Sign Up for FREE Daily Energy News
 
 
BREAKING NEWS:
Copper Tip Energy Services
MNP LLP Oilfield Services
Tundra Process Solutions

AltaGas Ltd. Reports Strong Second Quarter 2017 Results

FOR: ALTAGAS LTD.
TSX SYMBOL: ALA

Date issue: July 27, 2017
Time in: 7:45 AM e

Attention:

CALGARY, ALBERTA–(Marketwired – July 27, 2017) –

Highlights

(all financial figures are unaudited and in Canadian dollars unless otherwise
noted)

/T/

— Achieved record second quarter normalized EBITDA(1) of $166 million, an

increase of approximately 8 percent over the second quarter of 2016;
— Increased normalized funds from operations(1) by approximately 8 percent
to $123 million in the second quarter;
— Significantly advanced over $700 million in gas construction projects
including the Ridley Island Propane Export Terminal (RIPET), Townsend
2A, and North Pine;
— Announced a joint venture partnership pursuant to which Royal Vopak
obtained a 30 percent interest in RIPET;
— Modified take-or-pay agreement with Birchcliff Energy Ltd. (Birchcliff)
to incent volumes solely above the existing take-or-pay commitment at
Gordondale;
— Filed regulatory applications with the public utility commissions in
Maryland, Virginia and Washington D.C. in connection with AltaGas’
pending acquisition of WGL Holdings, Inc. (WGL Acquisition);
— Received Federal Energy Regulatory Commission (FERC) approval for the
WGL Acquisition, and the waiting period expired pursuant to the Hart-
Scott-Rodino Antitrust Improvements Act of 1976 (HSR Act); and
— As part of the financing plan for the pending WGL Acquisition, AltaGas
is launching the first phase of its asset sale process, which includes
large-scale, gas-fired power generation assets in California, together
with smaller non-core assets.

/T/

AltaGas Ltd. (AltaGas) (TSX:ALA) today reported that normalized EBITDA in the
second quarter of 2017 increased $13 million to $166 million, compared to the
same quarter in 2016. Normalized funds from operations were $123 million ($0.72
per share) for the second quarter of 2017, compared to $114 million ($0.75 per
share) in the same period of 2016. On a U.S. GAAP basis, net loss applicable to
common shares for the second quarter of 2017 was $8 million ($0.05 per share)
compared to net income applicable to common shares of $16 million ($0.10 per
share) in the second quarter of 2016. Normalized net income(1) was $28 million
($0.17 per share) for the second quarter of 2017, compared to $29 million
($0.19 per share) in the same period of 2016.

(1) Non-GAAP measure; see discussion in the advisories of this news release

“The performance of AltaGas’ diversified asset base and the consistent
operational excellence demonstrated across our three business segments has
driven another solid quarter for the company. Given these strong results, we
now expect to deliver low double digit percentage growth in normalized EBITDA
and high single digit percentage growth in normalized funds from operations
over 2016,” said David Harris, President and Chief Executive Officer of
AltaGas. “We remain steadfast in our commitment to our vision of being a
leading diversified North American energy infrastructure company with a
long-term strategy of maintaining a balanced portfolio between gas, power and
utilities. Due to the strong performance of our projects under construction and
several new opportunities we see this year, we are excited about the remainder
of 2017. As we continue to build on this momentum, the Board will make a
decision on the increase to the dividend in the fourth quarter. We are
committed to driving value for our shareholders.”

Year-to-date all three of AltaGas’ business segments have generated increased
results over the same period in 2016. AltaGas is actively working on
construction and/or growth opportunities in each segment.

Gas

AltaGas has significantly advanced its major construction projects for its
northeast B.C. and energy export strategies. The 99 Mmcf/d Townsend 2A
shallow-cut natural gas processing facility is currently tracking on-time and
on budget and is expected to begin commercial operations in October 2017. The
10,000 Bbls/d North Pine NGL Separation Facility continues to track ahead of
its original schedule and is expected online early in the first quarter of
2018. At RIPET, crews are currently working to pour the foundation for the
propane tank and have assembled the two tower cranes that will be used in the
civil construction works. Over the next few months, the propane tank will start
to take shape. This involves eight concrete pours with the final pour scheduled
near the end of 2017. RIPET is expected to be in service by the first quarter
of 2019.

On May 5, 2017, AltaGas announced a joint venture with Royal Vopak, a leading
independent tank storage company with a global network of terminals located at
strategic locations along major trade routes, pursuant to which Royal Vopak
obtained a 30 percent interest in RIPET. As part of the formation of the joint
venture, AltaGas will provide construction and operating services to the joint
venture. AltaGas has entered into negotiations with a number of producers and
suppliers and expects to underpin at least 40 percent of RIPET’s annual
expected capacity under tolling arrangements with producers and other suppliers.

“We are excited to see all of the development and logistics surrounding our
northeast B.C. strategy start to take shape. We are building strong
relationships with producers and suppliers that will provide sustainable growth
opportunities and benefits for all parties,” said Mr. Harris. “We are also
excited about our joint venture with Vopak as they are a very strategic global
tank storage company and bring significant experience in terminals worldwide.
We look forward to working with them on RIPET as well as considering future
opportunities to build out our joint venture.”

On June 29, 2017, AltaGas modified its existing take-or-pay agreement with
Birchcliff to incent increased utilization of AltaGas’ 135 Mmcf/d Gordondale
deep-cut natural gas processing facility until late 2020. The modifications
made apply solely to volumes above the existing take-or-pay volume commitments.
AltaGas continues to have positive discussions with a number of producers in
the area to expand the Gordondale gas gathering system to fill capacity and
potentially expand the facility.

Power

AltaGas continues to pursue opportunities to enhance the value of its
California power position. As it relates to both Blythe, following its PPA
expiration in July 2020, and the current development project Sonoran, AltaGas
continues to have bilateral discussions with public owned utilities, investor
owned utilities, community choice aggregators, municipalities, and corporations
for multi-year agreements, while also considering resource adequacy market
pricing, potential energy and ancillary service offerings, and alternative
configurations (gas, combined with solar and energy storage) using the multiple
transmission options and capacity available to best serve AltaGas’ potential
customers in the Desert Southwest region.

AltaGas also continues to pursue energy storage opportunities driven by the
needs of load serving entities. AltaGas is well suited to develop additional
brownfield and greenfield sites in load-constrained areas.

Utilities

AltaGas continues to invest in its five wholly-owned utilities, primarily
through system betterment opportunities as well as the addition of new
customers.

On December 15, 2016, SEMCO Gas filed an application with the Michigan Public
Service Commission (MPSC) seeking approval to construct, own, and operate the
Marquette Connector Pipeline (MCP). The MCP is a proposed new pipeline that
will connect the Great Lakes Gas Transmission pipeline to the Northern Natural
Gas pipeline in Marquette, Michigan, which will provide system redundancy and
increase deliverability, reliability and diversity of supply to SEMCO Gas’
approximately 35,000 customers in Michigan’s Western Upper Peninsula. A MPSC
decision is expected in 2017. The MCP is estimated to cost between US$135 to
$140 million with an anticipated in-service date in 2020.

“We have a lot to look forward to as we start to bring some of our construction
projects online later this year and continue to execute on new growth
opportunities,” said Mr. Harris. “The strategic positioning and advantages we
have in each of our business segments allows us to continue to grow and provide
long-term sustainable value.”

Strategic Pending Acquisition of WGL Holdings Inc. (WGL Acquisition)

On January 25, 2017, AltaGas announced it had entered into a definitive
agreement to indirectly acquire WGL Holdings, Inc. (WGL), a diversified energy
infrastructure company. The combination will bring together high quality,
low-risk, long-lived infrastructure assets in North America with approximately
$5 billion in secured growth projects and approximately $2 billion of growth
opportunities through 2021 which are in advanced stages of development.

“WGL is strongly aligned with our vision and strategy and will significantly
increase the scale of all three of our business segments,” said Mr. Harris.
“Combined, we will have gas operations in the two most prolific natural gas
plays in North America, the Montney and the Marcellus/Utica, power generation
in over 20 states and provinces, and utility operations in growing
jurisdictions.” Mr. Harris continued, “Each of our business segments will now
have a premier footprint in both Canada and the U.S., providing us with even
greater growth opportunities in each segment while further improving our
diversification. With our enhanced footprint we expect there will be further
growth opportunities over time even beyond what we have identified to date. We
will look to execute on those opportunities while staying true to our strategy
of a balanced portfolio of gas, power and utility assets and a low-risk value
proposition for our shareholders.”

The WGL Acquisition is expected to provide material accretion to earnings per
share (8 – 10 percent) and to normalized funds from operations per share(1) (15
– 20 percent) on average through 2021. Starting with the first full year
(2019), the WGL Acquisition is also expected to support visible dividend growth
of 8 – 10 percent per annum through 2021, while allowing AltaGas to maintain a
conservative payout of 50 – 60 percent of normalized funds from operations.

(1 ) Non-GAAP measure; see discussion in the advisories of this news release

On April 24, 2017, AltaGas filed regulatory applications with the public
utility commissions in Maryland, Virginia and Washington D.C. On the same date,
AltaGas and WGL also filed their voluntary Joint Notice to the Committee on
Foreign Investment in the United States (CFIUS), and an application with the
United States FERC. In addition, on June 15, 2017, a pre-merger Notification
and Report Form on the WGL Acquisition was filed in accordance with the
requirements of the HSR Act. To the extent required, hearings related to the
state regulatory applications are anticipated to begin in the fourth quarter of
2017 with final decisions anticipated to follow through the first half of 2018.
AltaGas anticipates that the CFIUS review will be completed by the end of
September 2017. On July 6, 2017, the FERC found that the transaction is
consistent with the public interest and is now approved. Also, as of July 17,
2017, when the waiting period required by Section 7A(b)(1) of the HSR Act
expired, the merger was deemed approved by the Federal Trade Commission and the
Department of Justice, such approval being valid for one year. WGL shareholders
voted in favor of the Merger Agreement governing the proposed acquisition on
May 10, 2017.

Financial Update

Normalized EBITDA in the second quarter increased 8 percent to $166 million as
compared to $153 million for the same quarter of 2016. The Gas segment
benefitted from the commencement of commercial operations at the Townsend
Facility in the third quarter of 2016 and higher frac exposed volumes. Results
for the Utilities were positively impacted by colder weather experienced in
Alaska and Alberta, rate and customer growth, insurance proceeds received by
SEMCO’s non-regulated operations, and an early termination payment from one of
SEMCO’s non-regulated customers moving from a fixed fee to a volumetric-based
contract. The Power segment benefitted from a full quarter of contributions
from the Pomona Energy Storage Facility which commenced commercial operations
on December 31, 2016, and the timing of the Blythe Energy Center outage. Both
the Power and Utilities segments benefitted from the stronger U.S. dollar on
reported results of the U.S. assets. The overall increases in normalized EBITDA
were partially offset by the impact of planned turnarounds at EEEP and Turin,
the impact of the sale of the EDS and JFP transmission assets in the first
quarter of 2017, lower equity earnings from Petrogas, lower ethane revenues due
to lower volumes, warmer weather at the Michigan and Nova Scotia Utilities and
lower interruptible storage service revenue at CINGSA.

Normalized funds from operations were $123 million ($0.72 per share) in the
second quarter of 2017, up from $114 million ($0.75 per share) in the second
quarter of 2016. The increase was driven by the increase in normalized EBITDA,
partially offset by lower distributions from Petrogas.

For the second quarter of 2017, AltaGas recorded income tax expense of $8
million compared to $4 million in the same quarter of 2016. The increase was
primarily due to unrealized losses on certain risk management contracts not
being tax deductible.

On a U.S. GAAP basis, net loss applicable to common shares for the second
quarter of 2017 was $8 million ($0.05 per share) compared to net income
applicable to common shares of $16 million ($0.10 per share) for the same
quarter in 2016. The decrease was mainly due to the transaction costs incurred
on the pending WGL Acquisition, higher unrealized losses recognized on risk
management contracts, higher income tax, interest, depreciation and
amortization expense, higher preferred share dividends, and the unrealized loss
recognized upon ceasing to account for the Tidewater investment using the
equity method, partially offset by the same previously referenced factors
resulting in the increase in normalized EBITDA.

Normalized net income was $28 million ($0.17 per share) for the second quarter
of 2017, compared to $29 million ($0.19 per share) reported for the same
quarter in 2016. The decrease was mainly due to higher depreciation and
amortization expense, and higher preferred share dividends, partially offset by
the same previously referenced factors resulting in the increase in normalized
EBITDA. Normalizing items in the second quarter of 2017 included after-tax
amounts related to transaction costs on acquisitions, unrealized losses on risk
management contracts and long-term investments, gain on sale of assets,
provision on assets, and financing costs associated with the bridge facility
for the pending WGL Acquisition. In the second quarter of 2016, normalizing
items included after-tax amounts related to unrealized losses on risk
management contracts and restructuring costs.

For the six months ended June 30, 2017, AltaGas reported normalized EBITDA of
$394 million compared to $332 million for the same period in 2016. The increase
was mainly due to the commencement of commercial operations at the Townsend
Facility in the third quarter of 2016, higher earnings from Petrogas including
the dividend income from the Petrogas Preferred Shares, colder weather
experienced at certain of the Utilities, higher realized frac spread and frac
exposed volumes, higher revenue from NGL marketing, higher natural gas storage
margins, the absence of equity losses from the Sundance B PPAs, the interim and
refundable rate increases at ENSTAR, contributions from the Pomona Energy
Storage Facility which commenced commercial operations on December 31, 2016, an
early termination payment from one of SEMCO’s non-regulated customers moving
from a fixed fee to a volumetric-based contract, and insurance proceeds
received by SEMCO’s non-regulated operations. These increases were partially
offset by the impact of planned turnarounds at EEEP and Turin in the second
quarter of 2017 and the impact of the sale of the EDS and JFP transmission
assets.

Normalized funds from operations for the first half of 2017 were $294 million
($1.74 per share), compared to $248 million ($1.66 per share) for the same
period in 2016, reflecting the same drivers as normalized EBITDA, partially
offset by lower cash distributions from Petrogas and higher interest expense.
In the first half of 2017, AltaGas received $6 million of dividend income from
the Petrogas Preferred Shares (2016 – $nil) and $2 million of common share
dividends from Petrogas (2016 – $12 million). Petrogas retained cash to fund
its growth capital program and for general corporate purposes.

AltaGas recorded income tax expense of $29 million for the first half of 2017
compared to $10 million in the same period of 2016. The increase was primarily
due to the absence of the $10 million tax recovery related to the Tidewater Gas
Asset Disposition recorded in the first quarter of 2016. In addition, a portion
of transaction costs incurred on the pending WGL Acquisition and unrealized
losses on certain risk management contracts were not tax deductible.

In March 2017, AltaGas completed the sale of the EDS and the JFP transmission
assets to Nova Chemicals for net proceeds of approximately $67 million,
resulting in a pre-tax loss on disposition of $3 million.

Net income applicable to common shares for the first half of 2017 was $24
million ($0.14 per share) compared to $71 million ($0.48 per share) for the
same period in 2016. The decrease was mainly due to the transaction costs
incurred on the pending WGL Acquisition, higher unrealized losses on risk
management contracts, the unrealized loss recognized upon ceasing to account
for the Tidewater investment using the equity method, higher income tax,
interest, depreciation and amortization expense, higher preferred share
dividends, and higher losses on sale of assets, partially offset by the same
previously referenced factors resulting in the increase in normalized EBITDA.
In addition, net income per common share decreased for the first half of 2017
compared to the same period in 2016 as a result of the same factors impacting
net income, as well as the increase in common shares outstanding in 2017.

Normalized net income was $93 million ($0.55 per share) for the first half of
2017, compared to $68 million ($0.46 per share) reported for the same period in
2016. The increase was driven by the same factors impacting normalized EBITDA,
partially offset by higher income tax, interest, depreciation and amortization
expense, and higher preferred share dividends. Normalizing items in the first
half of 2017 included after-tax amounts related to transaction costs on
acquisitions, unrealized losses on risk management contracts and long-term
investments, losses on sale of assets, provision on assets, and financing costs
associated with the bridge facility for the pending WGL Acquisition. In the
first half of 2016, normalizing items included after-tax amounts related to
transaction costs incurred on acquisitions, unrealized losses on risk
management contracts, gains on sale of assets, dilution loss recognized on
investment accounted for by the equity method, provision on investment
accounted for by the equity method, and restructuring costs.

2017 OUTLOOK

Based on strong performance year-to-date and an assessment for the remainder of
the year, AltaGas now expects to deliver low double digit percentage normalized
EBITDA growth in 2017 compared to 2016. All three business segments are
expected to drive the annual growth in 2017 compared to 2016, with the Gas
segment expecting to generate the highest normalized EBITDA percentage growth,
followed by the Power segment and the Utilities segment. The Power and
Utilities segments are expected to generate approximately 75 percent of 2017
normalized EBITDA. The Gas segment is expected to increase from 23 percent of
total 2016 normalized EBITDA to approximately 25 percent of total 2017
normalized EBITDA. The following are the key drivers contributing to the
expected normalized EBITDA growth in 2017:

/T/

— First full year of commercial operations at the Townsend Facility;
— Higher earnings from frac exposed volumes as a result of higher

commodity prices;
— Higher expected earnings from the Northwest Hydro Facilities due to
contractual price increases and continued improvements in operational
efficiency resulting in higher volumes and lower operating costs;
— Actual weather in the first half of 2017 was colder at certain of the
Utilities compared to the warmer weather experienced in 2016, with
normal weather expected for the remainder of 2017;
— Contributions from the Pomona Energy Storage Facility, which entered
commercial operation on December 31, 2016;
— Higher earnings from renewables primarily due to stronger wind
generation at the Bear Mountain Wind Facility and fewer planned outages
at the Craven Biomass Facility;
— Higher earnings from energy services primarily due to higher revenue
from NGL marketing and higher natural gas storage margins;
— Higher expected volumes at the Gordondale Facility following the
modifications made to the take-or-pay agreement for volumes solely above
the existing take-or-pay commitment to incent Birchcliff to deliver
additional volumes. AltaGas continues to have positive discussions with
a number of producers in the area to expand the Gordondale gas gathering
system to fill capacity and potentially expand the facility;
— Decrease in administrative expenses as a result of various cost savings
initiatives, including the savings from the Workforce Restructuring that
occurred in 2016; and
— Partial contributions from Townsend 2A entering commercial operations in
the fourth quarter of 2017.

/T/

The overall forecasted EBITDA growth in 2017 includes the negative impact from
the sale of the EDS and JFP transmission assets to Nova Chemicals, which was
completed in March 2017, and scheduled turnarounds at EEEP and the Turin
facility, which occurred in the second quarter of 2017. A turnaround at the
Gordondale facility is scheduled in the third quarter of 2017 but is not
expected to have a material impact on normalized EBITDA due to the majority of
costs being capitalized and revenues being billed under a take-or-pay
arrangement.

Normalized funds from operations are expected to grow by a high single digit
percentage, driven by the same factors noted above for normalized EBITDA
growth, but partially offset by higher current tax expenses and lower common
share dividends from Petrogas, as Petrogas is expected to retain a portion of
its cash to fund its capital program and for general corporate purposes.

AltaGas continues to focus on enhancing productivity and streamlining
businesses. As part of the financing strategy for the WGL Acquisition, AltaGas
is launching the first phase of its asset sale process, which includes
large-scale, gas-fired power generation assets in California, together with
smaller non-core assets. Depending on the closing date of the asset sales, the
2017 outlook for normalized EBITDA and normalized funds from operations may be
adversely impacted.

In the Gas segment, additional earnings in 2017 are expected to be driven by a
full year of contributions from the Townsend Facility, higher frac exposed
volumes and commodity prices, a full year of income from the Petrogas Preferred
Share dividends, higher NGL marketing revenue and natural gas storage margins,
higher volumes expected at the Gordondale facility due to the modifications
made to the take-or-pay agreement with Birchcliff, and a partial year
contribution from Townsend 2A entering commercial operations in the fourth
quarter of 2017. The additional earnings are partially offset by the closing of
the sale of the EDS and JFP transmission pipelines in the first quarter of
2017, lower ethane revenue at EEEP and the Pembina Empress Extraction Plant
(PEEP), and scheduled turnarounds at EEEP and the Turin facility in the second
quarter of 2017. Based on current commodity prices, AltaGas estimates an
average of approximately 9,500 Bbls/d will be exposed to frac spreads prior to
hedging activities. For the remainder of 2017, AltaGas has frac hedges in place
for approximately 5,500 Bbls/d at an average price of approximately $23/Bbl
excluding basis differentials.

In the Power segment, increased earnings are expected to be driven by higher
expected earnings from the Northwest Hydro Facilities due to contractual price
increases and continued improvements in productivity resulting in higher
volumes generated and lower operating costs, contributions from a full year of
operations at the Pomona Energy Storage Facility, fewer planned outages
expected at Blythe and at the Craven Biomass Facility, and higher earnings from
the Bear Mountain Wind Facility due to stronger wind generation. The earnings
and cash flows from the Northwest Hydro Facilities are expected to be
seasonally stronger through the end of the third quarter and are expected to
decline in the fourth quarter based on seasonal water flow patterns. Actual
seasonal water flow will vary with regional temperatures and precipitation
levels.

The Utilities segment is expected to report increased earnings in 2017 mainly
driven by the colder weather in the first half of 2017 at certain of the
Utilities and normal weather assumed for the second half of 2017, compared to
the warmer weather experienced at all of the Utilities in 2016. In addition,
higher customer usage at certain of the Utilities and lower expenses are
expected to benefit earnings. These increases are expected to be partially
offset by lower interruptible storage service revenue at CINGSA. Earnings at
all of the Utilities (except PNG) are affected by weather in their franchise
areas, with colder weather generally benefiting earnings. If the weather varies
from normal weather, earnings at the Utilities would be affected. In addition,
earnings from the Utilities segment are impacted by regulatory decisions and
the timing of these decisions. In 2017, ENSTAR expects EBITDA to increase by
approximately $3 million as a result of the interim refundable rate increase
approved in 2016 by the Regulatory Commission of Alaska, with final rates
expected to be set in the third quarter of 2017.

Earnings generated from AltaGas’ U.S. assets are exposed to fluctuations in the
U.S./Canadian dollar exchange rate. In general, the strengthening of the U.S.
dollar compared to the Canadian dollar will have a positive impact on earnings.
The weakening of the U.S. dollar will have the opposite effect. To the extent
AltaGas has outstanding U.S. dollar denominated debt and/or preferred shares,
fluctuations in the U.S./Canadian dollar exchange rate will have the opposite
effect as compared to the impact on earnings generated from AltaGas’ U.S.
assets.

Monthly Common Share Dividend and Quarterly Preferred Share Dividends

/T/

— The Board of Directors approved a dividend of $0.175 per common share.

The dividend will be paid on September 15, 2017, to common shareholders
of record on August 25, 2017. The ex-dividend date is August 23, 2017.
This dividend is an eligible dividend for Canadian income tax purposes;
— The Board of Directors approved a dividend of $0.21125 per share for the
period commencing June 30, 2017 and ending September 29, 2017, on
AltaGas’ outstanding Series A Preferred Shares. The dividend will be
paid on September 29, 2017 to shareholders of record on September 15,
2017. The ex-dividend date is September 13, 2017;
— The Board of Directors approved a dividend of $0.20101 per share for the
period commencing June 30, 2017 and ending September 29, 2017, on
AltaGas’ outstanding Series B Preferred Shares. The dividend will be
paid on September 29, 2017 to shareholders of record on September 15,
2017. The ex-dividend date is September 13, 2017;
— The Board of Directors approved a dividend of US$0.275 per share for the
period commencing June 30, 2017 and ending September 29, 2017, on
AltaGas’ outstanding Series C Preferred Shares. The dividend will be
paid on September 29, 2017 to shareholders of record on September 15,
2017. The ex-dividend date is September 13, 2017;
— The Board of Directors approved a dividend of $0.3125 per share for the
period commencing June 30, 2017, and ending September 29, 2017, on
AltaGas’ outstanding Series E Preferred Shares. The dividend will be
paid on September 29, 2017 to shareholders of record on September 15,
2017. The ex-dividend date is September 13, 2017;
— The Board of Directors approved a dividend of $0.296875 per share for
the period commencing June 30, 2017, and ending September 29, 2017, on
AltaGas’ outstanding Series G Preferred Shares. The dividend will be
paid on September 29, 2017 to shareholders of record on September 15,
2017. The ex-dividend date is September 13, 2017;
— The Board of Directors approved a dividend of $0.328125 per share for
the period commencing June 30, 2017, and ending September 29, 2017, on
AltaGas’ outstanding Series I Preferred Shares. The dividend will be
paid on September 29, 2017 to shareholders of record on September 15,
2017. The ex-dividend date is September 13, 2017; and
— The Board of Directors approved a dividend of $0.3125 per share for the
period commencing June 30, 2017, and ending September 29, 2017, on
AltaGas’ outstanding Series K Preferred Shares. The dividend will be
paid on September 29, 2017 to shareholders of record on September 15,
2017. The ex-dividend date is September 13, 2017.

