its ability to fund its
operations, could be positively enhanced by various factors, including the
following:

/T/

— Receiving payments from Petrobangla of amounts due,
— Executing sale(s) of the Company’s interests in its core assets in India

and Bangladesh, or
— Obtaining financing for planned development projects in the D6 Block.

/T/

No assurance can be made that appropriate steps will be taken, or goals
accomplished, in a manner or on a timely basis so as to enhance the Company’s
cash resources sufficiently. The failure to enhance the Company’s cash
resources on a timely basis will have a material adverse impact on the ability
of the Company to fund its operations.

Non-payments by Petrobangla of Amounts Due

Since June 2016, Petrobangla has paid reduced amounts to the operator of the
Block 9 PSC for invoiced amounts due for gas and condensate supplied from
March 2016 to March 2017 pursuant to the Block 9 gas and condensate sales
agreements, with the amounts withheld equal to the 60 percent share in the
Block 9 PSC held by Niko Exploration (Block 9) Limited (“Niko Block 9”) and
totalling $37 million to date. Niko Block 9 has issued notices of dispute and
force majeure under the Block 9 PSC and sales agreements to the Government of
Bangladesh (“GOB”) and Petrobangla. As the cash flow that was expected to be
generated by the Block 9 PSC was targeted to fund the capital and operating
expenditure of Block 9 as well as other cash requirements of the Company,
since late September 2016 Niko Block 9 has not paid cash calls that were due
and has been issued default notices by the operator of the Block 9 PSC. Under
the terms of the joint operating agreement (“JOA”) between the participating
interest holders in the Block 9 PSC, during the continuance of a default, the
defaulting party shall not have a right to its share of gas and condensate
sales proceeds, which shall vest in and be the property of the non-defaulting
parties who have paid to cover the amount in default in order to recover the
amounts owed by the defaulting party. In addition, if the defaulting party
does not cure a default within sixty days of the default notice, the
non-defaulting parties have the option to require the defaulting party to
withdraw from the PSC and JOA. To date, the non-defaulting parties have not
exercised this option. Refer to Note 24(a)(ii) of the condensed interim
consolidated financial statements for the three months ended June 30, 2017 for
further details on this matter.

Minimum Contract Quantities Dispute – India

As previously disclosed in Note 32(c) in the audited consolidated financial
statements for the year ended March 31, 2017, in accordance with previous
contracts for natural gas sales from the Hazira field in India, the Company
had committed to deliver certain minimum quantities. For the period ended
December 31, 2007, the Company was unable to deliver the minimum quantities to
certain customers and the Company’s joint operating partner in the Hazira
field delivered the shortfall volumes from other gas sources. The Company’s
joint operating partner filed arbitration claims for losses incurred as a
result of the delivery of these shortfall volumes.

In June 2017, the arbitration tribunal issued an award in favour of the
Company’s joint operating partner in an amount of approximately $17.8 million
along with the interest thereon at the rate of 10% per annum from 2012 to the
date of award (approximately $9.7 million) plus further interest at 10% per
annum from the date of the award until payment. The Company plans to appeal
the award in the Indian court system under the rules governing Indian
arbitration. The results of this dispute could have a material adverse impact
on the Company’s future cash flows.

Exploration Subsidiaries

The Company’s exploration subsidiaries that previously owned interests in PSCs
in Trinidad and Indonesia have significant accounts payable and accrued
liabilities (including PSC obligations) and unfulfilled exploration work
commitments reflected on the Company’s balance sheet as at June 30, 2017. In
May 2017, the Company’s indirect subsidiaries received written notices from
the GORTT terminating the three PSCs. In the Company’s view, the parent
guarantees for unfulfilled exploration commitments for the three PSCs have
expired. Effective with the termination of the PSCs, the Company reclassified
the Trinidad segment as discontinued operations in the condensed interim
consolidated financial statements for the three months ended June 30, 2017.

Contingent Liabilities

The Company and its subsidiaries are subject to various claims from other
parties, as described in Note 24 of the condensed interim consolidated
financial statements as at and for the three months ended June 30, 2017 and
are actively defending against these claims. An adverse outcome on one or more
of these claims could significantly impact the future cash flows of the
Company.

Ability of the Company to Continue as a Going Concern

As a result of the foregoing matters (including the ongoing obligations of the
Company and its subsidiaries), there are material uncertainties that may cast
significant doubt about the ability of the Company to continue as a going
concern.

Complete details of the Company’s financial results are contained in its
condensed interim consolidated financial statements and Management’s
Discussion and Analysis for the three months ended June 30, 2017 which will be
available under the Company’s SEDAR profile at www.sedar.com.

OVERALL PERFORMANCE AND RESULTS OF OPERATIONS BY REPORTABLE SEGMENT

The Company’s financial results for the three months ended June 30, 2017 were
impacted by the following significant items:

Non-payments by Petrobangla of Amounts Due

As a result of the continued non-payments by Petrobangla of amounts due and
Niko Block 9’s non-payments of cash calls due to the operator and the default
mechanism in the Block 9 JOA, the invoices issued by the operator of the Block
9 PSC for gas and condensate sales to Petrobangla for September 2016 to June
30, 2017 reflect the non-defaulting parties’ entitlement to the sales proceeds
and, as such, the Company has not recognized $24 million of net oil and gas
revenues that it otherwise would have been entitled to, of which $6 million
related to natural gas and condensate sales in the first quarter of fiscal
2018. In addition, the Company recognized an impairment of $13 million in the
second quarter of fiscal 2017 related to the net revenue receivable from
Petrobangla for the months of March 2016 to August 2016, of which $6 million
related to the natural gas and condensate sales in the first quarter of fiscal
2017.

If the non-defaulting parties to the Block 9 exercise their option to require
Niko Block 9 to withdraw from the PSC and JOA and if this results in a loss of
Niko Block 9’s interest in the PSC and JOA, then a full impairment of the
Company’s carrying value of the assets and liabilities related to Block 9
could result.

Minimum Contract Quantities Dispute – India

As a result of the arbitration award described above in respect of the Hazira
field in India, in the first quarter of fiscal 2018, the Company recognized a
liability of $28 million for awarded amount plus accrued interest to June 30,
2017.

The Company’s results for the first quarter ended June 30, 2017 are as
follows:

Consolidated

/T/

—————————————————————————-

Three months
(thousands of US Dollars, ended June 30,
unless otherwise indicated) 2017 2016
—————————————————————————-
Sales volumes (MMcfe/d)(1) 83 93
Net oil and natural gas revenue 5,764 16,355
EBITDAX from continuing operations(2) (680) 8,831
Net income (loss) from continuing operations (34,337) (20,831)
Net income (loss) from discontinued operations 180 (812)
—————————————————————————-

/T/

(1) Includes volumes for April 2017 to June 2017 in Bangladesh for which
revenue has not been recognized (see below).
(2) Refer to “Non-IFRS Measures” for details.

Production declines and lower natural gas prices for the D6 Block in India and
the non-recognition of net revenue for Block 9 in Bangladesh contributed to
lower net oil and natural gas revenue and lower EBITDAX for the Company in the
first quarter of fiscal 2018 compared to the first quarter of fiscal 2017.

Net loss from continuing operations of $34 million in the first quarter of
fiscal 2018 was primarily due to the recognition of a liability of $28 million
for an arbitration award relating to the minimum contracted quantities dispute
in India. Net loss from continuing operations of $21 million in the first
quarter of fiscal 2017 related primarily to interest expense recorded on the
term loan and convertible notes and restructuring costs associated with the
amendments to the term loan facilities agreement and convertible note
indenture executed in July 2016 (the Amendments) that do not require the
Company to make interest payments, other than in connection with waterfall
distributions (as described in Note 13 of the condensed interim consolidated
financial statements for the three months ended June 30, 2017).

India

/T/

—————————————————————————-

Three months
(thousands of US Dollars, ended June 30,
otherwise indicated) 2017 2016
—————————————————————————-
Sales volumes (MMcfe/d) 23 33
Net oil and natural gas revenue 5,759 10,029
Segment EBITDAX(1) 3,087 5,214
Segment loss (29,023) (2,853)
—————————————————————————-

/T/

(1) Refer to “Non-IFRS Measures” for details.

Total sales volumes from the D6 Block in the first quarter of fiscal 2018 of
23 MMcfe/d decreased from 33 MMcfe/d in the first quarter of fiscal 2018
primarily due to the impact of natural production declines and water and sand
ingress that resulted in the shut-in of wells, partially offset by the impact
of incremental production from sidetrack wells brought on-stream in the second
half of fiscal 2017.

Net oil and natural gas revenues decreased in the first quarter of fiscal 2018
compared to the first quarter of fiscal 2017 primarily due to lower sales
volumes and natural gas prices. The notified price for gas sales from the D6
Block was $2.48 / MMbtu for April 1, 2017 to September 30, 2017, which is
approximately 20 percent lower than the price of $3.06 / MMbtu for April 1,
2016 to September 30, 2016.

Segment EBITDAX of $3 million in the first quarter of fiscal 2018 decreased
compared to the first quarter of fiscal 2017 primarily due to lower net oil
and natural gas revenues, partially offset by lower production and operating
expenses for the D6 Block.

Segment loss of $29 million in the first quarter of fiscal 2018 increased
compared to segment loss of $3 million in the first quarter of fiscal 2017
primarily due to lower EBITDAX and the recognition of a liability of $28
million for an arbitration award relating to the minimum contracted quantities
dispute in India, partially offset by lower depletion expense in first quarter
of fiscal 2018.

Bangladesh

/T/

—————————————————————————-

Three months ended
(thousands of US Dollars, June 30,
unless otherwise indicated) 2017 2016
—————————————————————————-
Sales volumes (MMcfe/d)(1) 59 60
Net oil and natural gas revenue – 6,322
Segment EBITDAX(2) (1,510) 4,282
Segment income (loss) (2,713) 2,792
—————————————————————————-

/T/

(1) Includes volumes for April 2017 to June 2017 for which revenue has not
been recognized (see below).
(2) Refer to “Non-IFRS Measures” for details.

Total sales volumes from Block 9 in the first quarter of fiscal 2018 were
slightly lower than the first quarter of fiscal 2017, as the impact of
increased delivery pressure requirements of the sales trunkline, was nearly
offset by the impact of a development well that was brought on-stream in the
fourth quarter of fiscal 2017.

Net oil and natural gas revenue in the first quarter of fiscal 2018 was not
recognized due to non-payment of sales revenue by Petrobangla (refer to
discussion on Non-payments by Petrobangla of Amounts Due in the Liquidity and
Capital Resources section).

Segment EBITDAX in the first quarter of fiscal 2018 decreased compared to
first quarter of fiscal 2017 primarily as a result of the non-recognition of
net oil and gas revenues, partially offset by lower production and operating
expenses.

Segment loss of $3 million in the first quarter in fiscal 2018 increased
compared to segment income of $3 million in first quarter of fiscal 2017
primarily as a result of lower segment EBITDAX, partially offset by lower
depletion expense.

Other

/T/

—————————————————————————-

Three months
(thousands of US Dollars, ended June 30,
unless otherwise indicated) 2017 2016
—————————————————————————-
Segment EBITDAX from continuing operations(1) (2,257) (665)
Segment loss from continuing operations (2,601) (20,770)
Net income (loss) from discontinued operations 180 (812)
—————————————————————————-

/T/

(1) Refer to “Non-IFRS Measures” for details.

Segment EBITDAX from continuing operations in the first quarter in fiscal 2018
decreased from the first quarter of fiscal 2017, primarily due to increased
legal costs associated with the Company’s ICSID arbitration cases and foreign
exchange loss.

Segment loss from continuing operations in the first quarter in fiscal 2018
decreased from a segment loss of $21 million in first quarter of fiscal 2017,
as the Company recorded $17 million interest expense and $2 million of
restructuring costs related to the Term Loan and Convertible Notes in the
first quarter of fiscal 2017.

Forward-Looking Information

Certain statements in this press release constitute forward-looking
information. Specifically, this press release contains forward looking
information relating to the Company’s ability to fund its cash requirements
over the next several months, the ability of the Company to successfully
complete its strategic plan on a timely basis, the ability to receive consent
from the Lenders for the release of funds from a restricted cash reserve
account, and the ability to successfully appeal an arbitration award in
respect of Hazira field in India. Such forward-looking information is based on
a number of risks, uncertainties and assumptions, which may cause actual
results or other expectations to differ materially from those anticipated and
which may prove to be incorrect. There can be no assurances that the Company
will be able to successfully complete its strategic plan on a timely basis or
that the Company will be able to meet the goals and purposes of its business
plan (including resolving various disputes against governments and others in
its favour) or fund its operations over the next several months. The failure
to meet or satisfy any of the foregoing is likely to have a material adverse
impact on the Company and thereby significantly impair the value of security
holders’ interest in the Company. Undue reliance should not be placed on
forward-looking information. Such forward-looking information reflects the
Company’s current beliefs and assumptions and is based on information
currently available to the Company. This forward-looking information is based
on certain key expectations and assumptions, many of which are not within the
control of the Company and include expectations and assumptions regarding the
future actions of the Company’s lenders, non-defaulting parties not seeking to
require a subsidiary of the Company to withdraw from the Block 9 PSC or JOA, a
successful appeal of an arbitration award in respect of Hazira field in India,
future commodity prices, results of operations, production, future capital and
other expenditures (including the amount, nature and sources of funding
thereof), competitive advantages, plans for and results of drilling activity,
environmental matters, business prospects and opportunities, prevailing
exchange rates, applicable royalty rates and tax laws, future well production
rates, the performance of existing wells, the success of drilling new wells,
the availability of capital to undertake planned activities, the availability
and cost of labour and services and general market conditions. The reader is
cautioned that the assumptions used in the preparation of such information,
although considered reasonable at the time of preparation, may prove to be
incorrect. Actual results may vary from the information provided herein as a
result of numerous known and unknown risks and uncertainties and other factors
and such variations may be material. Such risk factors include, but are not
limited to: risks related to the ability of the Company to continue as a going
concern, risks related to the Company not being able to increase its cash
resources, the risks associated with the Company meeting its obligations under
the amended Facilities Agreement and successfully completing its strategic
plan, risks related to the various legal claims against the Company or its
subsidiaries, risks related to non-payments by Petrobangla of amounts due to
subsidiaries of the Company, as well as the risks associated with the oil and
natural gas industry in general, such as operational risks in development,
exploration and production, delays or changes in plans with respect to
exploration or development projects or capital expenditures, the uncertainty
of estimates and projections relating to production rates, costs and expenses,
commodity price and exchange rate fluctuations, government regulation,
marketing and transportation risks, environmental risks, competition, the
ability to access sufficient capital from internal and external sources,
changes in tax, royalty and environmental legislation, the impact of general
economic conditions, imprecision of reserve estimates, the lack of
availability of qualified personnel or management, stock market volatility,
risks associated with meeting all of the Company’s financing obligations and
contractual commitments (including work commitments), the risks discussed
under “Risk Factors” in the Company’s Annual Information Form for the
year-ended March 31, 2017 and in the Company’s public disclosure documents,
and other factors, many of which are beyond the Company’s control. Niko makes
no representation that the actual results achieved during the forecast period
will be the same in whole or in part as those forecasts.

The forward looking information included in this press release is expressly
qualified in its entirety by this cautionary statement. The forward looking
information included herein is made as of the date of this press release and
Niko assumes no obligation to update or revise any forward looking information
to reflect new events or circumstances, except as required by law.

Non-IFRS Measures

The selected financial information presented throughout this press release is
prepared in accordance with IFRS, except for “EBITDAX” and “Segment EBITDAX”.
The Company utilizes EBITDAX and Segment EBITDAX to assess performance and to
help determine its ability to fund future capital projects and to repay debt.
EBITDAX and Segment EBITDAX is calculated as net income before interest
expense, income taxes, depletion and depreciation expenses, exploration and
evaluation expenses, and other non-cash items (gain or loss on debt
modification, gain or loss on asset disposal, gain or loss on derivatives,
asset impairment, share-based compensation expense, restructuring expenses,
accretion expense, unfulfilled exploration commitment expense, commercial
claim expense and unrealized foreign exchange gain or loss). EBITDAX and
Segment EBITDAX should not be viewed as a substitute for measures of financial
performance presented in accordance with IFRS or as a measure of a company’s
profitability or liquidity. These non-IFRS measures do not have any
standardized meaning prescribed by IFRS and is therefore may not be comparable
to similar measures presented by other companies. Refer to the Company’s
Management’s Discussion and Analysis for details on these non-IFRS financial
measures.

– END RELEASE – 11/08/2017

For further information:

For further information, please contact:
Niko Resources Ltd.
(403) 262-1020
Glen Valk
VP Finance & CFO
www.nikoresources.com

COMPANY:
FOR: NIKO RESOURCES LTD.
TSX Symbol: NKO

INDUSTRY: Energy and Utilities – Oil and Gas
RELEASE ID: 20170811CC003

Press Release from Marketwired 1-866-736-3779

Corridor Announces Second Quarter Results

August 11, 2017 by The Canadian Press

FOR: CORRIDOR RESOURCES INC.
TSX SYMBOL: CDH

Date issue: August 11, 2017
Time in: 4:15 PM e

Attention:

HALIFAX, NOVA SCOTIA–(Marketwired – Aug. 11, 2017) – Corridor Resources Inc.
(“Corridor”) (TSX:CDH) announced today its second quarter financial results.

The following table provides a summary of Corridor’s financial and operating
results for the three and six months ended June 30, 2017, with comparisons to
the three and six months ended June 30, 2016. Corridor’s unaudited financial
statements and management’s discussion and analysis for the second quarter have
been filed on SEDAR at www.sedar.com and are available on Corridor’s website at
www.corridor.ca. All amounts referred to in this press release are in Canadian
dollars unless otherwise stated.

/T/

Selected Financial Information
—————————————————————————-

Three months ended Six months ended
June 30 June 30
thousands of dollars except per
share amounts 2017 2016 2017 2016
—————————————————————————-
Sales $ 46 $ 2,523 $ 4,513 $ 9,018
Net income (loss) $ (1,510) $ (41,629) $ 315 $ (40,346)
Net income (loss) per share –
basic and diluted $ (0.017) $ (0.469) $ 0.004 $ (0.455)
Cash flow from operations (1) $ (1,282) $ (1) $ 2,401 $ 3,352
Working capital $ 31,796 $ 29,476 $ 31,796 $ 29,476
Total assets $ 103,508 $ 92,783 $ 103,508 $ 92,783
—————————————————————————-
—————————————————————————-
(1) Cash flow from operations is a non-IFRS measure. Cash flow from
operations represents net earnings adjusted for non-cash items including
depletion, depreciation and amortization, deferred income taxes, share-
based compensation and other non-cash expenses. See “Non-IFRS Financial
Measures” in Corridor’s MD&A for the six months ended June 30, 2017.

Q2 2017 Netback Analysis
—————————————————————————-

Three months ended Six months ended
June 30 June 30
thousands of dollars 2017 2016 2017 2016
—————————————————————————-
Natural gas sales $ 38 $ 2,205 $ 4,204 $ 8,519
Realized financial derivatives
gain – – 1,094 –
Other revenues 8 318 309 499
Royalties (1) (46) (93) (183)
Transportation expense – (1,079) (428) (2,434)
Production expense (510) (532) (1,299) (1,249)
—————————————————————————-
Field operating netback $ (465) $ 866 $ 3,787 $ 5,152
—————————————————————————-

Natural gas production per day
(mmscfpd) 0.1 6.9 3.6 7.5
Barrels of oil equivalent per day
(boepd) 18 1,143 604 1,249
Average natural gas price
($/mscf) $ 3.86 $ 3.53 $ 6.41 $ 6.25
—————————————————————————-
—————————————————————————-

/T/

Unlike prior financial periods, Corridor has determined not to make any
disclosure of its financial performance on a per boe basis for the three and
six months ended June 30, 2017 and 2016, as any such disclosure would not be a
meaningful indicator of the performance of Corridor given its nominal
production in Q2 2017 as compared to prior comparative periods.

2017 Second Quarter Highlights

/T/

— Corridor shut-in most of its natural gas production starting in April

2017 in accordance with its production optimization strategy. This
strategy results in the shut-in of much of Corridor’s producing natural
gas wells in the McCully Field in New Brunswick during low summer/fall
season prices and timing the start-up of production to maximize the
recovery of flush volumes with peak winter pricing. Management will
continue to monitor forecast prices but expects to continue restricting
production until November 2017.
— At June 30, 2017, Corridor had cash and cash equivalents of $30,755
thousand, working capital of $31,796 thousand and no outstanding debt.
— Subsequent to the quarter end, Corridor and the Quebec Government
entered into a settlement agreement which facilitates an end to
Corridor’s participation in oil and gas exploration on Anticosti Island,
Quebec. Under the settlement agreement, Corridor agreed to proceed with
the cessation of all hydrocarbon exploration activities on Anticosti
Island and the Quebec Government paid $19.5 million to Corridor in
consideration for, amongst other things, the prejudice suffered by
Corridor in connection with its interests in Anticosti Hydrocarbons L.P.
The Quebec Government has also agreed to reimburse Corridor for any
further amounts expended prior to its departure from Anticosti Island,
and to assume all abandonment and reclamation obligations in respect of
three Anticosti wells in which Corridor has an interest outside of
Anticosti Hydrocarbons L.P.

/T/

Outlook

The Board of Directors has approved a total capital budget of $3.7 million for
the year ended December 31, 2017 which includes $3.1 million for the cost of a
user license for a controlled source electro-magnetic (“CSEM”) data program to
investigate the resistivity of geological prospects over the Newfoundland and
Labrador sector of the Old Harry prospect. The undertaking of the CSEM program,
currently planned by an independent service provider, is scheduled for October
2017, subject to receipt of necessary regulatory approvals.

“With working capital of approximately $51 million, we will continue to be
patient and selective in any opportunities we may decide to pursue.” said Steve
Moran, President and Chief Executive Officer.

Corridor is a Canadian junior resource company engaged in the exploration for
and development and production of petroleum and natural gas onshore in New
Brunswick and offshore in the Gulf of St. Lawrence. Corridor currently has
natural gas production and reserves in the McCully Field near Sussex, New
Brunswick. In addition, Corridor has a shale gas prospect in New Brunswick and
an offshore conventional hydrocarbon prospect in the Gulf of St. Lawrence.

Forward Looking Statements

This press release contains certain forward-looking statements and
forward-looking information (collectively referred to herein as
“forward-looking statements”) within the meaning of Canadian securities laws.
All statements other than statements of historical fact are forward-looking
statements. Forward-looking information typically contains statements with
words such as “anticipate”, “believe”, “plan”, “continuous”, “estimate”,
“expect”, “may”, “will”, “project”, “should”, or similar words suggesting
future outcomes. In particular, this press release contains forward-looking
statements pertaining to: business plans and strategies, including optimization
strategies to shut-in production in 2017 and potential opportunities; the 2017
capital budget; exploration and development plans, including the acquisition
of, the timing and cost of, and the benefits of, CSEM data; and natural gas
prices.

Undue reliance should not be placed on forward-looking statements, which are
inherently uncertain, are based on estimates and assumptions, and are subject
to known and unknown risks and uncertainties (both general and specific) that
contribute to the possibility that the future events or circumstances
contemplated by the forward-looking statements will not occur. There can be no
assurance that the plans, intentions or expectations upon which forward-looking
statements are based will in fact be realized. Actual results will differ, and
the difference may be material and adverse to Corridor and its shareholders.

Forward-looking statements are based on Corridor’s current beliefs as well as
assumptions made by, and information currently available to, Corridor
concerning anticipated financial performance, business prospects, strategies,
regulatory developments, discussions to date with the Government of Quebec,
future natural gas commodity prices, future natural gas production levels, the
ability to obtain equipment in a timely manner to carry out development
activities, the ability to market natural gas successfully to current and new
customers, the impact of increasing competition, the ability to obtain
financing on acceptable terms, and the ability to add production and reserves
through development and exploration activities. Although management considers
these assumptions to be reasonable based on information currently available to
it, they may prove to be incorrect. By their very nature, forward-looking
statements involve inherent risks and uncertainties, both general and specific,
and risks that forward-looking statements will not be achieved. These factors
may be found under the heading “Risk Factors” in Corridor’s Annual Information
Form for the year ended December 31, 2016.

The forward-looking statements contained in this press release are made as of
the date hereof and Corridor does not undertake any obligation to update
publicly or to revise any of the included forward-looking statements, except as
required by applicable law. The forward-looking statements contained herein are
expressly qualified by this cautionary statement.

– END RELEASE – 11/08/2017

For further information:
Steve Moran
President and CEO
Corridor Resources Inc.
#301, 5475 Spring Garden Road, Halifax, Nova Scotia B3J 3T2
(902) 429-0209 (FAX)
(902) 429-4511
www.corridor.ca

COMPANY:
FOR: CORRIDOR RESOURCES INC.
TSX SYMBOL: CDH

INDUSTRY: Energy and Utilities – Oil and Gas
RELEASE ID: 20170811CC0039

Press Release from Marketwired 1-866-736-3779

IEA Drives OPEC from Quiet Confidence to Panic Stations: Gadfly

August 11, 2017 by EnergyNow Media

August 11, 2017 (Bloomberg Gadfly) OPEC’s job of re-balancing the oil market has just got a lot more difficult. Not only is there a lot more oil in storage than it previously thought, but the group will need to make deeper output cuts to drain the excess. A month ago OPEC oil ministers had probably … Read more

Five Things World Business Will be Talking About Today

August 11, 2017 by EnergyNow Media

August 11, 2017 (Bloomberg) Trump ups the rhetoric, markets sell off some more, and U.S. inflation data due. Here are some of the things people in markets are talking about today. Tougher talk President Donald Trump said yesterday that his “fire and fury” comments may not have been tough enough, and refused to rule out a … Read more

Oil Slides Near $48 as IEA Cuts Demand Estimates for OPEC Crude

August 14, 2017August 11, 2017 by EnergyNow Media

August 11, 2017 (Bloomberg) Oil headed for a second weekly loss after the International Energy Agency reduced demand estimates for OPEC crude and said the group’s commitment to drain a global glut is fading. Futures declined 0.3 percent in New York. Neither a pledge by the two biggest Organization of Petroleum Exporting Countries producers to strengthen their commitment … Read more

Pengrowth Announces Closing of $300 Million Olds/Garrington Area Asset Sale

August 11, 2017 by The Canadian Press

FOR: PENGROWTH ENERGY CORPORATIONTSX SYMBOL: PGFNYSE SYMBOL: PGHDate issue: August 11, 2017Time in: 11:46 AM eAttention:
CALGARY, ALBERTA–(Marketwired – Aug. 11, 2017) – Pengrowth Energy Corporation
(TSX:PGF)(NYSE:PGH) is pleased to report that it ha…

Touchstone Announces Second Quarter 2017 Results

August 10, 2017 by The Canadian Press

FOR: TOUCHSTONE EXPLORATION INC.TSX SYMBOL: TXPAIM SYMBOL: TXPDate issue: August 11, 2017Time in: 2:01 AM eAttention:
CALGARY, ALBERTA–(Marketwired – Aug. 11, 2017) – Touchstone Exploration Inc.
(“Touchstone” or the “Company”) (TSX:TXP)(AIM:TXP) anno…

B.C. replaces Saskatchewan as fossil fuel thorn in Trudeau’s side

August 11, 2017August 10, 2017 by The Canadian Press

OTTAWA — Prime Minister Justin Trudeau lost the harshest critic of his plan to impose a carbon tax with Brad Wall’s surprise announcement Thursday that he’s retiring as Saskatchewan’s premier.

But just as Trudeau pulled that persistent thorn from his right side, he was stabbed in the left side by another thorn as British Columbia’s fledgling NDP government unveiled plans to block construction of the proposed Trans Mountain pipeline.

The twin announcements underscored the political teeter-totter Trudeau has been riding as he attempts to prove it’s possible — indeed necessary, in his opinion — to simultaneously combat climate change and build new pipeline capacity to get western Canada’s fossil fuels to tidewater.

Wall has threatened to go to court to prevent the federal government from imposing a carbon tax of $10 per tonne — rising to $50 in 2022 — on provinces that don’t implement a carbon pricing regime of their own by next year.

Saskatchewan is the only province that has flat-out refused to even consider carbon pricing, which Wall maintains would devastate the province’s already struggling oil and gas industry.

While his successor will doubtless carry on the crusade, along with federal Conservatives led by fellow Saskatchewanian Andrew Scheer, Wall has been the most articulate and highest-profile opponent of the scheme with a knack for simplifying the complicated issue. For instance, he’s summed up the federal carbon tax plan as “a ransom note.”

“He was a fierce defender of Saskatchewan and western Canada on this critical issue so it is a loss in that sense,” Conservative Sen. Denise Batters, a long-time friend and supporter, said in an interview.

Just how much relief Wall’s departure will give the Trudeau government on the carbon pricing front remains to be seen.

“Whenever a person who has cut such a large figure, certainly in Saskatchewan politics but also on the national scene, when a person of that longevity and strength decides to make a break and go do something else, it’s obviously a major change,” Public Safety Minister Ralph Goodale, who holds the Liberals’ only seat in Saskatchewan, said in an interview.

“What will result from that, who the successor will be, how it will effect the policy debate about various issues from time to time remains to be seen.”

Goodale praised Wall’s unquestioned “passion” for Saskatchewan and pointed out that, apart from the climate change file, he has worked co-operatively with the federal Liberals on a host of other issues: health care, child care, infrastructure, softwood lumber and the upcoming renegotiation of the North American Free Trade Agreement.

Wall briefly stoked renewed speculation Thursday that he may jump to the federal political arena when he said he’s leaving politics in Saskatchewan. “I should have said anywhere,” he clarified later.

Goodale said the federal carbon pricing plan is “an absolute linchpin” for getting approval of any pipelines.

“With carbon pricing in place, we can not only argue the economic gains that come from pipelines … but also the environmental integrity of the process because it is rooted in that fundamental principle of carbon pricing,” he said.

Yet, just as Wall’s departure will silence the leading critic of Trudeau’s carbon tax plan, the government has to contend with a newly minted NDP government. It reasserted Thursday its campaign vow to use “every tool available” to block Kinder Morgan’s proposed Trans Mountain pipeline expansion, which the Trudeau government has approved.

In the few weeks following the new government’s swearing-in last month, there was briefly some small hope among federal Liberals that Premier John Horgan might back off. Indeed, the pipeline wasn’t even mentioned when Horgan had a first, congenial meeting with Trudeau a couple of weeks ago, at which the two leaders chose instead to focus on issues upon which they agree.

That hope was dashed with Thursday’s announcement that B.C. is joining the legal fight against the pipeline. The Horgan government also warned Kinder Morgan, which had planned to start construction in September, that the province has rejected five of eight environmental management plans required to begin work on the project because of inadequate consultations with effected First Nations communities.

“Until that has been completed, Kinder Morgan, with the exception of some private land and some clearing of right-of-way, cannot put shovels in the ground,” said B.C.’s environment minister, George Heyman.

A spokesman for Natural Resources Minister Jim Carr said the federal government “will stand by” its decision to approve the Trans Mountain expansion, “based on facts and on evidence and what is in the national interest.”

“We have taken an approach to resource development that will grow our economy and protect the environment,” Alexandre Deslongchamps said. “Our government believes that these priorities go hand-in-hand.”

Goodale said the Trudeau government only approved the Trans Mountain project after thorough, comprehensive and inclusive consultations “where all points of view were heard and treated respectfully and taken into account.”

Joan Bryden, The Canadian Press

Quebec to pay Petrolia $20.5 million to end Anticosti oil development

August 10, 2017 by The Canadian Press

QUEBEC — The Quebec government will pay $20.5 million to Petrolia as part of its plan to end oil development on Anticosti Island.

The province’s Energy and Natural Resources Department said in a statement Thursday the compensation deal is based on public interest.

In late July, the government announced it was halting oil and gas exploration on the island and was negotiating with several companies to get them to abandon their research rights.

The decision was made to protect the island’s natural character and in support of its bid to become a UNESCO World Heritage Site.

With deals that have already been reached with Junex, Corridor and Maurel & Prom, the total compensation is more than $61 million.

The Canadian Press

Eagle Energy Inc. Announces Second Quarter 2017 Results, Succession Plan and Cost Reduction Initiatives

August 10, 2017 by The Canadian Press

FOR: EAGLE ENERGY INC.TSX SYMBOL: EGLDate issue: August 10, 2017Time in: 9:29 PM eAttention:
CALGARY, ALBERTA–(Marketwired – Aug. 10, 2017) – Eagle Energy Inc. (TSX:EGL)
(“Eagle”) is pleased to report its financial and operating results for the
secon…

Saudi, Iraq Oil Ministers Agree to Stronger Oil-Cuts Commitment

August 10, 2017 by EnergyNow Media

August 10, 2017 (Bloomberg) OPEC’s two biggest producers agreed to strengthen their commitment to production cuts and maintain balance in world crude markets, Saudi Energy Minister Khalid Al-Falih said after talks with his Iraqi counterpart Jabbar al-Luaibi, according to the kingdom’s state news agency SPA. The two ministers also agreed to ensure coordination of their … Read more

Saskatchewan Premier Brad Wall Retiring From Politics: Read & Watch

August 11, 2017August 10, 2017 by EnergyNow Media

Saskatchewan Premier Brad Wall announced on Thursday he is retiring from politics after 14 years as the leader of the Saskatchewan Party. Wall, 51, said he would stay on as premier until the party elects a new leader. “Together with [my wife] Tami, I have decided that now is the time for renewal — for … Read more

The Canadian Association of Oilwell Drilling Contractors (CAODC) Condemns B.C.’s Decision to Take Legal Action to Halt Trans Mountain Pipeline

August 11, 2017August 10, 2017 by EnergyNow Media

Today British Columbia’s Environment and Climate Change Strategy Minister George Heyman announced his government has retained external legal counsel to initiate legal action related to the Trans Mountain Expansion Pipeline. Mr. Thomas Berger, QC, OC, OBC has been secured by the Province as part of its stated strategy to “use all available tools” to block … Read more

Trump names ex-McConnell aide to lead energy agency for now

August 10, 2017 by The Canadian Press

WASHINGTON — President Donald Trump on Thursday named a former aide to Senate Majority Leader Mitch McConnell as interim leader of the commission that oversees the U.S. power grid.

Trump elevated Neil Chatterjee, McConnell’s longtime energy adviser, to head the Federal Energy Regulatory Commission, or FERC, for at least the next few weeks.

The appointment came as Trump resumed his taunts of McConnell, the Senate’s top Republican, expressing disbelief that McConnell couldn’t persuade a GOP majority to pass a health care bill.

“Can you believe that Mitch McConnell, who has screamed Repeal & Replace for 7 years, couldn’t get it done. Must Repeal & Replace ObamaCare!” Trump tweeted Thursday.

Hours later, Trump used Twitter to target McConnell again, nudging him to plunge into issues such as tax reform and infrastructure, even though Congress is on recess until after Labor Day.

On energy, Trump is waiting for the McConnell-led Senate to confirm his nomination of Washington lawyer Kevin McIntyre as FERC chairman. Chatterjee, who was sworn in as a commissioner this week, takes over on an interim basis, replacing Democrat Cheryl LaFleur.

Former Pennsylvania utility regulator Robert Powelson was sworn in Thursday as a FERC member, giving the five-member panel a voting quorum for the first time since February. Without a quorum, the agency has been unable to make decisions on natural gas pipelines and other projects worth billions of dollars.

Trump has promised to boost energy production and exports as part of a bid to establish “energy dominance” for the United States, but the FERC vacancies have hobbled the agency’s ability to make decisions.

More than a dozen major projects and utility mergers have been in regulatory limbo for months. The projects include the $2 billion Nexus pipeline in Ohio and Michigan; the $1 billion PennEast pipeline in Pennsylvania and New Jersey; and the $5 billion Atlantic Coast Pipeline in West Virginia, Virginia and North Carolina.

Matthew Daly, The Associated Press

Timeline: Key dates in the history of the Trans Mountain pipeline

August 10, 2017 by The Canadian Press

VANCOUVER — Kinder Morgan Canada’s proposal to triple the capacity of its Trans Mountain oil pipeline to 900,000 barrels a day has made it through years of regulatory and political scrutiny to secure approval. But there are still hurdles to clear.

Here are some key dates in the history of the Trans Mountain pipeline as Kinder Morgan Canada pushes towards starting construction in September:

October 1953: The Trans Mountain pipeline begins shipping oil with an initial capacity of 150,000 barrels per day. The project features four pump stations along its 1,150-kilometre route and a marine dock that connects loading facilities on the east side of Edmonton with ocean tankers in Burnaby, B.C.

1957: Pipeline capacity is expanded via the construction of a 160-kilometre pipeline loop. The Westridge Marine Terminal is built and commissioned in Burnaby, B.C.

Jan. 14, 1985: Trans Mountain’s biggest spill occurs at a tank farm in the Edmonton area. Nearly 10,000 barrels of oil are released.

2006 – 2008: The Anchor Loop project adds 160 kilometres of new pipeline through Jasper National Park and Mount Robson Provincial Park between Hinton, Alta., and Hargreaves, B.C. The extension includes 13 new pump stations and modifications to existing stations, increasing capacity from 260,000 bpd to 300,000 bpd.

Feb. 21, 2012: Kinder Morgan says it wants to expand the Trans Mountain pipeline after receiving support from oil shippers and will begin public consultations.

Dec. 16, 2013: An application is made to the National Energy Board (NEB) to expand the Trans Mountain pipeline. Construction is proposed to begin in 2017, with the aim of having oil flow through the expansion by December 2019.

November 2014: More than 100 people are arrested after they camp out in a conservation area on Burnaby Mountain, east of Vancouver, to block crews from conducting drilling and survey work related to the pipeline expansion. Most of the charges are later dropped.

August 2015: The NEB postpones public hearings after striking from the record economic evidence prepared by a Kinder Morgan consultant who was to begin working for the regulator.

Jan. 12, 2016: Alberta Premier Rachel Notley says in a written submission to the NEB that the Trans Mountain pipeline expansion is in the best interests of both Alberta and Canada.

Jan. 27, 2016: The federal Liberal government says pipeline projects such as the Trans Mountain expansion will now be assessed in part on the greenhouse gas emissions produced in the extraction and processing of the oil they carry. Proponents will also be required to improve consultations with First Nations.

May 17, 2016: Ottawa appoints a three-member panel to conduct an environmental review of the Trans Mountain expansion project.

May 29, 2016: The NEB recommends approval of the pipeline, subject to 157 conditions, concluding that it is in the public interest.

Nov. 29, 2016: Prime Minister Justin Trudeau sanctions the Trans Mountain expansion, part of a sweeping announcement that also saw approval of Enbridge’s Line 3 pipeline replacement but the end of its Northern Gateway project.

Jan. 11, 2017: B.C. Premier Christy Clark announces her support for the project, saying Kinder Morgan has met five government conditions including a revenue-sharing agreement worth up to $1 billion.

May 15, 2017: The Federal Court of Appeal grants Notley’s government intervener in a lawsuit filed by municipalities and First Nations against the project.

May 25, 2017: Kinder Morgan makes its final investment decision to proceed with the development, now estimated to cost $7.4-billion, subject to the successful public offering of Kinder Morgan Canada.

May 29, 2017: The B.C. NDP and Greens agree to form a coalition to topple the Liberal party, which won a minority government in an election earlier in the month. The parties agree to “immediately employ every tool available” to stop the project.

May 30, 2017: Kinder Morgan Canada (TSX:KML) debuts on the Toronto Stock Exchange after a $1.75 billion public offering, one of the largest IPOs in the exchange’s history.

June 29, 2017: The B.C. Liberals lose a no-confidence vote, clearing the way for NDP Leader John Horgan to become premier.

Aug. 10, 2017: The B.C. NDP government hires former judge Thomas Berger to provide legal advice as it seeks intervener status in the legal challenges against the project filed by municipalities and First Nations.

The Canadian Press

B.C. joins legal battles against Trans Mountain pipeline expansion

August 11, 2017August 10, 2017 by The Canadian Press

VANCOUVER — British Columbia says it will join the legal fight against the Trans Mountain pipeline expansion, while warning the company it can’t begin work on public land until it gets final approval from the province.

The NDP government has hired former judge Thomas Berger to provide legal advice as it seeks intervener status in court challenges against Ottawa’s approval of the $7.4-billion project.

Premier John Horgan promised in the provincial election this spring to use “every tool in the toolbox” to stop the expansion by Trans Mountain, a subsidiary of Kinder Morgan Canada.

Environment Minister George Heyman said the expansion is not in the province’s “best interests.”

“A seven-fold increase in tanker traffic in B.C.’s coastal waters is simply too great a risk to our environment, our economy and to thousands of existing jobs,” he said.

B.C.’s former Liberal government issued an environmental certificate for the project earlier this year.

Trans Mountain has said construction is set to begin in September, but Heyman said only three of eight environmental management plans required by the province have been accepted. It’s unlikely those remaining will get approval before work was to start, he said.

The other five management plans have not been accepted because the company didn’t adequately consult First Nations, Heyman said.

“Until that has been completed, Kinder Morgan, with the exception of some private land and some clearing of right-of-way, cannot put shovels in the ground.”

Heyman said a storage facility and marine terminal in Burnaby are on private property, but the majority of the pipeline either passes through First Nations territory or public land.

Kinder Morgan Canada president Ian Anderson said the company takes the comments of the B.C. government seriously and will meet with it to work through its concerns.

“We have undertaken thorough, extensive and meaningful consultations with Aboriginal Peoples, communities and individuals and remain dedicated to those efforts and relationships as we move forward with construction activities in September,” he said in a statement.

Fifty-one First Nations have signed mutual benefit agreements with Trans Mountain. Heyman said some do not necessarily favour the pipeline but want to ensure their people benefit if it proceeds.

The province is also committed to further consultations with First Nations on the project, including the impact it has on Aboriginal rights and title, Heyman said.

Attorney General David Eby said the legal challenges against Ottawa’s approval are expected to be heard this fall.

The Squamish Nation has also filed a lawsuit against B.C. over its environmental certificate, putting the new government in the awkward position of having to defend the approval of a project it opposes.

Eby said the province is working closely with Berger, a renowned lawyer and leader of the B.C. NDP in the 1960s, whom the attorney general praised as a “living example of modern First Nations law in Canada.” Berger and his team will be responsible for filing a response to the Squamish Nation’s lawsuit.

A spokesman for Natural Resources Minister Jim Carr said the federal government’s approval of the project was based on facts, evidence and the national interest.

“We look forward to working with every province and territory to ensure a strong future for Canadians but the facts and evidence do not change,” said Alexandre Deslongchamps in a statement.

The province’s announcement won support from environmental groups and the Green party, which has signed an agreement to back the minority NDP government in the legislature.

Green Leader Andrew Weaver accused Prime Minister Justin Trudeau of playing a “political game” and “bullying” B.C. He said the outlook for the project is dark given the opposition from the province, environmental groups and many Vancouver-area voters.

“Trans Mountain will never be built,” Weaver said. “I’m convinced of that.”

The Canadian Association of Oilwell Drilling Contractors condemned the province’s position and called on Ottawa to prevent B.C. from “holding the jobs and livelihoods of thousands of Canadians and British Columbians hostage.”

B.C. Liberal Leader Rich Coleman said the NDP is driving home the message that the province is not open for business.

“The B.C. NDP are hiring high-priced help to find ways to introduce more red tape so they can strangle another project.”

— Follow @ellekane on Twitter.

Laura Kane , The Canadian Press

Note to readers: This is a corrected story. In a previous version, the attorney general erroneously said that the province filed their response to Squamish Nation.

Trican Reports Second Quarter Results for 2017 and Updates 2017 Capital Program

August 10, 2017 by The Canadian Press

FOR: TRICAN WELL SERVICE LTD.
TSX SYMBOL: TCW

Date issue: August 10, 2017
Time in: 6:01 PM e

Attention:

CALGARY, ALBERTA–(Marketwired – Aug. 10, 2017) – Trican Well Service Ltd.
(TSX:TCW) (“Trican” or the “Company”) is pleased to announce its Second Quarter
results for 2017 and provides an update on its 2017 Capital Program. The
following news release should be read in conjunction with the Management’s
Discussion and Analysis, the unaudited interim consolidated financial
statements and related notes of Trican for the three and six months ended June
30, 2017, as well as the Annual Information Form for the year ended December
31, 2016. All of the above documents are available on Trican’s website at
www.tricanwellservice.com and on SEDAR at www.sedar.com.

SIGNIFICANT EVENT

On June 2, 2017, the Company closed an arrangement with Canyon Services Group
Inc. (“Canyon”) pursuant to which the Company acquired all of the issued and
outstanding common shares of Canyon (the “Canyon Shares”) on the basis of 1.70
common shares of Trican (the “Trican Shares”) for each outstanding Canyon Share
(the “Transaction”).

Three and six month financial results include Canyon’s financial and operating
results effective June 2, 2017.

SECOND QUARTER HIGHLIGHTS

/T/

— Consolidated revenue from continuing operations for Q2 2017 was $137.2

million, an increase of 322% compared to Q2 2016, and comparable to Q1
2017 revenue of $149.4 million.
— Fracturing intensity increased significantly as the Company pumped
approximately four times more proppant this quarter compared to the same
period last year, and approximately 25% more than Q1 2017 volumes.
— Q2 2017 represented the highest quarterly volume of proppant pumped in
Canada by Trican.
— Adjusted operating income(1) for the quarter was $12.2 million, compared
to a $19.1 million adjusted operating loss in Q2 2016 (excludes $8.8
million generated by Canyon in Q2 2017 prior to the Transaction).
— Annualized cost synergies(1) of $18 million.
— Negotiated price increases for the second half of 2017 of 20%-25% from
Q1 2017 levels.
— Exited Q2 2017 with all of our activated equipment fully utilized. We
expect full utilization to carry-forward through the rest of 2017.

/T/

Utilization of our activated equipment during Q2 2017 was relatively high
during the normally slow spring break-up season. The result was that Trican
pumped more proppant in Q2 2017 relative to both Q1 2017 and Q2 2016. This
resulted in the Company generating positive adjusted operating income(1),
significantly ahead of Q2 2016 levels. Second quarter 2017 adjusted operating
income(1) remained positive despite typical spring break-up conditions and
customer delays from some of the Company’s largest customers. In Q4 2016, the
Company had agreed to spring break-up discounted pricing arrangements with
certain of its customers to ensure minimum levels of activity during Q2 2017.
This resulted in an approximate 8% pricing decline in Q2 2017 relative to Q1
2017. However, pricing levels have significantly increased compared to the
second quarter of 2016.

CONTINUING OPERATIONS – FINANCIAL REVIEW

/T/

Three months ended Six months ended
($ millions, except
per share amounts;
job count;
proppant(1)
(thousands); and
HHP1 (thousands); June 30, June 30, March 31, June 30, June 30,
unaudited) 2017 2016 2017 2017 2016
—————————————————————————-
Revenue $137.2 $32.5 $149.4 $286.6 $132.4
Gross profit / (loss) (0.4) (28.5) 17.8 17.5 (59.8)
Operating income /
(loss)(1) (4.0) (29.2) 22.7 18.7 (55.6)
Adjusted operating
income / (loss)(1) 12.2 (19.1) 26.0 38.3 (35.3)
Net income / (loss) 8.1 (40.4) (37.6) (40.8) (82.9)
Per share – basic
and diluted $0.03 ($0.26) ($0.19) ($0.19) ($0.55)
Job count(1) 2,267 1,310 3,554 5,821 3,776
Proppant pumped
(tonnes)(1) 293 58 235 528 173
Canadian Segment
Hydraulic Pumping
Capacity
Total average
HHP(1) 508 424 424 466 424
Total exit HHP(1) 680 424 424 680 424
Total exit
activated HHP(1) 476 232 254 476 232
—————————————————————————-

/T/

OUTLOOK

Demand for our services has been steadily increasing during the past nine
months, and this trend intensified very early in the first quarter of 2017 and
carried on into the second quarter. We are currently operating at approximately
70% of our total fracturing capacity and 60% of our other pressure pumping
equipment. The key limiting factor to activating more equipment is the lack of
qualified personnel, which will be the key challenge to reactivating additional
equipment.

The undersupply of manned equipment in the pressure pumping industry resulted
in many customers not completing their work programs in the first half of the
year and pushed their programs to the second half. We expect this backlog of
work, combined with our anchor customers’ planned third quarter programs will
result in third quarter activity levels being considerably higher on a
sequential and year-over-year basis for all of our service lines. Management’s
expectations for the second half of 2017 are that activity and pricing will
continue to build from second quarter levels as many work programs have been or
are being repriced for the third and fourth quarters of 2017. Specifically, the
Company anticipates price increases of approximately 20%-25% for pressure
pumping services relative to Q1 2017 pricing levels. We do not anticipate
pricing increases to translate fully to increased margins due to cost inflation.

We activated 57,500 HHP of fracturing equipment and 4 cement crews during the
first half of 2017 and will continue to add capacity where possible. In the
current commodity price environment, we believe that demand is sufficient that
two more fracturing crews can be added in the third quarter, with the
possibility for a third crew to be activated once we receive clarity of our
customer’s 2018 budgets. This would represent the activation of an incremental
75,000 HHP currently parked fracturing equipment and bring our total active
horsepower to 85% of our fracturing fleet. If activity levels remain high and
sufficient personnel are recruited, our entire fracturing fleet could be
activated within the next twelve months. We expect that these activations would
secure work at the leading edge of pricing which would provide Trican with
rates of return in excess of our cost of capital. To support our reactivation
efforts, we have continued to hire and train during spring break-up.

The integration of Canyon with Trican is progressing as planned. We had
previously anticipated $20 million of annualized cost synergies and have
already achieved approximately $18 million of cost synergies (annualized)
to-date. The largest intangible synergy already being realized is the
integration of operations which is allowing us to service more customers and
increase our overall operational efficiency levels.

The primary challenges the Company expects in the second half of 2017 are:

/T/

— Personnel optimization: increasing our headcount to reactivate idled

equipment to service excess customer demand; and
— Minimizing cost inflation: minimizing the effects increasing pressure
pumping activity will have on the Company’s ongoing cost of operating.

/T/

Personnel Optimization

While the Company did not add significant staff through second quarter
recruiting efforts, the acquisition of Canyon provided an incremental labour
pool which has assisted the Company in optimizing organizational efficiency. As
a result of having additional crews and equipment that provide more
flexibility, the newly combined Company has been able to service incremental
customers that each of Canyon and Trican individually would not have been able
to service. This efficiency is evidenced by the sequential increase in overall
proppant volumes pumped during Q2 2017 relative to Q1 2017.

Minimizing Cost Inflation

Trican continues to be proactive in working with its suppliers to ensure the
effects of cost inflation are muted. The acquisition of Canyon provides further
scale with which Trican can work with its suppliers to minimize the effects of
cost inflation. In addition, the increased scale of the Company has allowed the
Company to optimize the business as can be evidenced by the previously
described annualized cost synergies.

2017 Capital Expenditures

The Company expects to spend approximately $25 million on capital equipment
during the second half of 2017. The Capital expenditures are selectively
targeted at equipment that will assist in improving Trican’s operational
efficiencies, particularly in the area of proppant logistics and handling. The
Company anticipates that maintenance capital expenditures will increase as the
intensity of hydraulic fracturing increases; however, we believe that current
pricing strategies reflect and support this anticipated increase in fracturing
intensity.

TRICAN ESTIMATED COMBINED FINANCIAL RESULTS(1)

The following tables summarize the combined operating results of Trican and
Canyon for the three and six months ended June 30, 2017. The calculated
combined financial results are estimates and may not be representative of
financial results had the Canyon acquisition actually occurred on April 1, 2017
and January 1, 2017, respectively:

/T/

—————————————————————————-

Period from
Three months April 1, 2017 Three months
ended June 30, to June 1, ended June 30,
($ thousands; unaudited) 2017 2017 2017
Trican Canyon Combined
—————————————————————————-
Revenue 137,197 88,468 225,665
Consolidated Gross Profit /
(Loss) (IFRS financial
measure) (350) 6,206 5,856
Deduct:
Administrative expenses (25,543) (12,487) (38,030)
Add:
Depreciation & amortization 2,513 1,296 3,809
Depreciation expense – cost
of sales 19,369 7,442 26,811
—————————————————————————-
Consolidated operating income (4,011) 2,457 (1,554)
Add:
Transaction costs 6,737 2,443 9,180
Amortization of debt issuance
costs 653 – 653
Equity-settled share-based
compensation 1,539 2,009 3,548
Keane indemnity claim 2,158 – 2,158
Severance costs 5,173 1,910 7,083
—————————————————————————-
Adjusted operating income(1) 12,249 8,819 21,068
—————————————————————————-

—————————————————————————-

Period from
Six monthsJanuary 1, 2017 Six months
ended June 30, to June 1, ended June 30,
($ thousands; unaudited) 2017 2017 2017
Trican Canyon Combined
—————————————————————————-
Revenue 286,600 213,291 499,891
Consolidated Gross Profit /
(Loss) (IFRS financial
measure) 17,475 23,238 40,713
Deduct:
Administrative expenses (35,950) (19,735) (55,685)
Add:
Depreciation & amortization 3,401 3,268 6,669
Depreciation expense – cost
of sales 33,736 19,124 52,860
—————————————————————————-
Consolidated operating income 18,662 25,895 44,557
Add:
Transaction costs 8,599 2,443 11,042
Amortization of debt issuance
costs 1,306 – 1,306
Equity-settled share-based
compensation 2,382 2,009 4,391
Keane indemnity claim 2,158 – 2,158
Severance costs 5,173 1,910 7,083
—————————————————————————-
Adjusted operating income(1) 38,280 32,257 70,537
—————————————————————————-

/T/

NON-GAAP DISCLOSURE

Operating income / (loss), adjusted operating income / (loss) and adjusted
administrative expenses do not have any standardized meaning as prescribed by
IFRS and, therefore, are considered non-GAAP measures.

Consolidated Gross Income (Loss) to Adjusted Consolidated Operating Income
(Loss)

Operating income / (loss) and adjusted operating income / (loss) have been
reconciled to gross profit / (loss), being the most directly comparable
measures calculated in accordance with IFRS.

Adjusted operating income provides investors with an indication of operating
income before equity-settled share-based compensation, amortization of debt
costs, severance costs and excludes items that are significant but not
reflective of our ongoing operations for the period. It provides investors with
an indication of comparable operating income / (loss) between periods and
provides an indication of measures used for debt covenant calculations.

/T/

—————————————————————————-
($ thousands;
unaudited) Three months ended Six months ended
—————————————————————————-
June 30, June 30, March 31, June 30, June 30,
2017 2016 2017 2017 2016
—————————————————————————-
Consolidated gross
(loss) / profit
(IFRS financial
measure) (350) (28,532) 17,825 17,475 (59,818)
—————————————————————————-
Deduct:
Administrative
expenses (25,543) (18,287) (10,407) (35,950) (33,519)
Add:
Depreciation &
amortization 2,513 2,080 888 3,401 4,936
Depreciation expense
– cost of sales 19,369 15,535 14,366 33,736 32,799
—————————————————————————-
Consolidated
operating (loss) /
income (4,011) (29,204) 22,672 18,662 (55,602)
—————————————————————————-
Add:
Transaction costs 6,737 – 1,862 8,599 –
Amortization of debt
issuance costs 653 978 653 1,306 2,467
Equity-settled share-
based compensation 1,539 675 843 2,382 1,463
Keane indemnity claim 2,158 – – 2,158 –
Severance costs 5,173 8,382 – 5,173 16,282
Professional fees
related to
restructuring – 77 – – 122
—————————————————————————-
Adjusted consolidated
operating income /
(loss) 12,249 (19,092) 26,030 38,280 (35,268)
—————————————————————————-

/T/

Other Non-Standard Financial Terms

In addition to the above non-GAAP financial measures, this document makes
reference to the following non-standard financial terms. These terms may differ
from similar measures used by other companies.

Adjusted operating income %

Adjusted operating % is determined by dividing Adjusted consolidated operating
income by revenue from continuing operations.

Synergies

Synergies represent the Company’s estimate of ongoing savings that can be
achieved as a result of the Canyon Transaction. Synergies are generally
measured on annual basis, but may be broken into specific periods of time.

Transaction costs

Transaction costs or Canyon acquisition are costs incurred to assist in
evaluating and completing the acquisition of Canyon, including legal, advisory
and accounting related fees.

Trican estimated combined financial results

Financial information is provided to assist the reader in understanding the
financial effect of the Canyon acquisition if it occurred at the start of 2017
for purposes of evaluating the business. The combined financial results
presentation may differ from other forms of pro forma calculations. The
financial information is unaudited.

FORWARD-LOOKING STATEMENTS

Certain statements contained in this document constitute forward-looking
information and statements (collectively “forward-looking statements”). These
statements relate to future events or our future performance. All statements
other than statements of historical fact may be forward-looking statements.
Forward-looking statements are often, but not always, identified by the use of
words such as “anticipate”, “achieve”, “estimate”, “expect”, “intend”, “plan”,
“planned”, and other similar terms and phrases. These statements involve known
and unknown risks, uncertainties and other factors that may cause actual
results or events to differ materially from those anticipated in such
forward-looking statements. We believe the expectations reflected in these
forward-looking statements are reasonable but no assurance can be given that
these expectations will prove to be correct and such forward-looking statements
included in this document should not be unduly relied upon. These statements
speak only as of the date of this document.

In particular, this document contains forward-looking statements pertaining to,
but not limited to, the following:

/T/

— the Company’s ability to maintain a strong market position and secure

work;
— anticipated industry activity levels and overall supply and demand in
jurisdictions and service lines where the Company operates, as well as
customer work programs and equipment utilization levels;
— anticipated adjustments to our active equipment fleet, related
adjustments to cost structure, and the ability to control our fixed cost
structure;
— expectations regarding workforce recruitment and retention;
— expectations regarding the Company’s cost structure;
— expectations regarding the Company’s financial results, working capital
levels, liquidity and profits;
— expectations regarding quantity of proppant pumped per well;
— expectations regarding pricing of the Company’s services;
— anticipated benefits and synergies of Canyon; and
— expectations surrounding weather and seasonal slowdowns.

/T/

Our actual results could differ materially from those anticipated in these
forward-looking statements as a result of the risk factors set forth below and
in the “Risk Factors” section of our Annual Information Form dated March 29,
2017:

/T/

— volatility in market prices for oil and natural gas;
— liabilities inherent in oil and natural gas operations;
— competition from other suppliers of oil and gas services;
— competition for skilled personnel;
— changes in income tax laws or changes in other laws and incentive

programs relating to the oil and gas industry; and
— changes in political, business, military and economic conditions in key
regions of the world.

/T/

Readers are cautioned that the foregoing lists of factors are not exhaustive.
Forward-looking statements are based on a number of factors and assumptions
which have been used to develop such statements and information but which may
prove to be incorrect. Although management of Trican believes that the
expectations reflected in such forward-looking statements or information are
reasonable, undue reliance should not be placed on forward-looking statements
because Trican can give no assurance that such expectations will prove to be
correct. In addition to other factors and assumptions which may be identified
in this document, assumptions have been made regarding, among other things:
crude oil and natural gas prices; the impact of increasing competition; the
general stability of the economic and political environment; the timely receipt
of any required regulatory approvals; Trican’s, Canyon’s and the combined
company’s ability to continue its operations for the foreseeable future and to
realize its assets and discharge its liabilities and commitments in the normal
course of business; industry activity levels; Trican’s policies with respect to
acquisitions; the ability of Trican to obtain qualified staff, equipment and
services in a timely and cost efficient manner; the ability to operate our
business in a safe, efficient and effective manner; the ability of Trican to
obtain capital resources and adequate sources of liquidity; the performance and
characteristics of various business segments; the regulatory framework; the
timing and effect of pipeline, storage and facility construction and expansion;
and future commodity, currency, exchange and interest rates.

The forward-looking statements contained in this document are expressly
qualified by this cautionary statement. We do not undertake any obligation to
publicly update or revise any forward-looking statements except as required by
applicable law.

Additional information regarding Trican including Trican’s most recent Annual
Information Form is available under Trican’s profile on SEDAR (www.sedar.com).

CONFERENCE CALL AND WEBCAST DETAILS

The Company will host a conference call on Friday August 11, 2017 at 10:00 a.m.
MT (12:00 p.m. ET) to discuss the Company’s results for the Second Quarter of
2017.

To listen to the webcast of the conference call, please enter
http://edge.media-server.com/m/p/wyp3ezg8 in your web browser or visit the
Investors section of our website at www.tricanwellservice.com/investors and
click on “Reports”.

To participate in the Q&A session, please call the conference call operator at
1-844-358-9180 (North America) or 478-219-0187 (outside North America) 15
minutes prior to the call’s start time and ask for the “Trican Well Service
Ltd. – Second Quarter 2017 Earnings Results Conference Call”.

The conference call will be archived on Trican’s website at
www.tricanwellservice.com/investors

Headquartered in Calgary, Alberta, Trican provides a comprehensive array of
specialized products, equipment and services that are used during the
exploration and development of oil and gas reserves.

(1) Certain financial measures in this news release – namely operating
income/(loss) adjusted operating income/(loss) and adjusted administrative
expenses are not prescribed by IFRS. These financial measures are reconciled to
IFRS measures in the Non-GAAP Disclosures section of this news release. Other
non-standard measures are also described in the Non-GAAP Disclosures.

– END RELEASE – 10/08/2017

For further information:
Requests for further information should be directed to:
Dale Dusterhoft
Chief Executive Officer
ddusterhoft@trican.ca
OR
Michael Baldwin
Senior Vice President and CFO
mbaldwin@trican.ca
OR
Phone: (403) 266-0202
Fax: (403) 237-7716
2900, 645 – 7th Avenue S.W.
Calgary, Alberta T2P 4G8
Please visit our website at www.tricanwellservice.com

COMPANY:
FOR: TRICAN WELL SERVICE LTD.
TSX SYMBOL: TCW

INDUSTRY: Energy and Utilities – Equipment, Energy and Utilities –
Oil and Gas
RELEASE ID: 20170810CC0084

Press Release from Marketwired 1-866-736-3779

Maxim Power Corp. Announces 2017 Second Quarter Financial and Operating Results

August 10, 2017 by The Canadian Press

FOR: MAXIM POWER CORP.
TSX SYMBOL: MXG

Date issue: August 10, 2017
Time in: 5:49 PM e

Attention:

CALGARY, ALBERTA–(Marketwired – Aug. 10, 2017) – Maxim Power Corp. (“MAXIM” or
the “Corporation”) (TSX:MXG) announced today the release of financial and
operating results for the second quarter ended June 30, 2017. The unaudited
condensed consolidated interim financial statements, accompanying notes and
Management Discussion and Analysis (“MD&A”) will be available on SEDAR and on
MAXIM’s website on August 10, 2017. All figures reported herein are Canadian
dollars unless otherwise stated.

The Financial Highlights below include the results from MAXIM’s continuing
operations, unless otherwise noted. Refer to MAXIM’s unaudited condensed
consolidated interim financial statements and MD&A for further details on
discontinued operations.

FINANCIAL HIGHLIGHTS

/T/

Three Months Ended Six Months Ended
June 30 June 30
($ in thousands except per
share amounts) 2017 2016 2017 2016
Revenue $ 45 $ 180 $ 2,024 $ 2,063
Net loss attributable to
shareholders
Continuing operations (10,479) (6,825) (14,990) (16,819)
Discontinued operations 50,431 (1,523) 51,357 462
Total 39,952 (8,348) 36,367 (16,357)
Total per share – basic and
diluted $ 0.73 $ (0.15)$ 0.67 $ (0.30)
Total assets $ 191,921 $ 310,674 $ 191,921 $ 310,674

/T/

OPERATING RESULTS

During the second quarter of 2017, net loss attributable to shareholders from
continuing operations increased compared to the same period in 2016. The change
in this financial measure was primarily due to asset impairment charges
recognized in intangible assets and property, plant and equipment in 2017. This
was partially offset by lower operating costs as a result of the temporary
suspension of operations at M1 and recoveries from the final resolution of the
cooling tower claims.

During the first six months of 2017 net loss attributable to shareholders from
continuing operations decreased compared to the same period in 2016. The change
in this financial measure was primarily due to the same factors impacting the
second quarter, in addition lower fuel and maintenance costs and realized gains
on commodity risk management activities in the first quarter of 2017.

SALE OF MAXIM POWER (USA), INC. (“MUSA”)

As previously reported on April 3, 2017, MAXIM announced that it has closed the
sale of 100% of its ownership interest in its wholly-owned subsidiary MUSA to
an affiliate of Hull Street Energy, LLC. The implied enterprise value was
approximately $106 million USD inclusive of working capital. Net proceeds to
MAXIM after accounting for debt and transaction costs were approximately $84
million USD. After closing costs and reclassification of foreign currency
adjustments, MAXIM recognized a gain on sale of $33.8 million CAD.

MAXIM utilized $8 million CAD of the net sales proceeds as collateral for
letters of credit that are securing potential obligations of the Corporation
and will utilize a further $5 million USD to fulfill obligations under the FERC
Settlement agreement previously disclosed on September 26, 2016. The remainder
of the proceeds will be held by MAXIM for strategic corporate purposes.

MILNER (“M1”) GENERATION TEMPORARILY SUSPENDED

On July 28, 2017, MAXIM temporarily suspended the generation of electricity at
M1 following the notice provided to the Alberta Electric System Operator on May
1, 2017. M1 has not generated electricity since April 2017. The decision to
temporarily suspend the operations at M1 was due to continued record low
Alberta power prices, which have undermined profitability for a prolonged
period. Laying-up M1 operations will result in a 75% reduction of plant staff
while operations are suspended. MAXIM is currently maintaining a smaller
operating team to undertake maintenance and repairs for a possible resumption
of generation as power market conditions improve. A significant improvement in
Alberta power prices in the current “energy only market” will be required to
justify resuming operations.

STRATEGIC REVIEW

MAXIM continues to own 156 MW of generating capacity in Canada. MAXIM also has
power generation development projects totalling up to 1,031 MW (refer to Growth
Initiatives section below) and a permitted metallurgical coal development
project in Alberta. MAXIM continues to evaluate alternatives for these
investments in order to maximize shareholder value. MAXIM will provide updates
as these considerations progress.

GROWTH INITIATIVES

MAXIM has four electrical generating development projects in Alberta totalling
1,031 MW of capacity. These projects are at various stages of the permitting
phase, with 796 MW having AUC permits and the remainder in the early stage of
permitting. The Corporation is currently evaluating the viability of each
project in the context of recent regulatory announcements by the Government of
Alberta. These regulatory announcements include provision for the transition of
Alberta’s “energy only” power market to a “capacity market” by 2021. The pace
and success of this transition will determine decisions on advancing
development of these projects. MAXIM has not made any definitive commitments to
the timing or certainty of advancing development of these projects.

MAXIM also owns a metallurgical coal development initiative located north of
Grande Cache, Alberta that in turn owns metallurgical coal leases for M14 and
M16S (“SUMMIT”). Current estimates for M14 are 18.9 million tonnes of low-mid
volatile metallurgical coal reserves with a mine life of 17 years based on the
NI 43-101 Technical Report filed on SEDAR on March 21, 2013. M16S is located 30
kilometers northwest of M14 and represents 1,792 hectares or 29% of SUMMIT’s
total area of coal leases. A NI 43-101 Technical Report has not been prepared
for M16S. M14 is permitted for a run-of-mine production rate of up to 1,300,000
tonnes per year. MAXIM has not made any definitive commitments to the timing or
certainty of advancing development of this project.

About MAXIM

Based in Calgary, Alberta, MAXIM is an independent power producer, which
acquires or develops, owns and operates innovative and environmentally
responsible power and power related projects. MAXIM currently owns and operates
two power plants in Alberta, having 156 MW of electric generating capacity.
MAXIM trades on the TSX under the symbol “MXG”. For more information about
MAXIM, visit our website at www.maximpowercorp.com.

Statements in this release which describe MAXIM’s intentions, expectations or
predictions, or which relate to matters that are not historical facts are
forward-looking statements. These forward-looking statements involve known and
unknown risks and uncertainties which may cause the actual results,
performances or achievements of MAXIM to be materially different from any
future results, performances or achievements expressed in or implied by such
forward-looking statements. MAXIM may update or revise any forward-looking
statements, whether as a result of new information, future events or changing
market and business conditions and will update such forward-looking statements
as required pursuant to applicable securities laws.

– END RELEASE – 10/08/2017

For further information:
Michael R. Mayder
Senior Vice President, Finance and CFO
(403) 750-9311

COMPANY:
FOR: MAXIM POWER CORP.
TSX SYMBOL: MXG

INDUSTRY: Energy and Utilities – Utilities, Energy and Utilities –
Pipelines
RELEASE ID: 20170810CC0083

Press Release from Marketwired 1-866-736-3779

Total Energy Services Inc. Announces Q2 2017 Results

August 10, 2017 by The Canadian Press

FOR: TOTAL ENERGY SERVICES INC.
TSX SYMBOL: TOT

Date issue: August 10, 2017
Time in: 5:33 PM e

Attention:

CALGARY, ALBERTA–(Marketwired – Aug. 10, 2017) – Total Energy Services Inc.
(“Total Energy” or the “Company”) (TSX:TOT) announces its consolidated
financial results for the three and six months ended June 30, 2017.

/T/

Financial Highlights
($000’s except per share data)
—————————————————————————-

Three Month Ended June 30 Six Months Ended June 30

%
2017 2016 % Change 2017 2016 Change
—————————————————————————-
Revenue $ 154,922 $ 43,893 253% $ 239,274 $ 93,849 155%
Operating Loss (13,105) (5,289) (148%) (13,346) (7,802) (71%)
EBITDA (1) 6,577 1,368 381% 14,519 5,671 156%
Cashflow 10,860 1,775 512% 18,681 6,814 174%
Net Loss (13,141) (4,203) (213%) (13,994) (6,335) (121%)

Attributable to

shareholders (11,565) (4,203) (175%) (12,418) (6,335) (96%)

Per Share Data
(Diluted)
EBITDA (1) $ 0.15 $ 0.04 275% $ 0.39 $ 0.18 117%
Cashflow $ 0.25 $ 0.06 317% $ 0.50 $ 0.22 127%
Net Loss
attributable to
shareholders $ (0.26)$ (0.14) (86%)$ (0.33)$ (0.20) (65%)
—————————————————————————-

June 30 Dec. 31 %
2017 2016 Change
—————————————————————————-
Financial
Position
Total Assets $ 1,053,302 $ 522,599 102%
Long-Term Debt
and Obligations
Under Finance
Leases
(excluding
current
portion) 256,266 46,557 450%
Working Capital
(2) 21,309 71,770 (70%)
Net Debt (3) 234,957 – n/m
Shareholders’
Equity 547,405 364,302 50%

Shares
Outstanding
(000’s)(4)
Basic 43,718 30,920 41% 37,617 30,920 22%
Diluted 43,718 30,920 41% 37,617 30,920 22%
—————————————————————————-

/T/

Notes 1 through 4 please refer to the Notes to the Financial Highlights set
forth at the end of this release.

Total Energy’s financial results for the three and six months ended June 30,
2017 include the financial results for Savanna Energy Services Corp.
(“Savanna”) from April 5, 2017 when the Company acquired control of Savanna
upon the reconstitution of the board of directors of Savanna. Negatively
impacting the Company’s financial results for the second quarter of 2017 was
approximately $4.0 million of non-recurring expenses that relate to completion
of the acquisition of Savanna and the subsequent integration and
rationalization of Savanna’s operations and a $4.5 million unrealized foreign
exchange loss included in cost of services that relates primarily to
intercompany working capital balances. Excluding these expenses, EBITDA for the
second quarter of 2017 was $15.1 million.

Finance costs for the second quarter of 2017 included $2.9 million of
non-recurring costs, notably $1.6 million of penalty interest paid on Savanna’s
debt following the change of control (including the one-percent premium paid on
the redemption of $39.6 million of Savanna’s 7% senior unsecured notes), $0.5
million of non-recurring fees associated with the establishment of Total
Energy’s $225 million revolving syndicated credit facilities (the “Credit
Facility”) and an unrealized loss on other assets of $0.8 million.

Total Energy’s Contract Drilling Services segment (“CDS”) achieved 20%
utilization during the second quarter of 2017, recording 2,021 operating days
(spud to rig release) with a fleet of 119 drilling rigs, compared to 52
operating days, or 3% utilization, during the second quarter of 2016 with a
fleet of 18 drilling rigs. Revenue per operating day for the second quarter of
2017 was $20,437. The acquisition of Savanna added 101 drilling rigs to the CDS
segment. During the second quarter of 2017, the CDS segment had 972 operating
days in Canada with a fleet of 86 rigs (13% utilization), 890 days in the
United States with a fleet of 28 rigs (37% utilization) and 159 days in
Australia with a fleet of 5 rigs (37% utilization).

The Rental and Transportation Services segment (“RTS”) achieved a utilization
rate on major rental equipment of 18% during the second quarter of 2017 as
compared to 10% during the second quarter of 2016. Segment revenue per utilized
rental piece increased 12% for the second quarter of 2017 compared to the same
period in 2016 due to a modest increase in pricing. This segment exited the
second quarter of 2017 with approximately 11,700 pieces of major rental
equipment (excluding access matting) and 125 heavy trucks as compared to 10,000
rental pieces and 112 heavy trucks at June 30, 2016. The acquisition of Savanna
added approximately 1,700 major rental pieces, four heavy trucks and a
significant inventory of small rental equipment to the RTS equipment fleet as
well as three full service branch locations in Fort MacKay, Lloydminster and
Swift Current.

Revenue in the Compression and Process Services segment (“CPS”) increased 76%
to $65.4 million for the three months ended June, 2017 compared to $37.1
million for the same period in 2016. This segment exited the second quarter of
2017 with a $149.3 million backlog of fabrication sales orders as compared to
$35.9 million at June 30, 2016 and $75.2 million at March 31, 2017. At June 30,
2017, there was 40,000 horsepower in the compression rental fleet, of which
approximately 19,000 horsepower was on rent as compared to 12,000 horsepower on
rent at June 30, 2016 and 16,500 horsepower at March 31, 2017. The gas
compression rental fleet operated at an average utilization rate of 46% during
the second quarter of 2017 as compared to 30% during the second quarter of 2016.

Total Energy’s Well Servicing segment (“WS”) was established with the
acquisition of Savanna. This segment generated $34.9 million of revenue during
the second quarter of 2017 on 34,850 billable hours, or $918 per billable hour,
with a fleet of 87 service rigs located in Canada (57 rigs), the United States
(18 rigs) and Australia (12 rigs). Service rig utilization for the three months
ended June 30, 2017 was 27% in Canada, 38% in the United States and 64% in
Australia.

Total Energy issued 15.32 million common shares from treasury in connection
with the acquisition of Savanna resulting in 46.2 million common shares
outstanding at June 30, 2017. During the second quarter, Total Energy declared
a quarterly dividend of $0.06 per share to shareholders of record on June 30,
2017. This dividend was paid on July 31, 2017. For Canadian income tax
purposes, all dividends paid by Total Energy on its common shares are
designated as “eligible dividends” unless otherwise indicated.

Outlook

Despite continuing volatility and uncertainty in global energy markets, North
American oil and natural gas drilling and completion activity levels continued
the recovery which began in the fourth quarter of 2016. While modest gains in
pricing have been achieved in North America, pricing remains low by historical
comparisons and operating margins remain challenged.

The record fabrication backlog enjoyed by the CPS segment at June 30, 2017
provides good visibility for the remainder of 2017 and into early 2018. With
the majority of the current sales backlog constituted by orders from outside of
Canada, this division continues to gain traction in the international gas
compression market. In June 2017, production commenced in a newly established
100,000 square foot gas compression fabrication facility located in Weirton,
West Virginia and subsequent to June 30, 2017 the Weirton facility received its
first direct order.

Total Energy remains focused on carefully managing its cost structure and
realizing efficiencies through the integration and rationalization of Savanna’s
operations. A significant proportion of the $5.1 million of Savanna-related
non-recurring costs incurred by Total Energy during the first half of 2017
relates to operational and overhead rationalization and the Company currently
expects that its target of $10.0 million of go-forward annualized cost savings
arising from the combination of Savanna and the Company, excluding interest
expense savings, will be achieved by year end.

The Company’s capital expenditure budget for 2017 is currently $44.8 million,
which includes a $22.0 million budget approved by the previous board of
Savanna. To June 30, 2017, $25.2 million of 2017 capital expenditures have been
made by the Company and Savanna (excluding $26.8 million related to the
acquisition of Savanna). Total Energy is currently reviewing its capital plans
for the remainder of 2017 in order to high-grade opportunities and maximize
synergies and economies of scale.

With the acquisition of Savanna on April 5, 2017, Total Energy assumed
approximately $281.3 million of Savanna debt. During the second quarter, the
Company utilized the Credit Facility to refinance $205.9 million of such debt,
thereby lowering the effective interest rate on this debt from approximately
7.16% to 3.45% as at June 30, 2017. While the applicable interest rate on the
Credit Facility is variable and tied to the Canadian prime rate of interest as
well as subject to a pricing grid based on financial ratios, the Company
expects to realize substantial interest expense savings going forward. At June
30, 2017, the Company’s total debt amounted to $326.3 million and consisted of
$192.5 million drawn on the Credit Facility (3.45% interest rate), $62.6
million of mortgage debt (3.57% weighted average interest rate), $67.5 million
of senior unsecured notes (7.0% interest rate) and $3.7 million of limited
partnership debt (5.45% interest rate).

Total Energy’s working capital position at June 30, 2017 was $21.3 million,
including $20.1 million of cash and marketable securities. Such working capital
position reflects the classification of $67.5 million of 7% notes as a current
liability given their maturity in May of 2018. In addition to the $225 million
Credit Facility, Savanna has a $5.0 million revolving line of credit that was
undrawn at June 30, 2017. Total Energy was in compliance with all debt
covenants at June 30, 2017 and able to fully draw on the remaining amounts
available under its credit facilities. The Credit Facility also provides the
Company with the option to increase such facility by $75 million subject to
certain terms and conditions including the agreement of the lenders to increase
their commitments.

Conference Call

At 9:00 a.m. (Mountain Time) on August 11, 2017 Total Energy will conduct a
conference call and webcast to discuss its second quarter financial results.
Daniel Halyk, President & Chief Executive Officer, will host the conference
call. A live webcast of the conference call will be accessible on Total’s
website at www.totalenergy.ca by selecting “Webcasts”. Persons wishing to
participate in the conference call may do so by calling (800) 806-5484 or (416)
340-2217 (passcode 7958945#). Those who are unable to listen to the call live
may listen to a recording of it on Total Energy’s website. A recording of the
conference call will also be available until September 11, 2017 by dialing
(800) 408-3053 (passcode 5805165#).

Selected Financial Information

Selected financial information relating to the three and six months ended June
30, 2017 and 2016 is attached to this news release. This information should be
read in conjunction with the interim condensed consolidated financial
statements of Total Energy and the attached notes to the interim condensed
consolidated financial statements and management’s discussion and analysis to
be issued in due course and reproduced in the Company’s 2017 second quarter
report.

/T/

Consolidated Statements of Financial Position
(in thousands of Canadian dollars)
—————————————————————————-

June 30, December 31,
2017 2016
—————————————————————————-
(unaudited) (audited)
Assets
Current assets:
Cash and cash equivalents $ 16,112 $ 15,916
Accounts receivable 119,202 47,545
Inventory 54,755 54,964
Income taxes receivable 4,486 –
Other assets 4,004 5,095
Prepaid expenses and deposits 11,545 4,029
—————————————————————————-
210,104 127,549

Property, plant and equipment 827,268 383,497
Income taxes receivable 7,070 7,070
Deferred tax asset 4,807 430
Goodwill 4,053 4,053
—————————————————————————-
$ 1,053,302 $ 522,599
—————————————————————————-

Liabilities & Shareholders’ Equity
Current liabilities:

Accounts payable and accrued liabilities $ 93,515 $ 36,755
Deferred revenue 19,004 13,573
Dividends payable 2,774 1,856
Income taxes payable – 249
Current portion of obligations under finance
leases 1,637 1,408
Current portion of long-term debt 71,865 1,938
—————————————————————————-
188,795 55,779

Long-term debt 254,478 44,962

Obligations under finance leases 1,788 1,595

Onerous lease liability 3,193 –

Deferred tax liability 57,643 55,961

Shareholders’ equity:

Share capital 291,317 88,654
Contributed surplus 3,247 7,683
Accumulated other comprehensive income (3,468) –
Non-controlling interest 1,557 –
Retained earnings 254,752 267,965
—————————————————————————-
547,405 364,302

—————————————————————————-

$ 1,053,302 $ 522,599
—————————————————————————-

Consolidated Statements of Comprehensive Loss
(in thousands of Canadian dollars except per share amounts)
(unaudited)

—————————————————————————-

Three months ended Six months ended
June 30 June 30
2017 2016 2017 2016
—————————————————————————-

Revenue $ 154,922 $ 43,893 $ 239,274 $ 93,849
Cost of services 133,528 37,202 202,243 76,856
Selling, general and
administration 14,633 5,264 22,253 11,088
Share-based compensation 255 501 484 1,010
Depreciation 19,611 6,215 27,640 12,697
—————————————————————————-
Operating loss (13,105) (5,289) (13,346) (7,802)
Gain on sale of property,
plant and equipment 71 442 225 776
Finance costs (6,646) (793) (7,243) (1,316)
—————————————————————————-
Net loss before income taxes (19,680) (5,640) (20,364) (8,342)
Current income tax expense
(recovery) (229) 81 (4,958) 396
Deferred income tax recovery (6,310) (1,518) (1,412) (2,403)
—————————————————————————-
Total income tax recovery (6,539) (1,437) (6,370) (2,007)

Net loss for the period $ (13,141) $ (4,203) $ (13,994) $ (6,335)
—————————————————————————-

Net loss attributable to:

Shareholders of the
Company $ (11,565) $ (4,203) $ (12,418) $ (6,335)
Non-controlling interest (1,576) – (1,576) –
—————————————————————————-

Loss per share
Basic and diluted $ (0.26) $ (0.14) $ (0.33) $ (0.20)
—————————————————————————-

Condensed Interim Consolidated Statements of Comprehensive Loss
(unaudited)
—————————————————————————-

Three months ended Six months ended
June 30 June 30
2017 2016 2017 2016
—————————————————————————-
Net loss for the period $ (13,141) $ (4,203) $ (13,994) $ (6,335)

Changes in fair value of
long-term investment 395 – 665 –
Realized gain on long-term
investment (665) – (665) –
Foreign currency translation
adjustment (4,775) – (4,751) –
Deferred tax effect 1,319 – 1,283 –
–
—————————————————————————-
Total other comprehensive
loss for the period (3,726) – (3,468) –

—————————————————————————-
Total comprehensive loss $ (16,867) $ (4,203) $ (17,462) $ (6,335)
—————————————————————————-

Total comprehensive loss
attributable to:

Shareholders of the
Company $ (15,291) $ (4,203) $ (15,886) $ (6,335)
Non-controlling interest (1,576) – (1,576) –
—————————————————————————-

Consolidated Statements of Cash Flows
(in thousands of Canadian dollars)
(unaudited)
—————————————————————————-

Three months ended Six months ended
June 30 June 30
2017 2016 2017 2016
—————————————————————————-

Cash provided by (used in):

Operations:

Net loss for the period $ (13,141) $ (4,203) $ (13,994) $ (6,335)
Add (deduct) items not
affecting cash:
Depreciation 19,611 6,215 27,640 12,697
Share-based compensation 255 501 484 1,010
Gain on sale of
property, plant and
equipment (71) (442) (225) (776)
Unrealized loss on other
assets 831 354 891 379
Finance costs 6,791 450 7,328 948
Realized gain on long-
term investment (665) – (665) –
Onerous leases (43) – (43) –
Unrealized loss (gain)
on foreign currencies
translation 4,511 (41) 4,696 713
Current income tax
expense (229) 81 (4,958) 396
Deferred income tax
recovery (6,310) (1,518) (1,412) (2,403)
Income taxes recovered
(paid) (680) 378 (1,061) 185
—————————————————————————-
Cashflow 10,860 1,775 18,681 6,814
Changes in non-cash
working capital items:
Accounts receivable 27,555 2,881 16,592 10,421
Inventory 1,465 7,023 5,436 8,297
Prepaid expenses and
deposits (4,998) 450 (6,166) 869
Accounts payable and
accrued liabilities (818) (2,543) 1,419 (2,221)
Deferred revenue 11,223 (2,845) 4,024 (4,753)
—————————————————————————-
Cash provided by operating
activities 45,287 6,741 39,986 19,427
Investing:
Purchase of property,
plant and equipment (10,504) (2,571) (13,432) (4,882)
Acquisitions (13,030) (5,099) (26,830) (8,689)
Cash acquired 16,167 – 16,167 –
Proceeds on sale of other
assets – 13 115 66
Proceeds on disposal of
property, plant and
equipment 111 1,916 1,028 4,221
Changes in non-cash
working capital items 550 (100) (213) (2,128)
—————————————————————————-
Cash used in investing
activities (6,706) (5,841) (23,165) (11,412)
Financing:
Advances under long-term
debt 204,000 – 204,000 –
Repayment of long-term
debt (205,419) (536) (205,898) (1,000)
Repayment of obligations
under finance leases (497) (601) (944) (1,266)
Short-term loan collected 2,997 – – –
Dividends to shareholders (2,331) (1,859) (4,187) (3,719)
Issuance of common shares 2,289 – 2,289 –
Repurchase of common
shares – (131) – (288)
Interest paid (11,421) (450) (11,885) (948)
Change in bank
indebtedness (12,087) – – –
—————————————————————————-
Cash used in financing
activities (22,469) (3,577) (16,625) (7,221)
—————————————————————————-
Change in cash and cash
equivalents 16,112 (2,677) 196 794

Cash and cash equivalents,
beginning of period – 12,346 15,916 8,875
—————————————————————————-

Cash and cash equivalents,
end of period $ 16,112 $ 9,669 $ 16,112 $ 9,669
—————————————————————————-

/T/

Segmented Information

The Company provides a variety of products and services in the oil and natural
gas industry through five reporting segments, which operate substantially in
three geographic segments. These reporting segments are Contract Drilling
Services, which includes the contracting of drilling equipment and the
provision of labour required to operate the equipment, Rentals and
Transportation Services, which includes the rental and transportation of
equipment used in drilling, completion and production operations, Compression
and Process Services, which includes the fabrication, sale, rental and
servicing of natural gas compression and oil and natural gas process equipment
and Well Servicing, which includes the contracting of service rigs and the
provision of labour required to operate the equipment. Corporate includes
activities related to the Company’s corporate and public issuer affairs.