/T/

Consolidated Financial Review

/T/

Three Months Six Months
Ended Ended
June 30 June 30
($ millions) 2017 2016 2017 2016
—————————————————————————-
Revenue 539 426 1,310 1,036
Normalized EBITDA(1) 166 153 394 332
Net income (loss) applicable to common
shares (8) 16 24 71
Normalized net income(1) 28 29 93 68
Total assets 10,099 9,858 10,099 9,858
Total long-term liabilities 4,670 4,561 4,670 4,561
Net additions to property, plant and
equipment 125 126 127 206
Dividends declared(2) 89 76 178 148
Normalized funds from operations(1) 123 114 294 248
—————————————————————————-
—————————————————————————-
Three Months Six Months
Ended Ended
June 30 June 30
($ per share, except shares outstanding) 2017 2016 2017 2016
—————————————————————————-
Net income (loss) per common share – basic (0.05) 0.10 0.14 0.48
Net income (loss) per common share –
diluted (0.05) 0.10 0.14 0.48
Normalized net income – basic(1) 0.17 0.19 0.55 0.46
Dividends declared(2) 0.53 0.50 1.05 0.99
Normalized funds from operations(1) 0.72 0.75 1.74 1.66
Shares outstanding – basic (millions)
During the period(3) 170 152 169 149
End of period 171 163 171 163
—————————————————————————-
—————————————————————————-
(1) Non-GAAP financial measure; see discussion in Non-GAAP Financial
Measures section of this MD&A.
(2) Dividends declared per common share per month: $0.165 beginning on
October 26, 2015 and $0.175 beginning on August 25, 2016.
(3) Weighted average.

/T/

CONFERENCE CALL AND WEBCAST DETAILS:

AltaGas will hold a conference call today at 9:00 a.m. MT (11:00 a.m. ET) to
discuss 2017 second quarter results, progress on construction projects, the
pending WGL Acquisition and other corporate developments.

Members of the investment community and other interested parties may dial
1-703-318-2220 or call toll free at 1-844-543-5238. The passcode is 35926799.
Please note that the conference call will also be webcast. To listen, please go
to http://www.altagas.ca/invest/events-and-presentations. The webcast will be
archived for one year.

Shortly after the conclusion of the call, a replay will be available by dialing
1-404-537-3406 or 1-855-859-2056. The passcode is 35926799. The replay will
expire at 2:00 p.m. (Eastern) on July 29, 2017.

Additional information relating to AltaGas’ results can be found in the
Management’s Discussion and Analysis and unaudited condensed interim
consolidated financial statements for the three months and six months ended
June 30, 2017 available through AltaGas’ website at www.altagas.ca or through
SEDAR at www.sedar.com.

AltaGas is an energy infrastructure company with a focus on natural gas, power
and regulated utilities. AltaGas creates value by acquiring, growing and
optimizing its energy infrastructure, including a focus on clean energy
sources. For more information visit: www.altagas.ca

FORWARD LOOKING INFORMATION

This news release contains forward-looking statements. When used in this news
release the words “may”, “would”, “could”, “should”, “will”, “intend”, “plan”,
“anticipate”, “further”, “continue”, “look forward”, “future”, “pursue”, “grow”
“believe”, “achieve”, “aim”, “advance”, “seek”, “propose”, “position”,
“estimate”, “forecast”, “expect”, “project”, “launch”. “target”, “on track”,
“potential” and similar expressions suggesting future events or future
performance, as they relate to the Corporation or any affiliate of the
Corporation, are intended to identify forward-looking statements.

In particular, this news release contains forward-looking statements with
respect to, among other things, business objectives; AltaGas’ vision and
strategy; expected growth and drivers of growth; capital expenditures
(including in respect of the 2017 capital program; expected allocation per
business segment and project and anticipated sources of financing thereof);
results of operations; operational and financial performance; business
projects; opportunities; strategic position of assets, ability to provide
long-term sustainable value; financial results, expectations regarding 2017
normalized EBITDA (including expected contributions per business segment and
sources of generation); projected growth in normalized EBITDA and normalized
funds from operations (including per business segment); AltaGas’ continuation
of advancement of its strategic initiatives; AltaGas’ ability to acquire, grow
and optimize energy infrastructure, expectations with respect to the WGL
Acquisition including the expected closing date, ability to obtain, and
timeline for obtaining, regulatory and other approvals, AltaGas’ ability to
sell assets (including AltaGas’ ability to launch and complete asset sales in
phases), anticipated benefits of the WGL Acquisition including the alignment
with AltaGas’ vision and strategy, footprint, portfolio and scale of assets of
the combined entity, nature, number, value and quality of the assets, the
nature, number, value, quality, timing and stage of development of growth
projects and opportunities and AltaGas’ ability to execute on projects and
opportunities, the strategic focus of the business, EPS accretion and
normalized FFOPS accretion, both in the first full year following the WGL
Acquisition and over the period to 2021, growth on an absolute dollar and per
share basis, strength of earnings (including, without limitation, EPS, FFOPS
and EBITDA growth rate through 2021), annual dividend growth rate, dividend
payout ratios, compatibility, strength and focus of the combined entity,
complimentary nature of businesses, ability to increase scale and provide
diversity;
AltaGas’ ability to maintain a balanced portfolio among business segments;
expectations regarding current projects under construction and new
opportunities for 2017 driving shareholder value; expectations with respect to
the Townsend Facility including, expected earnings and impact on earnings;
expectations with respect to Townsend 2A including expected timeline for
completion of construction and commercial operations and contribution to
earnings; expectations with respect to RIPET including timing of construction
completion and commercial operations, AltaGas’ ability to construct and
operate, sources of propane supply, ability to underpin capacity, tolling
arrangements, strength of relationships with producers and suppliers and
potential benefits to be derived from such relationships, strategic nature of
the joint venture, future opportunities for the joint venture and Vopak’s
terminal experience; expectations regarding take or pay arrangements with Birch
Cliff; expectations relating to the North Pine Facility including timeline for
construction and commercial operation; expectations relating to the Marquette
Connector Pipeline including timeline for MPSC approval, construction and
in-service date; cost, location, connection capability to existing pipelines
and gas supply opportunities; expectations relating to AltaGas’ ability to fund
its projects and business; expectations to enhance the value of AltaGas’
California power position; expectations regarding opportunities for Blythe and
Sonoran including re-contracting, re-configuring, offering resource adequacy,
energy and ancillary services, using multiple transmission options, serving
several western U.S. states, entering into multi-year agreements and pursuing
opportunities through bilateral discussions or otherwise; expectations relating
to potential future energy storage opportunities and AltaGas’ suitability to
develop; expectations relating to the Northwest Hydro Facilities including
expected generation, operational efficiency, operating costs, contributions to
earnings and seasonality impacts (including water flow patterns);
expected impact on earnings of the Tidewater Gas Asset Disposition;
expectations regarding gas processing volumes and disposition of smaller
non-core assets; expectations regarding Petrogas including dividends from
Petrogas, and Petrogas’ retention of cash and contributions; expectations
regarding the U.S. dollar exchange rate, foreign exchange forward contracts,
commodity hedge gains, frac spread exposure, frac exposed volumes, NGL
marketing revenue, storage margins, recovery in commodity prices, weather, wind
generation and operating and administrative costs; expectations regarding the
impact on earnings of the sale of EDS and JFP pipelines; impact of facility
turnarounds and outages on earnings and timing of turnarounds and outages;
expectations regarding volumes at the Gordondale facility and expansion of the
gas gathering system and facility; expectations regarding the utilities segment
including opportunities for system betterment and customer growth, earnings
from the utilities segment including from rate base and customer growth and
higher customer usage and impact on earnings from lower interruptible storage
service revenue from CINGSA and regulatory decisions and timing of regulatory
decisions (including in respect of ENSTAR’s 2016 rate case and expected
decision date and expected revenue increase); AltaGas’ ability to focus on
enhancing productivity and streamlining businesses; expectations regarding
dividends (including dividend increases and the payment of dividends) and
expectations regarding timing of the conference call.

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. Such statements reflect
AltaGas’ current views with respect to future events based on certain material
factors and assumptions and are subject to certain risks and uncertainties
including, without limitation, changes in market competition, governmental,
aboriginal or regulatory developments, changes in tax legislation, fluctuations
in commodity prices, interest or foreign exchange rates, access to capital
markets, general economic conditions, changes in the political environment,
changes to environmental and other laws and regulations, cost for labour,
equipment and materials and other factors set out in AltaGas’ continuous
disclosure documents, including the Annual Information Form and the MD&A as at
and for the year ended December 31, 2016.

Many factors could cause AltaGas’ actual results, performance or achievements
to vary from those described in this news release, including, without
limitation, those listed above. These factors should not be construed as
exhaustive. Should one or more of these risks or uncertainties materialize, or
should assumptions underlying forward-looking statements prove incorrect,
actual results may vary materially from those described in this news release as
intended, planned, anticipated, believed, sought, proposed, estimated or
expected, and such forward-looking statements included in, or incorporated by
reference in this news release, should not be unduly relied upon. Such
statements speak only as of the date of this news release. AltaGas does not
intend, and does not assume any obligation, to update these forward-looking
statements. The forward-looking statements contained in this news release are
expressly qualified by this cautionary statement.

Financial outlook information contained in this news release about prospective
financial performance, financial position or cash flows is 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. Readers are cautioned that such financial outlook information
contained in this news release should not be used for purposes other than for
which it is disclosed herein.

This news release contains references to certain financial measures that do not
have a standardized meaning prescribed by GAAP and may not be comparable to
similar measures presented by other entities. The non-GAAP measures and their
reconciliation to GAAP financial measures are shown in AltaGas’ Management’s
Discussion and Analysis (MD&A) as at and for the period ended June 30, 2017.
These non-GAAP measures provide additional information that management believes
is meaningful regarding AltaGas’ operational performance, liquidity and
capacity to fund dividends, capital expenditures, and other investing
activities. The specific rationale for and incremental information associated
with each non-GAAP measure is discussed in AltaGas’ MD&A as at and for the
period ended June 30, 2017. Readers are cautioned that these non-GAAP measures
should not be construed as alternatives to other measures of financial
performance calculated in accordance with GAAP.

– END RELEASE – 27/07/2017

For further information:
Investment Community
1-877-691-7199
[email protected]
OR
Media
(403) 691-7197
[email protected]

COMPANY:
FOR: ALTAGAS LTD.
TSX SYMBOL: ALA

INDUSTRY: Energy and Utilities – Oil and Gas , Energy and Utilities
– Utilities
RELEASE ID: 20170727CC0022

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.

New SHOWCASE Directory Companies

 

Predator Drilling
Galloway Construction Group
Environmental Refueling Systems (ERS)
Techmation Electric & Controls
Versa-Line
FUELware
Galdos Systems
Assetworks

Canadian Utilities Reports Second Quarter 2017 Earnings

FOR: CANADIAN UTILITIES LIMITED
TSX SYMBOL: CU
TSX SYMBOL: CU.X
TSX SYMBOL: CU.PR.C
TSX SYMBOL: CU.PR.D
TSX SYMBOL: CU.PR.E
TSX SYMBOL: CU.PR.F
TSX SYMBOL: CU.PR.G

Date issue: July 27, 2017
Time in: 7:42 AM e

Attention:

CALGARY, ALBERTA–(Marketwired – July 27, 2017) – Canadian Utilities Limited
(TSX: CU, CU.X)

Canadian Utilities Limited today announced second quarter adjusted earnings for
2017 of $129 million compared to $131 million in 2016. In June 2017, the
Alberta Utilities Commission (AUC) released a retroactive regulatory decision
that adversely impacted Electric Transmission’s adjusted earnings. Without the
prior period impact from this decision, adjusted earnings in the second quarter
of 2017 would have been $135 million.

Earnings growth in the Electricity and Pipelines & Liquids global business
units, mainly due to continued capital investment in our Regulated Utilities,
was offset by the timing of operating costs in Electric Distribution and the
earnings impact of the 2015 to 2017 General Tariff Application (GTA) Compliance
Filing decision in Electric Transmission.

Canadian Utilities invested $398 million in capital growth projects in the
second quarter and $683 million in the first half of 2017, of which 99 per cent
was invested in assets that earn a return under a regulatory business model or
are secured under long-term contracts. This capital investment is expected to
contribute significant earnings and cash flow and create long-term value for
share owners.

On July 12, 2017, Canadian Utilities declared a third quarter dividend for 2017
of 35.75 cents per Class A non-voting and Class B common share, a 10 per cent
increase over the quarterly dividends declared in the same period of 2016.
Canadian Utilities’ annual dividend per share has increased for 45 consecutive
years.

RECENT DEVELOPMENTS

/T/

— On June 19, 2017, the AUC issued a decision on Electric Transmission’s

Compliance Filing relating to its 2015 to 2017 GTA. This decision
adjusted Electric Transmission’s 2016 and 2017 forecast allocation of
labour costs between O&M expense and capital, and reduced second quarter
2017 adjusted earnings by $7 million. Without the one-time earnings
adjustment from this decision related to 2016 and the first quarter of
2017, Canadian Utilities’ earnings in the second quarter 2017 were $135
million on a normalized basis.

— On July 13, 2017, Dominion Bond Rating Service affirmed its ‘A (high)’

long-term corporate credit rating and stable outlook on Canadian
Utilities Limited subsidiary CU Inc.

— On July 25, 2017, Standard & Poor’s Ratings Service revised its long-

term corporate credit rating from ‘A’ with a negative outlook to ‘A-‘
with a stable outlook on Canadian Utilities Limited and subsidiary CU
Inc.

— On July 26, 2017, Standard & Poor’s Ratings Service revised its long-

term corporate credit rating from ‘A-‘ to ‘BBB+’ with a stable outlook
for ATCO Gas Australia LP.

/T/

FINANCIAL SUMMARY AND RECONCILIATION OF ADJUSTED EARNINGS

A financial summary and reconciliation of adjusted earnings to earnings
attributable to Class A and Class B shares is provided below:

/T/

For the Three Months For the Six Months
Ended June 30 Ended June 30
—————————————————————————-
($ millions except share data) 2017 2016 2017 2016
—————————————————————————-
—————————————————————————-

Adjusted earnings (1) 129 131 344 328
Gain on sales of operations (2) – – 30 13
Unrealized losses on mark-to-
market forward commodity
contracts (2) (26) – (31) –
Rate-regulated activities (2) (30) (40) (57) (75)
Dividends on equity preferred
shares 17 17 34 34
Other (3) 3 – 3 –
—————————————————————————-
Earnings attributable to Class A
and Class B shares 93 108 323 300
—————————————————————————-
Weighted average shares
outstanding (millions of
shares) 269.2 267.0 268.8 266.8
—————————————————————————-
—————————————————————————-
(1) Adjusted earnings are defined as earnings attributable to Class A and
Class B shares after adjusting for the timing of revenues and expenses
associated with rate-regulated activities, dividends on equity preferred
shares of the Company, and unrealized gains or losses on mark-to-market
forward commodity contracts. Adjusted earnings also exclude one-time
gains and losses, significant impairments, and items that are not in the
normal course of business or a result of day-to-day operations. Adjusted
earnings present earnings on the same basis as was used prior to
adopting International Financial Reporting Standards (IFRS) – that basis
being the U.S. accounting principles for rate- regulated entities – and
they are a key measure used to assess segment performance, to reflect
the economics of rate regulation and to facilitate comparability of
Canadian Utilities’ earnings with other Canadian rate-regulated
companies.
(2) Refer to Note 3 of the consolidated financial statements for detailed
descriptions of the adjustments.
(3)The Company adjusted for the deferred tax asset which was recognized as
a result of the Tula Pipeline Project impairment. The adjustment is due
to a difference between the tax base currency, which is Mexican pesos,
and the U.S. dollar functional currency.

/T/

This news release should be used as a preparation for reading the full
disclosure documents. Canadian Utilities’ consolidated financial statements and
management’s discussion and analysis for the quarter ended June 30, 2017 will
be available on the Canadian Utilities website (www.canadianutilities.com), via
SEDAR (www.sedar.com) or can be requested from the Company.

With approximately 5,400 employees and assets of $19 billion, Canadian
Utilities Limited is an ATCO company. ATCO is a diversified global corporation
delivering service excellence and innovative business solutions in Structures &
Logistics (workforce housing, innovative modular facilities, construction, site
support services, and logistics and operations management); Electricity
(electricity generation, transmission, and distribution); Pipelines & Liquids
(natural gas transmission, distribution and infrastructure development, energy
storage, and industrial water solutions); and Retail Energy (electricity and
natural gas retail sales). More information can be found at
www.canadianutilities.com.

Forward-Looking Information:

Certain statements contained in this news release may constitute
forward-looking information. Forward-looking information is often, but not
always, identified by the use of words such as “anticipate”, “plan”,
“estimate”, “expect”, “may”, “will”, “intend”, “should”, and similar
expressions.

Forward-looking 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.

The Company’s actual results could differ materially from those anticipated in
this forward-looking information as a result of regulatory decisions,
competitive factors in the industries in which the Company operates, prevailing
economic conditions, and other factors, many of which are beyond the control of
the Company.

The Company believes that the expectations reflected in the forward-looking
information are reasonable, but no assurance can be given that these
expectations will prove to be correct and such forward-looking information
should not be unduly relied upon.

Any forward-looking information contained in this news release represents the
Company’s expectations as of the date hereof, and is subject to change after
such date. The Company disclaims any intention or obligation to update or
revise any forward-looking information whether as a result of new information,
future events or otherwise, except as required by applicable securities
legislation.

– END RELEASE – 27/07/2017

For further information:
Media & Investor Inquiries:
D.A. (Dennis) DeChamplain
Senior Vice President &
Chief Financial Officer
403-292-7502

COMPANY:
FOR: CANADIAN UTILITIES LIMITED
TSX SYMBOL: CU
TSX SYMBOL: CU.X
TSX SYMBOL: CU.PR.C
TSX SYMBOL: CU.PR.D
TSX SYMBOL: CU.PR.E
TSX SYMBOL: CU.PR.F
TSX SYMBOL: CU.PR.G

INDUSTRY: Energy and Utilities – Utilities, Energy and Utilities –
Pipelines
RELEASE ID: 20170727CC0021

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.

New SHOWCASE Directory Companies

 

Environmental Refueling Systems (ERS)
Techmation Electric & Controls
Predator Drilling
Galloway Construction Group
Assetworks
FUELware
Galdos Systems
Versa-Line

Crescent Point Announces Strong Q2 2017 Results and Upwardly Revised 2017 Guidance

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

Date issue: July 27, 2017
Time in: 6:30 AM e

Attention:

CALGARY, ALBERTA–(Marketwired – July 27, 2017) –

All financial figures are approximate and in Canadian dollars unless otherwise
noted. This press release contains forward-looking information and references
to non-GAAP financial measures. Significant related assumptions and risk
factors, and reconciliations are described under the Non-GAAP Financial
Measures and the Forward-Looking Statements and Reserves Data sections of this
press release, respectively.

Crescent Point Energy Corp. (“Crescent Point” or the “Company”)
(TSX:CPG)(NYSE:CPG) is pleased to announce its operating and financial results
for the quarter ended June 30, 2017.

KEY HIGHLIGHTS

/T/

— Exceeded second quarter 2017 average production target by over 8,000

boe/d or five percent.
— Increased 2017 average production guidance to 174,500 boe/d from 172,000
boe/d based on positive operating results.
— Delivered strong initial 30-day production rates of approximately 1,000
boe/d in the Castle Peak zone.
— Completed a successful Wasatch well currently flowing at approximately
2,000 boe/d.

/T/

“Our strong operational results have driven one of our best quarters leading to
an increased 2017 guidance,” said Scott Saxberg, president and CEO of Crescent
Point. “The Company’s production outperformance includes the progression of the
Uinta Basin’s horizontal drilling program. Recent well results demonstrate new
zone potential and initial production rates above our current type curve.”

OPERATIONAL HIGHLIGHTS

/T/

— Crescent Point achieved average production of 175,615 boe/d, an increase

of approximately five percent from second quarter 2016. This represents
annualized growth of over 12 percent compared to third quarter 2016 when
the Company first accelerated its capital program due to its new play
development success.
— In the Uinta Basin, Crescent Point advanced its Castle Peak play with
extended reach horizontals and increased tonnage per stage of
completion. Initial production from each of the two programs is
encouraging with 30-day rates upward of 1,000 boe/d. The Company’s
current one-mile Castle Peak horizontal type curve generates 30-day
rates of 620 boe/d. Crescent Point also completed a one-mile horizontal
well in the Wasatch zone late second quarter. This well is currently
flowing at approximately 2,000 boe/d, with an initial 30-day rate of
approximately 1,700 boe/d.
— In the Williston Basin and southwest Saskatchewan resource plays, the
Company focused on low-risk, high-return infill development and down-
spacing programs. Crescent Point’s 2017 waterflood strategy remains
centered on implementing its Injection Control Device (“ICD”) waterflood
systems. The Company currently has 40 ICD waterflood systems in place
with approximately 10 additional installations planned for the remainder
of 2017.

/T/

FINANCIAL HIGHLIGHTS

/T/

— Funds flow from operations totaled $418.0 million or $0.77 per share

diluted. Crescent Point achieved a payout ratio of 12 percent based on
cash dividends paid of $0.09 per share.
— The Company spent $230.2 million on drilling and development activities
during second quarter, drilling 85.0 (66.8 net) wells. Crescent Point’s
total capital expenditures, including land, seismic and facilities, were
$294.6 million and resulted in a total payout ratio, including cash
dividends, of 82 percent.
— As part of its risk management program, the Company hedged 736,000
barrels of oil during second quarter 2017. As at July 24, 2017, 39
percent of Crescent Point’s second half 2017 oil production, net of
royalty interest, and 13 percent of its first half 2018 oil production,
are both hedged at a weighted average market value price of
approximately CDN$70.00/bbl. The Company also has a significant amount
of natural gas production hedged through 2019 at a weighted average
price of CDN$2.85/GJ.
— Crescent Point is currently marketing or in negotiations to dispose of
certain non-core assets with an aggregate value of approximately $180
million and expects to transact on the majority of these sales during
the second half of 2017. The Company plans to market an additional asset
package of similar value later this year. During second quarter,
Crescent Point completed its previously announced disposition for $93.2
million.
— During second quarter, the Company acquired approximately 80,000 net
acres of undeveloped land in the western portion of the Uinta Basin.
These lands provide Crescent Point the opportunity to transfer its
horizontal development expertise to a new operating area with multi-zone
potential.
— In June 2017, the Company successfully renewed its covenant-based,
unsecured credit facilities totaling $3.6 billion, with a maturity date
extension to June 10, 2020. Crescent Point retains a significant amount
of liquidity with no material near-term debt maturities. As at June 30,
2017, the Company’s unutilized credit capacity was approximately $1.5
billion, not reflecting asset dispositions expected to be completed
subsequent to second quarter.

/T/

OUTLOOK AND INCREASED 2017 GUIDANCE

Crescent Point is increasing its 2017 average production guidance to 174,500
boe/d, up from 172,000 boe/d, based on strong operating results and
better-than-expected spring break-up conditions. The Company’s exit guidance
remains at 183,000 boe/d as it is in the process of disposing additional
non-core assets.

“We are executing our organic growth strategy and expect to meet or exceed our
2017 exit production guidance,” said Saxberg. “Our team has been successful
with cost control initiatives and we remain on track with our budget. Given our
strong operating results to date, we do not anticipate the need to change our
capital program and expect to achieve per share growth of 10 percent.”

Total capital expenditures budgeted for 2017, excluding property and land
acquisitions, is unchanged at $1.45 billion. Although pressure pumping and
steel costs increased during second quarter, the overall impact to Crescent
Point’s budget remains in line with expectations. The Company is monitoring its
cost assumptions, efficiency improvements and potential cost reductions for the
second half of 2017 in light of the current volatile oil price environment.

“Our five-year plan in the Uinta Basin targets annualized growth upward of 25
percent without factoring in our recent success with extended reach
horizontals, increased tonnage per stage of completion and new zone
scalability,” said Saxberg. “We intend on advancing the play’s growth potential
with our approximately 287,000 net acres, of which we have delineated only 11
percent to date.”

The Company is committed to maintaining a strong financial position by
balancing its cash outflows with inflows, including acquisitions and
dispositions. Crescent Point remains focused on the organic development of its
land base of approximately four million net acres and further improving its
capital efficiencies through cost reduction initiatives.

OPERATIONS REVIEW

Drilling Results

The following table summarizes Crescent Point’s drilling results for the three
months ended June 30, 2017:

/T/

—————————————————————————-
Three months ended June 30, 2017 Gas Oil D&A Service Standing
—————————————————————————-
Williston Basin (1) – 47 – 1 –
Southwest Saskatchewan – 18 – – –
Uinta Basin (1) – 14 – – –
Other – 5 – – –
—————————————————————————-
Total – 84 – 1 –
—————————————————————————-

——————————————————————-
Three months ended June 30, 2017 Total Net % Success
——————————————————————-
Williston Basin (1) 48 38.9 100
Southwest Saskatchewan 18 17.2 100
Uinta Basin (1) 14 5.4 100
Other 5 5.3 100
——————————————————————-
Total 85 66.8 100
——————————————————————-
(1) The net well count is subject to final working interest determination

/T/

Second Quarter Operations Highlights and Summary

In the Williston Basin and southwest Saskatchewan resource plays, the Company’s
development strategy continues to include a combination of low-risk,
high-return infill development, step-out drilling to expand economic boundaries
and down-spacing to identify new drilling locations.

Crescent Point’s 2017 waterflood strategy remains focused on implementing its
ICD waterflood systems, which increased water injectivity in an initial pilot.
The Company currently has 40 ICD waterflood systems in place with encouraging
initial results. Approximately 10 additional ICD waterflood systems are
expected to be implemented in 2017.

During second quarter, Crescent Point’s Innes Unit became effective within the
Viewfield Bakken resource play. This is the Company’s second unit to become
effective within the play and the sixth unit that Crescent Point has
implemented overall. Full unitization allows for accelerated waterflood
development and is expected to help manage reservoir pressure in a larger
portion of the pool.

In the Uinta Basin, the Company advanced its Castle Peak one-mile horizontal
program with increased tonnage per stage of completion and two-mile extended
laterals. Initial production results from both programs are strong with 30-day
rates upward of 1,000 boe/d. Crescent Point’s current one-mile type curve
generates initial 30-day rates of 620 boe/d.

The Company’s 2017 Uinta Basin program also incorporates the delineation of new
zones, including the Wasatch and Uteland Butte. Crescent Point’s recent
one-mile horizontal well in the Wasatch zone is currently flowing at
approximately 2,000 boe/d with an initial 30-day rate of approximately 1,700
boe/d. This horizontal well is among the best the Company has drilled within
the basin.

Crescent Point continues to monitor these results as it optimizes its
completions process in the Uinta Basin and expects to update its horizontal
inventory toward the end of the year. The Company is also pleased to report
that as part of its environmental initiatives, it has nearly eliminated the use
of fresh water in its current completions process in the basin. Economics in
the Uinta Basin remain strong with realized pricing, including transportation
costs, above 90 percent of WTI based on spot differentials.

DISPOSITIONS UPDATE

Crescent Point is currently marketing or in negotiations to dispose of certain
non-core assets with an aggregate value of approximately $180 million and
expects to transact on the majority of these sales during the second half of
2017. The Company also plans to market an additional asset package of similar
value later this year, with proceeds to be redeployed toward debt reduction or
additional growth opportunities. During second quarter, Crescent Point
completed its previously announced disposition of non-operated conventional
assets in Manitoba for $93.2 million.

During second quarter, the Company completed two Uinta Basin acquisitions to
top up and consolidate approximately 80,000 net acres of undeveloped land.
Total cash consideration was US$72.5 million and includes 1,700 boe/d of
production.

“We remain focused on internally funding acquisitions through non-core asset
sales,” said Saxberg. “Proceeds from these dispositions increase our financial
flexibility as we execute our organic growth strategy.”

Crescent Point believes the acquired Uinta Basin lands to be highly prospective
based on extensive geological mapping. These lands provide the Company the
opportunity to identify additional horizontal locations and come with operating
control of lands in a new area on the western portion of the basin. Crescent
Point’s current land position in Uinta is approximately 287,000 net acres, an
increase of approximately 66 percent since its initial entry in late 2012.

CONFERENCE CALL DETAILS

Crescent Point management will host a conference call on Thursday, July 27,
2017 at 10:00 a.m. MST (12:00 p.m. EST) to discuss the results and outlook for
the Company.

Participants can access the conference call by dialing 844-231-0101 or
216-562-0389 and entering the passcode 57116209. Alternatively, to listen to
this event online, please enter http://edge.media-server.com/m/p/fqgj32jf into
any web browser.

For those unable to participate in the conference call at the scheduled time,
it will be archived for replay. The replay can be accessed by dialing
404-537-3406 or 855-859-2056 and entering the passcode 57116209. The replay
will be available approximately one hour following completion of the call. The
webcast will be archived on Crescent Point’s website at
www.crescentpointenergy.com.

Shareholders and investors can also find Crescent Point’s most recent investor
presentation on the Company’s website.

2017 GUIDANCE

The Company’s guidance for 2017 is as follows:

/T/

—————————————————————————-
Production Prior Revised
Oil and NGLs (bbls/d) 154,000 157,500
Natural gas (mcf/d) 108,000 102,000
—————————————————————————-
Total average annual production (boe/d) 172,000 174,500
—————————————————————————-
Exit production (boe/d) 183,000 183,000
—————————————————————————-
Capital expenditures (1)
Drilling and development ($millions) $1,290 $160
Facilities and seismic ($millions) $1,290 $160
—————————————————————————-
Total ($millions) $1,450 $1,450
—————————————————————————-
(1) The projection of capital expenditures excludes property and land
acquisitions, which are separately considered and evaluated.

/T/

ON BEHALF OF THE BOARD OF DIRECTORS

/T/

Scott Saxberg
President and Chief Executive Officer
July 27, 2017

/T/

The Company’s unaudited financial statements and management’s discussion and
analysis for the quarter ended June 30, 2017, are available on the System for
Electronic Document Analysis and Retrieval (“SEDAR”) at www.sedar.com, on EDGAR
at www.sec.gov/edgar.shtml and on Crescent Point’s website at
www.crescentpointenergy.com.

FINANCIAL AND OPERATING HIGHLIGHTS

/T/

—————————————————————————-

Three months Six months
ended June 30 ended June 30
——————————————–
(Cdn$ millions except per share
and per boe amounts) 2017 2016 2017 2016
—————————————————————————-
Financial
Cash flow from operating
activities 415.9 427.5 832.1 755.6
Funds flow from operations (1) 418.0 404.4 845.1 782.4
Per share (2) 0.77 0.79 1.55 1.54
Net income (loss) 83.6 (226.1) 203.0 (313.6)
Per share (2) 0.15 (0.45) 0.37 (0.62)
Adjusted net earnings from
operations (1) 39.5 15.1 101.4 9.9
Per share (1) (2) 0.07 0.03 0.19 0.02
Dividends declared 49.4 46.0 98.8 163.9
Per share (2) 0.09 0.09 0.18 0.32
Payout ratio (%) (1) 12 11 12 21
Net debt (1) 3,963.4 4,038.7 3,963.4 4,038.7
Net debt to funds flow from
operations (1) (3) 2.4 2.3 2.4 2.3
Climate change initiatives and
asset retirement (4) 8.2 3.2 17.5 14.0
Weighted average shares
outstanding
Basic 544.9 506.3 544.7 506.0
Diluted 546.1 509.1 546.5 508.6
—————————————————————————-
Operating
Average daily production
Crude oil (bbls/d) 140,878 132,730 140,095 138,351
NGLs (bbls/d) 17,658 16,870 17,361 16,822
Natural gas (mcf/d) 102,471 105,709 102,133 105,340
—————————————————————————-
Total (boe/d) 175,615 167,218 174,478 172,730
—————————————————————————-
Average selling prices (5)
Crude oil ($/bbl) 58.09 50.31 58.55 43.00
NGLs ($/bbl) 25.28 14.18 25.24 11.34
Natural gas ($/mcf) 3.03 1.72 3.04 1.88
—————————————————————————-
Total ($/boe) 50.92 42.45 51.30 36.69
—————————————————————————-
Netback ($/boe)
Oil and gas sales 50.92 42.45 51.30 36.69
Royalties (7.59) (5.79) (7.44) (5.10)
Operating expenses (12.85) (10.88) (12.38) (10.53)
Transportation expenses (2.19) (2.18) (2.15) (2.20)
—————————————————————————-
Netback before hedging 28.29 23.60 29.33 18.86
Realized gain on derivatives 1.45 7.62 1.08 10.44
—————————————————————————-
Netback (1) 29.74 31.22 30.41 29.30
—————————————————————————-
Capital Expenditures
Capital acquisitions (net) (6) 33.0 (0.3) 170.5 8.3
Development capital expenditures
(4)
Drilling and development 230.2 51.4 695.7 320.6
Facilities and seismic 34.1 24.7 87.9 67.8
Land 30.3 4.1 43.1 13.6
—————————————————————————-
Total 294.6 80.2 826.7 402.0
—————————————————————————-
(1) Funds flow from operations, adjusted net earnings from operations,
payout ratio, net debt, net debt to funds flow from operations and
netback as presented do not have any standardized meaning prescribed by
IFRS and, therefore, may not be comparable with the calculation of
similar measures presented by other entities.
(2) The per share amounts (with the exception of dividends per share) are
the per share – diluted amounts.
(3) Net debt to funds flow from operations is calculated as the period end
net debt divided by the sum of funds flow from operations for the
trailing four quarters.
(4) Climate change initiatives and asset retirement includes environmental
emission reduction expenditures, which are also included in development
capital expenditures in the table above.
(5) The average selling prices reported are before realized derivatives.
(6) Capital acquisitions represent total consideration for the transactions,
including long-term debt and working capital assumed, and exclude
transaction costs.

/T/

Non-GAAP Financial Measures

Throughout this press release, the Company uses the terms “funds flow from
operations”, “funds flow from operations per share – diluted”, “adjusted net
earnings from operations”, “adjusted net earnings from operations per share –
diluted”, “net debt”, “net debt to funds flow from operations”, “netback”,
“payout ratio” and “total payout ratio”. These terms do not have any
standardized meaning as prescribed by IFRS and, therefore, may not be
comparable with the calculation of similar measures presented by other issuers.

Funds flow from operations is calculated based on cash flow from operating
activities before changes in non-cash working capital, transaction costs and
decommissioning expenditures. Funds flow from operations per share – diluted is
calculated as funds flow from operations divided by the number of weighted
average diluted shares outstanding. Transaction costs are excluded as they vary
based on the Company’s acquisition activity, and to ensure that this metric is
more comparable between periods. Decommissioning expenditures are excluded as
the Company has a voluntary reclamation fund to fund decommissioning costs.
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. Funds flow 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.

The following table reconciles cash flow from operating activities to funds
flow from operations:

/T/

—————————————————————————-

Three months Six months
ended June 30 ended June 30
($ millions) 2017 2016 2017 2016
—————————————————————————-
Cash flow from operating
activities 415.9 427.5 832.1 755.6
Changes in non-cash working
capital (3.3) (25.8) (1.7) 19.5
Transaction costs 2.2 0.3 2.7 0.6
Decommissioning expenditures 3.2 2.4 12.0 6.7
—————————————————————————-
Funds flow from operations 418.0 404.4 845.1 782.4
—————————————————————————-

/T/

Adjusted net earnings from operations is calculated based on net income before
amortization of exploration and evaluation (“E&E”) undeveloped land, impairment
or impairment recoveries on property, plant and equipment (“PP&E”), unrealized
derivative gains or losses, unrealized foreign exchange gain or loss on
translation of hedged US dollar long-term debt, unrealized gains or losses on
long-term investments and gains or losses on capital acquisitions and
dispositions. Adjusted net earnings from operations per share – diluted is
calculated as adjusted net earnings from operations divided by the number of
weighted average diluted shares outstanding. Management utilizes adjusted net
earnings from operations to present a measure of financial performance that is
more comparable between periods. Adjusted net earnings from operations as
presented is not intended to represent net earnings or other measures of
financial performance calculated in accordance with IFRS.

The following table reconciles net income to adjusted net earnings from
operations:

/T/

—————————————————————————-

Three months Six months
ended June 30 ended June 30
($ millions) 2017 2016 2017 2016
—————————————————————————-
Net income (loss) 83.6 (226.1) 203.0 (313.6)
Amortization of E&E undeveloped
land 34.8 48.9 65.8 99.2
Unrealized derivative (gains)
losses 14.7 237.8 (74.4) 536.4
Unrealized foreign exchange
(gain) loss on translation of
hedged US dollar long-term
debt (111.2) 50.3 (134.1) (180.2)
Unrealized (gain) loss on long-
term investments 3.4 (2.8) 6.6 (4.9)
Deferred tax relating to
adjustments 14.2 (93.0) 34.5 (127.0)
—————————————————————————-
Adjusted net earnings from
operations 39.5 15.1 101.4 9.9
—————————————————————————-

/T/

Net debt is calculated as long-term debt plus accounts payable and accrued
liabilities and dividends payable, less cash, accounts receivable, prepaids and
deposits and long-term investments, excluding the unrealized foreign exchange
on translation of US dollar long-term debt. Management utilizes net debt as a
key measure to assess the liquidity of the Company.

The following table reconciles long-term debt to net debt:

/T/

—————————————————————————-

June 30, June 30,
($ millions) 2017 2016
—————————————————————————-
Long-term debt (1) 4,081.6 4,233.9
Accounts payable and accrued liabilities 539.2 446.3
Dividends payable 16.6 15.2
Cash (55.6) (4.2)
Accounts receivable (294.5) (259.1)
Prepaids and deposits (8.2) (7.2)
Long-term investments (29.2) (35.2)
Excludes:
Unrealized foreign exchange on translation of US
dollar long-term debt (286.5) (351.0)
—————————————————————————-
Net debt 3,963.4 4,038.7
—————————————————————————-
(1) Includes current portion of long-term debt.

/T/

Net debt to funds flow from operations is calculated as the period end net debt
divided by the sum of funds flow from operations for the trailing four
quarters. The ratio of net debt to funds flow from operations is used by
management to measure the Company’s overall debt position and to measure the
strength of the Company’s balance sheet. Crescent Point monitors this ratio and
uses this as a key measure in making decisions regarding financing, capital
spending and dividend levels.

Netback is calculated on a per boe basis as oil and gas sales, less royalties,
operating and transportation expenses and realized derivative gains and losses.
Netback is a common metric used in the oil and gas industry and is used by
management to measure operating results on a per boe basis to better analyze
performance against prior periods on a comparable basis. The calculation of
netback is shown in the Financial and Operating Highlights section in this
press release.

Payout ratio is calculated on a percentage basis as dividends declared divided
by funds flow from operations. Payout ratio is used by management to monitor
the dividend policy and the amount of funds flow from operations retained by
the Company for capital reinvestment.

Total payout ratio is calculated on a percentage basis as development capital
expenditures and dividends declared divided by funds flow from operations.
Total payout ratio is used by management to monitor the Company’s capital
reinvestment and dividend policy, as a percentage of the amount of funds flow
from operations.

Management believes the presentation of the Non-GAAP measures above provide
useful information to investors and shareholders as the measures provide
increased transparency and the ability to better analyze performance against
prior periods on a comparable basis.

Forward-Looking Statements and Other Matters

Any “financial outlook” or “future oriented financial information” in this
press release, as defined by applicable securities legislation has been
approved by management of Crescent Point. Such financial outlook or future
oriented financial information is provided for the purpose of providing
information about management’s current expectations and plans relating to the
future. Readers are cautioned that reliance on such information may not be
appropriate for other purposes.

Certain statements contained in this press release constitute “forward-looking
statements” within the meaning of section 27A of the Securities Act of 1933 and
section 21E of the Securities Exchange Act of 1934 and “forward-looking
information” for the purposes of Canadian securities regulation (collectively,
“forward-looking statements”). The Company has tried to identify such
forward-looking statements by use of such words as “could”, “should”, “can”,
“anticipate”, “expect”, “believe”, “will”, “may”, “intend”, “projected”,
“sustain”, “continues”, “strategy”, “potential”, “projects”, “grow”, “take
advantage”, “estimate”, “well-positioned” and other similar expressions, but
these words are not the exclusive means of identifying such statements.

In particular, this press release contains forward-looking statements
pertaining, among other things, to the following: growth plan targets for the
Uinta Basin under the Company’s five year plan; Crescent Point’s 2017
waterflood strategy, including ICD installation plans for the remainder of the
year; the Company’s third quarter and remaining year disposition strategy,
expectations and planned use of proceeds therefrom; the Company’s 2017 average
and exit production guidance, including associated capital allocations;
expected future production growth in the U.S.; 2017 capital expenditure
expectations (excluding property and land acquisitions); the Company’s
expectation that it will meet or exceed its 2017 targeted exit production
guidance and the flexibility of the Company’s capital program; the Company’s
annualized growth targets for the Uinta Basin under its five-year plan and how
such growth is expected to be driven; Crescent Point’s commitment to maintain a
strong financial position; the Company’s continued focus on the organic
development of its land base and further improving its capital efficiencies;
the Company’s development strategy for the Williston Basin and southwest
Saskatchewan; Crescent Point’s 2017 waterflood strategy and expectations; the
expectation that unitization of the Innes Unit will allow for accelerated
waterflood development and is expected to help manage reservoir pressure;
Crescent Point’s expectation that it will update its current horizontal
inventory in the Uinta Basin towards the end of 2017; the Company’s 2017
development plans for the Uinta Basin; the Company’s asset disposition plans
and its focus on internally funding acquisitions through non-core dispositions
and the benefit expected from the proceeds of dispositions; and the Company’s
belief that recently acquired Uinta Basin lands are prospective, allowing the
potential to identify new horizontal locations within multiple zones.

All forward-looking statements are based on Crescent Point’s beliefs and
assumptions based on information available at the time the assumption was made.
Crescent Point believes that 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 report should not be unduly relied upon. By their nature, such
forward-looking statements are subject to a number of risks, uncertainties and
assumptions, which could cause actual results or other expectations to differ
materially from those anticipated, expressed or implied by such statements,
including those material risks discussed in the Company’s Annual Information
Form for the year ended December 31, 2016 under “Risk Factors,” in our
Management’s Discussion and Analysis for the year ended December 31, 2016,
under the headings “Risk Factors” and “Forward-Looking Information” and for the
quarter ended June 30, 2017 under “Derivatives”, “Liquidity and Capital
Resources”, “Changes in Accounting Policy” and “Outlook”. The material
assumptions are disclosed in the Management’s Discussion and Analysis for the
year ended December 31, 2016, under the headings “Capital Expenditures”,
“Liquidity and Capital Resources”, “Critical Accounting Estimates”, “Risk
Factors”, “Changes in Accounting Policies” and “Outlook” and are disclosed in
the Management’s Discussion and Analysis for the quarter ended June 30, 2017
under the headings “Derivatives”, “Liquidity and Capital Resources”, “Changes
in Accounting Policy” and “Outlook”.

In addition, risk factors include: financial risk of marketing reserves at an
acceptable price given market conditions; volatility in market prices for oil
and natural gas; delays in business operations, pipeline restrictions,
blowouts; the risk of carrying out operations with minimal environmental
impact; industry conditions including changes in laws and regulations and the
adoption of new environmental laws and regulations and changes in how they are
interpreted and enforced; risks and uncertainties related to all oil and gas
interests and operations on tribal lands; uncertainties associated with
estimating oil and natural gas reserves; economic risk of finding and producing
reserves at a reasonable cost; uncertainties associated with partner plans and
approvals; operational matters related to non-operated properties; competition
for, among other things, capital, acquisitions of reserves and undeveloped
lands; competition for and availability of qualified personnel or management;
incorrect assessments of the value of acquisitions and exploration and
development programs; unexpected geological, technical, drilling, construction
and processing problems; availability of insurance; fluctuations in foreign
exchange and interest rates; stock market volatility; failure to realize the
anticipated benefits of acquisitions; general economic, market and business
conditions; uncertainties associated with regulatory approvals; uncertainty of
government policy changes; uncertainties associated with credit facilities and
counterparty credit risk; and changes in income tax laws, tax laws, crown
royalty rates and incentive programs relating to the oil and gas industry; and
other factors, many of which are outside the control of Crescent Point. 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
Crescent Point’s future course of action depends on management’s assessment of
all information available at the relevant time.

Additional information on these and other factors that could affect Crescent
Point’s operations or financial results are included in Crescent Point’s
reports on file with Canadian and U.S. securities regulatory authorities.
Readers are cautioned not to place undue reliance on this forward-looking
information, which is given as of the date it is expressed herein or otherwise.
Crescent Point undertakes no obligation to update publicly or revise any
forward-looking statements, whether as a result of new information, future
events or otherwise, unless required to do so pursuant to applicable law. All
subsequent forward-looking statements, whether written or oral, attributable to
Crescent Point or persons acting on the Company’s behalf are expressly
qualified in their entirety by these cautionary statements.

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

/T/

Crescent Point Energy Corp.
Suite 2000, 585 – 8th Avenue S.W.
Calgary, Alberta T2P 1G1

/T/

– END RELEASE – 27/07/2017

For further information:
Crescent Point Energy Corp.
Ken Lamont
Chief Financial Officer
(403) 693-0020 or Toll-free (US & 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 (US & 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: 20170727CC0011

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.

New SHOWCASE Directory Companies

 

Techmation Electric & Controls
Galloway Construction Group
Predator Drilling
Environmental Refueling Systems (ERS)
FUELware
Versa-Line
Galdos Systems
Assetworks

Crescent Point Announces Strong Q2 2017 Results and Upwardly Revised 2017 Guidance

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

Date issue: July 27, 2017
Time in: 6:30 AM e

Attention:

CALGARY, ALBERTA–(Marketwired – July 27, 2017) –

All financial figures are approximate and in Canadian dollars unless otherwise
noted. This press release contains forward-looking information and references
to non-GAAP financial measures. Significant related assumptions and risk
factors, and reconciliations are described under the Non-GAAP Financial
Measures and the Forward-Looking Statements and Reserves Data sections of this
press release, respectively.

Crescent Point Energy Corp. (“Crescent Point” or the “Company”)
(TSX:CPG)(NYSE:CPG) is pleased to announce its operating and financial results
for the quarter ended June 30, 2017.

KEY HIGHLIGHTS

/T/

— Exceeded second quarter 2017 average production target by over 8,000

boe/d or five percent.
— Increased 2017 average production guidance to 174,500 boe/d from 172,000
boe/d based on positive operating results.
— Delivered strong initial 30-day production rates of approximately 1,000
boe/d in the Castle Peak zone.
— Completed a successful Wasatch well currently flowing at approximately
2,000 boe/d.

/T/

“Our strong operational results have driven one of our best quarters leading to
an increased 2017 guidance,” said Scott Saxberg, president and CEO of Crescent
Point. “The Company’s production outperformance includes the progression of the
Uinta Basin’s horizontal drilling program. Recent well results demonstrate new
zone potential and initial production rates above our current type curve.”

OPERATIONAL HIGHLIGHTS

/T/

— Crescent Point achieved average production of 175,615 boe/d, an increase

of approximately five percent from second quarter 2016. This represents
annualized growth of over 12 percent compared to third quarter 2016 when
the Company first accelerated its capital program due to its new play
development success.
— In the Uinta Basin, Crescent Point advanced its Castle Peak play with
extended reach horizontals and increased tonnage per stage of
completion. Initial production from each of the two programs is
encouraging with 30-day rates upward of 1,000 boe/d. The Company’s
current one-mile Castle Peak horizontal type curve generates 30-day
rates of 620 boe/d. Crescent Point also completed a one-mile horizontal
well in the Wasatch zone late second quarter. This well is currently
flowing at approximately 2,000 boe/d, with an initial 30-day rate of
approximately 1,700 boe/d.
— In the Williston Basin and southwest Saskatchewan resource plays, the
Company focused on low-risk, high-return infill development and down-
spacing programs. Crescent Point’s 2017 waterflood strategy remains
centered on implementing its Injection Control Device (“ICD”) waterflood
systems. The Company currently has 40 ICD waterflood systems in place
with approximately 10 additional installations planned for the remainder
of 2017.

/T/

FINANCIAL HIGHLIGHTS

/T/

— Funds flow from operations totaled $418.0 million or $0.77 per share

diluted. Crescent Point achieved a payout ratio of 12 percent based on
cash dividends paid of $0.09 per share.
— The Company spent $230.2 million on drilling and development activities
during second quarter, drilling 85.0 (66.8 net) wells. Crescent Point’s
total capital expenditures, including land, seismic and facilities, were
$294.6 million and resulted in a total payout ratio, including cash
dividends, of 82 percent.
— As part of its risk management program, the Company hedged 736,000
barrels of oil during second quarter 2017. As at July 24, 2017, 39
percent of Crescent Point’s second half 2017 oil production, net of
royalty interest, and 13 percent of its first half 2018 oil production,
are both hedged at a weighted average market value price of
approximately CDN$70.00/bbl. The Company also has a significant amount
of natural gas production hedged through 2019 at a weighted average
price of CDN$2.85/GJ.
— Crescent Point is currently marketing or in negotiations to dispose of
certain non-core assets with an aggregate value of approximately $180
million and expects to transact on the majority of these sales during
the second half of 2017. The Company plans to market an additional asset
package of similar value later this year. During second quarter,
Crescent Point completed its previously announced disposition for $93.2
million.
— During second quarter, the Company acquired approximately 80,000 net
acres of undeveloped land in the western portion of the Uinta Basin.
These lands provide Crescent Point the opportunity to transfer its
horizontal development expertise to a new operating area with multi-zone
potential.
— In June 2017, the Company successfully renewed its covenant-based,
unsecured credit facilities totaling $3.6 billion, with a maturity date
extension to June 10, 2020. Crescent Point retains a significant amount
of liquidity with no material near-term debt maturities. As at June 30,
2017, the Company’s unutilized credit capacity was approximately $1.5
billion, not reflecting asset dispositions expected to be completed
subsequent to second quarter.