/T/

As at and for the three months ended June 30, 2017 (unaudited)

Contract Rentals and Compression
Drilling Transportation and Process
Services Services Services
—————————————————————————-

Revenue $ 41,304 $ 13,377 $ 65,356
Cost of services 41,283 9,204 57,196
Selling, general and
administration 3,129 2,910 2,002
Share-based compensation – – –
Depreciation 7,507 4,869 1,812
—————————————————————————-
Operating income (loss) (10,615) (3,606) 4,346
Gain on sale of property, plant
and equipment – 71 –
Finance costs (97) (176) (92)
—————————————————————————-

Net income (loss) before income
taxes (10,712) (3,711) 4,254
—————————————————————————-

Goodwill – 2,514 1,539
Total assets 440,920 237,074 168,260
Total liabilities 51,704 45,440 54,456
—————————————————————————-
Capital expenditures(1) $ 4,779 $ 3,283 $ 1,418
—————————————————————————-

As at and for the three months ended June 30, 2017 (unaudited)

Well Corporate Total
Servicing

————————————————————————

Revenue $ 34,885$ – $ 154,922
Cost of services 25,845 – 133,528
Selling, general and
administration 1,580 5,012 14,633
Share-based compensation – 255 255
Depreciation 4,574 849 19,611
————————————————————————
Operating income (loss) 2,886 (6,116) (13,105)
Gain on sale of property, plant
and equipment – – 71
Finance costs – (6,281) (6,646)
————————————————————————

Net income (loss) before income
taxes 2,886 (12,397) (19,680)
————————————————————————

Goodwill – 4,053
Total assets 138,581 68,467 1,053,302
Total liabilities 9,917 344,380 505,897
————————————————————————
Capital expenditures(1) $ 333$ 691 $ 10,504
————————————————————————
—————————————————————————-
Canada United States Australia
—————————————————————————-

Revenue 89,724 35,589 29,609
Non-current assets (3) 586,699 144,493 100,129
—————————————————————————-

————————————————————————

Other Total
————————————————————————

Revenue – 154,922
Non-current assets (3) – 831,321
————————————————————————

As at and for the three months ended June 30, 2016 (unaudited)

Contract Rentals and Compression
Drilling Transportation and Process
Services Services Services
—————————————————————————-

Revenue $ 675 $ 6,091 $ 37,127

Cost of services 619 4,492 32,091
Selling, general and
administration 382 2,671 1,440
Share-based compensation – – –
Depreciation 196 4,143 1,854
—————————————————————————-
Operating income (loss) (522) (5,215) 1,742

Gain on sale of property, plant
and equipment 10 125 307
Finance income – – –
Finance costs (89) (186) (109)
—————————————————————————-

Net income (loss) before income
taxes (601) (5,276) 1,940
—————————————————————————-

Goodwill – 2,514 1,539

Total assets 110,960 226,944 155,693
Total liabilities 20,083 37,961 28,340
—————————————————————————-

Capital expenditures(2) $ 195 $ 7,185 $ 286
—————————————————————————-

As at and for the three months ended June 30, 2016 (unaudited)

Well Corporate
Servicing
Total
————————————————————————

Revenue $ -$ – $ 43,893

Cost of services – – 37,202
Selling, general and
administration – 771 5,264
Share-based compensation – 501 501
Depreciation – 22 6,215
————————————————————————
Operating income (loss) – (1,294) (5,289)

Gain on sale of property, plant
and equipment – – 442
Finance income – 11 11
Finance costs – (420) (804)
————————————————————————

Net income (loss) before income
taxes – (1,703) (5,640)
————————————————————————

Goodwill – – 4,053

Total assets – 15,752 509,349
Total liabilities – 48,961 135,345
————————————————————————

Capital expenditures(2) $ -$ 4 $ 7,670
————————————————————————
—————————————————————————-
Canada United States Australia
—————————————————————————-

Revenue 39,804 2,852 1,114
Non-current assets (3) 378,826 13,803 1,538
—————————————————————————-

————————————————————————

Other Total
————————————————————————

Revenue 123 43,893
Non-current assets (3) – 394,167
————————————————————————

As at and for the six months ended June 30, 2017 (unaudited)

As at and for the six months ended Contract Rentals and Compression
June 30, 2017 Drilling Transportation and Process
Services Services Services
—————————————————————————-

Revenue $ 48,000 $ 30,933 $ 125,456

Cost of services 46,096 19,630 110,672
Selling, general and
administration 3,650 5,960 3,788
Share-based compensation – – –
Depreciation 9,524 9,029 3,645
—————————————————————————-
Operating income (loss) (11,270) (3,686) 7,351

Gain on sale of property, plant
and equipment – 195 30
Finance costs (188) (357) (187)
—————————————————————————-

Net income (loss) before income
taxes (11,458) (3,848) 7,194
—————————————————————————-

Goodwill – 2,514 1,539

Total assets 440,920 237,074 168,260
Total liabilities 51,704 45,440 54,456
—————————————————————————-

Capital expenditures (1) $ 5,241 $ 4,701 $ 2,466
—————————————————————————-

As at and for the six months ended June 30, 2017 (unaudited)

As at and for the six months ended
June 30, 2017 Well Corporate
Servicing Total
————————————————————————

Revenue $ 34,885$ – $ 239,274

Cost of services 25,845 – 202,243
Selling, general and
administration 1,580 7,275 22,253
Share-based compensation – 484 484
Depreciation 4,574 868 27,640
————————————————————————
Operating income (loss) 2,886 (8,627) (13,346)

Gain on sale of property, plant
and equipment – – 225
Finance costs – (6,511) (7,243)
————————————————————————

Net income (loss) before income
taxes 2,886 (15,138) (20,364)
————————————————————————

Goodwill – 4,053

Total assets 138,581 68,467 1,053,302
Total liabilities 9,917 344,380 505,897
————————————————————————

Capital expenditures (1) $ 333$ 691 $ 13,432
————————————————————————
—————————————————————————-
Canada United States Australia
—————————————————————————-

Revenue 159,682 44,053 35,528
Non-current assets (3) 586,699 144,493 100,129
—————————————————————————-

————————————————————————

Other Total
————————————————————————

Revenue 11 239,274
Non-current assets (3) – 831,321
————————————————————————

As at and for the three months ended June 30, 2016 (unaudited)

Contract Rentals and Compression
As at and for the six months ended Drilling Transportation and Process
June 30, 2016 Services Services Services
—————————————————————————-

Revenue $ 3,862 $ 17,235 $ 72,752

Cost of services 2,556 11,685 62,615
Selling, general and
administration 908 5,413 3,287
Share-based compensation – – –
Depreciation 733 8,193 3,731
—————————————————————————-
Operating income (loss) (335) (8,056) 3,119

Gain on sale of property, plant
and equipment 10 180 586
Finance income – – –
Finance costs (182) (375) (220)
—————————————————————————-

Net income (loss) before income
taxes (507) (8,251) 3,485
—————————————————————————-

Goodwill – 2,514 1,539

Total assets 110,960 226,944 155,693
Total liabilities 20,083 37,961 28,340
—————————————————————————-

Capital expenditures(2) $ 245 $ 12,041 $ 1,281
—————————————————————————-

As at and for the three months ended June 30, 2016 (unaudited)

Well
As at and for the six months ended Servicing Corporate
June 30, 2016 Total
————————————————————————

Revenue $ -$ – $ 93,849

Cost of services – – 76,856
Selling, general and
administration – 1,480 11,088
Share-based compensation – 1,010 1,010
Depreciation – 40 12,697
————————————————————————
Operating income (loss) – (2,530) (7,802)

Gain on sale of property, plant
and equipment – – 776
Finance income – 11 11
Finance costs – (550) (1,327)
————————————————————————

Net income (loss) before income
taxes – (3,069) (8,342)
————————————————————————

Goodwill – – 4,053

Total assets – 15,752 509,349
Total liabilities – 48,961 135,345
————————————————————————

Capital expenditures(2) $ -$ 4 $ 13,571
————————————————————————

/T/

—————————————————————————-

Canada United States Australia
—————————————————————————-

Revenue 84,669 7,790 1,114
Non-current assets (3) 378,826 13,803 1,538
—————————————————————————-

————————————————————————

Other Total
————————————————————————

Revenue 276 93,849
Non-current assets (3) – 394,167
————————————————————————
(1) Does not include acquisition of Savanna described in note 4 to the 2017
second quarter Condensed Interim Consolidated Financial Statements.
(2) Includes acquisition of assets in January of 2016 described in note 5 to
the 2016 annual audited Consolidated Financial Statements.
(3) Includes property, plant and equipment and goodwill.

/T/

Total Energy Services Inc. is a growth oriented energy services corporation
involved in contract drilling services, rentals and transportation services,
the fabrication, sale, rental and servicing of natural gas compression and oil
and natural gas process equipment and well servicing. The common shares of
Total Energy are listed and trade on the TSX under the symbol TOT.

For further information, please visit our website at www.totalenergy.ca

/T/

Notes to the Financial Highlights

(1) EBITDA means earnings before interest, taxes, depreciation and

amortization and is equal to net loss before income taxes plus finance
costs plus depreciation. EBITDA is not a recognized measure under IFRS.
Management believes that in addition to net loss, EBITDA is useful
supplemental measure as it provides an indication of the results
generated by the Company’s primary business activities prior to
consideration of how those activities are financed, amortized or how the
results are taxed in various jurisdictions as well as the cash generated
by the Company’s primary business activities without consideration of
the timing of the monetization of non-cash working capital items.
Readers should be cautioned, however, that EBITDA should not be
construed as an alternative to net loss determined in accordance with
IFRS as an indicator of Total Energy’s performance. Total Energy’s
method of calculating EBITDA may differ from other organizations and,
accordingly, EBITDA may not be comparable to measures used by other
organizations.

(2) Working capital equals current assets minus current liabilities.

(3) Net Debt equals long-term debt plus obligations under finance leases

plus current liabilities minus current assets.

(4) Basic and diluted shares outstanding reflect the weighted average number

of common shares outstanding for the periods. See note 9 to the
Company’s Interim Consolidated Financial Statements for the three and
six months ended June 30, 2017.

/T/

Certain statements contained in this press release, including statements which
may contain words such as “could”, “should”, “expect”, “believe”, “will” and
similar expressions and statements relating to matters that are not historical
facts are forward-looking statements. Forward-looking statements are based upon
the opinions and expectations of management of Total Energy as at the effective
date of such statements and, in some cases, information supplied by third
parties. Although Total Energy believes the expectations reflected in such
forward-looking statements are based upon reasonable assumptions and that
information received from third parties is reliable, it can give no assurance
that those expectations will prove to have been correct.

In particular, this press release contains forward-looking statements
concerning industry activity levels, expectations regarding Total Energy’s
market share and future compression and process production activity, Total
Energy’s expectations of future interest rates and its corresponding ability to
realize substantial interest expense savings, expectations as to the Company’s
ability to realize cost efficiencies and synergies arising from the acquisition
of Savanna as well as other expected benefits of the acquisition. Such
forward-looking statements are based on a number of assumptions and factors
including fluctuations in the market for oil and natural gas and related
products and services, political and economic conditions, central bank interest
rate policy, the demand for products and services provided by Total Energy,
Total Energy’s ability to attract and retain key personnel and other factors.
Such forward-looking statements involve known and unknown risks and
uncertainties which may cause the actual results, performances or achievements
of Total Energy to be materially different from any future results,
performances or achievements expressed or implied by such forward-looking
statements. Reference should be made to Total Energy’s most recently filed
Annual Information Form and other public disclosures (available at
www.sedar.com) for a discussion of such risks and uncertainties.

The TSX has neither approved nor disapproved of the information contained
herein.

– END RELEASE – 10/08/2017

For further information:
Total Energy Services Inc.
Daniel Halyk
President & Chief Executive Officer
(403) 216-3921
OR
Total Energy Services Inc.
Yuliya Gorbach
Vice-President Finance and Chief Financial Officer
(403) 216-3920
OR
Total Energy Services Inc.
investorrelations@totalenergy.ca
www.totalenergy.ca

COMPANY:
FOR: TOTAL ENERGY SERVICES INC.
TSX SYMBOL: TOT

INDUSTRY: Energy and Utilities – Equipment, Energy and Utilities –
Oil and Gas
RELEASE ID: 20170810CC0081

Press Release from Marketwired 1-866-736-3779

Chinook Energy Inc. Announces Second Quarter 2017 Results

August 10, 2017 by The Canadian Press

FOR: CHINOOK ENERGY INC.
TSX SYMBOL: CKE

Date issue: August 10, 2017
Time in: 5:26 PM e

Attention:

CALGARY, ALBERTA–(Marketwired – Aug. 10, 2017) – Chinook Energy Inc. (“our”,
“we”, or “us”) (TSX:CKE) is pleased to announce its second quarter 2017
financial and operating results.

Our operational and financial highlights for the three and six months ended
June 30, 2017 are noted below and should be read in conjunction with our
condensed consolidated financial statements for the three and six months ended
June 30, 2017 and 2016 and our related management’s discussion and analysis
which have been posted on the SEDAR website (www.sedar.com) and our website
(www.chinookenergyinc.com).

Second Quarter 2017 Financial and Operating Highlights

/T/

Three months
ended Six months ended
June 30 June 30
—————————————————————————-
2017 2016 2017 2016
—————————————————————————-
OPERATIONS
—————————————————————————-
Production Volumes
—————————————————————————-
Natural gas liquids (boe/d) 441 604 461 669
Natural gas (mcf/d) 19,065 22,776 18,546 23,995
Crude oil (bbl/d) 19 769 24 793
—————————————————————————-
Average daily production (boe/d) 3,638 5,169 3,576 5,461
—————————————————————————-
Sales Prices
—————————————————————————-
Average natural gas liquids price
($/boe) $ 44.48 $ 25.78 $ 48.07 $ 26.81
Average natural gas price ($/mcf) $ 2.77 $ 1.35 $ 2.74 $ 1.39
Average oil price ($/bbl) $ 59.55 $ 50.59 $ 60.01 $ 42.76
—————————————————————————-
Netback (1)
—————————————————————————-
Average commodity pricing ($/boe) $ 20.22 $ 16.50 $ 20.81 $ 15.61
Royalties ($/boe) $ (0.33) $ (0.44) $ (0.07) $ (0.73)
Realized gains on derivative
contracts ($/boe) $ 1.01 $ 0.14 $ 1.19 $ 0.08
Net production expenses ($/boe) (1) $ (11.82) $ (14.75) $ (11.55) $ (14.95)
—————————————————————————-
Operating Netback ($/boe) (1) $ 9.08 $ 1.45 $ 10.38 $ 0.01
—————————————————————————-
Wells Drilled (net)
—————————————————————————-
Total natural gas wells drilled
(net) 3.63 – 3.63 –
—————————————————————————-
—————————————————————————-
Three months ended Six months ended
June 30 June 30
—————————————————————————-
2017 2016 2017 2016
—————————————————————————-
FINANCIAL ($ thousands,
except per share amounts)
—————————————————————————-
Petroleum & natural gas
revenues, net of royalties $ 6,583 $ 7,550 $ 13,421 $ 14,794
Adjusted funds (outflow) from
operations(1) $ 1,195 $ (1,721) $ 3,231 $ (4,611)
Per share – basic and
diluted ($/share) $ 0.01 $ (0.01) $ 0.01 $ (0.02)
Net (loss) income $ (2,253) $ (12,520) $ 8,169 $ (25,295)
Per share – basic and
diluted ($/share) $ (0.01) $ (0.06) $ 0.04 $ (0.12)
Capital expenditures $ 8,235 $ 1,347 $ 17,058 $ 4,373
Net surplus (1) $ 18,294 $ 6,207 $ 18,294 $ 6,207
Total assets $ 144,891 $ 366,586 $ 144,891 $ 366,586
—————————————————————————-
Common Shares (thousands)
—————————————————————————-
Weighted average during
period
– basic 216,598 215,350 216,521 215,350
– diluted 216,598 215,350 217,042 215,350
Outstanding at period end 217,115 215,350 217,115 215,350
—————————————————————————-
—————————————————————————-

1. Adjusted funds (outflow) from operations, adjusted funds (outflow) from

operations per share, net surplus (debt), operating netback, and net
production expense are non-GAAP measures.
These terms do not have any standardized meanings as prescribed by IFRS
and, therefore, may not be comparable with the calculations of similar
measures presented by other companies.
See headings entitled “Adjusted Funds (outflow) from Operations”, “Net
Surplus (Debt)”, “Operational Netback” and “Net Production Expense” in
the Reader Advisory below for further information on such terms.

/T/

Highlights for the three months ended June 30, 2017

/T/

— We ended the second quarter of 2017 with a strong balance sheet and a

net surplus of $18.3 million.
— We generated funds from operations of $1.2 million compared to outflow
from operations of $1.7 million in the second quarter of 2016. This is
our fourth consecutive quarter of reported positive funds flow since we
started our transition to a pure Montney company.
— Our operating costs were reduced by 20% to $11.82 per boe over the same
period in 2016 and will continue to decrease as we bring on more
profitable volumes at Birley/Umbach in 2017.
— We secured an increased credit facility of $8.0 million from the
previous $2.0 million which provides us with further financial
flexibility. We remain undrawn on this facility and anticipate remaining
undrawn through 2017.
— We are reinvesting the proceeds from our first quarter 2017 dispositions
at Gold Creek and Knopcik/Pipestone into our Montney drilling program.
We incurred $8.2 million of capital reinvestment during the second
quarter which included drilling another four (3.63 net) horizontal wells
at Birley/Umbach as well as engineering and purchasing of long lead
items for our Birley/Umbach facility expansion.
— We are currently preparing these four (3.63 net) wells for completions
operations and fracking equipment is scheduled to arrive shortly. Two of
the wells have approximately 1,800 metre lateral sections and the other
two have approximately 1,600 metre lateral sections with a frac density
of 35 stages and 30 stages, respectively. Each stage will be stimulated
with nitrified slick water placing 55 tonnes of sand per stage.
— Preparations for our Birley/Umbach facility expansion are ongoing with
an expected construction commencement date of September 1, 2017 and an
on-stream date of December 1, 2017.
— We are maintaining our 2017 production guidance of 4,200 – 4,300 boe/d
despite lower production volumes during June and July which resulted
from delays in the McMahon Plant turnaround, which took an additional
unscheduled three weeks to complete and carried over into July.

/T/

Second Quarter 2017 Financial Results

Our production during the second quarter of 2017 averaged 3,638 boe/d, an
increase of 3.5% from the previous quarter primarily due to additional
production from our three (2.64 net) Birley/Umbach wells which were drilled in
the fourth quarter of 2016 and came on production at the end of the first
quarter of 2017. During the second quarter, these wells added 1,450 boe/d of
production during the days that they were producing. This increase in second
quarter volumes was despite June’s volumes decreasing by 4,300 boe/d compared
to May as a result of a planned McMahon Plant turnaround. This planned
turnaround was expected and we have included the majority of the production
decreases in our 2017 forecasted volumes. Our Montney production was back
on-stream in mid-July immediately following the completion of the McMahon Plant
turnaround. We averaged approximately 4,850 boe/d of production from July 18 –
24, 2017, but these volumes have since been impacted by further McMahon Plant
restrictions. We still expect to meet our 2017 guidance production of 4,200 –
4,300 boe/d.

Our production in the second quarter of 2017 decreased 30% from the same
quarter of 2016 primarily as a result of the disposition of the majority of our
Alberta assets through the 2016 distribution of a subsidiary’s shares to our
shareholders (the “Share Distribution”) and various other property dispositions.

For the second quarter of 2017, our operating netback increased 526% to
$9.08/boe compared to the same quarter of 2016. This increase was driven by
improvements in each component of the operating netback. Our realized commodity
price increases generally trended with the increase in benchmark pricing
resulting in a realized price of $20.22/boe for the second quarter. Royalties
per boe of $0.33/boe decreased from the same quarter of 2016 primarily as a
result of royalty credits that we were granted from the BC’s Infrastructure
Royalty Credit Program in addition to the absence of comparatively higher
Alberta royalty rate production due to the Share Distribution and divestitures.
Our net production expense of $11.82/boe during the second quarter decreased
from the same period of 2016 primarily due to the divestiture of higher cost
properties and the signing of a new BC gas handling agreement during the third
quarter of 2016. However, our net production expense was higher than our
expectations mostly due to higher fluid hauling costs resulting from weather
induced road bans and seasonal costs including the repair and maintenance of
our processing plants and our Birley/Umbach access road. We expect our on-going
operations to incur production costs under $10/boe once production volumes from
our 2017 four well drilling campaign are brought on-stream.

Our adjusted funds from operations for second quarter of 2017 of $1.2 million
increased from an adjusted outflow from operations of $1.7 million during the
second quarter of 2016, but decreased from an adjusted funds from operations of
$2.0 million in the first quarter of 2017. This increase from the prior year
resulted from higher commodity benchmark prices, realized gains on commodity
price contracts and a lower cash-based cost structure for our Montney focused
operations. The decrease from the first quarter was primarily driven by the
expected decrease in production volumes, and correspondingly lower petroleum
and natural gas revenue, driven by the McMahon Plant turnaround.

We reported a net loss for the second quarter of 2017 of $2.3 million compared
to a loss of $12.5 million during the same quarter of 2016. This improvement
reflects higher commodity prices, a lower cost structure associated with our
transition to a pure Montney play in addition to a $0.6 million gain on
commodity price contracts.

Second Quarter 2017 Operational Results

During the second quarter, we drilled four (3.63 net) horizontal Montney gas
wells with various downhole locations on our Birley/Umbach property in
northeastern BC on our D-93-F pad. Two of the wells have approximately 1,800
metre horizontal lateral sections. Drilling costs of these wells were
consistent with our guidance despite road restrictions that delayed operations
and increased transportation costs. Completions and equipping are scheduled for
the third quarter of 2017. All four wells will use 55 tonne fracs at 52 metre
spacing and are scheduled to be on-stream during the fourth quarter of 2017
bringing our exit production to our guidance of 6,300 – 6,500 boe/d.

We budgeted $10 million of our 2017 capital program for the expansion of our
Birley/Umbach facility to 50 mmcf/d, of which we spent $2.3 million during the
first half of 2017.

Production from our Birley/Umbach property is as follows:

/T/

Working Lateral Frac’d Flow 24 Hour Test
Interest Length Stages Time Rate End Date
Well (%) (metres) (gross) (hours) (MM/DD/YYYY)
—————————————————————————-
A-060-K/094-H-03 74.55 1,220 18 154 3/9/2014
B-071-F/094-H-03 74.55 1,553 23 211 10/4/2014
A-073-L/094-H-03 74.55 1,230 18 252 2/16/2015
C-037-K/094-H-03 100.00 1,210 18 145 9/23/2015
B-072-F/094-H-03 74.55 1,225 18 69 9/24/2015
B-004-K/094-H-03 100.00 1,200 16 119 9/24/2015
—————————————————————————-
A-071-F/094-H-03 74.55 1,457 24 113 2/8/2017
D-095-F/094-H-03 98.20 1,430 24 197 2/14/2017
C-095-F/094-H-03 89.20 1,437 24 98 2/15/2017
—————————————————————————-

Final 24
Hour
Average Final 24 Hour
Test Average Test
Total Gas Total FCGR IP30 IP60 IP90
Rates (1) (mcf/d) (mcf/d) (mcf/d)
Well (mcf/d) (bbl/mmcf)
—————————————————————————-
A-060-K/094-H-03 5,276 54 3,726 3,754 3,923
B-071-F/094-H-03 8,870 6 4,489 4,375 4,348
A-073-L/094-H-03 3,827 23 3,712 3,417 3,459
C-037-K/094-H-03 5,281 49 4,228 4,094 3,851
B-072-F/094-H-03 3,908 30 3,991 4,104 4,227
B-004-K/094-H-03 4,127 17 3,364 3,082 2,921
—————————————————————————-
A-071-F/094-H-03 7,319 8 3,271 3,433 3,344
D-095-F/094-H-03 6,756 11 3,404 3,554 3,454
C-095-F/094-H-03 8,202 25 2,957 2,665 2,549 (2)
—————————————————————————-

1. Free condensate gas ratio.
2. Production for well C-095-F is for 83 days.

/T/

Financial Commodity Price Contracts

We use financial commodity price contracts to support our capital investment
and growth by providing more certainty regarding our adjusted funds from
operations and balance sheet management. Our internal policy permits us to
hedge up to a maximum period of 24 months, based on our total estimated oil and
natural gas production volumes, consisting of no more than 50% for the first 12
months and 25% for the last 12 months. Our current financial commodity price
contracts in place are as follows:

/T/

Company’s Remaining Contractual
Indexed Price Notional Volumes Received Price Term
—————————————————————————-
AECO 7,500 GJ/d $3.205/GJ July 1, 2017 to
December 31, 2017
AECO 4,000 GJ/d $2.50/GJ July 1, 2017 to
October 31, 2017
—————————————————————————-

/T/

Outlook

We continue to execute on our previously announced $40 million capital program
for 2017 and remain excited about the growth it will provide. As we implement
this capital program we will continue to closely monitor our balance sheet and
commodity prices. As in previous years, we will remain prudent in how we deploy
our capital in order to defend our strong balance sheet.

We have made great strides over the past 12 months to improve our cost
structure, including completing the Craft Share Distribution and executing a
new gas handling agreement in BC. On a per boe basis, for fourth quarter of
2017, our net production expense is expected to approximate $8.00/boe. As we
begin to increase our production at Birley/Umbach, our cost structure and
profitability significantly improve.

We forecasted the McMahon Plant outages during the second quarter of 2017,
resulting in us achieving production guidance for the quarter. However, this
McMahon Plant turnaround continued past our expectations in July. Additionally,
we have been experiencing some Enbridge downstream line issues and TCPL
maintenance issues upstream of James River that may negatively impact our
Birley/Umbach production volumes and/or field prices during the latter part of
August. We are evaluating the impact of these unbudgeted proposed production
outages and their impact on field prices. However, for the interim, we are
maintaining our previously announced production guidance for 2017 as follows:

/T/

($ millions, except boe/d) 2017 Guidance (1)
—————————————————————————-
Average production (boe/d) 4,200 – 4,300
Exit production (boe/d) 6,300 – 6,500
Capital expenditures (2) $ 40
Net surplus as at December 31, 2017 $ 2
—————————————————————————-

1. 2017 guidance assumptions: AECO natural gas price $2.64/mmbtu, Station 2

natural gas price $2.11/mmbtu and Chicago Alliance natural gas price
$2.92/mmbtu.
2. Includes decommissioning obligation expenditures and capitalized general
and administrative costs.

/T/

About Chinook Energy Inc.

Chinook is a Calgary-based public oil and natural gas exploration and
development company which is focused on realizing per share growth from its
large contiguous Montney liquids-rich natural gas position at Birley/Umbach,
British Columbia.

Reader Advisory

Abbreviations

/T/

Oil and Natural Gas Liquids Natural Gas
———————————- —————————————-

bbl barrel mcf thousand cubic feet
bbls barrels mcf/d thousand cubic feet per day
bbls/d barrels per day GJ gigajoules
GJ/d gigajoules per day
Other
——-

boe barrel of oil equivalent on the basis of 6 mcf/1 boe for natural gas
and 1 bbl/1 boe for crude oil and natural gas liquids (this
conversion factor is an industry accepted norm and is not based on
either energy content or current prices)
boe/d barrel of oil equivalent per day

/T/

Forward-Looking Statements

In the interest of providing our shareholders and readers with information
regarding our company, including management’s assessment of our future plans
and operations, certain statements contained in this news release constitute
forward -looking statements or information (collectively “forward-looking
statements”) within the meaning of applicable securities legislation.
Forward-looking statements are typically identified by words such as
“anticipate”, “continue”, “estimate”, “expect”, “forecast”, “may”, “will”,
“project”, “could”, “plan”, “intend”, “should”, “believe”, “outlook”,
“potential”, “target” and similar words suggesting future events or future
performance. In particular, this news release contains, without limitation,
forward-looking statements pertaining to: that we expect to remain undrawn on
our demand revolving credit facility through 2017, the scheduled arrival time
of fracking equipment and our completions strategy for our 2017 four well
drilling program at Birley/Umbach, that all four wells from our 2017 four well
drilling program at our Birley/Umbach area are scheduled to be completed during
the third quarter of 2017 and on-stream during the fourth quarter of 2017, the
expected commencement date and on-stream date of our Birley/Umbach facility
expansion, the expected decrease in our operating costs, net production expense
and G&A in the fourth quarter of 2017 and our expectation that as we begin to
increase our production at Birley/Umbach our cost structure and profitability
will improve significantly, the amount of our 2017 capital program, future
exploration and development activities and the timing thereof and how we intend
to manage our company as well our guidance regarding average and ending
production for 2017, capital expenditures for 2017 and net surplus at December
31, 2017 set forth under the heading “Outlook”.

With respect to the forward-looking statements contained in this news release,
we have made assumptions regarding, among other things: that we will continue
to conduct our operations in a manner consistent with that expressed herein,
future capital expenditure levels, future oil and natural gas prices, future
oil and natural gas production levels, future currency, exchange and interest
rates, our ability to obtain equipment in a timely manner to carry out
exploration and development activities, the ability of the operator of the
projects in which we have an interest in to operate in the field in a safe,
efficient and effective manner, the impact of increasing competition, field
production rates and decline rates, anticipated production volumes, our ability
to replace and expand production and reserves through exploration and
development activities, certain cost assumptions, that the budgeted 2017
capital program, which is subject to the discretion of our Board of Directors,
will not be amended in the future, and the continued availability of adequate
debt and cash flow to fund our planned expenditures. Although we believe that
the expectations reflected in the forward-looking statements contained in this
news release, and the assumptions on which such forward-looking statements are
made, are reasonable, there can be no assurance that such expectations will
prove to be correct. Readers are cautioned not to place undue reliance on
forward-looking statements included in this news release, as there can be no
assurance that the plans, intentions or expectations upon which the
forward-looking statements are based will occur.
By their nature, forward-looking statements involve numerous assumptions, known
and unknown risks and uncertainties that contribute to the possibility that
predictions, forecasts, projections and other forward-looking statements will
not occur, which may cause our actual performance and financial results in
future periods to differ materially from any estimates or projections of future
performance or results expressed or implied by such forward-looking statements.
These risks and uncertainties include, without limitation, risks associated
with oil and gas exploration, development, exploitation, production, marketing
and transportation, loss of markets, volatility of commodity prices and
currency fluctuations, our Board of Directors may amend the 2017 capital
program based on its discretion; environmental risks, competition from other
producers, inability to retain drilling rigs and other services, unanticipated
increases in or unforeseen capital expenditure costs, including drilling,
completion and facilities costs, unexpected decline rates in wells, delays in
projects and/or operations resulting from surface conditions, wells not
performing as expected, delays resulting from or inability to obtain the
required regulatory approvals and inability to access sufficient capital from
internal and external sources. As a consequence, actual results may differ
materially from those anticipated in the forward-looking statements. Readers
are cautioned that the forgoing list of factors is not exhaustive. Additional
information on these and other factors that could affect our operations and
financial results are included in reports on file with Canadian securities
regulatory authorities and may be accessed through the SEDAR website
(www.sedar.com) and at our website (www.chinookenergyinc.com). Furthermore, the
forward-looking statements contained in this news release are made as at the
date of this news release and we do not undertake any obligation to update
publicly or to revise any of the forward-looking statements, whether as a
result of new information, future events or otherwise, except as may be
required by applicable securities laws.

Operating Netback

The reader is cautioned that this news release contains the term operating
netback, which is not a recognized measure under IFRS and is calculated as a
period’s sales of petroleum and natural gas, net of realized gains or losses on
commodity price contracts, royalties and net production expenses, divided by
the period’s sales volumes. We use this non-GAAP measure to assist us in
understanding our production profitability relative to current and fixed
commodity prices and it provides an analytical tool to benchmark changes in
field operational performance against prior periods. Readers are cautioned,
however, that this measure should not be construed as an alternative to other
terms such as net income determined in accordance with IFRS as a measure of
performance. Our method of calculating this measure may differ from other
companies, and accordingly, it may not be comparable to measures used by other
companies.

Net Production Expense

The reader is cautioned that this news release contains the term net production
expense, which is not a recognized measure under IFRS and is calculated as
production and operating expense less processing and gathering income. We use
net production expense to determine the current periods’ cash cost of operating
expenses and net production and operating expense per boe is used to measure
operating efficiency on a comparative basis. Our method of calculating this
measure may differ from other companies, and accordingly, it may not be
comparable to measures used by other companies.

Adjusted Funds (Outflow) from Operations

The reader is cautioned that this news release contains the term adjusted funds
(outflow) from operations, which is not a recognized measure under IFRS and is
calculated from cash flow from operations adjusted for changes in non-cash
working capital related to operations, exploration and evaluation expenses
related to operations, decommissioning obligation expenditures related to
operations and transaction costs. We believe that adjusted funds (outflow) from
operations is a key measure to assess our ability to finance capital
expenditures and when debt is drawn, debt repayments. Adjusted funds (outflow)
from operations is not intended to represent cash flow from operating
activities, net earnings or other measures of financial performance calculated
in accordance with IFRS and should not be construed as an alternative to, or
more meaningful than, cash flow from operating activities as determined in
accordance with IFRS as an indicator of our financial performance. Our method
of calculating this measure may differ from other companies, and accordingly,
it may not be comparable to measures used by other companies. Adjustments to
cash flow from operations are for changes in non-cash operating working capital
which are expected to reverse and for those costs that are not directly caused
by lifting production volumes.

Net Surplus (Debt)

The reader is cautioned that this news release contains the term net surplus
(debt), which is not a recognized measure under IFRS and is calculated as bank
debt adjusted for current assets less current liabilities as they appear on the
balance sheets, both of which exclude mark-to-market derivative contracts and
assets and liabilities held for sale and current liabilities excludes any
current portion of debt and decommissioning obligation. We use net surplus
(debt) to assist us in understanding our liquidity at specific points in time.
We exclude the current portion of decommissioning obligation as it is not a
financial instrument. Mark-to-market derivative contracts are excluded as they
are unrealized.

Future Oriented Financial Information

This news release, in particular the information in respect of the anticipated
capital expenditures, operating costs per boe, net production expense per boe,
G&A per boe and net surplus set out in the table under the heading “Outlook”,
may contain Future Oriented Financial Information (“FOFI”) within the meaning
of applicable securities laws. The FOFI has been prepared by our management to
provide an outlook of our activities and results and may not be appropriate for
other purposes. The FOFI has been prepared based on a number of assumptions
including the assumptions discussed under the heading “Forward-Looking
Statements” and assumptions with respect to production rates and commodity
prices. The actual results of our operations and the resulting financial
results may vary from the amounts set forth herein, and such variations may be
material. Our management believes that the FOFI has been prepared on a
reasonable basis, reflecting management’s best estimates and judgments.

Barrels of Oil Equivalent

Barrels of oil equivalent (boe) is calculated using the conversion factor of 6
mcf (thousand cubic feet) of natural gas being equivalent to one barrel of oil.
Boes may be misleading, particularly if used in isolation. A boe conversion
ratio of 6 mcf:1 bbl (barrel) is based on an energy equivalency conversion
method primarily applicable at the burner tip and does not represent a value
equivalency at the wellhead. Given that the value ratio based on the current
price of crude oil as compared to natural gas is significantly different from
the energy equivalency of 6:1, utilizing a conversion on a 6:1 basis may be
misleading as an indication of value.

Initial Production Rates

Any reference in this news release to initial, early and/or test or
production/performance rates (including IP30, IP60 and IP90) are useful in
confirming the presence of hydrocarbons, however, such rates are not
determinative of the rates at which such wells will continue production and
decline thereafter. Additionally, such rates may also include recovered “load
oil” fluids used in well completion stimulation. While encouraging, readers are
cautioned not to place reliance on such rates in calculating our aggregate
production. The initial production or test rates may be estimated based on
other third party estimates or limited data available at this time . In all
cases in this news release initial production or test rates are not necessarily
indicative of long-term performance of the relevant well or fields or of
ultimate recovery of hydrocarbons. Well-flow test result data should be
considered to be preliminary until a pressure transient analysis and/or
well-test interpretation has been carried out.

– END RELEASE – 10/08/2017

For further information:
Walter Vrataric
President and Chief Executive Officer
Chinook Energy Inc.
Telephone: (403) 261-6883
OR
Jason Dranchuk
Vice President, Finance and Chief Financial Officer
Chinook Energy Inc.
Telephone: (403) 261-6883
Website: www.chinookenergyinc.com

COMPANY:
FOR: CHINOOK ENERGY INC.
TSX SYMBOL: CKE

INDUSTRY: Energy and Utilities – Oil and Gas
RELEASE ID: 20170810CC0075

Press Release from Marketwired 1-866-736-3779

Canacol Energy Ltd. Reports Q2 2017 Results

August 10, 2017 by The Canadian Press

FOR: CANACOL ENERGY LTD.
TSX SYMBOL: CNE
BVC SYMBOL: CNEC
OTCQX SYMBOL: CNNEF

Date issue: August 10, 2017
Time in: 5:23 PM e

Attention:

CALGARY, ALBERTA–(Marketwired – Aug. 10, 2017) – Canacol Energy Ltd.
(“Canacol” or the “Corporation”) (TSX:CNE)(OTCQX:CNNEF)(BVC:CNEC) is pleased to
report its financial and operating results for the three and six months ended
June 30, 2017. Dollar amounts are expressed in United States dollars, except as
otherwise noted.

Charle Gamba, President and CEO of the Corporation, commented: “During the
second quarter of 2017, we made solid progress on all aspects related to our
gas business in Colombia. This included 1) making two new gas discoveries at
Canahuate-1 and Toronja-1 which tested 28 MMscfpd and 46 MMscfpd of gas
respectively, 2) having our auditors Gaffney, Cline & Associates prepare an
independent prospective resource audit for 47 individual prospects and leads
which aggregates to an unrisked mean of 2 trillion standard cubic feet or a
risked mean of 482 billion standard cubic feet of conventional natural gas
prospective resource on our gas exploration blocks, and 3) continued to
consolidate our exploration position with the acquisition of a 50% operated
working interest in the SSJN 7 E&P contract, all in the Lower Magdalena Valley
Basin. The management team is particularly excited about the implications of
the Toronja-1 gas discovery, which open up an entirely new prospective gas
exploration fairway across our 1.1 million net acres on our five gas blocks in
the Lower Magdalena Valley Basin. As we announced on Wednesday August 9, 2017,
we also confirmed the financing of the Sabanas gas flowline project which will
add 40 MMscfpd of new production capacity in December 2017. We are also pleased
to report a net income of $11.8 million for the three months ended June 30,
2017, a 5% increase from $11.2 million in 2016, which contributed to a strong
adjusted funds from operations of $45.2 million for the six months ended June
30, 2017, a 12% increase compared to the same period in 2016.

For the remainder of 2017, the management team is focused on 1) completing the
Sabanas gas flowline project on time to lift gas production to 130 MMscfpd in
December of 2017, and 2) adding more gas reserves via our exploration drilling
program which will include the Pandereta-1 and Gaitero-1 exploration wells,
thus allowing the Corporation to move closer to its target of lifting gas
production to 230 MMscfpd in December 2018. Canacol also reiterates production
guidance of 18,000 to 19,000 boepd for 2017.”

Highlights for the three and six months ended June 30, 2017

(Production is stated as working-interest before royalties)

Financial and operational highlights of the Corporation include:

/T/

— Realized contractual sales volumes increased 1% and 25% to 17,195 boepd

and 17,616 boepd for the three and six months ended June 30, 2017,
respectively, compared to 17,017 boepd and 14,120 boepd for the same
periods in 2016, respectively. The increase for the six month ended June
30, 2017 is primarily due to increase in gas production in Esperanza and
VIM-5 as a result of the additional sales related to the Promigas
pipeline expansion.

— Average production volumes increased 4% and 25% to 17,162 boepd and

17,077 boepd for the three and six months ended June 30, 2017,
respectively, compared to 16,423 boepd and 13,680 boepd for the same
periods in 2016, respectively. The increase for the six month ended June
30, 2017 is primarily due to increase in gas production in Esperanza and
VIM-5 as a result of the additional sales related to the Promigas
pipeline expansion.

— Adjusted funds from operations for the six months ended June 30, 2017

increased 12% to $45.2 million compared to $40.3 million for the same
period in 2016. Adjusted funds from operations for the three months
ended June 30, 2017 decreased 10% to $24.2 million compared to $26.9
million for the same period in 2016. Adjusted funds from operations are
inclusive of results from the Ecuador Incremental Production Contract
(the “Ecuador IPC”) (see full discussion in MD&A).

— Total petroleum and natural gas revenues for the six months ended June

30, 2017 increased 28% to $78.9 million compared to $61.6 million for
same period in 2016. Total petroleum and natural gas revenues for the
three months ended June 30, 2017 decreased 4% to $37.3 million compared
to $38.9 million for same period in 2016. Adjusted petroleum and natural
gas revenues, inclusive of revenues related to the Ecuador IPC, for the
six months ended June 30, 2017 increased 21% to $90 million compared to
$74.4 million for the same period in 2016. Adjusted petroleum and
natural gas revenues for the three months ended June 30, 2017 decreased
5% to $43 million compared to $45.4 million for the same period in 2016.

— Net income increased 5% to $11.8 million for the three months ended June

30, 2017 compared to $11.2 million for the same period in 2016. Net
income decreased 67% to $3.8 million for the six months ended June 30,
2017 compared to $11.7 million for the same period in 2016.

— On March 24, 2017, the Canahuate-1 exploration well was spud. The

Canahuate-1 well is located three kilometers (“kms”) north of the
Corporation’s Jobo gas processing facility and is targeting gas-bearing
sandstones within the Cienaga de Oro reservoir (“CDO”). The well
encountered 124 ft. md (86 feet true vertical depth) of net gas pay with
average porosity of 18% within the primary CDO reservoir target. Two
different zones were completed and flow tested at a combined rate of 28
MMscfpd of dry gas. Work is underway to tie the Canahuate-1 well into
the Corporation’s gas processing facility at Jobo.

— During the three months ended June 30, 2017, the Toronja-1 exploration

well was spud at the Corporation’s VIM-21 block. The well reached a
total depth of 7,200 feet measured depth (“ft. md.”) in six days. The
well encountered gas between 4,875 to 6,256 ft. md. with average
porosity of 20% within the primary Porquero sandstone resevoir target.
Two different zones were completed and flow tested within the Porquero
resevoir. The first zone test was perforated between 4,865 to 4,884 ft.
md. and flowed at a stabilized rate of 24.4 MMscfpd of dry gas. The
second zone tested was perforated between 6,249 to 6,257 ft. md. and
flowed at a final stabilized rate of 21.9 MMscfpd of dry gas. Work is
currently underway to tie the Toronja-1 exploration well into the
Corporation’s gas processing facility at Jobo.

— Net capital expenditures including acquisitions for the three and six

months ended June 30, 2017 was $30.6 million and $54.6 million,
respectively, while adjusted capital expenditures including
acquisitions, inclusive of amounts related to the Ecuador IPC, was $30.6
million and $55.5 million, respectively.

— At June 30, 2017, the Corporation had $25.6 million in cash and $62.9

million in restricted cash and continues to be well within all of its
banking covenants.

/T/

Outlook

For the remainder of 2017, the Corporation will focus on: 1) the drilling of
the Pandereta and Gaitero gas exploration wells on its VIM-5 E&P contract
located in the Lower Magdalena Basin, and 2) the construction of the gas
flowline connecting the Corporation’s gas processing facility at Jobo to the
Promigas connection point at Bremen, which will add 40 MMscfpd of additional
transportation capacity and lift Corporation gas production to 130 MMscfpd on
December 1, 2017.

The Corporation plans to spud the Pandereta-1 exploration well during the first
week of October 2017. The well is targeting prospective gas resources within
the proven CDO sandstone reservoir, and is anticipated to take five weeks to
drill and test. Upon completion of the Pandereta-1 well, the rig will be
mobilized to drill the Gaitero-1 exploration well, location approximately three
kms to the north. The well is targeting prospective gas resources within the
CDO sandstone reservoir and is anticipated to take approximately five weeks to
drill and test.

On August 9, 2017, the Corporation signed an agreement for the construction,
operation and ownership of the 82 kms long Sabanas gas flowline from its Jobo
gas plant to the connection point with the Promigas S.A. gas pipeline at
Bremen. Pursuant to the agreement, the $41 million Sabanas gas flowline project
will be financed through a $30.5 million investment by a group of private
investors and a $10.5 million contribution from Canacol (the investors and
Canacol, collectively the “Owners”), with each holding its interest in the
Sabanas gas flowline in separate companies. Canacol’s financial contribution to
the project will be almost entirely satisfied by costs incurred to date, and as
such will not involve the issuance of new equity or affect its current cash
position. The tariff for the Sabanas gas flowline is similar to other regulated
tariffs in the region and, as customary, the tariff will be borne by the
offtakers of the gas. Under the terms of the agreement, Canacol is not required
to either sign a ship or pay commitment to the benefit of the Owners, or place
a corporate guarantee in favour of the Owners. The Owners engaged Horizon
Capital Management Inc. (“Horizon”) as advisor for this transaction, and will
pay a fee of 3.5% on the $30.5 million of private funds raised. Two members of
Canacol’s board of directors have participated in the private investor
financing for an aggregate amount of $10.5 million. Under the terms of the
agreement with Horizon, Canacol has the option, valid until the commissioning
of the pipeline, to divest up to an additional $3 million of its share of the
project, thus lowering its investment to approximately $7.5 million plus the
leasing of the compression as previously announced.

Construction of the Sabanas gas flowline connecting Jobo to the Promigas
connection point at Bremen is proceeding on schedule, with first gas
transportation anticipated on December 1, 2017. Approximately 55% of the
tubulars have arrived on location, with the remainder expected on location in
September. The compression stations are anticipated to arrive in the third week
of August from the Port of Houston. All forestry, archeological, and
environmental permits have been obtained and 100% of the right of way has been
negotiated and purchased. Civil works at the two compression station locations
commenced the first week of August 2017, and digging and laying of the tubulars
is anticipated to commence the last week of August 2017. Flowline laying will
occur simultaneously at both Jobo and Bremen at either end of the 82 kms route,
with flowline laying anticipated to be completed the first week of November
2017. Commissioning of the compression stations and pressure testing of the
flowline is anticipated to be completed by the third week of November 2017.

The productive capacity of the Corporation’s current gas wells is approximately
195 MMscfpd, and that of the Corporation’s gas processing facilities located at
Jobo approximately 200 MMscfpd, more than adequate to lift production to 130
MMscfpd in December 2017 when construction of the Sabanas gas flowline is
complete. As previously announced, Canacol executed a ten year take-or-pay
contract for 40 MMscfpd of gas at contractual terms comparable to the
Corporation’s current US dollar denominated gas sale contracts, which is
expected to be transported by the Sabanas gas flowline commencing in December
2017.

/T/

Three months ended June Six months ended June
Financial 30, 30,
2017 2016 Change 2017 2016 Change
—————————————————————————-
Total petroleum and
natural gas revenues,
net of
royalties 37,283 38,926 (4%) 78,866 61,626 28%
Adjusted petroleum and
natural gas revenues,
net of 43,007 45,390 (5%) 89,982 74,390 21%
royalties(2)
Cash flow provided by
operating activities 11,130 13,764 (19%) 28,669 21,013 36%
Per share – basic ($) 0.06 0.09 (33%) 0.16 0.13 23%
Per share – diluted ($) 0.06 0.08 (25%) 0.16 0.13 23%

Adjusted funds from
operations (1) (2) 24,236 26,870 (10%) 45,183 40,321 12%
Per share – basic ($) 0.14 0.17 (18%) 0.26 0.25 4%
Per share -diluted ($) 0.14 0.16 (13%) 0.26 0.25 4%
Net income and
comprehensive income 11,770 11,245 5% 3,828 11,706 (67%)
Per share – basic ($) 0.07 0.07 – 0.02 0.07 (71%)
Per share – diluted ($) 0.07 0.07 – 0.02 0.07 (71%)

Capital expenditures,
net, including
acquisitions 30,572 5,046 506% 54,572 20,594 165%
Adjusted capital
expenditures, net,
including 30,648 5,376 470% 55,466 21,325 160%
acquisitions (1)(2)
Jun 30, Dec 31,
2017 2016 Change
————————-
Cash 25,582 66,283 (61%)
Restricted cash 62,891 62,073 1%
Working capital surplus
(1) 54,719 64,899 (16%)
Bank debt 273,940 250,638 9%
Total assets 795,067 787,508 1%
Common shares, end of
period (000’s) 174,932 174,359 –
—————————————————————————-
Three months ended June Six months ended June
Operating 30, 30,
2017 2016 Change 2017 2016 Change
—————————————————————————-
Petroleum and natural gas
production, before
royalties
(boepd)
Petroleum (3) 3,487 4,018 (13%) 3,496 4,273 (18%)
Natural gas 13,675 12,405 10% 13,581 9,407 44%
Total (2) 17,162 16,423 4% 17,077 13,680 25%
Petroleum and natural gas
sales, before royalties
(boepd)
Petroleum (3) 3,500 4,045 (13%) 3,508 4,312 (19%)
Natural gas 13,563 12,331 10% 13,487 9,331 45%
Total (2) 17,063 16,376 4% 16,995 13,643 25%
Realized contractual
sales, before royalties
(boepd)
Natural gas 13,695 12,972 6% 14,108 9,808 44%
Colombia oil 1,933 2,294 (16%) 1,973 2,575 (23%)
Ecuador tariff oil (2) 1,567 1,751 (11%) 1,535 1,737 (12%)
Total (2) 17,195 17,017 1% 17,616 14,120 25%
Operating netbacks
($/boe) (1)
Esperanza (natural gas) 24.35 27.24 (11%) 25.06 27.37 (8%)
VIM-5 (natural gas) 19.24 24.57 (22%) 19.44 24.35 (20%)
LLA-23 (oil) 19.31 12.45 55% 20.32 10.39 96%
Ecuador (tariff oil)
(2) 38.54 38.54 – 38.54 38.54 –
Total (2) 23.25 25.58 (9%) 23.91 24.90 (4%)
(1) Non-IFRS measure – see “Non-IFRS Measures” section within MD&A.
(2) Inclusive of amounts related to the Ecuador IPC – see “Non-IFRS
Measures” section within MD&A.
(3) Includes tariff oil production and sales related to the Ecuador IPC.

/T/

This press release should be read in conjunction with the Corporation’s
unaudited interim condensed consolidated financial statements and related
Management’s Discussion and Analysis. The Corporation’s has filed its unaudited
interim condensed consolidated financial statements and related Management’s
Discussion and Analysis as of and for the three and six months ended June 30,
2017 with Canadian securities regulatory authorities. These filings are
available for review on SEDAR at www.sedar.com.

Canacol is an exploration and production company with operations focused in
Colombia and Ecuador. The Corporation’s shares are traded on the Toronto Stock
Exchange under the symbol CNE, the OTCQX in the United States of America under
the symbol CNNEF, the Bolsa de Valores de Colombia under the symbol CNEC and
the Bolsa Mexicana de Valores under the symbol CNEN.

This press release contains certain forward-looking statements within the
meaning of applicable securities law. Forward-looking statements are frequently
characterized by words such as “plan”, “expect”, “project”, “target”, “intend”,
“believe”, “anticipate”, “estimate” and other similar words, or statements that
certain events or conditions “may” or “will” occur, including without
limitation statements relating to estimated production rates from the
Corporation’s properties and intended work programs and associated timelines.
Forward-looking statements are based on the opinions and estimates of
management at the date the statements are made and are subject to a variety of
risks and uncertainties and other factors that could cause actual events or
results to differ materially from those projected in the forward-looking
statements. The Corporation cannot assure that actual results will be
consistent with these forward looking statements. They are made as of the date
hereof and are subject to change and the Corporation assumes no obligation to
revise or update them to reflect new circumstances, except as required by law.
Information and guidance provided herein supersedes and replaces any forward
looking information provided in prior disclosures. Prospective investors should
not place undue reliance on forward looking statements. These factors include
the inherent risks involved in the exploration for and development of crude oil
and natural gas properties, the uncertainties involved in interpreting drilling
results and other geological and geophysical data, fluctuating energy prices,
the possibility of cost overruns or unanticipated costs or delays and other
uncertainties associated with the oil and gas industry. Other risk factors
could include risks associated with negotiating with foreign governments as
well as country risk associated with conducting international activities, and
other factors, many of which are beyond the control of the Corporation. Other
risks are more fully described in the Corporation’s most recent Management
Discussion and Analysis (“MD&A”) and Annual Information Form, which are
incorporated herein by reference and are filed on SEDAR at www.sedar.com.
Average production figures for a given period are derived using arithmetic
averaging of fluctuating historical production data for the entire period
indicated and, accordingly, do not represent a constant rate of production for
such period and are not an indicator of future production performance. Detailed
information in respect of monthly production in the fields operated by the
Corporation in Colombia is provided by the Corporation to the Ministry of Mines
and Energy of Colombia and is published by the Ministry on its website; a
direct link to this information is provided on the Corporation’s website.
References to “net” production refer to the Corporation’s working- interest
production before royalties.

Use of Non-IFRS Financial Measures – Due to the nature of the equity method of
accounting the Corporation applies under IFRS 11 to its interest in the Ecuador
IPC, the Corporation does not record its proportionate share of revenues and
expenditures as would be typical in oil and gas joint interest arrangements.
Management has provided supplemental measures of adjusted revenues and
expenditures, which are inclusive of the Ecuador IPC, to supplement the IFRS
disclosures of the Corporation’s operations in this press release. Such
supplemental measures should not be considered as an alternative to, or more
meaningful than, the measures as determined in accordance with IFRS as an
indicator of the Corporation’s performance, and such measures may not be
comparable to that reported by other companies. This press release also
provides information on adjusted funds from operations. Adjusted funds from
operations is a measure not defined in IFRS. It represents cash provided by
operating activities before changes in non-cash working capital and
decommissioning obligation expenditures, and includes the Corporation’s
proportionate interest of those items that would otherwise have contributed to
funds from operations from the Ecuador IPC had it been accounted for under the
proportionate consolidation method of accounting. The Corporation considers
adjusted funds from operations a key measure as it demonstrates the ability of
the business to generate the cash flow necessary to fund future growth through
capital investment and to repay debt. Adjusted funds from operations should not
be considered as an alternative to, or more meaningful than, cash provided by
operating activities as determined in accordance with IFRS as an indicator of
the Corporation’s performance. The Corporation’s determination of adjusted
funds from operations may not be comparable to that reported by other
companies. For more details on how the Corporation reconciles its cash provided
by operating activities to adjusted funds from operations, please refer to the
“Non-IFRS Measures” section of the Corporation’s MD&A. Additionally, this press
release references working capital, EBITDAX and operating netback measures.
Working capital is calculated as current assets less current liabilities,
excluding non-cash items, and is used to evaluate the Corporation’s financial
leverage. EBITDAX is defined as consolidated net income adjusted for interest,
income taxes, depreciation, depletion, amortization, exploration expenses,
share of joint venture profit/loss and other similar non-recurring or non-cash
charges.

Consolidated EBITDAX is further adjusted for the contribution to adjusted funds
from operations, before taxes, of the results of the Ecuador IPC. Operating
netback is a benchmark common in the oil and gas industry and is calculated as
total petroleum and natural gas sales, less royalties, less production and
transportation expenses, calculated on a per barrel of oil equivalent basis of
sales volumes using a conversion. Operating netback is an important measure in
evaluating operational performance as it demonstrates field level profitability
relative to current commodity prices. Working capital, EBITDAX and operating
netback as presented do not have any standardized meaning prescribed by IFRS
and therefore may not be comparable with the calculation of similar measures
for other entities.

Operating netback is defined as revenues less royalties and production and
transportation expenses.

Realized contractual gas sales is defined as gas produced and sold plus gas
revenues received from nominated take or pay contracts.

Boe Conversion – The term “boe” is used in this news release. Boe may be
misleading, particularly if used in isolation. A boe conversion ratio of cubic
feet of natural gas to barrels oil equivalent is based on an energy equivalency
conversion method primarily applicable at the burner tip and does not represent
a value equivalency at the wellhead. In this news release, we have expressed
boe using the Colombian conversion standard of 5.7 Mcf: 1 bbl required by the
Ministry of Mines and Energy of Colombia. As the value ratio between natural
gas and crude oil based on the current prices of natural gas and crude oil is
significantly different from the energy equivalency of 5.7:1, utilizing a
conversion on a 5.7:1 basis may be misleading as an indication of value.

– END RELEASE – 10/08/2017

For further information:
Canacol Energy Ltd.
Investor Relations
+1 (214) 235-4798
IR@canacolenergy.com
www.canacolenergy.com

COMPANY:
FOR: CANACOL ENERGY LTD.
TSX SYMBOL: CNE
BVC SYMBOL: CNEC
OTCQX SYMBOL: CNNEF

INDUSTRY: Energy and Utilities – Oil and Gas
RELEASE ID: 20170810CC0074

Press Release from Marketwired 1-866-736-3779

In Brad Wall, private sector had ally whose voice rang louder than most

August 11, 2017August 10, 2017 by The Canadian Press

With Brad Wall’s departure from politics, the private sector is losing an ally whose voice reverberated louder than most on the public stage.

During his 10-year tenure as Saskatchewan’s premier, Wall’s reputation as an advocate of free enterprise grew, whether he was defending the interests of potash or the oilpatch.

“He has been a strong champion for pipelines, for oil and gas, for enabling Saskatchewan to reach its economic potential,” said Tim McMillan, CEO of the Canadian Association of Petroleum Producers. McMillan previously served in several key cabinet portfolios in Wall’s government including energy.

“We will certainly miss his leadership,” McMillan said.

When he was sworn in as premier in November 2007, Wall inherited a province gushing in oil revenue thanks to high crude prices. Still, he ushered in a wave of belt-tightening measures in the years ahead, partly in anticipation of the volatility of resource revenues.

“During his term as premier we dramatically changed to a ‘can-do’ province,” said John Hopkins, CEO of the Regina and District Chamber of Commerce.

“We witnessed record growth in terms of jobs, income, and investment and it really changed from being a place to be from … to being a place to be because there were a lot of things going on.”

Scott Saxberg, CEO of Crescent Point Energy, said Wall’s consistent taxation and energy regulation policies helped enable his company to become the largest oil and gas producer in the province.

“He’s probably been one of our greatest leaders in Canada,” he said.

Saxberg and leaders of some other Calgary-based oil and gas companies with operations in Saskatchewan were invited in March to move their head offices there, a move that irked Alberta Premier Rachel Notley but for which Wall was unapologetic.

That illustrates both Wall’s role as “Our No. 1 cheerleader” and the province’s growing economic clout, even if it didn’t result in any big company moves, said Steve McLellan, CEO of the Saskatchewan Chamber of Commerce.

“Decades ago, people would have laughed out of those Calgary offices to hear a Saskatchewan premier invite them to come here,” McLellan said.

“(Now) it’s a logical consideration.”

While he was a proponent of the free market, he also stood against any measures he perceived as a threat to his home province’s economy.

A defining moment in Wall’s career occurred in 2010, when he aggressively opposed a hostile takeover bid of PotashCorp, a provincial Crown corporation, by Australia’s BHP Billiton. The acquisition was eventually blocked by the federal government.

Wall is supporting the current proposed merger of PotashCorp with Calgary-based Agrium, in part because its head office would remain in Saskatoon.

Colleen Collins, vice-president of the Canada West Foundation think tank, said Wall has been a strong voice for removing trade barriers in Western Canada and the Northwestern United States.

“He’s taken on a role as a spokesman for the West,” Collins said. “Losing someone of that experience and vision is going to be really unfortunate.”

While he was generally lauded in corporate quarters, others, including those from labour and environmental organizations, have a less favourable view of Wall’s legacy.

Bob Bymoen, president of the Saskatchewan Government and General Employees’ Union, said Wall’s time in power has been defined by privatizing government departments and replacing workers with private contractors and consultants.

“I hope the next premier doesn’t have such a hate-on for unions, that he respects working people and their right to organize and form a union,” said Bymoen, who represents about 20,000 government workers.

His government’s long-standing opposition to a carbon tax also drew scorn from environmental groups.

It’s a position that puts him “on the wrong side of history,” said Keith Stewart, a senior energy strategist with Greenpeace Canada.

Follow @HealingSlowly on Twitter.

Dan Healing, The Canadian Press

Birchcliff Announces Second Quarter 2017 Results and Updated Guidance – Part 1

August 10, 2017 by The Canadian Press

FOR: BIRCHCLIFF ENERGY LTD.
TSX SYMBOL: BIR

Date issue: August 10, 2017
Time in: 4:00 PM e

Attention:

CALGARY, ALBERTA–(Marketwired – Aug. 10, 2017) – Birchcliff Energy Ltd.
(“Birchcliff”) (TSX:BIR) is pleased to announce its second quarter 2017
results, with record quarterly funds flow from operations of $88.6 million and
record quarterly average production of 64,636 boe/d. Funds flow from operations
is up 568% and quarterly average production is up 64% from the second quarter
of 2016. The full text of Birchcliff’s Second Quarter Report containing the
unaudited interim condensed financial statements for the three and six month
periods ended June 30, 2017 and the related management’s discussion and
analysis will be available on Birchcliff’s website at www.birchcliffenergy.com
and on SEDAR at www.sedar.com.

“Birchcliff had a very strong second quarter in 2017, notwithstanding
transportation issues on the NGTL system, wet weather and access to third party
services. Our per unit operating costs were significantly lower compared to the
first quarter of 2017. Our 80 MMcf/d Phase V expansion of our Pouce Coupe
natural gas processing plant is on time and under budget which will result in
strong fourth quarter average production,” commented Jeff Tonken, President and
Chief Executive Officer of Birchcliff. “We have recently completed and entered
into a series of asset sales for total expected proceeds to Birchcliff of
approximately $142 million. As a result of these asset sales, we can now focus
on our properties in Pouce Coupe and Gordondale, whose profitable growth is the
driver of our returns to shareholders. The proceeds from these asset sales will
allow us to reduce our indebtedness, which will improve our balance sheet and
increase our financial flexibility. We expect that as a result of these asset
sales, our operating, transportation and marketing and interest costs will all
decrease on a per unit basis.”

Second Quarter 2017 Highlights

Highlights of the second quarter include the following:

/T/

— Record quarterly average production of 64,636 boe/d, a 64% increase from

39,513 boe/d in the second quarter of 2016. Production consisted of
approximately 77% natural gas and 23% light oil and NGLs as compared to
90% natural gas and 10% light oil and NGLs in the second quarter of
2016.
— Record quarterly funds flow from operations of $88.6 million ($0.33 per
basic common share), a 568% increase from $13.3 million ($0.09 per basic
common share) in the second quarter of 2016.
— Birchcliff saw a return to net income in the second quarter of 2017,
with net income to common shareholders of $17.0 million ($0.06 per basic
common share), as compared to the net loss to common shareholders of
$24.3 million ($0.16 per basic common share) in the second quarter of
2016.
— Operating costs of $4.67/boe, an 11% decrease from $5.22/boe in the
first quarter of 2017 and a 35% increase from $3.45/boe in the second
quarter of 2016. Operating costs increased from the second quarter of
2016 primarily as a result of the liquids-rich assets that Birchcliff
acquired in Gordondale on July 28, 2016, which have higher realized
sales prices but also have a higher cost structure.
— General and administrative expense of $1.07/boe, a 14% decrease from
$1.24/boe in the second quarter of 2016.
— Interest expense of $1.16/boe, a 47% decrease from $2.18/boe in the
second quarter of 2016.
— Net capital expenditures of $120.8 million for the three months ended
June 30, 2017 and $245.3 million for the six months ended June 30, 2017.
The majority of capital under Birchcliff’s planned 2017 capital
expenditure program will be spent during the first half of 2017 due to
the timing of the completion of the Phase V expansion of Birchcliff’s
100% owned and operated natural gas processing plant located in Pouce
Coupe (the “Pouce Coupe Gas Plant”) and the drilling, completion,
equipping and tie-in of the wells necessary to fill the expanded plant.
— At June 30, 2017, Birchcliff’s long-term bank debt was $628.4 million
and its total debt was $700.5 million, which does not take into account
expected proceeds in the amount of $132 million ($122 million in cash;
$10 million in securities) from asset sales which were announced
subsequent to the end of the quarter.
— The maturity dates of Birchcliff’s credit facilities were extended to
May 11, 2020 from May 11, 2018 and the borrowing base was confirmed at
$950 million. In addition, Birchcliff’s lenders consented to the
borrowing base remaining at $950 million after giving effect to the
asset sales.
— Birchcliff drilled a total of 22 (22.0 net) wells in the second quarter
of 2017, consisting of 16 (16.0 net) Montney/Doig horizontal natural gas
wells in Pouce Coupe and 6 (6.0 net) Montney horizontal oil and natural
gas wells in Gordondale.
— During the second quarter of 2017, Birchcliff completed the disposition
of certain non-core assets for total proceeds of approximately $10
million (prior to closing adjustments).

/T/

For further information regarding Birchcliff’s financial and operational
results for the second quarter of 2017, please see the President’s Message from
the Second Quarter Report, the full text of which is attached hereto.

Expansion to 2017 Capital Expenditure Budget

/T/

— Birchcliff’s Board of Directors has approved an increased 2017 capital

expenditure budget to approximately $404 million, from the $355 million
that was previously announced on February 8, 2017.
— Net capital expenditures in 2017 are expected to be approximately $262
million.
— A significant portion of the expanded budget relates to bringing 2018
capital forward in order to ensure the efficient execution of
Birchcliff’s 2018 capital program.
— Birchcliff’s increased capital expenditure program contemplates
infrastructure capital for the Phase VI expansion of the Pouce Coupe Gas
Plant and capital for the drilling of an additional 8 wells, 2 of which
are expected to be brought on production in October 2017 and 4 of which
are expected to be brought on production in late December 2017.

/T/

Updated 2017 Production Guidance

/T/

— Birchcliff has updated its 2017 production guidance to take into account

the asset sales recently announced (which represent forecast 2017
production of 3,600 boe/d) and its increased capital expenditure
program.
— Birchcliff’s 2017 annual average production is expected to be 67,000 to
68,000 boe/d (revised from 70,000 to 74,000 boe/d) and its fourth
quarter average production is expected to be 79,000 to 80,000 boe/d
(revised from 80,000 to 82,000 boe/d).

/T/

This press release contains forward-looking information within the meaning of
applicable securities laws. Such forward-looking information is based upon
certain expectations and assumptions and actual results may differ materially
from those expressed or implied by such forward-looking information. For
further information regarding the forward-looking information contained herein,
please see “Advisories – Forward-Looking Information”. In addition, this press
release contains references to “funds flow from operations”, “funds flow per
common share”, “operating netback”, “estimated operating netback”, “funds flow
netback”, “operating margin”, “total cash costs”, “adjusted working capital
deficit” and “total debt”, which do not have standardized meanings prescribed
by GAAP. For further information regarding these non-GAAP measures, including
reconciliations to the most directly comparable GAAP measure, please see
“Non-GAAP Measures”.

SECOND QUARTER 2017 FINANCIAL AND OPERATIONAL HIGHLIGHTS

/T/

—————————————-
Three months ended Six months ended
June 30, June 30,
—————————————-
2017 2016 2017 2016
—————————————————————————-
OPERATING
Average daily production
Light oil – (bbls) 7,121 2,504 6,212 2,868
Natural gas – (Mcf) 297,016 213,130 294,407 217,804
NGLs – (bbls) 8,013 1,488 7,877 1,567
Total – boe 64,636 39,513 63,157 40,736
—————————————————————————-
Average sales price ($ CDN)(1)
Light oil – (per bbl) 60.38 51.20 61.32 43.16
Natural gas – (per Mcf) 3.13 1.48 3.10 1.74
NGLs – (per bbl) 31.10 50.77 31.58 46.19
Total – boe 24.90 13.13 24.42 14.12
—————————————————————————-
NETBACK AND COST ($/boe)
Petroleum and natural gas
revenue(1) 24.92 13.14 24.43 14.13
Royalty expense (0.80) (0.25) (1.37) (0.46)
Operating expense (4.67) (3.45) (4.93) (3.58)
Transportation and marketing
expense (2.57) (2.35) (2.57) (2.30)
—————————————————————————-
Operating netback 16.88 7.09 15.56 7.79
General & administrative expense,
net (1.07) (1.24) (1.06) (1.28)
Interest expense (1.16) (2.18) (1.26) (1.94)
Realized gain on financial
instruments 0.42 0.02 0.43 0.01
—————————————————————————-
Funds flow netback 15.07 3.69 13.67 4.58
Stock-based compensation expense,
net (0.17) (0.15) (0.15) (0.16)
Depletion and depreciation expense (7.41) (8.75) (7.50) (8.85)
Accretion expense (0.14) (0.16) (0.15) (0.15)
Amortization of deferred financing
fees (0.06) (0.06) (0.06) (0.06)
Loss on sale of assets (3.58) (3.03) (1.62) (1.47)
Unrealized gain on financial
instruments 0.80 0.03 1.86 0.02
Dividends on Series C preferred
shares (0.15) (0.24) (0.15) (0.24)
Income tax recovery (expense) (1.30) 2.18 (1.71) 1.56
—————————————————————————-
Net income (loss) 3.06 (6.49) 4.19 (4.77)
Dividends on Series A preferred
shares (0.17) (0.27) (0.17) (0.27)
—————————————————————————-
Net income (loss) to common
shareholders 2.89 (6.76) 4.02 (5.04)
—————————————————————————-
FINANCIAL
Petroleum and natural gas revenue
($000s)(1) 146,597 47,261 279,305 104,764
—————————————————————————-
Funds flow from operations ($000s) 88,612 13,267 156,242 33,962
Per common share – basic ($) 0.33 0.09 0.59 0.22
Per common share – diluted ($) 0.33 0.09 0.58 0.22
—————————————————————————-
Net income (loss) ($000s) 18,015 (23,321) 47,943 (35,356)
Net income (loss) to common
shareholders ($000s) 17,015 (24,321) 45,943 (37,356)
Per common share – basic ($) 0.06 (0.16) 0.17 (0.25)
Per common share – diluted ($) 0.06 (0.16) 0.17 (0.25)
—————————————————————————-
Common shares outstanding (000s)
End of period – basic 265,417 152,308 265,417 152,308
End of period – diluted 284,461 169,089 284,461 169,089
Weighted average common shares for
period – basic 265,326 152,308 264,716 152,308
Weighted average common shares for
period – diluted 268,203 154,279 268,065 153,869
—————————————————————————-
Dividends on common shares ($000s) 6,635 – 13,239 –
Dividends on Series A preferred
shares ($000s) 1,000 1,000 2,000 2,000
Dividends on Series C preferred
shares ($000s) 875 875 1,750 1,750
—————————————————————————-
Capital expenditures, net ($000s) 120,782 4,722 245,320 68,582
Revolving term credit facilities
($000s) 628,401 709,510 628,401 709,510
Adjusted working capital deficit
($000s) 72,083 6,141 72,083 6,141
Total debt ($000s) 700,484 715,651 700,484 715,651
—————————————————————————-
(1) Excludes the effect of hedges using financial instruments.

/T/

PRESIDENT’S MESSAGE FROM THE SECOND QUARTER 2017 REPORT

August 10, 2017

Fellow Shareholders,

We are pleased to report the second quarter financial and operational results
for Birchcliff Energy Ltd. (“Birchcliff”) for the three and six month periods
ended June 30, 2017.

Highlights for the Second Quarter 2017

We had a successful second quarter in 2017, with record quarterly average
production of 64,636 boe/d and record quarterly funds flow from operations of
$88.6 million. In addition, we saw a return to net income as compared to the
net loss recorded in the second quarter of 2016, primarily as a result of
greater production and improved commodity prices. Highlights of the second
quarter include the following:

/T/

— We had record quarterly average production of 64,636 boe/d, a 64%

increase from 39,513 boe/d in the second quarter of 2016. Production
consisted of approximately 77% natural gas and 23% light oil and NGLs as
compared to 90% natural gas and 10% light oil and NGLs in the second
quarter of 2016.
— We had record quarterly funds flow from operations of $88.6 million
($0.33 per basic common share), a 568% increase from $13.3 million
($0.09 per basic common share) in the second quarter of 2016.
— We had net income to common shareholders of $17.0 million ($0.06 per
basic common share), as compared to the net loss to common shareholders
of $24.3 million ($0.16 per basic common share) in the second quarter of
2016.
— Our operating costs were $4.67/boe, an 11% decrease from $5.22/boe in
the first quarter of 2017 and a 35% increase from $3.45/boe in the
second quarter of 2016. Operating costs increased from the second
quarter of 2016 primarily as a result of the liquids-rich assets that we
acquired in Gordondale on July 28, 2016, which have higher realized
sales prices but also have a higher cost structure.
— Our general and administrative expense was $1.07/boe, a 14% decrease
from $1.24/boe in the second quarter of 2016.
— Our interest expense was $1.16/boe, a 47% decrease from $2.18/boe in the
second quarter of 2016.
— We had net capital expenditures of $120.8 million for the three months
ended June 30, 2017 and $245.3 million for the six months ended June 30,
2017. The majority of capital under our planned 2017 capital expenditure
program will be spent during the first half of 2017 due to the timing of
the completion of the Phase V expansion of our 100% owned and operated
natural gas processing plant located in Pouce Coupe (the “Pouce Coupe
Gas Plant”) and the drilling, completion, equipping and tie-in of the
wells necessary to fill the expanded plant.
— At June 30, 2017, our long-term bank debt was $628.4 million and our
total debt was $700.5 million, which does not take into account expected
proceeds in the amount of $132 million ($122 million in cash; $10
million in securities) from asset sales which were announced subsequent
to the end of the quarter.
— The maturity dates of our credit facilities were extended to May 11,
2020 from May 11, 2018 and the borrowing base was confirmed at $950
million. In addition, our lenders consented to the borrowing base
remaining at $950 million after giving effect to certain asset sales.
— We drilled a total of 22 (22.0 net) wells in the second quarter of 2017,
consisting of 16 (16.0 net) Montney/Doig horizontal natural gas wells in
Pouce Coupe and 6 (6.0 net) Montney horizontal oil and natural gas wells
in Gordondale.
— During the second quarter of 2017, we completed the disposition of
certain non-core assets for total proceeds of approximately $10 million
(prior to closing adjustments).

/T/

Birchcliff Announces Second Quarter 2017 Results and Updated Guidance – Part 2

August 10, 2017 by The Canadian Press

For further information regarding our financial and operational results for the
second quarter of 2017, please see “Second Quarter 2017 Financial and
Operational Results” below.

SECOND QUARTER 2017 FINANCIAL AND OPERATIONAL RESULTS

Production

Production for the second quarter of 2017 averaged 64,636 boe/d, which
represents a 64% increase over our quarterly average production of 39,513 boe/d
in the second quarter of 2016. The increase in production from the second
quarter of 2016 is primarily attributable to the production from our assets in
Gordondale which we acquired on July 28, 2016 (the “Gordondale Acquisition”).

Production consisted of approximately 77% natural gas, 11% light oil and 12%
NGLs in the second quarter of 2017 as compared to 90% natural gas, 6% light oil
and 4% NGLs in the second quarter of 2016. The increase in oil and NGLs
weighting as compared to the second quarter of 2016 is due to the more
heavily-weighted oil and NGLs production from our assets in Gordondale.

Funds Flow from Operations and Net Income

Funds flow from operations was $88.6 million ($0.33 per basic common share), a
568% increase from $13.3 million ($0.09 per basic common share) in the second
quarter of 2016. This increase from the second quarter of 2016 was largely due
to higher average realized sales prices and the production from our assets in
Gordondale which we acquired pursuant to the Gordondale Acquisition.

We saw a return to net income in the second quarter of 2017 as compared to the
second quarter of 2016. We had net income of $18.0 million as compared to the
net loss of $23.3 million in the second quarter of 2016. We recorded net income
to common shareholders of $17.0 million ($0.06 per basic common share) in the
second quarter of 2017 as compared to the net loss to common shareholders of
$24.3 million ($0.16 per basic common share) in the second quarter of 2016. The
changes were largely due to higher funds flow from operations.

Commodity Prices

During the second quarter of 2017, the average benchmark price for WTI oil was
US$48.29/bbl, up 6% from US$45.59/bbl during the second quarter of 2016, and
the average benchmark price for natural gas sold at AECO was $2.78/MMbtu, up
99% from $1.40/MMbtu during the second quarter of 2016. The average corporate
realized sales price during the quarter was $24.90/boe, a 90% increase from
$13.13/boe during the second quarter of 2016.

Operating Costs and General and Administrative Expense

Operating costs in the second quarter of 2017 were $4.67/boe, an 11% decrease
from $5.22/boe in the first quarter of 2017 and a 35% increase from $3.45/boe
in the second quarter of 2016. The increase in operating costs per boe from the
second quarter of 2016 was largely due to the higher cost structure associated
with our liquids-rich Gordondale assets that were acquired pursuant to the
Gordondale Acquisition and additional fees incurred to process natural gas from
Gordondale at AltaGas’ deep-cut natural gas processing facility located in
Gordondale (the “AltaGas Facility”).

General and administrative expense in the second quarter of 2017 was $1.07/boe,
a 14% decrease from $1.24/boe in the second quarter of 2016. The decrease is
due to an increase in production, partially offset by an increase in aggregate
general administrative expenses in the second quarter of 2017 as compared to
the second quarter of 2016.

Interest Expense

Our interest expense was $1.16/boe, a 47% decrease from $2.18/boe in the second
quarter of 2016. The decrease is due to an increase in production and a lower
average outstanding total credit facilities balance in the second quarter of
2017 as compared to the second quarter of 2016.

Pouce Coupe Gas Plant Netbacks

Approximately 57% of our total corporate natural gas production and 46% of our
total corporate production was processed at our Pouce Coupe Gas Plant during
the six months ended June 30, 2017 as compared to 79% and 73%, respectively,
during the six months ended June 30, 2016. These decreases are primarily due to
the liquids-rich production additions associated with our Gordondale assets.
The average plant and field operating cost for production processed through the
Pouce Coupe Gas Plant for the six months ended June 30, 2017 was $0.33/Mcfe
($1.90/boe) and the estimated operating netback at the Pouce Coupe Gas Plant
was $2.63/Mcfe ($15.80/boe), resulting in an operating margin of 77%.

The following table details our average daily production and estimated
operating netback for wells producing to the Pouce Coupe Gas Plant on a
production month basis for the periods indicated:

/T/

——————————————————
Six months ended Six months ended Six months ended
June 30, 2017 June 30, 2016 June 30, 2015
—————————————————————————-
Average daily
production, net to
Birchcliff:
Natural gas (Mcf) 169,040 171,422 157,462
Oil & NGLs (bbls) 1,081 967 1,249
—————————————————————————-
Total boe 29,254 29,537 27,494
—————————————————————————-
AECO – C daily
($/Mcf)(1) $2.74 $1.61 $2.70
—————————————————————————-
Netback and cost: $/Mcfe $/boe $/Mcfe $/boe $/Mcfe $/boe
Petroleum and
natural gas
revenue(2) 3.41 20.44 1.93 11.61 3.20 19.21
Royalty expense (0.10) (0.67) (0.05) (0.30) (0.12) (0.74)
Operating expense(3) (0.33) (1.90) (0.25) (1.47) (0.35) (2.11)
Transportation and
marketing expense (0.35) (2.07) (0.30) (1.88) (0.32) (1.92)
—————————————————————————-
Estimated operating
netback $2.63 $15.80 $1.33 $7.96 $2.41 $14.44
—————————————————————————-
Operating margin 77% 77% 69% 69% 75% 75%
—————————————————————————-
(1) $1.00/MMbtu = $1.00/Mcf based on a standard heat value Mcf.
(2) Excludes the effect of hedges using financial instruments.
(3) Represents plant and field operating costs.

/T/

Funds Flow Netback and Total Cash Costs

During the second quarter of 2017, we had funds flow netback of $15.07/boe, a
308% increase from $3.69/boe in the second quarter of 2016. The increase was
primarily driven by higher production and higher average realized oil and
natural gas prices, partially offset by an increase in total cash costs per
boe.

During the second quarter of 2017, we had total cash costs of $10.27/boe, an 8%
increase from $9.47/boe in the second quarter of 2016. On a per boe basis, the
increase in total cash costs in the second quarter of 2017 was primarily driven
by higher royalty, operating and transportation and marketing expenses
associated with our Gordondale assets, which were partially offset by lower
general and administrative and interest expenses when compared to the second
quarter of 2016.

Capital Activities and Expenditures

During the second quarter of 2017, we had net capital expenditures of $120.8
million as compared to $4.7 million during the second quarter of 2016. Our
total F&D capital during the second quarter of 2017 (which excludes
acquisitions, dispositions and administrative expenses) was $130.5 million,
which consists of $0.7 million on land and seismic, $79.9 million on drilling
and completions, $46.8 million on facilities and infrastructure and $3.1
million on other capital expenditures attributed to the execution of our
capital program. Of the $46.8 million spent on facilities and infrastructure,
approximately $20.0 million was spent on the Phase V and VI expansions of the
Pouce Coupe Gas Plant. See “Advisories – Capital Expenditures”.

Drilling and Completions

Our drilling and completions activities during the second quarter of 2017 were
focused on our Montney/Doig Resource Play in our Pouce Coupe and Gordondale
areas. During the quarter, we drilled a total of 22 (22.0 net) wells with a
100% success rate. In Pouce Coupe, we drilled 16 (16.0 net) Montney/Doig
horizontal natural gas wells, of which 10 were Montney D1 natural gas wells, 4
were Basal Doig/Upper Montney natural gas wells and 2 were Montney D4 natural
gas wells. In Gordondale, we drilled 6 (6.0 net) Montney horizontal wells, of
which 1 was a Montney D1 liquids-rich natural gas well, 1 was a Montney D1 oil
well and 4 were Montney D2 oil wells. At June 30, 2017, we have successfully
drilled and cased an aggregate of 338 (332.7 net) Montney/Doig horizontal
wells, which includes 87 (81.8 net) wells acquired in the Gordondale
Acquisition.

Credit Facilities and Debt

Our extendible revolving credit facilities have an aggregate principal amount
of $950 million (the “Credit Facilities”) and are comprised of an extendible
revolving syndicated term credit facility of $900 million (the “Syndicated
Credit Facility”) and an extendible revolving working capital facility of $50
million (the “Working Capital Facility”). The Credit Facilities are subject to
a semi-annual review of the borrowing base limit by our syndicate of lenders.
We may each year, at our option, request an extension to the maturity date of
the Syndicated Credit Facility and the Working Capital Facility, or either of
them, for an additional period of up to three years from May 11 of the year in
which the extension request is made.

In the second quarter of 2017, our syndicate of lenders completed its
semi-annual review of the borrowing base limit and in connection therewith,
Birchcliff and the lenders agreed to an extension of the maturity dates of each
facility from May 11, 2018 to May 11, 2020 and to the borrowing base remaining
unchanged at $950 million. In addition, subject to the terms and conditions of
the agreement governing the Credit Facilities, the lenders consented to the
disposition of certain assets of Birchcliff (which includes the Worsley
Disposition and the Additional Disposition) and to the borrowing base remaining
at $950 million after giving effect to such disposition. The next semi-annual
review is scheduled for November 2017. The Credit Facilities do not contain any
financial maintenance covenants.

At June 30, 2017, our long-term bank debt was $628.4 million (June 30, 2016:
$709.5 million) from available credit facilities of approximately $950 million
(June 30, 2016: $750 million), leaving $302.5 million of unutilized credit
capacity after adjusting for outstanding letters of credit and unamortized
interest and fees. Total debt at June 30, 2017 was $700.5 million as compared
to $715.7 million at June 30, 2016. The decreases in long-term debt and total
debt from June 30, 2016 are largely due to the fact that the remaining net
proceeds from the equity financings completed in July 2016 (after the payment
of the balance of the purchase price for the Gordondale assets acquired
pursuant to the Gordondale Acquisition) were used to reduce indebtedness under
our credit facilities, offset by increased capital spending in excess of funds
flow from operations during the first half of 2017.

Risk Management

At June 30, 2017, we are committed under our financial and physical hedge
contracts to the sale of 195,000 GJ/d or approximately 50% of our forecast
corporate natural gas production from July 1, 2017 to December 31, 2017 at an
average price of $3.03/GJ. At June 30, 2017, we had the following AECO natural
gas hedges outstanding on a quarterly basis:

/T/

————————————————-
Estimated
Average
Natural Gas Natural Gas
Production Wellhead
AECO AECO Hedged Price
(GJ/d) ($/GJ) (Mcf/d) ($/Mcf(1))
—————————————————————————
Q3 2017 180,000 3.00 157,245 3.44
Q4 2017 210,000 3.05 183,453 3.50
—————————————————————————
July 1, 2017 to December
31, 2017 195,000 3.03 170,349 3.47
—————————————————————————
(1) See “Advisories” for the conversion from GJ to Mcf.

/T/

We have outstanding financial derivative contracts for 1,500 bbls/d of crude
oil production from July 1, 2017 to December 31, 2017 at an average WTI price
of CDN$69.90/bbl for 2017.

FINANCIAL AND OPERATIONAL UPDATE

Series of Asset Sales for Expected Proceeds of $142 Million

We have completed and entered into definitive agreements for a series of asset
sales (the “Asset Sales”) for expected total proceeds to Birchcliff of
approximately $142 million ($132 million in cash; $10 million in securities)
(subject to closing adjustments). The Asset Sales collectively represent
forecast 2017 production of 3,600 boe/d (approximately 62% light oil and NGLs).

During the second quarter of 2017, we completed the disposition of certain
non-core assets for total proceeds of approximately $10 million (prior to
closing adjustments). On August 1, 2017, we entered into a definitive purchase
and sale agreement for the sale of our Worsley Charlie Lake Light Oil Pool for
total consideration of approximately $100 million ($90 million in cash; $10
million in securities of an affiliate of the purchaser) (the “Worsley
Disposition”). Closing of the Worsley Disposition is expected to occur on or
about August 31, 2017, subject to the receipt of all necessary regulatory
approvals and the satisfaction of other customary closing conditions. In
addition, further to our press release of August 1, 2017, we have now entered
into a definitive agreement for the sale of some of the remaining assets that
were being marketed for sale for total cash consideration of $31.7 million
(subject to closing adjustments) (the “Additional Disposition”). The effective
adjustment date of the Additional Disposition is August 1, 2017 and closing is
expected to occur on or about October 2, 2017, subject to the satisfaction of
customary closing conditions.

Update on Birchcliff Gas Plant Expansions

Pouce Coupe Gas Plant – Phase V

We have commenced the commissioning of our 80 MMcf/d Phase V expansion of our
Pouce Coupe Gas Plant, which will increase the processing capacity from the
current 180 MMcf/d to 260 MMcf/d. We anticipate that Phase V will be brought
on-stream in early September 2017, under budget and ahead of our initially
scheduled on-stream date of October 1, 2017.

Pouce Coupe Gas Plant – Phase VI

The engineering and licensing work has been completed for the 80 MMcf/d Phase
VI expansion, which will increase processing capacity from 260 MMcf/d to 340
MMcf/d. Fabrication of the major components has commenced and it is currently
expected that Phase VI will be brought on-stream in October 2018. The total
estimated cost for the Phase VI expansion is approximately $46 million, of
which we expect to spend approximately $26.5 million in 2017 and approximately
$19.5 million in 2018.

Pouce Coupe Gas Plant – Phases VII and VIII

As previously announced, we have commenced the planning and initial work to
further expand the processing capacity of our Pouce Coupe Gas Plant: (i) by 150
MMcf/d to 490 MMcf/d (Phase VII), which expansion would include deep-cut
capability; and (ii) by 100 MMcf/d to 590 MMcf/d (Phase VIII). An engineering
and design study for Phases VII and VIII was completed in June 2017. Once we
have finalized the design scope for Phases VII and VIII, we expect to commence
the regulatory approval process.

We had initially been planning for an on-stream date of 2019 for Phase VII and
2020 for Phase VIII; however, given our focus on maintaining a strong balance
sheet, reducing indebtedness and funding capital expenditures from internally
generated funds flow from operations, Birchcliff has made the decision to defer
these dates by one year to 2020 for Phase VII and 2021 for Phase VIII.
Birchcliff feels that this is a prudent decision which will help to ensure that
no unnecessary stress is placed on our balance sheet over the next few years as
capital is required to construct these plant expansions. Our revised
arrangement with AltaGas which is discussed below, allows us to defer our
planned expansions for each of Phase VII and VIII by approximately one year,
ensuring that natural gas processing is available to Birchcliff until the
construction of Phase VII is complete.

Birchcliff Announces Second Quarter 2017 Results and Updated Guidance – Part 3

August 10, 2017 by The Canadian Press

Elmworth Gas Plant

We have commenced the preliminary planning for the construction of a 100% owned
and operated natural gas plant in the Elmworth area (the “Elmworth Gas Plant”)
with a planned processing capacity of 40 MMcf/d. We had initially planned for
an on-stream date in the fall of 2021; however, Birchcliff has also made the
decision to defer this date by one year to 2022 for similar reasons set forth
above with respect to the Pouce Coupe Gas Plant.

Update on Processing Arrangements at the AltaGas Facility

We have access to 90 MMcf/d of firm processing capacity at the AltaGas Facility
and a right of first refusal with respect to firm processing capacity in excess
of 90 MMcf/d. Our processing agreement with AltaGas also contains a take-or-pay
obligation. On June 29, 2017, we modified our take-or-pay agreement with
AltaGas effective January 1, 2017 to incent volumes above our existing
take-or-pay commitment at the AltaGas Facility. Effective January 1, 2017, all
volumes over our existing take-or-pay volumes (the “Additional Volumes”) will
be processed for a significantly reduced fee. Additional Volumes shall not
apply to satisfy any portion of our existing take-or-pay obligations and the
Reduced Fee only applies to Additional Volumes.