/T/

OUTLOOK AND INCREASED 2017 GUIDANCE

Crescent Point is increasing its 2017 average production guidance to 174,500
boe/d, up from 172,000 boe/d, based on strong operating results and
better-than-expected spring break-up conditions. The Company’s exit guidance
remains at 183,000 boe/d as it is in the process of disposing additional
non-core assets.

“We are executing our organic growth strategy and expect to meet or exceed our
2017 exit production guidance,” said Saxberg. “Our team has been successful
with cost control initiatives and we remain on track with our budget. Given our
strong operating results to date, we do not anticipate the need to change our
capital program and expect to achieve per share growth of 10 percent.”

Total capital expenditures budgeted for 2017, excluding property and land
acquisitions, is unchanged at $1.45 billion. Although pressure pumping and
steel costs increased during second quarter, the overall impact to Crescent
Point’s budget remains in line with expectations. The Company is monitoring its
cost assumptions, efficiency improvements and potential cost reductions for the
second half of 2017 in light of the current volatile oil price environment.

“Our five-year plan in the Uinta Basin targets annualized growth upward of 25
percent without factoring in our recent success with extended reach
horizontals, increased tonnage per stage of completion and new zone
scalability,” said Saxberg. “We intend on advancing the play’s growth potential
with our approximately 287,000 net acres, of which we have delineated only 11
percent to date.”

The Company is committed to maintaining a strong financial position by
balancing its cash outflows with inflows, including acquisitions and
dispositions. Crescent Point remains focused on the organic development of its
land base of approximately four million net acres and further improving its
capital efficiencies through cost reduction initiatives.

OPERATIONS REVIEW

Drilling Results

The following table summarizes Crescent Point’s drilling results for the three
months ended June 30, 2017:

/T/

—————————————————————————-
Three months ended June 30, 2017 Gas Oil D&A Service Standing
—————————————————————————-
Williston Basin (1) – 47 – 1 –
Southwest Saskatchewan – 18 – – –
Uinta Basin (1) – 14 – – –
Other – 5 – – –
—————————————————————————-
Total – 84 – 1 –
—————————————————————————-

——————————————————————-
Three months ended June 30, 2017 Total Net % Success
——————————————————————-
Williston Basin (1) 48 38.9 100
Southwest Saskatchewan 18 17.2 100
Uinta Basin (1) 14 5.4 100
Other 5 5.3 100
——————————————————————-
Total 85 66.8 100
——————————————————————-
(1) The net well count is subject to final working interest determination

/T/

Second Quarter Operations Highlights and Summary

In the Williston Basin and southwest Saskatchewan resource plays, the Company’s
development strategy continues to include a combination of low-risk,
high-return infill development, step-out drilling to expand economic boundaries
and down-spacing to identify new drilling locations.

Crescent Point’s 2017 waterflood strategy remains focused on implementing its
ICD waterflood systems, which increased water injectivity in an initial pilot.
The Company currently has 40 ICD waterflood systems in place with encouraging
initial results. Approximately 10 additional ICD waterflood systems are
expected to be implemented in 2017.

During second quarter, Crescent Point’s Innes Unit became effective within the
Viewfield Bakken resource play. This is the Company’s second unit to become
effective within the play and the sixth unit that Crescent Point has
implemented overall. Full unitization allows for accelerated waterflood
development and is expected to help manage reservoir pressure in a larger
portion of the pool.

In the Uinta Basin, the Company advanced its Castle Peak one-mile horizontal
program with increased tonnage per stage of completion and two-mile extended
laterals. Initial production results from both programs are strong with 30-day
rates upward of 1,000 boe/d. Crescent Point’s current one-mile type curve
generates initial 30-day rates of 620 boe/d.

The Company’s 2017 Uinta Basin program also incorporates the delineation of new
zones, including the Wasatch and Uteland Butte. Crescent Point’s recent
one-mile horizontal well in the Wasatch zone is currently flowing at
approximately 2,000 boe/d with an initial 30-day rate of approximately 1,700
boe/d. This horizontal well is among the best the Company has drilled within
the basin.

Crescent Point continues to monitor these results as it optimizes its
completions process in the Uinta Basin and expects to update its horizontal
inventory toward the end of the year. The Company is also pleased to report
that as part of its environmental initiatives, it has nearly eliminated the use
of fresh water in its current completions process in the basin. Economics in
the Uinta Basin remain strong with realized pricing, including transportation
costs, above 90 percent of WTI based on spot differentials.

DISPOSITIONS UPDATE

Crescent Point is currently marketing or in negotiations to dispose of certain
non-core assets with an aggregate value of approximately $180 million and
expects to transact on the majority of these sales during the second half of
2017. The Company also plans to market an additional asset package of similar
value later this year, with proceeds to be redeployed toward debt reduction or
additional growth opportunities. During second quarter, Crescent Point
completed its previously announced disposition of non-operated conventional
assets in Manitoba for $93.2 million.

During second quarter, the Company completed two Uinta Basin acquisitions to
top up and consolidate approximately 80,000 net acres of undeveloped land.
Total cash consideration was US$72.5 million and includes 1,700 boe/d of
production.

“We remain focused on internally funding acquisitions through non-core asset
sales,” said Saxberg. “Proceeds from these dispositions increase our financial
flexibility as we execute our organic growth strategy.”

Crescent Point believes the acquired Uinta Basin lands to be highly prospective
based on extensive geological mapping. These lands provide the Company the
opportunity to identify additional horizontal locations and come with operating
control of lands in a new area on the western portion of the basin. Crescent
Point’s current land position in Uinta is approximately 287,000 net acres, an
increase of approximately 66 percent since its initial entry in late 2012.

CONFERENCE CALL DETAILS

Crescent Point management will host a conference call on Thursday, July 27,
2017 at 10:00 a.m. MST (12:00 p.m. EST) to discuss the results and outlook for
the Company.

Participants can access the conference call by dialing 844-231-0101 or
216-562-0389 and entering the passcode 57116209. Alternatively, to listen to
this event online, please enter http://edge.media-server.com/m/p/fqgj32jf into
any web browser.

For those unable to participate in the conference call at the scheduled time,
it will be archived for replay. The replay can be accessed by dialing
404-537-3406 or 855-859-2056 and entering the passcode 57116209. The replay
will be available approximately one hour following completion of the call. The
webcast will be archived on Crescent Point’s website at
www.crescentpointenergy.com.

Shareholders and investors can also find Crescent Point’s most recent investor
presentation on the Company’s website.

2017 GUIDANCE

The Company’s guidance for 2017 is as follows:

/T/

—————————————————————————-
Production Prior Revised
Oil and NGLs (bbls/d) 154,000 157,500
Natural gas (mcf/d) 108,000 102,000
—————————————————————————-
Total average annual production (boe/d) 172,000 174,500
—————————————————————————-
Exit production (boe/d) 183,000 183,000
—————————————————————————-
Capital expenditures (1)
Drilling and development ($millions) $1,290 $160
Facilities and seismic ($millions) $1,290 $160
—————————————————————————-
Total ($millions) $1,450 $1,450
—————————————————————————-
(1) The projection of capital expenditures excludes property and land
acquisitions, which are separately considered and evaluated.

/T/

ON BEHALF OF THE BOARD OF DIRECTORS

/T/

Scott Saxberg
President and Chief Executive Officer
July 27, 2017

/T/

The Company’s unaudited financial statements and management’s discussion and
analysis for the quarter ended June 30, 2017, are available on the System for
Electronic Document Analysis and Retrieval (“SEDAR”) at www.sedar.com, on EDGAR
at www.sec.gov/edgar.shtml and on Crescent Point’s website at
www.crescentpointenergy.com.

FINANCIAL AND OPERATING HIGHLIGHTS

/T/

—————————————————————————-

Three months Six months
ended June 30 ended June 30
——————————————–
(Cdn$ millions except per share
and per boe amounts) 2017 2016 2017 2016
—————————————————————————-
Financial
Cash flow from operating
activities 415.9 427.5 832.1 755.6
Funds flow from operations (1) 418.0 404.4 845.1 782.4
Per share (2) 0.77 0.79 1.55 1.54
Net income (loss) 83.6 (226.1) 203.0 (313.6)
Per share (2) 0.15 (0.45) 0.37 (0.62)
Adjusted net earnings from
operations (1) 39.5 15.1 101.4 9.9
Per share (1) (2) 0.07 0.03 0.19 0.02
Dividends declared 49.4 46.0 98.8 163.9
Per share (2) 0.09 0.09 0.18 0.32
Payout ratio (%) (1) 12 11 12 21
Net debt (1) 3,963.4 4,038.7 3,963.4 4,038.7
Net debt to funds flow from
operations (1) (3) 2.4 2.3 2.4 2.3
Climate change initiatives and
asset retirement (4) 8.2 3.2 17.5 14.0
Weighted average shares
outstanding
Basic 544.9 506.3 544.7 506.0
Diluted 546.1 509.1 546.5 508.6
—————————————————————————-
Operating
Average daily production
Crude oil (bbls/d) 140,878 132,730 140,095 138,351
NGLs (bbls/d) 17,658 16,870 17,361 16,822
Natural gas (mcf/d) 102,471 105,709 102,133 105,340
—————————————————————————-
Total (boe/d) 175,615 167,218 174,478 172,730
—————————————————————————-
Average selling prices (5)
Crude oil ($/bbl) 58.09 50.31 58.55 43.00
NGLs ($/bbl) 25.28 14.18 25.24 11.34
Natural gas ($/mcf) 3.03 1.72 3.04 1.88
—————————————————————————-
Total ($/boe) 50.92 42.45 51.30 36.69
—————————————————————————-
Netback ($/boe)
Oil and gas sales 50.92 42.45 51.30 36.69
Royalties (7.59) (5.79) (7.44) (5.10)
Operating expenses (12.85) (10.88) (12.38) (10.53)
Transportation expenses (2.19) (2.18) (2.15) (2.20)
—————————————————————————-
Netback before hedging 28.29 23.60 29.33 18.86
Realized gain on derivatives 1.45 7.62 1.08 10.44
—————————————————————————-
Netback (1) 29.74 31.22 30.41 29.30
—————————————————————————-
Capital Expenditures
Capital acquisitions (net) (6) 33.0 (0.3) 170.5 8.3
Development capital expenditures
(4)
Drilling and development 230.2 51.4 695.7 320.6
Facilities and seismic 34.1 24.7 87.9 67.8
Land 30.3 4.1 43.1 13.6
—————————————————————————-
Total 294.6 80.2 826.7 402.0
—————————————————————————-
(1) Funds flow from operations, adjusted net earnings from operations,
payout ratio, net debt, net debt to funds flow from operations and
netback as presented do not have any standardized meaning prescribed by
IFRS and, therefore, may not be comparable with the calculation of
similar measures presented by other entities.
(2) The per share amounts (with the exception of dividends per share) are
the per share – diluted amounts.
(3) Net debt to funds flow from operations is calculated as the period end
net debt divided by the sum of funds flow from operations for the
trailing four quarters.
(4) Climate change initiatives and asset retirement includes environmental
emission reduction expenditures, which are also included in development
capital expenditures in the table above.
(5) The average selling prices reported are before realized derivatives.
(6) Capital acquisitions represent total consideration for the transactions,
including long-term debt and working capital assumed, and exclude
transaction costs.

/T/

Non-GAAP Financial Measures

Throughout this press release, the Company uses the terms “funds flow from
operations”, “funds flow from operations per share – diluted”, “adjusted net
earnings from operations”, “adjusted net earnings from operations per share –
diluted”, “net debt”, “net debt to funds flow from operations”, “netback”,
“payout ratio” and “total payout ratio”. These terms do not have any
standardized meaning as prescribed by IFRS and, therefore, may not be
comparable with the calculation of similar measures presented by other issuers.

Funds flow from operations is calculated based on cash flow from operating
activities before changes in non-cash working capital, transaction costs and
decommissioning expenditures. Funds flow from operations per share – diluted is
calculated as funds flow from operations divided by the number of weighted
average diluted shares outstanding. Transaction costs are excluded as they vary
based on the Company’s acquisition activity, and to ensure that this metric is
more comparable between periods. Decommissioning expenditures are excluded as
the Company has a voluntary reclamation fund to fund decommissioning costs.
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. Funds flow 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.

The following table reconciles cash flow from operating activities to funds
flow from operations:

/T/

—————————————————————————-

Three months Six months
ended June 30 ended June 30
($ millions) 2017 2016 2017 2016
—————————————————————————-
Cash flow from operating
activities 415.9 427.5 832.1 755.6
Changes in non-cash working
capital (3.3) (25.8) (1.7) 19.5
Transaction costs 2.2 0.3 2.7 0.6
Decommissioning expenditures 3.2 2.4 12.0 6.7
—————————————————————————-
Funds flow from operations 418.0 404.4 845.1 782.4
—————————————————————————-

/T/

Adjusted net earnings from operations is calculated based on net income before
amortization of exploration and evaluation (“E&E”) undeveloped land, impairment
or impairment recoveries on property, plant and equipment (“PP&E”), unrealized
derivative gains or losses, unrealized foreign exchange gain or loss on
translation of hedged US dollar long-term debt, unrealized gains or losses on
long-term investments and gains or losses on capital acquisitions and
dispositions. Adjusted net earnings from operations per share – diluted is
calculated as adjusted net earnings from operations divided by the number of
weighted average diluted shares outstanding. Management utilizes adjusted net
earnings from operations to present a measure of financial performance that is
more comparable between periods. Adjusted net earnings from operations as
presented is not intended to represent net earnings or other measures of
financial performance calculated in accordance with IFRS.

The following table reconciles net income to adjusted net earnings from
operations:

/T/

—————————————————————————-

Three months Six months
ended June 30 ended June 30
($ millions) 2017 2016 2017 2016
—————————————————————————-
Net income (loss) 83.6 (226.1) 203.0 (313.6)
Amortization of E&E undeveloped
land 34.8 48.9 65.8 99.2
Unrealized derivative (gains)
losses 14.7 237.8 (74.4) 536.4
Unrealized foreign exchange
(gain) loss on translation of
hedged US dollar long-term
debt (111.2) 50.3 (134.1) (180.2)
Unrealized (gain) loss on long-
term investments 3.4 (2.8) 6.6 (4.9)
Deferred tax relating to
adjustments 14.2 (93.0) 34.5 (127.0)
—————————————————————————-
Adjusted net earnings from
operations 39.5 15.1 101.4 9.9
—————————————————————————-

/T/

Net debt is calculated as long-term debt plus accounts payable and accrued
liabilities and dividends payable, less cash, accounts receivable, prepaids and
deposits and long-term investments, excluding the unrealized foreign exchange
on translation of US dollar long-term debt. Management utilizes net debt as a
key measure to assess the liquidity of the Company.

The following table reconciles long-term debt to net debt:

/T/

—————————————————————————-

June 30, June 30,
($ millions) 2017 2016
—————————————————————————-
Long-term debt (1) 4,081.6 4,233.9
Accounts payable and accrued liabilities 539.2 446.3
Dividends payable 16.6 15.2
Cash (55.6) (4.2)
Accounts receivable (294.5) (259.1)
Prepaids and deposits (8.2) (7.2)
Long-term investments (29.2) (35.2)
Excludes:
Unrealized foreign exchange on translation of US
dollar long-term debt (286.5) (351.0)
—————————————————————————-
Net debt 3,963.4 4,038.7
—————————————————————————-
(1) Includes current portion of long-term debt.

/T/

Net debt to funds flow from operations is calculated as the period end net debt
divided by the sum of funds flow from operations for the trailing four
quarters. The ratio of net debt to funds flow from operations is used by
management to measure the Company’s overall debt position and to measure the
strength of the Company’s balance sheet. Crescent Point monitors this ratio and
uses this as a key measure in making decisions regarding financing, capital
spending and dividend levels.

Netback is calculated on a per boe basis as oil and gas sales, less royalties,
operating and transportation expenses and realized derivative gains and losses.
Netback is a common metric used in the oil and gas industry and is used by
management to measure operating results on a per boe basis to better analyze
performance against prior periods on a comparable basis. The calculation of
netback is shown in the Financial and Operating Highlights section in this
press release.

Payout ratio is calculated on a percentage basis as dividends declared divided
by funds flow from operations. Payout ratio is used by management to monitor
the dividend policy and the amount of funds flow from operations retained by
the Company for capital reinvestment.

Total payout ratio is calculated on a percentage basis as development capital
expenditures and dividends declared divided by funds flow from operations.
Total payout ratio is used by management to monitor the Company’s capital
reinvestment and dividend policy, as a percentage of the amount of funds flow
from operations.

Management believes the presentation of the Non-GAAP measures above provide
useful information to investors and shareholders as the measures provide
increased transparency and the ability to better analyze performance against
prior periods on a comparable basis.

Forward-Looking Statements and Other Matters

Any “financial outlook” or “future oriented financial information” in this
press release, as defined by applicable securities legislation has been
approved by management of Crescent Point. Such financial outlook or future
oriented financial information is provided for the purpose of providing
information about management’s current expectations and plans relating to the
future. Readers are cautioned that reliance on such information may not be
appropriate for other purposes.

Certain statements contained in this press release constitute “forward-looking
statements” within the meaning of section 27A of the Securities Act of 1933 and
section 21E of the Securities Exchange Act of 1934 and “forward-looking
information” for the purposes of Canadian securities regulation (collectively,
“forward-looking statements”). The Company has tried to identify such
forward-looking statements by use of such words as “could”, “should”, “can”,
“anticipate”, “expect”, “believe”, “will”, “may”, “intend”, “projected”,
“sustain”, “continues”, “strategy”, “potential”, “projects”, “grow”, “take
advantage”, “estimate”, “well-positioned” and other similar expressions, but
these words are not the exclusive means of identifying such statements.

In particular, this press release contains forward-looking statements
pertaining, among other things, to the following: growth plan targets for the
Uinta Basin under the Company’s five year plan; Crescent Point’s 2017
waterflood strategy, including ICD installation plans for the remainder of the
year; the Company’s third quarter and remaining year disposition strategy,
expectations and planned use of proceeds therefrom; the Company’s 2017 average
and exit production guidance, including associated capital allocations;
expected future production growth in the U.S.; 2017 capital expenditure
expectations (excluding property and land acquisitions); the Company’s
expectation that it will meet or exceed its 2017 targeted exit production
guidance and the flexibility of the Company’s capital program; the Company’s
annualized growth targets for the Uinta Basin under its five-year plan and how
such growth is expected to be driven; Crescent Point’s commitment to maintain a
strong financial position; the Company’s continued focus on the organic
development of its land base and further improving its capital efficiencies;
the Company’s development strategy for the Williston Basin and southwest
Saskatchewan; Crescent Point’s 2017 waterflood strategy and expectations; the
expectation that unitization of the Innes Unit will allow for accelerated
waterflood development and is expected to help manage reservoir pressure;
Crescent Point’s expectation that it will update its current horizontal
inventory in the Uinta Basin towards the end of 2017; the Company’s 2017
development plans for the Uinta Basin; the Company’s asset disposition plans
and its focus on internally funding acquisitions through non-core dispositions
and the benefit expected from the proceeds of dispositions; and the Company’s
belief that recently acquired Uinta Basin lands are prospective, allowing the
potential to identify new horizontal locations within multiple zones.

All forward-looking statements are based on Crescent Point’s beliefs and
assumptions based on information available at the time the assumption was made.
Crescent Point believes that 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 report should not be unduly relied upon. By their nature, such
forward-looking statements are subject to a number of risks, uncertainties and
assumptions, which could cause actual results or other expectations to differ
materially from those anticipated, expressed or implied by such statements,
including those material risks discussed in the Company’s Annual Information
Form for the year ended December 31, 2016 under “Risk Factors,” in our
Management’s Discussion and Analysis for the year ended December 31, 2016,
under the headings “Risk Factors” and “Forward-Looking Information” and for the
quarter ended June 30, 2017 under “Derivatives”, “Liquidity and Capital
Resources”, “Changes in Accounting Policy” and “Outlook”. The material
assumptions are disclosed in the Management’s Discussion and Analysis for the
year ended December 31, 2016, under the headings “Capital Expenditures”,
“Liquidity and Capital Resources”, “Critical Accounting Estimates”, “Risk
Factors”, “Changes in Accounting Policies” and “Outlook” and are disclosed in
the Management’s Discussion and Analysis for the quarter ended June 30, 2017
under the headings “Derivatives”, “Liquidity and Capital Resources”, “Changes
in Accounting Policy” and “Outlook”.

In addition, risk factors include: financial risk of marketing reserves at an
acceptable price given market conditions; volatility in market prices for oil
and natural gas; delays in business operations, pipeline restrictions,
blowouts; the risk of carrying out operations with minimal environmental
impact; industry conditions including changes in laws and regulations and the
adoption of new environmental laws and regulations and changes in how they are
interpreted and enforced; risks and uncertainties related to all oil and gas
interests and operations on tribal lands; uncertainties associated with
estimating oil and natural gas reserves; economic risk of finding and producing
reserves at a reasonable cost; uncertainties associated with partner plans and
approvals; operational matters related to non-operated properties; competition
for, among other things, capital, acquisitions of reserves and undeveloped
lands; competition for and availability of qualified personnel or management;
incorrect assessments of the value of acquisitions and exploration and
development programs; unexpected geological, technical, drilling, construction
and processing problems; availability of insurance; fluctuations in foreign
exchange and interest rates; stock market volatility; failure to realize the
anticipated benefits of acquisitions; general economic, market and business
conditions; uncertainties associated with regulatory approvals; uncertainty of
government policy changes; uncertainties associated with credit facilities and
counterparty credit risk; and changes in income tax laws, tax laws, crown
royalty rates and incentive programs relating to the oil and gas industry; and
other factors, many of which are outside the control of Crescent Point. 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
Crescent Point’s future course of action depends on management’s assessment of
all information available at the relevant time.

Additional information on these and other factors that could affect Crescent
Point’s operations or financial results are included in Crescent Point’s
reports on file with Canadian and U.S. securities regulatory authorities.
Readers are cautioned not to place undue reliance on this forward-looking
information, which is given as of the date it is expressed herein or otherwise.
Crescent Point undertakes no obligation to update publicly or revise any
forward-looking statements, whether as a result of new information, future
events or otherwise, unless required to do so pursuant to applicable law. All
subsequent forward-looking statements, whether written or oral, attributable to
Crescent Point or persons acting on the Company’s behalf are expressly
qualified in their entirety by these cautionary statements.

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

/T/

Crescent Point Energy Corp.
Suite 2000, 585 – 8th Avenue S.W.
Calgary, Alberta T2P 1G1

/T/

– END RELEASE – 27/07/2017

For further information:
Crescent Point Energy Corp.
Ken Lamont
Chief Financial Officer
(403) 693-0020 or Toll-free (US & 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 (US & 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: 20170727CC0011

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.

New SHOWCASE Directory Companies

 

Galloway Construction Group
Techmation Electric & Controls
Environmental Refueling Systems (ERS)
Predator Drilling
Assetworks
Versa-Line
Galdos Systems
FUELware

OneSoft Solutions Inc. Provides Business Update and Reports Financial Results for the Three Months Ended May 31, 2017 and Grant of Stock Options

FOR: ONESOFT SOLUTIONS INC.
TSX VENTURE SYMBOL: OSS
OTCQB SYMBOL: OSSIF

Date issue: July 27, 2017
Time in: 6:00 AM e

Attention:

EDMONTON, ALBERTA–(Marketwired – July 27, 2017) – OneSoft Solutions Inc. (the
“Company” or “OSS”) (TSX VENTURE:OSS)(OTCQB:OSSIF), a North American developer
of cloud-based business solutions announces its financial results for the three
months ended May 31, 2017.