As a result of this revised arrangement, we expect that our operating costs
will be reduced by approximately $4.7 million in 2017. In addition, as we now
expect that our take-or-pay obligation will not be fulfilled until 2020, we
will not be required to build our own plant until that time. This removes the
requirement to spend any material capital in 2017 and 2018 on our Phase VII
expansion as discussed above.

Expansion to 2017 Capital Expenditure Budget

Given our completed and planned dispositions for 2017, our Board of Directors
has approved an increased 2017 capital expenditure budget to approximately $404
million, from the $355 million that was previously announced. Net capital
expenditures in 2017 are expected to be approximately $262 million.

The additional capital under our increased 2017 capital program (the “2017
Capital Program”) will be primarily directed towards the infrastructure needed
for the Phase VI expansion of our Pouce Coupe Gas Plant and the drilling of
eight additional wells as outlined below. The following table provides the
details of our 2017 Capital Program, including a comparison to our original
2017 capital expenditure program:

/T/

2017 Capital Program(1)

Gross Wells Net Wells
—————————————-
New Old New Old
—————————————————————————-
Drilling & Development
Pouce Coupe – Montney D1 HZ Gas
Wells 26 22 26.0 22.0
Pouce Coupe – Basal Doig/Upper
Montney HZ Gas Wells 7 7 7.0 7.0
Pouce Coupe – Montney D4 HZ Gas
Wells 3 3 3.0 3.0
Pouce Coupe – Montney/Doig Vertical
Science/Technology Well(2) 1 – 1.0 –
Gordondale – Montney D2 HZ Oil
Wells 9 7 9.0 7.0
Gordondale – Montney D1 HZ Oil
Wells 5 5 5.0 5.0
Gordondale – Montney D1 HZ Gas
Wells 2 2 2.0 2.0
2018 Pre-Spend Capital(3) 1 – 1.0 –
2016 Carry Forward Capital(4) – – – –
—————————————————————————-
Total Drilling & Development(5) 54 46 54.0 46.0

Facilities & Infrastructure(6)
Production Optimization(7)
Land & Seismic
—————————————————————————-
Other
TOTAL CAPITAL
—————————————————————————-
—————————————————————————-
Acquisitions & Dispositions(8)
—————————————————————————-
—————————————————————————-
TOTAL NET CAPITAL
—————————————————————————-
—————————————————————————-

2017 Capital Program(1)

Difference in
Capital Capital
(MM$)(1) (MM$)(1)
————————-
New Old
—————————————————————————
Drilling & Development
Pouce Coupe – Montney D1 HZ Gas
Wells 113.9 86.1 27.8
Pouce Coupe – Basal Doig/Upper
Montney HZ Gas Wells 30.6 30.2 0.4
Pouce Coupe – Montney D4 HZ Gas
Wells 13.0 12.9 0.1
Pouce Coupe – Montney/Doig Vertical
Science/Technology Well(2) 3.0 – 3.0
Gordondale – Montney D2 HZ Oil
Wells 45.9 40.7 5.3
Gordondale – Montney D1 HZ Oil
Wells 27.2 28.9 (1.7)
Gordondale – Montney D1 HZ Gas
Wells 11.4 11.6 (0.2)
2018 Pre-Spend Capital(3) 9.9 – 9.9
2016 Carry Forward Capital(4) 17.0 19.4 (2.4)
—————————————————————————
Total Drilling & Development(5) 272.0 229.8 42.2

Facilities & Infrastructure(6) 87.7 85.6 2.1
Production Optimization(7) 23.9 19.4 4.5
Land & Seismic 4.5 4.6 (0.0)
—————————————————————————
Other 15.9 15.9 0.0
TOTAL CAPITAL 404.0 355.2 48.8
—————————————————————————
—————————————————————————
Acquisitions & Dispositions(8) (141.6) (0.2) (141.4)
—————————————————————————
—————————————————————————
TOTAL NET CAPITAL 262.4 355.0 (92.6)
—————————————————————————
—————————————————————————
(1) Numbers may not add due to rounding.
(2) Capital includes pad construction, drilling and core cutting and
analysis.
(3) Capital includes the drilling of 1 (1.0) Montney D1 horizontal natural
gas well in Pouce Coupe, 3 surface holes and surface pad construction
in anticipation of our 2018 drilling program.
(4) Primarily completion, equipping and tie-in costs associated with 10
(10.0 net) wells rig released at the end of 2016.
(5) All drilling and development costs have been presented on a drill,
case, complete, equip and tie-in basis except for 1 Montney D1 well
referred to in note (3) above and the Montney/Doig vertical
science/technology well.
(6) Includes approximately $26.3 million of capital in 2017 for the Phase V
expansion and $26.5 million of capital in 2017 for the Phase VI
expansion.
(7) Includes $12.3 million of sustaining capital.
(8) The 2017 Capital Program has been presented on both a total and net
basis (net of acquisitions and dispositions). Dispositions that have
been completed or announced at the date of this press release have been
accounted for in the table above. See “Advisories – Capital
Expenditures”.

/T/

The additional 8 (8.0 net) wells consist of 2 Montney D2 horizontal oil wells
in Gordondale, 5 Montney D1 horizontal natural gas wells in Pouce Coupe and 1
Montney/Doig vertical science and technology well in Pouce Coupe (see “Science
and Technology Multi-Well Pad Program”). Of these additional wells, the 2
Montney D2 horizontal oil wells in Gordondale are expected to be brought on
production in October 2017 and 4 Montney D1 horizontal natural gas wells in
Pouce Coupe are expected to be brought on production in late December 2017. The
remaining D1 horizontal well in Pouce Coupe will not be brought on production
until 2018. See “Operational Update” below.

The expanded portion of our 2017 Capital Program also includes capital for
longer-lead time items related to our 2018 capital program and the Phase VI
expansion of our Pouce Coupe Gas Plant, including the construction of
multi-well pads for use in 2018, the commencement of part of our 2018 drilling
program in December 2017 and pipeline infrastructure commitments for Phase VI
(which is scheduled to come on-stream in October 2018).

Operational Update

Our 2017 Capital Program is progressing well, is on schedule and is meeting our
expectations for capital costs and results. Our increased 2017 Capital Program
contemplates the drilling of a total of 54 (54.0 net) wells during 2017, 38
(38.0 net) in Pouce Coupe and 16 (16.0 net) in Gordondale. The following table
summarizes the wells we have drilled and brought on production year-to-date, as
well as the remaining wells to be drilled and brought on production during 2017:

/T/

Wells Drilled – 2017

—————————————————————————

Remaining
wells to be Total wells
Wells drilled drilled to be drilled
Area to-date in 2017 in 2017
—————————————————————————
Pouce Coupe
Montney D1 HZ Gas Wells 21 6 27
Basal Doig/Upper Montney HZ Gas
Wells 7 0 7
Montney D4 HZ Gas Wells 3 0 3
Montney/Doig Vertical
Science/Tech Well 0 1 1
————————————————————————-
Total – Pouce Coupe 31 7 38

Gordondale

Montney D2 HZ Oil Wells 9 0 9
Montney D1 HZ Oil Wells 5 0 5
Montney D1 HZ Liquids Rich Gas
Wells 2 0 2
————————————————————————-
Total – Gordondale 16 0 16

—————————————————————————
TOTAL – COMBINED 47 7 54
—————————————————————————

Wells Drilled and Brought on Production – 2017
—————————————————————————

Remaining
wells to be Total wells
Wells brought brought on to be brought
on production production in on production
Area to-date 2017 in 2017
—————————————————————————
Pouce Coupe
Montney D1 HZ Gas Wells 8 18 26(1)
Basal Doig/Upper Montney HZ Gas 1 6 7
Wells
Montney D4 HZ Gas Wells 1 2 3
Montney/Doig Vertical N/A N/A N/A(1)
Science/Tech Well
————————————————————————-
Total – Pouce Coupe 10 26 36(1)

Gordondale

Montney D2 HZ Oil Wells 3 6 9
Montney D1 HZ Oil Wells 4 1 5
Montney D1 HZ Liquids Rich Gas 2 0 2
Wells
————————————————————————-
Total – Gordondale 9 7 16

—————————————————————————
TOTAL – COMBINED 19 33 52(1)
—————————————————————————

(1) A total of 27 Montney D1 horizontal natural gas wells are expected to

be drilled in Pouce Coupe in 2017. Of these 27 wells, one well is
expected be drilled in December 2017 and will not be completed or
brought production until 2018. Accordingly, only 26 of the Montney D1
horizontal natural gas wells drilled in 2017 are expected to be brought
on production during the year. In addition, the Montney/Doig vertical
science/technology well will not be a producing well and will not
brought on production. Accordingly, of the 54 wells expected to be
drilled during 2017, only 52 will be brought on production during 2017.

/T/

We have drilled a total of 47 (47.0 net) wells year-to-date (21 during the
first quarter, 22 during the second quarter and an additional 4 wells
subsequent to the end of the second quarter), all of which were successful. Of
the 54 (54.0 net) wells planned to be drilled during 2017, a total of 52 wells
are anticipated to be brought on production this year as one Montney D1
horizontal natural gas well is scheduled to be drilled in December 2017 and
will not be brought on production until 2018 and the Montney/Doig vertical
science/technology well will not be a producing well. In addition, our 2017
Capital Program also included the capital associated with the completion,
equipping and tie-in of 10 wells drilled in 2016, all of which were brought on
production in the first quarter of 2017. Accordingly, a total of 62 (62.0 net)
wells are expected to be brought on production during 2017. Of the 33 wells
remaining to be brought on production, 15 have already been completed, 13 are
awaiting completion and 5 are remaining to be drilled.

Birchcliff Announces Second Quarter 2017 Results and Updated Guidance – Part 4

August 10, 2017 by The Canadian Press

All wells drilled in 2017 were drilled on multi-well pads, which allows us to
reduce our per well costs and our environmental footprint. In addition, we
actively employ the evolving technology utilized by the industry regarding
horizontal well drilling and the related multi-stage fracture stimulation
technology.

We currently have 2 drilling rigs at work, both in Pouce Coupe. In addition to
these drilling rigs, we have multiple completion rigs and pipeline crews
working on various projects.

In Pouce Coupe, there are 26 wells left to bring on production during the
remainder of 2017. It is currently expected that all but 4 of these wells will
be brought on production by October 1, 2017 in connection with Phase V coming
on-stream. The remaining 4 wells are anticipated to be brought on production in
December 2017.

In Gordondale, we drilled 6 (6.0 net) Montney horizontal wells in the fourth
quarter of 2016, 3 of which were Montney D2 oil wells and 3 of which were
Montney D1 liquids-rich natural gas wells. These wells were completed, equipped
and brought on production in the first quarter of 2017 and continue to meet our
expectations. We have 7 wells left to bring on production in Gordondale during
the remainder of 2017. It is expected that 3 wells will be brought on
production in August and the remaining 4 wells will be brought on production in
October 2017. After these remaining wells have been brought on production, we
will have drilled, cased, completed and equipped a total of 22 wells on our
Gordondale assets (12 Montney D2 oil wells, 5 Montney D1 oil wells and 5
Montney D1 liquids-rich natural gas wells) since we acquired the assets in July
2016.

Science and Technology Multi-Well Pad Program

We are finalizing the planning on the execution of a science and technology
multi-well pad program later this year in order to optimize field development
and develop an improved understanding of wells drilled on the Montney/Doig
Resource Play. The first phase of the program involves the drilling of the
vertical science and technology well, which is expected to be drilled in August
2017. The well will be drilled to the top of the Montney where we will extract
a full diameter core through the entire Montney section (approximately 300
metres). The extracted rock core will provide analytical data to increase our
knowledge of rock properties, which will be incorporated in our petrophysical
models and help us to more accurately represent the geology of the area. The
vertical well will be open holed logged with both conventional logging
techniques, as well as advanced logging techniques, including formation imager,
sonic scanner, geochemical spectroscopy and nuclear magnetic resonance. The
second phase of the program which is expected to commence in early 2018
involves the drilling, completing, equipping and bringing on production of a
Montney/Doig multi-layer four well pad utilizing the reservoir learnings from
the vertical well. During the completion of the 4 horizontal wells, we intend
to utilize the vertical well as a seismic monitoring well to gain further
insight into fracture parameters and complexity. In addition to the vertical
well, we plan to install a permanent fiber optic cable within the horizontal
portion of one of the Montney horizontal wells, allowing further data to be
collected on fracture parameters and ongoing production performance along the
horizontal well length.

The purpose of this program is to collect high quality and high value data from
the vertical well and the straddling horizontal wells, which can be used to
accelerate our technical capabilities and understanding with respect to the
drilling, completion and production from a multi-layer resource play.

Update on Natural Gas Transportation Capacity – Additional Firm Service

TCPL Mainline

We have entered into agreements with TransCanada Pipelines (“TCPL”) for the
firm service transportation of 175,000 GJ/d in aggregate (approximately 155
MMcf/d) of natural gas on TCPL’s Canadian Mainline for a ten year term, whereby
natural gas will be transported from the Empress receipt point in Alberta to
the Dawn trading hub located in Southern Ontario. The toll for the Empress to
Dawn portion of the service is $0.77/GJ plus fuel. Subject to regulatory
approval, this service is expected to become available in three tranches on
November 1 of each of 2017, 2018 and 2019. Provision of the service is
conditional on, among other things, TCPL receiving National Energy Board
approval on terms and conditions satisfactory to TCPL.

Alliance System

In addition, we have sales agreements with a third party marketer to sell
approximately 40 MMcf/d of natural gas under contracts commencing November 1,
2017 and expiring March 31, 2018 and approximately 5 MMcf/d of natural gas
under contracts commencing April 1, 2017 and expiring October 31, 2020. This
production will be delivered into the Alliance Pipeline system and sold at
Alliance’s Trading Pool daily index price. We have completed the installation
of the pipeline facilities necessary to access the Alliance pipeline system,
including the construction of a new meter station. We expect to sell gas at
various quantities to the Alliance system until November 1, 2017 where we will
flow over 40 MMcf/d as outlined above.

As virtually all of our natural gas production is currently transported on the
NGTL system in Alberta and sold at AECO, we expect that the above arrangements
will provide us with access to a more diverse portfolio of natural gas markets
and prices beyond AECO.

OUTLOOK AND GUIDANCE

We have updated our 2017 production guidance to take into account the Asset
Sales (which represent forecast 2017 production of approximately 3,600 boe/d)
and our increased 2017 Capital Program. The following table sets forth our
previous and updated guidance for 2017:

/T/

Previous Guidance Updated Guidance
——————————– ——————– ——————–
Estimated 2017 Annual Average 70,000 – 74,000 67,000 – 68,000
Production boe/d boe/d
% Oil and NGLs 23% 21%
Estimated 2017 Q4 Average 80,000 – 82,000 79,000 – 80,000
Production boe/d boe/d
% Oil and NGLs 21% 20%
Total capital expenditures $355 million $404 million
Net capital expenditures $355 million $262 million
—————————————————————————-
(1) For further information regarding our guidance, including the
assumptions surrounding such guidance, please see “Advisories –
Forward-Looking Information” in this press release.

/T/

We expect that our operating costs in the fourth quarter of 2017 will be less
than $4.00/boe, assuming the successful completion of the Asset Sales and the
Phase V expansion of our Pouce Coupe Gas Plant coming on-stream as planned.

We have hedged approximately 50% of our forecast 2017 natural gas production at
an estimated average wellhead price of $3.47/Mcf, which helps to protect our
balance sheet and our 2017 Capital Program. Although the majority of our
capital expenditures are planned to be spent during the first half of 2017, we
expect that the entirety of our 2017 Capital Program will be fully funded out
of our forecast 2017 funds flow from operations, as well as the proceeds from
the Asset Sales. The foregoing is based on our revised budgeted forecast
average prices of approximately WTI US$50.00 per barrel of oil and
approximately AECO CDN$2.35 per GJ of natural gas during 2017.

We are currently in the process of updating our Five Year Plan, which we expect
to announce in the fall of 2017. We have deferred the construction of Phases
VII and VIII of our Pouce Coupe Gas Plant, reduced the number of wells required
to be drilled as a result of the Asset Sales and reduced both the cost of
drilling wells and the per unit operating costs associated with our production.
We intend to continue to maintain a strong balance sheet and financial
flexibility, while we continue to pay a sustainable dividend.

SHAREHOLDER SUPPORT

We thank Mr. Seymour Schulich, our largest shareholder, for his leadership,
unwavering commitment and his ongoing support. It is this kind of leadership
that keeps our staff motivated and focused on the execution of our business
plan. Mr. Schulich currently holds 40 million common shares, which represents
approximately 15% of the current issued and outstanding common shares.

THANK YOU

We would like to take this opportunity to specifically thank our staff who are
leaving Birchcliff as a result of the Asset Sales. These people are committed
employees who were part of the Birchcliff Team. These people helped to create
significant value for our shareholders and were part of the fabric of our
culture. On behalf of our Board of Directors and our Management Team, we thank
them for their hard work and dedication and wish them the best in the future.

Our Management Team and our employees are excited, committed and remain
enthusiastic about executing our long-term plan and delivering value to our
shareholders. Thank you to all of our shareholders for your support and to our
employees who continue to go that extra mile for the benefit of all of us.

With Respect,

(signed) “A. Jeffery Tonken”

President and Chief Executive Officer

Birchcliff Energy Ltd.

ABBREVIATIONS

/T/

AECO physical storage and trading hub for natural gas on the
TransCanada Alberta transmission system which is the delivery
point for various benchmark Alberta index prices
bbl barrel
bbls barrels
bbls/d barrels per day
boe barrel of oil equivalent
boe/d barrels of oil equivalent per day
F&D finding and development
GAAP generally accepted accounting principles
GJ gigajoule
GJ/d gigajoules per day
HZ horizontal
IFRS International Financial Reporting Standards
m3 cubic metres
Mcf thousand cubic feet
Mcfe thousand cubic feet of gas equivalent
MJ megajoules
MMbtu million British thermal units
MMcf million cubic feet
MMcf/d million cubic feet per day
NGLs natural gas liquids
NGTL NOVA Gas Transmission Ltd.
WTI West Texas Intermediate oil at Cushing, Oklahoma, the
benchmark for North American crude oil pricing
000s thousands
$000s thousands of dollars

/T/

NON-GAAP MEASURES

This press release uses “funds flow from operations”, “funds flow per common
share”, “operating netback”, “estimated operating netback”, “funds flow
netback”, “operating margin”, “total cash costs”, “adjusted working capital
deficit” and “total debt”. These measures do not have standardized meanings
prescribed by GAAP and therefore may not be comparable to similar measures
presented by other companies where similar terminology is used. Management
believes that these non-GAAP measures assist management and investors in
assessing Birchcliff’s profitability, efficiency, liquidity and overall
performance. Each of these measures is discussed in further detail below.

“Funds flow from operations” denotes cash flow from operating activities before
the effects of decommissioning expenditures and changes in non-cash working
capital. “Funds flow per common share” denotes funds flow from operations
divided by the basic or diluted weighted average number of common shares
outstanding for the period. Management believes that funds flow from operations
and funds flow per common share assist management and investors in assessing
Birchcliff’s profitability, as well as its ability to generate the cash
necessary to fund future growth through capital investments, pay dividends and
repay debt. The following table provides a reconciliation of cash flow from
operating activities, as determined in accordance with IFRS, to funds flow from
operations:

/T/

——————————————-
Three months ended Six months ended
June 30, June 30,
——————————————-
($000s) 2017 2016 2017 2016
—————————————————————————
Cash flow from operating
activities 57,467 7,049 128,081 27,796
Adjustments:
Decommissioning expenditures 70 16 371 593
Change in non-cash working
capital 31,075 6,202 27,790 5,573
————————————————————————-
Funds flow from operations 88,612 13,267 156,242 33,962
—————————————————————————

/T/

“Operating netback” denotes petroleum and natural gas revenue less royalties,
less operating expenses and less transportation and marketing expenses.
“Estimated operating netback” of the Pouce Coupe Gas Plant (and the components
thereof) is based upon certain cost allocations and accruals directly
attributable to the Pouce Coupe Gas Plant and related wells and infrastructure
on a production month basis. “Funds flow netback” denotes petroleum and natural
gas revenue less royalties, less operating expenses, less transportation and
marketing expenses, less net general and administrative expenses, less interest
expenses and less any realized losses (plus realized gains) on financial
instruments and plus any other cash income sources. All netbacks are calculated
on a per boe basis, unless otherwise indicated. Management believes that
operating netback, estimated operating netback and funds flow netback assist
management and investors in assessing Birchcliff’s profitability and its
operating results on a per unit basis to better analyze its performance against
prior periods on a comparable basis. The following table provides a breakdown
of operating netback and funds flow netback for the periods indicated:

/T/

——————————————
Three months ended
June 30,
——————————————
2017 2016
——————————————
($000s) ($/boe)(1) ($000s) ($/boe)(1)
—————————————————————————-
Petroleum and natural gas
revenue 146,597 24.92 47,261 13.14
Royalty expense (4,711) (0.80) (885) (0.25)
Operating expense (27,453) (4.67) (12,403) (3.45)
Transportation and marketing
expense (15,175) (2.57) (8,496) (2.35)
—————————————————————————-
Operating netback 99,258 16.88 25,477 7.09
General & administrative
expense, net (6,286) (1.07) (4,468) (1.24)
Interest expense (6,844) (1.16) (7,825) (2.18)
Realized gain on financial
instruments 2,484 0.42 83 0.02
—————————————————————————-
Funds flow netback 88,612 15.07 13,267 3.69
—————————————————————————-

——————————————
Six months ended
June 30,
——————————————
2017 2016
——————————————
($000s) ($/boe)(1) ($000s) ($/boe)(1)
—————————————————————————-
Petroleum and natural gas
revenue 279,305 24.43 104,764 14.13
Royalty expense (15,677) (1.37) (3,436) (0.46)
Operating expense (56,403) (4.93) (26,555) (3.58)
Transportation and marketing
expense (29,381) (2.57) (16,999) (2.30)
—————————————————————————-
Operating netback 177,844 15.56 57,774 7.79
General & administrative
expense, net (12,139) (1.06) (9,481) (1.28)
Interest expense (14,358) (1.26) (14,414) (1.94)
Realized gain on financial
instruments 4,895 0.43 83 0.01
—————————————————————————-
Funds flow netback 156,242 13.67 33,962 4.58
—————————————————————————-
(1) All per boe figures are calculated by dividing each aggregate financial
amount by the production (boe) in the respective period.

/T/

Birchcliff Announces Second Quarter 2017 Results and Updated Guidance – Part 5

August 10, 2017 by The Canadian Press

“Operating margin” for the Pouce Coupe Gas Plant is calculated by dividing the
estimated operating netback for the period by the petroleum and natural gas
revenue for the period. Management believes that operating margin assists
management and investors in assessing the profitability and efficiency of the
Pouce Coupe Gas Plant and Birchcliff’s ability to generate operating cash flows
(equal to petroleum and natural gas revenue less royalties, less operating
expenses and less transportation and marketing expenses).

“Total cash costs” are comprised of royalty, operating, transportation and
marketing, general and administrative and interest expenses. Total cash costs
are calculated on a per boe basis. Management believes that total cash costs
assists management and investors in assessing Birchcliff’s efficiency and
overall cash cost structure.

“Adjusted working capital deficit” is calculated as current assets minus
current liabilities excluding the effects of any financial instruments.
Management believes that adjusted working capital deficit assists management
and investors in assessing Birchcliff’s liquidity. The following table
reconciles working capital deficit (current assets minus current liabilities),
as determined in accordance with IFRS, to adjusted working capital deficit:

/T/

———————————————
As at,($000s) June 30, 2017 December 31, 2016 June 30, 2016
—————————————————————————-
Working capital deficit 60,254 36,928 6,017
Fair value of financial
instruments 11,829 (9,433) 124
—————————————————————————-
Adjusted working capital
deficit 72,083 27,495 6,141
—————————————————————————-

/T/

“Total debt” is calculated as the revolving term credit facilities plus
adjusted working capital deficit. Management believes that total debt assists
management and investors in assessing Birchcliff’s liquidity. The following
table provides a reconciliation of the revolving term credit facilities, as
determined in accordance with IFRS, to total debt:

/T/

———————————————
As at,($000s) June 30, 2017 December 31, 2016 June 30, 2016
—————————————————————————
Revolving term credit
facilities 628,401 572,517 709,510
Adjusted working capital
deficit 72,083 27,495 6,141
—————————————————————————
Total debt 700,484 600,012 715,651
—————————————————————————

/T/

ADVISORIES

Unaudited Information

All financial and operating information contained in this press release for the
three and six months ended June 30, 2017 is unaudited.

Currency

All amounts in this press release are stated in Canadian dollars unless
otherwise specified.

Operating Costs

References in this press release to “operating costs” exclude transportation
and marketing costs.

Boe and Mcfe Conversions

Boe amounts have been calculated by using the conversion ratio of 6 Mcf of
natural gas to 1 bbl of oil and Mcfe amounts have been calculated by using the
conversion ratio of 1 bbl of oil to 6 Mcf of natural gas. Boe and Mcfe amounts
may be misleading, particularly if used in isolation. A boe conversion ratio of
6 Mcf: 1 bbl and an Mcfe conversion ratio of 1 bbl: 6 Mcf is based on an energy
equivalency conversion method primarily applicable at the burner tip and does
not represent a value equivalency at the wellhead. Given that the value ratio
based on the current price of crude oil as compared to natural gas is
significantly different from the energy equivalency of 6:1, utilizing a
conversion on a 6:1 basis may be misleading as an indication of value.

MMbtu Pricing Conversions

$1.00 per MMbtu equals $1.00 per Mcf based on a standard heat value Mcf.

Conversion from GJ to Mcf – Wellhead Price

Birchcliff receives premium pricing for its natural gas production due to its
high heat content from its properties. With respect to Birchcliff’s natural gas
hedging contracts outstanding as of June 30, 2017, the prices have been
presented in both AECO CDN $/GJ and $/Mcf, with the latter representing the
average expected natural gas wellhead price under contract. The conversion from
GJ to Mcf is based on an expected corporate average natural gas heat content
value of 40.63 MJ/m3 for the period from July 1, 2017 to December 31, 2017.

Initial Production Rates

Any references in this press release to initial production rates and other
short-term production rates are useful in confirming the presence of
hydrocarbons; however, such rates are not determinative of the rates at which
such wells will continue to produce and decline thereafter and are not
indicative of the long-term performance or of the ultimate recovery of such
wells.

Oil and Gas Metrics

This press release contains metrics commonly used in the oil and natural gas
industry, including “operating netback” and “funds flow netback”. These oil and
gas metrics do not have any standardized meanings or standard methods of
calculation and therefore may not be comparable to similar measures presented
by other companies where similar terminology is used and should not be used to
make comparisons. Such metrics have been included herein to provide readers
with additional measures to evaluate Birchcliff’s performance; however, such
measures are not reliable indicators of Birchcliff’s future performance and
future performance may not compare to Birchcliff’s performance in previous
periods and therefore such metrics should not be unduly relied upon. For
information on how such netbacks are calculated, please see “Non-GAAP Measures”.

Capital Expenditures

Unless otherwise stated, references in this press release to “net capital
expenditures” and “capital expenditures, net” denote F&D costs plus
administrative costs plus acquisition capital, less any dispositions.

The 2017 Capital Program has been presented both on a total and a net basis
(net of acquisitions and dispositions). Certain dispositions that have been
completed or announced at the date of this press release have been accounted
for in Birchcliff’s estimate of net capital expenditures as disclosed under the
heading “Expansion to 2017 Capital Expenditure Budget”. Birchcliff makes
acquisitions and dispositions in the ordinary course of business. Any further
acquisitions and dispositions completed during 2017 could have an impact on
Birchcliff’s capital expenditures, production and funds flow from operations
for 2017, which impact could be material. In addition, Birchcliff’s estimate of
2017 net capital expenditures is subject to change if any unplanned acquisition
and disposition activity is carried out during 2017. See also “Advisories –
Forward-Looking Information” below.

Forward-Looking Information

Certain statements contained in this press release constitute forward-looking
statements and information (collectively referred to as “forward-looking
information”) within the meaning of applicable Canadian securities laws. Such
forward-looking information relates to future events or Birchcliff’s future
performance. All information other than historical fact may be forward-looking
information. Such forward-looking information is often, but not always,
identified by the use of words such as “seek”, “plan”, “expect”, “project”,
“intend”, “believe”, “anticipate”, “estimate”, “forecast”, “potential”,
“proposed”, “predict”, “budget”, “continue”, “targeting”, “may”, “will”,
“could”, “might”, “should” and other similar words and expressions. This
information involves known and unknown risks, uncertainties and other factors
that may cause actual results or events to differ materially from those
anticipated in such forward-looking information. Birchcliff believes that the
expectations reflected in the forward-looking information are reasonable in the
current circumstances but no assurance can be given that these expectations
will prove to be correct and such forward-looking information included in this
press release should not be unduly relied upon.

In particular, this press release contains forward-looking information relating
to the following: Birchcliff’s plans and other aspects of its anticipated
future financial performance, operations, focus, objectives, strategies,
opportunities, priorities and goals, including Birchcliff’s focus on
maintaining a strong balance sheet, reducing indebtedness and funding capital
expenditures from internally generated funds flow; the Asset Sales, including
the total expected proceeds from the Asset Sales, the estimates of 2017
production for the assets, the anticipated closing dates of the Worsley
Disposition and the Additional Disposition, the anticipated use of proceeds
from the Asset Sales and the anticipated benefits of the Asset Sales (including
that the Asset Sales will allow Birchcliff to focus on its Pouce Coupe and
Gordondale properties, that the proceeds from the Asset Sales will allow
Birchcliff to reduce its indebtedness, that Birchcliff’s balance sheet will be
improved and that its financial flexibility will be increased and Birchcliff’s
expectation that certain of its costs will decrease on a per unit basis); the
2017 Capital Program and Birchcliff’s proposed exploration and development
activities and the timing thereof, including the amount and allocation of
capital expenditures, the number and types of wells to be drilled and brought
on production and the timing thereof, estimates of total and net capital
expenditures, that the majority of capital will be spent during the first half
of 2017, the focus of the program and Birchcliff’s expectation that the
entirety of the 2017 Capital Program will be fully funded out of Birchcliff’s
forecast funds flow from operations for 2017 and the proceeds from the Asset
Sales;
Birchcliff’s science and technology multi-well pad program; Birchcliff’s
production guidance, including its estimates of its annual average and fourth
quarter average production and commodity mix in 2017 and Birchcliff’s
expectation that it will have strong fourth quarter average production;
proposed expansions of the Pouce Coupe Gas Plant, including the anticipated
processing capacities of the Pouce Coupe Gas Plant after such expansions, the
anticipated timing of such expansions, the anticipated cost of and the capital
required for such expansions and the timing thereof (including that Phase V
will be under budget and that Birchcliff will not be required to spend any
material capital in 2017 and 2018 on Phase VII), the proposed design and
capabilities of such expansions, that no unnecessary stress is expected to be
placed on Birchcliff’s balance sheet over the next few years as capital is
required to construct these plant expansions and that natural gas processing
will be available to Birchcliff until the construction of Phase VII is
complete; the Elmworth Gas Plant, including the anticipated processing capacity
of the Elmworth Gas Plant and the anticipated timing of such plant;
Birchcliff’s expectation that as a result of its revised arrangement with
AltaGas, its operating costs will be reduced by approximately $4.7 million in
2017 and that its take-or-pay obligation will not be fulfilled until 2020;
Birchcliff’s expectation that its operating costs in the fourth quarter of 2017
will be less than $4.00/boe; the performance characteristics of Birchcliff’s
oil and natural gas properties and expected results from its assets, including
that the profitable growth of Birchcliff’s Pouce Coupe and Gordondale
properties is the driver of its returns to shareholders; the timing of the next
semi-annual review under Birchcliff’s Credit Facilities; firm service on TCPL’s
Canadian Mainline and the timing thereof and statements that Birchcliff’s
arrangements to sell natural gas into the Alliance system and the proposed firm
service on TCPL’s Canadian Mainline will provide Birchcliff with a more diverse
portfolio of natural gas markets and prices beyond AECO; Birchcliff’s
expectation that it will announce its updated Five Year Plan in the fall of
2017; and that Birchcliff intends to continue to maintain a strong balance
sheet and financial flexibility, while it continues to pay a sustainable
dividend.

With respect to forward-looking information contained in this press release,
assumptions have been made regarding, among other things: that the Worsley
Disposition and the Additional Disposition will be completed on the terms and
the timing anticipated; the ability to obtain any necessary regulatory
approvals and the satisfaction of all conditions to the Worsley Disposition and
the Additional Disposition in a timely manner; the scope of and the effects of
the expected benefits of the Asset Sales; Birchcliff’s ability to continue to
develop its assets and obtain the anticipated benefits therefrom; prevailing
and future commodity prices and differentials, currency exchange rates,
interest rates, inflation rates, royalty rates and tax rates; expected funds
flow from operations; Birchcliff’s future debt levels; the state of the economy
and the exploration and production business; the economic and political
environment in which Birchcliff operates; the regulatory framework regarding
royalties, taxes and environmental laws; the sources of funding for
Birchcliff’s capital expenditure programs and other activities; anticipated
timing and results of capital expenditures; the sufficiency of budgeted capital
expenditures to carry out planned operations; results of future operations;
future operating, transportation, marketing and general and administrative
costs; the performance of existing and future wells, well production rates and
well decline rates; well drainage areas; success rates for future drilling;
reserves and resource volumes and Birchcliff’s ability to replace and expand
oil and gas reserves through acquisition, development or exploration; the
impact of competition on Birchcliff; the availability of, demand for and cost
of labour, services and materials; Birchcliff’s ability to access capital; the
ability to obtain financing on acceptable terms; the ability to obtain any
necessary regulatory approvals in a timely manner; the ability of Birchcliff to
secure adequate transportation for its products; Birchcliff’s ability to market
oil and gas; and the availability of hedges on terms acceptable to Birchcliff.

In addition to the foregoing assumptions, Birchcliff has made the following
assumptions with respect to certain forward-looking information contained in
this press release:

/T/

— With respect to the 2017 Capital Program (including estimates of capital

expenditures and statements that the entirety of the 2017 Capital
Program will be fully funded out of Birchcliff’s forecast 2017 funds
flow from operations and the proceeds from the Asset Sales), such
program is based on the following commodity price and exchange rate
assumptions during 2017: an annual average WTI price of approximately
US$50.00 per bbl of oil (revised from US$55.00 as announced on February
8, 2017); an AECO price of approximately CDN $2.35 per GJ of natural gas
(revised from $3.00 as announced on February 8, 2017); and an exchange
rate of US$/CDN$ of 1.30 (revised from 1.29 as announced on February 8,
2017).

— With respect to Birchcliff’s estimates of capital expenditures, such
estimates assume that the 2017 Capital Program will be carried out
as currently contemplated and, in the case of its estimate of net
capital expenditures, that the Worsley Disposition and the
Additional Disposition are completed on the terms and timing
anticipated. See “Advisories – Capital Expenditures”.

— With respect to statements that the entirety of the 2017 Capital
Program will be fully funded out of Birchcliff’s forecast 2017 funds
flow from operations and the proceeds from the Asset Sales, such
estimates and statements assume that: the 2017 Capital Program will
be carried out as currently contemplated; the production targets and
commodity price assumptions set forth herein are achieved;
Birchcliff’s forecast commodity mix is achieved; and the Worsley
Disposition and the Additional Disposition are completed on the
terms and timing anticipated.

— Birchcliff had previously disclosed that it expected that the
entirety of its 2017 Capital Program would be fully funded out of
its forecast funds flow from operations as such funds flow was
expected to exceed its 2017 capital expenditures over the course of
2017, based on its budgeted forecast average prices of WTI US$55.00
per barrel of oil and AECO CDN$3.00 per GJ of natural gas during
2017. Birchcliff has revised its budgeted forecast commodity price
assumptions to an average price of WTI US$50.00 per barrel of oil
and an average price of AECO CDN$2.35 per GJ of natural gas during
2017. Given the Asset Sales and Birchcliff’s increased 2017 Capital
Program, its updated production guidance and its revised commodity
price assumptions for 2017, Birchcliff now expects that the entirety
of its 2017 Capital Program will be fully funded out of its forecast
funds flow from operations, as well as the proceeds of the Asset
Sales based on such revised commodity price assumptions and assuming
completion of the Worsley Disposition and the Additional Disposition
on the terms and timing anticipated.

— The amount and allocation of capital expenditures for exploration
and development activities by area and the number and types of wells
to be drilled is dependent upon results achieved and is subject to
review and modification by management on an ongoing basis throughout
the year. Actual spending may vary due to a variety of factors,
including commodity prices, economic conditions, results of
operations and costs of labour, services and materials.

— With respect to Birchcliff’s production guidance, the key assumptions

are that: Birchcliff’s capital expenditure programs will be carried out
as currently contemplated; no unexpected outages occur in the
infrastructure that Birchcliff relies on to produce its wells and that
any transportation service curtailments or unplanned outages that occur
will be short in duration or otherwise insignificant; the construction
of new infrastructure meets timing and operational expectations;
existing wells continue to meet production expectations; and future
wells scheduled to come on production meet timing, production and
capital expenditure expectations. In addition, Birchcliff’s production
may be affected by acquisition and disposition activity and acquisitions
and dispositions could occur that may impact expected production.

— With respect to statements of future wells to be drilled and brought on

production, the key assumptions are: the continuing validity of the
geological and other technical interpretations performed by Birchcliff’s
technical staff, which indicate that commercially economic volumes can
be recovered from Birchcliff’s lands as a result of drilling future
wells; and that commodity prices and general economic conditions will
warrant proceeding with the drilling of such wells.

— With respect to statements regarding proposed expansions of the Pouce

Coupe Gas Plant, including the anticipated processing capacities of the
Pouce Coupe Gas Plant after such expansions and the anticipated timing
of such expansions, the key assumptions are that: future drilling is
successful; there is sufficient labour, services and equipment
available; Birchcliff will have access to sufficient capital to fund
those projects; the key components of the plant will operate as
designed; and commodity prices and general economic conditions will
warrant proceeding with the construction of such facilities and the
drilling of associated wells.

— With respect to statements regarding Birchcliff’s intention to construct

the Elmworth Gas Plant, including the anticipated processing capacity of
such plant and the anticipated timing thereof, the key assumptions are
that: future drilling in the Elmworth area is successful; the acid gas
disposal well drilled by Birchcliff is capable of handling the volumes
of acid gas to be produced at the plant and complies with all regulatory
requirements; there is sufficient labour, services and equipment
available; Birchcliff will have access to sufficient capital to fund the
Elmworth Gas Plant; and commodity prices and general economic conditions
warrant proceeding with the construction of the Elmworth Gas Plant and
the drilling of associated wells.

/T/

Petrolia Reaches an Agreement with the Government of Quebec Concerning Anticosti

August 10, 2017 by The Canadian Press

FOR: PETROLIA INC.
TSX VENTURE SYMBOL: PEA

Date issue: August 10, 2017
Time in: 3:17 PM e

Attention:

QUEBEC CITY, QUEBEC–(Marketwired – Aug. 10, 2017) – Petrolia Inc. (TSX
VENTURE:PEA ) announces that company reached an agreement in principle with the
Government of Quebec to put an end to the work program planned on the Anticosti
Island.

The Government of Quebec and Petrolia signed, on August 9, 2017, an agreement
in principle concerning the cessation of oil & gas exploration and development
activities on Anticosti Island. The cessation of work, the end of the
exploration program, as well as the termination of the operator contract held
by Petrolia Anticosti were negotiated in return for a $20.5 million financial
compensation for Petrolia, which holds a 21.7% interest in the Anticosti
project.

It may be noted that on April 1, 2014, the company announced the closing of the
transaction that enabled the creation of a limited partnership (HASEC) whose
mandate was to operate the licences previously held by Petrolia and Corridor
Resources. Agreements resulting from this transaction had entrusted Petrolia
Anticosti, a Petrolia Inc. subsidiary, with the role of Anticosti project
operator.

“Although we are deeply disappointed with this turn of events, as we are still
convinced, even more so than in 2014, of the potential of the Anticosti, it’s
now the time to turn the page. The ongoing merger with Pieridae, as well as the
Bourque project, allows us to look forward to the future,” said Petrolia’s
Interim Chief Executive Officer, Mr. Martin Belanger.

The agreement in principle is subject to the signing of definitive agreements
in the coming weeks. These definitive agreements will be subject, notably, to a
vote by Ressources Quebec of 100% of its Petrolia shares in favour of the
proposed arrangement with Pieridae Energy Limited (the “Arrangement”) as well
as the signing by Ressources Quebec of the support and pooling agreements and
the same escrow agreement as the other Petrolia insiders.

About Petrolia

Petrolia is a junior oil and gas exploration company that is a leader in Quebec
oil and gas prospection and its vision is to develop hydrocarbons, by people
here, for here. The social and environmental dimensions are a major concern of
Petrolia and its exploration process. Petrolia has 108,399,683 shares issued
and outstanding.

Disclaimer

Certain statements made herein may constitute forward-looking statements. These
statements relate to future events or the future economic performance of
Petrolia and carry known and unknown risks, uncertainties and other factors
that may appreciably affect their results, economic performance or
accomplishments when considered in light of the content or implications or
statements made by Petrolia. Actual events or results could be significantly
different. Accordingly, investors should not place undue reliance on
forward-looking statements. Petrolia disclaims any intention or obligation to
update these forward-looking statements.

Neither the TSX Venture Exchange nor its regulation services provider (as that
term is defined in the policies of the TSX Venture Exchange) accepts
responsibility for the adequacy or accuracy of this release.

– END RELEASE – 10/08/2017

For further information:
Petrolia Inc.
Martin Belanger, P. Eng.
Interim President and Chief Executive Officer
418 657-1966
www.Petrolia-inc.com

COMPANY:
FOR: PETROLIA INC.
TSX VENTURE SYMBOL: PEA

INDUSTRY: Energy and Utilities – Oil and Gas
RELEASE ID: 20170810CC0051

Press Release from Marketwired 1-866-736-3779

Five Things World Business Will be Talking About Today

August 10, 2017 by EnergyNow Media

August 10, 2017 (Bloomberg) U.S. allies add to Korea warnings, risk-off mood continues in markets, and Glencore gets ready for a shopping trip. Here are some of the things people in markets are talking about today. North Korea warnings Japan and South Korea said that Pyongyang would face a strong response if it followed through on a threat … Read more

Crude Rises Above $50 After OPEC Boosts Oil Demand Outlook

August 10, 2017August 10, 2017 by EnergyNow Media

August 10, 2017 (Bloomberg) Oil climbed above $50 a barrel in New York after OPEC boosted estimates of demand for its crude amid stronger-than-expected fuel consumption and a weaker outlook for rival supply. Futures advanced 1 percent after climbing 0.8 percent Wednesday as the Organization of Petroleum Exporting Countries raised forecasts for the amount it needs … Read more

Petrus Resources Announces Second Quarter 2017 Financial and Operating Results

August 10, 2017 by The Canadian Press

FOR: PETRUS RESOURCES LTD.
TSX SYMBOL: PRQ

Date issue: August 10, 2017
Time in: 6:00 AM e

Attention:

CALGARY, ALBERTA–(Marketwired – Aug. 10, 2017) – Petrus Resources Ltd.
(“Petrus” or the “Company”) (TSX:PRQ) is pleased to report financial and
operating results for the second quarter of 2017. Petrus is focused on organic
growth and infrastructure control in its core area, Ferrier, Alberta. The
Company is targeting liquids rich natural gas in the Cardium formation as well
as investing in infrastructure in Ferrier to control operations and maximize
the Company’s return on investment. The Company’s Management’s Discussion and
Analysis (“MD&A”) and interim consolidated financial statements dated as at and
for the period ended June 30, 2017 are available on SEDAR (the System for
Electronic Document Analysis and Retrieval) at www.sedar.com.

/T/

— Petrus generated funds flow of $12.5 million in the second quarter of

2017, a 63% increase relative to the $7.7 million generated in the
second quarter of 2016. The second quarter marked a milestone for the
Company as its first fiscal quarter to exceed production of 10,000
boe/d. The 63% increase in funds flow is attributed to 21% higher
production, 28% lower operating expenses (on a per boe basis) and
improved commodity prices. This production growth and lower cost
structure reflects the Company’s strategic shift to focus on
developmental drilling, including facility ownership and control in the
Ferrier area, and divest non-core assets.

— Petrus’ second quarter funds flow of $12.5 million is 6% higher than the

$11.7 million generated in the first quarter of 2017. Production
increased by 10% since the prior quarter which is attributed to the
Company’s drilling program in the Ferrier area. During the second
quarter, Petrus recognized two non-routine reductions to funds flow; a
$0.8 million decommissioning expenditure as well as a $0.9 million
royalty adjustment related to its Gas Cost Allowance.

— Petrus reduced its net debt by 10% from the second quarter of 2016 to

the second quarter of 2017, including a $15 million reduction in the
Company’s second lien term loan, from $50 million to $35 million. Net
debt to funds flow(2)was 2.7 times for the second quarter of 2017 and
has decreased 45% since the second quarter of 2016. The Company
continues to focus on decreasing its leverage and is targeting net debt
to funds flow(2)of less than 2.3 times by the end of 2017(1).

— Second quarter average production was 10,240 boe/d in 2017 compared to

8,435 boe/d in 2016. The 21% increase is attributable to the Company’s
drilling program at Ferrier, where production has grown 98% since the
second quarter of 2016.

— In the second quarter of 2017, 3 gross (2.2 net) wells were drilled in

the Ferrier area. All new wells are now on production and have
contributed to the 10% increased production since the first quarter of
2017. Due to facility constraints, Petrus’ current productive capability
in the Ferrier area is higher than the Company’s current production.
These facility constraints are expected to be alleviated later in 2017
with the expansion of the Company’s gas processing facilities.

— Petrus has transformed its operating cost structure through the

construction of a natural gas processing plant in Ferrier and the
divestiture of higher cost assets. As a result, total operating expenses
have decreased 28% from $7.65 per boe in the second quarter of 2016 to
$5.53 per boe in the second quarter of 2017. Due to facility
constraints, a portion of the Company’s Ferrier production is currently
being processed through third party facilities. Ferrier operating
expenses are expected to decrease once the Ferrier gas plant expansion
is complete which is scheduled for the fourth quarter of 2017(1).

— Petrus utilizes financial derivative contracts to mitigate commodity

price risk. The Company’s realized gain on financial derivatives in the
second quarter of 2017 increased the Company’s corporate netback(2)by
$0.23 per boe. As a percentage of second quarter 2017 production, Petrus
has derivative contracts in place for 60% and 54% of its natural gas and
oil & natural gas liquids production, respectively, for the remainder of
fiscal 2017.

(1) Refer to “Advisories – Forward Looking Statements” attached hereto.
(2) Refer to “Non-GAAP Financial Measures” in the Management’s Discussion &

Analysis as at and for the three and six months ended June 30, 2017.

/T/

SELECTED FINANCIAL INFORMATION

/T/

Three Three Three Three Three
months months months months months
OPERATIONS ended ended ended ended ended
Jun. 30, Jun. 30, Mar. 31, Dec. 31, Sept. 30,
2017 2016 2017 2016 2016
—————————————————————————-
Average
Production
Natural gas
(mcf/d) 42,392 33,071 40,332 37,327 30,009
Oil (bbl/d) 2,015 2,200 1,542 1,452 1,419
NGLs (bbl/d) 1,160 723 1,067 922 680
—————————————————————————-
Total (boe/d) 10,240 8,435 9,331 8,595 7,100
Total (boe) 931,821 767,585 839,746 790,806 653,215
—————————————————————————-
Natural gas
sales
weighting 69% 65% 72% 72% 70%
—————————————————————————-
Realized Prices
Natural gas
($/mcf) 3.29 1.64 2.85 3.29 2.53
Oil ($/bbl) 59.02 46.68 62.62 59.42 44.50
NGLs ($/bbl) 30.32 8.47 33.18 24.56 15.56
—————————————————————————-
Total realized
price ($/boe) 28.69 19.32 26.48 26.97 21.06
—————————————————————————-
Royalty income 0.03 0.12 0.05 0.10 0.07
Royalty expense (4.62) (2.26) (3.94) (3.52) (2.99)
—————————————————————————-
Net oil and
natural gas
revenue ($/boe) 24.10 17.18 22.59 23.55 18.14
—————————————————————————-
Operating
expense (5.53) (7.65) (4.50) (3.63) (6.04)
Transportation
expense (1.32) (1.30) (1.38) (1.50) (1.49)
—————————————————————————-
Operating
netback (1)(2)
($/boe) 17.25 8.23 16.71 18.42 10.61
—————————————————————————-
Realized gain
on derivatives
($/boe) (2) 0.23 6.87 0.57 0.99 4.06
General &
administrative
expense (1.12) (1.86) (1.05) (3.78) (1.69)
Cash finance
expense (1.94) (3.18) (2.07) (2.58) (3.85)
Decommissioning
expenditures
(3) (1.03) (0.10) (0.19) (0.64) (0.04)
—————————————————————————-
Corporate
netback (1)(2)
($/boe) 13.39 9.96 13.97 12.41 9.09
—————————————————————————-
—————————————————————————-
FINANCIAL (000s Three Three Three Three Three
except per months months months months months
share) ended ended ended ended ended
Jun. 30, Jun. 30, Mar. 31, Dec. 31, Sept. 30,
2017 2016 2017 2016 2016
—————————————————————————-
Oil and natural
gas revenue 26,753 14,926 22,274 21,409 13,805
Net income (loss) (781) (46,334) 7,311 (11,842) (4,702)
Net income (loss)
per share
Basic (0.02) (1.02) 0.16 (0.26) (0.10)
Fully diluted (0.02) (1.02) 0.16 (0.26) (0.10)
Funds flow (3) 12,458 7,652 11,732 9,809 5,938
Funds flow per
share (3)
Basic 0.25 0.17 0.25 0.22 0.13
Fully diluted 0.25 0.17 0.25 0.22 0.13
Capital
expenditures 18,903 2,712 18,907 10,026 7,231
Net acquisitions
(dispositions) – – 8,818 – (29,718)
Weighted average
shares
outstanding
Basic 49,428 45,349 46,754 45,349 45,349
Fully diluted 49,428 45,349 46,989 45,349 45,349
As at period end
Common shares
outstanding
Basic 49,428 45,349 49,428 45,349 45,349
Fully diluted 49,428 45,349 52,664 45,349 45,349
Total assets 465,794 493,535 460,095 439,967 448,404
Non-current
liabilities 170,580 225,962 165,104 118,934 169,714
Net debt (1) 137,069 152,935 130,624 124,915 124,310
—————————————————————————-
—————————————————————————-
(1) Refer to “Non-GAAP Financial Measures” in the Management’s Discussion &
Analysis as at and for the three and six months ended June 30, 2017.
(2) In prior periods Petrus included realized gain on derivatives (hedging
gain (loss)) in the calculation of operating netback. The amount is
included in the calculation of corporate netback. The comparative
information has been re-classified to conform to current presentation.
(3) In prior periods Petrus excluded decommissioning expenditures from the
calculation of funds flow. The comparative information has been re-
classified to conform to current presentation.

/T/

OPERATIONS UPDATE

Production

Average second quarter production by area was as follows:

/T/

Average production for the
three months ended June 30, Central
2017 Ferrier Foothills Alberta Total
—————————————————————————-
Natural gas (mcf/d) 27,803 7,025 7,564 42,392
Oil (bbl/d) 1,288 252 475 2,015
NGLs (bbl/d) 953 18 189 1,160
—————————————————————————-
Total (boe/d) 6,875 1,441 1,924 10,240
—————————————————————————-
Natural gas sales weighting 67% 81% 66% 69%
—————————————————————————-

/T/

Second quarter average production was 10,240 boe/d (69% natural gas) in 2017
compared to 8,435 boe/d (65% natural gas) in the 2016. The 21% increase is
attributable to the Company’s drilling program at Ferrier, where production has
grown 98% since the second quarter of 2016. The second quarter marked a
milestone for the Company as its first fiscal quarter to exceed production of
10,000 boe/d.

The Company’s natural gas sales weighting was higher in the second quarter of
2017 relative to the second quarter of 2016 due to the divestiture of the Peace
River assets in 2016, and the timing of its Ferrier development.

In the second quarter of 2017, 3 gross (2.2 net) wells were drilled in the
Ferrier area. Each of those wells came on production during the second quarter.

Capital Development

Petrus’ Board of Directors approved a $50 to $60 million capital budget for
2017 (excluding acquisitions and dispositions) which provides for the drilling
of 16 gross (11.7 net) Cardium wells in the Ferrier area. The Company’s 2017
capital program also provides for investment in facilities. Petrus expects the
processing and compression capability of the Ferrier gas plant to double,
reaching a capacity of approximately 60 mmcf/d by the fourth quarter of 2017.(1)

Credit Review

On May 31, 2017 Petrus completed the annual review of its revolving credit
facility (“RCF”). The RCF syndicate of lenders unanimously agreed to increase
the borrowing base from $106 million to $120 million. Lender consent from the
RCF syndicate as well as the second lien term loan lender, is required for
total borrowings against the RCF exceeding $106 million.

/T/

(1) Refer to “Advisories – Forward Looking Statements” attached hereto.

/T/

An updated corporate presentation can be found on the Company’s website at
www.petrusresources.com.

ADVISORIES

Basis of Presentation

Financial data presented above has largely been derived from the Company’s
financial statements, prepared in accordance with GAAP which require publicly
accountable enterprises to prepare their financial statements using IFRS.
Accounting policies adopted by the Company are set out in the notes to the
audited financial statements as at and for the twelve months ended December 31,
2016. The reporting and the measurement currency is the Canadian dollar. All
financial information is expressed in Canadian dollars, unless otherwise stated.

Forward Looking Statements

Certain information regarding Petrus set forth in this news release contains
forward-looking statements within the meaning of applicable securities law,
that involve substantial known and unknown risks and uncertainties. The use of
any of the words “anticipate”, “continue”, “estimate”, “expect”, “may”, “will”,
“project”, “should”, “believe” and similar expressions are intended to identify
forward-looking statements. Such statements represent Petrus’ internal
projections, estimates or beliefs concerning, among other things, an outlook on
the estimated amounts and timing of capital investment, anticipated future
debt, production, revenues or other expectations, beliefs, plans, objectives,
assumptions, intentions or statements about future events or performance,
including targets for debt to funds flow. These statements are only predictions
and actual events or results may differ materially. Although Petrus believes
that the expectations reflected in the forward-looking statements are
reasonable, it cannot guarantee future results, levels of activity, performance
or achievement since such expectations are inherently subject to significant
business, economic, competitive, political and social uncertainties and
contingencies. Many factors could cause Petrus’ actual results to differ
materially from those expressed or implied in any forward-looking statements
made by, or on behalf of, Petrus.

In particular, forward-looking statements included in this news release
include, but are not limited to, statements with respect to: the availability
of cash flows from operating activities; expected timing of completion of the
expansion of the Ferrier gas plant and the resulting processing and compression
capacity at the Ferrier gas plant and expectations of decreased operating
expense; sources of financing and the requirement therefor; the growth of
Petrus and the availability of the full amount of the revolving credit
facility; the treatment of the revolving credit facility following the end of
the revolving period; Petrus’ ability to fund its financial liabilities; the
size of, and future net revenues from, crude oil, NGL (natural gas liquids) and
natural gas reserves; future prospects; the focus of and timing of capital
expenditures; expectations regarding the timing for bringing new wells on
production; expectations regarding the ability to raise capital and to
continually add to reserves through acquisitions and development; access to
debt and equity markets; projections of market prices and costs; the
performance characteristics of the Company’s crude oil, NGL and natural gas
properties including estimated production; crude oil, NGL and natural gas
production levels and product mix; Petrus’ future operating and financial
results; capital investment programs; supply and demand for crude oil, NGL and
natural gas; future royalty rates; drilling, development and completion plans
and the results therefrom; and treatment under governmental regulatory regimes
and tax laws. In addition, statements relating to “reserves” are deemed to be
forward-looking statements, as they involve the implied assessment, based on
certain estimates and assumptions, that the reserves described can be
profitably produced in the future.

These forward-looking statements are subject to numerous risks and
uncertainties, most of which are beyond the Company’s control, including the
impact of general economic conditions; volatility in market prices for crude
oil, NGL and natural gas; industry conditions; currency fluctuation;
imprecision of reserve estimates; liabilities inherent in crude oil and natural
gas operations; environmental risks; incorrect assessments of the value of
acquisitions and exploration and development programs; competition; the lack of
availability of qualified personnel or management; changes in income tax laws
or changes in tax laws and incentive programs relating to the oil and gas
industry; hazards such as fire, explosion, blowouts, cratering, and spills,
each of which could result in substantial damage to wells, production
facilities, other property and the environment or in personal injury; stock
market volatility; ability to access sufficient capital from internal and
external sources; completion of the financing on the timing planned and the
receipt of applicable approvals; and the other risks. With respect to
forward-looking statements contained in this news release, Petrus has made
assumptions regarding: future commodity prices and royalty regimes;
availability of skilled labour; timing and amount of capital expenditures;
future exchange rates; the impact of increasing competition; conditions in
general economic and financial markets; availability of drilling and related
equipment and services; effects of regulation by governmental agencies; and
future operating costs. Management has included the above summary of
assumptions and risks related to forward-looking information provided in this
news release in order to provide shareholders with a more complete perspective
on Petrus’ future operations and such information may not be appropriate for
other purposes. Petrus’ actual results, performance or achievement could differ
materially from those expressed in, or implied by, these forward-looking
statements and, accordingly, no assurance can be given that any of the events
anticipated by the forward-looking statements will transpire or occur, or if
any of them do so, what benefits that the Company will derive therefrom.
Readers are cautioned that the foregoing lists of factors are not exhaustive.

These forward-looking statements are made as of the date of this news release
and the Company disclaims any intent or obligation to update any
forward-looking statements, whether as a result of new information, future
events or results or otherwise, other than as required by applicable securities
laws.

BOE Presentation

The oil & gas industry commonly expresses production volumes and reserves on a
barrel of oil equivalent (“boe”) basis whereby natural gas volumes are
converted at the ratio of six thousand cubic feet to one barrel of oil. The
intention is to sum oil and natural gas measurement units into one basis for
improved measurement of results and comparisons with other industry
participants. Petrus uses the 6:1 boe measure which is the approximate energy
equivalency of the two commodities at the burner tip. Boe’s do not represent an
economic value equivalency at the wellhead and therefore may be a misleading
measure if used in isolation.

/T/

Abbreviations
000’s thousand dollars
$/bbl dollars per barrel
$/boe dollars per barrel of oil equivalent
$/GJ dollars per gigajoule
$/mcf dollars per thousand cubic feet
bbl barrel
bbl/d barrels per day
boe barrel of oil equivalent
boe/d barrel of oil equivalent per day
GJ gigajoule
GJ/d gigajoules per day
mcf thousand cubic feet
mcf/d thousand cubic feet per day
mmcf/d million cubic feet per day
NGLs natural gas liquids
WTI West Texas Intermediate

/T/

– END RELEASE – 10/08/2017

For further information:
Petrus Resources Ltd.
Neil Korchinski, P.Eng.
President and Chief Executive Officer
403-930-0889
nkorchinski@petrusresources.com

COMPANY:
FOR: PETRUS RESOURCES LTD.
TSX SYMBOL: PRQ

INDUSTRY: Energy and Utilities – Oil and Gas
RELEASE ID: 20170810CC0002

Press Release from Marketwired 1-866-736-3779

B.C. government to make announcement about Trans Mountain pipeline expansion

August 10, 2017August 9, 2017 by The Canadian Press

Fraser Institute News Release - Pipelines 2 times safer than rail for oil transportation tankers have safest record of all

VANCOUVER — Two key British Columbia cabinet ministers are expected to outline the government’s next steps Thursday on the Trans Mountain pipeline expansion after campaigning against the project.

No details have been provided about the announcement by Attorney General David Eby and Environment Minister George Heyman, but the future of the $7.4-billion project has been heavily scrutinized since the NDP government came to power.

Premier John Horgan promised on the campaign trail earlier this year to use “every tool in the toolbox” to stop the project, but a mandate letter to the Heyman softened the language, saying instead that he must “defend B.C.’s interests in the face of” the expansion.

Last month Eby said the province would not artificially delay permits for the project, because doing so would risk a costly lawsuit from proponent Trans Mountain, a subsidiary of Kinder Morgan Canada.

Several First Nations and municipalities have filed legal challenges against the expansion, which would triple the capacity of the Alberta-to-B.C. pipeline and increase the number of tankers in Vancouver-area waters seven-fold.

The project has been approved by Ottawa and the province’s former Liberal government.

Trans Mountain says construction is set to begin in September.

The Canadian Press

Essential Energy Services Announces Second Quarter Financial Results and Revised Capital Spending Forecast

August 9, 2017 by The Canadian Press

FOR: ESSENTIAL ENERGY SERVICES LTD.
TSX SYMBOL: ESN

Date issue: August 09, 2017
Time in: 10:14 PM e

Attention:

CALGARY, ALBERTA–(Marketwired – Aug. 9, 2017) – Essential Energy Services Ltd.
(TSX:ESN) (“Essential” or the “Company”) announces second quarter results.

SELECTED INFORMATION

/T/

—————————————————————————
—————————————————————————
(in thousands of
dollars except per
share, Three months ended June 30, Six months ended June 30,
percentages, hours 2017 2016 2017 2016
and fleet data)
—————————————————————————

Revenue $ 27,645 $ 11,915 $ 83,895 $ 38,471

Gross margin 1,484 (1,578) 15,878 (260)
Gross margin % 5% (13%) 19% (1%)

EBITDAS(1) from
continuing
operations (1,291) (4,224) 8,915 (6,426)

Net loss from
continuing
operations (5,005) (7,159) (1,525) (49,537)
Per share – basic
and diluted (0.04) (0.06) (0.01) (0.39)

Net loss (5,005) (7,486) (1,855) (61,404)
Per share – basic
and diluted (0.04) (0.06) (0.01) (0.49)

Operating hours
Coil tubing rigs 7,039 3,848 23,459 13,525
Pumpers 9,529 4,336 28,182 14,554
—————————————————————————
—————————————————————————

As at
June 30,
2017 2016
—————————————————————————
Total assets(i) $ 208,337 $ 238,450
Long-term debt 13,337 26,894

Equipment fleet(ii)
Coil tubing rigs 31 26
Pumpers 31 30
—————————————————————————
—————————————————————————

i. Total assets as at June 30, 2016 include the service rig business which

was sold in December 2016.
ii. Fleet data represents the number of units at the end of the period.

/T/

(1) Refer to “Non-IFRS Measures” section for further information.

HIGHLIGHTS

Essential’s revenue for the second quarter 2017 was $27.6 million, a
significant increase from 2016 as stronger customer demand contributed to
increases for both Essential Coil Well Service (“ECWS”) and Tryton. EBITDAS(1)
was negative $1.3 million, a $2.9 million improvement from the second quarter
2016. The higher revenue was partially offset by incremental repairs and
maintenance costs incurred by ECWS to ready equipment for the second half of
2017. While the financial results were better than the prior year period, they
are still reflective of the second quarter being seasonally slow due to spring
break-up.

Key operating highlights include:

/T/

— Operating hours in ECWS were the highest for a second quarter since

2014. The Generation III coil tubing rigs continued to be in high demand
with operating hours increasing 344% compared to the prior year period.
— Tryton reported increased revenue in all service lines compared to the
prior year period and demand was particularly strong for the Canadian
Multi-Stage Fracturing System(R) (“MSFS(R)”).

/T/

For the six months ended June 30, 2017 Essential reported revenue of $83.9
million, a 118% improvement from the first six months of 2016. EBITDAS(1) was
$8.9 million, $15.3 million higher than the prior year period.

Essential continues to have a strong balance sheet with debt outstanding at
June 30, 2017 of $13.3 million and $12.3 million outstanding at August 9, 2017.
The Company’s funded debt(1) to bank EBITDA(1) was 0.57x at June 30, 2017.

Essential increased its capital forecast from $16 million to $23 million. The
additional capital is for the purchase of two quintuplex fluid pumpers and
additional rental drill pipe. Customer well programs are focused on complex
long-reach horizontal wells requiring higher capacity fluid pumpers to support
the deeper coil tubing rigs.

COMPARATIVE FIGURES

The sale of Essential’s service rig business in December 2016 was reported as a
discontinued operation, with the three and six months ended June 30, 2016
comparative figures restated to this same basis of accounting and disclosure.

RESULTS OF OPERATIONS

Segment Results – Essential Coil Well Service

/T/

—————————————————————————-
—————————————————————————-
(in thousands of
dollars, Three months ended June 30, Six months ended June 30,
except 2017 2016 2017 2016
percentages,
hours and fleet
data)
—————————————————————————-

Revenue $ 14,569 $ 6,422 $ 43,288 $ 22,178

Operating expenses 14,904 7,463 36,258 21,638
—————————————————————————-

Gross margin $ (335) $ (1,041) $ 7,030 $ 540
Gross margin % (2%) (16%) 16% 2%
—————————————————————————-
—————————————————————————-

Operating hours
Coil tubing rigs 7,039 3,848 23,459 13,525
Pumpers 9,529 4,336 28,182 14,554

Equipment fleet(i)
Coil tubing rigs

(ii) 31 26 31 26
Fluid pumpers
(ii)(iii) 20 18 20 18
Nitrogen
pumpers(ii) 11 12 11 12
—————————————————————————-
—————————————————————————-

i. Fleet data represents the number of units at the end of the period.
ii. During the fourth quarter 2016, Essential acquired four Generation III

coil tubing rigs, three quintuplex fluid pumpers and one nitrogen
pumper.
iii. During the second quarter 2017, Essential retired one single fluid
pumper.

/T/

ECWS revenue was $14.6 million, a 127% increase compared to the three months
ended June 30, 2016, due to improved activity by key customers. Prior to the
second quarter, which is typically slow due to spring breakup conditions, ECWS
strategically positioned equipment on customer locations allowing some work to
continue into April. Activity slowed in May due to wet weather, but picked up
in mid-June.

Essential’s coil tubing and pumping operating hours for the three months ended
June 30, 2017 increased 83% and 120% respectively, compared to the same period
in 2016. Essential’s Generation III coil tubing rigs, twin triplex and
quintuplex fluid pumpers continued to experience strong demand, particularly in
the Montney region of the Western Canadian Sedimentary Basin, meeting customer
requirements for long-reach horizontal wells.

Pricing during the second quarter 2017 was consistent with the first quarter
2017 and improved compared to the second quarter 2016. For the three months
ended June 30, 2017, Essential did not offer discounts that are typical during
spring breakup. Revenue per hour can fluctuate from period to period due to the
mix of work. While revenue per hour remains below 2014, first quarter increases
helped offset rising operating costs, including labour and repairs and
maintenance expenses, which had been reduced in prior years as part of cost
reduction initiatives.

Second quarter 2017 gross margin as a percentage of revenue improved from the
second quarter 2016 as fixed costs comprised a smaller proportion of revenue.
While gross margin benefited from increased completion activity, ECWS incurred
incremental costs for repairs and maintenance to ready equipment for the second
half of 2017. In comparison, in the second quarter 2016, slow industry activity
and cost control measures resulted in only nominal repairs and maintenance
spending.

On a year-to-date basis, ECWS revenue was $43.3 million, $21.1 million higher
than the prior period due to higher oilfield service activity. Gross margin as
a percentage of revenue for the six months ended June 30, 2017 was 16%, a
significant improvement over the prior period. Gross margin improvement was due
to increased revenue, reduced variable costs due to operating efficiencies
associated with close proximity of well locations and pad work, and fixed costs
comprising a smaller percentage of a larger revenue base.

Segment Results – Tryton

/T/

—————————————————————————-
—————————————————————————-

Three months ended June 30, Six months ended June 30,
(in thousands of 2017 2016 2017 2016
dollars, except
percentages)
—————————————————————————-

Revenue $ 13,076 $ 5,583 $ 40,607 $ 16,472

Operating expenses 10,736 5,472 30,791 15,185
—————————————————————————-

Gross margin $ 2,340 $ 111 $ 9,816 $ 1,287
Gross margin % 18% 2% 24% 8%

Tryton revenue – %
of revenue
Tryton MSFS(R) 42% 15% 53% 32%
Conventional Tools
& Rentals 58% 85% 47% 68%
—————————————————————————-
—————————————————————————-

/T/

Tryton second quarter 2017 revenue was $13.1 million, a 134% increase from the
same period in 2016 with each service line experiencing higher activity.
Canadian MSFS(R) was particularly strong due to demand, primarily in the
Montney region, for completion of long-reach horizontal wells. Conventional
tools activity was also significantly higher than the prior year period due to
increased maintenance work on producing wells and abandonment work. Pricing
remained consistent with the first quarter 2017 as market competitiveness
limited the ability to implement price increases.

On a year-to-date basis, Tryton revenue increased $24.1 million compared to the
prior year period due to increased activity. A significant portion of the
year-over-year increase is attributed to MSFS(R) revenue due to strong demand
by key customers for their horizontal drilling and completion programs.

Gross margin improved for the three and six months ended June 30, 2017 compared
to the same prior year periods, as fixed costs represented a smaller portion of
a greater revenue base.

FINANCIAL RESOURCES AND LIQUIDITY

Credit Facility

Essential’s credit facility is comprised of a $40 million revolving term loan
facility with a $20 million accordion feature available at the lender’s consent
(the “Credit Facility”). The Credit Facility was renewed on June 15, 2016 and
matures on May 31, 2019. It is renewable at the lender’s consent and is secured
by a general security agreement over the Company’s assets. To the extent the
Credit Facility is not renewed, the balance becomes immediately due and payable
on the maturity date. At June 30, 2017, the maximum of $40 million under the
Credit Facility was available to Essential.

The Credit Facility includes an equity cure provision where proceeds from
equity offerings may be applied to the calculation of Bank EBITDA(1) in the
funded debt(1) to Bank EBITDA(1) covenant and the fixed charge coverage(1)
covenant. In October 2016, Essential received gross proceeds of $10.4 million
for 16,019,883 shares issued at $0.65 per share from an equity offering that
the Company applied as an equity cure to its fourth quarter 2016 Bank EBITDA(1)
calculation under the Credit Facility. Due to the trailing 12 month nature of
the covenants, the proceeds from the equity offering increase Bank EBITDA(1)
for the first, second and third quarter 2017 covenants as well.

As at June 30, 2017 all financial debt covenants and banking requirements under
the Credit Facility were satisfied.

Essential does not anticipate financial resource or liquidity issues to
restrict its future operating, investing or financing activities. On August 9,
2017, Essential had $12.3 million of debt outstanding.

Equipment Expenditures

/T/

—————————————————————————
—————————————————————————

Three months ended June 30, Six months ended June 30,
(in thousands of 2017 2016 2017 2016
dollars)
—————————————————————————

Essential Coil
Well Service $ 4,071 $ 2,828 $ 8,359 $ 6,034
Tryton 317 1,282 1,831 1,369
Corporate 203 4 238 34
—————————————————————————
Total equipment
expenditures 4,591 4,114 10,428 7,437
—————————————————————————

Less proceeds on
disposal of
property and
equipment (309) (1,135) (615) (1,546)
—————————————————————————

Net equipment
expenditures(1) $ 4,282 $ 2,979 $ 9,813 $ 5,891
—————————————————————————
—————————————————————————

Essential classifies its equipment expenditures as growth
capital(1) and maintenance capital(1):
—————————————————————————
—————————————————————————

Three months ended June 30, Six months ended June 30,
(in thousands of
dollars) 2017 2016 2017 2016
—————————————————————————

Growth capital(1) $ 2,492 $ 3,099 $ 6,346 $ 5,299
Maintenance
capital(1) 2,099 1,015 4,082 2,138
—————————————————————————
Total equipment
expenditures $ 4,591 $ 4,114 $ 10,428 $ 7,437
—————————————————————————
—————————————————————————

/T/

Capital Spending Forecast

Essential’s 2017 capital forecast increased from $16 million to $23 million and
is comprised of $12 million of growth capital and $11 million of maintenance
capital. The $6 million increase in growth capital consists of two new
quintuplex fluid pumpers and additional rental drill pipe. The fluid pumpers
will support Essential’s deep coil tubing fleet working on long-reach
horizontal wells where greater pumping capacity is required due to the depths
and pressures of these wells. The new pumpers are expected to be available for
service in early 2018.

PATENT LITIGATION

On October 23, 2013, Packers Plus Energy Services Inc. (“Packers Plus”) filed a
Statement of Claim in Canada’s Federal Court (the “Court”) against Essential
alleging that certain products and methods associated with the Tryton MSFS(R)
infringe on a patent issued to Packers Plus (the “Packers Plus Claim”). Packers
Plus subsequently limited its infringement allegations to just certain method
claims in the patent.

Essential believes the Packers Plus Claim is without merit and filed a
Statement of Defence and Counterclaim on November 22, 2013. The Statement of
Defence denies infringement and the Counterclaim pleads further that the patent
is invalid because the methodology and equipment claimed in the patent were in
use in the oil and natural gas industry prior to the patent’s effective filing
date of November 19, 2001 or represent nothing more than obvious variations
over what was already known in the industry at the time. This position is
supported by the existence of similar products, articles and other patents
prior to the effective filing date of the patent.

The trial was completed in March 2017. There were two parts to the trial:

/T/

— Validity – The validity portion of the trial focused on whether or not

the patent is valid. Given the fact that Packers Plus has asserted
infringement of the same patent against Essential and three other
defendants, Baker Hughes Canada Company, Weatherford Canada Ltd. and
Resource Well Completion Technologies Inc., and all of the defendants
filed counterclaims seeking a declaration that the patent is invalid,
the Court directed that the counterclaims be consolidated into a single
trial (the “Joint Validity Trial”). During the Joint Validity Trial the
four defendants asserted their common position that the patent is
invalid.
— Infringement – The infringement portion of the trial focused on whether
or not Essential has infringed the Packers Plus patent. The infringement
portions of the Baker Hughes Canada Company, Weatherford Canada Ltd. and
Resource Well Completion Technologies Inc. trials were not consolidated
with the infringement portion of the Essential case since each
infringement action, by its nature, deals with tools, designs and
business activities specific to each company.

/T/

The Court is expected to render its decision on both validity and infringement
prior to October 2017. In order for Essential to be found liable for damages,
the Court must find that the Packers Plus patent is both valid and infringed.
If the patent is found to be valid and it is determined that Essential has
infringed, a separate trial will be required to quantify damages (the
“Quantification of Damages Trial”).

Prior to commencement of the validity and infringement trials, the Court
scheduled dates for the Quantification of Damages Trial for Essential and
similar trials for each of the other three defendants, in case such trials are
required. The fact that the Quantification of Damages Trial has been scheduled
does not foreshadow an unfavourable Court decision on patent validity or
infringement. Essential’s potential Quantification of Damages Trial, if
required, is scheduled to commence in January 2018. The Quantification of
Damages Trial will only be required if Essential receives an unfavorable
decision in both its validity and infringement trials.

If the Quantification of Damages Trial is required, the trial will focus on the
damages that Packers Plus alleges that it suffered as a result of sales of the
Tryton MSFS(R) system or, alternatively, the profits that Essential earned from
such system. In determining Packers Plus’ damages or Essential’s profits, the
Court will also hear evidence relating to the ability of Packers Plus to
complete the work performed by Essential, the duty of Packers Plus to mitigate
its losses and Essential’s ability to sell alternative, non-infringing,
products.

Essential continues to believe that the case is without merit. If Essential
were to receive an unfavorable decision in both the validity and infringement
trials, it will appeal such a decision. Factoring in the appeal process and
the time to complete the Quantification of Damages Trial, the implications for
Essential may not be known for up to two more years.

The Packers Plus Claim targets only the Tryton MSFS(R) ball & seat system,
which Essential commenced using in 2009. It does not target past or future
operations of Essential’s conventional tools, other Tryton MSFS(R) tools or the
rentals service line.

OUTLOOK

To date, Essential has seen improved year-over-year results in 2017 compared to
2016. July activity for ECWS and Tryton was much better than July 2016 as
customers continued to invest in completions work. While recent commodity price
volatility has put into question the timing and extent of an industry recovery,
at this point, Essential expects steady activity for the third quarter of 2017.
Due to commodity price uncertainty, Essential does not have a clear outlook on
fourth quarter 2017 activity. It will be contingent on commodity prices and
customer capital programs.

Service pricing is relatively unchanged from the first quarter 2017. Essential
expects pricing discussions with customers to continue but with recent
commodity price volatility, the window for increases may be closing. Essential
believes in the long-term, higher pricing is required to achieve reasonable
margins given increases in labour and repairs and maintenance costs.

ECWS continued with its recruiting program in the second quarter but has slowed
the program in the third quarter. Activity in the third and fourth quarters
will determine the number of incremental employees required.

Essential increased its capital forecast to $23 million, consisting of $12
million for growth capital and $11 million maintenance capital. The growth
capital consists of two quintuplex pumpers, pumping support equipment, the cost
to recertify and upgrade the coil tubing rigs and pumping equipment acquired in
2016 and rental drill pipe assets. $10 million of the forecasted capital was
spent in the first half of 2017.

Essential continues to have a strong balance sheet and believes it is
well-positioned as the western Canadian oil and gas industry continues to
recover. Debt was $13.3 million at June 30, 2017 and funded debt(1) to bank
EBITDA(1) was 0.57x at June 30, 2017.

The Management’s Discussion and Analysis and Financial Statements are available
on Essential’s website at www.essentialenergy.ca and on SEDAR at www.sedar.com.

(1)Non-IFRS Measures

Throughout this news release, certain terms that are not specifically defined
in International Financial Reporting Standards (“IFRS”) are used to analyze
Essential’s operations. In addition to the primary measures of net income
(loss) and net income (loss) per share in accordance with IFRS, Essential
believes that certain measures not recognized under IFRS assist both Essential
and the reader in assessing performance and understanding Essential’s results.
Each of these measures provides the reader with additional insight into
Essential’s ability to fund principal debt repayments and capital programs. As
a result, the method of calculation may not be comparable with other companies.
These measures should not be considered alternatives to net income (loss) and
net income (loss) per share as calculated in accordance with IFRS.

Bank EBITDA – Bank EBITDA is generally defined in Essential’s Credit Facility
as EBITDAS from continuing operations, including the equity cure, excluding
onerous lease contract expense and severance costs.

EBITDAS (Earnings before finance costs, income taxes, depreciation,
amortization, transaction costs, losses or gains on disposal of equipment,
write-down of assets, impairment loss, foreign exchange gains or losses, and
share-based compensation, which includes both equity-settled and cash-settled
transactions) – These adjustments are relevant as they provide another measure
which is considered an indicator of Essential’s results from its principal
business activities.

The following table reconciles Bank EBITDA, EBITDAS from continuing operations,
and EBITDA from continuing operations, to the IFRS measure, net loss from
continuing operations:

/T/

—————————————————————————
—————————————————————————

Three months ended June 30, Six months ended June 30,
(in thousands of 2017 2016 2017 2016
dollars)
—————————————————————————

Bank EBITDA $ (1,272) $ (4,208) $ 8,952 $ (4,677)

Severance costs 19 16 37 1,749
—————————————————————————
EBITDAS from
continuing
operations $ (1,291) $ (4,224) $ 8,915 $ (6,426)

Share-based
compensation 679 188 2,223 715
Other (income)
expense 195 510 170 1,329
—————————————————————————

EBITDA from
continuing
operations $ (2,165) $ (4,922) $ 6,522 $ (8,470)

Depreciation and
amortization 3,881 3,832 7,882 9,768
Impairment loss – – – 45,838
Finance costs 390 381 737 668
—————————————————————————

Loss before
income tax from
continuing
operations $ (6,436) $ (9,135) $ (2,097) $ (64,744)
Total income tax
recovery (1,431) (1,976) (572) (15,207)
—————————————————————————

Net loss from
continuing
operations $ (5,005) $ (7,159) $ (1,525) $ (49,537)
—————————————————————————
—————————————————————————

/T/

Fixed charge coverage ratio – This measure is generally defined in Essential’s
Credit Facility as the ratio of EBITDAS less cash tax expense to the sum of
distributions, scheduled principal repayments and interest expense.

/T/

—————————————————————————
—————————————————————————

Trailing 12 months ended
(in thousands of dollars, except ratios) June 30, 2017
—————————————————————————

Bank EBITDA $ 21,911
Less current income tax recovery (1,863)
—————————————————————————
$ 23,774
Finance costs $ 1,332
—————————————————————————
—————————————————————————
Fixed charge coverage ratio 17.8x
—————————————————————————
—————————————————————————

/T/

Funded debt – Funded debt is generally defined in Essential’s Credit Facility
as long-term debt, including current portion of long-term debt plus deferred
financing costs and bank indebtedness, net of cash.

Growth capital – Growth capital is capital spending which is intended to result
in incremental revenue. Growth capital is considered to be a key measure as it
represents the total expenditures on equipment expected to add incremental
revenue to Essential.

Maintenance capital – Equipment additions that are incurred in order to
refurbish, replace or extend the life of previously acquired equipment. Such
additions do not provide incremental revenue.

Net equipment expenditures – This measure is equipment expenditures less
proceeds on the disposal of equipment. Essential uses net equipment
expenditures to describe net cash outflows related to the financing of
Essential’s capital program.

/T/

ESSENTIAL ENERGY SERVICES LTD.
CONSOLIDATED INTERIM STATEMENTS OF FINANCIAL POSITION
(Unaudited)

—————————————————————————
—————————————————————————

As at As at
June 30, December 31,
(in thousands of dollars) 2017 2016
—————————————————————————

Assets
Current

Cash $ 1,059 $ 143
Trade and other accounts receivable 24,409 29,300
Inventories 30,791 27,077
Income taxes receivable 4,582 8,119
Prepayments and deposits 2,603 1,774
—————————————————————————
63,444 66,413
—————————————————————————
Non-current
Property and equipment 139,606 137,039
Intangible assets 1,725 2,132
Goodwill 3,562 3,686
—————————————————————————
144,893 142,857
—————————————————————————

Total assets $ 208,337 $ 209,270
—————————————————————————
—————————————————————————

Liabilities
Current

Trade and other accounts payable $ 16,656 $ 19,312
Share based compensation 976 689
Current portion of onerous lease
contract 716 612
—————————————————————————
18,348 20,613
—————————————————————————

Non-current

Long-term onerous lease contract 3,788 4,142
Share based compensation 3,423 2,179
Long-term debt 13,337 11,250
Deferred tax liabilities 7,427 7,519
—————————————————————————
27,975 25,090
—————————————————————————

Total liabilities 46,323 45,703
—————————————————————————

Equity

Share capital 272,732 272,732
Deficit (116,457) (114,602)
Other reserves 5,739 5,437
—————————————————————————
Total equity 162,014 163,567
—————————————————————————

Total liabilities and equity $ 208,337 $ 209,270
—————————————————————————
—————————————————————————

ESSENTIAL ENERGY SERVICES LTD.
CONSOLIDATED INTERIM STATEMENTS OF NET LOSS AND COMPREHENSIVE LOSS
(Unaudited)

—————————————————————————
—————————————————————————

For the three months ended For the six months ended
June 30, June 30,
(in thousands of 2017 2016 2017 2016
dollars, except
per share
amounts)
—————————————————————————

Revenue $ 27,645 $ 11,915 $ 83,895 $ 38,471

Operating expenses 26,161 13,493 68,017 38,731
—————————————————————————
Gross margin 1,484 (1,578) 15,878 (260)

General and
administrative
expense 2,775 2,646 6,963 6,166
Depreciation and
amortization 3,881 3,832 7,882 9,768
Share based
compensation 679 188 2,223 715
Impairment loss – – – 45,838
Other expenses 195 510 170 1,329
—————————————————————————
Operating loss
from continuing
operations (6,046) (8,754) (1,360) (64,076)

Finance costs 390 381 737 668
—————————————————————————
Loss before income
taxes from
continuing
operations (6,436) (9,135) (2,097) (64,744)

Current income tax
recovery (1,059) (1,272) (547) (5,464)
Deferred income
tax recovery (372) (704) (25) (9,743)
—————————————————————————
Income tax
recovery (1,431) (1,976) (572) (15,207)
—————————————————————————

Net loss from
continuing
operations (5,005) (7,159) (1,525) (49,537)

Loss from
discontinued
operations, net
of tax – (327) (330) (11,867)
—————————————————————————

Net loss (5,005) (7,486) (1,855) (61,404)
—————————————————————————

Unrealized foreign
exchange gain
(loss) from
continuing
operations 52 (67) 62 (52)
Unrealized foreign
exchange gain
from discontinued
operations – 63 – –
—————————————————————————
Other
comprehensive
income (loss) 52 (4) 62 (52)
—————————————————————————

Comprehensive loss $ (4,953) $ (7,490) $ (1,793) $ (61,456)
—————————————————————————
—————————————————————————

Net loss per share
from continuing
operations
Basic and diluted $ (0.04) $ (0.06) $ (0.01) $ (0.39)

Net loss per share
Basic and diluted $ (0.04) $ (0.06) $ (0.01) $ (0.49)

Comprehensive loss
per share
Basic and diluted $ (0.03) $ (0.06) $ (0.01) $ (0.49)
—————————————————————————
—————————————————————————

ESSENTIAL ENERGY SERVICES LTD.
CONSOLIDATED INTERIM STATEMENTS OF CASH FLOWS
(Unaudited)

—————————————————————————
—————————————————————————

For the six months ended
June 30,
(in thousands of dollars) 2017 2016
—————————————————————————

Operating activities:
Net loss from continuing operations $ (1,525) $ (49,537)

Non-cash adjustments to reconcile net loss
for the period to operating cash flow:

Depreciation and amortization 7,882 9,768
Deferred income tax recovery (25) (9,743)
Share based compensation 240 192
Provision for impairment of trade
accounts receivable 300 754
Finance costs 737 668
Impairment loss – 45,838
(Gain) loss on disposal and write-down
of assets (270) 577
—————————————————————————
Operating cash flow before changes in non-
cash operating working capital 7,339 (1,483)
Changes in non-cash operating working
capital:
Trade and other accounts receivable
before provision 2,102 12,277
Inventories (3,715) 86
Income taxes receivable 3,590 (5,083)
Prepayments and deposits (836) 220
Trade and other accounts payable (297) (3,558)
Onerous lease contract (250) –
Share based compensation 1,531 150
—————————————————————————
Net cash provided by operating activities
from continuing operations 9,464 2,609
—————————————————————————

Investing activities:

Purchase of property, equipment and
intangible assets (10,428) (7,437)
Non-cash investing working capital in
trade and other accounts payable (432) (85)
Proceeds on disposal of equipment 615 1,546
—————————————————————————
Net cash used in investing activities from
continuing operations (10,245) (5,976)
—————————————————————————

Financing activities:

Increase in long-term debt 2,087 1,351
Dividends paid – (755)
Finance costs (737) (668)
—————————————————————————
Net cash provided by (used in) financing
activities from continuing operations 1,350 (72)
—————————————————————————

Foreign exchange gain (loss) on cash held
in a foreign currency 13 (54)
—————————————————————————

Net increase (decrease) in cash 582 (3,493)
Net increase in cash, discontinued
operations 334 2,937
Cash, beginning of period 143 1,042
—————————————————————————

Cash, end of period $ 1,059 $ 486
—————————————————————————
—————————————————————————

Supplemental cash flow information
Cash taxes received $ (4,137) $ (381)
Cash interest and standby fees paid $ 693 $ 514
—————————————————————————
—————————————————————————

/T/

FORWARD-LOOKING STATEMENTS AND INFORMATION

This news release contains “forward-looking statements” and “forward-looking
information” (collectively referred to herein as “forward-looking statements”)
within the meaning of applicable securities legislation. Such forward-looking
statements include, without limitation, forecasts, estimates, expectations and
objectives for future operations that are subject to a number of material
factors, assumptions, risks and uncertainties, many of which are beyond the
control of the Company.

Forward-looking statements are statements that are not historical facts and are
generally, but not always, identified by the words “expects”, “plans”,
“anticipates”, “believes”, “intends”, “estimates”, “continues”, “projects”,
“forecasts”, “potential”, “budget” and similar expressions, or are events or
conditions that “will”, “would”, “may”, “could” or “should” occur or be
achieved. This news release contains forward-looking statements, pertaining to,
among other things, the following: the impact of Essential’s financial
resources or liquidity on its future operating, investing and financing
activities; Essential’s capital forecast and in-service timing; new equipment;
industry recovery and activity; Essential’s activity; pricing discussions;
pricing impact on Essential; Essential’s competitive position and outlook; the
implications of Essential’s strong balance sheet; the Packers Plus Claim; the
Company’s belief that the Packers Plus Claim is without merit and the length of
time it will take to resolve the claim; and the timing and process with regard
to the Quantification of Damages Trial.

Although the Company believes that the material factors, expectations and
assumptions expressed in such forward-looking statements are reasonable based
on information available to it on the date such statements are made, undue
reliance should not be placed on the forward-looking statements because the
Company can give no assurances that such statements and information will prove
to be correct and such statements are not guarantees of future performance.
Since forward-looking statements address future events and conditions, by their
very nature they involve inherent risks and uncertainties.

Actual performance and results could differ materially from those currently
anticipated due to a number of factors and risks. These include, but are not
limited to: known and unknown risks, including those set forth in the Company’s
Annual Information Form (a copy of which can be found under Essential’s profile
on SEDAR at www.sedar.com); the risks associated with the oilfield services
sector (e.g. demand, pricing and terms for oilfield services; current and
expected oil and natural gas prices; exploration and development costs and
delays; reserves discovery and decline rates; pipeline and transportation
capacity; weather, health, safety and environmental risks); integration of
acquisitions, competition, and uncertainties resulting from potential delays or
changes in plans with respect to acquisitions, development projects or capital
expenditures and changes in legislation, including but not limited to tax laws,
royalties, incentive programs and environmental regulations; stock market
volatility and the inability to access sufficient capital from external and
internal sources; the ability of the Company’s subsidiaries to enforce legal
rights in foreign jurisdictions; general economic, market or business
conditions; global economic events; changes to Essential’s financial position
and cash flow; the availability of qualified personnel, management or other key
inputs; currency exchange fluctuations; changes in political and security
stability; risks and uncertainty related to distribution and pipeline
constraints; and other unforeseen conditions which could impact the use of
services supplied by the Company. Accordingly, readers should not place undue
importance or reliance on the forward-looking statements. Readers are cautioned
that the foregoing list of factors is not exhaustive.

Statements, including forward-looking statements, contained in this news
release are made as of the date they are given and the Company disclaims any
intention or obligation to publicly update or revise any forward-looking
statements, whether as a result of new information, future events or otherwise,
unless so required by applicable securities laws. The forward-looking
statements contained in this news release are expressly qualified by this
cautionary statement.

Additional information on these and other factors that could affect the
Company’s operations and financial results are included in reports on file with
applicable securities regulatory authorities and may be accessed under
Essential’s profile on SEDAR at www.sedar.com.

2017 SECOND QUARTER FINANCIAL RESULTS CONFERENCE CALL AND WEBCAST

Essential has scheduled a conference call and webcast at 10:00 am MT (12:00 pm
ET) on August 10, 2017.

The conference call dial in numbers are 416-406-0743 or 800-806-5484, passcode
1593381.

An archived recording of the conference call will be available approximately
one hour after completion of the call until August 23, 2017 by dialing
905-694-9451 or 800-408-3053, passcode 8808485.

A live webcast of the conference call will be accessible on Essential’s website
at www.essentialenergy.ca by selecting “Investors” and “Events and
Presentations”. Shortly after the live webcast, an archived version will be
available for approximately 30 days.

ABOUT ESSENTIAL

Essential provides oilfield services to oil and natural gas producers,
primarily in western Canada. Essential offers completion, production and
abandonment services to a diverse customer base. Services are offered with coil
tubing, fluid and nitrogen pumping and the sale and rental of downhole tools
and equipment. Essential offers the largest coil tubing fleet in Canada.
Further information can be found at www.essentialenergy.ca.

(R) MSFS is a registered trademark of Essential Energy Services Ltd.

The TSX has neither approved nor disapproved the contents of this news release.

– END RELEASE – 09/08/2017

For further information:
Garnet K. Amundson
President and CEO
(403) 513-7272
service@essentialenergy.ca
OR
Karen Perasalo
Investor Relations
(403) 513-7272
service@essentialenergy.ca

COMPANY:
FOR: ESSENTIAL ENERGY SERVICES LTD.
TSX SYMBOL: ESN

INDUSTRY: Energy and Utilities – Equipment, Energy and Utilities –
Oil and Gas
RELEASE ID: 20170809CC0092

Press Release from Marketwired 1-866-736-3779

Aerostar Drone Solutions Showcases New Collision Tolerant Drone for Inspection of Confined Spaces. Check it Out Here

August 9, 2017 by EnergyNow Media

Aerostar wants you to meet Elios, one of our newest drones containing cutting-edge technology! Carrying its own protective carbon-fiber frame, Elios is a collision-tolerant UAV, perfect for inspecting confined spaces without any risk of causing damage to the drone or equipment. Elios excels at inspecting the most inaccessible places, allowing for HD & Thermal Imaging … Read more

Bonterra Energy Corp. Announces Second Quarter 2017 Financial and Operational Results

August 9, 2017 by The Canadian Press

FOR: BONTERRA ENERGY CORP.
TSX SYMBOL: BNE

Date issue: August 09, 2017
Time in: 6:30 PM e

Attention:

CALGARY, ALBERTA–(Marketwired – Aug. 9, 2017) – Bonterra Energy Corp.
(www.bonterraenergy.com) (TSX:BNE) (“Bonterra” or “the Company”) is pleased to
announce its operating and financial results for the three and six months ended
June 30, 2017. The related unaudited condensed financial statements and notes,
as well as management’s discussion and analysis (MD&A), are available on the
System for Electronic Document Analysis and Retrieval (SEDAR) at www.sedar.com
and on Bonterra’s website at www.bonterraenergy.com.

HIGHLIGHTS

/T/

Three months ended Six months ended
As at and for the periods ended
($ 000s except for $ per share June 30, June 30, June 30, June 30,
and $ per BOE) 2017 2016 2017 2016
—————————————————————————-
FINANCIAL
Revenue – realized oil and gas
sales (1) 52,695 41,150 102,025 74,660
Funds flow (1) 28,508 29,765 53,751 46,137
Per share – basic and diluted 0.86 0.90 1.61 1.39
Dividend payout ratio 35% 33% 37% 43%
Cash flow from operations 27,370 13,392 51,910 24,538
Per share – basic and diluted 0.82 0.40 1.56 0.74
Dividend payout ratio 37% 75% 38% 81%
Cash dividends per share 0.30 0.30 0.60 0.60
Net earnings (loss) 2,978 (5,582) 3,453 (17,137)
Per share – basic and diluted 0.09 (0.17) 0.10 (0.52)
Capital expenditures, net of
dispositions 19,416 9,420 49,545 11,103
Total assets 1,173,936 1,169,782
Working capital deficiency 29,759 18,429
Long-term debt 341,070 336,923
Shareholders’ equity 529,844 564,075
—————————————————————————-
OPERATIONS
Oil
-barrels per day 8,287 7,780 7,912 8,052
-average price ($ per
barrel) 58.27 51.64 59.39 44.24
NGLs
-barrels per day 843 877 828 861
-average price ($ per
barrel) 27.48 20.79 29.19 17.81
Natural gas
– MCF per day 24,138 21,771 23,196 22,022
– average price ($ per
MCF) 3.03 1.48 3.00 1.75
Total barrels of oil equivalent
per day (BOE) (2) 13,153 12,285 12,606 12,584
—————————————————————————-
(1Funds flow is not a recognized measure under IFRS. For these purposes,
) the Company defines funds flow as funds provided by operations including
proceeds from sale of investments and investment income received
excluding the effects of changes in non-cash working capital items and
decommissioning expenditures settled.
(2)BOE may be misleading, particularly if used in isolation. A BOE
conversion ratio of 6 MCF: 1 bbl is based on an energy conversion method
primarily applicable at the burner tip and does not represent a value
equivalency at the wellhead.

/T/

Bonterra’s second quarter financial and operating results improved
significantly over the same period in 2016, and were modestly stronger than the
first quarter. The Company’s production averaged 13,153 BOE per day as a result
of sixteen new operated wells being placed on production, compared to only two
new wells in the second quarter of 2016, and five new horizontal wells in the
previous quarter. Bonterra’s first quarter 2017 capital budget had originally
contemplated the completion and tie-in of 14 gross (11.2 net) horizontal wells
but was restricted due to procurement and scheduling challenges with pumping
service providers, and the remaining activity was completed in the second
quarter, positively impacting volumes in Q2 2017.

Despite the expected seasonal impact of spring breakup, Bonterra was able to
maintain its capital program for the first six months of the year by planning
for the development of easily-accessible locations to coincide with spring
breakup. This ability arises due to the Company’s unique and concentrated
infrastructure in the Pembina field which allows for continued drilling,
completion and tying-in new production while other operators are subject to
spring road bans. As a result of the capital deployed and increased activity
level during the quarter, Bonterra increased its production by 1,100 BOE per
day, despite having approximately 420 BOE per day shut-in due to third
party-pipeline restrictions, non-operated facility turnarounds and extended wet
weather conditions.

Q2 and the Six Months Ended June 30, 2017 Highlights

/T/

— Averaged 13,153 BOE per day of production during the quarter, an

increase of nine percent over the previous quarter and seven percent
over the same period in 2016, a direct result of production additions
from sixteen new Cardium wells, but offset by approximately 420 BOE per
day of shut-in volumes;
— Generated funds flow of $28.5 million ($0.86 per share), compared to
$21.2 million ($0.64 per share) in Q2 2016 (before proceeds from the
sale of investments of $8.5 million or $0.26 per share), and $25.2
million ($0.76 per share) in the first quarter of 2017. Funds flow for
the six months ended June 30, 2017 totaled $53.8 million ($1.61 per
share) compared to $37 million ($1.12 per share) for the same period in
2016 (before proceeds on the sale of investments of $9.1 million or
$0.27 per share);
— During the first six months of 2017, Bonterra invested approximately $50
million, of which approximately $38 million was directed to drilling 21
gross operated (19.5 net) horizontal Cardium wells with related
infrastructure costs, and an additional six gross (1.5 net) Cardium non-
operated wells. In addition, the Company completed and tied-in 21 gross
(18.1 net) wells (of which three (1.7 net) wells were drilled in 2016,
but not completed until 2017), and directed $12 million towards
infrastructure and other capital;
— Cash netbacks increased to $23.84 per BOE for the quarter, compared to
$18.76 per BOE in Q2 2016, primarily as a result of increased commodity
prices. Cash netbacks were $23.55 per BOE for the six months ended June
30, 2017, 61 percent higher than the $14.62 per BOE for the same period
in 2016;
— On April 19, 2017 the Company successfully renewed its bank facilities
at $380 million with no material change to terms or conditions; and
— Paid out $0.30 per share in cash dividends to shareholders in the second
quarter ($0.60 per share during the first half of 2017), resulting in a
payout ratio of 35 percent of funds flow (37 percent for first half
2017).

/T/

Following the execution of the Company’s successful capital program in the
first half of 2017, Bonterra had $341 million drawn on its renewed $380 million
credit facility, which continues to provide the Company with sufficient
liquidity and financial flexibility to execute its business plan. The increase
in bank debt of $11 million over the end of the first quarter resulted from the
Company investing greater than 70 percent of its initial 2017 annual capital
budget in the first half of the year, which was compounded by the delays
experienced in bringing on new production from wells drilled in Q1 2017 until
Q2 2017. However, due to the incremental cash flow generated from higher
production in the second quarter, the Company was able to maintain its second
quarter net debt (defined as long-term debt plus working capital deficiency) at
levels comparable to the end of the first quarter.

During the first half of 2017, WTI benchmark crude oil prices increased from
lows of $30.62 US per bbl in February of 2016 to over $50.00 US per barrel into
Q1 2017, but softened somewhat during Q2 2017, averaging $48.28 US per bbl. In
spite of slightly weaker quarter over quarter benchmark commodity prices,
Bonterra has experienced only a mild decline in funds flow in the second
quarter compared to the first quarter due to increased production volumes.

Outlook

As a result of the drilling and completions investment through the first half
of the year, Bonterra expects to maintain its current production levels of
13,000 BOE per day through the balance of 2017. Supported by an inventory of
highly economic, low-risk drilling locations, the Company will continue
pursuing its sustainable growth strategy focused on operational efficiencies,
dividend management and debt reduction, with the goal of delivering attractive
returns for shareholders across a variety of commodity price levels.

The Company averaged 12,606 BOE per day for the first six months of 2017.
During the first quarter of 2017, Bonterra experienced scheduling delays with
pumping service providers which resulted in new production from wells drilled
during Q1 2017 being brought on in Q2 2017. Due to lower-than-anticipated
commodity prices during Q2 2017, and continued price volatility, the Company
has also elected to defer its Q3 2017 drilling program until the latter part of
August. In addition, Bonterra has reduced its annual capital spending budget to
approximately $65 million from its prior guidance of $70 million. Due to the
aforementioned production delays, the deferral of the Q3 2017 drilling program
until later in August, and the reduced capital program, the Company forecasts
that production through the second half of 2017 will average approximately
13,000 to 13,200 BOE per day, which is expected to result in annual production
of approximately 12,900 BOE per day compared to Bonterra’s original 2017
guidance between 13,000 to 13,500 BOE per day.

Bonterra is a low-cost and low production decline producer whose attractive
asset base offers significant exposure to the massive Pembina Cardium pool. The
Company’s large and oil weighted inventory of low-risk, highly economic
undrilled locations supports its sustainable growth plus dividend model across
a variety of commodity price levels, with significant torque to the upside in a
rising oil price environment. The future for Bonterra remains positive and the
Company will continue to manage the business conservatively for the benefit of
shareholders.

Bonterra Energy Corp. is a conventional oil and gas corporation with operations
in Alberta, Saskatchewan and British Columbia. The shares are listed on The
Toronto Stock Exchange under the symbol “BNE”.

Cautionary Statements

This summarized news release should not be considered a suitable source of
information for readers who are unfamiliar with Bonterra Energy Corp. and
should not be considered in any way as a substitute for reading the full
report. For the full report, please go to www.bonterraenergy.com.

Use of Non-IFRS Financial Measures

Throughout this release the Company uses the terms “payout ratio” and “cash
netback” to analyze operating performance, which are not standardized measures
recognized under IFRS and do not have a standardized meaning prescribed by
IFRS. These measures are commonly utilized in the oil and gas industry and are
considered informative by management, shareholders and analysts. These measures
may differ from those made by other companies and accordingly may not be
comparable to such measures as reported by other companies.

The Company calculates payout ratio by dividing cash dividends paid to
shareholders by cash flow from operating activities, both of which are measures
prescribed by IFRS which appear on our statements of cash flows. We calculate
cash netback by dividing various financial statement items as determined by
IFRS by total production for the period on a barrel of oil equivalent basis.

Forward Looking Information

Certain statements contained in this release include statements which contain
words such as “anticipate”, “could”, “should”, “expect”, “seek”, “may”,
“intend”, “likely”, “will”, “believe” and similar expressions, relating to
matters that are not historical facts, and such statements of our beliefs,
intentions and expectations about development, results and events which will or
may occur in the future, constitute “forward-looking information” within the
meaning of applicable Canadian securities legislation and are based on certain
assumptions and analysis made by us derived from our experience and
perceptions. Forward-looking information in this release includes, but is not
limited to: expected cash provided by continuing operations; cash dividends;
future capital expenditures, including the amount and nature thereof; oil and
natural gas prices and demand; expansion and other development trends of the
oil and gas industry; business strategy and outlook; expansion and growth of
our business and operations; and maintenance of existing customer, supplier and
partner relationships; supply channels; accounting policies; credit risks; and
other such matters.

All such forward-looking information is based on certain assumptions and
analyses made by us in light of our experience and perception of historical
trends, current conditions and expected future developments, as well as other
factors we believe are appropriate in the circumstances. The risks,
uncertainties, and assumptions are difficult to predict and may affect
operations, and may include, without limitation: foreign exchange fluctuations;
equipment and labour shortages and inflationary costs; general economic
conditions; industry conditions; changes in applicable environmental, taxation
and other laws and regulations as well as how such laws and regulations are
interpreted and enforced; the ability of oil and natural gas companies to raise
capital; the effect of weather conditions on operations and facilities; the
existence of operating risks; volatility of oil and natural gas prices; oil and
gas product supply and demand; risks inherent in the ability to generate
sufficient cash flow from operations to meet current and future obligations;
increased competition; stock market volatility; opportunities available to or
pursued by us; and other factors, many of which are beyond our control.

Actual results, performance or achievements could differ materially from those
expressed in, or implied by, this forward-looking information and, accordingly,
no assurance can be given that any of the events anticipated by the
forward-looking information will transpire or occur, or if any of them do, what
benefits will be derived there from. Except as required by law, Bonterra
disclaims any intention or obligation to update or revise any forward-looking
information, whether as a result of new information, future events or
otherwise.

The forward-looking information contained herein is expressly qualified by this
cautionary statement.

Frequently recurring terms

Bonterra uses the following frequently recurring terms in this press release:
“bbl” refers to barrel, “NGL” refers to Natural gas liquids, “MCF” refers to
thousand cubic feet and “BOE” refers to barrels of oil equivalent. Disclosure
provided herein in respect of a BOE may be misleading, particularly if used in
isolation. A BOE conversion ratio of 6 MCF: 1 bbl is based on an energy
conversion method primarily applicable at the burner tip and does not represent
a value equivalency at the wellhead.

Numerical Amounts

The reporting and the functional currency of the Company is the Canadian dollar.

The TSX does not accept responsibility for the accuracy of this release.

– END RELEASE – 09/08/2017

For further information:
Bonterra Energy Corp.
George F. Fink
Chairman and CEO
Telephone: (403) 262-5307
OR
Bonterra Energy Corp.
Robb D. Thompson
CFO and Secretary
Telephone: (403) 262-5307
OR
Bonterra Energy Corp.
Adrian Neumann
COO
Telephone: (403) 262-5307
Fax: (403) 265-7488
Email: info@bonterraenergy.com

COMPANY:
FOR: BONTERRA ENERGY CORP.
TSX SYMBOL: BNE

INDUSTRY: Energy and Utilities – Oil and Gas
RELEASE ID: 20170809CC0084

Press Release from Marketwired 1-866-736-3779

Strad Energy Services Announces Second Quarter Results – Part 2

August 9, 2017 by The Canadian Press

Adjusted EBITDA for the six months ended June 30, 2017, of $9.8 million,
increased 715% compared to $1.2 million for the same period in 2016. Adjusted
EBITDA as a percentage of revenue, for the six months ended June 30, 2017,
increased to 24% compared to 9% for the same period in 2016.

Operating expenses for the three and six months ended June 30, 2017, of $12.8
million and $27.5 million increased 217% and 179% compared to $4.0 million and
$9.8 million for the same period in 2016. The increase in operating expenses
during the first six months of 2017 is a result of increased activity levels,
utilization rates, and fleet size, as well as an increase in third party
expenses, as compared to the same period in 2016. The increase in overall
expenses is consistent with the increase in drilling activity and energy
infrastructure projects throughout the first half of 2017.

Selling, general and administrative costs (“SG&A”) for the three and six months
ended June 30, 2017, of $1.3 million and $2.7 million, respectively, increased
5% and 17% compared to $1.3 million and $2.3 million for the same period in
2016. SG&A costs increased over the three and six months as a result of the
third quarter 2016 Redneck acquisition and first quarter 2017 acquisition of
Got Mats?.

/T/

U.S. Operations

Three months ended June 30, Six months ended June 30,
—————————- —————————
—————————- —————————
($000’s) 2017 2016 % chg. 2017 2016 % chg.
——— ——– ——– ——– ——– ——–

Revenue 6,252 2,515 149 11,318 7,301 55
Operating expenses 4,766 2,314 106 8,718 6,444 35
Selling, general and
administration 861 1,420 (39) 1,757 2,508 (30)
Share based payments 15 13 32 17
Net income (4,411) (7,169) 38 (6,618) (9,079) 27
Adjusted EBITDA(1) 610 (1,232) 150 811 (1,668) 149
Adjusted EBITDA as a
% of revenue 10% (49)% 7% (23)%

Capital
expenditures(2) 488 143 2,673 439
Gross capital assets 134,972 141,966 (5) 134,972 141,966 (5)
Total assets 67,188 72,825 (8) 67,188 72,825 (8)

Equipment Fleet:
Surface equipment 2,040 2,010 2,040 2,010
Utilization %(3) 25% 13% 25% 17%
Matting 17,650 13,220 34 17,650 13,220 34
Utilization %(3) 29% 12% 24% 16%

/T/

Notes:

(1) Earnings before interest, taxes, depreciation and amortization and other
adjustments (“Adjusted EBITDA”) is not a recognized measure under IFRS; see
“Non-IFRS Measures Reconciliation”.

(2) Includes assets acquired under finance lease and purchases of intangible
assets.

(3) Equipment utilization includes surface and matting equipment on rent only
and is calculated using gross asset value.

Revenue for the three months ended June 30, 2017, increased 149% to $6.3
million from $2.5 million for the same period in 2016. The increase in revenue
is due to a combination of higher surface equipment and matting utilization
rates and modestly higher customer pricing resulting from increased drilling
activity when compared to the same period in 2016. Average rig counts in the
Bakken, Rockies and Marcellus regions increased by 80%, 130%, and 89%,
respectively, during the second quarter of 2017 compared to the same period in
2016.

During the second quarter, revenue from energy infrastructure projects was $1.0
million or 16% of total revenue for U.S. Operations compared to $nil in the
same period of 2016.

The U.S. matting fleet increased to 17,650 mats as at June 30, 2017, compared
to 13,220 mats as at June 30, 2016. The addition of mats during the first half
of 2017 was to support the increase in U.S. energy infrastructure customers.
The U.S. surface equipment fleet increased slightly by 30 pieces of equipment
to 2,040 pieces as at June 30, 2017, compared to 2,010 pieces as at June 30,
2016.

Adjusted EBITDA for the three months ended June 30, 2017, increased to $0.6
million compared to $(1.2) million for the same period in 2016. Adjusted EBITDA
as a percentage of revenue, for the three months ended June 30, 2017, was 10%
compared to (49)% for the same period in 2016. The increase in both adjusted
EBITDA and adjusted EBITDA as a percentage of revenue is primarily due to
increased drilling activity levels which resulted in higher utilization and
modestly improved customer pricing in the second quarter of 2017 compared to
the same period of 2016.

Revenue for the six months ended June 30, 2017, increased 55% to $11.3 million
from $7.3 million for the same period in 2016. The increase in revenue for the
six months ended June 30, 2017 can be attributed to higher surface equipment
and matting utilization rates due to increased drilling activity levels across
all of our U.S. operating regions and modestly higher customer pricing as
compared to the same period in 2016. In addition, energy infrastructure revenue
as a percentage of total revenue increased to $1.5 million or 13% during the
six months ended June 30, 2017 compared to $nil in the same period of 2016.

Adjusted EBITDA for the six months ended June 30, 2017, increased to $0.8
million compared to $(1.7) million for the same period in 2016. Adjusted EBITDA
as a percentage of revenue, for the six months ended June 30, 2017, was 7%
compared to (23)% for the same period in 2016. The increase in both adjusted
EBITDA and adjusted EBITDA as a percentage of revenue is primarily due to the
increase in revenue during the first six months of 2017 in addition to lower
fixed costs.

Operating expenses for the three and six months ended June 30, 2017, of $4.8
million and $8.7 million, respectively, increased 106% and 35% compared to $2.3
million and $6.4 million for the same period in 2016. The increase in operating
expenses during the first six months of 2017 is a result of increased activity
levels.

SG&A costs for the three and six months ended June 30, 2017, of $0.9 million
and $1.8 million decreased 39% and 30% compared to $1.4 million and $2.5
million for the same period in 2016. The decrease in SG&A expenses is due to
cost reductions implemented by management including staff reductions and
reductions in discretionary spending.

/T/

Product Sales

Three months ended June 30, Six months ended June 30,
————————— ————————-
————————— ————————-
($000’s) 2017 2016 % chg. 2017 2016 % chg.
—————————————————–

Revenue 3,034 2,232 36 4,682 4,129 13
Operating expenses 1,991 1,616 23 3,074 3,461 (11)
Selling, general and
administration 49 21 133 99 22 350
Net income (loss) (4) (252) 98 (274) (546) 50
Adjusted EBITDA(1) 994 595 67 1,509 646 134
Adjusted EBITDA as a
% of revenue 33% 27% 32% 16%

Capital
expenditures(2) – – – 25 – –
Total assets 34 52 (35) 34 52 (35)

/T/

Notes:

(1) Earnings before interest, taxes, depreciation and amortization and other
adjustments (“Adjusted EBITDA”) is not a recognized measure under IFRS; see
“Non- IFRS Measures Reconciliation”.

(2) Includes assets acquired under finance lease and purchases of intangible
assets.

Product Sales are comprised of in-house manufactured products sold to external
customers, third party equipment sales to existing customers and sales of
equipment from Strad’s existing fleet to customers.

Revenue for the three months ended June 30, 2017, increased 36% to $3.0 million
from $2.2 million for the same period in 2016, resulting primarily from higher
in-house manufactured equipment sales. During the three months ended June 30,
2017, Product Sales consisted of $2.1 million of in-house manufactured products
and $0.9 million of rental fleet sales compared to $0.1 million and $0.2
million, respectively, as well as $1.9 million of third party equipment sales
during the same period in 2016.

During the second quarter, revenue from energy infrastructure projects was $1.8
million or 57% of total revenue compared to $1.6 million or 71% of total
revenue in the same period of 2016.

Adjusted EBITDA for the three months ended June 30, 2017, increased to $1.0
million from $0.6 million for the same period in 2016. Adjusted EBITDA as a
percentage of revenue, for the three months ended June 30, 2017, was 33%
compared to 27% for the same period in 2016. Adjusted EBITDA has increased more
than revenue on a percentage basis, primarily as a result of lower fixed costs
related to the manufacturing facility for the three months ended June 30, 2017,
as compared to the same period in 2016.

Revenue for the six months ended June 30, 2017, increased 13% to $4.7 million
from $4.1 million for the same period in 2016, resulting primarily from higher
in-house manufactured equipment sales. Sales of Strad’s rental fleet equipment
fluctuate quarter-over-quarter and are primarily dependent on strategic
opportunities to monetize underutilized rental assets.

During the six months ended June 30, 2017, revenue from energy infrastructure
projects was $3.1 million or 67% of total revenue compared to $2.9 million or
70% of total revenue in the same period of 2016.

Adjusted EBITDA for the six months ended June 30, 2017, increased to $1.5
million from $0.6 million for the same period in 2016. Adjusted EBITDA as a
percentage of revenue, for the six months ended June 30, 2017, was 32% compared
to 16% for the same period in 2016.

Operating expenses for the three and six months ended June 30, 2017, of $2.0
million and $3.1 million increased 23% and decreased 11% compared to $1.6
million and $3.5 million for the same period in 2016. Operating expenses vary
with individual transactions and business activity levels.

OUTLOOK

We continued to see a year-over-year improvement in our financial performance
as our results were impacted by a number of different variables including
increased utilization, improved customer pricing and a significant revenue
contribution from our energy infrastructure customer vertical.

Increased demand for our services in the WCSB during the quarter was
attributable to increased average rig counts of 298 compared to 158 in the
prior year, the addition of Redneck Oilfield Services Ltd. which expanded our
equipment offering in western Canada and wet weather conditions which resulted
in an early start to our matting season and an increase in utilization during
the quarter, compared to the prior year.

In Canada, significantly higher demand for matting from both of our customer
verticals, along with a period of under investment in new matting product by
most matting providers, lead to favorable supply and demand market conditions
during the second quarter which translated into a marked improvement in our
average matting prices beyond the double digit increases we disclosed
previously. Providing the recent volatility in commodity prices does not alter
our customers’ 2017 capital programs, we should continue to see similar
utilization levels in the third quarter on an expanded matting fleet as a
result of the addition of Got Mats? and capital spending during the second
quarter. We anticipate deploying the additional $11.0 million of capital
throughout the remainder of 2017 to support our matting business and our energy
infrastructure customer vertical.

Second quarter results in our U.S. Operations improved significantly compared
to the prior year, due to higher rig counts in the regions in which we operate.
Stronger demand for our products and services in the U.S. during the quarter
continued to support our strategy of increasing our prices in certain product
lines and operating regions. We have realized modest pricing gains during the
first half of 2017 notwithstanding those gains are being made on historically
low pricing levels for our Company. For the remainder of 2017, we expect to see
continued improvement in our U.S. operations results based on the current level
of demand for our products and services.

During the second quarter, we continued to execute on our strategic priorities
being continued growth of the energy infrastructure customer vertical,
continued focus on increasing our size and scale and maintaining our lean cost
structure. Revenue generated by energy infrastructure customers continued to
increase accounting for 38% of total revenue, 43% of Canadian Operations
revenue, 16% of U.S. Operations revenue and 57% of Product Sales revenue during
the second quarter.

We continued to focus on growing our size and scale through organic growth with
$4.6 million of the $6.3 million capital spending being allocated primarily to
our Canadian matting fleet to meet strong demand. We plan to continue investing
in our matting fleet throughout the remainder of 2017 to meet customer demand
primarily in our energy infrastructure customer vertical.

Looking ahead to the remainder of 2017, we expect activity levels to continue
to trend higher year-over-year despite the recent volatility in oil prices,
providing our customers execute their remaining 2017 capital programs. We see
demand for our Canadian matting fleet continuing to be strong during the third
quarter as additional energy infrastructure projects begin in the summer
months. We anticipate demand for our Canadian surface equipment to remain
steady over the second half of 2017. In the U.S., we expect to see a slower and
steady improvement in our results over the remainder of 2017 as pricing
increases begin to take effect. We will continue our focus on increasing prices
for our products and services where we can and managing our lean cost structure
to ensure the efficiencies we gained over the past two years are maintained as
activity levels increase and drive margin improvement.

LIQUIDITY AND CAPITAL RESOURCES

/T/

($000’s) June 30, 2017 December 31, 2016
————————————–
————————————–

Current assets $ 37,291 $ 31,852
Current liabilities 13,862 16,216
————————————–
————————————–
Working Capital(1) 23,429 15,636

Banking facilities
Operating facility – 1,478
Syndicated revolving facility 20,951 26,501
————————————–
————————————–
Total facility borrowings 20,951 27,979

Total credit facilities(2) 48,500 48,500
————————————–
————————————–
Unused credit capacity 27,549 20,521

/T/

Strad Energy Services Announces Second Quarter Results – Part 3

August 9, 2017 by The Canadian Press

Notes:

(1) Working capital is calculated as current assets less current liabilities.

(2) Facilities are subject to certain limitations on accounts receivable,
inventory, and net book value of fixed assets and are secured by a general
security agreement over all of the Company’s assets. As at June 30, 2017, Strad
had access to $48.5 million of credit facilities.

As at June 30, 2017, working capital was $23.4 million compared to $15.6
million at December 31, 2016. The change in current assets is a result of a 20%
increase in accounts receivable to $29.4 million for the second quarter of 2017
compared to $24.4 million for the fourth quarter of 2016. The increase in
accounts receivable is due to an increase in matting and surface equipment
related revenue, as well as delays in customer payments during the second
quarter as compared to the fourth quarter of 2016. Inventory decreased by 5% to
$3.7 million at June 30, 2017, from $3.9 million at December 31, 2016, and
prepaid expenses decreased 24% to $0.8 million at June 30, 2017 from $1.1
million at December 31, 2016. The decrease in inventory and prepaids relates to
the normal course of business.

The change in current liabilities is a result of a 5% decrease in accounts
payable and accrued liabilities to $13.1 million at June 30, 2017, compared to
$13.9 million at year end. Bank indebtedness decreased to $nil at the end of
the second quarter compared to bank indebtedness of $1.5 million for the fourth
quarter of 2016.

Funds from operations for the three months ended June 30, 2017, increased to
$6.1 million compared to $(0.8) million for the three months ended June 30,
2016. Capital expenditures totaled $6.3 million for the three months ended June
30, 2017. Strad’s total facility borrowing decreased by $7.0 million for the
three months ended June 30, 2017, compared to the fourth quarter of 2016.
Management monitors funds from operations and the timing of capital additions
to ensure adequate capital resources are available to fund Strad’s capital
program.

As at June 30, 2017, the Company’s syndicated banking facility consists of an
operating facility with a maximum principal amount of $7.0 million CAD and $5.0
million USD, and a $36.5 million CAD syndicated revolving facility, both of
which are subject to certain limitations on accounts receivable, inventory and
net book value of fixed assets and are secured by a general security agreement
over all of the Company’s assets. As at June 30, 2017, the Company had access
to the maximum credit facilities. The syndicated banking facility bears
interest at bank prime plus a variable rate, which is dependent on the
Company’s funded debt to EBITDA ratio. The Company’s syndicated banking
facility matures on September 29, 2018.

Based on the Company’s current credit facility, the interest rate on the
syndicated credit facility is bank prime plus 1.25% on prime rate advances and
at the prevailing rate plus a stamping fee of 2.25% on bankers’ acceptances.
For the three months ended June 30, 2017, the overall effective rates on the
operating facility and revolving facility were 6.19% and 5.32%, respectively.
As of June 30, 2017, $nil was drawn on the operating facility and $21.0 million
was drawn on the revolving facility. Required payments on the revolving
facility are interest only.

As at June 30, 2017, the Company was in compliance with all of the financial
covenants under its credit facilities.

The relevant definitions of financial debt covenant ratio terms as set forth in
the Company’s syndicated banking facility are as follows:

/T/

— Funded debt includes bank indebtedness plus long-term debt plus current

and long-term obligations under finance lease less cash.
— EBITDA is based on trailing twelve months adjusted EBITDA plus share
based payments, plus additional one-time charges.
— Interest expense ratio is calculated as the ratio of trailing twelve
months adjusted EBITDA plus share based payments to trailing twelve
months interest expense on loans and borrowings.

/T/

The above noted definitions are not recognized under IFRS and are provided
strictly for the purposes of the financial debt calculation.

/T/

Financial Debt Covenants As at June 30, 2017 As at December 31, 2016
—————————————————————————-
Funded debt to EBITDA ratio (not
to exceed 5.5:1)
Funded debt $ 21,143 $ 29,025
EBITDA 18,320 9,119
—————————————————————————-
Ratio 1.2 3.2
—————————————————————————-
—————————————————————————-

EBITDA to interest coverage
ratio (no less than 2.50:1)
EBITDA $ 18,320 $ 9,119
Interest expense 1,694 1,557
—————————————————————————-
Ratio 10.8 5.9
—————————————————————————-
—————————————————————————-

/T/

NON-IFRS MEASURES RECONCILIATION

Certain supplementary measures in this MD&A do not have any standardized
meaning as prescribed under IFRS and, therefore, are considered non-IFRS
measures. These measures are described and presented in order to provide
shareholders and potential investors with additional information regarding the
Company’s financial results, liquidity and its ability to generate funds to
finance its operations. These measures are identified and presented, where
appropriate, together with reconciliations to the equivalent IFRS measure.
However, they should not be used as an alternative to IFRS, because they may
not be consistent with calculations of other companies. These measures are
further explained below.

Earnings before interest, taxes, depreciation and amortization and other
adjustments (“adjusted EBITDA”) is not a recognized measure under IFRS.
Management believes that in addition to net income, adjusted EBITDA is a useful
supplemental measure as it provides an indication of the results generated by
the Company’s principal business activities prior to consideration of how those
activities are financed or how the results are taxed. Adjusted EBITDA is
calculated as net income (loss) plus interest, finance fees, taxes,
depreciation and amortization, loss on disposal of property, plant and
equipment, loss on foreign exchange, less gain on foreign exchange and gain on
disposal of property, plant and equipment. Segmented adjusted EBITDA is based
upon the same calculation for defined business segments, which are comprised of
Canadian Operations, U.S. Operations and Product Sales.

Funds from operations are cash flow from operating activities excluding changes
in non-cash working capital. It is a supplemental measure to gauge performance
of the Company before non-cash items. Working capital is calculated as current
assets minus current liabilities. Working capital, cash forecasting and banking
facilities are used by Management to ensure funds are available to finance
growth opportunities.

Funded debt is calculated as bank indebtedness plus long-term debt plus current
and long-term portion of finance lease obligations less cash from syndicate
institutions.

Reconciliation of Funds from Operations

/T/

($000’s)

Three months ended June 30, Six months ended June 30,
2017 2016 2017 2016
—————————————————————————-

Net cash generated from
operating activities $ 3,031 $ 4,435 $ 6,572 $ 9,681
Less:
Changes in non-cash
working capital(1) (3,045) 5,214 (5,031) 8,705
—————————————————————————-
Funds from Operations 6,076 (779) 11,603 976
—————————————————————————-

/T/

Notes:

(1) Prior period comparative funds from operations have amounts that were
reclassified to conform to the current presentation of the interim consolidated
statement of cash flows.

Reconciliation of Adjusted EBITDA

/T/

(‘000’s)

Three months ended June 30, Six months ended June 30,
—————————————————————————
2017 2016 2017 2016
—————————————————————————

Net loss: $ (2,163) $ (6,958) $ (4,512) $ (9,952)
Add (deduct):
Depreciation and
amortization 7,572 4,516 13,955 9,665
Gain on disposal of
PP&E (150) (268) (227) (461)
Deferred income tax
expense (102) 1,439 14 238
Financing fees 73 47 147 94
Interest expense 419 157 855 401
Gain on foreign
exchange (58) 3 (145) (434)
Current income tax
recovery – (919) – (1,136)
—————————————————————————
Adjusted EBITDA 5,591 (1,983) 10,087 (1,585)
—————————————————————————

/T/

Reconciliation of quarterly non-IFRS measures

/T/

(000’s)

Three months ended
—————————————————————————
Jun 30, 2017 Mar 31, 2017 Dec 31, 2016 Sep 30, 2016
—————————————————————————

Net loss: $ (2,163) $ (2,347) $ (3,105) $ (3,746)
Add (deduct):
Depreciation and
amortization 7,572 6,383 7,610 4,930
Gain on disposal of
PP&E (150) (78) (105) (35)
(Gain) loss on
foreign exchange (58) (87) 123 17
Current income tax
(recovery) expense – – 204 (242)
Deferred income tax
(recovery) expense (102) 116 (403) (39)
Interest expense 419 436 415 318
Finance fees 73 73 43 44
—————————————————————————
Adjusted EBITDA 5,591 4,496 4,782 1,247
—————————————————————————

Three months ended
—————————————————————————
Jun 30, 2016 Mar 31, 2016 Dec 31, 2015 Sep 30, 2015
—————————————————————————

Net loss: $ (6,958) $ (2,994) $ (8,316) $ (20,362)
Add (deduct):
Depreciation and
amortization 4,516 5,149 7,126 9,616
Gain on disposal of
PP&E (268) (193) (99) (30)
(Gain) loss on
foreign exchange 3 (437) 216 380
Current income tax
recovery (919) (217) (677) (432)
Deferred income tax
(recovery) expense 1,439 (1,201) (4,033) (2,776)
Interest expense 157 244 427 311
Impairment loss – – 7,822 17,277
Finance fees 47 47 34 37
—————————————————————————
Adjusted EBITDA (1,983) 398 2,500 4,021
—————————————————————————

Reconciliation of funded debt
(000’s)

Six months ended Year ended
June 30, 2017 December 31, 2016
—————————————————————————-
Bank indebtedness, net of cash on hand at
syndicate banks $ (865) $ 1,478
Long term debt 20,951 26,501
Current and long term obligations under
finance lease 1,057 1,046
—————————————————————————-
Total Funded Debt 21,143 29,025
—————————————————————————-

/T/

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION AND STATEMENTS

Certain statements and information contained in this press release constitute
forward-looking information and statements within the meaning of applicable
securities laws. The use of any of the words “expect”, “plan”, “continue”,
“estimate”, “anticipate”, “potential”, “targeting”, “intend”, “could”, “might”,
“should”, “believe”, “may”, “predict”, or “will” and similar expressions are
intended to identify forward-looking information or statements. More
particularly, this press release contains forward-looking statements concerning
future capital expenditures of the Company, including its 2017 capital budget,
and funding thereof, changes and expectations in margins to be experienced by
Strad, anticipated cash flow, debt, demand for the Company’s products and
services, drilling activity in North America, pricing of the Company’s products
and services and expectations for the remainder of 2017, introduction of new
products and services and the potential for growth and expansion of certain
components of the Company’s business, including further additions to our
matting fleet, anticipated benefits from cost reductions and timing thereof,
manufacturing capacity to meet anticipated demand for the Company’s products,
and expected exploration and production industry activity including the effects
of industry trends on demand for the Company’s products. These statements
relate to future events or to the Company’s future financial performance and
involve known and unknown risks, uncertainties and other factors that may cause
the Company’s actual results, levels of activity, performance or achievements
to be materially different from future results, levels of activity, performance
or achievements expressed or implied by such forward-looking statements.

Strad Energy Services Announces Second Quarter Results – Part 4

August 9, 2017 by The Canadian Press

Various assumptions were used in drawing the conclusions or making the
projections contained in the forward-looking statements throughout this press
release. The forward-looking information and statements included in this press
release are not guarant…

Strategic Oil & Gas Ltd. Announces Payment in Kind of Interest on Convertible Debentures

August 9, 2017 by The Canadian Press

FOR: STRATEGIC OIL & GAS LTD
TSX VENTURE SYMBOL: SOG

Date issue: August 09, 2017
Time in: 5:47 PM e

Attention:

CALGARY, ALBERTA–(Marketwired – Aug. 9, 2017) – Strategic Oil & Gas Ltd.
(“Strategic” or the “Company”) (TSX VENTURE:SOG) announces that, with respect
to the Company’s outstanding convertible debentures, Strategic has elected to
pay the interest in kind for the semi-annual interest payment due on August 31,
2017. Approximately $3.9 million in additional debentures will be issued, which
will be convertible into common shares of Strategic at a conversion price of
$2.03 per common share, subject to approval from the TSX Venture Exchange.

ABOUT STRATEGIC OIL & GAS

ADDITIONAL INFORMATION

Additional information is also available at www.sogoil.com and at www.sedar.com.

Reader Advisories

This news release includes certain information, with management’s assessment of
Strategic’s future plans and operations, and contains forward-looking
statements which may include some or all of the following: (i) payment of
interest in additional debentures, which are provided to allow investors to
better understand the Company’s business. By their nature, forward-looking
statements are subject to numerous risks and uncertainties; some of which are
beyond Strategic’s control, including the impact of general economic
conditions, industry conditions, volatility of commodity prices, currency
fluctuations, imprecision of reserve estimates, environmental risks, changes in
environmental tax and royalty legislation, competition from other industry
participants, the lack of availability of qualified personnel or management,
stock market volatility and ability to access sufficient capital from internal
and external sources, and other risks and uncertainties described under the
heading ‘Risk Factors’ and elsewhere in the Company’s Annual Information Form
for the year ended December 31, 2016 and other documents filed with Canadian
provincial securities authorities and are available to the public at
www.sedar.com. Readers are cautioned that the assumptions used in the
preparation of such information, although considered reasonable at the time of
preparation, may prove to be imprecise and, as such, undue reliance should not
be placed on forward-looking statements. The principal assumptions Strategic
has made includes security of land interests; drilling cost stability; royalty
rate stability; oil and gas prices to remain in their current range; finance
and debt markets continuing to be receptive to financing the Company and
industry standard rates of geologic and operational success. Actual results
could differ materially from those expressed in, or implied by, these
forward-looking statements. Strategic disclaims any intention or obligation to
update or revise any forward-looking statements, whether as a result of new
information, future events or otherwise, except as required by law.

– END RELEASE – 09/08/2017

For further information:
Strategic Oil & Gas Ltd.
Gurpreet Sawhney
President and CEO
403.767.2949
403.767.9122 (FAX)
OR
Strategic Oil & Gas Ltd.
Aaron Thompson
Chief Financial Officer
403.767.2952
403.767.9122 (FAX)
www.sogoil.com

COMPANY:
FOR: STRATEGIC OIL & GAS LTD
TSX VENTURE SYMBOL: SOG

INDUSTRY: Energy and Utilities – Oil and Gas
RELEASE ID: 20170809CC0080

Press Release from Marketwired 1-866-736-3779

Parex Announces 2017 Second Quarter Results

August 9, 2017 by The Canadian Press

FOR: PAREX RESOURCES INC.
TSX Symbol: PXT

Date issue: August 09, 2017
Time in: 5:18 PM e

Attention:

CALGARY, AB –(Marketwired – August 09, 2017) –

NOT FOR DISTRIBUTION OF FOR DISSEMINATION IN THE UNITED STATES

Parex Resources Inc. (“Parex” or the “Company”) (TSX: PXT), a company focused
on Colombian oil exploration and production, announces its unaudited financial
and operating results for the three months ended June 30, 2017 (“Second
Quarter” or “Q2”). All amounts herein are in United States dollars (“USD”)
unless otherwise stated.

A conference call to discuss the Second Quarter results will be held on
Thursday August 10, 2017 beginning at 8:30 am Mountain Time.

2017 Second Quarter Financial and Operational Highlights

/T/

— Quarterly production was 34,291 barrels of oil equivalent per day

(“boe/d”) (99% crude oil), representing an increase of 5 percent over
the previous quarter ended March 31, 2017 and an increase of 18 percent
over the prior year comparative period;
— Generated adjusted funds flow from operations of $66.8 million ($0.43
per share basic) which has been adjusted to exclude a $15.0 million
($0.09 per share basic) one time legal settlement. This charge is
related to the settlement of litigation corresponding to the 2012
acquisition of Ramshorn International Ltd. which holds a 45% working
interest in Block LLA-34;
— Including the $15.0 million legal settlement, funds flow from operations
was $51.8 million ($0.34 per share basic) as compared to $0.21 per share
for the prior year comparative period and $0.44 per share in the
previous quarter;
— Earned net income of $3.5 million ($0.02 per share basic) compared to a
net loss of $0.2 million ($nil basic per share) in the comparative
quarter of 2016;
— Realized a sales price of $46.84/boe during the period at a $4.03/bbl
discount to the average Brent price, and an operating netback of
$26.59/boe. Funds flow from operations netback was $16.81/boe and
adjusted for the one-time legal settlement was $21.68/boe;
— Capital expenditures were $59.0 million in the period compared to $13.9
million in the comparative period of 2016. Parex expects to invest
approximately $225 million in capital projects in 2017. Capital activity
will increase significantly in the second half of 2017;
— Working capital was $128.3 million at June 30, 2017 compared to $131.1
million at March 31, 2017 and $97.5 million in the comparative period.
The Company has an undrawn bank credit facility of $100.0 million; and
— Participated in drilling 12 wells(1) in Colombia resulting in 9 oil
wells, 1 dry and abandoned and 2 untested wells, for a success rate of
90 percent.

/T/

(1) Oil wells: AB-19, AB-29, Bacano-4, Bacano-5, Jacana Sur-1, Jacana Sur-2,
Jacamar-1, Jacana-9 & Tigana Sur-5; Dry & Abandoned: Sinsonte-1; and Untested:
AB-8 & AB-21.

/T/

Six
months
Three Months Ended ended
June 30, March 31, June 30,
2017 2016 2017 2017
============================================================================
Operational
Average daily production
Oil & Gas (boe/d)(1) 34,291 29,136 32,591 33,452

Average daily sales of produced
oil & natural gas

Oil (bbl/d) 33,563 27,441 33,308 33,442
Gas (Mcf/d) 1,668 1,340 1,644 1,656
—————————————————————————-
Oil & Gas (boe/d) 33,841 27,664 33,582 33,718

Operating netback ($/boe)(1)

Reference price – Brent
($/bbl) 50.87 47.03 54.61 52.74
Oil & natural gas revenue
(excluding hedging) 46.84 39.74 48.72 47.77
Royalties (4.03) (3.33) (4.38) (4.21)
—————————————————————————-
Net revenue 42.81 36.41 44.34 43.56
Production expense (5.31) (4.51) (5.09) (5.20)
Transportation expense (10.91) (11.76) (11.11) (11.01)
—————————————————————————-
Operating netback ($/boe) 26.59 20.14 28.14 27.35

Funds flow provided by
operations ($/boe) 16.81 13.29 22.47 19.61
Adjusted funds flow provided by
operations ($/boe)(4) 21.68 13.29 22.47 22.07
—————————————————————————-

Financial (USD$000s except per
share amounts)
Oil and natural gas revenue 145,406 104,571 150,142 295,548

Net income (loss) 3,524 (185) 40,106 43,630
Per share – basic 0.02 0.00 0.26 0.28
Adjusted net income (loss)(4) 18,524 (185) 40,106 58,630
Per share – adjusted(4) 0.12 0.00 0.26 0.38

Funds flow from operations 51,763 31,792 67,906 119,669
Per share – basic 0.34 0.21 0.44 0.78
Adjusted funds flow from
operations(4) 66,763 31,792 67,906 134,669
Per share – adjusted(4) 0.43 0.21 0.44 0.88

Capital expenditure 59,008 13,922 35,563 94,571

Total assets 1,015,540 921,665 984,855 1,015,540
Working capital surplus 128,347 97,532 131,056 128,347
Long-term debt(2) – – – –

Outstanding shares (end of
period) (000s)

Basic 154,377 152,268 153,714 154,377
Weighted average basic 154,249 152,006 153,284 153,769
Diluted(3) 162,720 161,446 164,688 162,720
============================================================================

/T/

(1) The table above contains Non-GAAP measures. See “Non-GAAP Terms” for
further discussion.
(2) Borrowing limit of $100.0 million as of June 30, 2017.
(3) Diluted shares as stated include the effects of common shares and
in-the-money stock options outstanding at the period-end. The June 30, 2017
closing stock price was Cdn$14.75 per share.
(4) Adjusted for a one time legal settlement charge of $15.0 million related
to the settlement of litigation concerning Parex’ acquisition of Ramshorn
International Ltd. in 2012.

Operational Update:

Cabrestero (working interest (“WI”) 100%): There are currently 4 producing
Bacano wells, located to the south-west of the Jacana field. Bacano field
production rates are expected to be managed within the 3,000 – 5,000 bopd
range for the balance of 2017.

Capachos (WI 50%): Parex spud the first earning well Capachos-2 on July 9,
2017. The well will be drilled to a depth of approximately 16,500 feet and is
currently at intermediate casing at approximately 11,000 feet. After the
Capachos-2 well, Parex expects to drill the second earning well Capachos Sur-2
followed by the Capachos Norte-1 exploration well. The Capachos Block has
multiple development locations and exploration prospects. Parex has also
commenced the construction of the initial production facilities.

VMM-11 (WI 100%): The Company has drilled and cased its first 2 wells,
Glauca-1 and Glauca-2, in a planned 4 well 2017 program on the VMM-11 block.
We expect to test both wells with a service rig. We expect to drill VMM-11
exploration prospects Niagara-1 and Iguaza-1 prior to year-end 2017.

Aguas Blancas (WI 50%): Parex continues to advance its assessment of the Aguas
Blancas field. Overall, we have drilled 11 appraisal wells, including 7 in the
AB West Area (Foot Wall) and 4 in the AB East Area (Hanging Wall). Click the
link below to view the map of Aguas Blancas project:

http://parexresources.com/wp-content/uploads/2017/08/Aguas-Blancas-_August-20
17.pdf

AB West Area (Foot Wall): Parex began its first waterflood pilot on July 1,
2017 incorporating AB-26 (injector), AB-5, AB-19 and AB-29. Approximately 380
barrels of water per day (“bwpd) is being injected and total gross oil
production is approximately 305 bopd and 0.7 mmscfd of solution gas. AB-5 was
originally drilled in 1964 and produced a cumulative amount of 228,000 barrels
of oil, is producing as expected at a depleted rate of 10 bopd.

Parex is currently testing AB-8 and initial rates indicate that the well will
produce light oil at rates in the 80-100 bopd range. Recall that AB-8 is
downdip of AB-9 which tested an average oil rate of 130 bopd and 2.3 MMSCFD of
gas (news release dated January 9, 2017).

Through the remainder of 2017, Parex will be monitoring the waterflood pattern
performance and evaluating potential well stimulation operations that could
enhance well productivity. In addition, the Company plans to build new larger
drilling pads to enable further evaluation of the southern extent of the AB
West Area. Parex expects its 2018 budget to include a 10-20 wells
development/appraisal program in the AB West Area. After incorporating the
drilling results to date and seismic re-processing, Parex’ assessment of the
AB West Area is approximately 2,500-4,100 potential acres.

To date, the AB West Area is producing 34 API oil and initial sales indicate a
quality and transportation discount of approximately Brent less $6/bbl, which
is approximately a $10/bbl operating netback improvement over the Company’s
existing Llanos production. Parex is also planning to install a gas processing
facility to enable the commercialization of the existing solution gas and
potential gas zones.

AB East Area (Hanging Wall): A total of 4 wells have been drilled, including
one cored well under the initial assessment of the AB East Area. Testing
results and core analysis indicate that the AB East Area reservoir has lower
permeability relative to the AB West Area and comprises of interbedded
oil-bearing and water-bearing reservoirs. Due to the poor quality of the
cement jobs in the initial well bores, we will likely require new well bores
to evaluate the AB East Area economic potential. Parex anticipates to
re-assess the AB East Area following appraising the AB West Area.

Llanos 34 (WI 55%): Parex continues to delineate the Jacana/Tigana trend on
LLA-34. The Jacana-10 well was drilled to delineate a 4.9 kilometer gap
between the most northeastern well in the Jacana field (Jacana-5) and the most
southwestern well in the Tigana field (Tigana Suroeste-1). The well was
drilled 1.5 kilometers northeast along trend from Jacana-5 at a similar
structural position. The well was completed in the Guadalupe reservoir and
commenced testing on July 30, 2017. The well was tested over an 87 hour period
and produced a total of 2,530 barrels of oil with a final measured watercut of
0.5% and average production rate of 698 bopd. The average production rate
during the last 12 hours of the test after cleanup of completion fluids was
1,046 barrels of oil per day with bottom hole pressure recorders indicating a
drawdown of approximately 35%.

In June 2017, the Jacana-9 well was drilled at a distance of 1,200 meters
north-east and 70 feet downdip of the previous most down-dip Jacana producer,
Jacana-5, which is currently producing approximately 3,500 bopd at a watercut
of 8%. The well encountered potential oil pay at different levels in the
Guadalupe reservoir and the lowest section was perforated and tested. After
three weeks of production, the final rate was approximately 75 bopd with an
90% watercut indicating that the lowest section tested in the well is close to
the current water contact. A service rig will be mobilized to the Jacana-9
location to test addition zones of the Guadalupe section.

Three exploration wells were drilled in the quarter. The Sinsonte-1 well was
previously reported as dry and abandoned. The Jacamar-1 well encountered
potential oil reservoir in the Guadalupe and Mirador reservoirs; and the
Guadalupe reservoir was perforated and is currently on production at
approximately 300 bopd at an 80% watercut. The Curucucu-1 exploration well
from the same pad as the Jacamar well has been cased for testing. A completion
rig will be moved to the location in the next two weeks to complete and test
the Curucucu-1 well and recomplete the Jacamar-1 well for testing of the
Mirador formation.

The remainder of the drilling program in LLA-34 for 2017 is mainly focused on
further delineation of the Tigana and Jacana pools. The drilling rig from
Jacana-10 is being mobilized to drill the Jacana-13, Jacana-12 and Jacana-15
wells which will continue delineation west and downdip of the currently
defined Jacana pool. The drilling rig from Curucucu is being mobilized to
drill 3 Tigana Norte wells to delineate the area around the Tigana Norte-1
well. The Tigana Norte-1 well continues to produce at a rate of 2,700 bopd
with a watercut of under 3% after cumulative recovery of almost 3 MMBBL.

Guidance Update:

Q3 2017 production is expected to average above 36,000 boe/d, Q4 2017
production is expected to average above 38,000 boe/d, and the full year 2017
average production is anticipated to exceed 35,000 boe/d. Previous 2017 full
year average production guidance was to range between 34,000 and 36,000 boe/d.
The full year 2017 capital expenditures forecast is approximately $225
million, which is the high end of the previous guidance range of $200-$225
million. Parex still anticipates fully funding its capital program with funds
flow from operations.

Governance: Appointment of Director

Parex is pleased to announce that Ms. Carmen Sylvain has joined the Board of
Directors. Ms. Sylvain was a career Canadian diplomat and public servant with
over 30 years of combined experience in foreign affairs, international trade
and investment as well as major event management. As Canada’s Ambassador to
Colombia from 2014-2016, she provides in-depth knowledge of regional
environmental, social and governance matters. She also served in Global
Affairs Canada as Assistant Deputy Minister for Strategic Planning and Policy
where she led the development of a Foreign Policy Plan for Canada. Ms. Sylvain
received her Bachelor of Arts from San Jose State University, and completed a
Masters in Public Administration from Carleton University.

Q2 2017 Conference Call

Parex will host a conference call to discuss the Second Quarter Results on
Thursday, August 10, 2017 beginning at 8:30 am Mountain Time. To participate
in the call, from Canada and the United States, dial 1-866-696-5910 then enter
the passcode 7585696#.

The live audio webcast will be carried at:
http://bell.media-server.com/m/p/irws876e

Individuals located outside of Canada and the USA are invited to access this
event via webcast or by calling their respective location dial-in number
available at:
https://www.confsolutions.ca/ILT?oss=7P1R8666965910

This news release does not constitute an offer to sell securities, nor is it a
solicitation of an offer to buy securities, in any jurisdiction.

Non-GAAP Terms

The Company discloses several financial measures herein that do not have any
standardized meaning prescribed under International Financial Reporting
Standards (“IFRS”). These financial measures include funds flow used in, or
from operations, working capital, operating netback and funds flow netback.
Management uses these non-IFRS measures for its own performance measurement
and to provide shareholders and investors with additional measurements of the
Company’s efficiency and its ability to fund a portion of its future capital
expenditures.

Funds flow from operations is a non-IFRS term that includes all cash generated
from operating activities and is calculated before changes in non-cash working
capital. Management uses funds from (used in) operations to analyze operating
performance and monitor financial leverage, and considers funds from (used in)
operations to be a key measure as it demonstrates the Company’s ability to
generate cash necessary to fund future capital investments. Funds flow from
operations is reconciled with net (loss) income in the consolidated statements
of cash flows.

Shareholders and investors should be cautioned that these measures should not
be construed as an alternative to net income or other measures of financial
performance as determined in accordance with IFRS. Parex’ method of
calculating these measures may differ from other companies, and accordingly,
they may not be comparable to similar measures used by other companies. Please
see the Company’s most recent Management’s Discussion and Analysis, which is
available at www.sedar.com for additional information about these financial
measures.

Advisory on Forward Looking Statements

Certain information regarding Parex set forth in this document contains
forward-looking statements that involve substantial known and unknown risks
and uncertainties. The use of any of the words “plan”, “expect”,
“prospective”, “project”, “intend”, “believe”, “should”, “anticipate”,
“estimate”, “forecast”, “budget” or other similar words, or statements that
certain events or conditions “may” or “will” occur are intended to identify
forward-looking statements. Such statements represent Parex’ internal
projections, estimates or beliefs concerning, among other things, future
growth, results of operations, production, future capital and other
expenditures (including the amount, nature and sources of funding thereof),
competitive advantages, plans for and results of drilling activity,
environmental matters, business prospects and opportunities. These statements
are only predictions and actual events or results may differ materially.
Although the Company’s management believes that the expectations reflected in
the forward-looking statements are reasonable, it cannot guarantee future
results, levels of activity, performance or achievement since such
expectations are inherently subject to significant business, economic,
competitive, political and social uncertainties and contingencies. Many
factors could cause Parex’ actual results to differ materially from those
expressed or implied in any forward-looking statements made by, or on behalf
of, Parex.

In particular, forward-looking statements contained in this document include,
but are not limited to, statements with respect to the performance
characteristics of the Company’s oil properties; the Company’s anticipated
2017 capital budget, including the amount thereof; the Company’s forecasted
2017 average production; the Company’s 2017 capital expenditure budget,
including the expected allocations of such expenditures; the Company’s belief
that its capital budget will be fully funded from funds flow from operations;
the Company’s anticipated drilling, development, exploration and other growth
plans and activities for its assets, including the Company’s objectives at
Aguas Blancas, timing of commencement of the Company’s first water-flood
program at Aguas Blancas, the Company’s drilling plans at Aguas Blancas and
the Company’s drilling plans at Cabrestero; results of drilling and testing;
and activities to be undertaken in various areas. In addition, statements
relating to “reserves” are by their nature forward-looking statements, as they
involve the implied assessment, based on certain estimates and assumptions
that the resources described can be profitably produced in the future. The
recovery and reserve estimates of Parex’ reserves provided herein are
estimates only and there is no guarantee that the estimated reserves will be
recovered.

These forward-looking statements are subject to numerous risks and
uncertainties, including but not limited to, the impact of general economic
conditions in Canada and Colombia; prolonged volatility in commodity prices;
industry conditions including changes in laws and regulations including
adoption of new environmental laws and regulations, and changes in how they
are interpreted and enforced, in Canada and Colombia; competition; lack of
availability of qualified personnel; the results of exploration and
development drilling and related activities; obtaining required approvals of
regulatory authorities, in Canada and Colombia; risks associated with
negotiating with foreign governments as well as country risk associated with
conducting international activities; volatility in market prices for oil;
fluctuations in foreign exchange or interest rates; environmental risks;
changes in income tax laws or changes in tax laws and incentive programs
relating to the oil industry; changes to pipeline capacity, ability to access
sufficient capital from internal and external sources; risks related to the
lawsuit brought in Texas against Parex and certain foreign subsidiaries;
failure of counterparties to perform under contracts; risk that Brent oil
prices are lower than anticipated; risk that Parex’ evaluation of its existing
portfolio of development and exploration opportunities is not consistent with
its expectations; that production test results may not necessarily indicative
of long term performance or of ultimate recovery; and other factors, many of
which are beyond the control of the Company. Readers are cautioned that the
foregoing list of factors is not exhaustive. Additional information on these
and other factors that could affect Parex’ operations and financial results
are included in reports on file with Canadian securities regulatory
authorities and may be accessed through the SEDAR website (www.sedar.com).

Although the forward-looking statements contained in this document are based
upon assumptions which Management believes to be reasonable, the Company
cannot assure investors that actual results will be consistent with these
forward-looking statements. With respect to forward-looking statements
contained in this document, Parex has made assumptions regarding, among other
things: current and anticipated commodity prices and royalty regimes;
availability of skilled labour; timing and amount of capital expenditures;
future exchange rates; the price of oil, including the anticipated Brent oil
price; the impact of increasing competition; conditions in general economic
and financial markets; availability of drilling and related equipment; effects
of regulation by governmental agencies; receipt of partner, regulatory and
community approvals; royalty rates, future operating costs; effects of
regulation by governmental agencies; uninterrupted access to areas of Parex’
operations and infrastructure; recoverability of reserves and future
production rates; the status of litigation; timing of drilling and completion
of wells; on-stream timing of production from successful exploration wells;
operational performance of non-operated producing fields; pipeline capacity;
that Parex will have sufficient cash flow, debt or equity sources or other
financial resources required to fund its capital and operating expenditures
and requirements as needed; that Parex’ conduct and results of operations will
be consistent with its expectations; that Parex will have the ability to
develop its oil and gas properties in the manner currently contemplated;
anticipated operating netbacks, G&A, finance expenses and tax expenses;
current or, where applicable, proposed industry conditions, laws and
regulations will continue in effect or as anticipated as described herein;
that the estimates of Parex’ reserves volumes and the assumptions related
thereto (including commodity prices and development costs) are accurate in all
material respects; that Parex will be able to obtain contract extensions or
fulfill the contractual obligations required to retain its rights to explore,
develop and exploit any of its undeveloped properties; and other matters.

Management has included the above summary of assumptions and risks related to
forward-looking information provided in this document in order to provide
shareholders with a more complete perspective on Parex’ current and future
operations and such information may not be appropriate for other purposes.
Parex’ actual results, performance or achievement could differ materially from
those expressed in, or implied by, these forward-looking statements and,
accordingly, no assurance can be given that any of the events anticipated by
the forward-looking statements will transpire or occur, or if any of them do,
what benefits Parex will derive. These forward-looking statements are made as
of the date of this document and Parex disclaims any intent or obligation to
update publicly any forward-looking statements, whether as a result of new
information, future events or results or otherwise, other than as required by
applicable securities laws.

This press release and, in particular the information in respect of the
Company’s expected capital expenditures and funds flow from operations for
2017, may contain future oriented financial information (“FOFI”) within the
meaning of applicable securities laws. The FOFI has been prepared by
management to provide an outlook of the Company’s activities and results and
may not be appropriate for other purposes. The FOFI has been prepared based on
a number of assumptions including the assumptions discussed in this press
release. The actual results of operations of the Company and the resulting
financial results may vary from the amounts set forth herein, and such
variations may be material. The Company and management believe that the FOFI
has been prepared on a reasonable basis, reflecting management’s best
estimates and judgments. FOFI contained in this press release was made as of
the date of this press release and the press release, whether as a result of
new information, future events or otherwise, unless required pursuant to
applicable law.

Neither the TSX nor its Regulation Services Provider (as that term is defined
in the policies of the TSX) accepts responsibility for the adequacy or
accuracy of this release.

– END RELEASE – 09/08/2017

For further information:

For more information, please contact:
Mike Kruchten
Vice President, Capital Markets & Corporate Planning
Parex Resources Inc.
Phone: (403) 517-1733
Investor.relations@parexresources.com

COMPANY:
FOR: PAREX RESOURCES INC.
TSX Symbol: PXT

INDUSTRY: Energy and Utilities – Oil and Gas
RELEASE ID: 20170809CC010

Press Release from Marketwired 1-866-736-3779

BlackPearl Announces Second Quarter 2017 Financial and Operating Results

August 9, 2017 by The Canadian Press

FOR: BLACKPEARL RESOURCES INC.TSX SYMBOL: PXXOMX SYMBOL: PXXSDate issue: August 09, 2017Time in: 5:00 PM eAttention:
CALGARY, ALBERTA–(Marketwired – Aug. 9, 2017) – BlackPearl Resources Inc.
(“BlackPearl” or the “Company”) (TSX:PXX)(OMX:PXXS) is plea…

Prairie Provident Announces Second Quarter 2017 Financial and Operating Results

August 9, 2017 by The Canadian Press

FOR: PRAIRIE PROVIDENT RESOURCES INC.
TSX SYMBOL: PPR

Date issue: August 09, 2017
Time in: 4:38 PM e

Attention:

CALGARY, ALBERTA–(Marketwired – Aug. 9, 2017) – Prairie Provident Resources
Inc. (“Prairie Provident”, “PPR” or the “Company”) (TSX:PPR) is pleased to
announce its operating and financial results for the three and six months ended
June 30, 2017, and to provide an operational update. PPR’s consolidated
financial statements (“Financial Statements”) and related Management’s
Discussion and Analysis (“MD&A”) for the three and six months ended June 30,
2017 are available on its website and filed on SEDAR.

Prairie Provident was formed through the business combination of Lone Pine
Resources Inc. and Lone Pine Resources Canada Ltd. (now Prairie Provident
Resources Canada Ltd.) (collectively, “Lone Pine”) and Arsenal Energy Inc.
(“Arsenal”) which completed on September 12, 2016 (the “Arsenal Acquisition”).
Financial Statements referenced herein present the results for the historical
Lone Pine properties for the period up to September 12, 2016 and for the
combination of Lone Pine and Arsenal after September 12, 2016. This is a
significant factor in understanding the year-over-year and quarter-over-quarter
financial results of Prairie Provident.

SECOND QUARTER 2017 HIGHLIGHTS

/T/

— Second quarter production reached a new corporate record, averaging

5,872 boe/d (63% liquids), a 66% increase over the same period in 2016
due primarily to production additions from a successful Wheatland
drilling program, the Arsenal Acquisition, and the high-quality, light
oil assets acquired in the Greater Red Earth area of Northern Alberta on
March 22, 2017 (the “Red Earth Acquisition”);
— Compared to the first quarter of 2017, PPR’s second quarter production
increased 4% driven by a 22% increase in crude oil volumes, but was
negatively impacted by third-party facility outages at the Waterton and
Wheatland areas that curtailed production by approximately 300 boe/d
while extended downtime in Evi due to wet weather conditions and road
bans further impacted volumes by approximately 190 boe/d;
— Adjusted funds from operations(1) was 117% higher in the second quarter
of 2017 than the same period in 2016 at $7.1 million ($0.06 per diluted
share) due to increased production and improved operating netbacks;
— Operating netbacks(1) (after realized hedging gains) for the quarter
were $18.20/boe, a 2% increase over the same period in 2016 largely due
to stronger realized prices which were partially offset by lower gains
on derivative instruments, higher operating costs and increased
royalties due to higher pricing;
— Due to the seasonal impacts of spring break up, delayed scheduling of
frac crews, and a conscious decision to defer a portion of our capital
spending in response to commodity price uncertainty, second quarter
capital expenditures were $4.8 million, 31% lower than the first quarter
of 2017, with the majority directed to our Wheatland drilling and
completions program;
— Completed four (4.0 net) wells at Wheatland that were drilled in the
first quarter, of which two had come on stream by June 30, 2017 and the
other two came on-stream in the third quarter;
— Recorded net earnings of $1.1 million, compared to a net loss of $43.2
million in the same period in 2016, due primarily to higher adjusted
funds from operations and positive variances in several non-cash items,
including decreased impairment losses, increases in unrealized hedging
gains and a decrease in accretion expense, partially offset by higher
depletion, depreciation and amortization expenses; and
— Exited the second quarter with bank debt of $47 million drawn on the
Company’s $65 million credit facility. The Company and its lending
syndicate are progressing with new financing arrangements.

/T/

(1) Adjusted funds from operations and operating netbacks are non-IFRS measures
and are defined in this release under “Other Advisories”.

FINANCIAL AND OPERATING HIGHLIGHTS

/T/

—————————————————————————-
—————————————————————————-

Three Months Ended Six Months Ended
June 30, 2017 June 30, 2017
—————————————————————————-
—————————————————————————-
($000s except per unit
amounts) 2017 2016 2017 2016
—————————————————————————-
—————————————————————————-
Financial
Oil and natural gas revenue 21,682 9,151 40,890 16,354
Net earnings 1,066 (43,223) 8,328 (40,026)
Per share – basic 0.01 (0.44) 0.08 (0.41)
Per share – diluted 0.01 (0.44) 0.07 (0.41)
Adjusted funds from
operations(1) 7,060 3,252 12,994 4,342
Per share – basic &
diluted 0.06 0.03 0.12 0.04
Capital expenditures (net of
proceeds from dispositions) 4,767 1,201 53,153 11,933
—————————————————————————-
—————————————————————————-
Production Volumes
Crude oil (bbls/d) 3,458 1,784 3,147 1,834
Natural gas (Mcf/d) 13,136 9,733 14,099 8,715
Natural gas liquids (bbls/d) 225 134 259 129
—————————————————————————-
Total (boe/d) 5,872 3,540 5,756 3,416
—————————————————————————-
% Liquids 63% 54% 59% 57%
—————————————————————————-
—————————————————————————-
Average Realized Prices
Crude oil ($/bbl) 55.42 47.62 55.63 40.43
Natural gas ($/Mcf) 3.00 1.37 2.98 1.58
Natural gas liquids ($/bbl) 32.19 17.22 34.00 14.82
—————————————————————————-
Total ($/boe) 40.58 28.41 39.25 26.30
—————————————————————————-
—————————————————————————-
Operating Netback ($/boe)(2)
Realized price 40.58 28.41 39.25 26.30
Royalties (5.63) (2.87) (5.80) (2.53)
Operating costs (18.90) (15.60) (17.98) (18.43)
—————————————————————————-
Operating netback 16.05 9.94 15.47 5.34
Realized gains on derivative
instruments 2.15 7.88 1.78 9.85
—————————————————————————-
Operating netback, after
realized gains on
derivative instruments 18.20 17.82 17.25 15.19
—————————————————————————-
—————————————————————————-
Notes:
(1)(2) Adjusted funds from operations and operating netback are non-IFRS
measures and are defined below under “Other Advisories”.

—————————————————————————-
—————————————————————————-
Capital Structure As at As at
($000s) June 30, 2017 December 31, 2016
—————————————————————————-
Working capital (deficit)(1) (7,400) (4,380)
Long-term debt (50,429) (15,047)
——————————————
Total net debt(2) (57,829) (19,427)
Current debt capacity(3) 13,288 34,117
Common shares outstanding (in
millions) 115.9 104.2
—————————————————————————-
—————————————————————————-
Notes:
(1) Working capital (deficit) is a non-IFRS measure calculated as current
assets less current liabilities excluding the current portion of derivative
instruments, the current portion of decommissioning liabilities and flow-
through share premium. See “Other Advisories” below.
(2) Net debt is a non-IFRS measure, calculated by adding working capital
(deficit) and long-term debt. See “Other Advisories” below.
(3) Current debt capacity reflects the credit facility of $65 million at
June 30, 2017 and $55 million at December 31, 2016, net of amounts drawn
thereunder.

/T/

As at June 30, 2017, total net debt increased by $38.4 million from December
31, 2016 as a result of the Red Earth Acquisition which was funded primarily
through bank debt. Total net debt decreased by $1.9 million from March 31, 2017
as we deferred a portion of our original budgeted second quarter capital
spending and applied free cash flow towards net debt reduction. The deferral in
capital spending was a deliberate measure to preserve liquidity amidst the
volatile commodity price environment during the second half of the quarter, as
the Company remains intent on scaling the 2017 capital budget to commodity
prices as part of a continued focus on prudent capital management.

/T/

—————————————————————————-

Three months ended Six months ended
June 30 June 30
—————————————————————————-
2017 2016 2017 2016
—————————————————————————-
Drilling Activity
Gross wells – – 4 3
Working interest wells – – 4.0 2.9
Success rate, net wells (%) N/A N/A 100 100
—————————————————————————-
—————————————————————————-

/T/

OPERATIONS UPDATE

Wheatland, AB

Prairie Provident continued to focus on executing our capital program at
Wheatland. Our second quarter capital activity levels were reduced due to the
seasonal impacts of spring break up, delayed scheduling of frac crews, and a
conscious decision to defer a portion of our capital spending in response to
commodity price uncertainty. Invested capital was largely directed to the
completion, equipping and tie-in of four (4.0 net) wells drilled in the first
quarter, of which two were brought on production in the middle May and at the
end of June, 2017, respectively, and the other two were brought on-stream in
July and August, 2017.

PPR provided an overview of initial test results for each well in our June 7,
2017 operations update release. For the first 30 days of on-stream production,
Wayne-1 and Wayne-3 wells had average production of approximately 270 boe/d
(76% liquids) and 208 boe/d (18% liquids), respectively. The Wayne-2 produced
an average of approximately 111 boe/d (37% liquids) for the first 13 days of
on-stream production, while it was also retrieving load fluids. Entice-1 has
been on production for 8 days and is currently producing at 272 boe/d (11%
liquids). The Company cautions that initial production rates are not
necessarily indicative of long-term well or reservoir performance or of
ultimate recovery. Actual results will differ from those realized during an
initial short-term production period, and the difference may be material.

Area production in the second quarter averaged approximately 2,240 boe/d (26%
light / medium oil), which contributed to stronger corporate volumes despite
being negatively impacted by third-party facility outages of approximately 130
boe/d. To date, a total number of 22 (20.6 net) wells have been drilled in the
area.

PPR’s evolution towards pad drilling and mono-bore drilling design over past
periods has helped to maintain reduced drilling cycle times that currently
average approximately 8.5 days at Wheatland. This improvement also
significantly reduces surface costs, lowers the environmental footprint and
increases the anticipated return on capital. While we have seen cost inflation
from oilfield service providers and suppliers, we strive to maintain
efficiencies through a continued focus on cost control.

Princess, AB

Our Princess properties averaged 380 boe per day (84% medium oil) during the
second quarter of 2017. We have identified 15 potential drilling locations in
the Detrital and Glauconite formations and have conducted pre-drilling
activities on four of the locations, including seeking the necessary approvals
to commence drilling in the third and fourth quarters. In the third quarter,
PPR plans to tie-in two discovery wells, a Detrital well that flow tested at
300 boe/d (90% oil) over a four-day production test period and Glauconite well
that flow tested at 900 boe/d (10% oil) over a two-day production test period.
We continue to evaluate options to alleviate gas and water handling bottlenecks
at Princess which is expected to support expanded drilling.

The Company cautions that test results and initial production rates are not
necessarily indicative of long-term well or reservoir performance or of
ultimate recovery. Actual results will differ from those realized during
testing or an initial short-term production period, and the difference may be
material.

Evi, AB

At Evi, exploration and development capital expenditures totaled $0.4 million
for the second quarter, and were primarily directed to waterflood activities.
Average area production for the quarter was 2,375 boe per day (98% light oil)
reflecting the first full quarter of production impact from the Red Earth
Acquisition that closed on March 22, 2017. Production for the quarter was
negatively impacted by extended downtime due to wet weather conditions and road
bans. Certain properties acquired through the Red Earth Acquisition were behind
their ordinary maintenance schedule, which also resulted in some outages.

In the main Evi area, 8.25 of a total 37 sections are under waterflood with 24
injection wells (22 horizontals and 2 verticals) currently in operation. PPR
may elect to accelerate our waterflood program within the 2018 capital budget
given the additional expansion potential offered by the Red Earth Acquisition.
Our long-term full field waterflood scenario contemplates converting a further
20 producing wells to injection wells at projected total future costs of
approximately $20 million, which is anticipated to improve reserves at
attractive finding and development costs.

The Evi properties provide the Company with a stable cash flow base that
complements our development programs in other areas, lowers decline rates, and
generates robust rates of return, payback and recycle ratios, even at current
strip pricing. PPR believes that the waterflood program will continue to
stabilize production from this play and enhance our long-term recovery
potential.

2017 OUTLOOK AND GUIDANCE

PPR remains true to our corporate strategy, and conservatively executed our
capital program while seeking to control costs and manage debt levels. During
the first half of 2017, we invested approximately $17 million of our projected
full-year $25 to $35 million 2017 exploration and development budget, with our
current production volumes running close to our expected annual average. We
will continue to focus on improving corporate netbacks by targeting higher
value product streams (oil and condensate-rich liquids) and taking steps to
improve capital efficiencies through pad drilling as well as focusing on those
operating areas that have underutilized infrastructure capacity.

During the second quarter, the Company and syndicate of lenders for our
existing $65 million credit facility (comprised of a $55 million revolver and a
$10 million operating facility) (the “Facility”) extended the term-out date of
the Facility until August 18, 2017, with a maturity date of July 3, 2018. As at
June 30, 2017, the Facility was drawn approximately 72%. This leverage level is
supported by our reserves base and future cash flows, but remains above our
target levels.

Despite continued commodity price volatility, PPR remains focused on delivering
growth through production and funds from operations while continuing to
preserve our financial position. As such, PPR is targeting the lower end of our
previously announced 2017 guidance range and are forecasting a capital budget
of approximately $25 million. We currently plan to defer a portion of the
fourth quarter development to 2018, which will lower our expected exit
production to between 6,000 and 6,500 boe/d without significant impact to our
annual production guidance. We will continue to monitor the pricing conditions
and adjust the pace of our development as warranted to protect our project
economics.

PPR’s hedging program provides price protection for approximately 70% of our
2017 estimated base production volumes (net of royalties), and based on our
2017 forecast adjusted funds from operations(2); we anticipate adequate
liquidity to fund our capital budget without incurring additional debt.

The Company continues to build on our existing asset base and have identified
an attractive inventory of potential locations for conventional horizontal or
vertical development, and we anticipate this inventory would provide the
Company with more than five years of drilling based on our current pace of
investment. With the positive impact of our waterflood, we believe that PPR’s
corporate decline rates will continue to come down and allow us to stabilize
production levels over the medium and longer term.

ABOUT PRAIRIE PROVIDENT:

Prairie Provident is a Calgary-based company engaged in the exploration and
development of oil and natural gas properties in Alberta. The Company’s
strategy is to grow organically in combination with accretive acquisitions of
conventional oil prospects, which can be efficiently developed. Prairie
Provident’s operations are primarily focused at Wheatland and Princess in
Southern Alberta targeting the Ellerslie and the Lithic Glauc formations, along
with an early stage waterflood project at Evi in the Peace River Arch. Prairie
Provident protects its balance sheet through an active hedging program and
manages risk by allocating capital to opportunities offering maximum
shareholder returns.

(2) Assumed price forecasts of USD$50.00/bbl WTI, CAD$2.50/GJ AECO, and a
Canadian/US dollar exchange rate of $0.80.

FORWARD-LOOKING STATEMENTS

This news release contains certain forward-looking information and statements
within the meaning of applicable Canadian securities laws. Statements involving
forward-looking information relate to future performance, events or
circumstances, and are based upon internal assumptions, plans, intentions,
expectations and beliefs. All statements other than statements of current or
historical fact constitute forward-looking information. Forward-looking
information is typically, but not always, identified by words such as
“anticipate”, “believe”, “expect”, “intend”, “plan”, “budget”, “forecast”,
“target”, “estimate”, “propose”, “potential”, “project”, “continue”, “may”,
“will”, “should” or similar words suggesting future outcomes or events or
statements regarding an outlook. In particular, but without limiting the
foregoing, this news release contains forward-looking information and
statements pertaining to the following: new financing arrangements; projected
capital expenditure plans, production and product mix; development and
exploration plans at Wheatland, Princess and Evi (including with respect to
numbers of wells and drilling locations at Wheatland and Princess and Evi
waterflood activities and expectations); continued focus on corporate netbacks
and capital efficiency and anticipated activities in furtherance thereof;
targeting the lower end of the Company’s previously-announced 2017 guidance
range; projected 2017 exit production; deferral of a portion of fourth quarter
development to 2018; drilling inventory numbers; alleviation of gas and water
handling bottlenecks at Princess and expected support for expanded drilling;
the potential acceleration of the Evi waterflood program for the 2018 budget;
potential conversion of additional producing wells to injection wells at Evi
and projected costs thereof; and expected benefits of Evi waterflood
initiatives (including with respect to finding and development costs,
stabilized production and enhanced recovery potential).

The forward-looking information and statements contained in this news release
reflect material factors and expectations and assumptions of Prairie Provident
including, without limitation: the Company’s ability to reach an agreement with
counterparties to new financing arrangements on terms and conditions that are
acceptable to the Company; commodity prices and foreign exchange rates for 2017
and beyond; the timing and success of future drilling, development and
completion activities (and the extent to which the results thereof meet
Management’s expectations); the continued availability of financing (including
borrowings under the Company’s credit facility) and cash flow to fund current
and future expenditures, with external financing on acceptable terms; future
capital expenditure requirements and the sufficiency thereof to achieve the
Company’s objectives; the performance of both new and existing wells;
production from the Red Earth Acquisition and capital and operating costs in
respect thereof; the timely availability and performance of facilities,
pipelines and other infrastructure in areas of operation; the geological
characteristics and quality of Prairie Provident’s properties and the
reservoirs in which the Company conducts oil and gas activities (including
field production and decline rates); successful integration of the Red Earth
Acquisition assets into the Company’s operations; the successful application of
drilling, completion and seismic technology; future exploration, development,
operating, transportation, royalties and other costs; the Company’s ability to
economically produce oil and gas from its properties and the timing and cost to
do so; the predictability of future results based on past and current
experience; prevailing weather conditions; prevailing legislation and
regulatory requirements affecting the oil and gas industry (including royalty
regimes); the timely receipt of required regulatory approvals; the availability
of capital, labour and services on timely and cost-effective basis; the
creditworthiness of industry partners and the ability to source and complete
acquisitions; and the general economic, regulatory and political environment in
which the Company operates. Prairie Provident believes the material factors,
expectations and assumptions reflected in the forward-looking information and
statements are reasonable but no assurance can be given that these factors,
expectations and assumptions will prove to be correct.

All information and statements that are in the nature of a financial outlook
are forward-looking statements as they relate to prospective financial
performance, financial position or cash flows based on assumptions about future
economic conditions and courses of action. Financial outlook information in
this news release includes statements regarding the Company’s expected ability
to fund its capital budget without incurring additional debt based on 2017
forecast adjusted future funds from operations, which are subject to the
assumptions, risk factors, limitations and qualifications set forth above. All
financial outlook information is made as of the date of this news release and
is provided for the sole purpose of describing the Company’s internal
expectations on cash flow generation for 2017, and should not be used, and may
be inappropriate for, any other purpose.

Although Prairie Provident believes that the expectations and assumptions upon
which the forward-looking information in this news release is based are
reasonable based on currently available information, undue reliance should not
be placed on such information, which is inherently uncertain, relies on
assumptions and expectations, and is subject to known and unknown risks,
uncertainties and other factors, both general and specific, many of which are
beyond the Company’s control, that may cause actual results or events to differ
materially from those indicated or suggested in the forward-looking
information. Prairie Provident can give no assurance that the forward-looking
information contained herein will prove to be correct or that the expectations
and assumptions upon which they are based will occur or be realized. These
include, but are not limited to: risks inherent to oil and gas exploration,
development, exploitation and production operations and the oil and gas
industry in general, including geological, technical, engineering, drilling,
completion, processing and other operational problems and potential delays,
cost overruns, production or reserves loss or reduction in production, and
environmental, health and safety implications arising therefrom; uncertainties
associated with the estimation of reserves, production rates, product type and
costs; adverse changes in commodity prices, foreign exchange rates or interest
rates; the ability to access capital when required and on acceptable terms; the
ability to secure required services on a timely basis and on acceptable terms;
increases in operating costs; environmental risks; changes in laws and
governmental regulation (including with respect to royalties, taxes and
environmental matters); adverse weather or break-up conditions; competition for
labour, services, equipment and materials necessary to further the Company’s
oil and gas activities; and changes in plans with respect to exploration or
development projects or capital expenditures in respect thereof. These and
other risks are discussed in more detail in the Company’s current annual
information form and other documents filed by it from time to time with
securities regulatory authorities in Canada, copies of which are available
electronically under Prairie Provident’s issuer profile on the SEDAR website at
www.sedar.com and on the Company’s website at www.ppr.ca. This list is not
exhaustive. With respect to the Company’s efforts to progress with new
financing arrangements, while Prairie Provident believes that it will
ultimately be successful in reaching agreement with counterparties on
definitive terms and conditions thereof, no assurance can be given that
agreement will in fact be reached or, if it is, that the definitive terms and
conditions will be at least as favorable to the Company than those of the
existing credit facilities or will improve Prairie Provident’s liquidity
profile.

The forward-looking information and statements contained in this news release
speak only as of the date of this news release, and Prairie Provident assumes
no obligation to publicly update or revise them to reflect new events or
circumstances, or otherwise, except as may be required pursuant to applicable
laws. All forward-looking information and statements contained in this news
release are expressly qualified by this cautionary statement.

OTHER ADVISORIES

The oil and gas industry commonly expresses production volumes and reserves on
a “barrel of oil equivalent” basis (“boe”) whereby natural gas volumes are
converted at the ratio of six thousand cubic feet to one barrel of oil. The
intention is to sum oil and natural gas measurement units into one basis for
improved analysis of results and comparisons with other industry participants.
A boe conversion ratio of six thousand cubic feet to one barrel of oil is based
on an energy equivalency conversion method primarily applicable at the burner
tip. It does not represent a value equivalency at the wellhead nor at the plant
gate, which is where Prairie Provident sells its production volumes. Boes may
therefore be a misleading measure, particularly if used in isolation. Given
that the value ratio based on the current price of crude oil as compared to
natural gas is significantly different from the energy equivalency ratio of
6:1, utilizing a 6:1 conversion ratio may be misleading as an indication of
value.

Non-IFRS Measures

The Company uses certain terms in this news release and within the MD&A that do
not have a standardized or prescribed meaning under International Financial
Reporting Standards (IFRS), and, accordingly these measures may not be
comparable with the calculation of similar measures used by other companies.
For a reconciliation of each non-IFRS measure to its nearest IFRS measure,
please refer to the “Non-IFRS Measures” section in the MD&A. Non-IFRS measures
are provided as supplementary information by which readers may wish to consider
the Company’s performance, but should not be relied upon for comparative or
investment purposes. The non-IFRS measures used in this news release are
summarized as follows:

Working Capital – Working capital (deficit) is calculated as current assets
less current liabilities excluding the current portion of derivative
instruments, the current portion of decommissioning liabilities and
flow-through share premium. This measure is used to assist management and
investors in understanding liquidity at a specific point in time. The current
portion of derivatives instruments is excluded as management intends to hold
derivative contracts through to maturity rather than realizing the value at a
point in time through liquidation; the current portion of decommissioning
expenditures is excluded as these costs are discretionary; and the current
portion of flow-through share premium liabilities are excluded as it is a
non-monetary liability.