Financial results are summarized as follows:

/T/

—————————————————————————-
(In $,000)’s, per share in $ Three months ended May 31,
————————————
Increase /
2017 2016 (Decrease)
—————————————————————————-
$ $ %
————————————

—————————————————————————-

Revenue 223 103 117.5
—————————————————————————-
Operating expenses net of cost
capitalization 721 293 146.1
—————————————————————————-
Other income (expense) 14 (197) (107.2)
—————————————————————————-
Comprehensive net loss (501) (404) 23.8
—————————————————————————-
Weighted average common shares
outstanding – basic and fully diluted
(OOO)’s 81,876 62,543
—————————————————————————-
Comprehensive loss per share (0.01) (0.01) –
—————————————————————————-

————————————
May 31, May 31, Increase /
2017 2016 (Decrease)
————————————
$ $ %
—————————————————————————-
Cash 1,469 806 82.2
—————————————————————————-
Current assets 1,677 1,067 57.2
—————————————————————————-
Total assets 3,322 2,199 51.1
—————————————————————————-
Total liabilities 696 826 (15.7)
—————————————————————————-

/T/

Q1 FISCAL 2018 OPERATIONAL HIGHLIGHTS

Our Cognitive Integrity Management (“CIM”) and HoloLens solutions were
demonstrated at the annual Pipeline Pigging and Integrity Management (“PPIM”)
tradeshow held in Houston, Texas between February 27 and March 3, 2017. On
March 29, 2017, OneBridge presented its solutions at a Pipeline Asset
Management Workshop hosted by Microsoft at their Technology Center in Houston,
which was attended by senior managers from approximately 30 companies who are
responsible for pipeline integrity roles including integrity management,
maintenance, data science, analytics and information technologies. OneBridge
presented from a tradeshow booth at the Banff 2017 Pipeline Workshop from April
3-6, 2017 which focused on various aspects of the oil and gas pipeline
industry, including regulatory and standards development; corrosion; integrity,
and emergency preparedness and response. Microsoft sales teams worked
collaboratively with us by donating computer hardware, personnel and other
resources which assisted our presence at these venues. We consider these
activities as being successful in that they raised awareness of the OneBridge
solution, allowed us to make important industry contacts and initiated interest
with service organizations which could lead to subscriptions to use our product
at some future date.

In the quarter, the Company added to its operational capabilities by hiring
additional software development staff, data scientists, and a marketing
director whom together we believe will reduce our development timelines and
increase our sales and marketing effectiveness.

On March 6, 2017, certain insiders sold some of their shares and used a portion
of the sale proceeds to exercise warrants to replace the shares sold, which
raised $1,822,389 for the Company without incurring any dilution for other
shareholders. The Company completed listing its shares on the U.S. OTCQB market
in May 2017 to provide a venue for U.S. citizens to trade the Company’s shares.

The three months ended May 31, 2017 (“Q1 Fiscal 2018”) was the first full
quarter wherein revenue generation from the Company’s CIM product was recorded
following its commercial market release in January 2017. Revenue for the
quarter was $223,093, of which $210,593 was derived from a CIM SaaS
subscription, versus $102,528 in the same quarter last year, none of which was
due to CIM. Gross profit was $206,255 this quarter versus $85,311 in the
comparative quarter last year. $284,705 of costs met the criteria for
capitalization as software development costs as compared to $309,435 this
period last year. The net loss for the quarter was $500,745 versus $404,473 in
the comparative prior year quarter.

FINANCIAL OUTLOOK FOR FISCAL 2018 AND PROGRESS IN Q1 2018

We continue to focus on the US market with its 2.7 million miles of oil and gas
transmission pipeline infrastructure of which approximately 600,000 miles is
our initial target market, as these are the sections of pipelines that are
accessible by inline inspection tools and have, or could have, ILI data.
OneBridge’s commercial pricing of CIM for Fiscal 2018 is at a fixed fee of USD
$60 (or CAD $78, assuming a currency exchange premium of 30%) per data mile for
one year of service. Azure computing fees are incremental to CIM charge out
rates. Cost of goods sold, with the possible exception of staff salaries
allocated to direct costs, are expected to remain low for the foreseeable
future. In Fiscal 2018, these will be near zero due to Azure costs being offset
by unused Azure credits previously granted by Microsoft, and less than 10% of
revenue thereafter.

In our Q4, Fiscal 2017 MD&A (published on SEDAR on June 1, 2017), we provided a
summary of our revenue and cash expense targets for our fiscal year ending
February 28, 2018 (the “Fiscal 2018 Budget”), along with key factors and
assumptions made by Management. The following table provides updated disclosure
regarding the Company’s Fiscal 2018 Budget and achievement of stated objectives
in Fiscal 2018 Q1 ended May 31, 2017.

/T/

—————————————————————————
Objectives stated for the Fiscal 2018 Updates as at May 31, 2017
Budget published in the Feb. 28, 2017
MD&A
—————————————————————————

Management’s stated cash generation Management’s budgetary forecast for
objective is to invoice sufficient the three months ended May 31, 2017
data miles of CIM subscriptions to (“Q1 2018”) included in the Fiscal
pay the majority portion of our cash 2018 Budget was achieved. In the
expenses prior to working capital quarter, a new data base schema was
requirements and to continue initiated for CIM to allow the
increasing the capabilities of CIM by addition of new features. New
developing additional functionality. functionality added during the
quarter was the ability to mark
pipeline segments as having been
repaired, the ability to project
corrosion growth 10 years into the
future and the ability to export data
from the system. Improvements were
also made to the algorithms that
align the features of multiple
pipeline assessment data sets.

—————————————————————————

Revenue Scenario 1 In Q1 2018, cumulative data miles
invoiced, rate per mile and revenue
Using the charge out rate of USD invoiced were achieved in accordance
$5.00 per pipeline data mile per with Fiscal 2018 Budget expectations.
month plus Pilot Project and Azure
usage fees, revenue of $3,018,000 is As at the quarter end, contract
projected to be generated, providing negotiations were underway with one
the full 359,505 cumulative data private preview customer and one
miles are invoiced. Under this Pilot Project customer, and sales
scenario, cash of $858,000 will be processes were underway with
consumed in the year, comprised of a additional potential customers whom
$150,000 cash loss (pre-software we believe will engage in Pilot
capitalization), $594,000 for working Projects to use CIM for their
capital purposes and $114,000 for operations. We continue to attempt to
computer upgrades and additions. engage a second private preview
customer to use CIM on a commercial
Revenue Scenario 2 – Lower level of basis, which has not yet occurred as
Sales at the quarter end.

Only 259,753 cumulative data miles Expenses were less than those
are invoiced due to a lower budgeted in the Fiscal 2018 Budget.
attainment of new customers and our Cash generated in the first quarter
second private preview customer using of 2018 was $91,000 higher than that
CIM for a reduced level of mileage budgeted primarily due to less cash
than assumed in Revenue Scenario 1. being consumed for working capital
Using the same billing rate per mile purposes than budgeted.
and Pilot Project fees as stated
above, the invoiced mileage would
generate revenue of $2,120,000. Cash
expenses would be unchanged from
Scenario 1 of the Fiscal 2018 Budget
and revenue less cash expenses would
leave a shortfall of $1,048,000.
Capital assets purchases would be
unchanged and working capital
requirements would reduce to
$396,000. The Company would consume
cash of $1,558,000 in the year. After
conversion of warrants as stated
below, the Company would end the
fiscal year with cash of $1,517,000.

—————————————————————————

Warrant Financings under Revenue Cash received from warrants exercised
Scenario 1 during the quarter was $1,907,680.

Management believes that $4,050,000 Management’s Fiscal 2018 Budget
will be raised from exercise of the forecasts for exercise of Warrants
share purchase warrants currently remains unchanged as at Fiscal 2018
outstanding due to their average Q1 ended May 31, 2017.
exercise price of $0.13 being less
than the price of the Company’s
shares in the publicly traded markets
and due to the warrants expiry date
in February and March of 2018.

Warrant Financings under Revenue
Scenario 2

Due to lower revenue, only 50% of the
outstanding warrants may be
exercised, generating cash of
$2,983,000

—————————————————————————
Expenses in $000’s (for both Revenue Expenses in $000’s for Q1 2018.
Scenarios 1 & 2), Year ending Feb.
28, 2018.
Salaries & Benefits Direct costs – salary
2,702 allocation 12
General & Administrative 387 Salaries & Benefits 659
Sales & Marketing 375 General & Administrative 162
Non-cash expense: stock Sales & Marketing
compensation costs (295) 74
Total cash expenses Non-cash expense: stock
3,168 compensation costs (102)
Revenue less cash expenses (150) Total cash expenses 805
Revenue less cash expenses (582)
Note: Revenue is expected to increase Fiscal 2018 Q1 ended May 31, 2017
monthly during the year while essentially met our operational
expenses will be essentially budget expectations.
unchanged each quarter.
—————————————————————————

/T/

BUSINESS OUTLOOK

We are actively engaged in discussions and actions with multiple potential new
customers. As is often the case with the adoption of disruptive technologies,
our two main challenges appear to be long sales cycles which we anticipate may
be six months or more and the reluctance to embrace a new solution to replace
legacy practices.

To address these challenges, OneBridge created a Pilot Project program to allow
prospective customers to use CIM on a trial basis by submitting their data for
a portion of their pipeline and using CIM to quickly analyze and report on it
so they can experience first-hand the value proposition of using CIM. Pricing
for a Pilot Project participant has been set within the typical financial
authorization levels of integrity management personnel, to reduce sales cycles
and to expedite the onboarding of new customers using CIM. We believe the value
proposition of using CIM, once demonstrated with a customer’s specific data,
will be highly compelling and lead to quicker acceptance by new customers to
use our product. We further believe that once key industry participants who
have used our solution share their CIM user experience with their peers, which
typically occurs at industry gatherings, work-shops and conventions, our CIM
solution will gain traction as a credible alternative to less effective and
efficient legacy solutions used by industry today.

It is our belief that the combination of: (i) OneSoft’s alignment with
Microsoft cloud deployment strategies; (ii) our deep domain expertise with
respect to the pipeline industry and development expertise regarding cloud
computing; (iii) the high degree of interest and motivation of oil and gas
pipeline customers to improve their safety practices; and (iv) the need for
hazardous pipeline operators to comply with increasingly stringent operational,
safety and regulatory requirements are compelling factors that have potentially
positioned the Company for significant future growth and opportunity. We
believe that our solutions are ideally poised to provide the comprehensive and
cost-effective functionality that our potential customers are seeking. We also
believe that legacy systems in use today are not able to replicate the
capabilities that our cloud-based solutions that leverage big data and machine
learning data science can provide.

Our corporate development strategy continues to encompass investigation and
pursuit of initiatives that foster value creation for our shareholders,
including synergistic joint ventures and potentially merger and acquisition
scenarios.

Please review the Management’s Discussion and Analysis and Condensed
Consolidated Financial Statements for the three months ended May 31, 2017 on
SEDAR (www.sedar.com) for more detailed information regarding the Company’s
results.

GRANT OF STOCK OPTIONS

On July 25, 2017, the Company granted 275,000 stock options to the Directors
and Officers of the Company as a result of their reappointment following the
Annual General Meeting of the shareholders. 325,000 stock options were also
granted to senior executives as part of their compensation. All options have a
strike price of $0.27 per share, vest 50% on grant date and 50% on the
anniversary date, and will expire in five years if not exercised.

ON BEHALF OF THE BOARD OF DIRECTORS

ONESOFT SOLUTIONS INC.

Douglas Thomson, Chair

Forward-looking Statements

This Press Release contains historical information, descriptions of current
circumstances and statements about potential future developments and
anticipated financial results, performance or achievements of the Company. The
latter statements, which are forward-looking statements, are presented to
provide guidance to the reader but their accuracy depends on several
assumptions and are subject to various known and unknown risks and
uncertainties. Forward-looking statements are included under the headings,
“Business Outlook” and “Financial Outlook for Fiscal 2018 and Progress in Q1
2018″, When used in this Press Release, such statements may contain such words
as “may,” “will,” “intend,” “should,” “expect,” “believe,” “outlook,”
“predict,” “remain,” “anticipate,” “estimate,” “potential,” “continue,” “plan,”
“could,” “might,” “project”, “targeting” or the negative of these terms or
other similar terminology. Forward looking information in this Press Release
includes, without limitation, statements regarding funding requirements. These
statements are based on management’s current expectations regarding future
events and operating performance, are based on information currently available
to management, speak only as of the date of this Press Release and are subject
to risks which are referenced on page 16 of the Management Discussion and
Analysis for the year ended February 28, 2017 and in the Company’s other public
filings on the Canadian Securities Administrators’ website at www.sedar.com
(“SEDAR”) and as updated from time to time, and would include, but are not
limited to, dependence on market economic conditions, sales and margin risk,
acquisition and integration risks, competition, information system risks, risks
associated with the introduction of new products, product design risk,
environmental risks, customer and vendor risks, credit risks, currency risks,
tax risks, risks of legislative changes, risks relating to remote operations,
key executive risk and litigation risks.
In addition, there are numerous risks associated with an investment in the
Company’s common shares, which are also further described in the “Risks and
Uncertainties” section referenced on page 16 of the Management Discussion and
Analysis for the year ended February 28, 2017, and as updated from time to
time, the Company’s other public filings on SEDAR. These risks and
uncertainties may cause actual results to differ materially from those
contained in the statements. Such statements reflect management’s current views
and are based on certain assumptions. Some of the key assumptions include, but
are not limited to: assumptions regarding the performance of the Canadian and
the United States economies; interest rates; exchange rates; capital
availability; the amount of the Company’s cash flow from operations; tax laws;
laws and regulations relating to the protection of the environment; and capital
spending requirements or planning in respect thereto, including but not limited
to the performance of any such business and its operation. They are, by
necessity, only estimates of future developments and actual developments may
differ materially from these statements due to several known and unknown
factors. Investors are cautioned not to place undue reliance on these
forward-looking statements. All forward-looking information in this Press
Release is qualified by these cautionary statements. Although the
forward-looking information contained in this Press Release is based upon what
management believes are reasonable assumptions, there can be no assurance that
actual results will be consistent with these forward-looking statements.
Certain statements included in this Press Release may be considered “financial
outlook” for purposes of applicable securities laws, and such financial outlook
may not be appropriate for purposes other than this Press Release.

The forward-looking statements contained in this Press Release are made as of
the date of this report, and should not be relied upon as representing
management’s views as of any date subsequent to the date of this report. Except
as required by applicable law, the Company undertakes no obligation to publicly
update or otherwise revise any forward-looking statement, whether because of
new information, future events, or otherwise.

The TSX Venture Exchange has not reviewed and does not accept responsibility
for the adequacy or accuracy of this release.

– END RELEASE – 27/07/2017

For further information:
OneSoft Solutions Inc.
Dwayne Kushniruk
CEO
780-868-9507
[email protected]

COMPANY:
FOR: ONESOFT SOLUTIONS INC.
TSX VENTURE SYMBOL: OSS
OTCQB SYMBOL: OSSIF

INDUSTRY: Computers and Software – Software
RELEASE ID: 20170727CC0008

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.

New SHOWCASE Directory Companies

 

Environmental Refueling Systems (ERS)
Galloway Construction Group
Techmation Electric & Controls
Predator Drilling
Galdos Systems
Versa-Line
FUELware
Assetworks

Fraser Institute News Release: Pipelines 2.5 times safer than rail for oil transportation; tankers have safest record of all

FOR: THE FRASER INSTITUTE
Date issue: July 27, 2017Time in: 5:00 AM eAttention:
CALGARY, AB –(Marketwired – July 27, 2017) – Transporting oil by pipelines
is more than twice as safe as using rail, and marine tankers are safer still
with a markedly i…

New SHOWCASE Directory Companies

 

Techmation Electric & Controls
Predator Drilling
Galloway Construction Group
Environmental Refueling Systems (ERS)
FUELware
Galdos Systems
Versa-Line
Assetworks

Eco (Atlantic) Oil and Gas Ltd: Final Results for the year ended 31 March 2017

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

Date issue: July 27, 2017
Time in: 2:00 AM e

Attention:

TORONTO, ON–(Marketwired – July 26, 2017) – Eco (Atlantic) Oil and Gas Ltd
(TSX VENTURE: EOG) (AIM: ECO)

TSXV: EOG; AIM: ECO

27 July 2017

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

Final Results for the year ended 31 March 2017

Eco (Atlantic) Oil & Gas Ltd. (AIM: ECO, TSX-V:EOG), the oil and gas
exploration company with licences in highly prospective regions in South
America and Africa, is pleased to announce its preliminary results for the year
ended 31 March 2017.

Operational Highlights:

– Together with its Operating Partner, Tullow Oil plc (“Tullow”), the Company
is commencing a circa 2,550 km2 3D seismic survey on the 1,800 km2 Orinduik
Block, offshore Guyana, almost two years ahead of schedule, thereby seeking to
de-risk the existing defined targets located up dip and in close proximity to
Exxon Mobil Corporation’s (“Exxon”) recent Liza, Snoek, and Payara discoveries
on the Stabroek block estimated to contain oil recoverable resources of between
2.25 and 2.75 billion oil-equivalent barrels

– Extension of the Cooper, Sharon and Guy Licenses into the first renewal
period, until March 2018 – the second renewal phase under the petroleum
agreement for each license is until March 2020

– Advancement of the 3D interpretation on Cooper and Guy blocks offshore
Namibia and application for drilling permits and pre and post drilling EIA
surveys underway

– Sale of the Company’s Ghana subsidiary in order to significantly reduce
potential financial liabilities

– Strengthened the Board following the appointment of Mr. Derek Linfield as
Non-Executive Director and Mr. Gadi Levin as Chief Financial Officer

Financial Highlights:

– Successful admission to AIM in February 2017, following an oversubscribed
placing and financing of £ 5.09 million (c.C$8.4m)

– Healthy balance sheet end of the period with over C$6m in cash

– Continued reduction in general and administration costs, compensation costs,
and professional fees
– General and administrative expenses down 22% to C$385,568 (2016: C$497,009)
– Compensation down 25% to C$483,458 (2016: C$642,035)
– Professional fees down 12% to C$286,717 (2016: C$325,338)
– Travel expenses down 26% to C$132,348 (2016: 178,802)
– Occupancy and office expenses down 72% to C$82,332 (2016: 295,438)
– Operating costs up 5% to C$2,169,940 (2016: C$2,508,497)

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

http://www.rns-pdf.londonstockexchange.com/rns/2279M_1-2017-7-27.pdf

– END RELEASE – 27/07/2017

For further information:
Contact:
RNS
Customer Services
0044-207797-4400
[email protected]
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: 20170727CC0002

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.

New SHOWCASE Directory Companies

 

Galloway Construction Group
Predator Drilling
Techmation Electric & Controls
Environmental Refueling Systems (ERS)
FUELware
Galdos Systems
Versa-Line
Assetworks

Suncor posts higher net earnings despite oilsands production shortfall

CALGARY — Suncor (TSX:SU) is reporting higher net earnings in the second quarter despite lower than expected oilsands production due to maintenance down time at its northern Alberta projects.

The company says it had net earnings of $435 million or 26 cents per share in the three months ended June 30, compared with a net loss of $735 million or 46 cents per share in the same period last year, during which a wildfire near Fort McMurray, Alta., disrupted production.

Second-quarter earnings were boosted by higher crude oil prices as well as a non-cash gain of $278 million on the revaluation of U.S. dollar denominated debt.

Suncor says its total production was 539,100 barrels of oil equivalent per day in the second quarter, with oilsands operations contributing 352,600 barrels per day.

CEO Steve Williams said in a news release that the oilsands’ performance failed to match expectations in the second quarter, but stronger results are in store now that maintenance for the year has been substantially completed.

Suncor says it is cutting its average 2017 production expectation for its 54 per cent stake in Syncrude by 5,000 bpd to account for a fire and outage there in March, but says improved performance in its non-oilsands operations will allow it to maintain its overall targets.

 

The Canadian Press

New SHOWCASE Directory Companies

 

Environmental Refueling Systems (ERS)
Galloway Construction Group
Techmation Electric & Controls
Predator Drilling
Assetworks
FUELware
Galdos Systems
Versa-Line

Athabasca Oil Corporation Announces 2017 Second Quarter Results

FOR: ATHABASCA OIL CORPORATION
TSX SYMBOL: ATH

Date issue: July 26, 2017
Time in: 9:33 PM e

Attention:

CALGARY, ALBERTA–(Marketwired – July 26, 2017) – Athabasca Oil Corporation
(TSX:ATH) (“Athabasca” or the “Company”) is pleased to provide its 2017 second
quarter results and an operations update. The quarter marks continued
operational momentum, positive cash flow driven by strong liquids-rich Montney
growth at Placid and the full integration of Athabasca’s new thermal oil asset
at Leismer.

Second Quarter and Recent Highlights

/T/

— Q2 2017 Operating and Financial Results

— Production of 36,574 boe/d (91% liquids), representing 27% per share
growth over Q1 2017 and 162% year over year
— Funds flow of $27.6 million ($0.05 per share) and capital
expenditures of $31.7 million
— Continued cost discipline with a 61% year over year reduction in G&A
to $2.15/boe
— Net debt of $351 million with approximately $180 million of cash and
equivalents

— Light Oil – High Margin Liquids-Rich Growth

— Production of 7,246 boe/d (56% liquids), representing 97% per share
growth over Q1 2017
— Positioned to exit 2017 at approximately 10,000 boe/d and hold
production flat in the near-term with a one rig Montney program at
Placid

/T/

Placid Montney (70% working interest)

/T/

— 30 day restricted rates from the eight most recent wells averaged
950 boe/d, approximately 20% ahead of type curve expectations
— Increased type curve due to strong performance, with the plug and
perf completion design supporting higher extended production rates
(restricted IP90s averaged 725 boe/d, 62% liquids)
— Strategic land acquisitions have increased Athabasca’s gross
operated acres by 22,000 acres to approximately 80,000 acres (55,000
net)

/T/

Kaybob Duvernay (30% working interest)

/T/

— A new well at Kaybob West North had an IP30 and IP60 of 1,790 boe/d
(75% liquids) and 1,450 boe/d (74% liquids), respectively. This well
is one of the top industry producers in the volatile oil window
— The 2017 program is approximately $200 million gross ($15 million
net) and includes a total of 16 spuds and 13 completions

— Thermal Oil – Underpins Low Corporate Decline and Free Cash Flow

Generation

— Production of 29,328 bbl/d, representing 17% per share growth over
Q1 2017
— $13.3 million of Thermal Oil of free cash flow in Q2 2017
— With a focus on maximizing profitability and long-term recoveries,
the Company has reduced Thermal Oil capital by a total of $45
million, from the original $105 million annual budget

/T/

Athabasca’s Strategy

Athabasca is an intermediate oil weighted producer with exposure to several of
the largest resource plays in Western Canada, including the Montney, Duvernay
and oil sands. The Company has a funded and flexible development outlook
capable of delivering strong economic growth.

The Company is focused on maintaining scale of operations within Light Oil and
continued optimization of Thermal Oil to maximize profitability and long-term
recoveries. Athabasca retains optionality to accelerate operations across both
divisions with pricing support. The Company is guided by a strategy that
includes:

/T/

— Light Oil: Defined and Material Margin Growth

— A scalable operated Montney position at Placid
— Funded Duvernay development through the joint venture with Murphy
Oil
— Production growth to approximately 10,000 boe/d by year-end 2017 and
potential to over 20,000 boe/d by 2020 with a 1-rig program in the
Montney and current Duvernay development plans

— Thermal Oil: Free Cash Flow with Leverage to Oil Prices

— A large low decline asset base accelerates free cash flow
— Free cash flow of approximately $350 million over a five year period
at US$55/bbl WTI
— Future low risk expansion options

— Financial Sustainability

— Maturing cash flow profile with strong sustainability metrics and a
low overall corporate production decline of approximately 10%
annually
— Diverse asset base provides flexibility in future capital allocation
decisions
— Strong liquidity supported by $180 million of cash and equivalents,
$189 million Duvernay carry balance, $15 million market to market
hedge gains and a $120 million credit facility at the end of Q2 2017

/T/

/T/

Financial and
Operating
Highlights
——————-

3 months ended June 30 6 months ended June 30
($ Thousands,
except per share
and boe amounts) 2017 2016 2016
CONSOLIDATED
PRODUCTION
Petroleum and
natural gas
volumes (boe/d) 36,574 11,101 31,683 12,224
—————————————————————————-

LIGHT OIL DIVISION
Petroleum and

natural gas sales
volumes (boe/d) 7,246 5,743 5,344 6,031
Light Oil $
operating
income(1) 16,391 $ 7,215 $ 23,253 $ 12,123
Light Oil $
operating
netback(1)
($/boe) 24.85 $ 13.80 $ 24.04 $ 11.03
Capital $
expenditures 31,061 $ 5,518 $ 108,707 $ 36,176
Recovery of $
capital-carry
through capital
expenditures (13,493)$ (1,474)$ (24,173)$ (1,474)
—————————————————————————-

THERMAL OIL
DIVISION
Bitumen production

(bbl/d) 29,328 5,358 26,339 6,193
Thermal Oil $
operating income
(loss)(1) 27,396 $ (11,915)$ 39,735 $ (34,990)
Thermal Oil $
operating
netback(1)
($/bbl) 10.39 $ (29.33)$ 8.40 $ (33.03)
Capital $
expenditures(2) 14,127 $ 2,187 $ 24,994 $ 3,094
—————————————————————————-

CASH FLOWS AND
FUNDS FLOW
Cash flow from $
operating
activities 28,049 $ 5,759 $ (24,851)$ (32,268)
Cash flow from $
operating
activities per
share (basic &
diluted) 0.06 $ 0.01 $ (0.05)$ (0.08)
Funds flow from $
operations(1) 27,567 $ (27,304)$ 25,915 $ (67,420)
Funds flow from $
operations per
share (basic &
diluted) 0.05 $ (0.07)$ 0.05 $ (0.17)
—————————————————————————-

NET LOSS AND
COMPREHENSIVE LOSS
Net loss and $
comprehensive
loss 24,233 $ (59,169)$ (4,932)$ (124,298)
Net loss and $
comprehensive
loss per share
(basic & diluted) 0.05 $ (0.15)$ (0.01)$ (0.31)
—————————————————————————-

SHARES OUTSTANDING
Weighted average

shares
outstanding
(basic) 508,655,464 405,222,515 490,492,488 404,964,704
—————————————————————————-

ACQUISITIONS AND
FINANCINGS
Leismer Corner $
Acquisition( 3 ) (3,687)$ – $ (625,764)$ –
Net proceeds from $
sale of assets 35 $ 392,175 $ 90,205 $ 392,338
Net proceeds from $
issuance of 2022
Notes (437)$ – $ 542,117 $ –
Repayment of 2017 $
Notes – $ (284,722)$ (550,000)$ (285,441)
—————————————————————————-

June 30, December
As at ($ Thousands) 2017 31, 2016

LIQUIDITY AND

BALANCE SHEET
Cash and cash
equivalents $ 179,611 $ 650,301
Restricted cash $ 113,853 $ 107,012
Capital-carry
receivable
(current & LT
portion –
discounted) $ 189,296 $ 213,469
Face value of
long-term debt $ 584,212 $ 550,000
—————————————————————————-

Total assets $ 2,488,995 $ 2,257,887
Total Liabilities $ 765,260 $ 700,790
Shareholders’
equity $ 1,723,735 $ 1,557,097
—————————————————————————-
(1) Refer to “Advisories and Other Guidance” in the MD&A for additional
information on Non-GAAP Financial Measures.
(2) Thermal Oil capital expenditures excludes the cost of the Leismer
Corner Acquisition.
(3) Consists of cash of $435.0 million, common shares of $166.0 million
and contingent payment obligations of $24.7 million.

/T/

Operations Update

Light Oil

Production averaged 7,246 boe/d (56% liquids) in Q2 2017, representing 97% per
share growth over Q1 2017. The step change in production was driven by the
tie-in of Montney wells from the winter program. Volumes were impacted by a 16
day unplanned outage at Keyera’s Simonette Gas Plant in April which the Company
was able to partially mitigate by redirecting a portion of production to the
SemCAMS KA plant.

Light Oil operating income was $16.4 million ($24.85/boe netback). Capital
expenditures totaled $17.6 million net with activity focused on completing the
Montney and Duvernay winter programs. Light Oil lease operating expenses
decreased to $9.96/boe in Q2 2017, down 35% from Q1 2017, and are expected to
drop an additional 20% to approximately $8/boe by year-end 2017, supported by
additional production growth and field optimization.

Greater Placid Montney (Athabasca operated, 70% working interest)

At Placid, Athabasca completed an active winter program that included rig
releasing 20 Montney wells, commissioning a new battery and the tie-in of three
multi-well pads. Placid is positioned for flexible and scalable economic growth
over the next five years.

A total of three pads, 11 wells, were completed and placed on production this
winter. The Company modified its completion design to a plug and perf system
(from previous ball drop design) with the goal to improve fracture intensity
and ultimately long-term rates and recoveries.

Following initial clean-up, the wells are exhibiting strong extended production
at higher flowing pressures with results coming in ahead of the type curve
expectations. Peak 30 day rates from the 11 wells averaged 900 boe/d (56%
liquids) and IP90s averaged 725 boe/d (62% liquids). The Company is increasing
its Placid Montney type curve to reflect the strong results with IP30s and EURs
moving up approximately 20% to 1,000 boe/d (57% liquids) and 675mboe (45%
liquids), respectively. Placid boasts strong economics with single well type
curve metrics of 21 month payback, 46% IRR and $13,000/boe/d 1 year capital
efficiencies (US$50/bbl WTI flat pricing).

/T/

Placid 2016/17
Winter
Program(1) Peak 30 Day(2) IP60 IP90
Pad 1 – 07-30- On-stream
60-23W5(3) December 813 boe/d (70%) 742 boe/d (66%) 690 boe/d (67%)
Pad 2 – 12-19-
60-23W5 (Pod On-stream
2) April 821 boe/d (51%) 632 boe/d (65%) 670 boe/d (61%)
Pad 3 – 16-30- On-stream
60-23W5 April 1,053 boe/d (50%) 673 boe/d (64%) 798 boe/d (58%)
Pad 4 – 03-04- Completions
61-23W5 underway – – –
Pad 5 – 07-33- Completions
60-20W5 Aug/Sept – – –

(1) Liquids% includes free condensate and estimated plant based NGL

recovery.
(2) Peak 30 day rates reported as the initial rates in April were
temporarily restricted by spring road bans and the 16-day Keyera
unplanned outage.
(3) 7-30 wells were restricted through Q1 2017 due to elevated regional
line pressure prior to the commissioning of the Placid infrastructure
in April.

/T/

Completions operations are underway on Pad 4 and will follow on Pad 5 in Q3
2017. Drill and completion costs are estimated at approximately $7.9 million
per well, with drilling totaling $2.8 million per well and completions
estimated at $5.1 million per well (2,900 meter average laterals and 1,300
lb/ft proppant intensity). Both pads are expected to be placed on-stream in H2
2017 and will support further production growth.

The Company will spud a six well pad in late Q3 2017 (surface location
7-30-60-23W5 – Pod 2) with completions anticipated in early 2018. The 7-30 Pod
2 pad is low risk capital efficient development that will maintain base
production levels. Decisions regarding 2018 activity levels will be finalized
later this year and the Company retains flexibility to adapt activity levels to
results and external market conditions.

Over the past year the Company has completed a number of strategic land
acquisitions through industry swaps and crown land sales. The Company’s
operated Montney position now stands at approximately 80,000 gross acres (up
from 58,000 acres), of which 48,000 gross acres (36,000 net) are high-graded
Placid development. An inventory of over 200 locations positions the Company
for multi-year growth.

Greater Kaybob Duvernay (Murphy operated, 30% working interest)

Joint venture operations commenced in the fall of 2016 with the objective of
driving near-term production and cash flow growth, delineation across all phase
windows, optimizing well design and maximizing land retention.

Murphy operated two drilling rigs through the winter season and rig released
eight wells from four pads. Initial activity has been focused in the condensate
rich gas window at Kaybob West and in the volatile oil window at Kaybob West
North. Activity through the second half will step out through the volatile oil
window at Kaybob East, Two Creeks and Simonette. Murphy is experimenting with a
number of completion techniques in the initial wells, leveraging off their
experience in the Eagle Ford oil window.

A two well pad at surface location 4-32-64-20W5 was completed in Q2 and placed
on-stream in early June. The 16-36-64-21W5 well is a 2,300 meter lateral and
was completed with 3,000 lb/ft proppant intensity (38 stages, 4.5 T/M). The
well had an IP30 of 1,790 boe/d (75% liquids) and an IP60 of 1,450 boe/d (74%
liquids). The 3-28-64-20W5 well is a 2,450 meter lateral and was completed with
2,000 lb/ft proppant intensity (41 stages, 3.0 T/M). The well had a restricted
rate IP30 of 830 boe/d (74% liquids). The early stage production and pressure
data from these wells remain very encouraging and compares favorably to prior
regional wells and type curve expectations.

A three well pad at surface location 11-18-64-20W5 was rig released in April
and subsequently completed. Initial flow back is underway on the pad. A single
well at surface location 16-18-65-20W5 was rig released in late March with a
2,900 meter lateral.

The 2017 budget includes spudding 16 gross wells which are a mix of pad
development locations and delineation wells throughout the volatile oil window.
Total lateral drilling for the program is approximately 45,000 meters and this
compares to Athabasca’s initial 20 well appraisal campaign of approximately
27,000 meters since 2012. Results from the Duvernay program are expected
through H2 2017 with 10 spuds planned for the balance of the year.

Athabasca is encouraged by continued positive industry well results, robust
activity levels by offsetting majors (Shell, Encana and Chevron) and initial
results from the Murphy operated wells. The Duvernay is competitive with other
top North American shale plays and boasts high free liquids (200 – 1,000
bbl/mmcf), premium value condensate production and a low 5% royalty over the
first three years (compared to average Permian rates of approx. 25%). Resulting
operating netbacks for an 80% liquids well at US$50/bbl WTI are approximately
C$44/boe. The joint venture positions Athabasca shareholders with a funded
Duvernay development profile over the next four years and long-term upside with
a 30% working interest in over 200,000 prospective Duvernay acres and a 1,500+
well inventory.

Thermal Oil

Production averaged 29,328 bbl/d in Q2 2017, representing 17% per share growth
over Q1 2017. Volumes were supported by the full integration of Leismer for the
quarter and the continued ramp-up at Hangingstone. Thermal Oil operating income
was $27.4 million ($10.39/boe netbacks) with $14.1 million of capital
expenditures during the quarter. Resulting free cash flow was $13.3 million.

Leismer

Leismer production averaged 20,463 bbl/d in Q2 2017. The Company is taking
deliberate steps to prudently manage reservoir performance and maximize
profitability. The 2017 capital budget at Leismer has been reduced to $40
million, representing a 54% or $45 million reduction from the original $85
million budget. The Company expects to manage production between 20,000 –
22,000 bbl/d. Near-term operations will focus on production and steam
optimization across the field and the start-up of predrilled infills on Pad L5
into 2018.

The Company estimates a low average 32% recovery factor on existing wells to
date with recoveries expected to reach approximately 65% long-term, in line
with comparable industry projects. The asset’s reserve life index is 35 years
proven and 75 years proved plus probable. Management remains pleased with the
quality of the asset and inherent flexibility to reduce capital while
maintaining production in this environment.

Hangingstone

Hangingstone averaged 8,865 bbl/d in Q2 2017, up from 8,552 bbl/d in Q1 2017.
June production averaged over 9,200 bbl/d with positive operating netback.
Facility performance has been stable and production is expected to continue to
increase with steam chamber growth. Hangingstone will require minimal capital
over the next several years to maintain production levels.

Balance Sheet and Sustainability

Financial sustainability remains a core part of Athabasca’s strategy and
throughout 2017 the Company has focused on activities that will drive increased
margins and improve financial resiliency. 2017 capital has been primarily
directed to the high margin Montney and Duvernay with Light Oil volumes
expected to grow to approximately 10,000 boe/d (and contribute approximately
50% of operating income) by year-end. Material production growth in Light Oil
along with the strategic Leismer acquisition and an ongoing focus on cost
optimization has resulted in lower year over year operating and G&A expenses
per boe of 35% and 61%, respectively. The Company has also taken steps to
manage its exposure to commodity prices with 20,000 bbl/d hedged for the
balance of 2017 at an average WCS price of approximately C$50.75/bbl. Going
forward, a multi-year hedging program will form a key part of the Company’s
risk management strategy.

The Company maintains a solid balance sheet position with net debt at the end
of Q2 2017 of $351 million and a strong liquidity position. Liquidity is
supported by $180 million of cash and equivalents, a $189 million Duvernay
carry balance, $15 million market to market hedge gains and a $120 million
credit facility, which was reaffirmed by the Company’s lenders on May 31, 2017.
The Company also has significant asset value in its established and operated
Thermal and Light Oil infrastructure.

2017 Guidance and 2018 Capital Outlook

Corporate Guidance

Athabasca’s 2017 capital budget is unchanged at $210 million and includes
running a single rig in the Placid Montney area during H2 2017. Annual
corporate production is expected to average between 33,500 – 36,500 boe/d.

Light Oil Guidance

Athabasca’s 2017 Light Oil capital budget has been increased by $15 million to
$150 million ($135 million for Placid Montney and $15 million net for
Duvernay). The increased activity reflects spudding a 6-well Montney pad in Q3
2017 with completions and tie-in anticipated in early 2018. The increase in
capital has been funded through an optimized Thermal Oil budget which is
outlined below. Light Oil annual production guidance is unchanged at 6,500 –
7,500 boe/d and production is expected to reach 10,000 boe/d before year-end.
Guidance incorporates a 19 day planned turnaround at Keyera’s Simonette plant
through August.

Thermal Oil Guidance

Athabasca’s 2017 Thermal Oil capital budget has been reduced by an additional
$15 million to $60 million. Inclusive of the prior reduction at Q1, the Company
has reduced its Thermal Oil budget by a total of $45 million from the original
$105 million budget. Annual production guidance is between 27,000 – 29,000
bbl/d. The capital program consists of $40 million at Leismer, $15 million at
Hangingstone and $5 million for maintaining Athabasca’s long dated thermal
leases.

2017 Budget & Guidance Details

/T/

Full Year
CORPORATE (net)
Production (boe/d) 33,500 – 36,500
Liquids Weighting (%) approx. 91%
Funds Flow from Operations ($MM) approx. $55

LIGHT OIL

Production (boe/d) 6,500 – 7,500
Operating Income ($MM) approx. $61
Capital Expenditures ($MM) $150

THERMAL OIL

Bitumen Production (bbl/d) 27,000 – 29,000
Operating Income ($MM) approx. $83
Capital Expenditures ($MM) $60

COMMODITY ASSUMPTIONS

WTI (US$/bbl) $48.00
Western Canadian Select (C$/bbl) $47.25
AECO Gas (C$/mcf) $2.50
FX (US$/C$) 0.76

/T/

2018 Capital Outlook

Management’s expectations are to align 2018 capital spending with corporate
cash flow. The Company’s assets afford it significant capital flexibility in
both the Light and Thermal Oil divisions. Placid Montney activity has no
near-term land expiries, with a single rig capable of holding production flat.
In the Duvernay, the Company is protected by a capital carry on the first $1
billion of investment (7.5% capital exposure for a 30% WI). In the event the
partners agree to reduce the pace or change scope from the original joint
development agreement, Athabasca is entitled to a cash payment for carry
capital not spent in that year (2018 JDA $356 million gross, $27 million net,
$80 million capital carry). In Thermal Oil, capital and operations will
continue to be optimized to maximize profitability and long-term recoveries.
Athabasca retains readiness to accelerate activity in both divisions with
commodity support.

Conference Call

A conference call to discuss the results and provide a mid-year update will be
held for the investment community on July 27, 2017 at 7:00 a.m. MT (9:00 a.m.
ET). To participate, please dial (877) 291-4570 (toll-free in North America) or
(647) 788-4919 approximately 15 minutes prior to the conference call and enter
passcode 61002546. Alternatively, to listen to this event online, please enter
http://www.gowebcasting.com/8579 in your web browser. For those unable to
participate in the conference call at the scheduled time, it will be archived
for replay on the Company’s website at www.atha.com.

About Athabasca Oil Corporation

Athabasca Oil Corporation is a Canadian energy company with a focused strategy
on the development of thermal and light oil assets. Situated in Alberta’s
Western Canadian Sedimentary Basin, the Company has amassed a significant land
base of extensive, high quality resources. Athabasca’s common shares trade on
the TSX under the symbol “ATH”. For more information, visit www.atha.com.

Reader Advisory:

This News Release contains forward-looking information that involves various
risks, uncertainties and other factors. All information other than statements
of historical fact is forward-looking information. The use of any of the words
“anticipate”, “plan”, “continue”, “estimate”, “expect”, “may”, “will”,
“project”, “believe”, “contemplate”, “target”, “potential” and similar
expressions are intended to identify forward-looking information. The
forward-looking information is not historical fact, but rather is based on the
Company’s current plans, objectives, goals, strategies, estimates, assumptions
and projections about the Company’s industry, business and future operating and
financial results. 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.
No assurance can be given that these expectations will prove to be correct and
such forward-looking information included in this News Release should not be
unduly relied upon. This information speaks only as of the date of this News
Release. In particular, this News Release contains forward-looking information
pertaining to, but not limited to, the following: the Company’s 2017 guidance
and five year outlook; type well economic metrics; estimated recovery factors
and reserve life index in respect of the Leismer assets; and other matters.

Information relating to “reserves” is also deemed to be forward-looking
information, as it involves 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.
With respect to forward-looking information contained in this News Release,
assumptions have been made regarding, among other things: commodity outlook;
the regulatory framework in the jurisdictions in which the Company conducts
business; the Company’s financial and operational flexibility; the Company’s,
capital expenditure outlook, financial sustainability and ability to access
sources of funding; geological and engineering estimates in respect of
Athabasca’s reserves and resources; and other matters.

Actual results could differ materially from those anticipated in this
forward-looking information as a result of the risk factors set forth in the
Company’s Annual Information Form (“AIF”) dated March 9, 2017 that available on
SEDAR at www.sedar.com, including, but not limited to: fluctuations in
commodity prices, foreign exchange and interest rates; political and general
economic, market and business conditions in Alberta, Canada, the United States
and globally; changes to royalty regimes, environmental risks and hazards; the
potential for management estimates and assumptions to be inaccurate; the
dependence on Murphy as the operator of the Company’s Duvernay assets; the
capital requirements of Athabasca’s projects and the ability to obtain
financing; operational and business interruption risks; failure by
counterparties to make payments or perform their operational or other
obligations to Athabasca in compliance with the terms of contractual
arrangements; aboriginal claims; failure to obtain regulatory approvals or
maintain compliance with regulatory requirements; uncertainties inherent in
estimating quantities of reserves and resources; litigation risk; environmental
risks and hazards; reliance on third party infrastructure; hedging risks;
insurance risks; claims made in respect of Athabasca’s operations, properties
or assets; risks related to Athabasca’s amended credit facilities and senior
secured notes; and risks related to Athabasca’s common shares.

Also included in this press release are estimates of Athabasca’s 2017 capital
expenditures, funds flow from operations, operating netbacks and operating
income levels, which are based on the various assumptions as to production
levels, commodity prices and currency exchange rates and other assumptions
disclosed in this news release. To the extent any such estimate constitutes a
financial outlook, it was approved by management and the Board of Directors of
Athabasca on July 26, 2017, and is included to provide readers with an
understanding of the Company’s outlook. Management does not have firm
commitments for all of the costs, expenditures, prices or other financial
assumptions used to prepare the financial outlook or assurance that such
operating results will be achieved and, accordingly, the complete financial
effects of all of those costs, expenditures, prices and operating results are
not objectively determinable. 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 financial outlook contained in this
New Release was made as of the date of this press release and the Company
disclaims any intention or obligations to update or revise such financial
outlook, whether as a result of new information, future events or otherwise,
unless required pursuant to applicable law.

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.

Initial Production Rates

The initial production rates provided in this News Release should be considered
to be preliminary. Initial production rates disclosed herein may not
necessarily be indicative of long term performance or of ultimate recovery.

Drilling Locations

The 200 (gross) Montney inventory referenced in this presentation includes 8
probable undeveloped locations, with the balance being unbooked locations.
Proved undeveloped locations and probable undeveloped locations are booked and
derived from the Company’s most recent independent reserves evaluation as
prepared by GLJ Petroleum Consultants Ltd. as of December 31, 2016 and account
for drilling locations that have associated proved and/or probable reserves, as
applicable. Unbooked locations are internal management estimates. Unbooked
locations do not have attributed reserves or resources (including contingent or
prospective). Unbooked locations have been identified by management as an
estimation of Athabasca’s multi-year drilling activities expected to occur over
the next two decades 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 the Company
will actually drill wells, including the number and timing thereof is
ultimately dependent upon the availability of funding, oil and natural gas
prices, provincial fiscal and royalty policies, costs, actual drilling results
and 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.

Non-GAAP Financial Measures

The “Funds Flow from Operations”, “Light Oil Operating Income”, “Light Oil
Operating Netback”, “Thermal Oil Operating Income” and “Thermal Oil Operating
Netback”, and “Net Debt” financial measures contained in this News Release do
not have standardized meanings which are prescribed by IFRS and they are
considered to be non-GAAP measures. These measures may not be comparable to
similar measures presented by other issuers and should not be considered in
isolation with measures that are prepared in accordance with IFRS.

Funds Flow 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. The Funds Flow from Operations measure
allows management and others to evaluate the Company’s ability to fund its
capital programs and meet its ongoing financial obligations using cash flow
internally generated from ongoing operating related activities. Funds Flow from
Operations per share (basic and diluted) is calculated as Funds Flow from
Operations divided by the number of weighted average basic and diluted shares
outstanding.

The Light Oil Operating Income and Light Oil Operating Netback measures in this
News Release are calculated by subtracting royalties and operating and
transportation expenses from petroleum and natural gas sales and midstream
revenues received. The Light Oil Operating Netback measure is presented on a
per boe basis. The Light Oil Operating Income and the Light Oil Operating
Netback measures allow management and others to evaluate the production results
from the Company’s Light Oil assets.

The Operating Income and Operating Netback measures in this News Release with
respect to the Leismer Project and Hangingstone Project are calculated by
subtracting the cost of diluent blending, royalties, operating expenses and
transportation expenses from blended bitumen sales. The consolidated Thermal
Oil Operating Income and Operating Netback measures also include realized gains
on commodity risk management contracts. The Thermal Oil Operating Netback
measure is presented on a per bbl basis. The Thermal Oil Operating Income and
the Thermal Oil Operating Netback measures allow management and others to
evaluate the production results from the Company’s Thermal Oil assets.

The Net Debt measure is calculated by summing the face value of outstanding
term debt with current liabilities and subtracting current assets adjusted for
the capital carry receivable and risk management contracts. The Net Debt
measure is not intended to represent other measures of financial position on
the Company’s balance sheet that are calculated in accordance with IFRS. The
Net Debt financial measure allows management and others to evaluate the
Company’s funding position and utilization of debt within its capital
structure.

– END RELEASE – 26/07/2017

For further information:
Athabasca Oil Corporation
Media and Financial Community
Matthew Taylor
Vice President, Capital Markets and Communications
1-403-817-9104
[email protected]

COMPANY:
FOR: ATHABASCA OIL CORPORATION
TSX SYMBOL: ATH

INDUSTRY: Energy and Utilities – Oil and Gas
RELEASE ID: 20170726CC0080

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.

New SHOWCASE Directory Companies

 

Techmation Electric & Controls
Predator Drilling
Environmental Refueling Systems (ERS)
Galloway Construction Group
Galdos Systems
FUELware
Versa-Line
Assetworks

What was said about top court rulings on digenous consultations

OTTAWA — The Supreme Court of Canada ruled Wednesday that the National Energy Board can fulfil the Crown’s duty to consult Indigenous communities about development projects but it must be done properly. In decisions on two separate cases, the high court decided the NEB had properly consulted when reviewing a plan to expand an Enbridge pipeline between Ontario and Quebec, but that it had failed to do so when it approved seismic testing in Baffin Bay and Davis Straight.

Here’s some of the reaction to the rulings:

“I’m thinking about the people in Clyde River today. They can finally breathe a sigh of relief and perhaps even dance a celebratory jig and communities across Baffin island can rest assured that those seismic companies will not blast through their waters, they will not threaten their food sovereignty and steamroll unapologetically over their rights.” — Farrah Khan, arctic campaigner, Greenpeace Canada, which aided Clyde River in its legal battle against the seismic testing.

___

“It represents a victory not only for this community and its future but a significant and notable step forward in bringing Canadian law into line with important international human rights standards. For far too long now governments in Canada across the country and their regulatory bodies have treated consultation with Indigenous peoples as a mere formality.” — Alex Neve, secretary general of Amnesty International Canada.

___

“The government cannot continue to pay lip service to reconciliation and Indigenous rights while continuing to ignore the duty to consult and accommodate. It is insulting to see this government refuse, time after time, to walk the walk. They must immediately fix this broken process.” — NDP Indigenous and Northern Affairs Critic Romeo Saganash.

___

“That will certainly make it much more difficult in the future for the NEB to green light projects like this one, projects that have the potential to prove catastrophic for the Inuit people. Yeah, they can come back again and try again. We’ll be ready and we’ll be waiting.” — Clyde River lawyer Nader Hasan.

___

“The Chiefs of Ontario will continue to support the Chippewas of the Thames, and all other communities who are facing unwanted potential development on their lands. The fossil fuel industry will disappear over the next several decades, to be replaced by green energy. The real issue here is that we must preserve our lands and waters for future generations. This is the way forward in order to reverse climate change and the continued contamination of our lands, air and water. Our Peoples will continue the fight to save our planet for all our children.” Chiefs of Ontario Regional Chief Isadore Day.

 

The Canadian Press

New SHOWCASE Directory Companies

 

Techmation Electric & Controls
Predator Drilling
Galloway Construction Group
Environmental Refueling Systems (ERS)
Assetworks
Versa-Line
Galdos Systems
FUELware

Tribes fight trade groups’ intervention in pipeline dispute

BISMARCK, N.D. — American Indian tribes trying to shut down the Dakota Access oil pipeline are objecting to the possible intervention of national energy and manufacturing trade groups in the legal dispute.