Net Debt – Net debt is defined as long-term debt plus working capital surplus
or deficit. Net debt is commonly used in the oil and gas industry for assessing
the liquidity of a company.

Operating Netback – Operating netback is a non-IFRS measure commonly used in
the oil and gas industry. This measure assists management and investors to
evaluate operating performance at the oil and gas lease level. Operating
netbacks included in this news release were determined by calculating oil and
gas revenues less royalties less operating costs, and dividing that number by
gross working interest production. Operating netback, including realized
commodity (loss) and gain, adjusts the operating netback for only realized
gains and losses on derivative instruments.

Adjusted Funds from Operations – Adjusted funds from operations is calculated
based on cash flow from operating activities before changes in non-cash working
capital, transaction costs, restructuring costs, decommissioning expenditures
and other non-recurring items. Management believes that such a measure provides
an insightful assessment of Prairie Provident’s operating performance on a
continuing basis by eliminating certain non-cash charges and charges that are
non-recurring and uses the measure to assess its ability to finance operating
activities, capital expenditures and debt repayment. Adjusted funds from
operations as presented is not intended to represent cash flow from operating
activities, net earnings or other measures of financial performance calculated
in accordance with IFRS.

– END RELEASE – 09/08/2017

For further information:
Prairie Provident Resources Inc.
Tim Granger
President and Chief Executive Officer
(403) 292-8110
tgranger@ppr.ca
www.ppr.ca

COMPANY:
FOR: PRAIRIE PROVIDENT RESOURCES INC.
TSX SYMBOL: PPR

INDUSTRY: Energy and Utilities – Oil and Gas
RELEASE ID: 20170809CC0065

Press Release from Marketwired 1-866-736-3779

Peyto Announces Q2 2017 Results, Maintains Industry Leading Cash Costs – Part 1

August 9, 2017 by The Canadian Press

FOR: PEYTO EXPLORATION & DEVELOPMENT CORP.
TSX SYMBOL: PEY

Date issue: August 09, 2017
Time in: 4:30 PM e

Attention:

CALGARY, ALBERTA–(Marketwired – Aug. 9, 2017) – Peyto Exploration &
Development Corp. (TSX:PEY) (“Peyto” or the “Company”) is pleased to present
its operating and financial results for the second quarter of the 2017 fiscal
year. A 75% operating margin(1) and a 22% profit margin(2) in the quarter
delivered an annualized 10% return on equity (ROE) and 8% return on capital
employed (ROCE). Additional highlights included:

/T/

— Earnings of $0.24/share, dividends of $0.33/share. Earnings of $40

million were generated in the quarter while dividends of $54 million
were paid to shareholders. Dividend payments represented a before tax
payout ratio of 41% of Funds from Operations (“FFO”), down from 53% in
Q2 2016. The Company has never incurred a write down or recorded an
impairment and this quarter represents Peyto’s 50th consecutive quarter
of earnings.

— Funds from operations of $0.81/share. Generated $133 million in FFO in

Q2 2017 up 31% from $102 million in Q2 2016 (29%/share) as 11% higher
production was combined with 15% higher commodity prices. For the first
half of 2017, funds from operations were 8% higher than capital
expenditures, or $21 million of free cashflow (before dividend
payments).

— Total cash costs of $0.85/Mcfe (or $0.68/Mcfe ($4.11/boe) excluding

royalties). Industry leading total cash costs, including $0.17/Mcfe
royalties, $0.24/Mcfe operating costs, $0.18/Mcfe transportation,
$0.05/Mcfe G&A and $0.21/Mcfe interest, combined with a realized price
of $3.36/Mcfe, resulting in a $2.51/Mcfe ($15.04/boe) cash netback, up
18% from $2.12/Mcfe in Q2 2016.

— Capital investment of $98 million. A total of 25 gross wells (24 net)

were drilled in the second quarter, 24 gross wells (22 net) were
completed, and 29 gross wells (26 net) brought on production. Over the
last 12 months new wells brought on production accounted for 34,929
boe/d at the end of the quarter, which, when combined with a trailing
twelve month capital investment of $495 million, equates to an
annualized capital efficiency of $14,160/boe/d. Peyto had 19 gross wells
that were waiting on completion and/or tie in representing an expected
11,500 boe/d of behind pipe production which would have reduced the
capital efficiency to the $11,000/boe/d target levels

— Production per share up 9%. Second quarter 2017 production of 585

MMcfe/d (97,531 boe/d) was up 11% from Q2 2016. The backlog of drilled
but uncompleted wells has now been connected with August daily
production to date averaging 111,000 boe/d.

/T/

Second Quarter 2017 in Review

The plan to take advantage of reduced industry activity and reduced service
costs in the second quarter was partly hampered by heavy rains and wet ground
conditions that limited the majority of drilling and completion activity to the
month of June. Despite the challenging surface conditions Peyto was still able
to drill and complete 25 new wells and bring 29 wells on production. Average
drilling costs of $1.8 million/well and completion costs of $0.9 million/well
were achieved, consistent with 2016 levels. The liquids pipeline constructed in
Q1 2017, connecting four of the nine gas plants, was utilized for the last half
of the quarter to reduce liquids trucking in the quarter, increasing the
Company’s realized liquids prices by approximately $2.50/bbl, and reducing road
maintenance and environmental emissions. Operating costs were lower as warmer
weather reduced chemical consumption and facility utilizations were optimized.
Peyto added 13 sections of new land with pre-identified drilling locations to
its inventory of future prospects for an average price of $113/acre. A strict
focus on cost control improved operating margins resulting in increased year
over year returns on capital employed.

1. Operating Margin is defined as funds from operations divided by revenue
before royalties but including realized hedging gains/losses.
2. Profit Margin is defined as net earnings for the quarter divided by revenue
before royalties but including realized hedging gains/losses. Natural gas
volumes recorded in thousand cubic feet (mcf) are converted to barrels of oil
equivalent (boe) using the ratio of six (6) thousand cubic feet to one (1)
barrel of oil (bbl). Natural gas liquids and oil volumes in barrel of oil (bbl)
are converted to thousand cubic feet equivalent (Mcfe) using a ratio of one (1)
barrel of oil to six (6) thousand cubic feet. This could be misleading,
particularly if used in isolation as it is based on an energy equivalency
conversion method primarily applied at the burner tip and does not represent a
value equivalency at the wellhead.

/T/

————————————————————–

Three Months Ended June
30
2017 2016
————————————————————–
Operations
Production
Natural gas (mcf/d) 535,274 489,337
Oil & NGLs (bbl/d) 8,319 6,621
Thousand cubic feet equivalent
(mcfe/d @ 1:6) 585,187 529,064
Barrels of oil equivalent (boe/d @
6:1) 97,531 88,177
Production per million common shares
(boe/d)(i) 592 545
Product prices
Natural gas ($/mcf) 2.92 2.60
Oil & NGLs ($/bbl) 48.33 41.46
Operating expenses ($/mcfe) 0.24 0.26
Transportation ($/mcfe) 0.18 0.17
Field netback ($/mcfe) 2.77 2.39
General & administrative expenses
($/mcfe) 0.05 0.06
Interest expense ($/mcfe) 0.21 0.21
Financial ($000, except per share(i))
Revenue 178,982 140,891
Royalties 9,071 4,874
Funds from operations 133,487 102,178
Funds from operations per share 0.81 0.63
Total dividends 54,408 53,735
Total dividends per share 0.33 0.33
Payout ratio 41 53
Earnings 39,957 9,102
Earnings per diluted share 0.24 0.06
Capital expenditures 97,738 50,634
Weighted average common shares
outstanding 164,874,175 161,845,999
As at June 30
End of period shares outstanding
(includes shares to be issued
Net debt
Shareholders’ equity
Total assets
(i)all per share amounts using weighted average common shares
outstanding

————————————–

%Six Months Ended June 30 %
Change 2017 2016 Change
————————————–

9% 542,118 528,284 3%
26% 8,949 6,815 31%
11% 595,813 569,171 5%
11% 99,302 94,862 5%
9% 602 591 2%

12% 2.94 2.85 3%
17% 48.23 37.42 29%
-8% 0.26 0.25 4%
6% 0.18 0.16 13%
16% 2.78 2.57 8%
-17% 0.05 0.04 25%
– 0.20 0.19 5%

27% 366,932 320,243 15%
86% 19,707 11,859 66%
31% 272,792 242,085 13%
29% 1.66 1.51 10%
1% 108,796 106,255 2%
– 0.66 0.66 –
-23% 40 44 -9%
339% 80,211 51,045 57%
300% 0.49 0.32 53%
93% 251,612 226,397 11%
2% 164,837,609 160,494,262 3%

164,874,175 164,630,168 –
1,218,879 1,018,796 20%
1,647,133 1,656,995 -1%
3,604,373 3,389,786 6%
(i)all per share amounts using
weighted average common shares
outstanding

—————————————————————————-

Three Months Ended Six Months Ended June
June 30 30
($000 except per share) 2017 2016 2017 2016
—————————————————————————-
Cash flows from operating
activities 127,980 103,123 249,117 241,241
Change in non-cash working
capital 2,191 (9,279) 18,351 (10,391)
Change in provision for
performance based
compensation 3,316 8,334 5,324 11,235
—————————————————————————-
Funds from operations 133,487 102,178 272,792 242,085
—————————————————————————-
Funds from operations per
share 0.81 0.63 1.66 1.51
—————————————————————————-

/T/

(1) Funds from operations – Management uses funds from operations to analyze
the operating performance of its energy assets. In order to facilitate
comparative analysis, funds from operations is defined throughout this report
as earnings before performance based compensation, non-cash and non-recurring
expenses. Management believes that funds from operations is an important
parameter to measure the value of an asset when combined with reserve life.
Funds from operations is not a measure recognized by Canadian generally
accepted accounting principles (“GAAP”) and does not have a standardized
meaning prescribed by GAAP. Therefore, funds from operations, as defined by
Peyto, may not be comparable to similar measures presented by other issuers,
and investors are cautioned that funds from operations should not be construed
as an alternative to net earnings, cash flow from operating activities or other
measures of financial performance calculated in accordance with GAAP. Funds
from operations cannot be assured and future dividends may vary.

Exploration & Development

Second quarter 2017 activity was primarily focused in the Greater Sundance area
as wet conditions limited access in Brazeau and other areas during the quarter.
Four drilling rigs were active during April and May, while nine rigs were
drilling during June. The second quarter drilling activity was entirely focused
on the Spirit River group of formations including the Notikewin, Falher and
Wilrich. In total, 25 horizontal wells were drilled as shown in the following
table:

/T/

Field

Kisku/
Zone Sundance Nosehill Wildhay Ansell Berland Kakwa Brazeau
—————————————————————————-
—————————————————————————-
Belly River
Cardium
Notikewin 2 2 1 3
Falher 1 1 1
Wilrich 9 1 3 1
Bluesky
—————————————————————————-
—————————————————————————-
Total 12 3 5 5
—————————————————————————-
—————————————————————————-

Total
Wells
Drilled

Zone
———————-
———————-
Belly River
Cardium
Notikewin 8
Falher 3
Wilrich 14
Bluesky
———————-
———————-
Total 25
———————-
———————-

/T/

Horizontal well drilling costs in Q2 2017 were in line with Q1 and with 2016
average costs despite the wetter conditions and delays associated with spring
breakup. Completion costs (per meter of horizontal lateral) were down from Q1
2017 due to lower service costs and lower completion intensity in the Sundance
area versus the Brazeau area. The following table illustrates the progression
of cost optimization designed to contribute to lower overall development costs
and ultimately greater returns:

/T/

2017 2017
2010 2011 2012 2013 2014 2015 2016 Q1 Q2
—————————————————————————-
Gross Hz
Spuds 52 70 86 99 123 140 126 40 25
Measured
Depth (m) 3,762 3,903 4,017 4,179 4,251 4,309 4,197 4,313 4,143

Drilling
($MM/well) $2.76 $2.82 $2.79 $2.72 $2.66 $2.16 $1.82 $1.82 $1.89
$ per meter $734 $723 $694 $651 $626 $501 $433 $423 $457

Completion
($MM/well) $1.36 $1.68 $1.67 $1.63 $1.70 $1.21 $0.86 $1.09 $0.96
Hz Length (m) 1,335 1,303 1,358 1,409 1,460 1,531 1,460 1,547 1,498
$ per Hz
Length (m) $1,017 $1,286 $1,231 $1,153 $1,166 $792 $587 $705 $641
$ ‘000 per
Stage $231 $246 $257 $188 $168 $115 $79 $83 $76
—————————————————————————-

/T/

Capital Expenditures

During the second quarter of 2017, Peyto spent $48 million on drilling, $21
million on completions, $9 million on wellsite equipment and tie-ins, $17
million on facilities and major pipeline projects, and $2 million on new Crown
lands and seismic, for total capital investments of $98 million.

In addition to the 25 gross (24 net) horizontal wells drilled, 24 gross (23
net) wells were completed and 29 gross (26 net) wells were equipped and tied
in. Peyto completed construction and commissioned its Greater Sundance liquids
pipeline in the second quarter and installed a 6 km, 10″ gathering line in West
Brazeau, which crosses the Nordegg river and connects several new locations to
the Brazeau gathering system.

Peyto also purchased 13 sections of new Crown land at sales in the second
quarter, mostly in the Greater Sundance area, for an average purchase price of
$113/acre.

Commodity Prices

Average daily AECO natural gas prices were $2.64/GJ in Q2 2017, up slightly
from $2.58/GJ the quarter before but up significantly from the $1.33/GJ in Q2
2016. US Henry Hub spot prices increased in a similar fashion. A return to
historical norms for natural gas storage helped improve supply demand
fundamentals contributing to the increase.

Peyto Announces Q2 2017 Results, Maintains Industry Leading Cash Costs – Part 2

August 9, 2017 by The Canadian Press

On average for Q2 2017, Peyto realized a natural gas price of $2.54/GJ or
$2.92/Mcf. This was the result of a combination of approximately 17% of natural
gas production being sold in the daily or monthly spot market at an average of
$2.59/GJ ($2.99/Mcf) and 83% having been pre-sold at an average hedged price of
$2.52/GJ (prices reported net of TCPL fuel charges).

In the second quarter of 2017, lower realized liquid propane prices combined
with a progressively increasing carbon tax, which was imposed on Peyto’s Oldman
deep cut plant, resulted in less propane recoveries than in Q1 2017. As a
result, Peyto’s Q2 2017 blended, realized, oil and natural gas liquids price
was $48.33/bbl, which represented 78% of the $61.95/bbl average Canadian Light
Sweet posted price. Details of realized commodity prices by component are shown
in the following table:

Commodity Prices by Component

/T/

—————————————————————————-

Three Months ended
June 30
2017 2016
—————————————————————————-
AECO monthly ($/GJ) 2.63 1.18
AECO daily ($/GJ) 2.64 1.33
Henry Hub spot ($US/MMBTU) 3.08 2.14
—————————————————————————-
Natural gas – prior to hedging ($/GJ) 2.59 1.21
($/mcf) 2.99 1.38
—————————————————————————-
Natural gas – after hedging ($/GJ) 2.54 2.26
($/mcf) 2.92 2.60
—————————————————————————-

—————————————————————————-
Oil and natural gas liquids ($/bbl)

Condensate ($/bbl) 57.60 47.83
Propane ($/bbl) 13.39 0.40
Butane ($/bbl) 30.81 19.52
Pentane ($/bbl) 59.93 50.67
—————————————————————————-
Total Oil and natural gas liquids ($/bbl) 48.33 41.46
—————————————————————————-
Cnd Light Sweet stream ($/bbl) 61.95 54.70
—————————————————————————-

/T/

Liquids prices are Peyto realized prices in Canadian dollars adjusted for
fractionation and transportation.

Financial Results

Approximately 20%, or $0.69/Mcfe, of Peyto’s revenue come from its liquids
sales while 80%, or $2.67/Mcfe, came from natural gas. This liquids revenue
covered all cash costs but royalties. Cash costs of $0.85/Mcfe, included
royalties of $0.17/Mcfe, operating costs of $0.24/Mcfe, transportation costs of
$0.18/Mcfe, G&A of $0.05/Mcfe and interest costs of $0.21/Mcfe. Cash costs were
lower than the previous quarter due to reductions in operating costs and
royalties, partially offset by increases in transportation, G&A and interest.
These total cash costs, when deducted from realized revenues of $3.36/Mcfe,
resulted in a cash netback of $2.51/Mcfe or a 75% operating margin. Historical
cash costs and operating margins are shown in the following table. Going
forward, Peyto expects per unit cash costs will continue to trend towards
$0.80/Mcfe levels for the balance of 2017.

/T/

—————————————————

2015
($/Mcfe) Q1 Q2 Q3 Q4
—————————————————
Revenue 4.17 3.81 3.80 3.58
—————————————————
Royalties 0.18 0.13 0.15 0.13
Operating Costs 0.32 0.31 0.28 0.25
Transportation 0.15 0.15 0.16 0.16
G&A 0.04 0.04 0.02 0.05
Interest 0.20 0.19 0.19 0.16
————————————
Total Cash
Costs 0.89 0.82 0.80 0.75
—————————————————
Netback 3.28 2.99 3.00 2.83
—————————————————
Operating
Margin 79% 78% 79% 79%
—————————————————

———————————————————————

2016 2017
($/Mcfe) Q1 Q2 Q3 Q4 Q1 Q2
———————————————————————
Revenue 3.24 2.92 3.16 3.38 3.44 3.36
———————————————————————
Royalties 0.13 0.10 0.12 0.18 0.19 0.17
Operating Costs 0.23 0.26 0.25 0.26 0.29 0.24
Transportation 0.16 0.17 0.16 0.16 0.17 0.18
G&A 0.03 0.06 0.04 0.03 0.04 0.05
Interest 0.17 0.21 0.19 0.18 0.20 0.21
——————————————————
Total Cash
Costs 0.72 0.80 0.76 0.81 0.89 0.85
———————————————————————
Netback 2.52 2.12 2.40 2.57 2.55 2.51
———————————————————————
Operating
Margin 78% 73% 76% 76% 74% 75%
———————————————————————

/T/

Depletion, depreciation and amortization charges of $1.38/Mcfe, along with a
provision for deferred tax and market based bonus payments reduced the cash
netback to earnings of $0.75/Mcfe, or a 22% profit margin. Dividends of
$1.02/Mcfe were paid to shareholders.

Natural Gas Marketing

Peyto’s practice of layering in future sales in the form of fixed price swaps,
and thus smoothing out the volatility in natural gas prices, continued
throughout the quarter. For the balance of 2017, approximately 68% of gas
volumes have been hedged to protect against increased AECO volatility. The
following table summarizes the remaining hedged volumes and prices for the
upcoming years as of August 9, 2017:

/T/

—————————————————————————-

Future Sales Average Price (CAD)
—————————————————————————-
GJ Mcf $/GJ $/Mcf
—————————————————————————-
2017 70,490,000 61,295,652 2.61 3.00
2018 107,630,000 93,591,304 2.55 2.93
2019 13,550,000 11,782,609 2.47 2.85
2020 910,000 791,304 2.47 2.84
—————————————————————————-
Total 192,580,000 167,460,870 2.57 2.95
—————————————————————————-

/T/

(i)prices and volumes in mcf use Peyto’s historic heat content premium of 1.15.

In order to deal with restricted access to take-away capacity, Peyto has
arranged for excess firm transportation on the NGTL system north of the James
River receipt point of up to 120% of Peyto’s forecasted natural gas sales for
the remainder of the year. Specific monthly excess service is projected to
offset the outage forecast provided by NGTL and safeguard against potential
curtailments due to limited capacity. Beyond 2017, Peyto has secured new firm
transportation to accommodate its expected production growth.

Activity Update

Following an unusually wet spring breakup, continuous operations were resumed
in late June and have continued through July and into August. The backlog of
uncompleted wells accumulated during Q1 and carried through Q2 was effectively
eliminated over this period. Consequently, Peyto’s has recently reached record
daily production levels in excess of 115,000 BOE/d.

Peyto continues to run 9 drilling rigs (4 in Brazeau, 5 in Greater Sundance)
and since the end of the second quarter has spud 18 gross (16.5 net) wells,
completed 16 gross (16 net) wells, and tied in 22 gross (21.5 net) wells. Peyto
now expects to drill and tie-in 80 wells in the second half of 2017. Included
in this second half drilling will be step out Wilrich and Notikewin tests on
newly acquired lands in south Brazeau, as well as Wilrich step outs in a new
emerging area called Whitehorse. The Company has recently tied in 3 wells to a
third-party processing facility in Whitehorse and is encouraged by the early
results. Infrastructure plans for the Whitehorse area will be finalized in
early 2018 and will likely include construction of a Peyto facility to process
area volumes.

In addition, the site for the new Brazeau East gas plant is now ready, with the
construction timeline aligned with the fall drilling and tie-in schedule.
Pending installation of the first 70 mmcf/d of equipment, the Brazeau area will
have over 210 mmcf/d of processing capacity.

Summer gas prices have been extremely volatile and although Peyto has an active
hedging program, some volumes are still sold on the daily index. Ownership and
operatorship of 99% of the production and processing facilities provides the
flexibility to actively manage the daily volumes to ensure profit margins are
preserved.

Outlook

While natural gas prices have deteriorated of late, Management expects prices
will improve entering the fall for the winter heating season. The current and
future 5 year strip for AECO natural gas price is below $2.40/GJ and is
insufficient to sustain current Canadian gas production levels which would
result in a tightening of supply and demand. That said, the Company has
reviewed the economic returns of its remaining 2017 capital program in light of
the weaker price forecast and is confident the remaining drilling program
continues to make the economic return hurdle and deliver full cycle value
creation for shareholders.

As always, Peyto’s focus will be on maximizing efficiency and minimizing both
capital and cash costs throughout its business. This laser like focus on
profitability is unwavering and will continue to be used to direct capital to
the highest return opportunities within Peyto’s portfolio. This portfolio of
opportunities is growing, as Peyto adds new Crown lands with identified
drilling locations at historically low cost per acre. The Company’s operation
and financial flexibility, quality asset base and strong balance sheet position
Peyto to continue to be opportunistic in this environment.

Conference Call and Webcast

A conference call will be held with the senior management of Peyto to answer
questions with respect to the Q2 2017 financial results on August 10th, 2017 at
9:00 a.m. Mountain Daylight Time (MDT), or 11:00 a.m. Eastern Daylight Time
(EDT). Please see the press release for conference call details. To
participate, please call 1-844-492-6041 (North America) or 1-478-219-0837
(International). Shareholders and interested investors are encouraged to ask
questions about Peyto and its most recent results. Questions can be submitted
prior to the call at info@peyto.com. The conference call can also be accessed
through the internet at http://edge.media-server.com/m/p/m67ombbn. The
conference call will be archived on the Peyto Exploration & Development website
at www.peyto.com.

Management’s Discussion and Analysis

A copy of the second quarter report to shareholders, including the MD&A,
audited financial statements and related notes, is available at
http://www.peyto.com/Files/Financials/2017/Q22017MDandA.pdf and will be filed
at SEDAR, www.sedar.com at a later date.

Darren Gee
President and CEO
August 9, 2017

Certain information set forth in this document and Management’s Discussion and
Analysis, including management’s assessment of Peyto’s future plans and
operations, capital expenditures and capital efficiencies, contains
forward-looking statements. By their nature, forward-looking statements are
subject to numerous risks and uncertainties, some of which are beyond these
parties’ control, including the impact of general economic conditions, industry
conditions, volatility of commodity prices, currency fluctuations, imprecision
of reserve estimates, environmental risks, competition from other industry
participants, the lack of availability of qualified personnel or management,
stock market volatility and ability to access sufficient capital from internal
and external sources. Readers are cautioned that the assumptions used in the
preparation of such information, although considered reasonable at the time of
preparation, may prove to be imprecise and, as such, undue reliance should not
be placed on forward-looking statements. Peyto’s actual results, performance or
achievement could differ materially from those expressed in, or implied by,
these forward-looking statements and, accordingly, no assurance can be given
that any of the events anticipated by the forward-looking statements will
transpire or occur, or if any of them do so, what benefits Peyto will derive
there from. In addition, Peyto is providing future oriented financial
information set out in this press release for the purposes of providing clarity
with respect to Peyto’s strategic direction and readers are cautioned that this
information may not be appropriate for any other purpose. Other than is
required pursuant to applicable securities law, Peyto does not undertake to
update forward looking statements at any particular time. To provide a single
unit of production for analytical purposes, natural gas production and reserves
volumes are converted mathematically to equivalent barrels of oil (BOE). Peyto
uses the industry-accepted standard conversion of six thousand cubic feet of
natural gas to one barrel of oil (6 Mcf = 1 bbl). The 6:1 BOE ratio is based on
an energy equivalency conversion method primarily applicable at the burner tip.
It does not represent a value equivalency at the wellhead and is not based on
current prices. While the BOE ratio is useful for comparative measures and
observing trends, it does not accurately reflect individual product values and
might be misleading, particularly if used in isolation. As well, given that the
value ratio, based on the current price of crude oil to natural gas, is
significantly different from the 6:1 energy equivalency ratio, using a 6:1
conversion ratio may be misleading as an indication of value.

Peyto Exploration & Development Corp.
Condensed Balance Sheet (unaudited)
(Amount in $ thousands)

/T/

June 30 December 31
2017 2016
—————————————————————————-
Assets
Current assets
Cash 4,235 2,102
Accounts receivable 75,145 94,813
Due from private placement (Note 6) – 4,930
Derivative financial instruments (Note
8) 25,265 –
Prepaid expenses 32,448 13,385
—————————————————————————-
137,093 115,230
—————————————————————————-

Long-term derivative financial
instruments (Note 8) 5,030 –
Property, plant and equipment, net (Note
3) 3,462,250 3,347,859
—————————————————————————-
3,467,280 3,347,859
—————————————————————————-
3,604,373 3,463,089
—————————————————————————-
—————————————————————————-

Liabilities
Current liabilities
Accounts payable and accrued liabilities 107,571 158,173
Dividends payable (Note 6) 18,136 18,109
Derivative financial instruments (Note
8) – 119,280
Provision for future performance based
compensation (Note 7) 12,179 6,854
—————————————————————————-
137,886 302,416
—————————————————————————-

Long-term debt (Note 4) 1,205,000 1,070,000
Long-term derivative financial
instruments (Note 8) – 31,465
Provision for future performance based
compensation (Note 7) 6,848 4,499
Decommissioning provision (Note 5) 142,953 127,763
Deferred income taxes 464,553 386,012
—————————————————————————-
1,819,354 1,619,739
—————————————————————————-

Equity
Share capital (Note 6) 1,649,537 1,641,982
Shares to be issued (Note 6) – 4,930
Retained earnings (deficit) (27,809) 776
Accumulated other comprehensive (loss)
income (Note 6) 25,405 (106,754)
—————————————————————————-
1,647,133 1,540,934
—————————————————————————-
3,604,373 3,463,089
—————————————————————————-
—————————————————————————-

/T/

Peyto Announces Q2 2017 Results, Maintains Industry Leading Cash Costs – Part 3

August 9, 2017 by The Canadian Press

See accompanying notes to the financial statements.

Peyto Exploration & Development Corp.
Condensed Income Statement (unaudited)
(Amount in $ thousands except earnings per share amount)

/T/

Three months ended June 30 Six months ended June 30
2017 2016 2017 2016
—————————————————————————-
Revenue
Oil and gas sales 182,097 86,444 379,133 222,647
Realized (loss) gain
on hedges (Note 8) (3,115) 54,447 (12,201) 97,596
Royalties (9,071) (4,874) (19,707) (11,859)
—————————————————————————-
Petroleum and
natural gas sales,
net 169,911 136,017 347,225 308,384
—————————————————————————-

Expenses
Operating 13,018 12,732 28,703 25,273
Transportation 9,742 8,190 19,209 16,859
General and
administrative 2,646 2,853 4,959 4,710
Future performance
based compensation
(Note 7) 4,305 12,533 7,674 17,088
Interest 11,018 10,063 21,563 19,456
Accretion of
decommissioning
provision (Note 5) 715 543 1,465 1,147
Depletion and
depreciation (Note
3) 73,731 76,635 153,775 166,594
Gain on disposition
of assets (Note 3) – – – (12,668)
—————————————————————————-
115,175 123,549 237,348 238,459
—————————————————————————-
Earnings before
taxes 54,736 12,468 109,877 69,925
—————————————————————————-

Income tax
Deferred income tax
expense 14,779 3,366 29,666 18,880
—————————————————————————-
Earnings for the
period 39,957 9,102 80,211 51,045
—————————————————————————-
—————————————————————————-

—————————————————————————-
Earnings per share
(Note 6)
Basic and diluted $0.24 $0.06 $0.49 $0.32
—————————————————————————-
—————————————————————————-

/T/

See accompanying notes to the financial statements.

Peyto Exploration & Development Corp.
Condensed Statement of Comprehensive Income (Loss) (unaudited)
(Amount in $ thousands)

/T/

Three months ended June 30 Six months ended June 30
2017 2016 2017 2016
—————————————————————————-
Earnings for the
period 39,957 9,102 80,211 51,045
Other comprehensive
income (loss)
Change in unrealized
gain (loss) on cash
flow hedges 36,879 (110,733) 168,839 (15,178)
Deferred tax
(expense) recovery (10,798) 44,598 (48,881) 30,449
Realized loss (gain)
on cash flow hedges 3,115 (54,446) 12,201 (97,596)
—————————————————————————-
Comprehensive income
(loss) 69,153 (111,479) 212,370 (31,280)
—————————————————————————-
—————————————————————————-

/T/

See accompanying notes to the financial statements.

Peyto Exploration & Development Corp.
Condensed Statement of Changes in Equity (unaudited)
(Amount in $ thousands)

/T/

Six months ended June 30
2017 2016
—————————————————————————-
Share capital, beginning of period 1,641,982 1,467,264
—————————————————————————-
Common shares issued by private placement 7,574 7,644
Equity offering – 172,500
Common shares issuance costs (net of tax) (19) (5,402)
—————————————————————————-
Share capital, end of period 1,649,537 1,642,006
—————————————————————————-
—————————————————————————-

—————————————————————————-
Shares to be issued, beginning of period 4,930 3,769
—————————————————————————-
Shares issued (4,930) (3,769)
—————————————————————————-
Shares to be issued, end of period – –
—————————————————————————-
—————————————————————————-

—————————————————————————-
Retained earnings (deficit), beginning of 776 103,339
period
—————————————————————————-
Earnings for the period 80,211 51,045
Dividends (Note 6) (108,796) (106,255)
—————————————————————————-
Retained earnings (deficit), end of period (27,809) 48,129
—————————————————————————-
—————————————————————————-

—————————————————————————-
Accumulated other comprehensive income, (106,754) 49,185
beginning of period
—————————————————————————-
Other comprehensive loss (income) 132,159 (82,325)
—————————————————————————-
Accumulated other comprehensive (loss) income, 25,405 (33,140)
end of period
—————————————————————————-
—————————————————————————-

—————————————————————————-
Total equity 1,647,133 1,656,995
—————————————————————————-
—————————————————————————-

/T/

See accompanying notes to the financial statements.

Peyto Exploration & Development Corp.
Condensed Statement of Cash Flows (unaudited)
(Amount in $ thousands)

/T/

Three months ended June
30 Six months ended June 30
2017 2016 2017 2016
—————————————————————————-
Cash provided by (used in)
operating activities
Earnings 39,957 9,102 80,211 51,045
Items not requiring cash:
Deferred income tax 14,779 3,366 29,666 18,880
Depletion and depreciation 73,731 76,635 153,775 166,594
Accretion of
decommissioning provision 715 543 1,465 1,147
Gain on disposition of
assets – – – (12,668)
Long term portion of
future performance based
compensation 989 4,198 2,351 5,852
Change in non-cash working
capital related to
operating activities (2,191) 9,279 (18,351) 10,391
—————————————————————————-
127,980 103,123 249,117 241,241
—————————————————————————-
Financing activities
Issuance of common shares – 172,507 7,574 180,144
Issuance costs – (7,381) (26) (7,399)
Cash dividends paid (54,408) (53,142) (108,769) (105,631)
Increase (decrease) in bank
debt 70,000 (95,000) 135,000 –
—————————————————————————-
15,592 16,984 33,779 67,114
—————————————————————————-
Investing activities
Additions to property, plant
and equipment (97,738) (50,634) (251,612) (226,397)
Change in prepaid capital 3,770 233 (2,829) 7,733
Change in non-cash working
capital relating to
investing activities (45,369) (47,991) (26,322) (64,234)
—————————————————————————-
(139,337) (98,392) (280,763) (282,898)
—————————————————————————-
Net increase in cash 4,235 21,715 2,133 25,457
Cash, beginning of period – 3,742 2,102 –
—————————————————————————-
Cash, end of period 4,235 25,457 4,235 25,457
—————————————————————————-

—————————————————————————-
The following amounts are
included in cash flows from
operating activities:
—————————————————————————-

Cash interest paid 15,597 13,764 25,209 19,407
Cash taxes paid – – – –
—————————————————————————-

/T/

See accompanying notes to the financial statements.

Peyto Exploration & Development Corp.
Notes to Condensed Financial Statements (unaudited)
As at June 30, 2017 and 2016
(Amount in $ thousands, except as otherwise noted)

1. Nature of operations

Peyto Exploration & Development Corp. (“Peyto” or the “Company”) is a Calgary
based oil and natural gas company. Peyto conducts exploration, development and
production activities in Canada. Peyto is incorporated and domiciled in the
Province of Alberta, Canada. The address of its registered office is 300, 600 –
3rd Avenue SW, Calgary, Alberta, Canada, T2P 0G5.

These financial statements were approved and authorized for issuance by the
Audit Committee of Peyto on August 8, 2017.

2. Basis of presentation

The condensed financial statements have been prepared by management and
reported in Canadian dollars in accordance with International Accounting
Standard (“IAS”) 34, “Interim Financial Reporting”. These condensed financial
statements do not include all of the information required for full annual
financial statements and should be read in conjunction with the Company’s
financial statements as at and for the years ended December 31, 2016 and 2015.

Significant Accounting Policies

(a) Significant Accounting Judgments, Estimates and Assumptions

The timely preparation of the condensed financial statements requires
management to make estimates and assumptions that affect the reported amounts
of assets and liabilities and disclosures of contingencies, if any, as at the
date of the financial statements and the reported amounts of revenue and
expenses during the period. By their nature, estimates are subject to
measurement uncertainty and changes in such estimates in future years could
require a material change in the condensed financial statements.

All accounting policies and methods of computation followed in the preparation
of these financial statements are the same as those disclosed in Note 2 of
Peyto’s financial statements as at and for the years ended December 31, 2016
and 2015.

(b) Standards issued but not yet effective

In July 2014, the IASB completed the final elements of IFRS 9 “Financial
Instruments.” The Standard supersedes earlier versions of IFRS 9 and completes
the IASB’s project to replace IAS 39 “Financial Instruments: Recognition and
Measurement.” IFRS 9, as amended, includes a principle-based approach for
classification and measurement of financial assets, a single ‘expected loss’
impairment model and a substantially-reformed approach to hedge accounting. The
Standard will come into effect for annual periods beginning on or after January
1, 2018, with earlier adoption permitted. IFRS 9 will be applied by Peyto on
January 1, 2018. The impact of the standard has been evaluated and is expected
to have no material impact on the Company’s financial statements.

Canacol Energy Ltd. Enters Into Sabanas Gas Flowline Agreement

August 9, 2017 by The Canadian Press

FOR: CANACOL ENERGY LTD.TSX SYMBOL: CNEOTCQX SYMBOL: CNNEFBVC SYMBOL: CNECDate issue: August 09, 2017Time in: 4:30 PM eAttention:
CALGARY, ALBERTA–(Marketwired – Aug. 9, 2017) – Canacol Energy Ltd. (“Canacol”
or the “Corporation”) (TSX:CNE)(OTCQX:CNN…

Gear Energy Ltd. Announces Second Quarter 2017 Operating Results

August 9, 2017 by The Canadian Press

FOR: GEAR ENERGY LTD.
TSX SYMBOL: GXE

Date issue: August 09, 2017
Time in: 4:24 PM e

Attention:

CALGARY, ALBERTA–(Marketwired – Aug. 9, 2017) – Gear Energy Ltd. (“Gear” or
the “Company”) (TSX:GXE) is pleased to provide the following second quarter
operating update to shareholders. Gear’s Interim Financial Statements and
related Management’s Discussion and Analysis (“MD&A”) for the period ended June
30, 2017 are available for review on Gear’s website at www.gearenergy.com and
on www.sedar.com.

/T/

Financial Summary

—————————————————————————-

Three months ended Six months ended
(Cdn$ thousands, per boe Jun 30, Jun 30, Mar 31, Jun 30, Jun 30,
amounts) 2017 2016 2017 2017 2016
—————————————————————————-
FINANCIAL
Cash flow from operations
(1) 10,248 8,333 8,729 18,977 12,317
Per weighted average
basic share 0.05 0.10 0.05 0.10 0.14
Per weighted average
diluted share 0.05 0.10 0.04 0.09 0.14
Cash flow from operating
activities 5,362 5,066 12,245 17,607 8,622
Net income (loss) 3,001 (7,312) 2,986 5,987 (9,028)
Per weighted average
basic share 0.02 (0.08) 0.02 0.03 (0.11)
Per weighted average
diluted share 0.01 (0.08) 0.01 0.03 (0.11)
Capital expenditures 6,161 1,165 18,784 24,945 1,267
Net acquisitions (2) 127 26 (68) 59 (454)
Net debt outstanding (1) 43,409 34,200 46,745 43,409 34,200
Weighted average shares,
basic (thousands) 192,922 86,117 192,840 192,881 85,800
Weighted average shares,
diluted (thousands) 208,971 86,117 209,652 209,074 85,800
Shares outstanding, end of
period (thousands) 192,935 114,234 192,915 192,935 114,234

OPERATING
Production

Heavy Oil (bbl/d) 3,887 4,358 3,739 3,813 4,275
Light and Medium Oil
(bbl/d) 1,412 – 1,085 1,249 –
Natural gas liquids
(bbl/d) 322 – 217 270 –
Natural gas (mcf/d) 5,334 1,070 5,197 5,266 1,265
Total (boe/d) 6,510 4,536 5,907 6,210 4,485
Average prices
Heavy oil ($/bbl) 44.72 39.00 43.13 43.94 29.95
Light oil ($/bbl) 59.64 – 60.91 60.19 –
Natural gas liquids
($/bbl) 28.11 – 23.08 26.10 –
Natural gas ($/mcf) 2.91 1.20 3.00 2.96 1.39
Netback ($/boe)
Commodity and other
sales 43.77 37.75 41.98 42.92 29.10
Royalties (4.96) (2.96) (3.97) (4.49) (2.30)
Operating costs (17.78) (13.44) (16.28) (17.07) (14.38)
Operating netback (1) 21.03 21.34 21.73 21.36 12.41
Realized risk management
gains (losses) (0.77) 4.91 (1.24) (0.99) 8.76
General and
administrative (2.13) (3.28) (3.00) (2.54) (3.47)
Transaction costs – (1.22) – – (0.62)
Interest (0.83) (1.56) (0.88) (0.85) (1.54)
Other – – (0.19) (0.09) (0.59)
Corporate netback (1) 17.30 20.19 16.42 16.89 14.95

TRADING STATISTICS ($
based on intra-day
trading)
High 0.94 0.82 1.26 1.26 0.82
Low 0.60 0.46 0.76 0.60 0.25
Close 0.74 0.61 0.90 0.74 0.61
Average daily volume
(thousands) 253 272 553 403 206
—————————————————————————-
—————————————————————————-

(1) Cash flow from operations, net debt, operating netback and corporate

netback are non-GAAP measures and additional information with respect to
these measures can be found under the heading “Non-GAAP Measures” in
Gear’s MD&A.
(2) Net acquisitions exclude non-cash items for decommissioning liability
and deferred taxes and is net of post-closing adjustments.

/T/

QUARTERLY HIGHLIGHTS

/T/

— Realized quarterly cash flow from operations of $10.2 million, a 17 per

cent increase from the first quarter cash flow of $8.7 million and the
strongest quarterly cash flow Gear has realized in eight quarters. The
increase in quarterly cash flow is primarily due to a 10 per cent
increase in sales volumes to 6,510 boe per day and a slight increase in
realized revenues per boe.
— Production through the second quarter was supported by the following:
— Wildmere: Five horizontal multi-lateral heavy wells have been
drilled to date in 2017, three drilled in the first quarter and two
drilled during the second quarter. Two of the wells were on
production throughout the second quarter, contributing approximately
235 bbls per day to the quarterly total. The other three wells are
expected to come on production in the third quarter
— Wilson Creek: Three Basal Belly River light oil wells have been
drilled to date in 2017, all during the first quarter. In addition
one well that was drilled in 2016 was fracture stimulated and
brought on production in the first quarter. In total the four wells
contributed over 700 boe per day over the second quarter. Several of
the wells are continuing to be optimized.
— Paradise Hill: Four horizontal heavy oil wells were drilled in the
first half of 2017 with two of those wells drilled in the first
quarter and two more drilled in the second quarter. Two of the wells
produced throughout the second quarter contributing approximately
165 bbls per day to the quarterly total. Subsequent to quarter end,
seven more wells have been successfully drilled and are expected to
be brought on production through the third quarter.
— Hoosier: One horizontal Success well has been drilled and brought on
production to date in 2017. The well was drilled in the first
quarter with production coming on early in the second quarter. The
well contributed an average of 70 boe per day to the second quarter
total. Further optimization efforts are underway.
— Realized a corporate netback of $17.30 per boe, a five per cent
improvement over the first quarter of 2017. The improved netback is
primarily the result of higher pricing and lower G&A costs, offset by
higher operating costs.
— Operating costs for the second quarter increased to $17.78 per boe as a
result of seasonal costs associated with trucking, production, and
maintenance as well as road and lease repairs. Second quarter costs were
also impacted by the remediation of two isolated spill events that are
not expected to be recurring expenses. For the third and fourth
quarters, operating costs are expected to decline to a more normalized
level.
— In May 2017, Gear successfully increased its borrowing base for its
credit facilities from $50 million to $55 million and extended the
maturity date to May 30, 2019. Inclusive of the outstanding convertible
debentures, Gear’s total borrowing capacity is currently $69 million.
Net debt through the quarter decreased by $3.3 million to $43.4 million.
For the second quarter, net debt to annualized cash flow was 1.1 times.

/T/

OUTLOOK

/T/

— As a result of strong production results to date, Gear is revising

volume expectations upwards while maintaining the existing $45 million
capital plan. First half production averaged just over 6,200 boe per day
and with continued strong results from the ongoing drilling program, the
second half production is predicted to be approximately 7,000 boe per
day, yielding an annual average of 6,600 boe per day with a strong 2017
exit. Current expectations are that Gear will deliver approximately 18
per cent production growth from the fourth quarter of 2016 to the fourth
quarter of 2017 while investing close to or within annual cash flow at
current prices. The 2017 drilling program is now forecast to include a
total of 34 wells (33 net), with the remaining activity focused in the
core areas of Paradise Hill, Wildmere, Hoosier and Wilson Creek. At
current strip pricing this program is expected to yield a net debt to
cash flow for 2017 at or below 1.0 times.

—————————————————————————-

Revised 2017 Previous 2017 H1 2017 YTD
Guidance Guidance Actuals
—————————————————————————-
Production (boe/d) 6,600 6,400 6,210
—————————————————————————-
Per cent heavy oil (%) 63 62 61
—————————————————————————-
Per cent light/medium oil &
NGLs (%) 23 24 24
—————————————————————————-
Royalty rate (%) 10 10 10.5
—————————————————————————-
Operating costs ($/boe) 16.50 15.50 17.07
—————————————————————————-
General and administrative
expense ($/boe) 2.20 2.15 2.54
—————————————————————————-
Interest expense ($/boe) 0.80 0.70 0.85
—————————————————————————-
Capital and abandonment
expenditures ($ millions) 45 45 25.7
—————————————————————————-

/T/

Forward-looking Information and Statements

This press release contains certain forward-looking information and statements
within the meaning of applicable securities laws. The use of any of the words
“expect”, “anticipate”, “continue”, “estimate”, “objective”, “ongoing”, “may”,
“will”, “project”, “should”, “believe”, “plans”, “intends”, “strategy” and
similar expressions are intended to identify forward-looking information or
statements. In particular, but without limiting the foregoing, this press
release contains forward-looking information and statements pertaining to the
following: drilling, completion and optimization plans for Gear’s assets; third
quarter 2017 production; 2017 guidance on production, product mix, royalty
rate, operating costs, general and administrative expense, interest expense,
and capital and abandonment expenditures; fourth quarter 2017 production
growth; the expectation that the 2017 capital expenditure program will be
funded solely from cash flow from operations; the expected 2017 net debt to
cash flow ratio; and third and fourth quarter operating costs normalizing.

The forward-looking information and statements contained in this press release
reflect several material factors and expectations and assumptions of Gear
including, without limitation: that Gear will continue to conduct its
operations in a manner consistent with past operations; the general continuance
of current industry conditions; the continuance of existing (and in certain
circumstances, the implementation of proposed) tax, royalty and regulatory
regimes; the accuracy of the estimates of Gear’s reserves and resource volumes;
certain commodity price and other cost assumptions; and the continued
availability of adequate debt and equity financing and cash flow from
operations to fund its planned expenditures. Gear believes the material
factors, expectations and assumptions reflected in the forward-looking
information and statements are reasonable but no assurance can be given that
these factors, expectations and assumptions will prove to be correct.

To the extent that any forward-looking information contained herein may be
considered a financial outlook, such information has been included to provide
readers with an understanding of management’s assumptions used for budgeting
and developing future plans and readers are cautioned that the information may
not be appropriate for other purposes. The forward-looking information and
statements included in this press release are not guarantees of future
performance and should not be unduly relied upon. Such information and
statements involve known and unknown risks, uncertainties and other factors
that may cause actual results or events to differ materially from those
anticipated in such forward-looking information or statements including,
without limitation: changes in commodity prices; changes in the demand for or
supply of Gear’s products; unanticipated operating results or production
declines; changes in tax or environmental laws, royalty rates or other
regulatory matters; changes in development plans of Gear or by third party
operators of Gear’s properties, increased debt levels or debt service
requirements; inaccurate estimation of Gear’s oil and gas reserve and resource
volumes; limited, unfavorable or a lack of access to capital markets; increased
costs; a lack of adequate insurance coverage; the impact of competitors; and
certain other risks detailed from time to time in Gear’s public documents
including in Gear’s most current annual information form which is available on
SEDAR at www.sedar.com.

The forward-looking information and statements contained in this press release
speak only as of the date of this press release, and Gear does not assume any
obligation to publicly update or revise them to reflect new events or
circumstances, except as may be required pursuant to applicable laws.

NON-GAAP Measures

This press release contains the terms cash flow from operations, net debt,
operating netback and corporate netback, which do not have standardized
meanings under Canadian generally accepted accounting principles (“GAAP”) and
therefore may not be comparable with the calculation of similar measures by
other companies. Management believes that these key performance indicators and
benchmarks are key measures of financial performance for Gear and provide
investors with information that is commonly used by other oil and gas
companies. Cash flow from operations is calculated as cash flow from operating
activities before changes in noncash operating working capital and
decommissioning liabilities settled. Net debt is calculated as debt less
current working capital items, excluding risk management contracts. Operating
netbacks are presented both before and after taking into account the effects of
hedging and are calculated based on the amount of revenues received on a per
unit of production basis after royalties and operating costs. Corporate
netbacks are presented after taking into account the effects of hedging and are
calculated based on the amount of revenues received on a per unit of production
basis after royalties, operating costs, general and administrative expenses,
interest and foreign exchange gain or loss. Additional information relating to
certain of these non-GAAP measures, including the reconciliation between cash
flow from operations and cash flow from operating activities, can be found in
the MD&A.

Barrels of Oil Equivalent

Disclosure provided herein in respect of BOEs may be misleading, particularly
if used in isolation. A BOE conversion ratio of six Mcf to one Bbl is based on
an energy equivalency conversion method primarily applicable at the burner tip
and do not represent a value equivalency at the wellhead. Additionally, given
that the value ratio based on the current price of crude oil, as compared to
natural gas, is significantly different from the energy equivalency of 6:1;
utilizing a conversion ratio of 6:1 may be misleading as an indication of value.

Initial and Other Production Rates

Any references in this document to initial production rates or production rates
of new wells over a period of time are useful in confirming the presence of
hydrocarbons, however, such rates are not determinative of the rates at which
such wells or other future wells will continue production and decline
thereafter. Additionally, such rates may also include recovered “load oil”
fluids used in well completion stimulation. There is no certainty that other
wells on such properties will achieve such production levels. Readers are
cautioned not to place reliance on such rates in calculating the aggregate
production for Gear.

– END RELEASE – 09/08/2017

For further information:
Ingram Gillmore
President & CEO
403-538-8463
Email: igillmore@gearenergy.com
OR
David Hwang
Vice President Finance & CFO
403-538-8437
Email: dhwang@gearenergy.com
Website: www.gearenergy.com

COMPANY:
FOR: GEAR ENERGY LTD.
TSX SYMBOL: GXE

INDUSTRY: Energy and Utilities – Oil and Gas
RELEASE ID: 20170809CC0061

Press Release from Marketwired 1-866-736-3779

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Kelt Reports Financial and Operating Results for the Three and Six Months Ended June 30, 2017

August 9, 2017 by The Canadian Press

FOR: KELT EXPLORATION LTD.
TSX Symbol: KEL

Date issue: August 09, 2017
Time in: 8:45 AM e

Attention:

CALGARY, AB –(Marketwired – August 09, 2017) – Kelt Exploration Ltd. (TSX:
KEL) (“Kelt” or the “Company”) has released its financial and operating
results for the three and six months ended June 30, 2017. The Company’s
financial results are summarized as follows:

/T/

—————————————————————————-
FINANCIAL
HIGHLIGHTS Three months ended June 30 Six months ended June 30
(CA$ thousands,
except as
otherwise
indicated) 2017 2016 % 2017 2016 %
—————————————————————————-

Revenue, before
royalties and
financial
instruments 60,072 40,718 48 120,297 81,116 48

Adjusted funds
from operations
(1) 25,333 11,671 117 52,156 17,622 196
Basic ($/ common
share) (1) 0.14 0.07 100 0.30 0.10 200
Diluted ($/
common share)
(1) 0.14 0.07 100 0.29 0.10 190

Loss and
comprehensive
loss (4,869) (20,413) -76 (7,136) (46,331) -85
Basic ($/ common
share) (0.03) (0.12) -75 (0.04) (0.27) -85
Diluted ($/
common share) (0.03) (0.12) -75 (0.04) (0.27) -85

Total capital
expenditures, net
of dispositions 31,630 25,908 22 (3,734) 49,313 -108

Total assets 1,203,174 1,260,245 -5 1,203,174 1,260,245 -5
Bank debt, net of
working capital
(1) 80,618 139,080 -42 80,618 139,080 -42
Convertible
debentures 72,685 69,320 5 72,685 69,320 5
Shareholders’
equity 839,485 835,241 1 839,485 835,241 1

Weighted average
shares
outstanding
(000s)

Basic 175,894 173,818 1 175,805 171,321 3
Diluted 177,316 173,972 2 177,093 171,444 3
—————————————————————————-

/T/

(1) Refer to advisories regarding non-GAAP financial measures and other key
performance indicators.

Financial Statements

Kelt’s unaudited condensed consolidated interim financial statements and
related notes for the quarter ended June 30, 2017 will be available to the
public on SEDAR at www.sedar.com and will also be posted on the Company’s
website at www.keltexploration.com on August 9, 2017.

Kelt’s operating results for the second quarter ended June 30, 2017 are
summarized as follows:

/T/

—————————————————————————-
OPERATIONAL
HIGHLIGHTS Three months ended June 30 Six months ended June 30
(CA$ thousands,
except as
otherwise
indicated) 2017 2016 % 2017 2016 %
—————————————————————————-

Average daily
production

Oil (bbls/d) 5,929 5,066 17 5,863 5,469 7
NGLs (bbls/d) 1,967 2,632 -25 2,162 2,686 -20
Gas (mcf/d) 76,730 75,060 2 74,525 81,577 -9
—————————————————————————-
Combined (BOE/d) 20,684 20,208 2 20,446 21,751 -6
—————————————————————————-

Production per
million common
shares (BOE/d)
(1) 118 116 2 116 127 -9

Average realized
prices, before
financial
instruments

Oil ($/bbl) 56.80 49.76 14 58.48 41.30 42
NGLs ($/bbl) 29.04 18.21 59 28.36 16.19 75
Gas ($/mcf) 3.47 1.97 76 3.50 2.16 62

Operating netbacks
($/BOE) (1)

Petroleum and
natural gas
revenue 31.91 22.14 44 32.50 20.49 59
Realized gain
(loss) on
financial
instruments (0.21) (0.01) 2000 (0.10) (0.01) 900
—————————————————————————-
Average realized
price, after
financial
instruments 31.70 22.13 43 32.40 20.48 58
Royalties (2.47) (1.65) 50 (3.04) (1.49) 104
Production
expense (10.27) (8.87) 16 (9.94) (9.61) 3
Transportation
expense (3.47) (2.89) 20 (3.36) (2.79) 20
—————————————————————————-
Operating
netback (1) 15.49 8.72 78 16.06 6.59 144
—————————————————————————-

Undeveloped land

Gross acres 777,550 665,010 17 777,550 665,010 17
Net acres 658,538 543,530 21 658,538 543,530 21
—————————————————————————-

/T/

(1) Refer to advisories regarding non-GAAP financial measures and other key
performance indicators.

Message to Shareholders

Average production for the three months ended June 30, 2017 was 20,684 BOE per
day, up 2% compared to average production of 20,208 BOE per day during the
second quarter of 2016. Production during the second quarter of 2017 reflects
the disposition of the majority of the Company’s oil and gas assets at Karr
which included approximately 1,300 BOE per day of production. The Karr
disposition was completed on January 18, 2017.

The Company’s average production during the second quarter of 2017 was below
original estimates as third party outages and downtime exceeded expectations.
The following downtime and outages negatively affected 2017 second quarter
production: TransCanada Pipeline Ltd. restricted a portion of firm service
production on the NGTL pipeline system upstream of the James River receipt
area in June for approximately two weeks; turnaround operations at the McMahon
Gas Plant lasted longer than originally expected; compression downtime on the
Westcoast pipeline system during the McMahon plant outage resulted in partial
outages at the West Stoddart Gas Plant, where the majority of the Company’s
gas in British Columbia is processed; an outage at the Younger Gas Plant in
British Columbia, where repairs were conducted, reduced the amount of NGL
recoveries that Kelt normally realizes during the period of repairs; in June
2017, the Alliance Pipeline system declared a force majeure resulting from
excavation and inspection of the upper and lower sections of its pipeline
segment in the area of the slope movement near the Wapiti River requiring Kelt
to shut-in significant volumes of production in both British Columbia and
Alberta; and at Spirit River, the Company was required to also shut-in
approximately 400 BOE per day of production that flowed through a third party
gathering system. The owner of the pipeline gathering system does not intend
to complete the repairs required to bring the system back to operation at this
time. Kelt is currently reviewing alternative options to bring that production
back on stream.

Initial production rates from recent drilling results in both British Columbia
and Alberta have exceeded the Company’s estimates. As a result, despite the
lower second quarter production, Kelt has not changed its full year guidance
of average daily production of 23,500 BOE per day. The Company intends to
review its production guidance again in September and will provide updated
information at that time.

At La Glace, Alberta, the Company drilled and completed two wells in the
Middle Montney. The wells were completed using gelled-water with 36 fracture
stages and approximately 40 tonnes of proppant per stage. The well located at
02/13-33-074-08W6 had an IP30 rate (gross estimated sales) of 790 BOE per day
of which 90% was oil and NGLs. The second well located at 02/04-23-074-08W6
had an IP30 rate (gross estimated sales) of 888 BOE per day of which 69% was
oil and NGLs. Given the lower capital expenditures per well and the resulting
quick payback on these wells, at under six months in the current commodity
price environment, Kelt has drilled two additional wells at La Glace in July
2017.

At Inga, British Columbia, the Company drilled its third Middle Montney well
on its large contiguous land block. The well was completed using slick-water
with 46 fracture stages and approximately 70 tonnes of proppant per stage. The
well located at 02/15-33-087-23W6 had an IP24 rate (gross estimated sales) of
2,157 BOE per day of which 81% was oil and NGLs. This is the highest Middle
Montney initial production rate recorded to date at Inga/Fireweed. In the
current commodity price environment, given the high oil content of the initial
production, this well is expected to payback in approximately six months. With
the success to date in the Middle Montney, Kelt expects to drill additional
Middle Montney wells at Inga during the second half of 2017 and in 2018.

At Pipestone/Wembley, Alberta where the Company has recently increased its
land position to 59,080 acres (92 sections) of lands with Montney rights, Kelt
has drilled its first horizontal exploratory well located at
00/04-01-072-08W6. This well has now been completed using slick-water with 50
fracture stages and approximately 70 tonnes of proppant per stage. Initial
production results are expected to be available in September 2017.

At Inga/Stoddart, British Columbia where the Company has 104,862 acres (164
sections) of lands with Baldonnel rights, Kelt has drilled its first
horizontal exploratory well located at 00/13-29-087-21W6. This well is
currently being completed using slick-water with 30 planned fracture stages
and approximately 26 tonnes of proppant per stage.

Commodity prices have improved from 2016 levels and have shown significant
gains in the second quarter of 2017 compared to the second quarter of 2016.
Kelt’s realized average oil price during the second quarter of 2017 was $56.80
per barrel, up 14% from $49.76 per barrel in the second quarter of 2016. The
realized average NGLs price during the second quarter of 2017 was $29.04 per
barrel, up 59% from $18.21 per barrel in the corresponding quarter of 2016.
Kelt’s realized average gas price for the second quarter of 2017 was $3.47 per
MCF, up 76% from $1.97 per MCF in the second quarter of the previous year.

The Company continues to realize higher average gas prices compared to the
AECO index price through its gas market diversification strategy. In British
Columbia, where there have been gas egress congestion and bottlenecks in the
past, for the upcoming gas year (November 1, 2017 to October 31, 2018), Kelt
has contracted service for approximately 25,000 MMBtu per day of gas sales for
its British Columbia production. Approximately 15,000 MMBtu per day will be
delivered to the Station 2 Hub and Kelt will receive the Sumas Hub USD Monthly
Index price less US$0.695 per MMBtu. Approximately 10,000 MMBtu per day will
be delivered to an Alliance pipeline receipt point and Kelt will receive the
Chicago Hub Gas Daily Index price less transportation charges. As a result,
Kelt will have minimal to no exposure to Station 2 pricing in its British
Columbia gas market portfolio. In Alberta, the Company has contracts in place
to sell 15,000 MMBtu per day of gas at NIT and to receive the Malin Hub USD
Index price less US$0.70 per MMBtu (November 1, 2017 to October 31, 2020) and
23,700 MMBtu per day of gas at the Dawn hub in southern Ontario less
transportation charges (November 1, 2017 to October 31, 2020). These contracts
provide Kelt with gas market diversification and ensure that the Company’s
future gas sales revenue is not subject to the risks associated with a single
market.

For the three months ended June 30, 2017, revenue was $60.1 million and
adjusted funds from operations was $25.3 million ($0.14 per share, diluted),
compared to $40.7 million and $11.7 million ($0.07 per share, diluted)
respectively, in the second quarter of 2016. At June 30, 2017, bank debt, net
of working capital was $80.6 million, down 42% from $139.1 million at June 30,
2016.

Capital expenditures incurred during the three months ended June 30, 2017,
prior to property dispositions, were $35.0 million. The Company spent $19.6
million (56%) on drilling and completion operations, $14.1 million (40%) on
facilities, pipelines and equipment and $1.2 million (4%) on land and seismic.
In addition, during the second quarter of 2017, Kelt received cash proceeds of
$3.3 million from minor property dispositions.

Kelt has recently moved to development drilling from multi-well pads as part
of its future development plan for its vast corporate Montney acreage. Capital
efficiencies gained from pad drilling and improved completion results with
increased fracture stages, greater proppant tonnage and high intensity pump
rates have resulted in short payback periods in the current commodity price
environment. The tables below show the estimated payback of capital incurred
to drill and complete all new Montney wells that the Company has brought on
production in 2017 (except the Inga 00/14-24-087-23W6 well which was brought
on production on December 12, 2016). Two Montney wells drilled at Progress are
not included in Table 1 as these wells are currently in the process of being
brought on stream.

/T/

Table 1 âÃ‡Ã´ Paybacks for 2017 Montney Development Wells:
—————————————————————–

Drill &
Complete Production
Cost ($ MM) Initial Start Date
Well [1] Test Date [2]

—————————————————————–
Pouce Coupe 02/06-18-078-11W6 4.8 2017-01-26 2017-01-26
—————————————————————–
Pouce Coupe 03/07-18-078-11W6 4.1 2017-01-26 2017-01-26
—————————————————————–
Pouce Coupe 04/07-18-078-11W6 5.0 2017-01-24 2017-03-03
—————————————————————–
Pouce Coupe 05/07-18-078-11W6 4.3 2017-01-23 2017-03-08
—————————————————————–
Pouce Coupe 00/01-09-078-11W6 5.0 2017-02-21 2017-03-11
—————————————————————–
Pouce Coupe 03/16-25-077-13W6 5.8 2017-02-25 2017-06-19
—————————————————————–
La Glace 02/13-33-074-08W6 3.8 2017-04-01 2017-04-01
—————————————————————–
La Glace 02/04-23-074-08W6 4.0 2017-05-26 2017-05-26
—————————————————————–

Table 1 âÃ‡Ã´ Paybacks for 2017 Montney Development Wells:
—————————————————————–

Actual Cumulative to May 31, 2017
Well [3]
———————————
Operating Operating
Production Income ($ Netback
(MBOE) MM) ($/BOE)
—————————————————————–
Pouce Coupe 02/06-18-078-11W6 150.7 4.8 31.90
—————————————————————–
Pouce Coupe 03/07-18-078-11W6 125.4 4.0 31.84
—————————————————————–
Pouce Coupe 04/07-18-078-11W6 101.4 3.0 30.00
—————————————————————–
Pouce Coupe 05/07-18-078-11W6 105.0 3.2 30.08
—————————————————————–
Pouce Coupe 00/01-09-078-11W6 89.8 3.0 33.50
—————————————————————–
Pouce Coupe 03/16-25-077-13W6 26.5 0.4 13.83
—————————————————————–
La Glace 02/13-33-074-08W6 42.8 1.8 42.86
—————————————————————–
La Glace 02/04-23-074-08W6 2.1 0.1 26.88
—————————————————————–

Table 1 âÃ‡Ã´ Paybacks for 2017 Montney Development Wells:
—————————————————————————-

Last
Month’s
Production
Payback Rate at
Remaining to Payback Period Payback
Well [4] (years) (BOE/d)
———————-
Operating
Production Income
Estimate Estimate ($
(MBOE) MM)
—————————————————————————-
Pouce Coupe 02/06-18-078-11W6 22.8 0.5 0.4 761
—————————————————————————-
Pouce Coupe 03/07-18-078-11W6 23.8 0.6 0.4 792
—————————————————————————-
Pouce Coupe 04/07-18-078-11W6 83.8 2.2 0.7 440
—————————————————————————-
Pouce Coupe 05/07-18-078-11W6 40.2 1.2 0.4 578
—————————————————————————-
Pouce Coupe 00/01-09-078-11W6 70.3 2.1 0.6 450
—————————————————————————-
Pouce Coupe 03/16-25-077-13W6 426.1 5.8 0.8 1,061
—————————————————————————-
La Glace 02/13-33-074-08W6 56.0 2.1 0.5 406
—————————————————————————-
La Glace 02/04-23-074-08W6 131.8 4.2 0.7 347
—————————————————————————-

/T/

Notes: Refer to explanatory notes provided under Table 2.

In addition to favourable economic results from its Montney development
drilling program, the Company expects to achieve short paybacks on its capital
incurred on Montney delineation and step-out wells. A move to pad drilling on
these newly de-risked lands should result in further improvements in capital
efficiencies in the future.

/T/

Table 2 âÃ‡Ã´ Paybacks for 2017 Montney Delineation/Step-out Wells:
—————————————————————————-

Drill &
Complete Cost Initial Test Production
Well ($ MM) [1] Date Start Date [2]

—————————————————————————-
Inga 00/14-24-087-23W6
[ Middle Montney ] 6.5 2016-12-12 2016-12-12
—————————————————————————-
Fireweed C-31-I/94-A-12
[ Upper Montney ] 6.9 2017-01-16 2017-01-16
—————————————————————————-
Stoddart 00/08-17-087-22W6
[ Upper Montney ] 7.4 [5] 2017-03-22 2017-04-25
—————————————————————————-
Inga 02/15-33-087-23W6
[ Middle Montney ] 5.5 2017-07-06 2017-07-13
—————————————————————————-

Table 2 âÃ‡Ã´ Paybacks for 2017 Montney Delineation/Step-out Wells:
—————————————————————————-

Well Actual Cumulative to May 31, 2017 [3]
———————————————
Production Operating Operating
(MBOE) Income ($ MM) Netback ($/BOE)
—————————————————————————-
Inga 00/14-24-087-23W6
[ Middle Montney ] 135.6 4.6 34.17
—————————————————————————-
Fireweed C-31-I/94-A-12
[ Upper Montney ] 142.9 3.6 25.13
—————————————————————————-
Stoddart 00/08-17-087-22W6
[ Upper Montney ] 32.6 0.9 28.02
—————————————————————————-
Inga 02/15-33-087-23W6
[ Middle Montney ] – – –
—————————————————————————-

Table 2 âÃ‡Ã´ Paybacks for 2017 Montney Delineation/Step-out Wells:
—————————————————————————-

Last Month’s
Production
Payback Rate at
Remaining to Payback Period Payback
Well [4] (years) (BOE/d)
———————-
Operating
Production Income
Estimate Estimate ($
(MBOE) MM)
—————————————————————————-
Inga 00/14-24-087-23W6
[ Middle Montney ] 58.2 2.0 0.8 449
—————————————————————————-
Fireweed C-31-I/94-A-12
[ Upper Montney ] 151.5 3.3 1.4 313
—————————————————————————-
Stoddart 00/08-17-087-22W6
[ Upper Montney ] 259.6 6.5 2.6 177
—————————————————————————-
Inga 02/15-33-087-23W6
[ Middle Montney ] 193.7 5.7 0.5 656
—————————————————————————-

/T/

Notes:

[1] Half-cycle capital âÃ‡Ã´ equipment and tie-in costs for delineation/step-out
wells are not included in the payback period calculation, as the initial
tie-in costs for single wells will eventually benefit additional wells drilled
from the same pad. Equipment and tie-in costs for pad wells are on average an
incremental $300,000 per well and are included in the payback period
calculation for development wells.

[2] Production Start Date is the date when the well commenced steady
production after tie-in operations were completed. The payback period is
calculated from this date.

[3] Actual production and operating income cumulative to date is up to May 31,
2017 and includes any production and operating income generated during the
test period, prior to the Production Start Date.

[4] Estimated operating income required to payback is calculated based on
actual sales prices received to date. Estimated future production is
calculated based on internally generated production forecasts/decline curves
for each respective well. Actual production for June and July 2017, based on
field estimates, is included in estimated future production.

[5] During completion operations, the Stoddart 8-17 well experienced fracking
and drill-out problems which added approximately $1.0 million to the
completion costs.

The Company’s Board of Directors has agreed to increase the 2017 capital
expenditure budget by a net $10.0 million. Total exploration and development
capital expenditures planned for 2017 are $191.0 million (previously $173.0
million) and proceeds from property dispositions are expected to be $111.0
million (previously $103.0 million), resulting in a net capital expenditure
budget of $80.0 million (previously $70.0 million). The increase in the
capital expenditure budget reflects an additional $18.0 million for
infrastructure expenditures and additional proceeds from minor property
dispositions in the amount of $8.0 million ($3.3 million of which was already
completed at June 30, 2017 and the balance is an estimate for further
transactions expected to occur in the second half of 2017).

On July 31, 2017, the Company completed the purchase of a major infrastructure
package for $12.5 million. After a new lease has been surveyed and built, this
infrastructure package will be moved from its existing location in
northeastern British Columbia and installed on a new site at Inga, British
Columbia, in close proximity to the Company’s existing Inga facility located
at 15-03-088-23W6. The infrastructure package includes four 4,700 horse power
gas compressors with aggregate capacity of 100 MMCF per day, two 50 MMCF per
day gas dehydration units, a fuel gas conditioning skid, a high pressure flare
system, four 750 barrel tanks, a vapor recovery unit, instrument air
compressors, three electric power generators, a master control centre building
and several other buildings and associated equipment. This infrastructure
purchase is expected to lower future production expenses regardless of whether
the Company elects to construct its own gas plant at Inga, or alternatively,
continues to process gas through third party facilities in British Columbia.

Kelt has also commenced installation of blending facilities at its three main
oil terminals located at Inga, La Glace and Progress, which are now pipeline
connected to oil sales and water injection. These new facilities are expected
to provide the Company with higher price realizations for its oil and butane
sales in each of these areas and are anticipated to be completed prior to
year-end.

The Company is well positioned financially to execute its capital program
during the remainder of 2017 and expects to enter 2018 with strong operational
momentum.

Management looks forward to updating shareholders with 2017 third quarter
results on or about November 9, 2017.

Advisory Regarding Forward-Looking Statements

This press release contains forward-looking statements and forward-looking
information within the meaning of applicable securities laws. The use of any
of the words “expect”, “anticipate”, “continue”, “estimate”, “objective”,
“ongoing”, “may”, “will”, “project”, “should”, “believe”, “plans”, “intends”
and similar expressions are intended to identify forward-looking information
or statements. In particular, this press release contains forward-looking
statements pertaining to the following: the expectation that the Company’s new
firm service gas transportation contracts will limit exposure to discounted
Station 2 pricing for its operations in northeastern BC; the anticipated
improvement in Kelt’s price realizations for its oil and butane sales
following the installation of blending facilities at the Company’s three main
oil terminals, which are expected to be completed prior to December 31, 2017;
the expectation that the recent purchase of a major infrastructure package in
northeastern BC will reduce the Company’s production expenses in the future;
that the estimated future production and operating income for the 2017 Montney
development wells (Table 1) and delineation/step-out wells (Table 2) will be
sufficient to payback the drill and complete capital costs incurred for each
respective well; the Company’s ability to continue accumulating land at a
low-cost in its core operating areas and potentially monetize non-core assets;
and the Company’s expected future financial position and operating results, as
well as the amount and timing of future development capital expenditures.
Statements relating to “reserves” or “resources” are deemed to be forward
looking statements, as they involve the implied assessment, based on certain
estimates and assumptions, that the reserves described exist in the quantities
predicted or estimated and that the reserves can be profitably produced in the
future. Actual reserves may be greater than or less than the estimates
provided herein.

Although Kelt believes that the expectations and assumptions on which the
forward-looking statements are based are reasonable, undue reliance should not
be placed on the forward-looking statements because Kelt cannot give any
assurance that they will prove to be correct. Since forward-looking statements
address future events and conditions, by their very nature they involve
inherent risks and uncertainties. Actual results could differ materially from
those currently anticipated due to a number of factors and risks. These
include, but are not limited to, the risks associated with the oil and gas
industry in general (e.g., operational risks in development, exploration and
production; delays or changes in plans with respect to exploration or
development projects or capital expenditures; the uncertainty of reserve
estimates; the uncertainty of estimates and projections relating to
production, costs and expenses; failure to obtain necessary regulatory
approvals for planned operations; health, safety and environmental risks;
uncertainties resulting from potential delays or changes in plans with respect
to exploration or development projects or capital expenditures; volatility of
commodity prices, currency exchange rate fluctuations; imprecision of reserve
estimates; and competition from other explorers) as well as general economic
conditions, stock market volatility; and the ability to access sufficient
capital. We caution that the foregoing list of risks and uncertainties is not
exhaustive.

In addition, the reader is cautioned that historical results are not
necessarily indicative of future performance. The forward-looking statements
contained herein are made as of the date hereof and the Company does not
intend, and does not assume any obligation, to update or revise any
forward-looking statements, whether as a result of new information, future
events or otherwise unless expressly required by applicable securities laws.

Certain information set out herein may be considered as “financial outlook”
within the meaning of applicable securities laws. The purpose of this
financial outlook is to provide readers with disclosure regarding Kelt’s
reasonable expectations as to the anticipated results of its proposed business
activities for the periods indicated. Readers are cautioned that the financial
outlook may not be appropriate for other purposes.

Non-GAAP Financial Measures and Other Key Performance Indicators

This press release contains certain financial measures, as described below,
which do not have standardized meanings prescribed by GAAP. In addition, this
press release contains other key performance indicators (“KPI”), financial and
non-financial, that do not have standardized meanings under the applicable
securities legislation. As these non-GAAP financial measures and KPI are
commonly used in the oil and gas industry, the Company believes that their
inclusion is useful to investors. The reader is cautioned that these amounts
may not be directly comparable to measures for other companies where similar
terminology is used.

Non-GAAP financial measures

“Operating income” is calculated by deducting royalties, production expenses
and transportation expenses from petroleum and natural gas revenue, after
realized gains or losses on associated financial instruments. The Company
refers to operating income expressed per unit of production as an “Operating
netback”. “Adjusted funds from operations” is calculated as cash provided by
operating activities before changes in non-cash operating working capital, and
adding back (if applicable): transaction costs associated with acquisitions
and dispositions, provisions for potential credit losses, and settlement of
decommissioning obligations. Adjusted funds from operations per common share
is calculated on a consistent basis with profit (loss) per common share, using
basic and diluted weighted average common shares as determined in accordance
with GAAP. Adjusted funds from operations and operating income or netbacks are
used by Kelt as key measures of performance and are not intended to represent
operating profits nor should they be viewed as an alternative to cash provided
by operating activities, profit or other measures of financial performance
calculated in accordance with GAAP.

Other KPI

“Production per common share” is calculated by dividing total production by
the basic weighted average number of common shares outstanding, as determined
in accordance with GAAP.

Measurements

All dollar amounts are referenced in thousands of Canadian dollars, except
when noted otherwise. This press release contains various references to the
abbreviation BOE which means barrels of oil equivalent. Where amounts are
expressed on a BOE basis, natural gas volumes have been converted to oil
equivalence at six thousand cubic feet per barrel and sulphur volumes have
been converted to oil equivalence at 0.6 long tons per barrel. The term BOE
may be misleading, particularly if used in isolation. A BOE conversion ratio
of six thousand cubic feet per barrel is based on an energy equivalency
conversion method primarily applicable at the burner tip and does not
represent a value equivalency at the wellhead and is significantly different
than the value ratio based on the current price of crude oil and natural gas.
This conversion factor is an industry accepted norm and is not based on either
energy content or current prices. Such abbreviation may be misleading,
particularly if used in isolation. References to “oil” in this press release
include crude oil and field condensate. References to “natural gas liquids” or
“NGLs” include pentane, butane, propane, and ethane. References to “liquids”
include field condensate and NGLs. References to “gas” in this discussion
include natural gas and sulphur.

Abbreviations

/T/

bbls barrels
bbls/d barrels per day
mcf thousand cubic feet
mcf/d thousand cubic feet per day
mmcf million cubic feet
mmcf/d million cubic feet per day
MMBTU million British Thermal Units
GJ gigajoule
BOE barrel of oil equivalent
BOE/d barrel of oil equivalent per day
NGLs natural gas liquids
AECO Alberta Energy Company “C” Meter Station of the NOVA Pipeline
System
NIT NOVA Inventory Transfer (“AB-NIT”), being the reference price at
the AECO Hub
WTI West Texas Intermediate
NYMEX New York Mercantile Exchange
Station 2 Spectra Energy receipt location
API American Petroleum Institute
IP24 initial production from a well for the first 576 hours (24 days)
based on operating/producing hours
IP30 initial production from a well for the first 720 hours (30 days)
based on operating/producing hours
US$ United States dollars
CA$ Canadian dollars
TSX the Toronto Stock Exchange
KEL trading symbol for Kelt Exploration Ltd. common shares on the TSX
KEL.DB trading symbol for Kelt Exploration Ltd. 5% convertible
debentures on the TSX
GAAP Generally Accepted Accounting Principles
KPI Key Performance Indicators

/T/

– END RELEASE – 09/08/2017

For further information:

For further information, please contact:

Kelt Exploration Ltd.
Suite 300, 311 âÃ‡Ã´ 6th Avenue SW, Calgary, Alberta
Canada T2P 3H2

David J. Wilson
President and Chief Executive Officer
(403) 201-5340

Sadiq H. Lalani
Vice President and Chief Financial Officer
(403) 215-5310.
Or visit our website at www.keltexploration.com

COMPANY:
FOR: KELT EXPLORATION LTD.
TSX Symbol: KEL

INDUSTRY: Energy and Utilities – Oil and Gas
RELEASE ID: 20170809CC017

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Keystone XL foes question proposed route through Nebraska

August 9, 2017August 8, 2017 by The Canadian Press

LINCOLN, Neb. — Opponents of the Keystone XL pipeline questioned its proposed pathway through Nebraska on Tuesday in hopes that state regulators will reject or reroute it, a decision that would create more delays for the 9-year-old project.

But pipeline builder TransCanada defended its proposal to the Nebraska Public Service Commission, arguing that the company’s “preferred route” makes the most sense and causes the least amount of disruption.

The proposed pipeline faced another day of scrutiny in a hearing before the Nebraska Public Service Commission, whose five members must decide whether the Keystone XL serves the public interest. Approving the project would allow TransCanada to gain access to holdout landowners’ property using Nebraska’s eminent domain laws.

The 1,179-mile crude oil pipeline has faced relentless criticism from environmental groups, Native American tribes and a well-organized minority of Nebraska landowners who don’t want the project cutting through their property. Business groups and some unions support the Keystone XL, saying it will provide jobs and property tax revenue for local governments.

Opponents argue that, if it wins approval, the Keystone XL should run along the same path as the original Keystone pipeline, a line through eastern Nebraska that was completed with little opposition in 2010. TransCanada’s preferred route would carry crude oil roughly 275 miles through Nebraska, whereas the original Keystone route only stretches 210 miles, said Brian Jorde, an attorney for the landowners.

Company officials have said their preferred route is the most direct and least expensive way to transport oil from Alberta, Canada, to an existing pipeline in Steele City, Nebraska. Rerouting the pipeline would add millions of dollars to the project’s $8 billion price tag.

“A lot of work was put into the original main line with those landowners, accommodating their requests,” said Jon Schmidt, a Florida-based regulatory consultant hired by TransCanada. “That would have to be reinitiated.”

Because it would travel along a nearly straight path, company officials said their preferred route would affect the least amount of land. TransCanada considered other routes, including one that would have run along Interstate 90 in South Dakota, but rejected them because they were longer, Meera Kothari, a company engineer.

The most direct path “lends itself to a diagonal route through Alberta, Montana, South Dakota and Nebraska,” Kothari said.

The company has also argued that the route through neighbouring South Dakota is already set, thus requiring it to cross the border at a point near Mills, Nebraska.

On Tuesday, a leading advocate for Nebraska landowners who oppose the pipeline argued that South Dakota’s route was not set in stone.

“We’ve been here for two days of hearings in which we’ve heard witness after witness say that we have to approve a route with a fixed starting point because the South Dakota Public Utilities Commission approved it, but all the South Dakota Public Utilities commission did was to grant a construction permit,” said Dave Domina, an Omaha attorney.

The Nebraska Public Service Commission must decide by Nov. 23 whether to approve or reject the project, based on evidence presented at hearings that could continue through Friday. The elected commission is comprised of four Republicans and one Democrat.

Outside the hearing, about 40 Native American tribe members and supporters gathered to protest the project. The tribes voiced concerns about the pipeline contaminating the state’s groundwater.

“We just don’t think there’s a need for this,” said Larry Wright Jr., chairman of the Ponca Tribe of Nebraska.

___

Follow Grant Schulte on Twitter at https://twitter.com/GrantSchulte

Grant Schulte, The Associated Press

Brady Debuts the New Ultra Compact Group Lock Box

August 8, 2017 by EnergyNow Media

Innovative lock box provides a portable solution for carrying and securing padlocks MILWAUKEE, Wis. (August 8, 2017) — Brady (NYSE:BRC), a global leader in industrial and safety printing systems and solutions, announced today the launch of the new Ultra Compact Lock Box. This new lock box is ideal for group lockout situations with multiple isolation … Read more

EIA Raises Both 2017, 2018 U.S. Crude Production Forecasts

August 8, 2017 by EnergyNow Media

August 8, 2017 (Bloomberg) U.S. producers are seen pumping away, even with the price of West Texas Intermediate crude lingering below $50 as barrel, according to the latest government estimates. Domestic output will average 9.91 million barrels a day next year, the U.S. Energy Information Administration said in its monthly Short-Term Energy Outlook released Tuesday. … Read more

NuVista Energy Ltd. Announces Second Quarter 2017 Financial and Operating Results

August 8, 2017 by The Canadian Press

FOR: NUVISTA ENERGY LTD.
TSX SYMBOL: NVA

Date issue: August 08, 2017
Time in: 6:56 PM e

Attention:

CALGARY, ALBERTA–(Marketwired – Aug. 8, 2017) – NuVista Energy Ltd. (“NuVista”
or the “Company”) (TSX:NVA) is pleased to announce results for the three and
six months ended June 30, 2017 and provide an update on its future business
plans. NuVista experienced another strong quarter with continued development
drilling success. Funds from operations, production, and netbacks remained
strong despite planned and unplanned outages and a reduction in commodity
prices compared to the first quarter. This strength was primarily as a result
of favorable well results and increased condensate production as lower
condensate-ratio wells were shut in during outage periods.

NuVista is continuing to deliver on our accelerated 2017 drilling program, and
has made impactful progress in early Gold Creek development and Pipestone
delineation during the second quarter. We possess a material position in the
condensate-rich Wapiti Montney play which is delivering strong financial
returns to shareholders now and is expected to do so over the long term. With
our prudent focus on balance sheet strength, we maintain flexibility to adjust
capital spending and pace of growth commensurate with the business environment
while adhering to our long term growth and profitability objectives.

Significant Operating Highlights

/T/

— Achieved second quarter 2017 production of 25,454 Boe/d, well above the

top of our revised second quarter guidance range of 22,500 – 25,000
Boe/d. This result is due to strong recent well performance and is
despite 7,000 Boe/d of planned and unplanned outages in the quarter.
NuVista is pleased to report that current production has again exceeded
33,000 Boe/d in recent weeks following the outages;
— Achieved funds from operations of $39.3 million ($0.23/share, basic) for
the second quarter;
— Delivered funds from operations netback of $16.98/Boe for the second
quarter of 2017 despite weaker commodity pricing;
— Successfully executed a very active second quarter capital program of
$69.3 million, utilizing three to four drilling rigs for much of the
quarter to rig-release 11 (11.0 net) wells in our Wapiti Montney
condensate rich resource play;
— Achieved first production on five new wells in Bilbo and Gold Creek
during the second and early third quarter, for a total of 13 new Montney
wells onstream this year as of today. Approximately 15 more wells are
expected to be brought on production by the end of 2017;
— Well completion progress has been excellent with the recent dry summer
weather, and the 22 drilled uncompleted wells from our winter program
are expected to be finished fracture stimulation during August;
— Achieved second quarter operating costs of $10.66/Boe, in line with
expectations and first quarter operating costs. G&A costs continued in
line with expectations at $1.75/Boe for the second quarter of 2017;
— Exited the second quarter of 2017 with net debt of $182 million,
including credit facility borrowings of $93 million versus our facility
limit of $235 million. NuVista concluded the second quarter with a ratio
of net debt to annualized current quarter funds from operations of 1.2x;
and
— Achieved our fourth consecutive quarter with positive earnings. Earnings
in the second quarter of 2017 were $25.8 million ($0.15 per share, basic
and diluted).

/T/

Bilbo Block

The Bilbo compression and dehydration facility is now at capacity with
production up to 20,000 Boe/d depending on normal operational fluctuations.
Four additional wells reached IP30 in Bilbo during the second quarter. The
IP30’s for the four wells averaged 1,890 Boe/d including 885 Bbl/day of
condensate and a high condensate-gas ratio (CGR) of 129, while flowing on a
restricted basis. Two of the wells were regular fracture intensity and two were
high fracture intensity (HiFi). We are very pleased with ongoing regular and
HiFi well results, as evidenced by the high CGR ratios. The two HiFi wells are
outperforming the two regular fracture intensity wells. It is encouraging that
our ten-well moving average of Bilbo results continues to increase as the
average cost per well has continued to fall.

Capital costs for drilling, completing, and tie-ing in wells are expected to
increase approximately 10% for the second half of 2017 as compared to 2016,
roundly in line with previous estimates which included modest room for cost
inflation commensurate with the commodity price environment. Our aspiration is
that evolving HiFi well results will mitigate the effect of cost inflation with
higher production volumes.

The drilling of our 6-well pad at northeast Bilbo was concluded as planned, and
completion operations have been finished successfully last week. This pad will
now be equipped and tied in, then brought online in the fall.

Elmworth Block

The Elmworth block has recently reached a new production record of 15,000
Boe/d, including the Gold Creek production which is presently flowing through
the Elmworth facility. Completion activities are progressing well now with
summer weather, and a total of five new Elmworth wells have been completed
successfully and are being tied in. Completion operations are underway on a
further four-well pad. We expect to see continued production increases in
Elmworth through the second half of 2017 with the nine new wells being tied in,
reaching as high as 16,000 Boe/d.

Gold Creek Block

All three wells on our extended reach horizontal (“ERH”) pad at Gold Creek have
now been completed successfully, with two of the three wells having HiFi
completions. This pad contains wells with lateral length ranging from 2,900 m
to our record 3,850 m. A total of 164 stages were fractured in the wells,
including 71 stages in the longest well. Tied in to our Elmworth compressor and
dehydration facility, this three well pad is currently producing approximately
5,100 Boe/d including 15 MMcf/d of raw gas, 2,680 Bbls/d of condensate, and 270
Bbl/d of natural gas liquids.

We are very pleased with the projected IP30 data for these wells which have now
been on production for 15 to 23 days respectively. The three well average
projected IP30 flowrate is 1,575 Boe/d per well, including 660 Bbls/day of
condensate per well. This compares very favorably to the IP30 average of the
five original NuVista Gold Creek wells of 1,173 Boe/d and 408 Bbls/day
condensate per well. Importantly, the IP30 CGR of these three wells averaged
109 Bbls/MMcf as compared to 81 for the original five wells. In addition, the
average of the two HiFi wells outperformed the regular fracture interval well
on this pad by a margin of 64% and 82% on the Boe/d rate and condensate rate
respectively.

The pad was achieved with a drilling and completion cost of $30.3 million, in
line with expectations. We have now commenced drilling an additional well in
Gold Creek towards delineation of the north end of the block.

Pipestone Block

We have concluded the drilling of our first NuVista well in this emerging
block. The well was drilled to a lateral length of 3,100 m in just 19 days.
This well will be completed and flow tested, with results expected to be
available for reporting in the fall. The Pipestone stakeholder and development
plan is proceeding well to underpin our planned future growth in this area
which has continued to see exciting offsetting industry activity.

Lower Montney

NuVista has recently commenced drilling our first Lower Montney horizontal well
at Bilbo. We look forward to well results in the fall in this new emerging
layer of the Montney formation.