Attorneys for the Standing Rock and Cheyenne River Sioux tribes say in court documents filed Tuesday that the arguments of the trade groups are too lengthy and duplicate those already made by Texas-based pipeline developer Energy Transfer Partners and the Army Corps of Engineers, the federal agency that permitted the $3.8 billion pipeline which began moving North Dakota oil to Illinois about two months ago.

U.S. District Judge James Boasberg, in Washington, D.C., in June ordered the Corps to further review the pipeline’s impact on the Standing Rock Sioux tribe, which has sued along with three other tribes over fears of environmental harm — a claim ETP rejects. Boasberg is deciding whether to shut down the pipeline while the work is completed.

The national trade groups seeking a say are the American Petroleum Institute, American Fuel and Petrochemical Manufacturers, Association of Oil Pipe Lines, national Chamber of Commerce and National Association of Manufacturers. They maintain in court documents that ceasing pipeline operations “would have serious adverse economic impacts throughout the oil industry and local and regional economies.”

Tribal attorneys Jan Hasselman and Nicole Ducheneaux say the groups’ 18-page argument is too long and “reiterates many of the arguments and legal principles raised by the Corps and Dakota Access (ETP).”

The trade groups on Wednesday submitted a revised argument that is only 10 pages contended again that their input can help Boasberg with his decision.

Boasberg last week ruled that the North Dakota Petroleum Council, which represents more than 500 companies, including ETP, will be allowed a say in the shutdown debate. The state group maintains it could be devastating to North Dakota’s oil industry to shut down a pipeline shipping half of the daily production of the nation’s No. 2-producing oil state.

The tribes aren’t objecting to the intervention of the state group, saying its argument “consists primarily of factual information specific to the North Dakota oil industry.”

___

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

Blake Nicholson, The Associated Press

New SHOWCASE Directory Companies

 

Galloway Construction Group
Predator Drilling
Environmental Refueling Systems (ERS)
Techmation Electric & Controls
Galdos Systems
Versa-Line
Assetworks
FUELware

B.C.’s LNG outlook dims after $36B Pacific NorthWest LNG project killed

VANCOUVER — The dream of a booming liquefied natural gas industry in British Columbia appears to be fading, at least for the foreseeable future, after Petronas and its partners scrapped a $36-billion megaproject in the province, experts say.

A consortium led by Malaysia-owned Petronas announced Tuesday it would not proceed with the Pacific NorthWest LNG project near Port Edward, B.C., due to an “extremely challenging environment” brought on by prolonged low prices.

The project would have included a natural gas export terminal on Lelu Island on the province’s northern coast and a 900-kilometre pipeline to bring the natural gas in from northeastern B.C.

The proponents of two other major projects, Shell-backed LNG Canada and Chevron’s Kitimat LNG, say they are proceeding toward final investment decisions, but analysts predict the facilities are unlikely to be built in the next three to five years — if at all.

“I’d say it’s a pretty low possibility. It’s not quite zero, but the Shell LNG project is also a very big, expensive greenfield project,” said Martin King, vice-president of institutional research at GMP First Energy.

Shell, along with PetroChina, KOGAS and Mitsibushi, have formed a joint venture company called LNG Canada that has proposed an export terminal in Kitimat on B.C.’s north coast. It indefinitely delayed making a final investment decision in July 2016.

LNG Canada said in a statement that it “continues to progress key activities” toward a future final investment decision, including ongoing negotiations with a construction contractor, completing permits and consulting with First Nations and community members.

B.C.’s other major proposal, Kitimat LNG, is backed by Chevron and Woodside Energy International. The companies are committed to delivering a globally competitive project that is ready at the right time, said spokesman Ray Lord.

“Current oil and gas market conditions remain challenged as an excess in LNG market supply is expected to continue,” he said in an email. “However, a significant opportunity exists for competitive projects to supply LNG to Asia sometime in the middle of the next decade.”

But in response to prevailing market conditions, Chevron and Woodside have reduced capital spending on planning, engineering and early site preparation work, he said.

Former B.C. Liberal premier Christy Clark made LNG a cornerstone of her successful election campaign in 2013 with promises of 100,000 jobs and $100-billion in revenue over decades. Her aim was to have three LNG facilities operating by 2020.

Woodfibre LNG, a $1.6-billion plant near Squamish, is the only project in B.C. to reach a positive final investment decision. Site preparation is underway and construction is expected to begin next year, said spokeswoman Jennifer Siddon.

She noted the project is smaller than other proposals and it is on a brownfield site with a deep water port, hydroelectric access and a gas pipeline that needs to be expanded.

“Is it challenging? Yes, it’s definitely challenging, but we are moving forward with our project,” she said.

An NDP government was sworn in last week. Clark’s Liberals have blamed the cancellation of Pacific NorthWest LNG on the New Democrats, given the NDP’s past reluctance to support the project.

Petronas denied the change in government played a role, and Michelle Mungall, the new energy minister, said it was very clear from her meeting with the company that the decision was about global market pricing.

Mungall said she has spoken with the proponents of LNG Canada and Kitimat LNG, as well as First Nations, and assured them the new government is going to work with them “on a road map to success.”

She also spoke with Natural Resources Minister Jim Carr on Wednesday about ways to make Canada and B.C. more competitive, although she would not say what measures were on the table.

“I think B.C. is in a very strong place to see this industry succeed,” she said.

James Tansey, a professor at the University of British Columbia’s Sauder School of Business, said he doesn’t think the Petronas decision is a death knell for the industry but it’s unlikely any major facilities will be built in the next three to five years.

“I think it’ll send ripples through the sector and it’ll send a strong signal to the B.C. government.”

— With files from Dirk Meissner in Victoria and Ian Bickis in Calgary

Laura Kane, The Canadian Press

New SHOWCASE Directory Companies

 

Predator Drilling
Techmation Electric & Controls
Galloway Construction Group
Environmental Refueling Systems (ERS)
FUELware
Galdos Systems
Assetworks
Versa-Line

Suncor Energy reports second quarter 2017 results

FOR: SUNCOR ENERGY INC.
TSX SYMBOL: SU
NYSE SYMBOL: SU

Date issue: July 26, 2017
Time in: 8:00 PM e

Attention:

CALGARY, ALBERTA–(Marketwired – July 26, 2017) –

Unless otherwise noted, all financial figures are unaudited, presented in
Canadian dollars (Cdn$), and have been prepared in accordance with
International Financial Reporting Standards (IFRS), specifically International
Accounting Standard (IAS) 34 Interim Financial Reporting as issued by the
International Accounting Standards Board. Production volumes are presented on a
working interest basis, before royalties, except for Libya, which is on an
entitlement basis. Certain financial measures referred to in this news release
(funds from operations, operating earnings (loss), Oil Sands operations cash
operating costs and Syncrude cash operating costs) are not prescribed by
Canadian generally accepted accounting principles (GAAP). See the Non-GAAP
Financial Measures section of this news release. References to Oil Sands
operations exclude Suncor’s interest in Syncrude’s operations.

“Our integrated model and a continued focus on cost reduction supported our
performance in the second quarter,” said Steve Williams, president and chief
executive officer. “Strong performance from our offshore and downstream
businesses helped to offset the facility incident at Syncrude and major
maintenance at the majority of our Oil Sands assets, generating cash flow in
excess of our sustaining capital and dividend commitments.”

– Funds from operations of $1.627 billion ($0.98 per common share). Cash flow
provided by operating activities, which includes changes in non-cash working
capital, was $1.671 billion ($1.00 per common share).

– Operating earnings of $199 million ($0.12 per common share) and net earnings
of $435 million ($0.26 per common share).

– Total Oil Sands production was 413,600 barrels per day (bbls/d) compared to
213,100 bbls/d in the prior year period, with the prior year quarter being
significantly impacted by the forest fires in the Fort McMurray area.

– Oil Sands operations cash operating costs per barrel (bbl) were $27.80 for
the second quarter of 2017, reflecting reduced production due to planned
maintenance and the positive impact of the company’s cost reduction
initiatives.

– Exploration and Production (E&P) production increased to 125,500 barrels of
oil equivalent per day (boe/d) from 117,600 boe/d in the prior year quarter.

– Refining and Marketing (R&M) crude throughput improved to 435,500 bbls/d from
400,200 bbls/d in the prior year quarter.

– The Fort Hills project is 90% complete, with turnover of the ore processing
and main primary extraction assets to operations in the period. The project
cost estimate is on track with first oil expected at the end of 2017. In
addition, the East Tank Farm Development was commissioned subsequent to the end
of the quarter and will support Fort Hills operations following first oil at
the end of 2017.

– The Hebron platform was successfully towed out to its final offshore location
and safely positioned on the sea floor in the second quarter of 2017. Drilling
activities are on schedule and first oil remains on track for the end of 2017.

– The West White Rose Project was sanctioned during the second quarter of 2017.
Suncor is a non-operating partner with a blended working interest of
approximately 26%. First oil is targeted for 2022, with the company’s share of
peak oil production estimated to be 20,000 boe/d.

Financial Results

Suncor recorded second quarter 2017 operating earnings of $199 million ($0.12
per common share) compared to a $565 million operating loss ($0.36 per common
share) in the prior year quarter. Highlights of the quarter included improved
crude oil pricing, increased production from E&P and R&M, and continued focus
on costs in all areas. Results in the current period were impacted by a
facility incident at Syncrude occurring late in the first quarter of 2017 and
planned maintenance at the majority of the company’s Oil Sands assets. Results
in the prior year period were impacted by production being shut in as a result
of forest fires in the Fort McMurray area, partially offset by an R&M first-in,
first-out gain.

Funds from operations were $1.627 billion ($0.98 per common share) compared to
$916 million ($0.58 per common share) in the second quarter of 2016 and were
impacted by the same factors noted in operating earnings above.

Net earnings were $435 million ($0.26 per common share) in the second quarter
of 2017, compared with a net loss of $735 million ($0.46 per common share) in
the prior year quarter. Net earnings for the second quarter of 2017 included an
unrealized after-tax foreign exchange gain of $278 million on the revaluation
of U.S. dollar denominated debt, an after-tax charge of $10 million for early
payment of debt, net of associated realized foreign currency hedge gains, and a
non-cash after-tax loss of $32 million on forward interest rate swaps and
foreign currency derivatives. The net loss in the prior year quarter included
an unrealized after-tax foreign exchange loss of $27 million on the revaluation
of U.S. dollar denominated debt, an after-tax charge of $73 million for early
payment of debt and a non-cash after-tax loss of $70 million on forward
interest rate swaps.

Operating Results

Operating, selling and general expense in the second quarter of 2017 included
costs associated with the additional 5% Syncrude working interest acquired
partway through the second quarter of 2016, and, in 2016, costs were avoided
while operations were shut in as a result of forest fires in the Fort McMurray
area. Excluding these two factors, total operating, selling and general expense
was lower in the current quarter as controllable cost savings more than offset
an increase in energy input costs that resulted from higher natural gas prices.

Suncor’s total upstream production was 539,100 boe/d in the second quarter of
2017, compared with 330,700 boe/d in the prior year quarter.

Oil Sands operations production was 352,600 bbls/d in the second quarter of
2017, compared to 177,500 bbls/d in the prior year quarter, with the increase
primarily due to production being shut in during the second quarter of 2016 as
a result of the forest fires in the Fort McMurray area, as well as a turnaround
of Upgrader 2 in the same period. Production in the second quarter of 2017 was
impacted by the first five-year turnaround of the expanded Firebag central
facilities, as well as planned upgrader maintenance, which was completed in the
period. Although the ramp-up following the turnaround at Firebag was longer
than anticipated, the extension of this turnaround cycle to five years has
provided an overall net benefit to the company through the experience gained,
which will be leveraged during future turnaround cycles. Production at Oil
Sands operations returned to normal operating rates by the end of the quarter.

Oil Sands operations cash operating costs per barrel were $27.80 in the second
quarter of 2017, reflecting major maintenance in the period and the positive
impact of the company’s cost reduction initiatives, compared to $46.80 in the
prior year quarter. The quarter-over-quarter improvement was primarily due to
the increased production and lower controllable costs.

Suncor’s share of Syncrude production was 61,000 bbls/d in the second quarter
of 2017, compared to 35,600 bbls/d in the prior year quarter. The increase is
attributed to the negative impact of the forest fires during the second quarter
of 2016 combined with an additional working interest acquired partway through
the second quarter of 2016. Production in the second quarter of 2017 was
significantly impacted by a facility incident that occurred late in the first
quarter of 2017, a planned upgrader turnaround and the advancement of coker
maintenance originally planned for the fourth quarter of 2017, which was
accelerated to coincide with the unplanned outage in an effort to maximize
annual production. Syncrude cash operating costs per barrel in the second
quarter of 2017 were $97.80, a decrease from $113.55 in the prior year quarter,
with both periods being impacted by the previously noted production outages.
Syncrude has completed the required facility repairs and the planned upgrader
turnaround and expects to return to normal operating rates by early August,
following the completion of coker maintenance.

“Although the performance of some of our Oil Sands assets did not meet our
expectations in the second quarter, we have full confidence in these assets,”
said Williams. “We have substantially completed extensive oil sands maintenance
and anticipate strong performance going forward.”

Production volumes in E&P increased to 125,500 boe/d in the second quarter of
2017, compared to 117,600 boe/d in the prior year quarter, primarily due to
lower planned maintenance at Terra Nova, production from new wells at Hibernia
and production from Libya, partially offset by natural declines at Buzzard.

Overall production guidance for 2017 remains unchanged as increased production
from E&P is expected to offset the impact of the facility incident at Syncrude.

Strong operational performance contributed to increased refinery crude
throughput of 435,500 bbls/d, compared to 400,200 bbls/d in the prior year
quarter, and also reflected lower planned maintenance and improved crude
availability. Average refinery utilization in the second quarter of 2017 was
94%, compared with 87% in the prior year quarter. Results in R&M also benefited
from strong retail sales volumes in the second quarter of 2017, contributing to
a year-to-date record for the first half of 2017.

Strategy Update

The disciplined execution of Suncor’s 2017 capital program is focused on
bringing Suncor’s major growth projects, Fort Hills and Hebron, to first oil by
the end of the year, while continuing to invest in the safety, reliability and
efficiency of the company’s operating assets.

Fort Hills project construction was 90% complete at the end of the second
quarter of 2017, with turnover of the ore processing and main primary
extraction assets to operations occurring in the period. Activity in the
quarter also included the utilities plant entering into the completion and
turnover to operations phase. Construction at the secondary extraction
facility, which is the final area to be completed to bring the project to first
oil, continued in the quarter, and the project remains on target to start
production at the end of 2017. Expenditures in the second quarter of 2017 were
also focused on early-works sustaining activities that will support the
execution of the Fort Hills mine and tailings plan following the commencement
of production. Subsequent to the end of the quarter, the company commissioned
the East Tank Farm Development and will begin readying the terminal for the
receipt of Fort Hills bitumen at the end of 2017.

The company continued to progress the sale of a combined 49% interest in the
East Tank Farm Development with the Fort McKay and Mikisew Cree First Nations
for estimated proceeds of approximately $500 million and expects to close the
arrangement in the second half of 2017.

The Hebron project achieved a major milestone in the second quarter of 2017,
with the platform towed out to its final offshore location and successfully
positioned on the sea floor. Drilling activities at Hebron are on schedule, and
first oil remains on track for late 2017. Activity in the second quarter in E&P
also included continued development drilling at Hibernia and White Rose and
development work on the Norwegian Oda project.

“Fort Hills and Hebron are on track for first oil at the end of 2017, with both
projects achieving major milestones,” said Williams. “Front end commissioning
of several key assets at Fort Hills has begun and the completed Hebron platform
has been successfully positioned at its final location, where drilling
activities are on schedule.”

The West White Rose Project was sanctioned during the second quarter of 2017.
Suncor is a non-operating partner with a blended working interest of
approximately 26%. First oil is targeted for 2022, with the company’s share of
peak oil production estimated to be 20,000 boe/d.

Syncrude sustaining capital in the second quarter of 2017 was primarily focused
on the planned upgrader turnaround, advanced coker maintenance previously
scheduled for the fourth quarter of 2017 and repairs associated with the
facility incident from the first quarter of 2017. The company expects to
receive insurance proceeds to offset a significant portion of the expenditures
associated with the facility incident.

During the second quarter of 2017, the company continued efforts with Syncrude
to drive operating efficiencies, improve performance and develop regional
synergies through integration. In the second quarter of 2017, Suncor’s
logistics network continued to handle volumes of intermediate sour Syncrude
production to assist in inventory management and allow certain Syncrude assets
to run at partial rates to avoid a full shutdown and restart as a result of the
facility incident.

Under the new Normal Course Issuer Bid, which commenced in the second quarter
of 2017, the company bought back $296 million of its own shares for
cancellation.

During the second quarter of 2017, Suncor repaid US$1.250 billion of 6.10%
notes originally scheduled to mature on June 1, 2018, to reduce financing costs
and provide ongoing balance sheet flexibility.

Operating Earnings (Loss) Reconciliation(1)

/T/

Three months ended Six months ended
June 30 June 30
($ millions) 2017 2016 2017 2016
============================================================================
Net earnings (loss) 435 (735) 1 787 (478)
—————————————————————————-
Unrealized foreign exchange (gain)
loss on U.S. dollar denominated
debt (278) 27 (381) (858)
—————————————————————————-
Non-cash mark to market loss on
interest rate swaps and foreign
currency derivatives(2) 32 70 32 160
—————————————————————————-
Loss on early payment of long-term
debt(3) 10 73 10 73
—————————————————————————-
Gain on significant disposals(4) – – (437) –
—————————————————————————-
COS acquisition and integration
costs(5) – – – 38
============================================================================
Operating earnings (loss)(1) 199 (565) 1 011 (1 065)
============================================================================
(1) Operating earnings (loss) is a non-GAAP financial measure. All
reconciling items are presented on an after-tax basis. See the Non-GAAP
Financial Measures section of this news release.

(2) Non-cash mark to market loss on forward interest rate swaps and foreign

currency derivatives resulting from changes in long-term interest rates
and foreign exchange rates in the Corporate segment.

(3) Charges associated with the early repayment of debt, net of associated

realized foreign currency hedge gains, in the Corporate segment.

(4) Gain of $354 million related to the sale of the company’s lubricants

business in the R&M segment, combined with a gain of $83 million related
to the sale of the company’s interest in the Cedar Point wind facility
in the Corporate segment.

(5) Transaction and related charges associated with the acquisition of

Canadian Oil Sands Limited (COS) in the Corporate segment.

/T/

Corporate Guidance

Suncor has updated its production, capital and other information in its 2017
corporate guidance, previously issued on April 26, 2017. The full year outlook
for Syncrude production has been updated from 135,000 – 150,000 bbls/d to
130,000 – 145,000 bbls/d, and the full year outlook range for Syncrude cash
operating costs has been updated from $36.00 – $39.00/bbl to $42.00 –
$45.00/bbl, to reflect the extended return to operations following the facility
incident that occurred late in the first quarter of 2017. In addition, the full
year outlook range for E&P production has been updated from 110,000 – 120,000
boe/d to 115,000 – 125,000 boe/d due to improved asset performance, resulting
in no change to the full year outlook range for total Suncor production.

The full year outlook range for Oil Sands operations cash operating costs has
been updated from $24.00 – $27.00/bbl to $23.00 – $26.00/bbl to reflect lower
natural gas and maintenance costs.

The updated full year outlook range for capital expenditures of $5.4 – $5.6
billion has increased from $4.8 – $5.2 billion to reflect an opportunity to
accelerate the pace of work at Fort Hills, as well as increased costs at
Syncrude related to the facility incident late in the first quarter of 2017 and
its 2017 turnaround. The project cost estimate is on track with first oil
expected at the end of 2017.

The following full year outlook assumptions have also been adjusted: Current
income taxes to $600 – $900 million from $500 – $800 million, Brent Sollum Voe
to US$49.00/bbl from US$53.00/bbl, WTI at Cushing to US$47.00/bbl from
US$52.00/bbl, WCS at Hardisty to US$35.00/bbl from US$38.00/bbl, New York
Harbor 3-2-1 crack to US$14.50/bbl from US$13.50/bbl and AECO – C Spot to
$2.50/GJ from $3.00/GJ. For further details and advisories regarding Suncor’s
2017 revised corporate guidance, see suncor.com/guidance.

Non-GAAP Financial Measures

Operating earnings (loss) is defined in the Non-GAAP Financial Measures
Advisory section of Suncor’s Management’s Discussion and Analysis dated July
26, 2017 (the MD&A) and reconciled to GAAP measures in the Consolidated
Financial Information and Segment Results and Analysis sections of the MD&A.
Oil Sands operations cash operating costs and Syncrude cash operating costs are
defined in the Non-GAAP Financial Measures Advisory section of the MD&A and
reconciled to GAAP measures in the Segment Results and Analysis section of the
MD&A. Funds from operations is defined and reconciled to GAAP measures in the
Non-GAAP Financial Measures Advisory section of the MD&A. These non-GAAP
financial measures are included because management uses this information to
analyze business performance, leverage and liquidity. These non-GAAP measures
do not have any standardized meaning and therefore are unlikely to be
comparable to similar measures presented by other companies and should not be
considered in isolation or as a substitute for measures of performance prepared
in accordance with GAAP.

Legal Advisory – Forward-Looking Information

This news release contains certain forward-looking information and
forward-looking statements (collectively referred to herein as “forward-looking
statements”) within the meaning of applicable Canadian and U.S. securities
laws. Forward-looking statements in this news release include references to:
Suncor’s growth projects, including: (i) statements around the Fort Hills
project, including that early-works sustaining activities will support the
execution of the mine and tailings plan following the commencement of
production, that the project cost estimate is on track with first oil expected
at the end of 2017, and expectations for the East Tank Farm Development; (ii)
statements around the Hebron project, including that first oil is expected by
the end of 2017; and (iii) statements about the West White Rose Project,
including the expectation that the company’s share of peak oil production is
estimated to be 20,000 boe/d and that first oil from the project is targeted
for 2022; the expectation that the overall net benefit from the extension of
the Firebag turnaround cycle to five years through the experience gained will
be leveraged during future turnaround cycles; anticipated strong performance in
Oil Sands going forward; the expectation that Syncrude will return to normal
operating rates by early August, following the completion of coker maintenance;
the expectation that increased production from E&P will offset the impact of
the facility incident at Syncrude; the expectation that the disciplined
execution of Suncor’s 2017 capital program will focus on bringing Suncor’s
major growth projects, Fort Hills and Hebron, to first oil by the end of the
year, while continuing to invest in the safety, reliability and efficiency of
the company’s operating assets; estimated proceeds of approximately $500
million from the sale of a combined 49% interest in the East Tank Farm
Development to the Fort McKay and Mikisew Cree First Nations and the
expectation that the arrangement will close in the second half of 2017; the
expectation that Suncor will receive insurance proceeds to offset a significant
portion of the expenditures associated with the Syncrude facility incident;
efforts with Syncrude to drive operating efficiencies, improve performance and
develop regional synergies through integration; the expectation that the
reduction in outstanding debt will reduce financing costs and provide ongoing
balance sheet flexibility; Suncor’s outlook for full year Syncrude production,
Syncrude cash operating costs, E&P production, Oil Sands operations cash
operating costs, capital expenditures and current income taxes and outlook
assumptions. In addition, all other statements and information about Suncor’s
strategy for growth, expected and future expenditures or investment decisions,
commodity prices, costs, schedules, production volumes, operating and financial
results and the expected impact of future commitments are forward-looking
statements. Some of the forward-looking statements and information may be
identified by words like “expects”, “anticipates”, “will”, “estimates”,
“plans”, “scheduled”, “intends”, “believes”, “projects”, “indicates”, “could”,
“focus”, “vision”, “goal”, “outlook”, “proposed”, “target”, “objective”,
“continue”, “should”, “may” and similar expressions.

Forward-looking statements are based on Suncor’s current expectations,
estimates, projections and assumptions that were made by the company in light
of its information available at the time the statement was made and consider
Suncor’s experience and its perception of historical trends, including
expectations and assumptions concerning: the accuracy of reserves and resources
estimates; commodity prices and interest and foreign exchange rates; the
performance of assets and equipment; capital efficiencies and cost savings;
applicable laws and government policies, including royalty rates and tax laws;
future production rates; the sufficiency of budgeted capital expenditures in
carrying out planned activities; the availability and cost of labour and
services; the satisfaction by third parties of their obligations to Suncor; and
the receipt, in a timely manner, of regulatory and third-party approvals.

Forward-looking statements are not guarantees of future performance and involve
a number of risks and uncertainties, some that are similar to other oil and gas
companies and some that are unique to Suncor. Suncor’s actual results may
differ materially from those expressed or implied by its forward-looking
statements, so readers are cautioned not to place undue reliance on them.