Commodity Price Risk Management Continues to Benefit NuVista

NuVista continues to benefit from the discipline of our strong hedging program
during this period of volatile commodity prices. This has been a challenging
summer for AECO, with spot natural gas prices under pressure briefly due to
temporary restrictions in pipeline and compressor station capacity on the
Alberta NGTL system. We are pleased to report that there was virtually no
impact to NuVista pricing as a result of these restrictions and price
reductions. We currently possess hedges which in aggregate cover 60% of
remaining 2017 projected liquids production at a floor WTI price of
C$67.31/Bbl, and 64% of remaining 2017 projected gas production at a price of
C$3.13/Mcf. Both of these percentage figures relate to production net of
royalty volumes. Due to our fixed price hedges, basis hedges, and our export
pipeline volumes, NuVista has less than 5% of our natural gas volumes exposed
to spot AECO prices in 2017.

2017 Outlook: Annual Guidance Reaffirmed

In accordance with our 2017 plan, NuVista has recently reduced activity to two
rigs drilling in the Wapiti Montney area. We have significant flexibility to
adjust the capital program quickly if desired, commensurate with our views on
commodity pricing and changes in the business environment. At this time we have
no plans to alter the program from our original 2017 budget, and re-affirm our
projected capital spending in the range of $280-300 million. Commodity prices
have continued with weakness and volatility so we will revisit our 2018
spending plans in the fall to determine if spending reductions are appropriate,
commensurate with the pricing view at that time. First and foremost, we will
continue to preserve our financial flexibility.

As previously stated, production through the third quarter of 2017 is expected
to be choppy due to the major 5-year-cycle planned maintenance outage at the
non-operated Simonette gas plant. Underlying production outside of outage
periods is proceeding at or above planned levels with run rates already
exceeding 33,000 Boe/d. As a result, we re-affirm our third and fourth quarter
production guidance ranges of 26,000 to 29,000 Boe/d and 35,000 to 38,000 Boe/d
respectively. Third quarter funds from operations netbacks are expected to be
temporarily reduced since it is the condensate rich Bilbo block which will
experience downtime in respect of the Simonette maintenance outage. Despite
this, the full year 2017 production guidance range of 28,000 to 31,000 Boe/d
remains intact.

Given top quality assets and a management team focused upon relentless
improvement, NuVista will continue to optimize well results, improve margins,
and grow our production profitably toward our 2021 goal of 60,000 Boe/d. We
would like to thank our staff, contractors, and suppliers for their continued
dedication and delivery, and we thank our board of directors and our
shareholders for their guidance and support as we build an ever more valuable
future for NuVista.

Please note that our corporate presentation is being updated and will be
available at www.nuvistaenergy.com on August 8, 2017. NuVista’s second quarter
2017 condensed interim financial statements and notes to the financial
statements and management’s discussion and analysis will be filed on SEDAR
(www.sedar.com) under NuVista Energy Ltd. on or before August 9, 2017 and can
also be accessed on NuVista’s website.

/T/

—————————————————————————-
—————————————————————————-
Corporate Highlights
—————————————————————————-
—————————————————————————-

Three months ended June 30
———————————-
($ thousands, except per share and per
$/Boe) 2017 2016 % Change
—————————————————————————-
FINANCIAL
Oil and natural gas revenues $ 79,401 $ 57,840 37
Funds from operations (1) 39,318 35,619 10
Per share – basic 0.23 0.23 –
Net earnings (loss) 25,767 (7,320) (452)
Per share – basic 0.15 (0.05) (400)
Total assets
Net debt (1)
Capital expenditures 69,250 28,765 141
Proceeds on property dispositions 528 69,495 (99)
Weighted average common shares
outstanding – basic 173,013 153,455 13
End of period common shares outstanding
—————————————————————————-
OPERATING
Production
——————————————
Natural gas (MMcf/d) 91.6 91.8 –
Condensate & oil (Bbls/d) 8,682 6,422 35
NGLs (Bbls/d) (2) 1,501 1,731 (13)
Total (Boe/d) 25,454 23,451 9
Condensate, oil & NGLs weighting 40% 35%
Condensate & oil weighting 34% 27%
Average selling prices (3) (4)
——————————————
Natural gas ($/Mcf) 3.72 3.25 14
Condensate & oil ($/Bbl) 57.26 49.42 16
NGLs ($/Bbl) 22.93 11.26 104
Netbacks ($/Boe)
——————————————
Oil and natural gas revenues 34.28 27.10 26
Realized gain on financial derivatives 0.51 3.39 (85)
Royalties (1.02) 1.31 (178)
Transportation expenses (3.13) (2.07) 51
Operating expenses (10.66) (9.66) 10
Operating netback (1) 19.98 20.07 –
Funds from operations netback (1) 16.98 16.69 2
—————————————————————————-
SHARE TRADING STATISTICS
High 7.73 7.18 8
Low 5.91 4.45 33
Close 6.55 6.25 5
Average daily volume 531,576 496,656 7
—————————————————————————-
—————————————————————————-

Six months ended June 30
———————————–
($ thousands, except per share and per
$/Boe) 2017 2016 % Change
—————————————————————————-
FINANCIAL
Oil and natural gas revenues $ 163,637 $ 117,559 39
Funds from operations (1) 82,572 65,907 25
Per share – basic 0.48 0.43 12
Net earnings (loss) 64,084 (4,867) (1,417)
Per share – basic 0.37 (0.03) (1,333)
Total assets 1,107,004 921,401 20
Net debt (1) 182,354 157,135 16
Capital expenditures 176,662 89,957 96
Proceeds on property dispositions 824 69,945 (99)
Weighted average common shares
outstanding – basic 172,887 153,387 13
End of period common shares outstanding 173,242 156,838 10
—————————————————————————-
OPERATING
Production
—————————————–
Natural gas (MMcf/d) 95.6 97.2 (2)
Condensate & oil (Bbls/d) 8,519 6,333 35
NGLs (Bbls/d) (2) 1,629 1,937 (16)
Total (Boe/d) 26,089 24,468 7
Condensate, oil & NGLs weighting 39% 34%
Condensate & oil weighting 33% 26%
Average selling prices (3) (4)
—————————————–
Natural gas ($/Mcf) 3.74 3.52 6
Condensate & oil ($/Bbl) 60.29 45.60 32
NGLs ($/Bbl) 20.24 7.99 153
Netbacks ($/Boe)
—————————————–
Oil and natural gas revenues 34.65 26.40 31
Realized gain on financial derivatives 0.26 4.20 (94)
Royalties (1.07) (0.06) 1,683
Transportation expenses (2.82) (2.42) 17
Operating expenses (10.69) (10.14) 5
Operating netback (1) 20.33 17.98 13
Funds from operations netback (1) 17.48 14.81 18
—————————————————————————-
SHARE TRADING STATISTICS
High 7.73 7.18 8
Low 5.52 2.72 103
Close 6.55 6.25 5
Average daily volume 505,910 480,409 5
—————————————————————————-
—————————————————————————-

1. See “Non-GAAP measurements”.
2. Natural gas liquids (“NGLs”) include butane, propane and ethane.
3. Product prices exclude realized gains/losses on financial derivatives.
4. The average NGLs selling price is net of tariffs and fractionation fees.

/T/

Basis of presentation

Unless otherwise noted, the financial data presented in this news release has
been prepared in accordance with Canadian generally accepted accounting
principles (“GAAP”) also known as International Financial Reporting Standards
(“IFRS”). The reporting and measurement currency is the Canadian dollar.

Advisories regarding oil and gas information

This news release contains the term barrels of oil equivalent (“Boe”). Natural
gas is converted to a Boe using six thousand cubic feet of gas to one barrel of
oil. Boes may be misleading, particularly if used in isolation. A conversion
ratio of one barrel to six thousand cubic feet of natural gas is based on an
energy equivalency conversion method primarily applicable at the burner tip and
does not represent a value equivalency at the wellhead. Given that the value
ratio based on the current price of crude oil as compared to natural gas is
significantly different from the energy equivalency of 6:1, utilizing a
conversion ratio on a 6:1 basis may be misleading as an indication of value.

National Instrument 51-101 – “Standards of Disclosure for Oil and Gas
Activities” includes condensate within the product type of natural gas liquids.
NuVista has disclosed condensate values separate from natural gas liquids
herein as NuVista believes it provides a more accurate description of NuVista’s
operations and results therefrom.

Any reference in this news release to initial production rates such as IP30 are
useful in confirming the presence of hydrocarbons, however, such rates are not
determinative of the rates at which such wells will continue production and
decline thereafter. While encouraging, readers are cautioned not to place
reliance on such rates in calculating the aggregate production for NuVista.

Advisory regarding forward-looking information and statements

This news release contains forward-looking statements and forward-looking
information (collectively, “forward-looking statements”) within the meaning of
applicable securities laws. The use of any of the words “will”, “expects”,
“believe”, “plans”, “potential” and similar expressions are intended to
identify forward-looking statements. More particularly and without limitation,
this news release contains forward looking statements, including management’s
assessment of: NuVista’s future focus, strategy, plans, opportunities and
operations; plans to reduce costs; expectations regarding future drilling and
completions costs; future G&A cost reductions; financial and commodity risk
management strategy; NuVista’s planned capital expenditures; the timing,
allocation and efficiency of NuVista’s capital program and the results
therefrom; the anticipated impact on NuVista’s production from scheduled plant
maintenance; the anticipated potential and growth opportunities associated with
NuVista’s asset base; future drilling results; and production guidance.
By their nature, forward-looking statements are based upon certain assumptions
and are subject to numerous risks and uncertainties, some of which are beyond
NuVista’s control, including the impact of general economic conditions,
industry conditions, current and future commodity prices, currency and interest
rates, anticipated production rates, borrowing, operating and other costs and
funds from operations, the timing, allocation and amount of capital
expenditures and the results therefrom, anticipated reserves and the
imprecision of reserve estimates, the performance of existing wells, the
success obtained in drilling new wells, the sufficiency of budgeted capital
expenditures in carrying out planned activities, access to infrastructure and
markets, competition from other industry participants, availability of
qualified personnel or services and drilling and related equipment, stock
market volatility, effects of regulation by governmental agencies including
changes in environmental regulations, tax laws and royalties; the ability to
access sufficient capital from internal sources and bank and equity markets;
and including, without limitation, those risks considered under “Risk Factors”
in our Annual Information Form. Readers are cautioned that the assumptions used
in the preparation of such information, although considered reasonable at the
time of preparation, may prove to be imprecise and, as such, undue reliance
should not be placed on forward-looking statements. NuVista’s actual results,
performance or achievement could differ materially from those expressed in, or
implied by, these forward-looking statements, or if any of them do so, what
benefits NuVista will derive therefrom. NuVista has included the
forward-looking statements in this news release in order to provide readers
with a more complete perspective on NuVista’s future operations and such
information may not be appropriate for other purposes. NuVista disclaims any
intention or obligation to update or revise any forward-looking statements,
whether as a result of new information, future events or otherwise, except as
required by law.

Future Oriented Financial Information

This news release contains future-oriented financial information and financial
outlook information (collectively, “FOFI”) about NuVista’s prospective
operational results and annual capital spending, all of which are subject to
the same assumptions, risk factors, limitations, and qualifications as set
forth above. Readers are cautioned that the assumptions used in the preparation
of such information, although considered reasonable at the time of preparation,
may prove to be imprecise and, as such, undue reliance should not be placed on
FOFI and forward-looking statements. NuVista’s actual results, performance or
achievement could differ materially from those expressed in, or implied by,
these forward-looking statements and FOFI, or if any of them do so, what
benefits NuVista will derive therefrom. NuVista has included the
forward-looking statements and FOFI in order to provide readers with a more
complete perspective on NuVista’s future operations and such information may
not be appropriate for other purposes. NuVista disclaims any intention or
obligation to update or revise any forward-looking statements, whether as a
result of new information, future events or otherwise, except as required by
law.

Non-GAAP measurements

Within the news release, references are made to terms commonly used in the oil
and natural gas industry. Management uses “funds from operations”, “funds from
operations per share”, “annualized current quarter funds from
operations”,”funds from operations netback”, “net debt”, “net debt to
annualized current quarter funds from operations” and “operating netback”.
These terms do not have any standardized meaning prescribed by GAAP and
therefore may not be comparable with the calculation of similar measures for
other entities. These terms are used by management to analyze operating
performance on a comparable basis with prior periods and to analyze the
liquidity of NuVista.

Funds from operations are based on cash flow from operating activities as per
the statement of cash flows before changes in non-cash working capital, asset
retirement expenditures, note receivable allowance (recovery) and environmental
remediation expenses (recovery). Funds from operations as presented is not
intended to represent operating cash flow or operating profits for the period
nor should it be viewed as an alternative to cash flow from operating
activities, per the statement of cash flows, net earnings or other measures of
financial performance calculated in accordance with GAAP.

Funds from operations per share is calculated based on the weighted average
number of common shares outstanding consistent with the calculation of net
earnings per share. Total revenue equals oil and natural gas revenues including
realized financial derivative gains/losses. Operating netback equals the total
of revenues including realized financial derivative gains/losses less
royalties, transportation and operating expenses calculated on a Boe basis.
Funds from operations netback is operating netback less general and
administrative, deferred share units, and interest expenses calculated on a Boe
basis. Net debt is calculated as long-term debt plus senior unsecured notes
plus adjusted working capital. Adjusted working capital is current assets less
current liabilities and excludes the current portions of the financial
derivative assets or liabilities, asset retirement obligations and deferred
premium on flow through shares. Net debt to annualized current quarter funds
from operations is net debt divided by annualized current quarter funds from
operations.

– END RELEASE – 08/08/2017

For further information:
Jonathan A. Wright
President and CEO
(403) 538-8501
OR
Ross L. Andreachuk
VP, Finance and CFO
(403) 538-8539

COMPANY:
FOR: NUVISTA ENERGY LTD.
TSX SYMBOL: NVA

INDUSTRY: Energy and Utilities – Oil and Gas
RELEASE ID: 20170808CC0064

Press Release from Marketwired 1-866-736-3779

Craig’s Corner – Are You Covered for Cyber Liability? What is it? Read On…

August 8, 2017 by EnergyNow Media

Cyber Liability addresses first-party and third-party exposures associated with websites, computer networks, and information assets. Exposures include privacy issues, including breaches of personally identifiable information as well as personal health information, corporate confidential information, virus transmission, data loss, cyber extortion, and security failure, among others. Traditional insurance policies have significant gaps in coverage for cyber … Read more

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FOR: CANACOL ENERGY LTD.TSX SYMBOL: CNEBVC SYMBOL: CNECOTCQX SYMBOL: CNNEFDate issue: August 08, 2017Time in: 4:30 PM eAttention:
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Also known as Japex, the company says it has decided to abandon the development due to low oil prices and the technical risks of reactivating the wells.

The pilot project had been in operation through a subsidiary called Japan Canada Oil Sands Ltd. since 1999 and produced a cumulative total of 35 million barrels of bitumen.

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The projects are 25 per cent owned by Nexen Energy, a subsidiary of China National Offshore Oil Corp. or CNOOC.

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FOR: PENGROWTH ENERGY CORPORATIONTSX SYMBOL: PGFNYSE SYMBOL: PGHDate issue: August 08, 2017Time in: 3:00 PM eAttention:
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Oil Trades Above $49 as Saudis Said to Curb Crude Sales to Asia

August 8, 2017August 8, 2017 by EnergyNow Media

August 8, 2017 (Bloomberg) Oil traded above $49 a barrel in New York after Saudi Arabia was said to cut crude sales to Asian buyers as part of its pledge to reduce exports and shrink a global glut. Futures rose 0.7 percent after dropping Monday. Saudi Arabia will supply lower volumes than some customers requested for September, … Read more

Five Things World Business Will be Talking About Today

August 8, 2017 by EnergyNow Media

August 8. 2017 (Bloomberg) Zuma’s future hangs in the balance, warnings mount over a pricey market, and Republicans discuss tax compromise. Here are some of the things people in markets are talking about today. Confidence vote President Jacob Zuma faces a vote by secret ballot in today’s motion of no-confidence in South Africa’s parliament. The opposition filed the motion after … Read more

SNC Targets Canada Projects as Trudeau Plan Gets Jump on Trump’s

August 8, 2017August 8, 2017 by EnergyNow Media

August 8, 2017 (Bloomberg) Canada’s biggest builder is keeping its focus at home even as U.S. President Donald Trump pledges to ramp up infrastructure spending next door. SNC-Lavalin Group Inc. is bidding on projects such as light-rail lines in Ottawa and Toronto and a C$6 billion ($4.7 billion) rapid-transit system for Montreal, as Prime Minister … Read more

Oil Holds Above $49 as Investors Look for More OPEC Compliance

August 8, 2017August 7, 2017 by EnergyNow Media

August 7, 2017 (Bloomberg) Oil held above $49 a barrel as investors looked for signs that the world’s largest oil producing countries will solidify compliance with their supply-cut deal. Futures dropped 0.4 percent in New York. Russia and Kuwait were said to meet producers such as Iraq in Abu Dhabi to discuss compliance to the OPEC … Read more

Keystone XL’s Path Up for Grabs as Nebraska Commission Weighs In

August 8, 2017August 7, 2017 by EnergyNow Media

August 7, 2017 (Bloomberg) The future of TransCanada Corp.’s Keystone XL pipeline could hinge on whether a Nebraska commission believes the project is in the public’s interest or a private land grab as property owners claim. More than 90 percent of TransCanada’s preferred 270 mile route through the state would cut across privately owned land, … Read more

EU slaps sanctions on 3 Russians, firms over Crimea turbines

August 4, 2017 by The Canadian Press

BRUSSELS — The European Union has slapped sanctions on three Russians including top energy officials and three companies accused of involvement in the transfer of gas turbines to Crimea.

The EU imposed sanctions on Russia three years ago after it annexed Ukraine’s Crimean Peninsula, and refuses to recognize Moscow’s authority there.

It said in a statement Friday that the turbines were sold to Russia by German electricity giant Siemens for use on Russian territory. Moving them to Crimea breaches conditions of sale.

Among the Russians are a vice minister for energy and an Energy Ministry head of department.

The EU measures involve a freeze on their assets and travel bans. The move means that a total of 153 people and 40 entities like companies have been sanctioned over Russia’s destabilization of Ukraine.

The Associated Press

Five Things World Business Will be Talking About Today

August 4, 2017 by EnergyNow Media

August 4, 2017 (Bloomberg) It’s jobs day, a grand jury is formed in the Trump-Russia investigation, and Brexit bites banks. Here are some of the things people in markets are talking about today. Jobs report The jobs report for July comes out at 8:30 a.m. Eastern Time and economists expect the report to show that the … Read more

Canada’s Jobless Rate Falls, Trade Disappoints: Key Takeaways

August 4, 2017August 4, 2017 by EnergyNow Media

August 4, 2017 (Bloomberg) Canada’s jobless rate fell last month to 6.3 percent, the lowest since October 2008, as the nation’s labor market continued its strong performance with an eighth straight employment increase. The country added 10,900 jobs in July, according to Statistics Canada data Friday. The decline in the jobless rate was due in … Read more

Oil Retreats After 2017’s Best Week as Output Gain Back in Focus

August 4, 2017August 4, 2017 by EnergyNow Media

August 4, 2017 (Bloomberg) Oil is back down again this week following the year’s biggest rally as investor focus shifted to rising output from the U.S. and OPEC, and away from a seasonal increase in American fuel demand. Futures in New York were down 1.4 percent for the week after an 8.6 percent surge in … Read more

TORC Oil & Gas Ltd. Announces Second Quarter 2017 Financial & Operational Results; Increases 2017 Production Guidance

August 8, 2017August 4, 2017 by EnergyNow Media

CALGARY, Aug. 2, 2017 /CNW/ – TORC Oil & Gas Ltd. (“TORC” or the “Company”) (TSX: TOG) is pleased to announce its financial and operating results for the three and six months ended June 30, 2017. The associated management’s discussion and analysis (“MD&A”) and unaudited interim financial statements as at and for the three and six months ended June … Read more

Tourmaline More Than Doubles Six Month Cash Flow and Continues Profitable Strong Growth

August 8, 2017August 4, 2017 by EnergyNow Media

CALGARY, Aug. 2, 2017 /CNW/ – Tourmaline Oil Corp. (TSX:TOU) (“Tourmaline” or the “Company”) is pleased to release strong financial and operating results for the second quarter of 2017. HIGHLIGHTS Financial Results Second quarter earnings were $108.6 million ($0.40/share) underscoring the fundamental profitability of Tourmaline’s EP business in all three core complexes. Second quarter 2017 cash flow(1) was $ 313.3 million ($1.16/share) up … Read more

Alberta Energy Regulator charges Syncrude in deaths of 31 great blue herons

August 3, 2017August 3, 2017 by The Canadian Press

CALGARY — The Alberta Energy Regulator has charged Syncrude Canada in the deaths of 31 great blue herons two years ago at its Mildred Lake oilsands mine in northern Alberta.

The company is charged under the provincial Environmental Protection and Enhancement Act with failing to properly store a hazardous substance in a way that ensures it doesn’t come into direct contact with or contaminate animals.

Syncrude, which faces a penalty of up to $500,000 if convicted, is to appear in court on Sept. 27 in Fort McMurray, Alta.

Spokesman Will Gibson said Syncrude is reviewing the charge to determine its next step but has already made changes to better protect birds on site.

“This has strengthened our resolve to make sure that bird deterrent systems are everywhere they are needed on our site,” he said, adding Syncrude’s plan previously focused mainly on its tailings ponds, which store water contaminated with oil, chemicals and clay from its oilsands processes.

“Our waterfowl protection plan now addresses incidental bodies of water which includes areas such as sumps where the dead herons were found.”

He said he didn’t know what caused the death of the birds at the sump, which he described as an inactive dugout near a pump station.

Syncrude was previously fined $3 million for an incident in 2008 when more than 1,600 ducks died after landing on a tailings pond.

Two years later, more than 550 birds had to be killed when an early winter storm forced them to land on waste ponds belonging to Syncrude and Suncor Energy.

The Canadian Press

KPMG and 3esi-Enersight invite all E&P professionals to take the inaugural E&P Planning Survey.

September 4, 2017August 3, 2017 by EnergyNow Media

KPMG and 3esi-Enersight invite all E&P professionals to take the inaugural E&P Planning Survey. Responses are anonymous, and the results will be presented to the industry to help decision makers gain a better understanding of the planning challenges companies face in today’s dynamic environment. Take the Survey: https://3esi-enersight.com/events/kpmg-3esi-enersight-2017-ep-planning-survey/

Gran Tierra Energy Inc. Provides Operations Update Highlighted by Progress with Costayaco A-Limestone, Putumayo Exploration Success and Acordionero Development

August 3, 2017 by The Canadian Press

FOR: GRAN TIERRA ENERGY INC.NYSE MKT SYMBOL: GTETSX SYMBOL: GTEDate issue: August 03, 2017Time in: 8:04 PM eAttention:
CALGARY, ALBERTA–(Marketwired – Aug. 3, 2017) – Gran Tierra Energy Inc. (“Gran
Tierra” or the “Company”) (NYSE American:GTE)(NYSE M…

Gran Tierra Energy Inc. Announces Second Quarter 2017 Results Highlighted by Strong Financial Performance, 22% Increase in Production and Continued Success in Putumayo and Middle Magdalena Basins

August 3, 2017 by The Canadian Press

FOR: GRAN TIERRA ENERGY INC.
TSX SYMBOL: GTE
NYSE MKT SYMBOL: GTE

Date issue: August 03, 2017
Time in: 8:02 PM e

Attention:

CALGARY, ALBERTA–(Marketwired – Aug. 3, 2017) – Gran Tierra Energy Inc. (“Gran
Tierra” or the “Company”) (NYSE American:GTE)(NYSE MKT:GTE)(TSX:GTE), a company
focused on oil and gas exploration and production in Colombia, today announced
its financial and operating results for the quarter ended June 30, 2017. All
dollar amounts are in United States (“U.S.”) dollars unless otherwise
indicated. Per barrel of oil equivalent (“BOE”) amounts are based on working
interest (“WI”) sales before royalties. For per BOE amounts based on net after
royalty (“NAR”) production, see Gran Tierra’s Quarterly Report on Form 10-Q
filed August 3, 2017.

Key Highlights

/T/

— Increased average WI production before royalties in the second quarter

2017 (“the Quarter”) to 31,437 barrels of oil equivalent per day
(“BOEPD”), 22% higher than second quarter 2016’s average WI production
before royalties of 25,744 BOEPD. The Quarter’s average WI production
before royalties was up 5%, or 1,558 BOEPD, relative to first quarter
2017 (the “Prior Quarter”), largely as a result of record production
from development wells drilled in the Acordionero field and production
deferred during the Prior Quarter to test new discoveries.

— On June 30, 2017, the Company completed the disposition of its assets in

Brazil for a purchase price of $35 million which, after certain interim
closing adjustments, resulted in cash consideration of approximately $38
million.

— Demonstrated ongoing strong financial performance in the second quarter

2017:
— Net loss of $7 million compared with net income of $13 million in
the Prior Quarter, and included loss on sale of the Company’s Brazil
business unit of $9 million;

— Funds flow from operations(1) increased by 13% to $51 million
compared with the Prior Quarter;

— Operating netback(1) on a per BOE basis decreased by 8% relative to
the Prior Quarter to $21.91 per BOE, but increased 9% relative to
second quarter 2016;

— Transportation expenses for the Quarter of $2.28 per BOE, a decrease
of 12% compared with the Prior Quarter due to the use of
transportation routes which had lower costs per BOE than the routes
used in the Prior Quarter;

— Operating expenses for the Quarter of $9.50 per BOE increased by 7%
compared with the Prior Quarter, primarily as a result of increased
workover expenses and the Mocoa landslides on April 1, 2017;

— General and Administrative (“G&A”) expenses for the Quarter
decreased by 5% to $2.67 per BOE compared with the Prior Quarter;

— Capital expenditures in the Quarter were $58 million, mainly funded
by funds flow from operations;

— The Company exited the Quarter with $145 million of undrawn capacity
on its $300 million credit facility and $53 million of cash on the
balance sheet. Gran Tierra’s committed borrowing base increased by
$50 million to $300 million effective June 1, 2017.
— Demonstrated strong operational results during the Quarter and through
July 2017:
— Continued A-Limestone Success at Costayaco, 100% WI

— Strong production performance continues from three vertical
wells and one horizontal well

— The second horizontal well in the field, CYC-29, has been
successfully drilled and completed with acid injected into the
first six of ten planned stages. The well was put onto natural
flow over a two day period and stabilized at 1,200 barrels of
fluid per day (“bfpd”) with a 40% water cut (spent acid), 27
degrees to 28 degrees API oil, GOR of 337 scf/stb, 180 pounds
per square inch (“psi”) flowing wellhead pressure and flowing
bottom hole pressure of 3,008 psi. These results were achieved
with only 60% of the well stimulated; the productivity index is
estimated to be 4 bfpd per psi (“bfpd/psi”), approximately
double the CYC-28’s productivity index of 1.9 bfpd/psi. The
Company is in the process of running a high capacity electric
submersible pump (“ESP”)

— Multi-Zone Discovery with Vonu-1 Exploration Well, Putumayo-1 (“PUT-
1”) Block, 55% WI

— The well had successful short-term production tests from the A-
Limestone and U Sand and was brought on production for a long-
term test from the A-Limestone alone on July 21, 2017

— Progress with N Sands Wells in Putumayo-7 (“PUT-7”) Block, 100% WI

— Cumplidor-1 and Confianza-1: both on production from the N Sand.
As a result of pump failures, the PUT-7 Block only averaged 294
BOEPD during the Quarter but is currently producing
approximately 1,866 BOEPD.

— Continued Strong Performance at Acordionero Field, 100% WI

— Four more development wells have been brought on production with
one more development well successfully drilled and cased;
production from the field averaged 8,362 BOEPD in the Quarter,
up from 6,198 BOEPD in the Prior Quarter and 5,686 BOPED in the
fourth quarter of 2016; Acordionero exited the Quarter at 10,005
BOEPD and is currently producing approximately 11,120 BOEPD.
— On April 27, 2017, the Company closed the previously announced strategic
acquisitions of the Santana and Nancy-Burdine-Maxine blocks, along with
key pipeline and transportation infrastructure, for cash consideration
of approximately $30 million.

— Gran Tierra expects 2017 average WI production before royalties to be

33,300 to 34,300 BOEPD, adjusted for the sale of its Brazil business
unit effective June 30, 2017, which would represent an increase of 23%
to 27% from our 2016 average WI production before royalties of 27,062
BOEPD. The Company revised the top end of the guidance as a result of
the testing of additional zones in the first and second quarters of
2017, operational delays in bringing onstream the CYC-28 and 29 A-
Limestone horizontal wells and a pump failure in Cumplidor-1 in the PUT-
7 Block. The Company disposed of 950 BOEPD of non-operated, low netback
production in the fourth quarter of 2016 and an additional 1,400 BOEPD
of non-core assets located in Brazil on June 30, 2017.

— Gran Tierra is currently producing 34,178 BOEPD, and expects fourth

quarter 2017 average WI production before royalties to be 35,000 to
37,000 BOEPD.

— Gran Tierra has also narrowed the range of the Company’s projected 2017

capital program to $200 million to $225 million, which is expected to be
funded from cash flow from operations.

/T/

Message to Shareholders

Gary Guidry, President and Chief Executive Officer of Gran Tierra, commented
“Our portfolio in Colombia delivered strong production growth and cash flow
generation during the Quarter. In 2016, we focused on transforming the
portfolio by consolidating our land position in the Putumayo Basin, acquiring
strategic infrastructure, and diversifying into the Middle Magdalena Valley
(“MMV”) Basin. In the Quarter, we are starting to see the results of this
transformation. We currently are generating free cash flow from our three core
fields – Costayaco, Moqueta and Acordionero – which we will continue to deploy
into our exciting exploration portfolio. Despite the ongoing challenges of
volatile world oil prices, we believe our low cost structure and solid
production base allow us to successfully create value in a variety of pricing
environments.

In the A-Limestone at the Costayaco field, we are now producing oil from three
recompleted vertical wells and one horizontal well. The CYC-29, the second
horizontal well targeting the A-Limestone has been successfully drilled and
completed with encouraging flow test results and planned production testing
about to begin. The CYC-29’s estimated productivity index is approximately
twice the CYC-28’s productivity index. In the adjacent PUT-1 Block, we have
confirmed that the Vonu-1 exploration well is a new oil discovery in the
A-Limestone and U Sand. With oil productivity now established in the Costayaco
field, the PUT-1 Block in the north, and the PUT-7 Block in the south of the
Putumayo Basin, we believe the A-Limestone may be a basin-wide play with
significant resource potential. In addition, at PUT-7, our N Sand program is
back on track with both the Cumplidor-1 and Confianza-1 wells on production. We
have a very strong Putumayo land position with 16 blocks and 1.1 million gross
acres covering the main exploration fairways for both the A-Limestone and the N
Sand oil plays, both of which will be further tested through the multiple
exploration wells we plan on drilling in the second half of 2017 and throughout
2018 and 2019.

In the Middle Magdalena Valley (“MMV”) Basin, the Acordionero field continues
to exceed our expectations where our continuous development drilling program
has delivered four more oil wells which are all now on production. Since
acquiring the MMV Basin properties August 23, 2016, we have been able to reduce
average drilling costs per well by $1.3 million (33% reduction) as well as
drilling times (28% reduction), with our best well so far taking only 25 days
from spud to onstream. When we acquired these assets last year, the MMV Basin
fields were producing 5,620 BOEPD and now, approximately 11 months later, the
fields are producing 11,958 BOEPD. Also, since the acquisition, the MMV Basin
properties have generated $59 million of operating netback while we incurred
$42 million of capital expenditures, as of June 30, 2017.

Our strong Quarter financial performance is demonstrated by the fact that,
notwithstanding a net loss of $7 million, which includes a $9 million loss on
the sale of the Brazil business, funds flow from operations was up 13% relative
to the Prior Quarter to $51 million, and covered 88% of the Company’s capital
expenditures in the Quarter of $58 million. The increase in funds flow from
operations was due to lower current income and equity taxes, partially offset
by lower operating netbacks commensurate with the decrease in oil price. During
the Quarter, we repurchased 4 million common shares of Gran Tierra stock
pursuant to our previously announced normal course issuer bid.

Despite delays in production start ups for the CYC-28 and 29 A-Limestone
horizontal wells in the Costayaco field, and the Cumplidor-1 N Sand well in the
PUT-7 Block, strong production growth at Acordionero allowed Gran Tierra’s
total WI production before royalties for second quarter 2017 to average 31,437
BOEPD, which was 5% higher compared to 29,879 BOEPD in the Prior Quarter.

Gran Tierra’s strong financial and production performance in second quarter
2017 reaffirms our plans over the next three years to deliver visible organic
reserves and production growth and to drill a total of 30 to 35 exploration
wells, with all of this activity expected to be funded from cash flows from
operations.”

Financial and Operational Highlights (all amounts in $000s, except per share
and BOE amounts)

/T/

Three Months Ended Six Months Ended
——————————————————-
——————————————————-
June 30, March 31, June 30, June 30, June 30,
——————————————————-
——————————————————-
2017 2017 2016 2017 2016
——————————————————-
——————————————————-
Net Income (Loss) $ (6,807) $ 12,771 $ (63,559) $ 5,964 $(108,591)
Per Share – Basic
and Diluted $ (0.02) $ 0.03 $ (0.21) $ 0.01 $ (0.37)

Oil and Gas Sales $ 96,128 $ 94,659 $ 71,713 $ 190,787 $ 129,116
Operating Expenses (27,208) (23,937) (17,748) (51,145) (36,815)
Transportation
Expenses (6,492) (6,942) (6,217) (13,434) (18,545)
——————————————————-
Operating Netback(1) $ 62,428 $ 63,780 $ 47,748 $ 126,208 $ 73,756
——————————————————-
——————————————————-

G&A Expenses Before
Stock-Based
Compensation $ 7,610 $ 7,563 $ 5,987 $ 15,173 $ 11,638
Stock-Based
Compensation 1,903 1,149 1,988 3,052 3,386
——————————————————-
G&A Expenses,
Including Stock
Based Compensation $ 9,513 $ 8,712 $ 7,975 $ 18,225 $ 15,024
——————————————————-
——————————————————-

EBITDA(1) $ 41,634 $ 61,538 $ 40,532 $ 103,172 $ 64,716

Funds Flow from
Operations(1) $ 50,920 $ 45,026 $ 33,755 $ 95,946 $ 45,318

Capital Expenditures $ 57,865 $ 46,160 $ 18,407 $ 104,025 $ 44,587

Average Daily Volumes
(BOEPD)
———————
———————
WI Production Before
Royalties 31,437 29,879 25,744 30,663 25,677
Royalties (5,014) (5,089) (4,049) (5,051) (3,435)
——————————————————-
Production NAR 26,423 24,790 21,695 25,612 22,242
(Increase) Decrease
in Inventory (140) 18 723 (61) 1,682
——————————————————-
Sales 26,283 24,808 22,418 25,551 23,924
——————————————————-
——————————————————-
Royalties, % of WI
Production Before
Royalties 16% 17% 16% 16% 13%

Per BOE(2)
———————
———————
Brent $ 50.92 $ 54.66 $ 45.52 $ 52.79 $ 39.61
Quality and
Transportation
Discount (10.73) (12.27) (10.37) $ (11.53) $ (9.95)
Royalties (6.50) (7.22) (5.14) $ (6.85) $ (3.73)
——————————————————-
Average Realized
Price 33.69 35.17 30.01 $ 34.41 $ 25.93
Transportation
Expenses (2.28) (2.58) (2.60) (2.42) (3.72)
——————————————————-
Average Realized
Price Net of
Transportation
Expenses 31.41 32.59 27.41 31.99 22.21
Operating Expenses (9.50) (8.87) (7.40) (9.20) (7.36)
——————————————————-
Operating Netback(1) 21.91 23.72 20.01 22.79 14.85
G&A Expenses (2.67) (2.81) (2.51) (2.74) (2.34)
Transaction Expenses – – – – (0.25)
Severance Expenses – – (0.12) – (0.26)
Equity Tax – (0.45) – (0.22) (0.61)
Realized Foreign
Exchange Loss – (0.36) (0.23) (0.18) (0.30)
Realized Financial
Instruments Gain
(Loss) 0.16 0.29 – 0.22 0.01
Interest Expense,
Excluding
Amortization of Debt
Issuance Costs (0.95) (0.93) (0.72) (0.94) (0.42)
Interest Income 0.09 0.15 0.31 0.12 0.24
Current Income Tax
Expense (0.62) (2.76) (2.42) (1.66) (1.57)
——————————————————-
Cash Netback(1) $ 17.92 $ 16.85 $ 14.32 $ 17.39 $ 9.35
——————————————————-
——————————————————-

Share Information
(000s)
———————
———————
Common Stock
Outstanding, End of
Period 386,742 390,815 289,323 386,742 289,323
Exchangeable Shares
Outstanding, End of
Period 8,030 8,192 8,514 8,030 8,514
Weighted Average
Number of Common and
Exchangeable Shares
Outstanding – Basic 398,585 399,007 296,566 398,795 295,189
Weighted Average
Number of Common and
Exchangeable Shares
Outstanding –
Diluted 398,585 399,046 296,566 398,816 295,189

As at
———————————-
———————————-
June 30, December 31, %
(Thousands of U.S. Dollars) 2017 2016 Change
———————————-
———————————-
Cash, Cash Equivalents and Current
Restricted Cash and Cash Equivalents $ 59,154 $ 33,497 77
Revolving Credit Facility $ 155,000 $ 90,000 72
Convertible Senior Notes $ 115,000 $ 115,000 –

/T/

(1) Operating netbacks, earnings before interest, taxes, depletion,
depreciation, accretion and impairment (“DD&A”) (“EBITDA”), funds flow from
operations and cash netbacks are non-GAAP measures and do not have a
standardized meaning under generally accepted accounting principles in the
United States of America (“GAAP”). Refer to “Non-GAAP Measures” in this press
release for descriptions of these non-GAAP measures and reconciliations to the
most directly comparable measures calculated and presented in accordance with
GAAP.

(2) Per BOE amounts are based on WI sales before royalties. For per BOE amounts
based on NAR production, see Gran Tierra’s Quarterly Report on Form 10-Q filed
August 3, 2017.

Conference Call Information:

Gran Tierra Energy Inc. will host its second quarter 2017 results conference
call on Friday, August 4, 2017. Details of the conference call are as follows:

/T/

—————————————————————————-
Date: Friday, August 4, 2017
—————————————————————————-
Time: 11:00 a.m. Eastern Time (9:00 a.m. Mountain Time)
—————————————————————————-
North American
participants call: 1-844-348-3792 (Toll-Free)
—————————————————————————-
Outside of Canada & USA
call: 1-614-999-9309
—————————————————————————-

/T/

Interested parties may also access the live webcast on the investor relations
page of Gran Tierra’s website at www.grantierra.com. An archive of the webcast
will be available on Gran Tierra’s website until August 11, 2017. In addition,
an audio replay of the conference call will be available following the call
until August 8, 2017. To access the replay, dial toll-free 1-855-859-2056
(North America), or 1-404-537-3406 (outside of Canada and USA), conference ID:
57318699.

About Gran Tierra Energy Inc.

Gran Tierra Energy Inc. together with its subsidiaries is an independent
international energy company focused on oil and natural gas exploration and
production in Colombia. The Company also has business activities in Peru. The
Company is focused on its existing portfolio of assets in Colombia and will
pursue new growth opportunities throughout Colombia, leveraging our financial
strength. The Company’s common shares trade on the NYSE American and the
Toronto Stock Exchange under the ticker symbol GTE. Additional information
concerning Gran Tierra is available at www.grantierra.com. Information on the
Company’s website does not constitute a part of this press release. Investor
inquiries may be directed to info@grantierra.com or (403) 265-3221.

Gran Tierra’s Securities and Exchange Commission filings are available on a
website maintained by the Securities and Exchange Commission at www.sec.gov and
on SEDAR at www.sedar.com.

Forward Looking Statements and Legal Advisories:

This press release contains opinions, forecasts, projections, and other
statements about future events or results that constitute forward-looking
statements within the meaning of the United States Private Securities
Litigation Reform Act of 1995, Section 27A of the Securities Act of 1933, as
amended, and Section 21E of the Securities Exchange Act of 1934, as amended,
and financial outlook and forward looking information within the meaning of
applicable Canadian securities laws (collectively, “forward-looking
statements”). Such forward-looking statements include, but are not limited to,
Gran Tierra’s committed borrowing base, anticipated drilling efficiencies, the
Company’s expectations and guidance, the Company’s strategies, the Company’s
operations including planned operations, the Company’s ability to succeed in a
variety of pricing environments, the base capital program, the allocation of
capital, the exploration and development of certain blocks and fields,
production growth or estimates and drilling plans including trends,
infrastructure schedules, the expected timing of certain projects and how such
drilling plans will be financed.

The forward-looking statements contained in this press release reflect several
material factors and expectations and assumptions of Gran Tierra including,
without limitation, that Gran Tierra will continue to conduct its operations in
a manner consistent with its current expectations, the accuracy of testing and
production results and seismic data, pricing and cost estimates (including with
respect to commodity pricing and exchange rates), rig availability, the effects
of drilling down-dip, the effects of waterflood and multi-stage fracture
stimulation operations, the extent and effect of delivery disruptions, and the
general continuance of current or, where applicable, assumed operational,
regulatory and industry conditions including in areas of potential expansion,
and the ability of Gran Tierra to execute its current business and operational
plans in the manner currently planned. Gran Tierra believes the material
factors, expectations and assumptions reflected in the forward-looking
statements are reasonable at this time but no assurance can be given that these
factors, expectations and assumptions will prove to be correct.

Among the important factors that could cause actual results to differ
materially from those indicated by the forward-looking statements in this press
release are: sustained or future declines in commodity prices; potential future
impairments and reductions in proved reserve quantities and value; Gran
Tierra’s operations are located in South America, and unexpected problems can
arise due to guerilla activity; technical difficulties and operational
difficulties may arise which impact the production, transport or sale of our
products; geographic, political and weather conditions can impact the
production, transport or sale of our products; the risk that current global
economic and credit conditions may impact oil prices and oil consumption more
than Gran Tierra currently predicts; the ability of Gran Tierra to execute its
business plan; the risk that unexpected delays and difficulties in developing
currently owned properties may occur; the timely receipt of regulatory or other
required approvals for our operating activities; the failure of exploratory
drilling to result in commercial wells; unexpected delays due to the limited
availability of drilling equipment and personnel; the risk that oil prices
could continue to fall, or current global economic and credit market conditions
may impact oil prices and oil consumption more than Gran Tierra currently
predicts, which could cause Gran Tierra to further modify its strategy and
capital spending program; and the risk factors detailed from time to time in
Gran Tierra’s periodic reports filed with the Securities and Exchange
Commission, including, without limitation, under the caption ” Risk Factors” in
Gran Tierra’s Annual Report on Form 10-K filed March 1, 2017 and its Quarterly
Reports. These filings are available on the Web site maintained by the
Securities and Exchange Commission at www.sec.gov and on SEDAR at
www.sedar.com. Although the current capital spending program and long term
strategy of Gran Tierra is based upon the current expectations of the
management of Gran Tierra, should any one of a number of issues arise, Gran
Tierra may find it necessary to alter its business strategy and/or capital
spending program and there can be no assurance as at the date of this press
release as to how those funds may be reallocated or strategy changed.

All forward-looking statements are made as of the date of this press release
and the fact that this press release remains available does not constitute a
representation by Gran Tierra that Gran Tierra believes these forward-looking
statements continue to be true as of any subsequent date. Actual results may
vary materially from the expected results expressed in forward-looking
statements. Gran Tierra disclaims any intention or obligation to update or
revise any forward-looking statements, whether as a result of new information,
future events or otherwise, except as expressly required by applicable
securities laws. Gran Tierra’s forward-looking statements are expressly
qualified in their entirety by this cautionary statement.

The estimates of future production set forth in this press release may be
considered to be future-oriented financial information or a financial outlook
for the purposes of applicable Canadian securities laws. Financial outlook and
future-oriented financial information contained in this press release about
prospective financial performance, financial position or cash flows are based
on assumptions about future events, including economic conditions and proposed
courses of action, based on management’s assessment of the relevant information
currently available, and to become available in the future. In particular, this
press release contains projected operational information for 2017 average WI
production and fourth quarter 2017 average WI production. These projections
contain forward-looking statements and are based on a number of material
assumptions and factors set out above. Actual results may differ significantly
from the projections presented herein. These projections may also be considered
to contain future-oriented financial information or a financial outlook. The
actual results of Gran Tierra’s operations for any period could vary from the
amounts set forth in these projections, and such variations may be material.
See above for a discussion of the risks that could cause actual results to
vary. The future-oriented financial information and financial outlooks
contained in this press release have been approved by management as of the date
of this press release. Readers are cautioned that any such financial outlook
and future-oriented financial information contained herein should not be used
for purposes other than those for which it is disclosed herein. The Company and
its management believe that the prospective financial information has been
prepared on a reasonable basis, reflecting management’s best estimates and
judgments, and represent, to the best of management’s knowledge and opinion,
the Company’s expected course of action. However, because this information is
highly subjective, it should not be relied on as necessarily indicative of
future results.

Non-GAAP Measures

This press release includes non-GAAP financial measures as further described
herein. These non-GAAP measures do not have a standardized meaning under GAAP.
Investors are cautioned that these measures should not be construed as
alternatives to net income or loss or other measures of financial performance
as determined in accordance with GAAP. Gran Tierra’s method of calculating
these measures may differ from other companies and, accordingly, they may not
be comparable to similar measures used by other companies. Each non-GAAP
financial measure is presented along with the corresponding GAAP measure so as
not to imply that more emphasis should be placed on the non-GAAP measure.

Operating netback as presented is oil and gas sales net of royalties and
operating and transportation expenses. Cash netback as presented is net income
or loss before DD&A expenses, asset impairment, deferred income tax recovery,
amortization of debt issuance costs, unrealized foreign exchange gains and
losses, loss on sale of Brazil business unit, gain on acquisition, non-cash
operating and G&A expenses and unrealized financial instruments gains and
losses. Management believes that operating and cash netback are useful
supplemental measures for investors to analyze financial performance and
provide an indication of the results generated by Gran Tierra’s principal
business activities prior to the consideration of other income and expenses.
See the table entitled Financial and Operational Highlights, above for the
components of operating netback. A reconciliation from net loss to cash netback
is as follows:

/T/

Three Months Ended Six Months Ended
——————————————————-
——————————————————-
June 30, March 31, June 30, June 30, June 30,
——————————————————-
——————————————————-
Cash Netback – Non-
GAAP Measure ($000s) 2017 2017 2016 2017 2016
——————————————————-
——————————————————-
Net income (loss) $ (6,807) $ 12,771 $ (63,559) $ 5,964 $(108,591)
Adjustments to
reconcile net income
(loss) income to
cash netback
DD&A expenses 31,644 26,593 31,884 58,237 68,796
Asset impairment 169 283 92,843 452 149,741
Deferred income tax
(recovery) expense 11,525 11,379 (28,615) 22,904 (55,751)
Amortization of
debt issuance
costs 620 605 489 1,225 629
Unrealized foreign
exchange loss
(gain) 3,895 (2,819) 233 1,076 50
Loss on sale of
Brazil business
unit 9,076 – – 9,076 –
Gain on acquisition – – – – (11,712)
Non-cash operating
expenses 77 54 74 131 136
Non-cash G&A
expenses 1,903 1,149 1,988 3,052 3,386
Unrealized
financial
instruments gain (999) (4,671) (1,069) (5,670) (180)
——————————————————-
Cash netback $ 51,103 $ 45,344 $ 34,268 $ 96,447 $ 46,504
——————————————————-
——————————————————-

/T/

EBITDA, as presented, is net income or loss adjusted for depletion,
depreciation and accretion (“DD&A”) expenses, asset impairment, interest
expense and income tax recovery or expense. Management uses these financial
measures to analyze performance and income or loss generated by our principal
business activities prior to the consideration of how non-cash items affect
that income or loss, and believes that these financial measures are also useful
supplemental information for investors to analyze performance and our financial
results. A reconciliation from net income or loss to EBITDA is as follows:

/T/

Three Months Ended Six Months Ended
——————————————————-
——————————————————-
June 30, March 31, June 30, June 30, June 30,
——————————————————-
——————————————————-
EBITDA – Non-GAAP
Measure ($000s) 2017 2017 2016 2017 2016
——————————————————-
——————————————————-
Net income (loss) $ (6,807) $ 12,771 $ (63,559) $ 5,964 $(108,591)
Adjustments to
reconcile net income
(loss) to EBITDA
DD&A expenses 31,644 26,593 31,884 58,237 68,796
Asset impairment 169 283 92,843 452 149,741
Interest expense 3,331 3,095 2,201 6,426 2,720
Income tax expense
(recovery) 13,297 18,796 (22,837) 32,093 (47,950)
——————————————————-
EBITDA $ 41,634 $ 61,538 $ 40,532 $ 103,172 $ 64,716
——————————————————-
——————————————————-

/T/

Funds flow from operations, as presented, is net income or loss adjusted for
DD&A expenses, asset impairment, deferred tax expense or recovery, stock-based
compensation expense, amortization of debt issuance costs, cash settlement of
RSUs, unrealized foreign exchange gains and losses, financial instruments
gains, cash settlement of financial instruments, loss on sale of Brazil
business unit and gain on acquisition. Management uses this financial measure
to analyze performance and income or loss generated by our principal business
activities prior to the consideration of how non-cash items affect that income
or loss, and believes that this financial measure is also useful supplemental
information for investors to analyze performance and our financial results. A
reconciliation from net income or loss to funds flow from operations is as
follows:

/T/

Three Months Ended Six Months Ended
——————————————————-
——————————————————-
June 30, March 31, June 30, June 30, June 30,
——————————————————-
——————————————————-
Funds Flow From
Operations – Non-
GAAP Measure ($000s) 2017 2017 2016 2017 2016
——————————————————-
——————————————————-
Net income (loss) $ (6,807) $ 12,771 $ (63,559) $ 5,964 $(108,591)
Adjustments to
reconcile net income
(loss) to funds flow
from operations
DD&A expenses 31,644 26,593 31,884 58,237 68,796
Asset impairment 169 283 92,843 452 149,741
Deferred tax
expense (recovery) 11,525 11,379 (28,615) 22,904 (55,751)
Stock-based
compensation
expense 1,980 1,203 2,062 3,183 3,522
Amortization of
debt issuance
costs 620 605 489 1,225 629
Cash settlement of
RSUs (183) (318) (513) (501) (1,186)
Unrealized foreign
exchange loss
(gain) 3,895 (2,819) 233 1,076 50
Financial
instruments gain (1,447) (5,439) (1,072) (6,886) (227)
Cash settlement of
financial
instruments 448 768 3 1,216 47
Loss on sale of
Brazil business
unit 9,076 – – 9,076 –
Gain on acquisition – – – – (11,712)
——————————————————-
Funds flow from
operations $ 50,920 $ 45,026 $ 33,755 $ 95,946 $ 45,318
——————————————————-
——————————————————-

/T/

Presentation of Oil and Gas Information

BOEs have been converted on the basis of 6 thousand cubic feet (“Mcf”) of
natural gas to 1 barrel of oil. BOEs may be misleading, particularly if used in
isolation. A BOE conversion ratio of 6 Mcf: 1 barrel is based on an energy
equivalency conversion method primarily applicable at the burner tip and does
not represent a value equivalency at the wellhead. In addition, given that the
value ratio based on the current price of oil as compared with natural gas is
significantly different from the energy equivalent of six to one, utilizing a
BOE conversion ratio of 6 Mcf: 1 barrel would be misleading as an indication of
value.

This press release contains certain oil and gas metrics, including operating
netback and cash netback, which do not have standardized meanings or standard
methods of calculation and therefore such measures may not be comparable to
similar measures used by other companies. Such metrics have been included
herein to provide readers with additional measures to evaluate the Company’s
performance; however, such measures are not reliable indicators of the future
performance of the Company and future performance may not compare to the
performance in previous periods.

Investors are urged to consider closely the disclosures and risk factors in the
Company’s Annual Report on Form 10-K, Quarterly Reports on Form 10-Q and in the
other reports and filings with the SEC, available on the Company’s website at
www.grantierra.com. These forms can also be obtained from the SEC website at
www.sec.gov or by calling 1-800-SEC-0330.

– END RELEASE – 03/08/2017

For further information:
For investor and media inquiries:
Gran Tierra Energy Inc.
Gary Guidry
Chief Executive Officer
403-767-6500
OR
Gran Tierra Energy Inc.
Ryan Ellson
Chief Financial Officer
403-767-6501
OR
Gran Tierra Energy Inc.
Rodger Trimble
Vice President, Investor Relations
403-698-7941
info@grantierra.com
www.grantierra.com

COMPANY:
FOR: GRAN TIERRA ENERGY INC.
TSX SYMBOL: GTE
NYSE MKT SYMBOL: GTE

INDUSTRY: Energy and Utilities – Oil and Gas
RELEASE ID: 20170803CC0088

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PHX Energy Announces its Second Quarter Results – Part 1

August 3, 2017 by The Canadian Press

FOR: PHX ENERGY SERVICES CORP.
TSX SYMBOL: PHX

Date issue: August 03, 2017
Time in: 7:10 PM e

Attention:

CALGARY, ALBERTA–(Marketwired – Aug. 3, 2017) –

Financial Results

For the three-month period ended June 30, 2017, PHX Energy (TSX:PHX) generated
consolidated revenue of $53.8 million, more than double the $26.4 million
generated in the respective 2016-period. The increased revenue primarily
resulted from greater activity levels across all of the Corporation’s operating
segments, as consolidated operating days in the second quarter of 2017 grew by
94 percent to 4,749 days from 2,452 days in the 2016-quarter.

In the second quarter of 2017, adjusted EBITDA (see “Non-GAAP Measures”) rose
to $0.6 million, an improvement over the negative $2.0 million realized in the
2016-quarter. The Corporation reduced its quarterly net loss by 22 percent in
2017 to $10.4 million from $13.4 million in the comparable 2016-quarter.
Included in these results is Stream Services’ (“Stream”) adjusted EBITDA of
negative $0.6 million (2016 – negative $0.7 million) and net losses of $0.9
million (2016 – $1.3 million).

As at June 30, 2017, PHX Energy had long-term debt of $5.0 million and working
capital (see “Non-GAAP Measures”) of $44.7 million.

Capital Spending

During the second quarter of 2017, the Corporation incurred $6.7 million in
capital expenditures (2016 – $2.0 million), which were primarily used to expand
the fleet of Velocity Real-Time Systems (“Velocity”) and electronic drilling
recorder (“EDR”) equipment.

As at June 30, 2017, the Corporation had $14.4 million of outstanding capital
commitments to purchase drilling and other equipment. These commitments include
$9.5 million for Velocity systems, $3.0 million for performance drilling
motors, $1.2 million for resistivity while drilling (“RWD”) systems, $0.5
million for EDR equipment and $0.2 million for machinery and equipment. The
Corporation expects the equipment to be delivered throughout the remainder of
2017.

PHX Energy’s anticipated capital expenditure budget for 2017 remains at $25.0
million.

Normal Course Issuer Bid

The TSX approved PHX Energy’s Normal Course Issuer Bid (“NCIB”) to purchase for
cancellation, from time-to-time, up to a maximum of 2,929,494 common shares of
the Corporation. Purchases of common shares will be made on the open market
through the facilities of the TSX and through alternative trading systems. The
price which PHX Energy will pay for any common shares purchased will be at the
prevailing market price on the TSX or alternate trading systems at the time of
such purchase. The NCIB commenced on June 26, 2017 and will terminate on June
25, 2018 or such earlier time as the NCIB is completed or terminated at the
option of the Corporation. No share purchases, pursuant to the NCIB, were made
by the Corporation during the period from June 26, 2017 to June 30, 2017.

Equity Financing

On February 2, 2017, PHX Energy closed a bought deal financing for aggregate
proceeds of $28.8 million. An aggregate of 7,187,500 common shares of the
Corporation were issued at a price of $4.00 per common share. Concurrent with
the closing of the public offering, certain directors, officers, employees and
consultants of PHX Energy purchased a total of 500,000 common shares at a price
of $4.00 per share on a private placement basis. The gross proceeds from the
public offering and concurrent private placement totaled to approximately $30.8
million.

The proceeds from the equity financing were primarily used to reduce the
outstanding loans and borrowings under the Corporation’s credit facility.

(Stated in thousands of dollars except per share amounts, percentages and
shares outstanding)

/T/

Three-month periods ended June 30,
2017 2016 % Change
—————————————————————————-
—————————————————————————-
Operating Results (unaudited) (unaudited)
Revenue 53,822 26,359 104
Net loss (10,412) (13,360) (22)
Loss per share – diluted (0.18) (0.32) (44)
Adjusted EBITDA (1) 553 (2,018) n.m.
Adjusted EBITDA per share – diluted
(1) 0.01 (0.05) n.m.
Adjusted EBITDA as a percentage of
revenue (1) 1% (8%)
—————————————————————————-
Cash Flow
Cash flows from operating activities 13,671 4,075 n.m.
Funds from (used in) operations (1) 113 (3,192) n.m.
Funds from (used in) operations per
share – diluted(1) – (0.08) n.m.
Dividends paid – – –
Dividends per share (2) – – –
Capital expenditures 6,698 2,035 n.m.
—————————————————————————-

—————————————————————————-
Financial Position (unaudited)
Working capital
Long-term debt
Shareholders’ equity
Common shares outstanding
—————————————————————————-
—————————————————————————-

Six-month periods ended June 30,
2017 2016 % Change
—————————————————————————-
—————————————————————————-
Operating Results (unaudited) (unaudited)
Revenue 114,944 66,808 72
Net loss (17,555) (20,764) (15)
Loss per share – diluted (0.31) (0.50) (38)
Adjusted EBITDA (1) 4,886 2,097 n.m.
Adjusted EBITDA per share – diluted
(1) 0.09 0.05 80
Adjusted EBITDA as a percentage of
revenue (1) 4% 3%
—————————————————————————-
Cash Flow
Cash flows from operating activities 3,774 4,833 (22)
Funds from (used in) operations (1) 4,096 393 n.m.
Funds from (used in) operations per
share – diluted(1) 0.07 0.01 n.m.
Dividends paid – 416 (100)
Dividends per share (2) – 0.01 (100)
Capital expenditures 8,497 2,892 n.m.
—————————————————————————-

—————————————————————————-
Financial Position (unaudited) Jun 30, ’17 Dec 31, ’16
Working capital 44,671 44,230 1
Long-term debt 5,000 29,014 (83)
Shareholders’ equity 189,641 178,387 6
Common shares outstanding 58,589,887 50,810,721 15
—————————————————————————-
—————————————————————————-

n.m. not meaningful
(1) Refer to non-GAAP measures section that follows the outlook section.
(2) Dividends paid by the Corporation on a per share basis in the period.

/T/

Non-GAAP Measures

PHX Energy uses certain performance measures throughout this press release that
are not recognizable under Canadian generally accepted accounting principles
(“GAAP”). These performance measures include adjusted earnings before interest,
taxes, depreciation and amortization (“EBITDA”), adjusted EBITDA per share,
funds from operations, funds from operations per share, debt to covenant EBITDA
ratio and working capital. Management believes that these measures provide
supplemental financial information that is useful in the evaluation of the
Corporation’s operations and are commonly used by other oil and natural gas
service companies. Investors should be cautioned, however, that these measures
should not be construed as alternatives to measures determined in accordance
with GAAP as an indicator of PHX Energy’s performance. The Corporation’s method
of calculating these measures may differ from that of other organizations, and
accordingly, these may not be comparable. Please refer to the non-GAAP measures
section following the Outlook section for applicable definitions and
reconciliations.

Cautionary Statement Regarding Forward-Looking Information and Statements

This document contains certain forward-looking information and statements
within the meaning of applicable securities laws. The use of “expect”,
“anticipate”, “continue”, “estimate”, “objective”, “ongoing”, “may”, “will”,
“project”, “could”, “should”, “can”, “believe”, “plans”, “intends”, “strategy”
and similar expressions are intended to identify forward-looking information or
statements.

The forward-looking information and statements included in this document are
not guarantees of future performance and should not be unduly relied upon.
These statements and information involve known and unknown risks, uncertainties
and other factors that may cause actual results or events to differ materially
from those anticipated in such forward-looking statements and information. The
Corporation believes the expectations reflected in such forward-looking
statements and information are reasonable, but no assurance can be given that
these expectations will prove to be correct. Such forward-looking statements
and information included in this document should not be unduly relied upon.
These forward-looking statements and information speak only as of the date of
this document.

In particular, forward-looking information and statements contained in this
document include, without limitation, the delivery of capital expenditure
items, the projected capital expenditures budget and how this budget will be
funded, and how R&D projects will enhance and expand PHX Energy’s services.

The above are stated under the headings: “Capital Spending”, “Operating Cost
and Expenses”, and “Capital Resources”. Furthermore all statements in the
Outlook section of this document contains forward-looking statements.

In addition to other material factors, expectations and assumptions which may
be identified in this document and other continuous disclosure documents of the
Corporation referenced herein, assumptions have been made in respect of such
forward-looking statements and information regarding, among other things: the
Corporation will continue to conduct its operations in a manner consistent with
past operations; the general continuance of current industry conditions;
anticipated financial performance, business prospects, impact of competition,
strategies, the general stability of the economic and political environment in
which the Corporation operates; exchange and interest rates; the continuance of
existing (and in certain circumstances, the implementation of proposed) tax,
royalty and regulatory regimes; the sufficiency of budgeted capital
expenditures in carrying out planned activities; the availability and cost of
labour and services and the adequacy of cash flow; debt and ability to obtain
financing on acceptable terms to fund its planned expenditures, which are
subject to change based on commodity prices; market conditions and future oil
and natural gas prices; and potential timing delays. Although Management
considers these material factors, expectations and assumptions to be reasonable
based on information currently available to it, no assurance can be given that
they will prove to be correct.

Readers are cautioned that the foregoing lists of factors are not exhaustive.
Additional information on these and other factors that could affect the
Corporation’s operations and financial results are included in reports on file
with the Canadian Securities Regulatory Authorities and may be accessed through
the SEDAR website (www.sedar.com) or at the Corporation’s website. The
forward-looking statements and information contained in this document are
expressly qualified by this cautionary statement. The Corporation does not
undertake any obligation to publicly update or revise any forward-looking
statements or information, whether as a result of new information, future
events or otherwise, except as may be required by applicable securities laws.

Revenue

(Stated in thousands of dollars)

/T/

Three-month periods ended June 30, Six-month periods ended June 30,
2017 2016 % Change 2017 2016 % Change
—————————————————————————-
—————————————————————————-
Revenue 53,822 26,359 104 114,944 66,808 72
—————————————————————————-
—————————————————————————-

/T/

During the three-month period ended June 30, 2017, the Corporation generated
consolidated revenue of $53.8 million, more than double the $26.4 million
recognized in the 2016-period. The increase in the consolidated quarterly
revenue in 2017 was driven by higher levels of drilling activity that resulted
from improved commodity prices when compared to the 2016-period. Consolidated
operating days in the second quarter of 2017 rose by 94 percent to 4,749 days
as compared to 2,452 days in the 2016-quarter. The average consolidated day
rate in the 2017-quarter, excluding the motor rental division in the US and the
Stream division, was $11,029, a 5 percent improvement over the $10,549 realized
in the comparable 2016-quarter. US and international revenue as a percentage of
total consolidated revenue were 65 and 10 percent, respectively, for the
2017-quarter as compared to 66 and 12 percent in 2016.

During the 2017-quarter, there were twice as many rigs operating per day in
both Canada and the US as the industry recovered from the historical lows
experienced in 2016. In Canada, horizontal drilling continued to dominate all
activity at 96 percent of industry drilling days in the second quarter of 2017
(2016 – 92 percent), and in the US the average number of horizontal rigs
running per day represented 84 percent of the rig count in the 2017-quarter
(2016 – 77 percent) (Sources: Daily Oil Bulletin and Baker Hughes).

Consolidated revenue for the six-month period ended June 30, 2017 increased by
72 percent to $114.9 million from $66.8 million in the comparable 2016-period.
The Corporation achieved 11,432 consolidated operating days in the six-month
period ended June 30, 2017, which is 75 percent higher than the 6,521 days
reported in 2016.

Operating Costs and Expenses

(Stated in thousands of dollars except percentages)

/T/

Three-month periods ended Six-month periods ended
June 30, June 30,
2017 2016 % Change 2017 2016 % Change
—————————————————————————-
—————————————————————————-
Direct costs 56,776 36,253 57 117,581 82,264 43
Gross loss as a
percentage of
revenue (5%) (38%) (2%) (23%)
Depreciation &
amortization
(included in
direct costs) 10,514 13,013 (19) 21,445 27,015 (21)
Gross profit as
percentage of
revenue excluding
depreciation &
amortization 14% 12% 16% 17%
—————————————————————————-
—————————————————————————-

/T/

PHX Energy Announces its Second Quarter Results – Part 2

August 3, 2017 by The Canadian Press

Direct costs are comprised of field and shop expenses, and include depreciation
and amortization of the Corporation’s equipment. For the three and six-month
periods ended June 30, 2017, direct costs increased to $56.8 million and $117.6
million, respectively, from $36.3 million and $82.3 million in the comparable
2016-periods.

The increased costs for both 2017-periods was primarily due to higher activity
levels, as well as the following factors:

/T/

— higher field expenses as increases were made in labour rates during the

first quarter;
— greater third party rental costs required to meet the increased volume
of activity; and
— increased motor repair costs.

/T/

In the 2017-periods, the gross loss as a percentage of revenue fell to 5
percent and 2 percent, respectively, as compared to 38 percent and 23 percent
in the 2016-periods. The reduced gross loss margins in 2017 are primarily the
result of all operating segments being more active.

The reduction in the depreciation and amortization expense for the three and
six-month periods ended June 30, 2017 was mainly the result of PHX Energy’s
lower level of capital spending in the 2016 and 2017-years.

Excluding depreciation and amortization, gross profit as a percentage of
revenue improved to 14 percent for the three-month period ended June 30, 2017
from 12 percent in the comparable 2016-period. The more favourable second
quarter margin was mainly driven by increased activity levels, partially offset
by the above factors. Whereas, for the first half of 2017, gross profit as
percentage of revenue excluding depreciation & amortization fell slightly to 16
percent versus 17 percent in 2016. The lower margin in the current year period
is primarily the result of lower client day rates in the first quarter of 2017
and the factors listed above.

(Stated in thousands of dollars except percentages)

/T/

Three-month periods Six-month periods ended
ended June 30, June 30,
2017 2016 % Change 2017 2016 % Change
—————————————————————————-
—————————————————————————-
Selling, general &
administrative (“SG&A”)
costs 7,776 6,880 13 14,985 13,559 11
Equity-settled share-based
payments (included in SG&A
costs) 1,030 611 69 1,518 897 69
Cash-settled share-based
payments (recoveries)
(included in SG&A costs) (159) 1,099 n.m. (27) 950 n.m.
Onerous contracts lease
payment (70) – n.m. (177) – n.m.
SG&A costs excluding equity
and cash-settled share-
based payments and
provision for onerous
contracts as a percentage
of revenue 13% 20% 12% 18%
—————————————————————————-
—————————————————————————-
n.m. not meaningful

/T/

For the three and six-month periods ended June 30, 2017, SG&A costs rose to
$7.8 million and $15.0 million, respectively, from $6.9 million and $13.6
million in the comparable 2016-periods. The higher SG&A costs for both
2017-periods are primarily the result of improved activity levels and issuance
of equity settled share-based awards, partially offset by recoveries on
cash-settled share-based awards.

For the three and six-month periods ended June 30, 2017, excluding equity and
cash-settled share-based payments and the provision for onerous contracts, SG&A
costs as a percentage of consolidated revenue were 13 percent and 12 percent,
respectively. This is much improved over the 20 percent and 18 percent in the
comparable 2016-periods. The more favourable percentages in both 2017-periods
are mainly attributable to the greater volume of activity.

Equity-settled share-based payments relate to the amortization of the fair
values of issued options of the Corporation using the Black-Scholes model. In
the three and six-month periods ended June 30, 2017, equity-settled share-based
payments increased by 69 percent, as compared to the corresponding
2016-periods, mainly due to a higher compensation expense related to options
granted in the first quarter of 2017.

Cash-settled share-based retention awards, which are included in SG&A costs,
are measured at fair value. For the three and six-month periods ended June 30,
2017, the Corporation recognized share-based compensation recoveries from the
revaluation of the retention awards based on the reduction in PHX Energy’s
stock price during both periods.

(Stated in thousands of dollars)

/T/

Three-month periods Six-month periods
ended June 30, ended June 30,
2017 2016 % Change 2017 2016 % Change
—————————————————————————-
—————————————————————————-
Research & development expense 764 225 n.m. 1,371 750 83
—————————————————————————-
—————————————————————————-

n.m. not meaningful

/T/

Research and development (“R&D”) expenditures during the three and six-month
periods ended June 30, 2017 were $0.8 million (2016 – $0.2 million) and $1.4
million (2016 – $0.8 million), respectively. R&D expenditures were higher in
both 2017-periods, which is mainly the result of increased R&D personnel in the
current year and the receipt of scientific research and experimental
development (“SR&ED”) credits, which reduced the 2016-periods expense. The R&D
department continues to focus on new technology development and cost-saving and
reliability initiatives that will enhance and expand PHX Energy’s services.

(Stated in thousands of dollars)

/T/

Three-month periods Six-month periods
ended June 30, ended June 30,
2017 2016 % Change 2017 2016 % Change
—————————————————————————-
—————————————————————————-
Finance expense 428 527 (19) 1,013 1,099 (8)
—————————————————————————-
—————————————————————————-

/T/

Finance expenses relate to interest charges on the Corporation’s long-term and
short-term bank facilities. For the three and six-month periods, finance
charges decreased to $0.4 million (2016 – $0.5 million) and $1.0 million (2016
– $1.1 million) respectively. The reduction in finance charges in both
2017-periods was primarily due to lower levels of borrowings compared to the
prior year periods, partially offset by additional financing charges and higher
fixed pricing on borrowings.

(Stated in thousands of dollars)

/T/

Three-month periods Six-month periods ended
ended June 30, June 30,
2017 2016 2017 2016
—————————————————————————-
—————————————————————————-
Loss (Gain) on
disposition of drilling
equipment (94) 426 (241) (779)
Foreign exchange losses
(gains) 83 125 255 (226)
Provision for (Recovery
of) bad debts 24 (96) 252 (66)
—————————————————————————-
Other expense (income) 13 455 266 (1,071)
—————————————————————————-
—————————————————————————-

/T/

During the three and six-month periods ended June 30, 2017, the Corporation
recognized gains on the disposition of drilling equipment of $0.1 million (2016
– $0.4 million loss) and $0.2 million (2016 – $0.8 million). Gains from the
disposition of drilling equipment typically result from insurance programs
undertaken whereby proceeds for the lost equipment are at current replacement
values, which are higher than the respective equipment’s book value. Losses
typically result from any asset retirements that were made before the end of
the equipment’s useful life and self-insured downhole equipment losses.

For the three and six-month periods ended June 30, 2017, the Corporation
incurred foreign exchange losses of $0.1 million (2016 – $0.1 million) and $0.3
million (2016 – $0.2 million gain), respectively. These losses resulted mainly
from the settlement of Canadian-denominated intercompany payables in the
Corporation’s Russian operations and the revaluation of Canadian-denominated
intercompany payables in the US.

During the three and six-month periods ended June 30, 2017, the Corporation
recognized provisions for bad debts of $24,000 (2016 – $0.1 million recovery)
and $0.3 million (2016 – $0.1 million recovery), respectively. Provisions for
bad debt in the 2017-quarter relate mainly to accounts receivable in the
Corporation’s US segment.

(Stated in thousands of dollars, except percentages)

/T/

Three-month periods Six-month periods ended
ended June 30, June 30,
2017 2016 2017 2016
—————————————————————————-
—————————————————————————-
Provision for (Recovery
of) income taxes (1,521) (4,622) (2,716) (9,029)
Effective tax rates 13% 26% 13% 30%
—————————————————————————-
—————————————————————————-

/T/

The recovery of income taxes for the three and six-month period ended June 30,
2017 was $1.5 million and $2.7 million, respectively, as compared to $4.6
million and $9.0 million in the comparable 2016-periods. The expected combined
Canadian federal and provincial tax rate for 2017 is 27 percent. The effective
tax rate in the 2017-periods were lower than the expected rate mainly as a
result of the effect of tax rates in foreign jurisdictions.

Segmented Information

The Corporation reports three operating segments on a geographical basis
throughout the Canadian provinces of Alberta, Saskatchewan, British Columbia,
and Manitoba; throughout the Gulf Coast, Northeast and Rocky Mountain regions
of the US; and internationally, in Russia and Albania.

Canada

(Stated in thousands of dollars)

/T/

Three-month periods ended Six-month periods ended
June 30, June 30,
2017 2016 % Change 2017 2016 % Change
—————————————————————————-
—————————————————————————-
Revenue 13,450 5,832 131 42,892 21,452 100
Reportable segment loss
before tax (5,247) (7,320) (28) (4,479) (10,559) (58)
—————————————————————————-
—————————————————————————-

/T/

For the three-month period ended June 30, the Corporation’s Canadian revenue
grew from $5.8 million in 2016 to $13.5 million in 2017. The recovery in the
industry rig count continued during Canadian spring break-up, with
substantially more rigs operating in 2017 than in the prior year. PHX Energy’s
Canadian segment reported 1,699 operating days, up from 663 days in the
2016-quarter. This is consistent with the industry’s performance as horizontal
and directional drilling activity, as measured by drilling days, increased from
3,301 days in the 2016-quarter to 10,729 days in the 2017-quarter (Source:
Daily Oil Bulletin). In the second quarter of 2017, there was an increased
proportion of jobs requiring fewer rig site personnel which caused the average
day rate (excluding Stream revenue) to fall by 11 percent to $7,535 from $8,420
in the 2016-quarter.

During the second quarter of 2017, oil drilling, as measured by drilling days,
represented approximately 51 percent of PHX Energy’s Canadian activity and the
Corporation remained active in the Montney, Wilrich, Bakken, Shaunavon,
Duvernay, Cardium and Viking areas.

For the six-month period ended June 30, 2017, the Corporation recognized
revenue of $42.9 million, double the $21.5 million of revenue earned in the
2016-period. The increased revenue in the first half of 2017 was primarily the
result of the higher rig count in the Canadian market. The Corporation’s
operating days grew from 2,614 days in the first half of 2016 to 5,703 days in
2017. This is consistent with Canadian industry activity, as the number of
reported horizontal and directional drilling days grew to 32,792 days for the
first half of 2017 as compared to 14,493 days in 2016 (Sources: Daily Oil
Bulletin). In the six-month period ended June 30, 2017, oil drilling
represented approximately 60 percent of PHX Energy’s Canadian activity (2016 –
45 percent). In the first half of 2017, PHX Energy saw its average day rates
(excluding Stream revenue) decline by 11 percent to $7,166 from $8,010 in 2016,
as a result of market conditions and an increased proportion of jobs requiring
fewer rig site personnel.

For the three and six-month periods ended June 30, 2017, the reportable segment
loss before tax was $5.2 million (2016 – $7.3 million) and $4.5 million (2016 –
$10.6 million). The improved margins for both 2017-periods was primarily due to
the significant recovery of activity levels as compared to the 2016-periods.

Stream Services

Included in the Canadian segment’s revenue for the three and six-month periods
ended June 30, 2017 is $0.7 million (2016- $0.2 million) and $2.0 million (2016
– $0.5 million), respectively, of revenue generated by the Stream division. For
the second quarter, Stream grew its operating days by 71 percent from 500 days
in 2016 to 854 days in 2017. Along with the growth in activity level, average
day rates for the division also rose by 53 percent to $761 in the second
quarter of 2017, up from $498 in the 2016-quarter.

For the three and six-month periods ended June 30, 2017, the Stream division
incurred reportable losses before tax of $1.3 million (2016 – $1.8 million) and
$1.7 million (2016 – $3.5 million). The Stream division’s losses in both
2017-periods pertain mostly to depreciation expenses of $0.6 million and $1.2
million, respectively, as well as the costs associated with the continued
expansion of the division.

United States

(Stated in thousands of dollars)

/T/

Three-month periods ended Six-month periods ended
June 30, June 30,
2017 2016 % Change 2017 2016 % Change
—————————————————————————-
—————————————————————————-
Revenue 35,206 17,381 103 62,021 39,120 59
Reportable segment
loss before tax (4,011) (6,803) (41) (10,180) (14,608) (30)
—————————————————————————-
—————————————————————————-

/T/

For the three-month period ended June 30, 2017, the US segment generated
revenue of $35.2 million which is twice the $17.4 million generated in the
2016-period. PHX Energy’s US operating days grew by 89 percent to 2,404 days in
the 2017-quarter from 1,275 days in the 2016-quarter. Average day rates,
excluding the Corporation’s US motor rental division, rose by 7 percent to
$14,315 in the 2017-quarter compared to $13,441 in the 2016-period, with the
2017 rates being assisted by the strengthening of the US dollar. In US dollars,
the average day rates were relatively consistent quarter-over-quarter.

Debunking the myth: SR&ED eligibility for E&P companies – TSGI Corp.

August 4, 2017August 3, 2017 by EnergyNow Media

Why should SR&ED matter to E&P? SR&ED is a major competitive advantage for oil and gas companies to reduce costs in today’s economy. SR&ED is Canada’s largest industrial innovation program, returning between 15% and 41.5% of eligible costs for activities that advance technology or scientific understanding. E&P companies are eligible for SR&ED At first glance, … Read more

SR&ED for the Energy industry: New White Paper Series – TSGI Corp.: Does Your Company Qualify?

August 4, 2017August 3, 2017 by EnergyNow Media

We’re starting a new 5-part series of White Papers on the topic of SR&ED for companies in the Energy industry. We aim to dispel misconceptions about SR&ED and offer special considerations for fully leveraging the program. We want every E&P and service company to leave no stone unturned for cost-saving measures in today’s economy. TSGI has … Read more

Raging River Exploration Inc. Announces Second Quarter 2017 Operating and Financial Results and Increased Credit Facilities

August 3, 2017 by The Canadian Press

FOR: RAGING RIVER EXPLORATION INC.
TSX SYMBOL: RRX

Date issue: August 03, 2017
Time in: 5:39 PM e

Attention:

CALGARY, ALBERTA–(Marketwired – Aug. 3, 2017) – Raging River Exploration Inc.
(the “Company” or “Raging River”) (TSX:RRX) announces its operating and
financial results for the three and six months ended June 30, 2017. Selected
financial and operational information is outlined below and should be read in
conjunction with the unaudited interim financial statements and the related
management’s discussion and analysis (“MD&A”). These filings will be available
at www.sedar.com and the Company’s website at www.rrexploration.com.

Financial and Operating Highlights

/T/

Three months Six months
ended Percent ended Percent
June 30, Change June 30, Change

2017 2016 2017 2016
————— ——- ————— ——-
Financial (thousands of
dollars except share data)
Petroleum and natural gas
revenue 105,982 67,528 57 217,999 117,909 85
Funds from operations (1) 64,965 43,999 48 137,717 73,901 86
Per share – basic 0.28 0.19 47 0.60 0.33 82
– diluted 0.28 0.19 47 0.60 0.33 82
Net earnings (loss) 18,595 5,320 250 33,938 (2,534) 1439
Per share – basic 0.08 0.02 300 0.15 (0.01) 1600
– diluted 0.08 0.02 300 0.15 (0.01) 1600
Development capital
expenditures 68,640 38,602 78 181,323 75,982 139
Property and corporate
acquisitions – 25,125 (100) – 25,125 (100)
Total capital expenditures 68,640 63,727 8 181,323 101,107 79
Net debt(1)(3) 253,117 63,101 301
Shareholders’ equity 938,337 826,775 13
Weighted average shares
(thousands)
Basic 231,178 226,231 2 231,165 221,362 4
Diluted 231,335 227,167 2 231,402 221,362 5
Shares outstanding, end of
period (thousands)
Basic 231,243 226,600 2
Diluted 232,979 236,768 (2)
—————————————————————————-
Operating (6:1 boe
conversion)

Average daily production

Crude oil and NGLs
(bbls/d) 18,795 14,603 29 19,134 14,818 29
Heavy crude oil (bbls/d) 1,189 171 595 1,303 163 699
Natural gas (mcf/d) 12,185 7,368 65 11,676 7,634 53
—————————————————————————-
Barrels of oil equivalent
(2)(boe/d) 22,015 16,002 38 22,383 16,253 38
—————————————————————————-

Netbacks ($/boe)

Operating
Oil and gas sales(3) 52.90 46.37 14 53.81 39.86 35
Royalties (5.05) (4.54) 11 (5.14) (3.89) 32
Operating expenses (11.31) (8.98) 26 (10.90) (8.97) 22
Transportation expenses (1.41) (1.39) 1 (1.43) (1.38) 4
—————————————————————————-

Field netback(1) 35.13 31.46 12 36.34 25.62 42
Realized gain (loss) on
commodity contracts (0.37) 0.11 (436) (0.12) 0.12 (200)
—————————————————————————-
Operating netback 34.76 31.57 10 36.22 25.74 41
General and
administrative expense (1.05) (1.20) (13) (1.04) (1.23) (15)
Financial charges (1.14) (0.46) 148 (1.07) (0.64) 67
Asset retirement
expenditures (0.15) (0.04) 275 (0.13) (0.04) 225
Current taxes recovery – 0.34 (100) – 1.15 (100)
—————————————————————————-
Funds flow netback(1) 32.42 30.21 7 33.98 24.98 36
—————————————————————————-
Net earnings (loss) per
boe 9.28 3.66 154 8.36 (0.86) 1072
—————————————————————————-
Wells drilled(4)
Gross 64 40 60 163 97 68
Net 60.6 39.9 52 155.1 96.4 61
Success 97% 98% (1) 98% 99% (1)
(1) See “Non-IFRS Measures.”
(2) See ‘”Barrels of Oil Equivalent.”
(3) Excludes unrealized risk management contracts.
(4) Excludes injection and service wells.

/T/

SECOND QUARTER 2017 HIGHLIGHTS

/T/

— Achieved quarterly average production of 22,015 boe/d (91% oil), an

increase of 38% over the comparable period in 2016. This represents a
35% production per share increase from the comparable period of 2016.
— The Company’s capital expenditures were $68.6 million inclusive of $9
million on land and $59.6 million of development capital resulting in
the drilling of 60.6 net Viking horizontal wells at a 97% success rate.
— Achieved funds flow from operations (“FFO”) of $65 million ($0.28/share
basic), an increase of 48% from the second quarter of 2016.
— Generated second quarter net earnings of $18.6 million ($0.08/share
basic), an increase of 250% from the second quarter 2016.
— The Company generated field operating netbacks of $35.13/boe and funds
flow netbacks of $32.42/boe.
— Continued diligent cost control with top decile general and
administrative costs of $1.05/boe, a reduction of 13% from the
comparable period in 2016.
— Maintained balance sheet strength with second quarter exit net debt of
$253.1 million representing 1.0 times debt to the second quarter
annualized FFO.

/T/

CREDIT FACILITY EXPANSION

As a result of the Company’s continued operational success, effective July 31,
2017, Raging River’s borrowing base on its credit facilities was increased to
$500 million from $400 million. The increased credit facilities are comprised
of a $50 million non-syndicated operating facility and a $450 million
syndicated extendible revolving facility, on similar terms and conditions to
the pre-existing facilities.

Our commitment to balance sheet strength remains paramount with the Company now
anticipating exit 2017 net debt of approximately $285 million representing a
net debt to expected trailing fourth quarter FFO of approximately 1.1 times
based on current strip WTI pricing of approximately US$49.80/bbl.

OPERATIONS UPDATE

In the second quarter of 2017, field conditions were very cooperative and the
Company had timely access to services. As a result, Raging River was able to
drill 60.6 net wells, a record level of second quarter activity for the Company.

In the second quarter, of the 60.6 net wells drilled, 16 wells were extended
reach horizontals (“ERH”) bringing the total producing ERH well count to 89.
Average per well ERH results continue to show 1.8 – 2.0 times improvement over
comparable offsetting short laterals. For the remainder of 2017, it is expected
that approximately 60% of wells drilled will be ERH.

Average well costs year to date have been $670 thousand for short laterals and
$900 thousand blended cost for 3/4 mile and 1 mile ERH wells. Average well
costs are on budget with our anticipated 5-7% increase from the lows of 2016.
We anticipate costs to remain flat through the remainder of 2017.

GUIDANCE AND OUTLOOK

Raging River’s 2017 capital budget and guidance remains unchanged with targeted
annual average production of 22,750 boe/d and capital spending of $340 million.

Two key initiatives that were outlined in the May 8, 2017 press release include
the allocation of: (i) $10 million of incremental capital towards waterflood
related facilities at Gleneath and Eureka; and (ii) $10 million of capital to
new play development. The Company has made good progress on both of these
initiatives.

The Company is on track with the waterflood related facility projects which are
set to commence in the third quarter of 2017 and to be completed by the year
end. Operating cost savings associated with these expenditures are expected to
be seen in 2018.

With respect to the new play development initiative, as disclosed in the June
5, 2017, press release, Raging River has been accumulating lands prospective
for light oil in the East Duvernay Shale basin in central Alberta. We have
continued to make progress with this initiative, and have increased our net
land position from 100,000 to 130,000 net acres. All of the lands acquired to
date are targeting the oil phase of the basin.

The Company plans to methodically evaluate this East Duvernay Shale
opportunity. We are currently surveying and acquiring surface lands in multiple
locations in anticipation of drilling the first evaluation well early in the
fourth quarter of 2017, with anticipated production results in the first
quarter of 2018. Our current plans, contemplate six evaluations wells in 2018,
with two wells targeted for the first half of 2018 and the balance for the
second half of 2018.

Given the progress that the Company has made towards establishing a meaningful
land position in this early stage, light oil resource play, we will continue to
evaluate our Duvernay development plans in the context of the prevailing
commodity price environment with a goal towards accelerating our pace of
activity, should commodity pricing be supportive.

We are currently evaluating anticipated 2018 capital expenditure levels which
is expected to be managed to ensure net debt to trailing FFO does not exceed
1.5 times. The board of directors continuously reviews our long term strategic
plan and continues to be supportive of balanced per share growth and new play
development while maintaining financial flexibility with our balance sheet.

The business approach taken by the Company since our inception over five years
ago, has been to prudently manage our balance sheet while generating and
maintaining meaningful per share growth while developing an enviable drilling
inventory. Our established Viking drilling inventory of approximately 3,200
locations provides a robust growth and cash flow platform with in excess of 10
years of growth inventory at our current pace of development. In addition to
our Viking platform, Raging River’s entrance into the emerging Duvernay light
oil play in east central Alberta provides exposure to an exciting early stage
opportunity that provides visibility towards additional per share value
creation.

Additional corporate information can be found on our website at
www.rrexploration.com.

FORWARD LOOKING STATEMENTS: This press release contains forward-looking
statements. More particularly, this press release contains statements
concerning Raging River’s expectations regarding, plans and timing of execution
of capital activities, expectations of 2017 exit net debt and expected exit net
debt to trailing annualized fourth quarter 2017 FFO ratio, expected 2017
average production, expected capital costs for remainder of 2017, expected
average drilling costs for remainder of 2017, expected 2018 operating costs
savings, timing of completion of waterflood projects, expected 2017 and 2018
drilling plans including the types of wells to be drilled and specifically
drilling plans for the East Duvernay Shale basin, expected future drilling
locations, expectation that drilling inventory represents over 10 years of
growth and the expectations of the Company’s ability to maintain itself and
grow on a per share basis based on different commodity price assumptions. In
addition, the use of any of the words “guidance”, “initial, “scheduled”, “can”,
“will”, “prior to”, “estimate”, “anticipate”, “believe”, “potential”, “should”,
“unaudited”, “forecast”, “future”, “continue”, “may”, “expect”, “project”, and
similar expressions are intended to identify forward-looking statements.
The forward-looking statements contained herein are based on certain key
expectations and assumptions made by the Company, including but not limited to
expectations and assumptions concerning the success of optimization and
efficiency improvement projects the availability of capital, current
legislation, receipt of required regulatory approval, the success of future
drilling and development activities, the performance of existing wells, the
performance of new wells, Raging River’s growth strategy, general economic
conditions, availability of required equipment and services, prevailing
equipment and services costs and prevailing commodity prices. Although the
Company believes that the expectations and assumptions on which the
forward-looking statements are based are reasonable, undue reliance should not
be placed on the forward-looking statements because the Company can give no
assurance that they will prove to be correct. Since forward-looking statements
address future events and conditions, by their very nature they involve
inherent risks and uncertainties. Actual results could differ materially from
those currently anticipated due to a number of factors and risks. These
include, but are not limited to, risks associated with the oil and gas industry
in general (e.g., operational risks in development, exploration and production;
delays or changes in plans with respect to exploration or development projects
or capital expenditures; as the uncertainty of reserve estimates; the
uncertainty of estimates and projections relating to production, costs and
expenses, and health, safety and environmental risks), commodity price and
exchange rate fluctuations, changes in legislation affecting the oil and gas
industry and uncertainties resulting from potential delays or changes in plans
with respect to exploration or development projects or capital expenditures.
Refer to Raging River’s most recent Annual Information Form dated March 6,
2017, on SEDAR at www.sedar.com, and the risk factors contained therein.

The forward-looking statements contained in this press release are made as of
the date hereof and the Company undertakes no obligation to update publicly or
revise any forward-looking statements or information, whether as a result of
new information, future events or otherwise, unless so required by applicable
securities laws.

FUTURE ORIENTED FINANCIAL INFORMATION: Any financial outlook or future oriented
financial information in this press
release, as defined by applicable securities legislation, has been approved by
management of Raging River as of the date hereof. Readers are cautioned that
any such future-oriented financial information contained herein should not be
used for purposes other than those for which it is disclosed herein. The
Company and its management believe that the prospective financial information
as to the anticipated results of its proposed business activities for 2017 has
been prepared on a reasonable basis, reflecting management’s best estimates and
judgments, and represent, to the best of management’s knowledge and opinion,
the Company’s expected course of action. However, because this information is
highly subjective, it should not be relied on as necessarily indicative of
future results.

NON-IFRS MEASURES: This document contains the terms “funds flow from
operations” (or “FFO”), “net debt”, “field netback”, “operating netback” and
“funds flow netback”, which do not have standardized meanings prescribed by
International Financial Reporting Standards (“IFRS”) and therefore may not be
comparable with the calculation of similar measures by other companies.
Management uses funds from operations to analyze operating performance and
leverage. Management believes “net debt” is a useful supplemental measure of
the total amount of current and long-term debt of the Company. Mark-to-market
risk management contracts are excluded from the net debt calculation.
Management believes “field netback”, “operating netback” and “funds flow
netback” are useful supplemental measures of firstly, the amount of revenues
received after royalties and operating and transportation costs, secondly, the
amount of revenues received after royalties, operating, transportation costs
and realized gain (loss) on derivatives, and thirdly, the amount of revenues
received after royalties, operating, transportation costs, realized gain (loss)
on derivatives, general and administrative costs, financial charges, asset
retirement obligations and current taxes. Additional information relating to
certain of these non-IFRS measures, including the reconciliation between funds
from operations and cash flow from operating activities, can be found in the
MD&A.

BARRELS OF OIL EQUIVALENT: The term “boe” or barrels of oil equivalent may be
misleading, particularly if used in isolation. A boe conversion ratio of six
thousand cubic feet of natural gas to one barrel of oil equivalent (6 Mcf: 1
bbl) is based on an energy equivalency conversion method primarily applicable
at the burner tip and does not represent a value equivalency at the wellhead.
Additionally, given that the value ratio based on the current price of crude
oil, as compared to natural gas, is significantly different from the energy
equivalency of 6:1; utilizing a conversion ratio of 6:1 may be misleading as an
indication of value.

DRILLING LOCATIONS: This press release discloses future drilling locations.
Such drilling locations may be in three different categories: (i) proved
locations; (ii) probable locations; and (iii) unbooked locations. Proved
locations and probable locations are derived from the Company’s most recent
independent reserves evaluation as prepared by Sproule as of December 31, 2016
and account for drilling locations that have associated proved and/or probable
reserves, as applicable. Unbooked locations are internal estimates based on the
Company’s prospective acreage and an assumption as to the number of wells that
can be drilled per section based on industry practice and internal review.
Unbooked locations do not have attributed reserves or resources. Of the 3,200
drilling locations of the Company identified herein, approximately 1,100 are
proved locations, approximately 71 are probable locations and approximately
2,029 are unbooked locations. Unbooked locations have been identified by
management as an estimation of our multi-year drilling activities based on
evaluation of applicable geologic, seismic, engineering, production and
reserves information. Unbooked locations have been identified by management as
an estimation of our multi-year drilling activities based on evaluation of
applicable geologic, seismic, engineering, production and reserves information.
There is no certainty that the Company will drill all unbooked drilling
locations and if drilled there is no certainty that such locations will result
in additional oil and gas reserves, resources or production. The drilling
locations on which we actually drill wells will ultimately depend upon the
availability of capital, regulatory approvals, seasonal restrictions, oil and
natural gas prices, costs, actual drilling results, additional reservoir
information that is obtained and other factors. While certain of the unbooked
drilling locations have been derisked by drilling existing wells in relative
close proximity to such unbooked drilling locations, the majority of other
unbooked drilling locations are farther away from existing wells where
management has less information about the characteristics of the reservoir and
therefore there is more uncertainty whether wells will be drilled in such
locations and if drilled there is more uncertainty that such wells will result
in additional oil and gas reserves, resources or production.

– END RELEASE – 03/08/2017

For further information:
RAGING RIVER EXPLORATION INC.
Mr. Neil Roszell, P. Eng.
CEO and Executive Chairman
403-767-1250
403-387-2951 (FAX)
OR
RAGING RIVER EXPLORATION INC.
Mr. Bruce Beynon, P. Geol.
President
403-767-1251
403-387-2951 (FAX)
OR
RAGING RIVER EXPLORATION INC.
Mr. Jerry Sapieha, CA
Vice President, Finance and Chief Financial Officer
403-767-1265
403-387-2951 (FAX)

COMPANY:
FOR: RAGING RIVER EXPLORATION INC.
TSX SYMBOL: RRX

INDUSTRY: Energy and Utilities – Oil and Gas
RELEASE ID: 20170803CC0073

Press Release from Marketwired 1-866-736-3779

Dissidents Discontinue Lawsuit Against Eagle Energy Inc.

August 3, 2017 by The Canadian Press

FOR: EAGLE ENERGY INC.TSX SYMBOL: EGLDate issue: August 03, 2017Time in: 5:05 PM eAttention:
CALGARY, ALBERTA–(Marketwired – Aug. 3, 2017) – Eagle Energy Inc. (TSX:EGL)
announced today that dissident shareholders Kingsway Financial Services Inc.
and …

Whose O&G Wells Have Geothermal Potential?

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All Alberta oil and gas wells as of October 31, 2016, have been assessed for their geothermal potential (through a study facilitated by CanGEA). There were more than 60,000 wells identified (out of nearly 600,000 wellbores in the province). The wells are grouped into those with potential for Direct Heat (>60c), Industrial Heat (>90c) and … Read more

Feds back in ‘Gasland’ town to test water, air

August 8, 2017August 3, 2017 by The Canadian Press

The federal government has returned to a Pennsylvania village that became a flashpoint in the national debate over fracking to investigate ongoing complaints about the quality of the drinking water.

Government scientists are collecting water and air samples this week from about 25 homes in Dimock, a tiny crossroads about 150 miles north of Philadelphia.

“Residents have continued to raise concerns about natural gas activities impacting their private water well quality,” the Agency for Toxic Substances and Disease Registry said Thursday in a statement to The Associated Press.

Dimock was the scene of the most highly publicized case of methane contamination to emerge from the early days of Pennsylvania’s natural-gas drilling boom. State regulators blamed faulty gas wells drilled by Cabot Oil & Gas Corp. for leaking combustible methane into Dimock’s groundwater.

Cabot, one of the largest natural gas producers in the state, has consistently denied responsibility, saying methane was an issue in the groundwater long before it began drilling.

The ATSDR, a federal public health agency, said Thursday that it is “conducting an exposure investigation to determine if there are drinking water quality issues that may continue to pose a health threat.”

The water will be tested for bacteria, gases and chemicals. The agency is also testing indoor air for radon. Sampling results are expected in the fall, which will be shared with residents. A report will be released to the public next year.

Dimock became a battleground in environmental activists’ fight against fracking, the technique that allows drilling companies to extract huge volumes of oil and natural gas from rock formations deep underground. The village was featured in the Emmy-winning 2010 documentary “Gasland,” which showed residents lighting their tap water on fire. Drilling supporters have long accused Dimock residents of seeking money and attention.

Dozens of plaintiffs who say their water was ruined settled their lawsuit against Cabot in 2012.

In April, a federal judge threw out a $4.24 million jury verdict against the Houston-based driller and ordered a new trial in a lawsuit alleging that Cabot contaminated the well water of two families who were not part of the 2012 settlement.

A Cabot spokesman did not immediately respond to an email from the AP on Thursday.

It’s the first time that ATSDR has tested private well water in Dimock. The Environmental Protection Agency conducted testing in 2012.

Michael Rubinkam, The Associated Press

Don’t Let Trump Blow Nafta Apart, Canadian Businesses Tell Trudeau

August 4, 2017August 3, 2017 by EnergyNow Media

August 3, 2017 (Bloomberg) The Canadians with the most to lose in Nafta negotiations have a message for Justin Trudeau: Don’t let Donald Trump blow the thing apart. Key industry groups, companies and stakeholders are urging the prime minister to “do no harm” to the North American Free Trade Agreement while seeking updates on labor … Read more

How realistic are plans to ban new gas and diesel cars?

August 8, 2017August 3, 2017 by The Canadian Press

FRANKFURT — Ban the sale of gasoline and diesel cars by a deadline — 2040, 2030, even 2025. More and more governments are proposing just that.

But how seriously can such deadlines be taken?

The issue of how to phase out polluting traditional engines has been pushed to the forefront by scandals and crises. First Volkswagen’s admission to cheating on U.S. diesel emissions tests, and more recently a push by cities in Germany and elsewhere to ban diesels to make the air cleaner.

The political desire to switch to get rid of traditional engines, however, runs into a number hurdles in the real world. More recharging stations need to be set up globally, at a potentially high cost. And millions of jobs depend on the production of internal combustion engines, making the decision politically difficult in many places.

“I think there’s a majority, especially in cities, who say ‘we need change,'” says Dieter Janacek, a member of Germany’s Green party who is campaigning for re-election in the national poll Sept. 24 on his party’s official call for an end to new gas and diesel sales by 2030.

He is running not just from anywhere but from Munich, home to auto giant BMW.

Yet he thinks the call to phase out traditional engines is a winner. Janacek, 41, says that many people are “skeptical of the internal combustion engine, because they have to live with the consequences and the emissions.” That’s particularly true of urbanites — more than half the residents of Munich’s innermost neighbourhoods don’t even own a car. And it is in cities where the pollution issue is most pressing.

A lot would have to happen before such a big move happens, however.

There aren’t enough public fast-charging stations that can enable longer trips with all-electric cars. Janacek loves his electric Renault Zoe, which has enough range to make campaign trips and then get back home to recharge overnight. But for longer trips, he and his wife rely on her conventional Toyota Yaris, a common compromise arrangement among early adopters. Experts say electrics could start to beat gas and diesel on cost and convenience by the mid-2020s as battery range and infrastructure improve.

Janacek concedes that “yes, it’s very ambitious. On the other hand, there are countries like Norway that want to move ahead faster. I am convinced it will happen.”

And then there is the impact on those who make gas and diesel engines.

Banning internal combustion engines from 2030 would affect more than 600,000 jobs in Germany directly or indirectly, or 10 per cent of the nation’s workforce, according to a study commissioned by the German Association of the Automotive Industry.

That may be why the dates touted by governments to end the sale of traditional engines look more like soft targets than drop-dead dates.

Norway has aggressively promoted electrics, but even there the proposed elimination of gas and diesel except for hybrids by 2025 is a goal to be achieved, not a fixed date for a ban. France and Britain are looking at 2040 — so far ahead that the politicians involved will no longer be around and technology will have changed in ways that are hard to predict. The former Netherlands cabinet proposed all electrics by 2035, but a new government will have to take the final decision. Carmaker Volvo said in July that all its models will have an electric motor from 2019 onwards. However, many of those cars will be hybrids, which also have an internal combustion engine and are regarded as a halfway house to emissions-free driving.

In California, the powerful Air Resources Board is pushing manufacturers to include more zero-emission vehicles in their lineups, without calling for a ban by a specific date. China is heavily incentivizing electrics.

Still, soft goals can have serious impact; Norway reached its target of 50,000 electrics in 2015, three years ahead of schedule.

“It’s an easy thing to say, especially since some of those politicians will not be around in 2040,” said Brett Smith, assistant director of the manufacturing, engineering and technology group at the Center for Automotive Research in Ann Arbor, Michigan. “The practicality of it is another matter.”

What would happen to resale values for owners of internal combustion cars as the deadline approaches? What would happen to gas stations and their owners? Those are “huge questions politicians don’t really want to think about when they set those dates,” Smith said.

The dates are “more like guidelines, and when we get closer we’ll figure out how to get there. It’s not an unreasonable approach.”

As important as the deadlines are the incentives governments give to the industry and consumers.

In Norway, electrics are exempt from the 25 per cent value-added tax and other fees. Higher taxes on cars that pollute more would offset lost revenue. Just as important, most of Norway’s electricity comes from hydro power, not from burning fossil fuel. That means increased demand for power from cars won’t mean more emissions from coal- or natural gas-fired electricity plants.

The industry, meanwhile, is committed to diesel and traditional engines for the near future while it ramps up investment in new technologies. Daimler spent 3 billion euros ($3.5 billion) developing a new, lower emissions diesel engine that is already in some of its E-class sedans. At the same time, it is spending 10 billion euros on electric and autonomous technology.

Governments do the industry a favour by setting firm deadlines, says Ferdinand Dudenhoeffer, director of the Center for Automotive Research at Germany’s University of Duisburg-Essen. “Clear dates, such as 2040 for instance, would mean that the car makers could make a clear plan what to do in the future.”

Smith said the market would still play a major role: “If the business model is there, people will find a way to fund it.”

David McHugh, The Associated Press

Feature Story: Voice Construction – The Real Voice of Safety and Quality Civil Construction Projects

August 3, 2017 by EnergyNow Media

For over 75 years, Voice Construction (‘Voice’) has brought quality civil construction projects to life in Western Canada. Founded in 1939 by Arthur A. Voice, Voice began as a small, family-run business in Edmonton, growing over the years to become an industry-leading operation with multiple branches and a proven track record of excellence, safety, and … Read more

How the Wild Shale Race May Be Harming the Permian’s Oil Trove

August 3, 2017 by EnergyNow Media

August 2, 2017 (Bloomberg) The frantic shale race may be causing some long-term damage to assets in the Permian and other major U.S. oil fields. As production from wells rapidly declines, drillers are rushing to add new ones at a faster pace in order to keep increasing output. The problem is that drilling multiple wells … Read more

Oil Nears $50 as Traders Weigh U.S. Stockpile Drop, Output Gain

August 3, 2017August 3, 2017 by EnergyNow Media

August 3, 2017 (Bloomberg) Oil traded near $50 a barrel as investors weighed declining U.S. stockpiles against rising output. Futures added 0.3 percent in New York, extending their 0.9 percent gain on Wednesday. U.S. crude inventories dropped by 1.53 million barrels last week, while gasoline supplies fell for a seventh week, according to a report from the Energy Information … Read more

Five Things World Business Will be Talking About Today

August 3, 2017 by EnergyNow Media

August 3, 2017 (Bloomberg) It’s “Super Thursday” at the Bank of England, there’s a raft of economic data, and Tesla pleases investors. Here are some of the things people in markets are talking about today. BOE decision At 7:00 a.m. Eastern Time the Bank of England will release its latest interest rate decision and update its forecasts for … Read more

Loop Energy Fuel Cell Range-Extended Yard Truck in Operation

August 3, 2017 by The Canadian Press

FOR: LOOP ENERGY
Date issue: August 03, 2017Time in: 1:00 PM eAttention:
Zero-Emission System Offers Performance and Cost Benefits to Advance Port
Sustainability
VANCOUVER, BRITISH COLUMBIA–(Marketwired – Aug. 3, 2017) –
Note to editors: There is a p…

Enbridge says costs of Line 3 rising, cites regulatory delays, route changes

August 4, 2017August 3, 2017 by The Canadian Press

CALGARY — Enbridge Inc. (TSX:ENB) says the cost of its Line 3 replacement project has risen nine per cent from its original estimate when it was sanctioned in 2014.

The company now estimates it will cost $5.3 billion for the portion in Canada and US$2.9 billion in the United States to replace the pipeline that runs from Hardisty, Alta., to Superior, Wisc.

It attributed the higher cost to delays in the regulatory process and route modifications, among other changes.

However, the company said the impact of the increased costs on project returns are expected to be offset by lower operating costs and a strong U.S. dollar.

Enbridge said it expects to start construction in Canada this summer and have the pipeline in service in the second half of 2019.

The announcement came as Enbridge reported a second-quarter profit of $919 million or 56 cents per diluted share compared with a profit of $301 million or 33 cents per diluted share a year ago when the company had fewer shares outstanding.

Adjusted earnings for the quarter amounted to $662 million or 41 cents per share, up from $456 million of 50 cents per share a year ago.

The Canadian Press

Canadian Natural Resources reports $1.07-billion second-quarter profit

August 3, 2017August 3, 2017 by The Canadian Press

CALGARY — Canadian Natural Resources Ltd. (TSX:CNQ) trimmed its capital spending plan for this year as it reported a profit of $1.07 billion in its latest quarter compared with a loss a year ago.

The oilsands company says it has decreased its capital spending program by about $180 million for 2017. It had said it March that it planned to spend about $3.9 billion this year.

The decision came as Canadian Natural also raised the mid-point of its 2017 annual liquids and barrels of oil equivalent production guidance by 11,000 bbl/d and 3,000 BOE/d respectively.

The company says its profit in its latest quarter amounted to 93 cents per diluted share compared with a loss of $339 million or 31 cents per share in the same quarter last year.

Adjusted earnings from operations were $332 million or 29 cents per share compared with a loss of $210 million or 19 cents per share a year ago.

Production in the quarter averaged 913,171 barrels of oil equivalent per day, up from 783,988 in the second quarter last year.

The Canadian Press

Enbridge Income Fund Holdings Inc. Reports Second Quarter Results

August 3, 2017 by The Canadian Press

FOR: ENBRIDGE INCOME FUND HOLDINGS INC.TSX SYMBOL: ENFDate issue: August 03, 2017Time in: 7:00 AM eAttention:
CALGARY, ALBERTA–(Marketwired – Aug. 3, 2017) –
Q2 HIGHLIGHTS(all financial figures are unaudited and in Canadian dollars unless otherwiseno…

Enbridge Inc. Reports Second Quarter 2017 Results – Part 1

August 3, 2017 by The Canadian Press

FOR: ENBRIDGE INC.
TSX SYMBOL: ENB
NYSE SYMBOL: ENB

Date issue: August 03, 2017
Time in: 7:00 AM e

Attention:

CALGARY, ALBERTA–(Marketwired – Aug. 3, 2017) –

Q2 HIGHLIGHTS

(all financial figures are unaudited and in Canadian dollars unless otherwise
noted)

/T/

— Earnings were $919 million or $0.56 per common share for the second

quarter and $1,557 million or $1.11 per common share for the six-month
period, both including the impact of a number of unusual, non-recurring
or non-operating factors
— Adjusted earnings were $662 million or $0.41 per common share for the
second quarter and $1,337 million or $0.95 per common share for the six-
month period
— Adjusted earnings before interest and income taxes (EBIT) were $1,713
million for the second quarter and $3,228 million for the six-month
period
— Available cash flow from operations (ACFFO) was $1,324 million or $0.81
per common share for the second quarter and $2,539 million or $1.81 per
common share for the six-month period; 2017 ACFFO per share guidance
range is unchanged at $3.60-$3.90 per share
— On June 1, 2017, Enbridge paid a previously announced quarterly dividend
on its common shares of $0.61 per share, a 15% increase over the
quarterly dividend paid on June 1, 2016
— Enbridge announced today that it will begin construction this summer to
replace certain segments of the Line 3 pipeline in Canada; in the United
States, construction has now begun in Wisconsin (collectively, the Line
3 Replacement Program). The Line 3 Replacement Program is expected to
come into service in the second half of 2019
— Enbridge continued the execution of its secured growth program bringing
an additional $5 billion of growth projects into service during the
quarter
— In June 2017, Enbridge announced that it had secured the $1.0 billion T-
South natural gas pipeline expansion in British Columbia, the $0.5
billion Spruce Ridge expansion on the T-North natural gas network in
British Columbia (Spruce Ridge Program), and the $0.4 billion expansion
of the Hohe See Offshore Wind Project in Germany (Hohe See Expansion
Project)
— Subsequent to the first quarter of 2017, the Company further
strengthened its financial position with the issuance of US$1.0 billion
of hybrid debt securities and made significant progress on its capital
funding plan by issuing over $5 billion of term debt, primarily to
refinance long-term debt at favourable rates
— On July 31, 2017, Enbridge completed the sale of its interest in the
Olympic refined products pipeline (Olympic Pipeline) for $0.2 billion.
This sale further bolsters the balance sheet and brings total asset
monetizations executed to $2.5 billion since the announcement of the
merger with Spectra Energy Corp (Spectra Energy) (the Merger
Transaction)

/T/

Enbridge Inc. (Enbridge or the Company) (TSX:ENB)(NYSE:ENB) today reported
second quarter 2017 adjusted EBIT of $1,713 million. Second quarter ACFFO was
$1,324 million, or $0.81 per common share. This was the first full quarter of
operations subsequent to the Merger Transaction that closed on February 27,
2017.

The largest driver of EBIT growth for the second quarter of 2017 relative to
the second quarter of 2016 was the contribution of Enbridge’s new natural gas
assets acquired in the Merger Transaction, which has substantially diversified
the Company’s asset base and business platforms. Also contributing to
year-over-year growth was improved performance from Green Power and
Transmission and the impact of a stronger United States dollar. These positive
contributors were partially offset by lower results in Energy Services and
Liquids Pipelines.

Liquids Pipelines’ results for the quarter were impacted by several transitory
items including a significant unexpected outage and accelerated maintenance at
a customer’s upstream facility, additional related and unrelated production
disruptions, and a hydrostatic testing program on Line 5 during the month of
June 2017. The combined adjusted EBIT impact on the Canadian and United States
mainline system (Mainline System) of these factors was approximately $50
million in the quarter. Up until the month of June, the Mainline System had
been delivering near record volumes and operating under apportionment in heavy
crude oil service. Apportionment on the Mainline System also impacted the EBIT
contribution of certain downstream pipelines during the quarter.

EBIT generated by Liquids Pipelines is expected to grow over the second half of
2017 as throughput on the Mainline System returns to levels achieved earlier in
the year. This is driven in part by capacity optimization projects completed in
the first half of the year that will address capacity constraints and help
alleviate apportionment.

ACFFO for the second quarter was $1,324 million, an increase of $456 million
over the comparable prior period, driven largely by the same factors noted
above. ACFFO of $0.81 per share was lower than the prior period primarily as a
result of the issuance of additional shares as consideration under the Merger
Transaction.

“Our financial results this quarter highlight the benefits of having a
well-diversified portfolio of businesses and growth platforms,” said Al Monaco,
President and Chief Executive Officer. “The overall performance of the US Gas
Transmission assets that we acquired in connection with the Merger Transaction
has been solid and as expected. We anticipate the performance of our Liquids
Pipelines business to strengthen over the balance of the year as production and
throughput ramps back up on the Mainline System and we benefit from capacity
optimization initiatives that have been implemented to accommodate greater
heavy volumes. Given the strengthening outlook for Liquids Pipelines, the
success we are having in executing our secured growth program, and our progress
in driving out synergies from the Merger Transaction thus far, we remain right
on track for delivering financial results in line with the guidance we provided
earlier in the year.”

Commenting on the overall strategic positioning and near term outlook for the
business, Mr. Monaco noted: “I’m pleased with the progress that we’ve made in
this first full quarter since we merged with Spectra Energy. Management is
keenly focused on the key strategic priorities that we laid out at our mid-year
investor update which include: growing organically, minimizing risk and
streamlining the organization. Since the end of the first quarter, we’ve
brought $5 billion of projects into service, added high-quality, low-risk
organic projects to our inventory of secured growth projects, executed on our
funding plans and strengthened the balance sheet. Our integration and synergy
realization plans remain right on track and we continue to optimize the
performance of our existing assets while operating safely and reliably.
Entering the second half of the year, we are well-positioned to deliver growing
cash flow in line with expectations, and we look forward to our core business
and projects coming into service this year and next driving growing cash flows
in 2018 and 2019.”

Line 3 Replacement Program

Enbridge announced today that it will begin construction this summer on certain
segments of the Line 3 Replacement Program in Canada and that construction in
Wisconsin has commenced. This program entails a full replacement of the
existing pipeline which runs from Hardisty, Alberta to Superior, Wisconsin.

All required regulatory permitting is in place to proceed with the Canadian
construction work. Regulatory permitting is also in place for construction in
North Dakota and in Wisconsin. The only remaining jurisdiction in which the
regulatory permitting process is still under way is in Minnesota, where the
Minnesota Department of Commerce is expected to release a Final Environmental
Impact Statement in the third quarter of 2017. Based on the expected regulatory
process and timeline, Management’s anticipated in-service date for the project
is the second half of 2019.

Given the updated execution plan, the finalized cost estimate for the project
is now $5.3 billion in Canada and US$2.9 billion in the United States. The
revised cost is approximately 9 percent above the original estimate at the time
of project sanctioning in 2014, and primarily reflects delays in the regulatory
process, scope changes and route modifications as well as other changes that
resulted from the extensive consultation process. The impact of these
additional costs on project returns are fully offset by lower estimated
operating costs and a stronger United States dollar relative to the original
project assumptions.

“Line 3 is a critical piece of energy infrastructure that supports our economy
and assures reliable and cost-effective supply of energy,” commented Mr.
Monaco. “The new Line 3 will comprise the newest and most advanced pipeline
technology and provide much needed incremental capacity to support Canadian
crude oil production growth and United States and Canadian refinery demand.”

Project Execution

Enbridge continued to execute on its secured growth capital program, bringing
an additional $5 billion of projects into service this quarter, including Sabal
Trail Transmission, LLC’s natural gas pipeline, the Norlite Pipeline System,
and its equity investment in the Bakken Pipeline System (which commenced
service during the quarter). This brings the total growth capital projects
brought into service to well over $6 billion thus far in 2017. Over the
remainder of this year, the Company expects to bring a further $7 billion of
growth projects into service. All of these projects are supported by low-risk
long-term take-or-pay contracts, cost-of-service frameworks or similar
commercial arrangements and will provide a significant uplift to cash flow as
they come into service.

New Secured Growth Projects

At its mid-year investor conference in June, Enbridge announced the addition of
$1.9 billion of new secured growth projects.

Following a highly successful open season, Enbridge is proceeding with the $1.0
billion T-South natural gas pipeline expansion project. This expansion will add
190 million cubic feet per day (mmcf/d) of additional capacity supported by
long-term contracts under a cost-of-service framework, and will enable greater
access for growing Montney production to attractive demand pull markets in the
Pacific Northwest by late 2020. Enbridge is also proceeding with the expansion
of several segments of the T-North natural gas gathering and transportation
system in British Columbia to facilitate better access and connectivity to
regional infrastructure. The $0.5 billion Spruce Ridge Program is supported by
long-term contracts under a cost-of-service framework and is expected to come
into service in the second half of 2018.

The sanctioning of the $0.4 billion Hohe See Expansion Project brings
Enbridge’s total investment in this facility to $2.1 billion. As co-developer,
Enbridge will participate in the construction and operation of the project,
which is supported by long-term fixed price power purchase contracts.
Completion of this low-risk and immediately accretive project is expected in
the second half of 2019.

“We’ve now successfully secured almost $4 billion of new projects since the
Merger Transaction was announced,” noted Mr. Monaco. “Our success reflects the
strength of our diversified business model, which incorporates six strategic
growth platforms post the Merger Transaction. These new projects are a great
fit with Enbridge’s investor value proposition, extending our industry leading
$31 billion secured capital program into 2020, and supporting our long-term
dividend growth outlook of 10-12 percent through 2024.”

Funding Progress

During the second quarter of 2017, Enbridge was active in the capital markets,
making significant progress on the execution of its funding plan.

Since the end of the first quarter, the Company has raised over $5 billion of
term debt in both the United States and Canadian markets across a range of
maturities, the proceeds of which were primarily used to refinance existing or
maturing debt at favourable rates. In July, Enbridge successfully completed
tender offers for approximately US$1.0 billion of outstanding Spectra Energy
Capital, LLC term debt as part of an ongoing effort to streamline and simplify
the Company’s financing structure and further reduce its cost of capital.

On July 14, 2017, Enbridge further strengthened its balance sheet with the
issuance of US$1.0 billion of hybrid securities. In addition, the Company
closed the sale of its interest in the Olympic Pipeline for $0.2 billion on
July 31, 2017, increasing the total asset monetizations to $2.5 billion since
the announcement of the Merger Transaction. Enbridge will continue to assess
its overall asset portfolio for opportunities to selectively monetize non-core
assets and free up capital for re-deployment to its growth program.

Quarterly Dividend

On June 1, 2017, Enbridge paid a previously announced quarterly dividend on its
common shares of $0.61 per share. On January 5, 2017, the Company announced
that it would increase its quarterly common share dividend from $0.53 per share
to $0.583 per share effective with the dividend payable on March 1, 2017.
Following the successful closing of the merger with Spectra Energy, the Company
announced a further $0.027 per share increase in the Company’s common share
dividend to be effective with the dividend payable on June 1, 2017. Together,
these increases represent a 15% increase over the prevailing quarterly rate in
2016.

SECOND QUARTER 2017 PERFORMANCE OVERVIEW

For more information on Enbridge’s growth projects and operating results,
please see Management’s Discussion and Analysis (MD&A) which is filed on SEDAR
and EDGAR and also available on the Company’s website at
www.enbridge.com/InvestorRelations.aspx.

HIGHLIGHTS

/T/

Three months
ended Six months ended
June 30, June 30,
—————– —————–
2017 2016 2017 2016
—————————————————————————-
(unaudited, millions of Canadian
dollars, except per share amounts)
Earnings attributable to common
shareholders
Liquids Pipelines 1,272 643 2,396 2,255
Gas Pipelines and Processing 682 19 1,021 80
Gas Distribution 153 83 428 322
Green Power and Transmission 51 41 101 90
Energy Services (18) (7) 138 (13)
Eliminations and Other (41) (48) (356) 173
—————————————————————————-
Earnings before interest and income
taxes 2,099 731 3,728 2,907
Interest expense (565) (369) (1,051) (781)
Income tax expense (293) (10) (491) (427)
(Earnings)/loss attributable to
noncontrolling interests and
redeemable noncontrolling interests (241) 20 (465) (41)
Preference share dividends (81) (71) (164) (144)
—————————————————————————-
Earnings attributable to common
shareholders 919 301 1,557 1,514
Earnings per common share 0.56 0.33 1.11 1.69
Diluted earnings per common share 0.56 0.33 1.10 1.67
—————————————————————————-
—————————————————————————-
Adjusted earnings
Liquids Pipelines 938 922 1,908 2,006
Gas Pipelines and Processing 667 90 1,003 177
Gas Distribution 153 73 422 313
Green Power and Transmission 51 40 101 88
Energy Services (3) 47 (8) 48
Eliminations and Other (93) (83) (198) (169)
—————————————————————————-
Adjusted earnings before interest and
income taxes(1) 1,713 1,089 3,228 2,463
Interest expense(2) (588) (363) (1,053) (757)
Income taxes(2) (194) (131) (338) (307)
Noncontrolling interests and
redeemable noncontrolling
interests(2) (188) (68) (336) (136)
Preference share dividends (81) (71) (164) (144)
—————————————————————————-
Adjusted earnings(1) 662 456 1,337 1,119
Adjusted earnings per common share(1) 0.41 0.50 0.95 1.25
—————————————————————————-
—————————————————————————-
Cash flow data
Cash provided by operating activities 2,033 1,370 3,710 3,231
Cash used in investing activities (2,368) (2,080) (5,891) (3,932)
Cash provided by financing activities 531 230 2,124 981
—————————————————————————-
—————————————————————————-
Available cash flow from operations(3)
Available cash flow from operations 1,324 868 2,539 1,982
Available cash flow from operations
per common share 0.81 0.95 1.81 2.21
—————————————————————————-
—————————————————————————-
Dividends
Common share dividends declared 1,003 492 1,551 952
Dividends paid per common share 0.610 0.530 1.193 1.060
—————————————————————————-
—————————————————————————-
Shares outstanding (millions)
Weighted average common shares
outstanding 1,628 917 1,404 897
Diluted weighted average common shares
outstanding 1,636 925 1,413 904
—————————————————————————-
—————————————————————————-
Three months
ended Six months ended
June 30, June 30,
———————————–
2017 2016 2017 2016
—————————————————————————-
Operating data
Liquids Pipelines – Average deliveries
(thousands of bpd)
Canadian Mainline(4) 2,449 2,242 2,521 2,392
Lakehead System(5) 2,604 2,440 2,675 2,588
Regional Oil Sands System(6) 1,171 823 1,228 987
Gas Pipelines – Average throughput
(mmcf/d)
Alliance Pipeline Canada 1,519 1,559 1,574 1,587
Alliance Pipeline US 1,623 1,698 1,674 1,724
Canadian Midstream(7) 2,177 – 2,458 –
Gas Pipelines and Processing – Volumes
processed (mmcf/d)
Canadian Midstream(8) 1,715 – 1,875 –
US Midstream(9) 5,422 1,141 5,591 1,154
Gas Pipelines and Processing – natural
gas liquids (NGL) production (thousands
of bpd)
US Midstream(9 ) 518 159 516 149
Gas Distribution – Enbridge Gas
Distribution Inc. (EGD)
Volumes (billions of cubic feet) 71 78 243 251
Number of active customers
(thousands)(10) 2,167 2,133 2,167 2,133
Heating degree days(11)
Actual 462 546 2,148 2,255
Forecast based on normal weather
volume 476 478 2,351 2,309
Gas Distribution – Union Gas Limited
(Union Gas)
Volumes (billions of cubic feet) 222 – 371 –
Number of active customers
(thousands)(10) 1,465 – 1,465 –
Heating degree days(11)
Actual 492 – 1,093 –
Forecast based on normal weather
volume 514 – 1,090 –
—————————————————————————-
—————————————————————————-
1 Adjusted EBIT, adjusted earnings and adjusted earnings per common share
are non-GAAP measures that do not have any standardized meaning
prescribed by GAAP – see Non-GAAP Measures.
2 These balances are presented net of adjusting items.
3 ACFFO is defined as cash flow provided by operating activities before
changes in operating assets and liabilities (including changes in
environmental liabilities) less distributions to noncontrolling interests
and redeemable noncontrolling interests, preference share dividends and
maintenance capital expenditures, and further adjusted for unusual, non-
recurring or non-operating factors. ACFFO and ACFFO per common share are
non-GAAP measures that do not have any standardized meaning prescribed by
GAAP.
4 Canadian Mainline throughput volume represents mainline system deliveries
ex-Gretna, Manitoba which is made up of United States and eastern Canada
deliveries originating from western Canada.
5 Lakehead Pipeline System (Lakehead System) throughput volume represents
mainline system deliveries to the United States mid-west and eastern
Canada.
6 Volumes are for the Athabasca mainline, Athabasca Twin, Waupisoo Pipeline
and Woodland Pipeline and exclude laterals on the Regional Oil Sands
System.
7 Canadian Midstream throughput volumes represent throughput from the
Western Canada Transmission & Processing assets only.
8 Canadian Midstream processing volumes represent the volumes processed
through the Tupper Main and Tupper West gas plants and the Western Canada
Transmission & Processing assets.
9 US Midstream processing volumes and NGL production represent the volumes
processed and produced from the Field Services assets and the Midcoast
Energy Partnership assets as well as the Aux Sable processing plant.
10 Number of active customers is the number of natural gas consuming EGD and
Union Gas customers at the end of the period.
11 Heating degree days is a measure of coldness that is indicative of
volumetric requirements for natural gas utilized for heating purposes in
EGD’s and Union Gas’s franchise area. It is calculated by accumulating,
for the fiscal period, the total number of degrees each day by which the
daily mean temperature falls below 18 degrees Celsius. The figures given
are those accumulated in the Greater Toronto Area.

/T/

Enbridge Inc. Reports Second Quarter 2017 Results – Part 2

August 3, 2017 by The Canadian Press

EARNINGS BEFORE INTEREST AND INCOME TAXES

For the three and six months ended June 30, 2017, EBIT was $2,099 million and
$3,728 million, respectively, compared with $731 million and $2,907 million for
the three and six months ended June 30, 2016. Earnings for the three and six
months ended June 30, 2017 were positively impacted by contributions from new
assets following the completion of the Merger Transaction.

The positive impact to EBIT resulting from the Merger Transaction’s new assets
was partially offset by lower results in the Energy Services and Liquids
Pipelines segments as discussed below.

The comparability of the Company’s earnings period-over-period is also impacted
by a number of unusual, non-recurring or non-operating factors that are
enumerated in the Non-GAAP Reconciliation tables, the most significant of which
are changes in unrealized derivative fair value gains and losses. For the three
months ended June 30, 2017, the Company’s EBIT reflected $461 million of
unrealized derivative fair value gains, compared with losses of $98 million in
the corresponding 2016 period. For the six months ended June 30, 2017, the
Company’s EBIT reflected $877 million of unrealized derivative fair value
gains, compared with gains of $834 million in the corresponding 2016 period.
The Company has a comprehensive long-term economic hedging program to mitigate
interest rate, foreign exchange and commodity price risks which creates
volatility in short-term earnings. Over the long-term, Enbridge believes its
hedging program supports the reliable cash flows and dividend growth upon which
the Company’s investor value proposition is based.

In addition, the comparability of period-over-period EBIT was impacted by the
recognition of an impairment of $176 million ($103 million after-tax
attributable to Enbridge) in the second quarter of 2016 related to Enbridge’s
75 percent joint venture interest in Eddystone Rail Company, LLC, a
rail-to-barge transloading facility located in Greater Philadelphia,
Pennsylvania.

EBIT for the six months ended June 30, 2017 also reflected charges of $178
million ($130 million after-tax) with respect to costs incurred in conjunction
with the Merger Transaction, as well as $208 million ($146 million after-tax)
of employee severance costs in relation to the Company’s enterprise-wide
reduction of workforce in March 2017 and restructuring costs in connection with
the completion of the Merger Transaction.

EARNINGS ATTRIBUTABLE TO COMMON SHAREHOLDERS

Earnings attributable to common shareholders for the three months ended June
30, 2017 were $919 million, or $0.56 per common share, compared with $301
million, or $0.33 per common share, for the three months ended June 30, 2016.
Earnings attributable to common shareholders for the six months ended June 30,
2017 were $1,557 million, or $1.11 per common share, compared with $1,514
million, or $1.69 per common share, for the six months ended June 30, 2016.

In addition to the factors discussed in EBIT above, interest expense for the
three and six months ended June 30, 2017 was higher, compared with the
corresponding 2016 periods, as a result of debt assumed in the Merger
Transaction. Preference share dividends were also higher reflecting additional
preference shares issued in the fourth quarter of 2016 to partially fund the
Company’s growth capital program.

Income tax expense increased for the three and six months ended June 30, 2017,
compared with the corresponding 2016 periods, largely due to the increase in
earnings.

Earnings attributable to noncontrolling interests and redeemable noncontrolling
interests increased in the second quarter and the first half of 2017, compared
with the corresponding 2016 periods. The increase was driven by additional
noncontrolling interests associated with the assets acquired in the Merger
Transaction and lower earnings attributable to noncontrolling interests in
Enbridge Energy Partners, L.P. (EEP) during 2016.

Lower earnings per common share for the six months ended June 30, 2017,
compared with the corresponding 2016 period, reflected the issuance of
approximately 691 million common shares in February 2017 as part of the
consideration for the Merger Transaction, the issuance of approximately 75
million common shares in 2016 through a 56 million follow-on common share
offering in the first quarter of 2016, and ongoing issuances under the
Company’s Dividend Reinvestment Program.

ADJUSTED EARNINGS BEFORE INTEREST AND INCOME TAXES

For the three and six months ended June 30, 2017, adjusted EBIT was $1,713
million and $3,228 million, respectively, an increase of $624 million and $765
million over the corresponding three and six-month periods in 2016. The largest
driver of adjusted EBIT growth over the prior year periods was the
contributions of new assets acquired in the Merger Transaction. Also
contributing to the period-over-period growth in adjusted EBIT were increased
contributions from the Green Power and Transmission segment. These positive
contributions were partially offset by warmer weather in the franchise areas
served by the Company’s gas distribution utilities and lower results in the
Energy Services and Liquids Pipelines segments.

Growth in adjusted EBIT was most pronounced in the Gas Pipelines and Processing
segment, where a majority of the new assets acquired through the Merger
Transaction are reported. Growth for this segment also reflected contributions
from the Tupper Main and Tupper West gas plants acquired in April 2016.

Excluding contributions from Express-Platte as part of the Merger Transaction,
Liquids Pipelines adjusted EBIT decreased in the three and six months ended
June 30, 2017, compared with the corresponding 2016 periods. The second quarter
of 2017 was impacted by several transitory items including a significant
unexpected outage and accelerated maintenance at a customer’s upstream
facility, additional related and unrelated production disruptions, and a
hydrostatic testing program on Line 5 during the month of June 2017. The
combined impact on the Mainline System of these factors was approximately $50
million in the second quarter of 2017. Up until the month of June, the Mainline
System had been delivering near record volumes and operating under
apportionment in heavy crude oil service. Apportionment on the Mainline System
also impacted the adjusted EBIT contribution of certain downstream pipelines
during the first and second quarters of 2017. Liquids Pipelines reported
performance was further impacted by a change in practice whereby the Company no
longer includes cash received under certain take-or-pay contracts with make-up
rights in its determination of adjusted EBIT. In addition, the divestiture of
certain assets and lower surcharge revenues decreased adjusted EBIT. Adjusted
EBIT generated by Liquids Pipelines is expected to grow over the second half of
2017 as throughput on the Mainline System is expected to return to record
levels achieved earlier in the year and capacity optimization projects,
undertaken in the first half of the year to alleviate apportionment on the
Mainline System, are operationalized.

Within the Gas Distribution segment, EGD generated lower adjusted EBIT for the
six months ended June 30, 2017, compared with the corresponding 2016 period,
primarily due to lower distribution revenues attributable to warmer than normal
weather in the first half of 2017. Effective January 1, 2017, EGD ceased to
exclude the effect of warmer/colder weather from its adjusted EBIT. In the
first half of 2017, warmer than normal weather impacted EGD’s adjusted EBIT by
approximately $23 million. The period-over-period decrease in EGD’s adjusted
EBIT was more than offset by contributions from Union Gas since the completion
of the Merger Transaction.

Energy Services adjusted EBIT for the three and six months ended June 30, 2017
reflected compressed location and quality differentials in certain markets,
lower refinery demand for certain products and fewer opportunities to achieve
profitable margins on facilities where the Company holds capacity obligations.
Adjusted EBIT from Energy Services is dependent on market conditions and
results achieved in one period may not be indicative of results to be achieved
in future periods.

The increase in adjusted loss before interest and income taxes reported within
Eliminations and Other reflects higher unallocated corporate costs which
primarily resulted from the Merger Transaction, partially offset by synergies
achieved thus far on integration of corporate functions.

ADJUSTED EARNINGS

Adjusted earnings were $662 million, or $0.41 per common share, for the three
months ended June 30, 2017, compared with $456 million, or $0.50 per common
share, for the three months ended June 30, 2016. Adjusted earnings were $1,337
million, or $0.95 per common share, for the six months ended June 30, 2017,
compared with $1,119 million, or $1.25 per common share, for the six months
ended June 30, 2016.

In addition to the factors discussed in Adjusted Earnings Before Interest and
Income Taxes above, the comparability of adjusted earnings is consistent with
the discussion in Earnings Attributable to Common Shareholders above.

AVAILABLE CASH FLOW FROM OPERATIONS

ACFFO for the three months ended June 30, 2017 was $1,324 million, or $0.81 per
common share, compared with $868 million, or $0.95 per common share, for the
three months ended June 30, 2016. ACFFO was $2,539 million, or $1.81 per common
share, for the six months ended June 30, 2017, compared with $1,982 million, or
$2.21 per common share, for the six months ended June 30, 2016. The
year-over-year growth in ACFFO was driven by the same factors as discussed in
Adjusted EBIT above, as well as other items discussed below. However, ACFFO per
common share has decreased quarter-over-quarter due to the increase in the
number of common shares outstanding which resulted from the completion of the
Merger Transaction, and other issuances in 2016, as noted above in Earnings
Attributable to Common Shareholders.

Also contributing to the quarter-over-quarter increase in ACFFO were higher
cash distributions that the Company received from its equity investments,
resulting from their improved operating performance as well as distributions
from newly acquired equity investments which were a part of the Merger
Transaction.

The above positive effects on ACFFO quarter-over-quarter were partially offset
by higher maintenance capital expenditures in the first half of 2017, which
reflected the spending on assets acquired in the Merger Transaction and higher
spending in Liquids Pipelines on certain leasehold improvements. The increase
was partially offset by a decrease in maintenance capital expenditures in the
Gas Distribution segment due to the timing of higher spending in 2016 on EGD’s
Work and Asset Management System program; and a decrease, excluding the effect
of the Merger Transaction, in the Gas Pipelines and Processing segment due to a
shift in the timing of maintenance capital expenditures to the later quarters
of 2017.

Also partially offsetting the increase in ACFFO was higher interest expense and
higher preference share dividends for the three and six months ended June 30,
2017, compared with the corresponding periods, as discussed in Earnings
Attributable to Common Shareholders above.

The increase in ACFFO quarter-over-quarter was also impacted by the increased
distributions to noncontrolling interests related to assets acquired in the
Merger Transaction, which was partially offset by the decrease in distributions
to noncontrolling interests in EEP resulting from the reduction in its
quarterly distribution as well as the purchase of Midcoast Energy Partners,
L.P.’s outstanding publicly-held common units. Refer to United States Sponsored
Vehicle Strategy in the Company’s MD&A.

Also offsetting the positive effects on ACFFO were higher distributions to
redeemable noncontrolling interests due to increased public ownership in the
Fund Group (comprising the Enbridge Income Fund, Enbridge Commercial Trust,
Enbridge Income Partners LP (EIPLP) and the subsidiaries and investees of
EIPLP) resulting from Enbridge Income Fund Holdings Inc.’s secondary offering
in the second quarter of 2017.

Other non-cash adjustments include various non-cash items presented in the
Company’s Consolidated Statements of Cash Flows, as well as adjustments for
unearned revenues received in each period.

CONFERENCE CALL

Enbridge will host a joint conference call and webcast on Thursday, August 3,
2017 at 9:00 a.m. Eastern Time (7:00 a.m. Mountain Time) with Enbridge Income
Fund Holdings Inc., Enbridge Energy Partners, L.P. and Spectra Energy Partners,
LP to discuss the second quarter 2017 results. Analysts, members of the media
and other interested parties can access the call toll free at (877) 930-8043 or
within and outside North America at (253) 336-7522 using the access code of
51403910#. The call will be audio webcast live at
http://edge.media-server.com/m/p/7gd26ak2. A webcast replay and podcast will be
available approximately two hours after the conclusion of the event and a
transcript will be posted to the website within 24 hours. The replay will be
available for seven days after the call toll-free (855) 859-2056 or within and
outside North America at (404) 537-3406 (access code 51403910#).

The conference call format will include prepared remarks from the executive
team followed by a question and answer session for the analyst and investor
community only. Enbridge’s media and investor relations teams will be available
after the call for any additional questions.

FORWARD-LOOKING INFORMATION

Forward-looking information, or forward-looking statements, have been included
in this news release to provide information about the Company and its
subsidiaries and affiliates, including management’s assessment of Enbridge and
its subsidiaries’ future plans and operations. This information may not be
appropriate for other purposes. Forward-looking statements are typically
identified by words such as “anticipate”, “expect”, “project”, “estimate”,
“forecast”, “plan”, “intend”, “target”, “believe”, “likely” and similar words
suggesting future outcomes or statements regarding an outlook. Forward-looking
information or statements included or incorporated by reference in this
document include, but are not limited to, statements with respect to the
following: expected EBIT or expected adjusted EBIT; expected earnings/(loss) or
adjusted earnings/(loss); expected earnings/(loss) or adjusted earnings/(loss)
per share; expected ACFFO or ACFFO per share; expected future cash flows;
expected performance of the Liquids Pipelines business; financial strength and
flexibility; expectations on sources of liquidity and sufficiency of financial
resources; expected costs related to announced projects and projects under
construction; expected in-service dates for announced projects and projects
under construction; expected capital expenditures; expected equity funding
requirements for the Company’s commercially secured growth program; expected
future growth and expansion opportunities; expectations about the Company’s
joint venture partners’ ability to complete and finance projects under
construction; expected closing of acquisitions and dispositions; estimated
future dividends; recovery of the costs of the Canadian portion of the Line 3
Replacement Program (Canadian L3R Program); expected expansion of the T-South
System; expected future actions of regulators; expected costs related to leak
remediation and potential insurance recoveries; expectations regarding
commodity prices; supply forecasts; expectations regarding the impact of the
Merger Transaction including the combined Company’s scale, financial
flexibility, growth program, future business prospects and performance; impact
of the Canadian L3R Program on existing integrity programs; dividend payout
policy; dividend growth and dividend payout expectation; and expectations on
impact of hedging program.

Although Enbridge believes these forward-looking statements are reasonable
based on the information available on the date such statements are made and
processes used to prepare the information, such statements are not guarantees
of future performance and readers are cautioned against placing undue reliance
on forward-looking statements. By their nature, these statements involve a
variety of assumptions, known and unknown risks and uncertainties and other
factors, which may cause actual results, levels of activity and achievements to
differ materially from those expressed or implied by such statements. Material
assumptions include assumptions about the following: the expected supply of and
demand for crude oil, natural gas, natural gas liquids (NGL) and renewable
energy; prices of crude oil, natural gas, NGL and renewable energy; exchange
rates; inflation; interest rates; availability and price of labour and
construction materials; operational reliability; customer and regulatory
approvals; maintenance of support and regulatory approvals for the Company’s
projects; anticipated in-service dates; weather; the realization of anticipated
benefits and synergies of the Merger Transaction; governmental legislation;
acquisitions and the timing thereof; the success of integration plans; impact
of the dividend policy on the Company’s future cash flows; credit ratings;
capital project funding; expected EBIT or expected adjusted EBIT; expected
earnings/(loss) or adjusted earnings/(loss); expected earnings/(loss) or
adjusted earnings/(loss) per share; expected future cash flows and expected
future ACFFO and ACFFO per share; and estimated future dividends. Assumptions
regarding the expected supply of and demand for crude oil, natural gas, NGL and
renewable energy, and the prices of these commodities, are material to and
underlie all forward-looking statements.
These factors are relevant to all forward-looking statements as they may impact
current and future levels of demand for the Company’s services. Similarly,
exchange rates, inflation and interest rates impact the economies and business
environments in which the Company operates and may impact levels of demand for
the Company’s services and cost of inputs, and are therefore inherent in all
forward-looking statements. Due to the interdependencies and correlation of
these macroeconomic factors, the impact of any one assumption on a
forward-looking statement cannot be determined with certainty, particularly
with respect to the impact of the Merger Transaction on the Company, expected
EBIT, adjusted EBIT, earnings/(loss), adjusted earnings/(loss) and associated
per share amounts, or estimated future dividends. The most relevant assumptions
associated with forward-looking statements on announced projects and projects
under construction, including estimated completion dates and expected capital
expenditures, include the following: the availability and price of labour and
construction materials; the effects of inflation and foreign exchange rates on
labour and material costs; the effects of interest rates on borrowing costs;
the impact of weather and customer, government and regulatory approvals on
construction and in-service schedules and cost recovery regimes.

Enbridge Inc. Reports Second Quarter 2017 Results – Part 3

August 3, 2017 by The Canadian Press

Enbridge’s forward-looking statements are subject to risks and uncertainties
pertaining to the impact of the Merger Transaction, operating performance,
regulatory parameters, dividend policy, project approval and support, renewals
of rights of way, weather, economic and competitive conditions, public opinion,
changes in tax laws and tax rates, changes in trade agreements, exchange rates,
interest rates, commodity prices, political decisions and supply of and demand
for commodities, including but not limited to those risks and uncertainties
discussed in this news release and in the Company’s other filings with Canadian
and United States securities regulators. The impact of any one risk,
uncertainty or factor on a particular forward-looking statement is not
determinable with certainty as these are interdependent and Enbridge’s future
course of action depends on management’s assessment of all information
available at the relevant time. Except to the extent required by applicable
law, Enbridge assumes no obligation to publicly update or revise any
forward-looking statements made in this news release or otherwise, whether as a
result of new information, future events or otherwise. All subsequent
forward-looking statements, whether written or oral, attributable to Enbridge
or persons acting on the Company’s behalf, are expressly qualified in their
entirety by these cautionary statements.

ABOUT ENBRIDGE INC.

Enbridge Inc. is North America’s premier energy infrastructure company with
strategic business platforms that include an extensive network of crude oil,
liquids and natural gas pipelines, regulated natural gas distribution utilities
and renewable power generation. The Company safely delivers an average of 2.8
million barrels of crude oil each day through its Mainline and Express
Pipeline, the majority of which accounts for approximately 65 percent of United
States-bound Canadian crude oil exports, and moves approximately 20 percent of
all natural gas consumed in the United States serving key supply basins and
demand markets. The Company’s regulated utilities serve approximately 3.5
million retail customers in Ontario, Quebec, New Brunswick and New York State.
Enbridge also has a growing involvement in electricity infrastructure with
interests in more than 2,500 megawatt hours of net renewable generating
capacity in North America and an expanding offshore wind portfolio in Europe.
The Company has ranked on the Global 100 Most Sustainable Corporations index
for the past eight years; its common shares trade on the Toronto and New York
stock exchanges under the symbol ENB. Life takes energy and Enbridge exists to
fuel people’s quality of life. For more information, visit www.enbridge.com.
None of the information contained in, or connected to, Enbridge’s website is
incorporated in or otherwise part of this news release.

DIVIDEND DECLARATION

On August 2, 2017, the Enbridge Board of Directors declared the following
quarterly dividends. All dividends are payable on September 1, 2017, to
shareholders of record on August 15, 2017.

/T/

—————————————————————————-
Common Shares $0.61000
Preference Shares, Series A $0.34375
Preference Shares, Series B(1) $0.21340
Preference Shares, Series C(2) $0.18600
Preference Shares, Series D $0.25000
Preference Shares, Series F $0.25000
Preference Shares, Series H $0.25000
Preference Shares, Series J(3) US$0.30540
Preference Shares, Series L US$0.25000
Preference Shares, Series N $0.25000
Preference Shares, Series P $0.25000
Preference Shares, Series R $0.25000
Preference Shares, Series 1 US$0.25000
Preference Shares, Series 3 $0.25000
Preference Shares, Series 5 US$0.27500
Preference Shares, Series 7 $0.27500
Preference Shares, Series 9 $0.27500
Preference Shares, Series 11 $0.27500
Preference Shares, Series 13 $0.27500
Preference Shares, Series 15 $0.27500
Preference Shares, Series 17 $0.32188
—————————————————————————-
1 The quarterly dividend amount of Series B was reset to $0.21340 from
$0.25000 on June 1, 2017, due to reset on every fifth anniversary
thereafter.
2 The quarterly dividend amount of Series C was set at $0.18600 on June 1,
2017, due to reset on a quarterly basis thereafter.
3 The quarterly dividend amount of Series J was reset to US$0.30540 from
US$0.25000 on June 1, 2017, due to reset on every fifth anniversary
thereafter.

/T/

NON-GAAP MEASURES

This news release contains references to adjusted EBIT, adjusted earnings,
adjusted earnings per common share, ACFFO and ACFFO per common share. Adjusted
EBIT represents EBIT adjusted for unusual, non-recurring or non-operating
factors on both a consolidated and segmented basis. Adjusted earnings
represents earnings attributable to common shareholders adjusted for unusual,
non-recurring or non-operating factors included in adjusted EBIT, as well as
adjustments for unusual, non-recurring or non-operating factors in respect of
interest expense, income taxes, noncontrolling interests and redeemable
noncontrolling interests on a consolidated basis. These factors, referred to as
adjusting items, are reconciled and discussed in the financial results sections
for the affected business segments in the Company’s MD&A.

ACFFO is defined as cash flow provided by operating activities before changes
in operating assets and liabilities (including changes in environmental
liabilities) less distributions to noncontrolling interests and redeemable
noncontrolling interests, preference share dividends and maintenance capital
expenditures, and further adjusted for unusual, non-recurring or non-operating
factors.

Management believes the presentation of adjusted EBIT, adjusted earnings,
adjusted earnings per common share, ACFFO and ACFFO per common share gives
useful information to investors and shareholders as they provide increased
transparency and insight into the performance of the Company. Management uses
adjusted EBIT and adjusted earnings to set targets and to assess the
performance of the Company. Management also uses ACFFO to assess the
performance of the Company and to set its dividend payout target. Adjusted
EBIT, adjusted EBIT for each segment, adjusted earnings, adjusted earnings per
common share, ACFFO and ACFFO per common share are not measures that have
standardized meaning prescribed by generally accepted accounting principles in
the United States of America (U.S. GAAP) and are not U.S. GAAP measures.
Therefore, these measures may not be comparable with similar measures presented
by other issuers.

NON-GAAP RECONCILIATION – EBIT TO ADJUSTED EARNINGS

/T/

Three months
ended Six months ended
June 30, June 30,
—————– —————–
2017 2016 2017 2016
—————————————————————————-
(millions of Canadian dollars)
Earnings before interest and income
taxes 2,099 731 3,728 2,907
Adjusting items(1):
Change in unrealized derivative fair
value (gain)/loss(2) (461) 98 (877) (834)
Assets and investment impairment loss – 187 – 187
Unrealized intercompany foreign
exchange (gain)/loss 7 (5) 14 55
Hydrostatic testing – – – (12)
Make-up rights adjustments(3) – 48 – 115
Northeastern Alberta wildfires
pipelines and facilities restart
costs – 21 – 21
Leak remediation costs, net of leak
insurance recoveries 4 1 8 16
Warmer/(colder) than normal weather(4) – (9) – 8
Project development and transaction
costs 50 3 203 3
Employee severance and restructuring
costs 79 8 208 8
Other (65) 6 (56) (11)
—————————————————————————-
Adjusted earnings before interest and
income taxes 1,713 1,089 3,228 2,463
Interest expense (565) (369) (1,051) (781)
Income taxes (293) (10) (491) (427)
(Earnings)/loss attributable to
noncontrolling interests and redeemable
noncontrolling interests (241) 20 (465) (41)
Preference share dividends (81) (71) (164) (144)
Adjusting items in respect of:
Interest expense (23) 6 (2) 24
Income taxes 99 (121) 153 120
Noncontrolling interests and
redeemable noncontrolling interests 53 (88) 129 (95)
—————————————————————————-
Adjusted earnings 662 456 1,337 1,119
—————————————————————————-
—————————————————————————-
1 The above table summarizes adjusting items by nature. For a detailed
listing of adjusting items by segment, refer to individual segment
discussions in the Company’s MD&A.
2 Changes in unrealized derivative fair value gains and losses are presented
net of amounts realized on the settlement of derivative contracts during
the applicable period.
3 Effective January 1, 2017, the Company no longer makes such an adjustment
to its EBIT. For further details refer to Financial Results – Liquids
Pipelines in the Company’s MD&A.
4 Effective January 1, 2017, the Company no longer makes such an adjustment
to its EBIT. For further details refer to Financial Results – Gas
Distribution in the Company’s MD&A.

/T/

NON-GAAP RECONCILIATION – ADJUSTED EBIT TO ACFFO

To facilitate understanding of the relationship between adjusted EBIT and
ACFFO, the following table provides a reconciliation of these two key non-GAAP
measures.

/T/

Three months
ended Six months ended
June 30, June 30,
—————– —————–
2017 2016 2017 2016
———————————————————- —————–
(millions of Canadian dollars)
Adjusted earnings before interest and
income taxes 1,713 1,089 3,228 2,463
Depreciation and amortization(1) 868 555 1,540 1,114
Maintenance capital expenditures(2) (374) (144) (556) (295)
—————————————————————————-
2,207 1,500 4,212 3,282
Interest expense(3) (631) (363) (1,110) (757)
Current income taxes(3) (42) (34) (83) (81)
Distributions to noncontrolling
interests (195) (178) (386) (362)
Distributions to redeemable
noncontrolling interests (63) (53) (117) (95)
Preference share dividends (81) (71) (164) (144)
Cash distributions in excess of equity
earnings(3) 68 43 55 21
Other non-cash adjustments 61 24 132 118
—————————————————————————-
Available cash flow from operations 1,324 868 2,539 1,982
—————————————————————————-
—————————————————————————-
1 Depreciation and amortization:
Liquids Pipelines 385 336 741 682
Gas Pipelines and Processing 250 75 386 149
Gas Distribution 157 84 269 164
Green Power and Transmission 50 47 101 95
Energy Services 1 1 1 1
Eliminations and Other 25 12 42 23
—————————————————————————-
868 555 1,540 1,114
—————————————————————————-
—————————————————————————-
2 Maintenance capital expenditures:
Liquids Pipelines (54) (28) (105) (72)
Gas Pipelines and Processing (153) (12) (192) (23)
Gas Distribution (131) (84) (195) (166)
Green Power and Transmission – (1) (2) (1)
Eliminations and Other (36) (19) (62) (33)
—————————————————————————-
(374) (144) (556) (295)
—————————————————————————-
—————————————————————————-
3 These balances are presented net of adjusting items.

/T/

NON-GAAP RECONCILIATION – ACFFO

The following table provides a reconciliation of cash provided by operating
activities (a GAAP measure) to ACFFO.

/T/

Three months
ended Six months ended
June 30, June 30,
—————– —————–
2017 2016 2017 2016
—————————————————————————-
(millions of Canadian dollars, except
per share amounts)
Cash provided by operating activities 2,033 1,370 3,710 3,231
Adjusted for changes in operating assets
and liabilities(1) (219) (87) (460) (209)
—————————————————————————-
1,814 1,283 3,250 3,022
Distributions to noncontrolling
interests (195) (178) (386) (362)
Distributions to redeemable
noncontrolling interests (63) (53) (117) (95)
Preference share dividends (81) (71) (164) (144)
Maintenance capital expenditures(2) (374) (144) (556) (295)
Significant adjusting items:
Weather normalization – (7) – 6
Make-up rights adjustments 29 46 42 113
Project development and transaction
costs 47 3 199 3
Realized inventory revaluation
allowance(3) – (15) – (283)
Employee severance and restructuring
costs 79 8 206 8
Other items 68 (4) 65 9
—————————————————————————-
Available cash flow from operations 1,324 868 2,539 1,982
—————————————————————————-
—————————————————————————-
Available cash flow from operations per
common share 0.81 0.95 1.81 2.21
—————————————————————————-
—————————————————————————-
1 Changes in operating assets and liabilities include changes in
environmental liabilities, net of recoveries.
2 Maintenance capital expenditures are expenditures that are required for
the ongoing support and maintenance of the existing pipeline system or
that are necessary to maintain the service capability of the existing
assets (including the replacement of components that are worn, obsolete or
completing their useful lives). For the purpose of ACFFO, maintenance
capital excludes expenditures that extend asset useful lives, increase
capacities from existing levels or reduce costs to enhance revenues or
provide enhancements to the service capability of the existing assets.
3 Realized inventory revaluation allowance relates to losses on sale of
previously written down inventory for which there is an approximate
offsetting realized derivative gain in ACFFO.

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Seven Generations Q2 funds from operations up 36% to $268.1 million, or 73 cents per share

August 3, 2017 by The Canadian Press

FOR: SEVEN GENERATIONS ENERGY LTD.
TSX SYMBOL: VII

Date issue: August 03, 2017
Time in: 7:00 AM e

Attention:

Strong condensate production, well results indicate potential expansion of
top-tier drilling inventory

CALGARY, ALBERTA–(Marketwired – Aug. 3, 2017) – Seven Generations Energy Ltd.
(TSX:VII) continued its strong financial and operating performance in the
second quarter of 2017, generating funds from operations of $268.1 million, or
73 cents per share, up 36 and 11 percent, respectively, compared to the second
quarter of 2016. Second quarter production was 165,200 barrels of oil
equivalent per day (boe/d), record volumes that mark a 41 percent increase
compared to one year earlier. 7G’s liquids-to-gas ratio continued at the high
end of the forecast range, averaging 59 percent, with the condensate-to-gas
ratio averaging 132 barrels per million cubic feet of natural gas production.

Marking key milestones in second quarter, surpassing 1 Bcfe/d

“Since the second quarter of 2014, prior to our initial public offering, 7G’s
production has grown seven fold, and the company achieved a number of
milestones in the second quarter. Condensate production surpassed 54,000
barrels per day (bbls/d) and natural gas production averaged more than 400
million cubic feet per day (MMcf/d). In June, 7G’s production surpassed 1
billion cubic feet equivalent per day (Bcfe/d). This growth has been the result
of strong support from our stakeholders who have enabled 7G to create one of
Canada’s top 10 producers in a remarkably short time. Our asset base, balance
sheet, market access and commitment to stakeholder service differentiates 7G as
we continue on our path of profitable growth,” said Marty Proctor, 7G’s
President and Chief Executive Officer.

Recent well results indicate expansion of top-tier inventory

Two wells drilled along the boundary between the Nest 2 and Nest 1 areas,
completed with 60-stages, have produced about 2.5 times more condensate than
the average of 7G’s Nest 2 wells. These two wells have averaged about 1,900
bbls of condensate per day in the first 90 days of production, with one of the
two wells yielding more than 200,000 bbls of cumulative condensate production
to date. On the southern portion of the lands acquired in mid-2016, 7G recently
drilled a 40-stage well that has delivered strong natural gas production in its
first 60 days, averaging about 15.5 MMcf/d of natural gas and 550 bbls/d of
condensate. These wells provide an early indication that 7G’s top-tier
inventory may be significantly expanded, and offer a balance of gas-weighted
and liquids-weighted drilling opportunities.

Third-party outages contribute to reduction of production guidance

Recently, 7G was notified that a third-party plant that processes 7G’s natural
gas will require an unplanned nine-day shut down in August to repair a
dehydration unit. This processing deficiency has limited the plant to a peak
natural gas throughput of about 165 MMcf/d which, combined with planned and
unplanned processing outages, constrained second quarter production to 165,200
boe/d. The processing constraint and the August outage are expected to curtail
production to 180,000 to 185,000 boe/d in the third quarter of 2017. Fourth
quarter production is expected to be more than 200,000 boe/d. Annual production
is now expected to be 175,000 to 180,000 boe/d, four percent below 7G’s
original 2017 guidance of 180,000 to 190,000 boe/d, and representing production
growth of more than 50 percent compared to 2016.

SECOND QUARTER HIGHLIGHTS

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— Average production was 165,200 boe/d, up 41 percent, with condensate

contributing 54,200 boe/d, up 40 percent compared to the second quarter
of 2016. Total liquids represented 59 percent of production.

— Funds from operations were $268.1 million in the second quarter of 2017,

or 73 cents per share, up 36 percent and 11 percent, respectively,
compared to the second quarter of 2016.

— New wells on the boundary of Nest 2 and Nest 1 lands, located on the

southern portion of lands acquired in mid-2016, delivered excellent
early production rates and provide an indication that 7G’s top-tier
drilling inventory may be significantly expanded.

— Increased credit facility from $1.1 billion to $1.4 billion and

transitioned to a fixed four-year, covenant-based facility,
strengthening the company’s financial flexibility with available funding
of approximately $1.6 billion.

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2017 SECOND QUARTER FINANCIAL AND OPERATING RESULTS

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Three months ended Six months ended
June 30 June 30
% %
2017 2016 Change 2017 2016 Change
—————————————————————————-
Operational Highlights
($ millions, except per
share and volume data)
Production
Condensate (mbbl/d) 54.2 38.8 40 50.5 33.6 50
NGLs (mbbl/d) 42.8 30.2 42 42.5 26.4 61
Natural gas (MMcf/d) 409.6 290.1 41 397.1 257.5 54
—————————————————————————-
Total (mboe/d) 165.2 117.4 41 159.2 102.9 55
Liquids % 59% 59% – 58% 58% –
—————————————————————————-

Realized prices
Condensate and oil
($/bbl) 58.57 52.05 13 61.10 46.92 30
NGLs ($/bbl) 16.45 12.49 32 17.23 10.98 57
Natural gas ($/Mcf) 4.09 2.62 56 4.22 2.89 46
—————————————————————————-
Total ($/boe) 33.60 26.91 25 34.51 25.37 36
—————————————————————————-

OPERATING
NETBACK(1)($/boe)
Liquids and natural gas
revenues 33.60 26.91 25 34.51 25.37 36
Royalties (0.62) 1.74 nm (0.91) 0.30 nm
Operating expenses (6.24) (4.20) 49 (5.65) (4.05) 40
Transportation,
processing and other (5.47) (5.26) 4 (5.36) (4.90) 9
—————————————————————————-
Netback prior to hedging 21.27 19.19 11 22.59 16.72 35
Realized hedging gain
(loss) 0.12 2.77 (96) (0.19) 3.51 nm
—————————————————————————-
Operating netback after
hedging 21.39 21.96 (3) 22.40 20.23 11
—————————————————————————-
General and
administrative expenses
per boe 0.82 0.96 (15) 0.80 0.95 (16)
—————————————————————————-

Selected financial
information
Liquids and natural gas
revenue 505.1 287.4 76 994.4 475.4 109
Operating income(1) 59.5 56.0 6 133.6 65.4 104
Per share – diluted 0.16 0.19 (16) 0.37 0.23 61
Net income for the period 178.1 (57.5) nm 393.3 81.0 386
Per share – diluted 0.49 (0.21) nm 1.08 0.28 286
Funds from operations(1) 268.1 197.5 36 540.4 308.2 75
Per share – diluted 0.73 0.66 11 1.48 1.07 38
Cash provided by
operating activities 193.9 152.2 27 529.6 296.7 78
Capital investments(3) 512.5 219.3 134 874.8 486.5 80
Adjusted working capital 246.7 433.1 (43) 246.7 433.1 (43)
Available funding(1) 1,587.1 1,246.1 27 1,587.1 1,246.1 27
Net debt(1) 1,797.2 1,020.1 76 1,797.2 1,020.1 76
Debt outstanding 2,041.9 1,444.0 41 2,041.9 1,444.0 41
Weighted average shares
-basic(2) 353.4 278.4 27 352.0 270.8 30
Weighted average shares
-diluted(2) 365.1 297.8 23 364.8 287.9 27
—————————————————————————-
—————————————————————————-
(1) Operating netback, operating income, funds from operations, adjusted
working capital, available funding and net debt are not defined under
IFRS. See “Non-IFRS Financial Measures” in Management’s Discussion and
Analysis dated August 2, 2017 for the three and six months ended June
30, 2017.
(2) Certain comparative figures have been reclassified to conform to
current period presentation.
(3) Excluding acquisitions and equity investments.
(4) For the three and six months ended June 30, 2016, figures include $27.4
million ($20.0 million after tax) of prior period royalty recoveries.

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DRILLING AND COMPLETIONS

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—————————————————————————-

Three months Three months
ended ended
June 30 March 31
% %
Nest Activity 2017 2016 Change 2017 Change
—————————————————————————-
Drilling(1)
Horizontal wells rig released 30 10 200 23 30
Average measured depth (m) 5,867 5,592 5 5,875 –
Average horizontal length (m) 2,614 2,685 (3) 2,649 (1)
Average drilling days per well 36 41 (12) 34 6
Average drill cost per lateral metre
($)(2) 1,642 1,950 (16) 1,441 14
Average well cost ($ millions)(2) 4.2 4.6 (9) 3.8 11
—————————————————————————-
Completion(1)
Wells completed 33 21 57 14 136
Average number of stages per well 38 30 27 39 (3)
Average tonnes pumped per well 5,961 4,865 23 6,520 (9)
Average cost per tonne(2) 1,282 1,142 12 1,155 11
Average well cost ($ millions)(2) 7.6 5.6 36 7.5 1
—————————————————————————-
Total D&C cost per well ($
millions)(2) 11.8 10.2 16 11.3 4
—————————————————————————-

—————————————————————————-

Six months
ended
June 30
Nest Activity 2017 2016 % Change
—————————————————————————-
Drilling(1)
Horizontal wells rig released 53 25 112
Average measured depth (m) 5,871 5,798 1
Average horizontal length (m) 2,630 2,690 (2)
Average drilling days per well 35 39 (10)
Average drill cost per lateral metre
($)(2) 1,555 1,643 (5)
Average well cost ($ millions)(2) 4.0 4.4 (9)
—————————————————————————-
Completion(1)
Wells completed 47 39 21
Average number of stages per well 39 29 34
Average tonnes pumped per well 6,135 4,824 27
Average cost per tonne(2) 1,234 1,135 9
Average well cost ($ millions)(2) 7.6 5.7 33
—————————————————————————-
Total D&C cost per well ($
millions)(2) 11.6 10.1 15
—————————————————————————-
(1) The drilling and completion counts include only horizontal Montney
wells in the Nest. The drilling counts and metrics exclude wells that
are re-drilled or abandoned. Drill counts are based on rig release date
and brought on production counts are based on the first production date
after the well is tied in to permanent facilities.
(2) Information provided is based on field estimates and are subject to
change.

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OPERATIONS

Average drilling and completion costs per well increased to $11.8 million
during the second quarter of 2017 compared to $10.2 million during the same
period in 2016. The increase was largely due to service cost inflation, water
handling and disposal cost pressures, extended well testing through temporary
production equipment, eight nitrogen-based completions in the second quarter of
2017 compared to none in the second quarter of 2016 and high-intensity
completions resulting in total proppant utilized being up 23 percent
year-over-year.

With up to 13 rigs and four completions spreads running during the second
quarter, the resulting higher water volumes increased water handling and
disposal costs. Trucking costs also increased due to seasonal road bans that
resulted in reduced load sizes. Drilling costs on a per unit basis increased
largely due to downhole difficulties on two wells. When the cost of these
anomalous drilling disruptions are removed, per unit costs were similar to the
first quarter of 2017.

Comprehensive plan underway to reduce costs towards historical levels

Operating expenses in the second quarter were $6.24 per boe compared to $4.20
per boe in the second quarter of 2016, predominantly due to higher water
handling costs and the use of temporary production equipment.

“We are disappointed in the increase in unit costs. We are implementing a
comprehensive cost reduction plan to bring our service and operating costs back
to historical levels. Cost management and reduction is a top priority for the
second half of 2017. With the addition of production and water management
infrastructure, and the startup of permanent production facilities, we expect
operating costs to be in line with historical levels by the fourth quarter of
2017. We will also engage suppliers and service providers who share our
objectives to improve capital efficiencies,” said Glen Nevokshonoff, 7G’s Chief
Operating Officer.

7G’s comprehensive cost reduction plan includes a new third-party water
disposal well, located near the heart of the Nest 2 operating area, that is
connected by an internal field pipeline. A new 7G-owned water disposal well is
drilled, being commissioned and is expected to begin injections in early 2018.
In addition, 7G is recycling a portion of the water that is recovered from
slickwater completions, which will reduce water sourcing, trucking and disposal
costs. Permanent well tie-ins in the second half will also reduce the need for
temporary production equipment.

FINANCIAL

Capital investment focused on full-cycle returns

Second quarter capital investment of $512.5 million included $165 million for
processing and facilities infrastructure to support long-term growth. Seven
Generations’ $1.5 billion to $1.6 billion capital program in 2017 includes
funding for engineering and initial construction of a third wholly-owned
natural gas processing facility, located at the north end of 7G’s Kakwa lands.
Designed to initially process 250 MMcf/d and come on-stream in the second half
of 2018, initial construction will include foundational design and site
preparation that will enable the company to double the plant’s capacity to 500
MMcf/d in the future.

Strong liquids production resulted in cash flow that was ahead of internal
budget for the first half of 2017. Given the recent reduction in commodity
prices, strengthening of the Canadian dollar relative to the US dollar and
pressure on well costs from service cost increases, 7G has deemed it imperative
to focus on cost control and controlling the level of capital expenditures
relative to cash flow. Reaching a self-funding state, with cash flow equivalent
to capital expenditures, remains a key strategic goal.

“After years of very high production growth, we believe it is imperative to
enhance our focus on return on capital employed and unit cost control,
particularly in the prevailing commodity price environment. While we are
dealing with localized cost pressures, we need to increase our scrutiny on
capital allocation and operating practices to ensure we maximize return on
investment,” said Chris Law, Chief Financial Officer. “We believe we can
continue to provide investors with a balance of production and cash flow per
share growth, financial strength and enhanced returns through cost controls
that match the top peers in North America.”

MARKET ACCESS

Increased transportation commitments support future production growth

In the second quarter, 7G added natural gas pipeline transportation capacity
that will further diversify its market access. 7G has contracted delivery
capacity to the Pacific Northwest and northern California on TransCanada’s
Foothills and Gas Transmission Northwest pipelines starting with modest volumes
in November 2019, ramping up to about 90 MMcf/d in 2020. This solidifies 7G’s
market access to new customers in Washington, Oregon and California, adding to
its established markets in the U.S. Midwest, Alberta, Eastern Canada and the
U.S. Gulf Coast.

In addition to this delivery commitment, 7G added TransCanada NGTL receipt
capacity of 333 MMcf/d at its planned mainline Wildrose meter station. Combined
with existing receipt commitments, this new commitment brings the contracted
NGTL receipt capacity at Wildrose to 500 MMcf/d, which matches the total design
capacity of the new plant to be constructed at the north end of 7G’s Kakwa
lands. This commitment phases in over a period of time, reaching peak receipt
capacity in the second half of 2021 and supports future production growth.

7G continues to pursue and evaluate a variety of new market opportunities,
including supplying natural gas to power generation facilities in Alberta,
supplying natural gas and natural gas liquids to petrochemical facilities and
exporting liquefied natural gas and propane off Canada’s West Coast to serve
consumers in Asia.

OUTLOOK

Capital investments to support profitable growth

Seven Generations intends to complete a $1.5 billion to $1.6 billion capital
investment program in 2017. 7G will continue with its planned investments in
drilling, completions and the facilities and infrastructure to improve capital
efficiencies and provide the base for future, profitable growth. 7G’s 2017
production guidance is 175,000 to 180,000 boe/d, 55 to 60 percent of which is
expected to be composed of liquids.

Conference Call

7G management will hold a conference call to discuss results and address
investor questions today, August 3, 2017 at 9 a.m. MT (11 a.m. ET).

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Participant Dial-In Numbers:

Operator Assisted Toll-Free (877) 390-7644
Local or International (647) 252-4486
Conference Call ID: 49456878

Encore Dial In: (855) 859-2056 or (800) 585-8367
Replay code: 49456878
Available: August 3 – 11, 2017

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Seven Generations Energy

Seven Generations is a low-supply-cost, high-growth Canadian natural gas
developer generating long-life value from its liquids-rich Kakwa River Project,
located about 100 kilometres south of its operations headquarters in Grande
Prairie, Alberta. 7G’s corporate headquarters are in Calgary and its shares
trade on the TSX under the symbol VII.

Further information on Seven Generations is available on the company’s website:
www.7genergy.com.

Non-IFRS Financial Measures and Other Measures

This news release includes certain terms or performance measures commonly used
in the oil and natural gas industry that are not defined under IFRS, including
“funds from operations”, “operating income”, “operating netback”, “available
funding”, “net debt” and “adjusted working capital”. Operating netback has been
calculated on a per boe basis and is determined by deducting royalties,
operating and transportation, processing and other expenses from oil and
natural gas revenue and, except where otherwise indicated, after adjusting for
realized hedging gains or losses. Operating netback is utilized by the company
and others to better analyze the operating performance of its oil and natural
gas assets.
In particular, but without limiting the foregoing, this news release contains
forward-looking information and statements pertaining to the following: the
potential expansion of the company’s top-tier drilling inventory; expected
production in the third quarter, fourth quarter and for the full year in 2017;
expected long-term production growth; expectation that historic operating costs
will be in line with historic levels by the fourth quarter of 2017, with the
addition of production and water management infrastructure, the use of water
recycling, and the start-up of permanent production facilities; well tie-ins
expected in the second half of the year; expected capital investments in 2017;
timing of the construction and the expected processing capacity of the new gas
processing facility that is planned to be constructed at the north end of the
Kakwa field; plans to design that new facility to enable the company to double
the processing capacity of the facility in the future; expectation that the
company will reach a self-funding state; expectation that the company will
provide investors with a balance of production and cash flow per share growth,
financial strength, and enhanced returns through cost control that will match
top peers in North America; anticipated processing and transportation capacity;
expected market access; future outlook; the timing of a third party plant
shut-down in August 2017; the expected impact of the plant shut-down on the
company’s production; the expectation that the repairs at the plant will
restore the plant to its design processing capacity; planned focus on return on
capital employed and cost control; the ability to generate long-life value from
the Kakwa River Project. The data presented are intended to provide additional
information and should not be considered in isolation or as a substitute for
measures of performance prepared in accordance with IFRS. These non-IFRS
measures should be read in conjunction with the company’s financial statements
and accompanying notes. Readers are cautioned that the non-IFRS measures do not
have any standardized meaning and should not be used to make comparisons
between the company and other companies without also taking into account any
differences in the way the calculations were prepared.

For more information regarding “funds from operations”, “operating income”,
“operating netback”, “available funding”, “net debt”, “adjusted working
capital”, and “adjusted EBITDA”, see “Non-IFRS Financial Measures” in the
company’s Management’s Discussion and Analysis dated August 2, 2017, for the
three and six months dated June 30, 2017. Per share amounts are presented on a
diluted basis.

Reader Advisory

This news release contains certain forward-looking information and statements
that involve various risks, uncertainties and other factors. The use of any of
the words “anticipate”, “continue”, “estimate”, “expect”, “may”, “will”,
“should”, “believe”, “plans”, and similar expressions are intended to identify
forward-looking information or statements. In particular, but without limiting
the foregoing, this news release contains forward-looking information and
statements pertaining to the following: outlook; expected well productivity;
the number of new wells to be brought on production in 2017; the timing of the
third party facility outage that is planned for August 2017; the expected
impact of the facility outage on the company’s production; the expectation that
the repairs at the facility will restore the facility’s processing capacity to
its design capacity of 250 MMcf/d; anticipated production in the third quarter,
fourth quarter, and for the full year in 2017; production growth; expected
capital investments in 2017; plans to invest in facilities and operational
enhancements which are expected to generate returns, including pipelines, well
tie-ins, a second condensate stabilizer at the Karr facility, production
equipment on the assets acquired in 2016, and the installation of new gas lift
infrastructure; plans to focus on operating cost reductions in the second half
of 2017, including by replacing temporary production facilities with permanent
infrastructure and reducing water handling costs with the completion of water
injection facilities; plans to reduce the number of drilling rigs and
completions crews to be contracted for the remainder of 2017; expected
long-term growth; timing of the construction and the expected processing
capacity of the new gas processing facility that is planned to be constructed
at the north end of the Kakwa field; plans to design that new facility to
enable the company to double the processing capacity of the facility in the
future; expected transportation capacity and market access; the increased focus
on investment discipline that is expected for the remainder of the year; the
ability to return operating costs to historic levels and the continued delivery
of full-cycle returns; the ability to generate long-life value from the Kakwa
River Project.

With respect to forward-looking information contained in this news release,
assumptions have been made regarding, among other things: future oil, NGLs and
natural gas prices being consistent with current commodity price forecasts
after factoring in quality adjustments at the company’s points of sale; the
company’s continued ability to obtain qualified staff and equipment in a timely
and cost-efficient manner; infrastructure and facility design concepts that
have been applied by the company in its Kakwa River Project may be successfully
applied elsewhere in the Kakwa River Project; the consistency of the regulatory
regime and framework governing royalties, taxes and environmental matters in
the jurisdictions in which the company conducts its business and any other
jurisdictions in which the company may conduct its business in the future; the
company’s ability to market production of oil, NGLs and natural gas
successfully to customers; the company’s future production levels and amount of
future capital investment will be consistent with the company’s current
development plans and budget; the applicability of new technologies for
recovery and production of the company’s reserves and resources may improve
capital and operational efficiencies in the future; the recoverability of the
company’s reserves and resources; sustained future capital investment by the
company; future cash flows from production; the future sources of funding for
the company’s capital program; the company’s future debt levels; geological and
engineering estimates in respect of the company’s reserves and resources; the
geography of the areas in which the company is conducting exploration and
development activities, and the access, economic, regulatory and physical
limitations to which the company may be subject from time to time; the impact
of competition on the company; and the company’s ability to obtain financing on
acceptable terms.

Actual results could differ materially from those anticipated in the
forward-looking information that is contained herein as a result of the risks
and risk factors that are set forth in the company’s Annual Information Form
for the year ended December 31, 2016, dated March 7, 2017 (the “AIF”), which is
available on SEDAR at www.sedar.com, including, but not limited to: volatility
in market prices and demand for oil, NGLs and natural gas and hedging
activities related thereto; general economic, business and industry conditions;
variance of the company’s actual capital costs, operating costs and economic
returns from those anticipated; the ability to find, develop or acquire
additional reserves and the availability of the capital or financing necessary
to do so on satisfactory terms; risks related to the exploration, development
and production of oil and natural gas reserves and resources; negative public
perception of oil sands development, oil and natural gas development and
transportation, hydraulic fracturing and fossil fuels; actions by governmental
authorities, including changes in government regulation, royalties and
taxation; potential legislative and regulatory changes; the rescission, or
amendment to the conditions, of groundwater licenses of the company; management
of the company’s growth;
the ability to successfully identify and make attractive acquisitions, joint
ventures or investments, or successfully integrate future acquisitions or
businesses; the availability, cost or shortage of rigs, equipment, raw
materials, supplies or qualified personnel; adoption or modification of climate
change legislation by governments; the absence or loss of key employees;
uncertainty associated with estimates of oil, NGLs and natural gas reserves and
resources and the variance of such estimates from actual future production;
dependence upon compressors, gathering lines, pipelines and other facilities,
certain of which the company does not control; the ability to satisfy
obligations under the company’s firm commitment transportation arrangements;
the uncertainties related to the company’s identified drilling locations; the
high-risk nature of successfully stimulating well productivity and drilling for
and producing oil, NGLs and natural gas; operating hazards and uninsured risks;
the risks of fires, flood and natural disasters; the possibility that the
company’s drilling activities may encounter sour gas; execution risks
associated with the company’s business plan; failure to acquire or develop
replacement reserves; the concentration of the company’s assets in the Kakwa
River Project area; unforeseen title defects; aboriginal claims; failure to
accurately estimate abandonment and reclamation costs; development and
exploratory drilling efforts and well operations may not be profitable or
achieve the targeted return; horizontal drilling and completion technique risks
and failure of drilling results to meet expectations for reserves or
production; limited intellectual property protection for operating practices
and dependence on employees and contractors;
third-party claims regarding the company’s right to use technology and
equipment; expiry of certain leases for the undeveloped leasehold acreage in
the near future; failure to realize the anticipated benefits of acquisitions or
dispositions; failure of properties acquired now or in the future to produce as
projected and inability to determine reserve and resource potential, identify
liabilities associated with acquired properties or obtain protection from
sellers against such liabilities; changes in the application, interpretation
and enforcement of applicable laws and regulations; restrictions on drilling
intended to protect certain species of wildlife; potential conflicts of
interests; actual results differing materially from management estimates and
assumptions; seasonality of the company’s activities and the Canadian oil and
gas industry; alternatives to and changing demand for petroleum products;
extensive competition in the company’s industry; changes in the company’s
credit ratings; dependence upon a limited number of customers; lower oil, NGLs
and natural gas prices and higher costs; failure of 2D and 3D seismic data used
by the company to accurately identify the presence of oil and natural gas;
risks relating to commodity price hedging instruments; terrorist attacks or
armed conflict; cyber-security risks, loss of information and computer systems;
inability to dispose of non-strategic assets on attractive terms; security
deposits required under provincial liability management programs; reassessment
by taxing authorities of the company’s prior transactions and filings;
variations in foreign exchange rates and interest rates; third-party credit
risk, including risk associated with counterparties in risk management
activities related to commodity prices and foreign exchange rates; sufficiency
of insurance policies; potential litigation; variation in future calculations
of non-IFRS measures; sufficiency of internal controls; breach of agreements by
counterparties and potential enforceability issues in contracts; impact of
expansion into new activities on risk exposure; inability of the company to
respond quickly to competitive pressures; and the risks related to the common
shares that are publicly traded and the company’s senior notes and other
indebtedness.

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Definitions and Abbreviations
bbl barrel
bbls barrels
bcf billion cubic feet
bcfe(2) billion cubic feet equivalent
boe(1) barrels of oil equivalent
d day
D&C drilling and completions
IFRS International Financial Reporting Standards
m metres
Mcf thousand cubic feet
mcfe(2) thousand cubic feet equivalent
mboe thousands of barrels of oil equivalent
mbbl thousands of barrels
MMcf million cubic feet
Nest 1 means the prospects within the Nest, outside of the Nest 2 area
Nest 2 means the highest return prospects within the Nest
Nest means the primary development block of the Kakwa River Project
NGLs natural gas liquids
Q2 second quarter of the year
TSX Toronto Stock Exchange

/T/

Seven Generations Energy Ltd. is also referred to as Seven Generations, Seven
Generations Energy, 7G or the company.

/T/

1. Seven Generations has adopted the standard of 6 Mcf:1 bbl when

converting natural gas to boes. Condensate and other NGLs are converted
to boes at a ratio of 1 bbl:1 bbl. Boes may be misleading, particularly
if used in isolation. A boe conversion ratio of 6 Mcf:1 bbl is based
roughly on an energy equivalency conversion method primarily applicable
at the burner tip and does not represent a value equivalency at the
company’s sales point. Given the value ratio based on the current price
of oil as compared to natural gas is significantly different from the
energy equivalency of 6 Mcf: 1 bbl, utilizing a conversion ratio at 6
Mcf: 1 bbl may be misleading as an indication of value.
2. Mcfe and bcfe have been calculated using a conversion ratio of 1 bbl: 6
Mcf when converting oil to natural gas equivalent. Mcfe and bcfe amounts
may be misleading particularly if used in isolation. An Mcfe conversion
ratio of 1 bbl: 6 Mcf is based on an energy equivalency conversion
method primarily applicable at the burner tip and does not represent a
value equivalency at the wellhead. Given that the value ratio based on
the current price of oil as compared to natural gas is significantly
different from the energy equivalency of 1 bbl: 6 Mcf, utilizing a
conversion ratio of 1 bbl: 6 Mcf may be misleading as an indication of
value.

/T/

– END RELEASE – 03/08/2017

For further information:
Investor Relations
Chris Law, Chief Financial Officer
Brian Newmarch, Vice President, Capital Markets
403-767-0752
bnewmarch@7genergy.com
OR
Media Relations
Alan Boras
Director, Communications and Stakeholder Relations
403-767-0772
aboras@7genergy.com
OR
Seven Generations Energy Ltd.
Suite 4400, 525 – 8th Avenue SW
Calgary, AB T2P 1G1
www.7genergy.com

COMPANY:
FOR: SEVEN GENERATIONS ENERGY LTD.
TSX SYMBOL: VII

INDUSTRY: Energy and Utilities – Oil and Gas
RELEASE ID: 20170803CC0015

Press Release from Marketwired 1-866-736-3779

Gibson Energy Reports Solid Second Quarter Results and Announces Plans to Divest U.S. Environmental Services Business

August 2, 2017 by EnergyNow Media

CALGARY, Alberta, Aug. 01, 2017 (GLOBE NEWSWIRE) — Gibson Energy Inc. (“Gibsons” or the “Company”), (TSX:GEI), announces performance driven by continued growth in its crude oil infrastructure business, resulting in significant increases in profit and distributable cash flow. The Company also announces plans to divest of its United States Environmental Services business. Highlights: (Comparisons made … Read more

Baytex Reports Solid Q2 2017 Results With 5% Production Growth and Strong Eagle Ford Performance

August 2, 2017 by EnergyNow Media

CALGARY, Alberta, Aug. 01, 2017 (GLOBE NEWSWIRE) — Baytex Energy Corp. (“Baytex”) (TSX:BTE) (NYSE:BTE) reports its operating and financial results for the three and six months ended June 30, 2017 (all amounts are in Canadian dollars unless otherwise noted). “Driven by excellent capital efficiencies across our portfolio, we have been able to substantially grow production … Read more

Whitecap Resources Inc. Announces Second Quarter 2017 Results

August 2, 2017 by EnergyNow Media

CALGARY, Aug. 1, 2017 /CNW/ – Whitecap Resources Inc. (“Whitecap” or the “Company”) (TSX: WCP) is pleased to report its operating and unaudited financial results for the three and six months ended June 30, 2017. Selected financial and operating information is outlined below and should be read with Whitecap’s unaudited interim consolidated financial statements and related Management’s Discussion … Read more

Oil Rises as Record Gasoline Demand Allays Shale Boom Worries

August 2, 2017 by EnergyNow Media

August 2, 2017 (Bloomberg) Oil ended a fickle session on the rise as record demand for gasoline helped ease concerns that increasing crude production from America’s shale fields will worsen a global glut. Futures closed 0.9 percent higher in New York after disappointing numbers for crude supplies and output sent prices tumbling. U.S. oil stockpiles last … Read more

US oil and gas plowback robust despite capex and revenue cuts says EY

August 2, 2017 by EnergyNow Media

August 2, 2017 PR Newswire HOUSTON, Aug. 2, 2017 /PRNewswire/ — Despite the low price environment, continued declines in revenues and lower capital expenditures, the 50 largest US exploration and production (E&P) companies demonstrated a commitment toward resource acquisition and development with strong plowback percentages* in 2016 — 158% compared to a five-year average of 132%, according to the US … Read more

Rick George, former Suncor Energy CEO and pioneer of oilsands industry, dies at 67

August 2, 2017August 2, 2017 by The Canadian Press

CALGARY — Rick George, former CEO of Suncor Energy and a pioneer of Canada’s oilsands industry, has died at the age of 67 after a battle with acute myeloid leukemia.

George, who died Tuesday, is credited with transforming Suncor from a money-losing oilsands mining company into one of Canada’s largest corporations over a 21-year career before his retirement in 2012.

“Rick’s impact on the oilsands industry, the Canadian business community, and the broader community has been immeasurable,” said Suncor CEO Steve Williams in a statement.

“Rick was very much admired and loved by his Suncor family.”

Williams worked as an executive with George for 10 years at Suncor before assuming the helm of the company.

George joined the company that would become Suncor in 1991 and brought in changes that upset traditional mining practices but boosted production and profitability.

“He had the fortitude and the vision to change the model and he … reinvented the model to allow oilsands to reach its potential in a way that we’re all benefiting from today,” said Tim McMillan, president of the Canadian Association of Petroleum Producers.

George oversaw Suncor’s $19-billion merger with Petro-Canada in 2009, creating a company with oilsands production, refineries, retail outlets, offshore and conventional oil and gas assets throughout the country.

Suncor’s shares are now worth about $68 billion.

In a statement on Wednesday, his family asked for privacy.

“With heavy hearts, we are determined to embrace challenges and adventure with the same rigour that he demonstrated every day,” the statement said.

“A brilliant businessman, a loyal friend, and a loving husband, father and grandfather, he will be greatly missed.”

His immediate family includes his wife Julie, sons Matthew and Zachary, and daughter Emily.

George was born in the small ranching community of Brush, Colo., and earned science and law degrees in the United States.

He served as managing director of Sun Oil Britain Ltd. before moving to Canada in 1991, later adopting Canadian citizenship.

Mike O’Brien, a current member of the Suncor board who retired as chief financial officer in 2002, said George’s drive was balanced by a folksy charm that helped him win converts to his point of view.

“He’s a hell of a nice guy. Everyone wants to help him get it done,” said O’Brien.

George was appointed an officer of the order of Canada in 2007 in recognition of his business acumen and commitment to Aboriginal communities and sustainable development.

“He was on the environmental file before anyone else was. He was on the Aboriginal file,” said O’Brien. “He just felt those things were priorities and he saw the big picture.”

George wrote a biography after retiring called Sun Rise: Suncor, the Oil Sands and the Future of Energy, in which he staunchly defended the environmental record of the oilsands and its interactions with Aboriginals while decrying delays in approving export oil pipelines such as the Keystone XL.

He recently served on the boards of Osum Oil Sands Corp., RBC and Anadarko Petroleum, and as a partner at Novo Investment Group.

George was chairman of Penn West Petroleum and officiated over the annual meeting in June in downtown Calgary where the company’s name was changed to Obsidian Energy.

Follow @HealingSlowly on Twitter.

Dan Healing, The Canadian Press

Trilogy Energy Corp. Announces Financial and Operating Results for the Three and Six Months-Ended June 30, 2017

August 2, 2017 by The Canadian Press

FOR: TRILOGY ENERGY CORP.
TSX SYMBOL: TET

Date issue: August 02, 2017
Time in: 5:34 PM e

Attention:

CALGARY, ALBERTA–(Marketwired – Aug. 2, 2017) – Trilogy Energy Corp. (TSX:TET)
(“Trilogy”) is pleased to announce its financial and operating results for the
three and six months-ended June 30, 2017.

Financial and Operating Highlights

/T/

— Reported sales volumes for the second quarter of 2017 decreased 14

percent to 21,669 Boe/d (36 percent liquids) as compared to 25,133 Boe/d
(38 percent liquids) for the first quarter of 2017. The decrease was
attributed to dispositions of assets at the end of May, scheduled and
non-scheduled plant and pipeline outages, new well production declines
and for wet surface conditions which precluded access and production
from a number of sites. Year-over-year, for the six months ended June
30, reported sales volumes increased by 9 percent on new well production
at Trilogy’s Montney oil play and resumed production on less economic
plays in conjunction with recovering commodity prices in the latter part
of 2016. Liquids composition increased year-over-year by 7 percent to 37
percent of total reported sales volumes. Production for July is
estimated to be approximately 25,000 Boe/d and production volumes are
expected to average approximately 25,000 Boe/d for the third quarter of
2017;
— Average realized pricing, after hedges, decreased by 10 percent to
$32.28/Boe ($31.08/Boe before hedges) in the second quarter of 2017 from
$35.97/Boe ($33.64/Boe before hedges) in the previous quarter. Year over
year, for the six months ended June 30, average realized pricing, after
hedges, increased 42 percent (50 percent before hedges) over 2016;
— Funds flow from operations (1) decreased 31 percent to $24.9 million for
the second quarter of 2017 as compared to $36.4 million for the previous
quarter. Year over year, for the six months ended June 30, funds flow
from operations increased by 240 percent in 2017 to $61.3 million from
$18.0 million in 2016;
— Trilogy drilled 3.0 net wells in the second quarter for a total year-to-
date of 12.0 net wells drilled. Capital expenditures, prior to
acquisitions and dispositions, totaled $22.1 million for the second
quarter compared to $41.6 million for the first quarter;
— Trilogy completed the sale in the second quarter of non-core oil and gas
properties for proceeds of approximately $110 million. The proceeds were
applied against Trilogy’s Revolving Credit Facility. Net debt (1)
decreased, on the disposition, to $466.9 million as at June 30, 2017
from $588.6 million as at December 31, 2016. Capacity under the
Company’s Revolving Credit Facility is approximately $111 million as at
the end of the second quarter;
— Subsequent to the quarter, Trilogy has announced that it has entered
into an agreement to merge with Paramount Resources Ltd. (“Paramount”).
Under the merger, Paramount would acquire all of the common shares and
non-voting shares of Trilogy not already owned by Paramount in exchange
for common shares of Paramount on the basis of one Paramount share for
every 3.75 Trilogy shares. The merger is to be effected by way of an
arrangement under the Business Corporations Act (Alberta) and is subject
to shareholder and court approvals, including minority shareholder
approval by the shareholders of each of Trilogy and Paramount, and the
fulfilment of other conditions that are typical for transactions of this
nature. The special meetings of shareholders are expected to be held in
September 2017. If all approvals are received and other closing
conditions satisfied, the merger is expected to be completed that month.
The senior unsecured notes of Trilogy will remain outstanding following
completion of the merger as the merger will not trigger any change of
control payments. Following the merger, the outstanding Trilogy options
will entitle the option holders to acquire Paramount shares rather than
Trilogy shares at an adjusted exercise price, based on the exchange
ratio for the merger and in accordance with the options’ original
vesting schedules.

/T/

(1) Refer to Non-GAAP measures

/T/

Financial and Operating Highlights Table

(In thousand Canadian dollars except per share amounts and where stated
otherwise)

Three Months Ended Six Months Ended
June 30, March 31, Change% June 30, June 30, Change%
2017 2017 2017 2016
—————————————————————————-
FINANCIAL
Petroleum and
natural gas
sales 61,280 76,089 (19) 137,369 84,652 62
Funds flow
From
operations(1) 24,941 36,382 (31) 61,322 18,034 240
Per share –
diluted 0.20 0.29 (31) 0.48 0.14 239
Earnings
Income (loss)
before tax 36,030 10,874 231 46,903 (74,455) 163
Per share –
diluted 0.29 0.09 232 0.37 (0.59) 163
Income (loss)
after tax 24,855 7,694 223 32,548 (56,657) 157
Per share –
diluted 0.20 0.06 224 0.26 (0.45) 157
Capital
expenditures
Exploration,
development,
land,
and facility 22,116 41,658 (47) 63,773 23,355 173
Acquisitions
(dispositions)
and
other – net (108,977) (675) 16,045 (109,652) (412) 26,515
Net capital
expenditures (86,861) 40,983 (312) (45,879) 22,943 (300)
Total assets 1,133,387 1,230,978 (8) 1,133,387 1,237,887 (8)
Net debt(1) 466,875 583,777 (20) 466,875 561,585 (17)
Shareholders’
equity 398,421 372,525 7 398,421 398,975 –
Total shares
outstanding
(thousands)
– As at end of
period (2) 126,133 126,106 – 126,133 126,064 –
—————————————————————————-
—————————————————————————-
OPERATING
Production
Natural gas
(MMcf/d) 84 93 (10) 88 90 (2)
Oil (Bbl/d) 5,221 6,305 (17) 5,760 4,090 41
Condensate
(Boe/d) 1,474 2,059 (28) 1,765 1,590 11
Natural gas
liquids (Boe/d) 1,043 1,207 (14) 1,125 860 31
—————————————————————————-
Total production
(Boe/d @ 6:1) 21,669 25,133 (14) 23,391 21,543 9
—————————————————————————-
Liquids
Composition
(percentage) 36 38 (6) 37 30 22
—————————————————————————-
Average prices
after financial
instruments
Natural gas
($/Mcf) 3.04 3.63 (16) 3.35 2.10 60
Crude Oil
($/Bbl) 62.08 62.69 (1) 62.41 44.07 42
Condensate
($/Boe) 61.86 63.25 (2) 62.67 49.64 26
Natural gas
liquids ($/Boe) 28.57 32.95 (13) 30.91 19.42 59
—————————————————————————-
Average realized
price ($/Boe) 32.28 35.97 (10) 34.25 24.05 42
Drilling activity
(gross)
Gas 4 4 – 8 3 167
Oil – 6 (100) 6 3 100
—————————————————————————-
—————————————————————————-
Total wells 4 10 (60) 14 6 133
(1) Funds flow from operations and net debt are non-GAAP terms. Please refer
to the advisory on Non-GAAP measures below.

(2) Excluding shares held in trust for the benefit of Trilogy’s officers and

employees under the Company’s Share Incentive Plan. Includes Common
Shares and Non-voting Shares. Refer to the notes to the Annual Audited
Consolidated Financial Statements for additional information.

/T/

Operations Update for the Second Quarter 2017

Trilogy’s second quarter 2017 production was 21,669 Boe/d (36 percent oil and
natural gas liquids), a decrease of 14 percent from first quarter 2017
production of 25,133 Boe/d (38 percent oil and natural gas liquids). The
decrease in second quarter production reflects the impact of the previously
announced asset sales in Grande Prairie and Kaybob (approximately 900 Boe/d),
scheduled and non-scheduled plant and pipeline outages (approximately 700
Boe/d) and delays in bringing on some of the wells drilled in the first quarter
as a result of a prolonged spring break up in the Kaybob area during the second
quarter. New horizontal Montney oil wells drilled and completed in the first
quarter 2017 offset a portion of the impact of natural production declines,
asset sales and infrastructure outages and restrictions. Production for July is
estimated to be approximately 25,000 Boe/d and production volumes are expected
to average approximately 25,000 Boe/d for the third quarter of 2017.

Second quarter funds flow from operations were $24.9 million and capital
expenditures, before dispositions, totaled $22.1 million. Year-to-date funds
flow from operations totaled $61.3 million, while year-to-date capital
expenditures were $63.8 million. The Company currently plans to continue with
its Montney oil drilling and completion program in the second half of the year
and is evaluating whether to proceed with its budgeted 4 well Duvernay pad in
the Smoky area, for budgeted annual capital expenditures of approximately $130
million, or defer this project, in which case capital expenditures are expected
to be approximately $100 million.

Asset Sales

In the second quarter, Trilogy completed the sale of two non-core asset sales.
The sale of the Valhalla property in the Grande Prairie area closed on May 30,
2017 for $50 million (before customary adjustments) and included approximately
1,100 Boe/d of production (16 percent oil and natural gas liquids), 44,000 net
acres of mineral rights, 1.8 MMBoe of Total Proved Developed Producing reserves
and 5.5 MMBoe of Total Proved Plus Probable reserves.

The second asset sale closed on May 31, 2017, for total proceeds of $60 million
(before customary adjustments) and included approximately 600 Boe/d of
production (30 percent condensate and natural gas liquids), 9.7 net sections of
primarily Duvernay mineral rights, 0.9 MMBoe of Total Proved Developed
Producing reserves and Trilogy`s 11 percent working interest in a non-operated
gas plant.

Montney Oil Pool

The shift from hydrocarbon-based to slickwater fracture stimulations in early
2016 reduced completion costs and allowed the Company to economically increase
proppant volume and decrease stage spacing, thereby better distributing
proppant along the length of the lateral wellbore. Trilogy has varied sand
volumes from 10 tonnes per stage in the Company’s original horizontal Montney
oil wells to as much as 20 tonnes per stage in recent wells. At the same time,
stage spacing was reduced from 75 meters per stage in the original wells to 50
to 65 meters in recent wells. In addition, completion pump rates have increased
substantially, resulting in increased fracture complexity. All of these factors
combined have contributed to higher initial well productivity as compared to
the Company’s first generation Montney oil wells. In the third quarter, Trilogy
will be completing its next multi-well pad with up to 25 – 32 tonnes per stage
and reducing stage spacing to 42 – 55 meter intervals to further evaluate the
impact that sand and stage spacing has on production and ultimate recoverable
reserves.

Trilogy has allocated approximately $60 million to further develop its Montney
oil pool in 2017. The majority of the capital will be allocated to drill 15
wells and complete 18 wells in the pool, incorporating the efficiencies from
the Company’s 2016 Montney drilling and completion program. Year-to-date,
Trilogy has drilled 6 Montney oil wells into the pool, all in the first
quarter. Drilling operations in the pool resumed in early July and will
continue through most of the second half of the year. Current budget plans are
to drill 9 additional horizontal wells through the second half of 2017;
however, given continued success with the new completion program, Trilogy will
have the option to drill up to 4 additional wells later in the fourth quarter.
Trilogy also intends to allocate capital to a water disposal project, a gas
reinjection project and to the construction of pad sites and pipelines intended
for future development of the pool.

Presley Montney Gas Development

Trilogy’s 2017 budget provided approximately $30 million to develop 6 (6.0 net)
wells in the Presley Montney liquids – rich gas pool. In Presley, Trilogy has
also reduced stage spacing from 100 meters to 75 meters and are testing 50
meter stage spacing. Proppant loading has also increased up to 30 tonnes per
stage in the pool, resulting in a significant increase in total proppant per
well. Trilogy drilled 3 (3.0 net) extended length horizontal wells (each
approximately 2 miles in lateral length) into the pool in the first quarter and
a 3-well pad (1 mile laterals) in the second quarter. One of the extended reach
lateral wells was fracture stimulated in April and was on production in early
May. The remaining 2 wells were expected to be completed in mid-May and on
production in mid-June; however, a prolonged spring break-up prevented the
wells from being completed until early July with production brought on in
mid-July. The 3-well pad was completed in mid-July. Tie-in operations are
currently underway and are expected to be complete in early August,
contributing to third quarter production growth. Trilogy plans to continue
preparing drilling locations and evaluating infrastructure alternatives for the
Montney gas pool, in preparation for additional field development when
commodity prices increase.

Duvernay Update

During the second quarter drilling, Trilogy did not participate in any new
Duvernay drilling or completion operations. However, the industry’s continued
improvements in drilling and completion technologies which better stimulate the
Duvernay shale reservoir are expected to result in higher productivity wells
with higher ultimate recoverable reserves. Trilogy will continue to monitor
the progress and will adapt to the evolving drilling and completion
improvements when it starts its Duvernay development program. Trilogy has
allocated approximately $35 million towards Duvernay projects in the second
half of 2017. The decision as to whether or not to execute this portion of the
2017 capital budget will be made later in the year. Annual 2017 production
guidance will not be impacted by this decision.

Subsequent Event

Subsequent to the end of the second quarter, Trilogy announced that it has
entered into a Plan of Arrangement to merge with Paramount Resources Ltd.
(“Paramount”). Under the merger, Paramount would acquire all of the common
shares and non-voting shares of Trilogy not already owned by Paramount in
exchange for common shares of Paramount on the basis of one Paramount share for
each 3.75 Trilogy shares. The merger is to be effected by way of a an
arrangement under the Business Corporations Act (Alberta) and is subject to
shareholder and court approvals, including minority shareholder approval by the
shareholders of both Trilogy and Paramount, and the fulfillment of other
conditions that are typical of transactions of this nature. The special
meetings of shareholders are expected to be held in September 2017. If all
approvals are received and other closing conditions satisfied, the merger is
expected to be completed that month.

Outlook

Trilogy maintains its plan to execute a 2017 capital spending budget that is
within anticipated 2017 funds flow from operations based on Trilogy’s 2017
actual and forecast production and pricing for the remainder of the year. The
level of capital spending in the second half of the year will depend on
commodity prices and will primarily impact the Duvernay projects later in 2017.
The Grande Prairie and Kaybob non-core asset sales are not expected to have a
significant impact on annual production or funds flow from operations.

Given the foregoing, Trilogy is reaffirming its 2017 annual guidance as follows:

/T/

. Average production: 24,000 Boe/d (approx. 35% oil and NGLs)
. Average operating costs: $8.50/Boe
. Capital expenditures: $100 – $130 Million

/T/

Additional Information

Trilogy’s financial and operating results for the second quarter of 2017,
including Management’s Discussion and Analysis and the Company’s Unaudited
Interim Consolidated Financial Statements and related Notes as at and for the
quarter-ended June 30, 2017 can be obtained by clicking on the following link:
http://media3.marketwire.com/docs/Q2_2017_REPORT.pdf. These reports will also
be made available through Trilogy’s website at www.trilogyenergy.com and SEDAR
at www.sedar.com.

About Trilogy

Trilogy is a petroleum and natural gas-focused Canadian energy corporation that
actively develops, produces and sells natural gas, crude oil and natural gas
liquids. Trilogy’s geographically concentrated assets are primarily, high
working interest properties that provide abundant low-risk infill drilling
opportunities and good access to infrastructure and processing facilities, many
of which are operated and controlled by Trilogy. Trilogy’s common shares are
listed on the Toronto Stock Exchange under the symbol “TET”.

Non-GAAP Measures

Certain measures used in this document, including “adjusted EBITDA”,
“consolidated debt”, “finding and development costs”, “funds flow from
operations”, “operating income”, “net debt”, “operating netback”, “recycle
ratio” and “senior debt” collectively the “Non GAAP measures” do not have any
standardized meaning as prescribed by IFRS and previous GAAP and, therefore,
are considered Non-GAAP measures. Non-GAAP measures are commonly used in the
oil and gas industry and by Trilogy to provide Shareholders and potential
investors with additional information regarding the Company’s liquidity and its
ability to generate funds to finance its operations. However, given their lack
of standardized meaning, such measurements are unlikely to be comparable to
similar measures presented by other issuers.

“Adjusted EBITDA” refers to “Funds flow from operations” plus cash interest,
tax expenses, certain other items (accrued cash remuneration costs for its
employees – deducted from EBITDA when paid) that do not appear individually in
the line items of the Company’s financial statements, in addition to pro- forma
adjustments for properties acquired or disposed of in the period and the
exclusion of revenues or losses of an extraordinary and non-recurring nature.

“Consolidated debt” generally includes all long-term debt plus any issued and
undrawn letters of credit, less any cash held.

“Finding and development costs” refers to all capital expenditures and costs of
acquisitions, excluding expenditures where the related assets were disposed of
by the end of the year, and including changes in future development capital on
a total proved or total proved plus probable basis. “Finding and development
costs per Barrel of oil equivalent” (“F&D $/Boe”) is calculated by dividing
finding and development costs by the current year’s reserve extensions,
discoveries and revisions on a total proved or total proved plus probable
reserve basis. Management uses finding and development costs as a measure to
assess the performance of the Company’s resources required to locate and
extract new hydrocarbon reservoirs.

“Funds flow from operations” refers to the cash flow from operating activities
before net changes in operating working capital as shown in the consolidated
statements of cash flows. Management utilizes funds flow from operations as a
key measure to assess the ability of the Company to finance dividends,
operating activities, capital expenditures and debt repayments.

“Operating income” is equal to petroleum and natural gas sales before financial
instruments and bad debt expenses minus royalties, operating charges, and
transportation costs. Management uses this metric to measure the discrete
operating results of its oil and gas properties.

“Operating netback” refers to operating income plus realized financial
instrument gains and losses and other income minus actual decommissioning,
restoration, and remediation costs incurred. Operating netback provides
management with a more fulsome metric on its oil and gas properties considering
strategic decisions (for example, hedging programs) and associated full life
cycle charges.

“Net debt” is calculated as current liabilities minus current assets therein
plus long-term debt. Management utilizes net debt as a key measure to assess
the liquidity of the Company.

“Recycle ratio” is equal to “Operating netback” on a production barrel of oil
equivalent for the year divided by “F&D $/Boe” (computed on a total proved or
total proved plus probable reserve basis as applicable). Management uses this
metric to measure the profitability of the Company in turning a barrel of
reserves into a barrel of production.

“Senior debt” is generally defined as “Consolidated debt” but excluding any
indebtedness under the Senior Unsecured Notes.

Investors are cautioned that the Non-GAAP measures should not be considered in
isolation or construed as alternatives to their most directly comparable
measure calculated in accordance with IFRS, as set forth above, or other
measures of financial performance calculated in accordance with IFRS.

Forward-Looking Information

Certain statements included in this document (including this MD&A and the
Operations Update) constitute forward- looking statements under applicable
securities legislation. Forward-looking statements or information typically
contain statements with words such as “anticipate”, “believe”, “expect”,
“plan”, “intend”, “estimate”, “propose”, “budget”, “goal”, “objective”,
“possible”, “probable”, “projected”, “scheduled”, or state that certain
actions, events or results “may”, “could”, “should”, “would”, “might” or “will”
be taken, occur or be achieved, or similar words suggesting future outcomes or
statements regarding an outlook. Forward-looking statements or information in
this document include but are not limited to statements regarding:

/T/

— the proposed merger with Paramount and the timing and expected results

thereof;
— business strategy and objectives for 2017 and beyond;
— drilling, completion and infrastructure plans for the Company’s Kaybob
Montney oil and gas assets and Duvernay play, among others, and the
timing, cost payout and other anticipated benefits thereof;
— forecast 2017 annual production levels, the relative content of natural
gas liquids therein and the expected impact of the second quarter asset
dispositions;
— planned 2017 capital expenditures, the allocation and timing thereof and
Trilogy’s intention to execute its capital budget within annual funds
flow from operations;
— operating, finding and development, decommissioning, asset retirement,
restoration and other costs and the anticipated results of Trilogy’s
operational efficiencies and cost cutting measures;
— anticipated funds flow from operations and other measures of profit,
— expectations regarding future commodity prices for crude oil, natural
gas, NGLs and related products and the potential impact to Trilogy of
commodity price fluctuations;
— Trilogy’s capacity under its credit facilities;
— projected results of hedging contracts and other financial instruments;
and
— other expectations, beliefs, plans, goals, objectives, assumptions,
information and statements about possible future events, conditions, and
results of operations or performance.

/T/

Statements regarding “reserves” are forward-looking statements, as they involve
the implied assessment, based on certain estimates and assumptions, that the
reserves described exist in the quantities predicted or estimated, and can be
profitably produced in the future.

Such forward-looking statements or information are based on a number of
assumptions which may prove to be incorrect. In addition to other assumptions
identified in this document, assumptions have been made regarding, among other
things:

/T/

— the likelihood that all necessary shareholder and other approvals will

be obtained and all conditions will be satisfied in order for the
proposed merger with Paramount to proceed as proposed;
— future crude oil, natural gas, condensate, NGLs and other commodity
pricing and supply;
— funds flow from operations and cash flow consistent with expectations;
— current reserves estimates;
— credit facility availability and access to sources of funding for
Trilogy’s planned operations and expenditures;
— the ability of Trilogy to service and repay its debt when due;
— current production forecasts and the relative mix of crude oil, natural
gas and NGLs therein;
— geology applicable to Trilogy’s land holdings;
— the extent and development potential of Trilogy’s assets (including,
without limitation, Trilogy’s Kaybob area Montney oil and gas assets and
the Duvernay Shale play, among others);
— the ability of Trilogy and its industry partners to obtain drilling and
operational results, improvements and efficiencies consistent with
expectations (including in respect of anticipated production volumes,
reserves additions and NGL yields);
— well economics;
— decline rates;
— foreign currency, exchange and interest rates;
— royalty rates, taxes and capital, operating, general & administrative
and other costs and expenses;
— assumptions regarding royalties and expenses and the applicability and
continuity of royalty regimes and government incentive programs to
Trilogy’s operations;
— general business, economic, industry and market conditions;
— projected capital investment levels and the successful and timely
implementation of capital projects;
— anticipated timelines and budgets being met in respect of drilling
programs and other operations;
— the ability of Trilogy to obtain equipment, services, supplies and
personnel in a timely manner and at an acceptable cost to carry out its
evaluations and activities;
— the ability of Trilogy to secure adequate product processing,
transportation, fractionation and storage capacity on acceptable terms
or at all and assumptions regarding the timing and costs of run-times,
outages and turnarounds;
— the ability of Trilogy to market its oil, natural gas, condensate, other
NGLs and other products successfully to current and new customers;
— expectation that counterparties will fulfill their obligations under
operating, processing, marketing and midstream agreements;
— the timely receipt of required regulatory approvals;
— the continuation of assumed tax regimes, estimates and projections in
respect of the application of tax laws and estimates of deferred tax
amounts, tax assets and tax pools;
— the extent of Trilogy’s liabilities; and
— assumptions used in calculating the provisions made for the cost of the
Kaybob North Montney pipeline release and the third party prior year
production reallocations.

/T/

Although Trilogy believes that the expectations reflected in such
forward-looking statements or information are reasonable, undue reliance should
not be placed on forward-looking statements because Trilogy can give no
assurance that such expectations will prove to be correct. Forward-looking
statements or information are based on current expectations, estimates and
projections that involve a number of risks and uncertainties which could cause
actual results to differ materially from those anticipated by Trilogy and
described in the forward-looking statements or information. These risks and
uncertainties include but are not limited to:

/T/

— the risk that the proposed merger with Paramount will not proceed as

proposed or within the expected timing thereof as a result of not
obtaining the requisite shareholder or other approvals or due to other
conditions not being satisfied;
— fluctuations in crude oil, natural gas, condensate and other natural gas
liquids and commodity prices;
— the ability to generate sufficient funds flow from operations and obtain
financing on acceptable terms to fund planned exploration, development,
construction and operational activities and to meet current and future
obligations;
— the possibility that Trilogy will not commercially develop its Duvernay
shale assets in the near future or at all;
— uncertainties as to the availability and cost of financing;
— Trilogy’s ability to satisfy maintenance covenants within its credit and
debt arrangements;
— the risk and effect of a downgrade in Trilogy’s credit rating;
— fluctuations in foreign currency, exchange rates and interest rates;
— the risks of the oil and gas industry, such as operational risks in
exploring for, developing and producing crude oil, natural gas,
condensate and other natural gas liquids, and market demand;
— risks and uncertainties involving the geology of oil and gas;
— the uncertainty of reserves estimates and reserves life;
— the uncertainty of estimates and projections relating to future
production and NGL yields as well as costs and expenses;
— the ability of Trilogy to add production and reserves through
development and exploration activities and acquisitions;
— Trilogy’s ability to secure adequate product processing, transmission,
transportation, fractionation and storage capacity on acceptable terms
and on a timely basis or at all;
— potential disruptions or unexpected technical difficulties in designing,
developing, or operating new, expanded, or existing pipelines or
facilities (including third party operated pipelines and facilities);
— risks inherent in Trilogy’s marketing operations, including credit and
other financing risks and the risk that Trilogy may not be able to enter
into arrangements for the sale of its sales volumes;
— volatile business, economic and market conditions;
— general risks related to strategic and capital allocation decisions,
including potential delays or changes in plans with respect to
exploration or development projects or capital expenditures and
Trilogy’s ability to react to same;
— availability of equipment, goods, services and personnel in a timely
manner and at an acceptable cost;
— health, safety, security and environmental risks;
— the timing and cost of future abandonment and reclamation obligations
and potential liabilities for environmental damage and contamination;
— risks and costs associated with environmental, regulatory and
compliance, including those potentially associated with hydraulic
fracturing, greenhouse gases and “climate change” and the cost to
Trilogy in order to comply with same;
— weather conditions;
— the possibility that government policies, regulations or laws may
change, including risks related to the imposition of moratoriums;
— the possibility that regulatory approvals may be delayed or withheld;
— risks associated with Trilogy’s ability to enter into and maintain
leases and licenses;
— uncertainty with regard to royalty payments and the applicability of and
changes to royalty regimes and incentive programs including, without
limitation, applicable royalty incentive regimes and the Modernized
Royalty Framework, the Emerging Resources Program and the Enhanced
Hydrocarbon Recovery Program, among others;
— imprecision in estimates of product sales, commodity prices, capital
expenditures, tax pools, tax deductions available to Trilogy, changes to
and the interpretation of tax legislation and regulations;
— uncertainty regarding results of objections to Trilogy’s exploration and
development plans by third party industry participants, aboriginal and
local populations and other stakeholders;
— risks associated with existing and potential lawsuits, regulatory
actions, audits and assessments;
— changes in land values paid by industry;
— risks associated with Trilogy’s mitigation strategies including
insurance and hedging activities;
— risks related to the actions and financial circumstances of Trilogy
agents and contractors, counterparties and joint venture partners,
including renegotiation of contracts;
— risks relating to cybersecurity, vandalism, and terrorism;
— the ability of management to execute its business plan;
— the risk that the assumptions used by Management to estimate the
provision for the costs resulting from the recent Kaybob North Montney
pipeline release and the third party prior year production reallocation
prove to be incorrect; and
— other risks and uncertainties described elsewhere in this document and
in Trilogy’s other filings with Canadian securities authorities,
including its Annual Information Form.

/T/

The foregoing lists are not exhaustive. Additional information on these and
other factors which could affect the Company’s operations or financial results
are included in the Company’s most recent Annual Information Form and in other
documents on file with the Canadian Securities regulatory authorities. The
forward-looking statements or information contained in this document are made
as of the date hereof and Trilogy undertakes no obligation to update publicly
or revise any forward-looking statements or information, whether as a result of
new information, future events or otherwise, unless so required by applicable
securities laws.

Oil and Gas Advisory

This document contains disclosure expressed as “Boe”, “MBoe”, “Boe/d”, “Mcf”,
“Mcf/d”, “MMcf”, “MMcf/d”, “Bcf”, “Bbl”, and “Bbl/d”. All oil and natural gas
equivalency volumes have been derived using the ratio of six thousand cubic
feet of natural gas to one barrel of oil (6:1). Equivalency measures may be
misleading, particularly if used in isolation. A conversion ratio of six
thousand cubic feet of natural gas to one barrel of oil is based on an energy
equivalency conversion method primarily applicable at the burner tip and does
not represent a value equivalency at the well head. For Q2 2017, the ratio
between Trilogy’s average realized oil price and the average realized natural
gas price was approximately 20:1 (“Value Ratio”). The Value Ratio is obtained
using the Q2 2017 average realized oil price of $58.13 (CAD$/Bbl) and the Q2
2017 average realized natural gas price of $2.98 (CAD$/Mcf). This Value Ratio
is significantly different from the energy equivalency ratio of 6:1 and using a
6:1 ratio would be misleading as an indication of value.

– END RELEASE – 02/08/2017

For further information:
J.H.T. (Jim) Riddell, Chief Executive Officer
J.B. (John) Williams, President and Chief Operating Officer
M.G. (Michael) Kohut, Chief Financial Officer
OR
Trilogy Energy Corp.
1400 – 332 – 6th Avenue S.W.
Calgary, Alberta T2P 0B2
Phone: (403) 290-2900
Fax: (403) 263-8915

COMPANY:
FOR: TRILOGY ENERGY CORP.
TSX SYMBOL: TET

INDUSTRY: Energy and Utilities – Oil and Gas
RELEASE ID: 20170802CC0061

Press Release from Marketwired 1-866-736-3779

Crew Energy Inc. Announces Second Quarter 2017 Financial and Operating Results

August 2, 2017 by The Canadian Press

FOR: CREW ENERGY INC.
TSX SYMBOL: CR

Date issue: August 02, 2017
Time in: 5:05 PM e

Attention:

CALGARY, ALBERTA–(Marketwired – Aug. 2, 2017) – Crew Energy Inc. (TSX:CR)
(“Crew” or the “Company”) is pleased to announce our operating and financial
results for the three and six month periods ended June 30, 2017. Our Financial
Statements and Notes, as well as Management’s Discussion and Analysis (“MD&A”)
for the three and six month periods ended June 30, 2017 are available on Crew’s
website and filed on SEDAR.

Q2 HIGHLIGHTS

/T/

— Production for the quarter averaged 20,468 boe per day, reflecting the

impact of several planned and unplanned third party pipeline and
facility outages which affected our core northeast British Columbia (“NE
BC”) operating areas by approximately 1,500 boe per day for the quarter.
With the resumption of service, our current production is at a
restricted average of approximately 24,500 boe per day.

— Funds from operations totaled $21.4 million in the second quarter, a 33%

increase over the same period in 2016 ($0.14 per fully diluted share),
largely due to improved pricing and offset by higher royalties and a
decrease in realized hedging gains.

— Improved product pricing year over year combined with a continued focus

on cost reductions contributed to operating netbacks (including hedging)
of $15.93 per boe, a 38% improvement over the same period in 2016.

— Net exploration and development expenditures totaled $36.7 million for

the quarter, slightly above previous forecasts of $25 to $35 million,
reflecting Crew’s ability to restart three drilling rigs and two frac
spreads sooner than anticipated after break up.

— Crew drilled six (6.0 net) Montney wells and completed nine (9.0 net)

wells at our liquids-rich Greater Septimus area during the second
quarter, and combined with early third quarter activity, have resulted
in an inventory of 17 drilled and uncompleted wells and eight wells in
various stages of completion and tie-in.

— Five wells on an infill pad at Septimus, which was originally developed

between 2009 and 2012 with low well density spacing and dated completion
practices, were completed during the second quarter. After one week of
production, the wells were flowing at a combined rate of 32.6 mmcf per
day at an average flowing casing pressure of 1,550 psi.

— Ongoing site work to double the capacity of our West Septimus facility

to 120 mmcf per day continued during the quarter and remains on
schedule, with a target on-stream date in fourth quarter, 2017.

— A successful $49.1 million disposition of non-core assets in the Goose

area of NE BC further strengthened our financial position, with no
impact on production or assigned reserves, and contributed to Crew’s
strong balance sheet at the end of the second quarter, which includes
$28.1 million in cash and an undrawn $235 million bank facility.

/T/

FINANCIAL & OPERATING HIGHLIGHTS:

/T/

—————————————————————————-
—————————————————————————-

Three Three Six Six
months months months months
FINANCIAL ended ended ended ended
($ thousands, except per share June 30, June 30, June 30, June 30,
amounts) 2017 2016 2017 2016
—————————————————————————-
Petroleum and natural gas sales 48,886 36,232 106,184 72,575
Funds from operations(1) 21,353 16,048 49,072 27,762
Per share
– basic 0.14 0.11 0.33 0.20
– diluted 0.14 0.11 0.32 0.19
Net income /(loss) 21,880 (16,815) 29,936 (23,610)
Per share
– basic 0.15 (0.12) 0.20 (0.17)
– diluted 0.14 (0.12) 0.20 (0.17)

Exploration and Development
expenditures 36,656 15,096 111,820 32,859
Property acquisitions (net of
dispositions) (45,701) 16 (46,053) 972
——————————————-
Net capital expenditures (9,045) 15,112 65,767 33,831

—————————————————————————-
—————————————————————————-

As at As at
Capital Structure June 30, Dec. 31,
($ thousands) 2017 2016
—————————————————————————-
Working capital (surplus)/deficiency(2) (18,831) 10,006
Bank loan – 88,036
————————-
(18,831) 98,042
Senior Unsecured Notes 293,296 147,329
————————-
Total Net Debt 274,465 245,371
Current Debt Capacity(3) 535,000 385,000
Common Shares Outstanding (thousands) 148,910 146,812
—————————————————————————-
—————————————————————————-
Notes:
(1) Funds from operations is calculated as cash provided by operating
activities, adding the change in non-cash working capital,
decommissioning obligation expenditures and accretion of deferred
financing costs. Funds from operations is used to analyze the Company’s
operating performance and leverage. Funds from operations does not have
a standardized measure prescribed by International Financial Reporting
Standards and therefore may not be comparable with the calculations of
similar measures for other companies. See “Non-IFRS Measures” contained
within Crew’s MD&A.
(2) Working capital (surplus) / deficiency includes cash and cash
equivalents plus accounts receivable less accounts payable and accrued
liabilities.
(3) Current Debt Capacity reflects the bank facility of $235 million plus
$300 million in senior unsecured notes outstanding.

—————————————————————————-
—————————————————————————-

Three Three
months months Six months Six months
ended ended ended ended
June 30, June 30, June 30, June 30,
Operations 2017 2016 2017 2016
—————————————————————————-
Daily production
Light crude oil (bbl/d) 499 285 514 294
Heavy crude oil (bbl/d) 1,778 2,362 1,817 2,580
Natural gas liquids (bbl/d) 2,886 3,015 3,123 3,187
Natural gas (mcf/d) 91,828 97,726 98,321 100,975
———————————————–
Total (boe/d @ 6:1) 20,468 21,950 21,841 22,890
Average prices (1)
Light crude oil ($/bbl) 58.14 48.33 58.96 42.67
Heavy crude oil ($/bbl) 45.05 37.47 43.98 28.24
Natural gas liquids ($/bbl) 38.66 35.12 42.43 30.29
Natural gas ($/mcf) 3.45 1.94 3.50 2.15
Oil equivalent ($/boe) 26.25 18.14 26.86 17.42
—————————————————————————-
Notes:
(1) Average prices are before deduction of transportation costs and do not
include gains and losses on financial instruments.

—————————————————————————-

Three Three
months months Six months Six months
ended ended ended ended
June 30, June 30, June 30, June 30,
2017 2016 2017 2016
—————————————————————————-
Netback ($/boe)
Revenue 26.25 18.14 26.86 17.42
Royalties (2.06) (1.02) (2.12) (0.95)
Realized commodity hedging
gain 0.64 2.83 0.10 2.51
Operating costs (6.15) (6.04) (5.74) (6.25)
Transportation costs (2.75) (2.38) (2.51) (2.44)
———————————————–
Operating netback (1) 15.93 11.53 16.59 10.29
G&A (1.52) (1.28) (1.51) (1.53)
Interest on long-term debt (2.93) (2.22) (2.66) (2.10)
———————————————–
Funds from operations 11.48 8.03 12.42 6.66

Drilling Activity

Gross wells 7 1 22 5
Working interest wells 7.0 1.0 22.0 5.0
Success rate, net wells (%) 100% 100% 95% 100%
—————————————————————————-
—————————————————————————-
Notes:
(1) Operating netback equals petroleum and natural gas sales including
realized hedging gains and losses on commodity contracts less
royalties, operating costs and transportation costs calculated on a boe
basis. Operating netback and funds from operations netback do not have
a standardized measure prescribed by International Financial Reporting
Standards and therefore may not be comparable with the calculations of
similar measures for other companies. See “Non-IFRS Measures” contained
within Crew’s MD&A.

/T/

OVERVIEW

The second quarter of 2017 presented several challenges as exceptionally wet
weather conditions in NE BC led to our three drilling rigs being shut down
through break up and several extended planned and unplanned third party
facility and pipeline outages impacted production. Despite these challenges, we
continued to execute our strategy with the majority of our efforts directed to
the West Septimus facility expansion, as well as late quarter drilling and
completion activity at Greater Septimus. The facility expansion to 120 mmcf per
day is currently on schedule and we anticipate the plant will be on-stream in
the fourth quarter of 2017. We also strengthened our balance sheet with a
non-core asset disposition of $49.1 million, which had no impact on production
or reserves, and supports ongoing financial flexibility to withstand
longer-term uncertainty in commodity prices.

We achieved second quarter production volumes of 20,468 boe per day, which is
the mid-point of our original quarterly guidance of 20,000 to 21,000 boe per
day, and demonstrates the benefits of Crew’s infrastructure network, infield
logistics and marketing strategy. The Company’s connectivity to multiple
pipelines proved beneficial as NE BC operators were subject to numerous
scheduled and unscheduled third party plant and pipeline outages in June which
restricted product movement to sales points. Crew’s access to egress, coupled
with our active marketing strategy, enabled the Company to successfully divert
a portion of our volumes and mitigate some of the market access issues.

FINANCIAL

Funds from operations in the second quarter of 2017 totaled $21.4 million, a
33% increase over the same period in 2016 reflecting improved commodity prices
partially offset by lower realized hedging gains. Netbacks during the quarter
were impacted by higher per unit costs than realized in recent quarters. This
was the result of fixed costs, including take-or-pay transportation and
processing charges that were incurred while production was shut-in due to third
party outages. In the third quarter of 2017, the Company’s costs per unit are
expected to return to levels consistent with those realized in previous
quarters.

Realized commodity prices improved across the board compared to those received
in the second quarter of 2016. The Company’s realized prices for its liquids
products continued to reflect a stronger world oil market bolstered in the
first half of 2017 by OPEC production curtailments. Crew’s light crude, heavy
crude and natural gas liquids prices in the second quarter of 2017 realized a
20%, 20% and 10% increase, respectively, over the same period in 2016. Crew’s
realized second quarter natural gas prices increased 78% compared to the second
quarter of 2016. This is consistent with the increase in natural gas prices
across North America which benefited from supportive weather in the latter half
of 2016 as well as natural gas supply reductions stemming from lower industry
investment in natural gas drilling.

Second quarter 2017 exploration and development expenditures totaled $36.7
million, at the high end of our guidance as improved weather conditions in late
May enabled Crew to accelerate work. The majority of our capital was directed
to drilling and completions activities, including drilling six (6.0 net) and
completing nine (9.0 net) Montney wells, drilling one (1.0 net) and completing
two (2.0 net) heavy oil wells and recompleting five (4.5 net) heavy oil wells
at Lloydminster. Work continued on the expansion of our West Septimus facility
from 60 mmcf per day to 120 mmcf per day during the quarter. The Company
confirmed the participation of one of our working interest partners in the West
Septimus facility expansion, who will participate for 72% of the costs. As
forecasted, net second quarter facility expenditures reflect the recovery of
costs incurred in prior quarters due to our partner’s participation in the
expansion. The Company also acquired 11.9 sections of surface rights at
Groundbirch for the planned construction of a gas plant and associated future
Montney well development for $3.8 million.

As a result of the disposition of the non-core Goose asset for $49.1 million,
Crew’s total net debt at the end of the quarter was $274.5 million, which
includes cash on our balance sheet, a working capital surplus and our new $300
million ($293.3 million net of deferred financing costs) 6.5% senior unsecured
notes that have a seven year term with repayment due in March of 2024.

During the quarter the Company commenced a Normal Course Issuer Bid (“NCIB”).
Under the NCIB, Crew may purchase for cancellation, from time to time as the
Company considers advisable, up to a maximum of 7.5 million common shares. Crew
purchased, cancelled and removed from share capital a total of 924,100 common
shares during the second quarter at a total cost of $3.3 million for an average
price of $3.51 per share.

TRANSPORTATION, MARKETING & HEDGING

Crew’s natural gas sales portfolio mix for the second quarter was consistent
with the previous quarter allocation with approximately 45% to Chicago City
Gate, 26% to AECO, 19% to Alliance ATP and 10% to Station 2, and is expected to
remain consistent through Q3. This diversity of markets will help to mitigate
the impact of discounted Canadian pricing that is expected to occur throughout
the summer as a result of various maintenance outages planned on the three
major Canadian egress pipeline systems.

As part of our longer term growth strategy, Crew will continue to plan for
processing and transportation diversification for natural gas from our Greater
Septimus and Groundbirch areas. In April of 2018, we have secured 60 mmcf per
day of firm service capacity on the TransCanada pipeline system (“TCPL”),
uniquely positioning Crew with access to triple-connectivity to all three major
pipeline systems and optimal market diversification. In mid-2019, we have also
secured an additional 60 mmcf per day of firm capacity on the TCPL system.

The Company’s marketing team continues to monitor commodities futures markets
with the view to adding to the hedge position when pricing is conducive to
maintaining attractive economics. For the balance of 2017, Crew’s total natural
gas hedged position is approximately 50% of our forecast 2017 gas sales at a
transportation-adjusted equivalent price of $2.92 per gj, which when adjusting
for the higher heat content of Crew’s gas, equates to $3.62 per mcf. For
liquids, we have approximately 50% of our 2017 light oil and natural gas
liquids sales hedged at an average price of CDN$68.17 per bbl.

OPERATIONS

NE BC Montney – Greater Septimus Overview

During the second quarter, Crew invested $31.2 million in drilling and
completions at Greater Septimus, and was able to resume field activities
earlier than anticipated. Crew restarted our three drilling rigs in early June,
which resulted in the drilling of five (5.0 net) Montney wells at Greater
Septimus before the end of the quarter. Although we experienced completion
delays through most of the first half of 2017, we were able to access two frac
spreads and successfully completed nine (9.0 net) Montney wells at Greater
Septimus. Combined with early third quarter activity, the completion backlog
that resulted from wet field conditions and service shortages earlier in the
year has been eliminated.

Crew has incurred net expenditures of $11 million for the expansion of our West
Septimus facility from 60 to 120 mmcf per day. Progress continues with the
delivery of major equipment currently underway. In conjunction with the West
Septimus facility buildout and expansion, Crew’s drilling and completions focus
has been directed to this area over the past 12 to 18 months. During this time,
we have evolved our completions from 20 to 30 stages with a sand loading of 0.5
to 0.8 tonnes per metre to 30 to 46 stages with 1.0 to 2.0 tonnes per metre.
Four key wells that were completed late in the quarter at our West Septimus
15-9 pad were brought on production in July and were producing approximately
28.0 mmcf per day in aggregate after two weeks of flow. This initial result is
very positive for Crew’s western and southern Greater Septimus acreage, and we
will provide further updates on these wells in our third quarter release.

Crew has many areas within our original Septimus field that were developed up
to eight years ago with low well density spacing and dated completion
practices. This presents an excellent opportunity to assess the potential for
incremental recovery associated with improving technology while enhancing rates
of return through lower well costs and our ability to use existing
infrastructure. During the second quarter, we completed five wells at a
Septimus pad. These wells were interspersed among wells that were originally
completed from 2009 to 2012 and have benefitted from the enhanced completion
technology, demonstrating a 52% improvement in the cumulative volume relative
to the earlier wells over the same flow period with 34% higher average flowing
pressures. After one week of production, the wells were flowing at a combined
rate of 32.6 mmcf per day at an average flowing casing pressure of 1,550 psi.
We will continue to evaluate the long term productivity of these wells for
potential application of further infill drilling in areas that were thought to
be partially depleted.

Greater Septimus

/T/

—————————————————————————-
—————————————————————————-

Q2 Q1 Q4 Q3 Q2
Production & Drilling 2017 2017 2016 2016 2016
—————————————————————————-
Average daily production
(boe/d) 15,558 17,440 17,307 18,592 17,131
Wells drilled (gross /
net) 5 / 5.0 10 / 10.0 8 / 7.7 8 / 7.0 –
Wells completed (gross /
net) 9 / 9.0 3 / 3.0 5 / 4.0 7 / 7.0 7 / 6.3
—————————————————————————-

—————————————————————————-
—————————————————————————-
Operating Netback Q2 Q1 Q4 Q3 Q2
($ per boe) 2017 2017 2016 2016 2016
—————————————————————————-
Revenue 24.51 26.49 25.10 20.56 16.06
Royalties (1.57) (1.66) (1.47) (0.94) (0.69)
Realized commodity hedge
gain / (loss) 0.77 (0.41) (0.39) 1.11 3.24
Operating costs (4.10) (3.34) (3.34) (3.61) (4.02)
Transportation costs (2.03) (1.67) (1.68) (1.59) (1.97)
—————————————————————————-
Operating netback 17.58 19.41 18.22 15.53 12.62
—————————————————————————-

/T/

Our Greater Septimus operations were impacted during the second quarter by a
combination of planned and unplanned outages on third party systems. An
unplanned force majeure outage on the Alliance pipeline caused Crew’s Montney
production (approximately 18,000 boe per day) to be shut-in for four days. In
addition, a planned 21 day outage on the Enbridge system was extended to 40
days which impacted approximately 2,500 boe per day for the last 26 days of the
second quarter and two weeks into the third quarter. The combined impact of
these outages was a reduction of Crew’s average second quarter production by
approximately 1,500 boe per day. Our current corporate production is at a
restricted average of approximately 24,500 boe per day, approximately 20%
higher than our second quarter average. The Company is currently restricting
flow in NE BC as a result of unfavourable pricing caused by pipeline
restrictions in Alberta and forest fires in BC.

NE BC Montney – Groundbirch Overview

Crew has drilled two delineation wells at Groundbirch, one in the first quarter
and one in the second quarter, targeting two specific stratigraphic intervals
within the Upper Montney that were not tested in the original two wells drilled
in the area in 2014. These wells are being completed and we expect to have test
results by our third quarter release in early November. We continue to be
encouraged by the production performance and high natural gas liquids rates
from the first two wells drilled in the area, particularly the initial
condensate ratios of 25 to 35 bbls per mmcf.

NE BC Montney – Tower Overview

Crew’s Montney Tower area continues to represent a significant future
development opportunity for the Company and has torque to crude oil prices. Our
Tower oil production was 105% higher than the second quarter of 2016 and
declined slightly through the second quarter to 481 bbls per day compared to
493 bbls per day in the previous quarter, as a number of wells were shut in
awaiting the installation of gas lift. Infrastructure to accommodate gas lift
is being installed at Tower and is expected to result in production
improvements once fully implemented. The Company is currently installing the
final pipeline segment and would expect the system to be operational in the
third quarter.

Lloydminster, AB/SK Overview

At Lloydminster, we drilled our second dual lateral horizontal oil well at the
Company’s Swimming area and completed both wells during the second quarter. The
wells were placed on production in June and are each currently producing
approximately 100 bbls per day. We also recompleted five (4.5 net) oil wells
during the period. Crew intends to continue to invest minor amounts of capital
in order to maintain the asset value of our Lloydminster heavy oil property as
part of our ongoing disposition process.

OUTLOOK

Crew will continue to strategically develop and delineate our greater than 16
Billion boe of Total Petroleum Initially In Place (“TPIIP”) resource on over
280,000 net acres of Montney rights in NE BC. We are solely focused on the
efficient and cost effective execution of our capital program which is
currently in full gear. Since the beginning of 2017, Crew has had up to three
drilling rigs running with two rigs currently in operation and one to two frac
spreads operating when required. Our West Septimus plant expansion to take
productive capacity to 120 mmcf per day from its current 60 mmcf per day is on
budget and on schedule. The majority of the components are on site and a full
complement of personnel are completing the installation. At our current pace of
drilling, Crew will add four new wells per month to our inventory. This
elevated level of activity has led to a current inventory of 17 drilled and
uncompleted wells and eight wells in various stages of completion and tie-in.

With the successful disposition of our Goose asset for $49.1 million during the
second quarter, and our recent $300 million high yield note placement, Crew has
successfully managed our balance sheet with $28.1 million of available cash at
the end of the second quarter and an undrawn $235 million credit facility.
These actions have aligned our long term growth plans with our capital
structure, affording Crew the financial flexibility to execute our capital
program.

Our Septimus line loop will be completed this year at a projected cost of $13
million. After taking into account this expenditure combined with the capital
required to maintain the plant at or near capacity with six wells, Septimus is
expected to generate free cash flow in 2017 as it did in 2016. Our business
model is simple: replicate what we have accomplished at Septimus five
additional times over the next three years providing commodity prices are
supportive. We expect West Septimus to provide free cash flow in 2019 based on
initial forecasts.

A key component of Crew’s ability to optimize our free cash flow for the long
term is the strategic location of our asset base providing access to the three
major export pipelines in Canada. We have plans to invest approximately $55
million through 2018 to install 43 kilometers of interconnecting pipelines that
will complete our physical connection to these export pipelines, and will allow
for movement of natural gas and natural gas liquids between our operating areas
completing the first phase of Crew’s vision of a diverse marketing platform.
The combination of a physical connection, access to greater and flexible
downstream market options, our ongoing commitment to improving capital
efficiencies and a demonstrated willingness to take advantage of value creating
opportunities within our large land base will ensure Crew has the optimum
flexibility to manage through the current commodity cycle.

Our guidance for 2017 remains unchanged with average production of 24,000 to
26,000 boe per day and a forecast year end exit rate over 31,000 boe per day.
Crew is currently focused on proceeding with the infrastructure build-out and
the drilling of our wells in inventory to support our growth plan as these key
elements require the longest lead time. We expect third quarter production of
24,500 to 26,500 which reflects the loss of 410 boe per day for the quarter
from the extension of the McMahon gas plant turnaround for 14 days into July,
and fourth quarter production of 29,500 to 31,500 boe per day. Crew is
currently monitoring projected activity and pricing levels for the first
quarter of 2018 and will flex our activity levels and capital as appropriate to
mitigate service supply constraints and cost inflation experienced in the first
quarter of 2017.

We would like to thank our employees and Board of Directors for their
commitment to Crew, and our shareholders for their ongoing support.

A summary of Crew’s operational and financial highlights are as follows:

/T/

—————————————————————————-
2017 average production(1) 24,000 – 26,000 boe/d
—————————————————————————-
2017 exit production(1) greater than 31,000 boe/d
—————————————————————————-
Total proved + probable reserves(2) 324 MMboe
—————————————————————————-
Total proved + probable BT NPV10(2) $2 billion
—————————————————————————-
Resource TPIIP(3) 112.2 TCFE
—————————————————————————-
Montney potential drilling locations(4) 5,782
—————————————————————————-
2017 capital program(1) $200 MM
—————————————————————————-
Net debt(5) $274.5 MM
—————————————————————————-
Exit 2017 net debt / funds from 2.1 x
operations(1)
—————————————————————————-
Basic shares outstanding(5) 148.9 MM
—————————————————————————-
Tax pools(5) approx. $1 billion
—————————————————————————-
(1) Forecast. See “Forward Looking Information and Statements”.
(2) Reserves included herein are stated on a company gross basis (working
interest before deduction of royalties without including any royalty
interests). Information presented herein in respect of reserves and
related information is based on our independent reserves evaluation
(the “Sproule Report”) for the year ended December 31, 2016 prepared by
Sproule Associates Limited (“Sproule”) details of which were provided
in our press release issued on February 9, 2017 and are contained in
our Annual Information Form filed on SEDAR.
(3) As per Crew’s independent Resource Evaluation as at December 31, 2016
prepared by Sproule in accordance with the NI 51-101 and current COGE
Handbook guidelines, the details of which were provided in our press
release issued on May 8, 2017.
(4) Estimated potential drilling locations are the total number of risked
Contingent (2,071) and Prospective (3,355) resource locations as
identified in Crew’s year end independent Resource Evaluation, plus the
2P booked locations (356) as identified in the Sproule Report, both of
which were prepared in accordance with the COGE Handbook provisions and
NI 51-101.
(5) As at June 30, 2017.

/T/

Cautionary Statements

Information Regarding Disclosure on Oil and Gas Reserves, Resources and
Operational Information

All amounts in this news release are stated in Canadian dollars unless
otherwise specified. Throughout this press release, the terms Boe (barrels of
oil equivalent) and Mmboe (millions of barrels of oil equivalent), are used.
Such terms when used in isolation, may be misleading. Where applicable, natural
gas has been converted to barrels of oil equivalent (“BOE”) based on 6 Mcf:1
BOE and oil and liquids have been converted to natural gas equivalent on the
basis of 1 bbl:6 mcfe. The BOE rate is based on an energy equivalent conversion
method primarily applicable at the burner tip, and given that the value ratio
based on the current price of crude oil as compared to natural gas is
significantly different than the energy equivalency of the 6:1 conversion
ratio, utilizing the 6:1 conversion ratio may be misleading as an indication of
value. The BOE rate is based on an energy equivalent conversion method
primarily applicable at the burner tip and does not represent a value
equivalent at the wellhead. In accordance with Canadian practice, production
volumes and revenues are reported on a company gross basis, before deduction of
Crown and other royalties and without including any royalty interest, unless
otherwise stated. Unless otherwise specified, all reserves volumes in this news
release (and all information derived therefrom) are based on “company gross
reserves” using forecast prices and costs. Our oil and gas reserves statement
for the year-ended December 31, 2016 includes complete disclosure of our oil
and gas reserves and other oil and gas information in accordance with NI
51-101, and is contained within our Annual Information Form which is available
on our SEDAR profile at www.sedar.com.

This press release contains metrics commonly used in the oil and natural gas
industry, such as “funds from operations” and “operating netback”. Such terms
do not have a standardized meaning and may not be comparable to similar
measures presented by other companies, and therefore should not be used to make
such comparisons. These metrics do not have standardized meanings and may not
be comparable to similar measures presented by other companies. As such, they
should not be used to make comparisons. Management uses these oil and gas
metrics for its own performance measurements and to provide shareholders with
measures to compare Crew’s performance over time, however, such measures are
not reliable indicators of Crew’s future performance and future performance may
not compare to the performance in previous periods.

This new release contains references to estimates of oil and gas classified as
Total Petroleum Initially In Place (“TPIIP”) in Crew’s Montney region in
northeast British Columbia which are not, and should not, be confused with, oil
and gas reserves. Such estimates are based upon an independent resource
evaluation effective as at December 31, 2016, prepared for Crew in accordance
with the Canadian Oil & Gas Evaluation Handbook, complete details of which
evaluation were set forth in Crew’s previously disseminated press release dated
May 8, 2017 (the “Resource Report Press Release”). Such resource estimates are
broken into the requisite categories and are subject to a number of cautionary
statements, assumptions, risks, positive and negative factors relative to the
estimates and contingencies, all of which details are set forth in the Resource
Report Press Release, all of which is incorporated by reference herein.

Forward-Looking Information and Statements

This news release contains certain forward-looking information and statements
within the meaning of applicable securities laws. The use of any of the words
“expect”, “anticipate”, “continue”, “estimate”, “may”, “will”, “project”,
“should”, “believe”, “plans”, “intends” “forecast” and similar expressions are
intended to identify forward-looking information or statements. In particular,
but without limiting the foregoing, this news release contains forward-looking
information and statements pertaining to the following: the volume and product
mix of Crew’s oil and gas production; production estimates including Q3, Q4 and
annual 2017 forecast average production and 2017 exit rate; the volumes and
estimated value of Crew’s resources and undeveloped land; future oil and
natural gas prices and Crew’s commodity risk management programs; future
liquidity and financial capacity; future results from operations and operating
metrics; year end forecasted debt to funds from operations ratio; anticipated
reductions in operating costs, well costs and G&A expenditures and potential to
improve ultimate recoveries and initial production rates; future costs,
expenses and royalty rates; future interest costs; the exchange rate between
the $US and $Cdn; future development, exploration, acquisition and development
activities and related capital expenditures and the timing thereof; the number
of wells to be drilled, completed and tied-in and the timing thereof; our
expectations regarding free cash flow generation at Greater Septimus and the
timing thereof; the potential value of our undeveloped land base; the amount
and timing of capital projects including infrastructure, pipeline and facility
expansions, commissioning and the timing and anticipated impact thereof; the
total future capital associated with development of reserves and resources; and
methods of funding our capital program, including possible non-core asset
divestitures and asset swaps.

Forward-looking statements or information are based on a number of material
factors, expectations or assumptions of Crew which have been used to develop
such statements and information but which may prove to be incorrect. Although
Crew believes that the expectations reflected in such forward-looking
statements or information are reasonable, undue reliance should not be placed
on forward-looking statements because Crew can give no assurance that such
expectations will prove to be correct. In addition to other factors and
assumptions which may be identified herein, assumptions have been made
regarding, among other things: the impact of increasing competition; the
general stability of the economic and political environment in which Crew
operates; the timely receipt of any required regulatory approvals; the ability
of Crew to obtain qualified staff, equipment and services in a timely and cost
efficient manner; drilling results; the ability of the operator of the projects
in which Crew has an interest in to operate the field in a safe, efficient and
effective manner; the ability of Crew to obtain financing on acceptable terms
and the adequacy of cash flow to fund its planned expenditures; field
production rates and decline rates; the ability to replace and expand oil and
natural gas reserves through acquisition, development and exploration; the
timing and cost of pipeline, storage and facility construction and expansion
and the ability of Crew to secure adequate product transportation; future
commodity prices; currency, exchange and interest rates; regulatory framework
regarding royalties, taxes and environmental matters in the jurisdictions in
which Crew operates; the ability of Crew to successfully market its oil and
natural gas products.

The forward-looking information and statements included in this news release
are not guarantees of future performance and should not be unduly relied upon.
Such information and statements, including the assumptions made in respect
thereof, involve known and unknown risks, uncertainties and other factors that
may cause actual results or events to defer materially from those anticipated
in such forward-looking information or statements including, without
limitation: changes in commodity prices; the potential for variation in the
quality of the Montney formation; changes in the demand for or supply of Crew’s
products; unanticipated operating results or production declines; changes in
tax or environmental laws, royalty rates or other regulatory matters; changes
in development plans of Crew or by third party operators of Crew’s properties,
increased debt levels or debt service requirements; inaccurate estimation of
Crew’s oil and gas reserve and resource volumes; limited, unfavourable or a
lack of access to capital markets; increased costs; a lack of adequate
insurance coverage; the impact of competitors; and certain other risks detailed
from time-to-time in Crew’s public disclosure documents (including, without
limitation, those risks identified in this news release and Crew’s Annual
Information Form).

The forward-looking information and statements contained in this news release
speak only as of the date of this news release, and Crew does not assume any
obligation to publicly update or revise any of the included forward-looking
statements or information, whether as a result of new information, future
events or otherwise, except as may be required by applicable securities laws.

Test Results and Initial Production Rates

A pressure transient analysis or well-test interpretation has not been carried
out and thus certain of the test results provided herein should be considered
to be preliminary until such analysis or interpretation has been completed.
Test results and initial production rates disclosed herein may not necessarily
be indicative of long term performance or of ultimate recovery.

About Crew

Crew Energy Inc. is a dynamic, growth-oriented exploration and production
company, focused on increasing long-term production, reserves and cash flow per
share through the development of our world-class Montney resource. Crew is
based in Calgary, Alberta and our shares are traded on the Toronto Stock
Exchange under the trading symbol “CR”.

Financial statements and MD&A for the three and six month periods ended June
30, 2017 and 2016 will be filed on SEDAR at www.sedar.com and are available on
the Company’s website at www.crewenergy.com.

– END RELEASE – 02/08/2017

For further information:
Crew Energy Inc.
Dale Shwed
President and C.E.O.
(403) 266-2088
OR
Crew Energy Inc.
John Leach
Senior Vice President and C.F.O.
(403) 266-2088
OR
Crew Energy Inc.
Rob Morgan
Senior Vice President and C.O.O.
(403) 266-2088
investor@crewenergy.com

COMPANY:
FOR: CREW ENERGY INC.
TSX SYMBOL: CR

INDUSTRY: Energy and Utilities – Oil and Gas
RELEASE ID: 20170802CC0056

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Birchcliff Energy Ltd. Announces Series of Asset Sales for Expected Proceeds of Approximately $142 Million

August 2, 2017August 1, 2017 by The Canadian Press

FOR: BIRCHCLIFF ENERGY LTD.
TSX SYMBOL: BIR

Date issue: August 01, 2017
Time in: 4:00 PM e

Attention:

CALGARY, ALBERTA–(Marketwired – Aug. 1, 2017) – Birchcliff Energy Ltd.
(“Birchcliff”) (TSX:BIR) is pleased to announce that it has completed a series
of asset sales and expects to complete additional asset sales, including the
sale of its Worsley Charlie Lake Light Oil Pool, for total disposition proceeds
of approximately $142 million (subject to closing adjustments). These asset
sales collectively represent forecast 2017 annual average production of
approximately 3,600 boe/d (approximately 62% light oil and NGLs) and proved
plus probable reserves of 48.2 MMboe at December 31, 2016.

The proceeds from these asset sales have been and are anticipated to be used to
initially reduce Birchcliff’s indebtedness under its credit facilities, which
will be subsequently redrawn as needed to fund Birchcliff’s capital expenditure
program and for general corporate purposes. Birchcliff expects that it will
provide updated guidance in its second quarter 2017 press release, which is
currently scheduled to be released on August 10, 2017 at 2:00 p.m. (MDT).

“We believe that these asset sales will allow us to become more geographically
focused and become even more competitive in our industry. In addition, the
proceeds from these asset sales will allow us to reduce our indebtedness, which
will improve our balance sheet and increase our financial flexibility.
Notwithstanding these assets sales, the borrowing base under our credit
facilities will remain at $950 million, which is a testament to the quality of
our reserves,” commented Jeff Tonken, President and Chief Executive Officer of
Birchcliff. “As a result of these transactions, we expect that our operating,
transportation and marketing and interest costs will decrease on a per unit
basis, reducing our already low-cost structure.”

Modification to AltaGas Gordondale Processing Arrangement

Birchcliff and AltaGas have modified their take-or-pay agreement effective
January 1, 2017 to incent volumes above Birchcliff’s existing take-or-pay
commitment at AltaGas’ deep-cut natural gas processing facility located in
Gordondale. This modification will significantly decrease the processing fees
payable by Birchcliff on volumes over Birchcliff’s existing take-or-pay volumes
and is expected to reduce Birchcliff’s unit operating costs until Birchcliff
builds its own deep-cut facility.

Details Regarding Asset Sales

Birchcliff has entered into a definitive purchase and sale agreement with a
private oil and gas company for the sale of its Worsley Charlie Lake Light Oil
Pool located in the Peace River Arch area of Alberta (the “Worsley Assets”) for
total consideration of approximately $100 million (subject to closing
adjustments), consisting of: (i) cash consideration of $90 million; and (ii)
securities of an affiliate of the purchaser with a total value of $10 million
(the “Worsley Disposition”). The effective adjustment date of the Worsley
Disposition is July 1, 2017. Closing is expected to occur on or about August
31, 2017, subject to the receipt of all necessary regulatory approvals and the
satisfaction of other customary closing conditions. The Worsley Assets
represent approximately 3,080 boe/d of forecast 2017 annual average production
(approximately 69% light oil and NGLs) and proved plus probable reserves of
38.9 MMboe at December 31, 2016.

“Since we first acquired our assets on the Worsley Charlie Lake Light Oil Play
in 2007, they have been instrumental in allowing us to create significant value
for our shareholders as they provided us with a source of cash flow that we
used to develop our Montney/Doig Resource Play. As we have not allocated any
significant capital to our Worsley Charlie Lake Light Oil Pool in recent years,
we made the decision to sell the assets in order to reduce our indebtedness and
concentrate on our premium-quality assets on the Montney/Doig Resource Play,”
commented Jeff Tonken, President and Chief Executive Officer of Birchcliff.

During the second quarter of 2017, Birchcliff completed the disposition of
various non-core assets for total proceeds of approximately $10 million (prior
to closing adjustments). In addition, Birchcliff is currently in the process of
negotiating the sale of some of the remaining assets that were marketed for
sale for additional proceeds of approximately $32 million (subject to closing
adjustments) (the “Additional Disposition”). Completion of the Additional
Disposition is subject to the entering into of a definitive purchase and sale
agreement and closing will be subject to the satisfaction of customary closing
conditions. If completed, it is expected that the Additional Disposition will
close in the fourth quarter of 2017.

ABBREVIATIONS

/T/

bbl barrel
boe barrel of oil equivalent
boe/d barrels of oil equivalent per day
Mcf thousand cubic feet
MMboe million barrels of oil equivalent
NGLs natural gas liquids

/T/

ADVISORIES

Boe Conversions

Boe amounts have been calculated by using the conversion ratio of 6 Mcf of
natural gas to 1 bbl of oil. Boe amounts may be misleading, particularly if
used in isolation. A boe conversion ratio of 6 Mcf to 1 bbl is based on an
energy equivalency conversion method primarily applicable at the burner tip and
does not represent a value equivalency at the wellhead. Given that the value
ratio based on the current price of crude oil as compared to natural gas is
significantly different from the energy equivalency of 6:1, utilizing a
conversion on a 6:1 basis may be misleading as an indication of value.

Presentation of Reserves Information

The reserves information contained herein in respect of the disposed assets is
based upon independent evaluations prepared by Birchcliff’s independent
qualified reserves evaluators, Deloitte LLP (“Deloitte”) and McDaniel &
Associates Consultants Ltd. (“McDaniel”), effective December 31, 2016, which
are contained in the consolidated report of Deloitte with an effective date of
December 31, 2016 (the “Consolidated Report”). Deloitte prepared the
Consolidated Report by consolidating the properties evaluated by Deloitte in
its evaluation with the properties evaluated by McDaniel in its evaluation, in
each case using Deloitte’s forecast price and cost assumptions effective
December 31, 2016. There are numerous uncertainties inherent in estimating
quantities of reserves and estimates of reserves are based upon a number of
variable factors and assumptions. Actual production with respect to reserves
will vary from estimates thereof and such variations could be material. There
is no assurance that the forecast prices and costs assumptions will be attained
and variances could be material. At December 31, 2016, Birchcliff had total
proved plus probable reserves of 880.5 MMboe, as contained in the Consolidated
Report. The estimates of reserves and future net revenue for individual
properties may not reflect the same confidence level as estimates of reserves
and future net revenue for all properties, due to the effects of aggregation.
All reserves information contained herein has been presented on a gross basis,
meaning Birchcliff’s working interest before the deduction of royalties and
without including any royalty interests of Birchcliff. Further information
regarding Birchcliff’s reserves is contained in its Annual Information Form for
the year ended December 31, 2016, a copy of which is available on SEDAR.

Forward-Looking Information

In particular, this press release contains forward-looking information relating
to the following: the asset sales, including that Birchcliff expects to
complete additional asset sales, the total expected disposition proceeds from
the asset sales, the entering into of a definitive purchase and sale agreement
in connection with the Additional Disposition, the purchase price for the
Additional Disposition, the anticipated closing dates of the Worsley
Disposition and the Additional Disposition, the anticipated use of proceeds
from the asset sales and the anticipated benefits of the asset sales (including
that the asset sales will allow Birchcliff to become more geographically
focused and become more competitive, that Birchcliff’s balance sheet will be
improved and its financial flexibility will be increased and Birchcliff’s
expectation that certain of its costs will decrease); estimates of 2017 annual
average production and reserves for the disposed assets; Birchcliff’s
expectation that it will provide updated guidance in its second quarter 2017
press release and the timing thereof; that Birchcliff’s modified take-or-pay
agreement is expected to reduce Birchcliff’s unit operating costs until
Birchcliff builds its own-deep cut facility; Birchcliff’s plans and other
aspects of its anticipated future financial performance, operations, focus,
objectives, strategies, opportunities, priorities and goals; and the
performance characteristics of Birchcliff’s oil and natural gas properties and
expected results from its assets. Information relating to reserves is
forward-looking as it involves the implied assessment, based on certain
estimates and assumptions, that the reserves exist in the quantities predicted
or estimated and that the reserves can be profitably produced in the future.

With respect to forward-looking information contained in this press release,
assumptions have been made regarding, among other things: that the Worsley
Disposition will be completed on the terms and the timing anticipated; that
Birchcliff will enter into a definitive purchase and sale agreement with
respect to the Additional Disposition and that the Additional Disposition will
be completed on the terms and the timing anticipated; the ability to obtain any
necessary regulatory approvals and the satisfaction of all conditions to the
Worsley Disposition and the Additional Disposition in a timely manner; the
scope of and the effects of the expected benefits of the asset sales;
Birchcliff’s ability to continue to develop its assets and obtain the
anticipated benefits therefrom; prevailing and future commodity prices and
differentials, currency exchange rates, interest rates, inflation rates,
royalty rates and tax rates; expected funds flow from operations; Birchcliff’s
future debt levels; the state of the economy and the exploration and production
business; the economic and political environment in which Birchcliff operates;
the regulatory framework regarding royalties, taxes and environmental laws; the
sources of funding for Birchcliff’s capital expenditure programs and other
activities; anticipated timing and results of capital expenditures; the
sufficiency of budgeted capital expenditures to carry out planned operations;
results of future operations; future operating, transportation, marketing and
general and administrative costs; the performance of existing and future wells,
well production rates and well decline rates; success rates for future
drilling; reserves volumes and Birchcliff’s ability to replace and expand oil
and gas reserves through acquisition, development or exploration; the impact of
competition on Birchcliff; the availability of, demand for and cost of labour,
services and materials; Birchcliff’s ability to access capital; the ability to
obtain financing on acceptable terms; the ability of Birchcliff to secure
adequate transportation for its products; and Birchcliff’s ability to market
oil and gas. With respect to estimates of reserves, the key assumption is the
validity of the data used by Birchcliff’s independent qualified reserves
evaluators in their independent evaluations, which includes technical
information and forecast commodity prices.
With respect to statements regarding the building of a deep-cut gas plant, the
key assumptions are that future drilling is successful, that there is
sufficient labour, services and equipment available, that Birchcliff will have
access to sufficient capital, that the key components of the plant will operate
as designed and that commodity prices and general economic conditions will
warrant proceeding with the construction of such plant and the drilling of
associated wells. With respect to Birchcliff’s estimated production for the
disposed assets, the key assumptions are that no unexpected outages occur in
the infrastructure that Birchcliff relies on to produce its wells and that any
transportation service curtailments or unplanned outages that occur will be
short in duration or otherwise insignificant and that existing wells continue
to meet production expectations.

Birchcliff’s actual results, performance or achievements could differ
materially from those anticipated in the forward-looking information as a
result of both known and unknown risks and uncertainties including, but not
limited to: that the Worsley Disposition does not close on the terms or the
timing anticipated or at all; the failure to enter into a definitive purchase
and sale agreement with respect to the Additional Disposition on the terms
anticipated or at all and that the Additional Disposition does not close on the
terms or the timing anticipated or at all; the failure to obtain any required
approvals or satisfy other closing conditions in a timely manner or at all; the
failure to realize the anticipated benefits of the asset sales; general
economic, market and business conditions which will, among other things, impact
the demand for and market prices of Birchcliff’s products and Birchcliff’s
access to capital; volatility of crude oil and natural gas prices; fluctuations
in currency and interest rates; operational risks and liabilities inherent in
oil and natural gas operations; uncertainties associated with estimating oil
and natural gas reserves; the accuracy of oil and natural gas reserves
estimates and estimated production levels as they are affected by exploration
and development drilling and estimated decline rates; geological, technical,
drilling, construction and processing problems; uncertainty of geological and
technical data; uncertainties related to Birchcliff’s future potential drilling
locations;
fluctuations in the costs of borrowing; changes in tax laws, crown royalty
rates, environmental laws and incentive programs relating to the oil and
natural gas industry and other actions by government authorities, including
changes to the royalty and carbon tax regimes and the imposition or
reassessment of taxes; the cost of compliance with current and future
environmental laws; political uncertainty and uncertainty associated with
government policy changes; uncertainties and risks associated with pipeline
restrictions and outages to third-party infrastructure that could cause
disruptions to production; the ability to satisfy obligations under
Birchcliff’s firm marketing and transportation arrangements; the inability to
secure adequate production transportation for Birchcliff’s products; the
occurrence of unexpected events such as fires, equipment failures and other
similar events affecting Birchcliff or other parties whose operations or assets
directly or indirectly affect Birchcliff; potential delays or changes in plans
with respect to exploration or development projects or capital expenditures;
stock market volatility; loss of market demand; environmental risks, claims and
liabilities; incorrect assessments of the value of acquisitions and exploration
and development programs; shortages in equipment and skilled personnel; the
absence or loss of key employees; uncertainty that development activities in
connection with its assets will be economical; competition for, among other
things, capital, acquisitions of reserves, undeveloped lands, equipment and
skilled personnel; uncertainties associated with credit facilities;
counterparty credit risk; risks associated with Birchcliff’s hedging program
and the risk that hedges on terms acceptable to Birchcliff may not be
available; and variances in Birchcliff’s actual capital costs, operating costs
and economic returns from those anticipated.

Readers are cautioned that the foregoing lists of factors are not exhaustive.
Additional information on these and other risk factors that could affect
results of operations, financial performance or financial results are included
in Birchcliff’s most recent Annual Information Form and in other reports filed
with Canadian securities regulatory authorities.

Any future-orientated financial information and financial outlook information
(collectively, “FOFI”) contained in this press release, as such terms are
defined by applicable securities laws, is provided for the purpose of providing
information about management’s current expectations and plans relating to the
future and is subject to the same assumptions, risk factors, limitations and
qualifications as set forth in the above paragraphs. FOFI contained in this
press release was made as of the date of this press release and Birchcliff
disclaims any intention or obligation to update or revise any FOFI contained in
this press release, whether as a result of new information, future events or
otherwise, unless required by applicable law. Readers are cautioned that any
FOFI contained herein should not be used for purposes other than those for
which it has been disclosed herein.

Management has included the above summary of assumptions and risks related to
forward-looking information provided in this press release in order to provide
readers with a more complete perspective on Birchcliff’s future operations.
Readers are cautioned that this information may not be appropriate for other
purposes. The forward-looking information contained in this press release is
expressly qualified by the foregoing cautionary statements. The forward-looking
information contained in this press release is made as of the date of this
press release. Birchcliff is not under any duty to update or revise any of the
forward-looking information except as expressly required by applicable
securities laws.

About Birchcliff:

Birchcliff is a Calgary, Alberta based intermediate oil and gas company with
operations concentrated within its one core area, the Peace River Arch of
Alberta. Birchcliff’s Common Shares and Cumulative Redeemable Preferred Shares,
Series A and Series C, are listed for trading on the Toronto Stock Exchange
under the symbols “BIR”, “BIR.PR.A” and “BIR.PR.C”, respectively.

– END RELEASE – 01/08/2017

For further information:
Birchcliff Energy Ltd.
Suite 1000, 600 – 3rd Avenue S.W.
Calgary, Alberta T2P 0G5
(403) 261-6401
(403) 261-6424 (FAX)
info@birchcliffenergy.com
www.birchcliffenergy.com
OR
Jeff Tonken
President, Chief Executive Officer and Chairman
OR
Bruno Geremia
Vice-President and Chief Financial Officer

COMPANY:
FOR: BIRCHCLIFF ENERGY LTD.
TSX SYMBOL: BIR

INDUSTRY: Energy and Utilities – Oil and Gas
RELEASE ID: 20170801CC0049

Press Release from Marketwired 1-866-736-3779

Shell refinery to remain closed until at least mid-August

August 1, 2017 by The Canadian Press

THE HAGUE, Netherlands — Royal Dutch Shell says a refinery in Rotterdam that it largely shut down over the weekend following a fire at an electricity station will remain closed until at least mid-August.

The energy multinational said in a statement Tuesday that it expects to restart operations at the Pernis refinery “at the earliest in the second half of August.”

The Pernis refinery in Rotterdam’s sprawling port is Europe’s largest. It has the capacity to refine just over 400,000 barrels of crude oil per day.

The company has not released details of the financial impact of the closure.

In a statement, Shell says: “we are doing everything we can to minimize impact to our customers.”

The Associated Press

Five Things World Business Will be Talking About Today

August 1, 2017 by EnergyNow Media

July 31, 2017 (Bloomberg) Crude oil tops $50 per barrel for the first time since May, RBA meeting on deck, and Scaramucci is out as White House communications director. Here are some of the things people in markets are talking about.$50West Texas Intermediate front-month futures closed above $50 per barrel for the first time since May … Read more

Crude Oil Drops Below $50 as Rising Dollar Erodes Earlier Gains

August 2, 2017August 1, 2017 by EnergyNow Media

August 1, 2017 (Bloomberg) Oil dropped below $50 a barrel as a stronger dollar eroded gains ahead of U.S. government data on crude stockpiles. Futures fell as much as 0.9 percent in New York after climbing 9.6 percent the previous six sessions. The dollar rose as much as 0.2 percent, reducing the appeal of commodities … Read more

Fight Over Abandoned Oil Wells in Canada May Go to Top Court

August 1, 2017August 1, 2017 by EnergyNow Media

August 1, 2017 (Bloomberg) A battle over whether energy-company creditors should help pay for cleaning up thousands of abandoned oil wells in Canada may be heading to the country’s Supreme Court. At the center of the dispute is Redwater Energy Corp., a small publicly traded oil producer in Alberta that filed for bankruptcy in late … Read more

BP sees earnings slip as spill costs continue to weigh

August 1, 2017 by The Canadian Press

LONDON — Oil producer BP’s second-quarter earnings slipped 5 per cent as the Deepwater Horizon disaster continued to weigh on the company.

A key measure of earnings, called underlying replacement cost profit, fell to $684 million from $720 million in the same period last year. The figure, which excludes one-time items and fluctuations in the value of inventories, is the industry’s preferred gauge of earnings.

Chief Executive Bob Dudley says BP is still working to adjust to an era of lower oil prices with a “tight focus on costs, efficiency and discipline in capital spending.”

Oil companies have been cutting costs and selling assets to adjust to lower oil prices, which early last year plunged to their lowest levels in more than a decade. BP said the average price it received during the second quarter this year rose 17 per cent to $46.27 a barrel. Oil was above $100 a barrel as recently as September 2014.

That pushed BP’s net income to $144 million, compared with a year-earlier loss of $1.42 billion.

BP set aside an additional $347 million in the quarter to cover claims and other expenses related to the 2010 Deepwater Horizon oil spill in the Gulf of Mexico, bringing total charges to $63.2 billion.

Net debt rose to $39.8 billion, higher than analyst forecasts of $38.5 billion.

“While net debt rose primarily due to Gulf of Mexico payments, we expect this will improve over the second half as these payments decline and divestment proceeds come in towards the end of the year,”Chief Financial Officer Brian Gilvary said.

Danica Kirka, The Associated Press

Bonterra Energy Corp. Confirms Cash Dividend for July 2017 Payable August 31st, 2017

August 1, 2017 by The Canadian Press

FOR: BONTERRA ENERGY CORP.TSX SYMBOL: BNEDate issue: August 01, 2017Time in: 7:00 AM eAttention:
CALGARY, ALBERTA–(Marketwired – Aug. 1, 2017) – Bonterra Energy Corp.
(www.bonterraenergy.com) (TSX:BNE) announces that the July 2017 monthly cash
divide…

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