The MD&A and Suncor’s Annual Information Form, Form 40-F and Annual Report to
Shareholders, each dated March 1, 2017, and other documents it files from time
to time with securities regulatory authorities describe the risks,
uncertainties, material assumptions and other factors that could influence
actual results and such factors are incorporated herein by reference. Copies of
these documents are available without charge from Suncor at 150 6th Avenue
S.W., Calgary, Alberta T2P 3E3, by calling 1-800-558-9071, or by email request
to [email protected] or by referring to the company’s profile on SEDAR at
sedar.com or EDGAR at sec.gov. Except as required by applicable securities
laws, Suncor 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.

Legal Advisory – BOEs

Certain natural gas volumes have been converted to barrels of oil equivalent
(boe) on the basis of one barrel to six thousand cubic feet. Any figure
presented in boe may be misleading, particularly if used in isolation. A
conversion ratio of one bbl of crude oil or natural gas liquids 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 on a 6:1 basis may be
misleading as an indication of value.

Suncor Energy is Canada’s leading integrated energy company. Suncor’s
operations include oil sands development and upgrading, offshore oil and gas
production, petroleum refining, and product marketing under the Petro-Canada
brand. A member of Dow Jones Sustainability indexes, FTSE4Good and CDP, Suncor
is working to responsibly develop petroleum resources while also growing a
renewable energy portfolio. Suncor is listed on the UN Global Compact 100 stock
index and the Corporate Knights’ Global 100. Suncor’s common shares (symbol:
SU) are listed on the Toronto and New York stock exchanges.

For more information about Suncor visit our website at suncor.com, follow us on
Twitter @SuncorEnergy or
or together.suncor.com

A full copy of Suncor’s second quarter 2017 Report to Shareholders and the
financial statements and notes (unaudited) can be downloaded at
suncor.com/financialreporting.

Suncor’s updated Investor Relations presentation is available online, visit
suncor.com/investor-centre.

To listen to the webcast discussing Suncor’s second quarter results, visit
suncor.com/webcasts.

– END RELEASE – 26/07/2017

For further information:
Media inquiries:
403-296-4000
[email protected]
OR
Investor inquiries:
800-558-9071
[email protected]

COMPANY:
FOR: SUNCOR ENERGY INC.
TSX SYMBOL: SU
NYSE SYMBOL: SU

INDUSTRY: Energy and Utilities – Oil and Gas
RELEASE ID: 20170726CC0077

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.

New SHOWCASE Directory Companies

 

Environmental Refueling Systems (ERS)
Galloway Construction Group
Techmation Electric & Controls
Predator Drilling
Galdos Systems
FUELware
Assetworks
Versa-Line

Britain to ban sale of new diesel and gasoline cars by 2040

LONDON — Britain will ban the sale of new cars and vans using diesel and gasoline starting in 2040 as part of a sweeping plan to tackle air pollution that experts say is feasible, if ambitious.

The government announcement Wednesday follows similar moves in France and Norway and comes amid a global debate on how quickly electric and hybrid cars can replace internal combustion engines. Traditional engines running on diesel and gasoline are still popular with consumers as they’re relatively cheap and do not face some limits of electric cars, such as a limited range.

But with the technology for electric and hybrid cars improving, governments are trying to set long-term goals to help guide the investments of automakers and, ultimately, consumers’ choices.

Britain’s government said it would put up 255 million pounds ($326 million) to help local communities address diesel pollution. The measures are part of a clean air strategy that authorities published only days before a deadline mandated by the High Court. The money is part of a 3 billion pound effort to clean up the air.

The government plan includes the consideration of a targeted scrappage scheme for drivers who need support and to provide an incentive to switch vehicles. It also aims for “almost every car and van on the road to be a zero emission vehicle by 2050,” the government said in its overview of the program.

Frederik Dahlmann, an assistant professor of global energy at Warwick Business School, described the plans as “ambitious but realistic.”

“I am confident enough that the industry will be able to respond within that timeline,” he said.

It would, however, require significant investment in in the infrastructure, such as a network of charging stations, that is required to make electric and hybrid vehicles more widely popular. Another point of focus is improving batteries so that they last longer.

While carmaker Volvo has committed to switching to only selling electric and hybrid cars within two years, most major manufacturers say that traditional engines will remain an important part of their sales for years.

On Wednesday, Daimler CEO Dieter Zetsche said that diesel engines can help lower overall carbon dioxide emissions because they emit less than gasoline cars. Environmental activists note, however, that diesels emit more nitrogen oxide, which is harmful for people’s health.

So far, growth in electric and hybrid vehicle sales has been strong, but from a low base.

Analytics company IHS Markit estimate that sales of internal combustion engines are expected to fall from 17 million vehicles in 2015 across the EU to about 12 million in 2025, which would still make up a significant portion of cars on the road.

Meanwhile, sales of electric and hybrid cars are expected to increase from about 350,000 in 2015 to 1.85 million by 2025.

___

Associated Press Writer Dee Ann Durbin contributed to this story.

Leonore Schick, The Associated Press


New SHOWCASE Directory Companies

 

Galloway Construction Group
Predator Drilling
Environmental Refueling Systems (ERS)
Techmation Electric & Controls
Assetworks
Versa-Line
FUELware
Galdos Systems

Five Effective & Affordable Tips for Marketing Your Oilfield Service Company

For oilfield service companies that have survived the past three years, the industry continues to be very  competitive as a result of decreased oil prices and as many companies scramble to obtain a piece of a smaller “revenue” pie.  For many companies, merely breaking even has been the main objective as market conditions forced producers … Read more

New SHOWCASE Directory Companies

 

Predator Drilling
Environmental Refueling Systems (ERS)
Techmation Electric & Controls
Galloway Construction Group
Assetworks
Galdos Systems
Versa-Line
FUELware

Big Oil Beating Slump as CEOs Learn to Live With $50 Crude

July 25, 2017 (Bloomberg)  Big Oil is starting to beat the crude-market slump as the industry rediscovers how to make money at lower prices. Exxon Mobil Corp. and Royal Dutch Shell Plc are forecast to more than double second-quarter profit from a year earlier, far outstripping the 8 percent gain in benchmark Brent crude, according to … Read more

New SHOWCASE Directory Companies

 

Predator Drilling
Galloway Construction Group
Techmation Electric & Controls
Environmental Refueling Systems (ERS)
Galdos Systems
FUELware
Versa-Line
Assetworks

Oil Climbs From Seven-Week High on Signs U.S. Stockpiles Plunged

Oil Climbs From Seven-Week High on Signs U.S

July 26, 2017 (Bloomberg)  Oil extended gains from the highest close in seven weeks as industry data showed U.S. crude stockpiles plunged, easing a glut. Futures climbed as much as 1.5 percent in New York after rising 4.6 percent in the previous two sessions. Inventories tumbled by 10.2 million barrels last week, the American Petroleum … Read more

New SHOWCASE Directory Companies

 

Predator Drilling
Environmental Refueling Systems (ERS)
Galloway Construction Group
Techmation Electric & Controls
Versa-Line
Assetworks
FUELware
Galdos Systems

Commencement of 2,550 km2 3D Seismic Survey

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

Date issue: July 26, 2017
Time in: 12:39 PM e

Attention:

TORONTO, ON–(Marketwired – July 26, 2017) – Eco (Atlantic) Oil and Gas Ltd
(TSX VENTURE: EOG) (AIM: ECO)

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

Eco Atlantic and Tullow Oil commence 2,550 km2 3D Seismic Survey Offshore
Guyana

Toronto, July 25th, 2017 – Eco (Atlantic) Oil & Gas Ltd. (“Eco Atlantic” or
“Company”) (TSX-V:EOG, LSE:ECO) is pleased to announce that Eco Atlantic and
its Operating Partner, Tullow Oil (“Tullow”), have commenced a 2,550 km2
seismic survey on the Company’s Orinduik Block offshore the Co-operative
Republic of Guyana (“Orinduik”). The survey is being conducted by Schlumberger
Guyana Inc. (Western Geco) using R/V GECO Eagle and two supporting vessels, and
is expected to be completed within 50 days following which the results will be
interpreted before an announcement is published.

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

http://www.rns-pdf.londonstockexchange.com/rns/2001M_1-2017-7-26.pdf

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/

– END RELEASE – 26/07/2017

For further information:
RNS
Customer Services
0044-207797-4400
[email protected]
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: 20170726CC0044

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.

New SHOWCASE Directory Companies

 

Techmation Electric & Controls
Environmental Refueling Systems (ERS)
Galloway Construction Group
Predator Drilling
Galdos Systems
FUELware
Assetworks
Versa-Line

Five Things World Business Will be Talking About Today

July 26, 2017 (Bloomberg)  It’s decision day at the Fed, the U.K. sees a “notable slowdown,” and oil holds over $48. Here are some of the things people in markets are talking about today. Fed meeting At 2 p.m. Eastern Time today, the Federal Open Markets Committee will announce its latest monetary policy decision. With no change … Read more

New SHOWCASE Directory Companies

 

Predator Drilling
Galloway Construction Group
Techmation Electric & Controls
Environmental Refueling Systems (ERS)
Galdos Systems
FUELware
Versa-Line
Assetworks

Perspective: A Worldwide Gas Glut Claims $27 Billion Victim in Canada

July 26, 2017 (Bloomberg)  A $27 billion energy project in Canada just became the latest casualty of a worldwide glut of natural gas. Malaysia’s Petroliam Nasional Bhd abandoned on Tuesday its plans for the Pacific Northwest LNG terminal, a plant that would have liquefied Canada’s gas and sent the fuel by tanker from the western … Read more

New SHOWCASE Directory Companies

 

Predator Drilling
Environmental Refueling Systems (ERS)
Galloway Construction Group
Techmation Electric & Controls
Versa-Line
FUELware
Assetworks
Galdos Systems

Why Electric Vehicles Are No Threat To Oil Prices Anytime Soon – David Yager – Yager Management

David-Yager-Feature Image

        David Yager – Yager Management Ltd. Oilfield Services Executive Advisory – Energy Policy Analyst July 26, 2017 Hardly a day goes by without another media report about the impending demise of the Internal Combustion Engine (ICE) as petroleum powered cars and trucks are replaced by uber-clean Electric Vehicles (EV). It is … Read more

New SHOWCASE Directory Companies

 

Environmental Refueling Systems (ERS)
Predator Drilling
Techmation Electric & Controls
Galloway Construction Group
Galdos Systems
Assetworks
FUELware
Versa-Line

High court gives red light for Clyde River but green light for Line 9 pipeline

OTTAWA — The Inuit Hamlet of Clyde River won a nearly six-year-long battle Wednesday to stop seismic testing in the Arctic that could kill or maim the marine mammals upon which they rely for food and jobs.

The Supreme Court unanimously ruled the National Energy Board failed miserably at properly consulting Inuit and didn’t adequately assess the impact on treaty and Indigenous rights of the proposed oil and gas exploration project before approving it in 2014.

The court quashed the NEB’s approval, meaning the testing cannot proceed.

In a separate but related decision, the court upheld the approval granted to Enbridge to reverse the flow and increase capacity of its Line 9 pipeline between Ontario and Quebec.

In that case, also a unanimous decision, the court found the NEB properly consulted the Chippewas of the Thames First Nation in southwestern Ontario.

In both cases, the court upheld that the NEB is capable and allowed to fulfil the Crown’s duty to consult Indigenous groups about development projects in their traditional territories, as long as that consultation is robust.

“What an exciting day for us,” said Jerry Natanine, the former mayor of Clyde River. “We’ve been saying justice is on our side because we’re fighting for our life, we’re fighting for our way of life.”

Natanine clutched an eagle feather as he spoke in soft tones of the years-long battle that pitted his tiny, remote hamlet of about 1,100 people against three Norwegian companies seeking to fire air guns into the waters of Baffin Bay and Davis Straight looking for oil.

“We are not totally against development, but it has to be done right,” Natanine said. “You know whales don’t have to die, seals don’t have to die off, or plankton. There’s a better way to do these things.”

Prime Minister Justin Trudeau said the government respects the Supreme Court and takes the judgements very seriously.

“For these two specific decisions, obviously we will study them, but what they underline is that Aboriginal communities need to be adequately consulted, have to be partners and be implicated in decisions,” he said at an event in Quebec. “And that’s what I’ve been saying for two years and that’s what we are working on.”

A spokeswoman for the NEB said the agency is reviewing the court decision.

Vancouver lawyer and Indigenous legal expert Tom Isaac said the decisions are a good day for Canada because the courts have outlined in some very specific ways what did and didn’t qualify as acceptable consultation.

“There isn’t a grey cloud of legal uncertainty over Canada on the duty to consult,” said Isaac. “They have filled in the blanks on what good consultation looks like and what bad consultation looks like.”

He said the decisions in a way form a blueprint for future development reviews and decisions, said Isaac.

The difference between the two decisions largely stemmed from the fact that in the Clyde River case the NEB looked at the environmental impacts of the testing, but didn’t specifically look at or address the impact on treaty rights.

The court said the Inuit had well-established treaty rights in the region, including the right to harvest marine mammals. It was also undisputed that the seismic testing could harm mammals like whales and seals, damaging their hearing, affecting their migration routes and even killing them.

That assessment meant the Crown’s duty to consult was “at the highest end of the spectrum,” but the consultations “fell short in several respects,” the court found.

The NEB didn’t hold oral hearings, didn’t provide funding to help the Inuit communities participate in the review process and relied on scientific information from the companies that was delivered in a format the Inuit couldn’t access.

“To put it mildly, furnishing answers to questions that went to the heart of the treaty rights at stake in the form of a practically inaccessible document dump months after the questions were initially asked in person is not true consultation,” the court wrote.

In the Chippewas case, the court found the NEB consultation process was proper, included adequate opportunity and funding for the Chippewas to participate and specifically addressed the impact on treaty rights.

The NEB found the project posed some risk to the Chippewas territory, but those risks could be mitigated. As well, Enbridge didn’t need any new land rights, most work would take place in existing facilities and use its existing right of way.

A Chippewas spokesperson hasn’t yet been available to comment.

Natanine said he was sad the Chippewas of the Thames were not successful in stopping the Enbridge pipeline expansion in their territory, even going so far as to wear a T-shirt with the words “Chippewas Solidarity” printed on the front.

The court issued a stern warning that the consultation process on Indigenous rights has to occur before projects are approved rather than after courts force it to happen.

“True reconciliation is rarely, if ever, achieved in courtrooms,” the judgement said.

— Follow @mrabson on Twitter.

Mia Rabson, The Canadian Press




New SHOWCASE Directory Companies

 

Galloway Construction Group
Predator Drilling
Environmental Refueling Systems (ERS)
Techmation Electric & Controls
Versa-Line
FUELware
Assetworks
Galdos Systems

Fraser Institute Media Advisory: How safe are marine tankers for transporting oil? New study coming Thursday, July 27

FOR: THE FRASER INSTITUTE
Date issue: July 26, 2017Time in: 5:00 AM eAttention:
CALGARY, AB –(Marketwired – July 26, 2017) – On Thursday, July 27, the
Fraser Institute will release a new study on oil and gas transportation.
Safety First: Intermodal …

New SHOWCASE Directory Companies

 

Galloway Construction Group
Predator Drilling
Environmental Refueling Systems (ERS)
Techmation Electric & Controls
Galdos Systems
Versa-Line
Assetworks
FUELware

B.C.’s new attorney general says province won’t delay Trans Mountain permits

David Eby BC Attorney General

VANCOUVER — British Columbia’s attorney general says the NDP government will not artificially delay permits for the Trans Mountain pipeline, despite the premier’s vow to use every available tool to stop the project.

David Eby said he’s been tasked by Premier John Horgan to identify options to halt Kinder Morgan Canada’s $7.4-billion expansion of its Alberta-to-B.C. pipeline, which has already been approved by Ottawa and the previous B.C. government.

Eby said the province cannot deliberately stall on permits without risking a very costly lawsuit, but it can ensure that permits require that construction be done in a way that minimizes spills, protects the environment and ensures appropriate cleanup.

“I’ve been tasked by the premier to identify our options. There is an important piece to that, which is that we must do so within the laws of British Columbia and Canada, because if we don’t, we’ll be sued,” Eby told Kamloops radio station CHNL.

“We’ll end up paying hundreds of millions of dollars that should be going to schools and hospitals to an oil company and that is not a goal that anybody’s looking for.”

Trans Mountain, a subsidiary of Kinder Morgan Canada, declined comment on Eby’s remarks but said it’s in an ongoing process of seeking and receiving permits from the necessary agencies, as construction of the project is phased.

Eby did not immediately respond to requests for comment from The Canadian Press.

Horgan’s NDP won 41 seats in the province’s May 9 election, shy of the 44 needed to mount a majority. But the Greens, who hold three seats, signed an agreement to support the New Democrats in a minority government.

The agreement states the government will “immediately employ every tool available to stop” the pipeline expansion.

A mandate letter issued by Horgan to Environment Minister George Heyman on Monday softens the language slightly, saying instead that he must employ every tool available to “defend B.C.’s interests in the face of” the expansion.

James Coleman, an energy law professor at Southern Methodist University who previously worked at the University of Calgary, said Eby’s remarks reflect the government’s need to be cautious about what it says and does.

“That’s certainly what you’d want to say. If you want to avoid compensation (to Trans Mountain), you wouldn’t want to give the suggestion that you were deliberately delaying or acting in bad faith,” he said.

“That’s one of those challenges the government faces. Because it has been so explicit that it’s going to use every tool to try and block this pipeline, that they may worry that the courts will see the government’s actions as being in bad faith.”

First Nations and environmental groups have filed lawsuits against the federal government’s approval of the project. Some groups have also launched legal challenges of B.C.’s environmental certificate.

The NDP government has not said what it plans to do about the lawsuits, but Coleman said if it is looking to avoid compensation, then the normal move would be to defend the certificate.

“The question is: Is that a half-hearted defence?” he asked. “I think that remains to be seen.”

Horgan said at a joint news conference with Prime Minister Justin Trudeau in Ottawa on Tuesday that he hasn’t yet been briefed by his attorney general but he has spoken with First Nations who have filed lawsuits against the federal government.

“I’ve met with the leadership of the Tsleil-Waututh, Musqueam and Squamish First Nations and have heard very clearly their views on the matter, and we’ll deal with those in the days and weeks ahead,” he said.

Charlene Aleck, an elected councillor of the Tsleil-Waututh, said she had met with Horgan and felt confident he supports their efforts to halt the pipeline expansion. However, Horgan has not signalled that he intends to join their legal fight, she said.

Green party Leader Andrew Weaver said in a statement that he understands Eby’s points and expects they are not indicative of a broader change in the NDP’s stance on the pipeline.

“As an opposition party, we will remain steadfast in calling on the NDP government to use every legally available tool to stop the pipeline from going ahead,” Weaver said.

— Follow @ellekane on Twitter.

Laura Kane, The Canadian Press

New SHOWCASE Directory Companies

 

Environmental Refueling Systems (ERS)
Techmation Electric & Controls
Galloway Construction Group
Predator Drilling
FUELware
Versa-Line
Galdos Systems
Assetworks

QuickQuotes: Supporters, detractors weigh in on Pacific Northwest LNG decision

VANCOUVER — Malaysian national energy company Petronas announced Tuesday it was walking away from the Pacific NorthWest LNG project, a massive liquefied natural gas development that was to be built in British Columbia. While the project received federal government approval, it also faced opposition from some First Nations and an environmental group that sought to squash the go-ahead in the courts.

Here is what some people had to say about it:

———

“NDP comes to office in B.C., Petronas immediately cancels its $30B LNG investment, 1 of the largest planned foreign investments in CDN history… NDP politicians want huge, endless increases in government spending, but oppose & drive away the industries that can help pay for it.” — Jason Kenney, who is running to be the leader of the newly formed United Conservative Party in Alberta, in a series of tweets.

———

“Since the beginning it has been clear that the global marketplace does not support the LNG industry that the BC Liberals promised in their 2013 election campaign. Rather than doing the hard work required to strengthen and secure the economic opportunities already available in other sectors, the BC Liberals recklessly went all in on a single industry. They let opportunities for innovation and economic development in clean technology, the resource sector and other major B.C. industries fall by the wayside.” — Andrew Weaver, leader of the B.C. Green caucus, in a statement.

———

“This is good news all around, because this project would have lost money while fuelling dangerous levels of climate change. The sooner we move on from fossil fuel mega-projects to building the renewable energy economy, the better positioned we’ll be to thrive in the emerging low-carbon world.” —  Keith Stewart, a senior energy strategist for Greenpeace Canada, in an email.

———

“Today’s decision by Petronas to cancel the Pacific Northwest LNG project sends a clear signal about the impact of the closed for businesses agenda put forward by the NDP government…. John Horgan’s activist NDP agenda is making it harder to do business in British Columbia. Massive carbon tax hikes will not be revenue-neutral and higher costs on flaring in the gas sector will make it more expensive to create jobs and do business in British Columbia.” — the B.C. Liberal Caucus in a statement.

———

“I think we need to be clear that British Columbia remains a player in the LNG sector and that I’ll be on the phone later today … with all of our LNG stakeholders to reassure them that this new NDP government is going to be working with them.” — Michelle Mungall, B.C.’s energy, mines and petroleum resources minister, at a press conference.

———

“Today’s announcement concerning the Pacific Northwest LNG project was a business decision made by the proponent…. We will continue to deliver for the energy sector, laying the foundation for its long-term, sustainable development and growth, which will maintain and create jobs while ensuring a cleaner Canada for future generations.” — Alexandre Deslongchamps, a Natural Resources Canada spokesperson, in an email.

———

“We are deeply disappointed that PNW will not go forward, as it means thousands of construction jobs will not materialize…. This is a significant lost opportunity that would have brought many benefits. Canada has to act faster to seize the opportunities that our responsible resource development industries can deliver.” — Chris Gardner, president of the Independent Contractor and Business Association of B.C., in a statement.

———

The Canadian Press

New SHOWCASE Directory Companies

 

Predator Drilling
Techmation Electric & Controls
Galloway Construction Group
Environmental Refueling Systems (ERS)
Assetworks
Versa-Line
FUELware
Galdos Systems

Pacific Northwest LNG mega-project not going ahead

Pacific Northwest LNG mega-project not going ahead

Pacific NorthWest LNG says it will not be proceeding with the $36-billion liquefied natural gas (LNG) mega-project it had planned to build in British Columbia. The consortium says the announcement by Petronas and its partners comes after a careful review of changes in market conditions. “We are disappointed that the extremely challenging environment brought about by the prolonged depressed … Read more

New SHOWCASE Directory Companies

 

Predator Drilling
Environmental Refueling Systems (ERS)
Galloway Construction Group
Techmation Electric & Controls
Assetworks
Galdos Systems
FUELware
Versa-Line

The evaporation of an LNG project: A chronology of Pacific NorthWest LNG

VANCOUVER — Here is a look at how the Pacific NorthWest LNG project evolved over the last several years before the announcement of its demise Tuesday:

Feb. 19, 2013: Pacific NorthWest LNG submits its project description to the Canadian Environmental Assessment Agency.

April 29, 2013: Japan Petroleum Exploration Co. Ltd. buys a 10 per cent stake in Pacific NorthWest LNG and agrees to buy 10 per cent of the liquefied natural gas produced over at least 20 years, becoming the first secure buyer.

Dec. 16, 2013: The National Energy Board grants Pacific NorthWest LNG a licence to export up to 22.2 million tonnes of LNG annually for 25 years. It had applied in July for a licence to export up to 19.68 million tonnes, beginning in 2019.

Feb. 28, 2014: Pacific NorthWest LNG submits its environmental impact statement to the Canadian Environmental Assessment Agency.

March 26, 2014: The federal government approves Pacific NorthWest LNG’s export licence.

June 11, 2015: In what it calls its final investment decision, Pacific NorthWest LNG announces it will proceed with the project as long as it satisfies two conditions: approval of a project development agreement by the B.C. legislature and clearing the federal environmental assessment review process.

July 21, 2015: The B.C. government passes legislation to ratify a project development agreement with Pacific NorthWest LNG.

March 21, 2016: The federal government grants the Canadian Environmental Assessment Agency more time to review the project.

Sept, 27, 2016: The federal government approves the project with 190 conditions, including for the first time a maximum cap on greenhouse gas emissions.

Oct. 27, 2016: Two First Nations and an environmental group file separate applications for judicial review in Federal Court to quash approval of the project. A fourth challenge is launched in January 2017.

July 25, 2017: Pacific Northwest LNG says it will not proceed with the project, citing poor market conditions including a prolonged period of low LNG prices.

The Canadian Press

New SHOWCASE Directory Companies

 

Environmental Refueling Systems (ERS)
Predator Drilling
Galloway Construction Group
Techmation Electric & Controls
FUELware
Assetworks
Versa-Line
Galdos Systems

Canadian airlines aiming to become a biofuel superpower, reduce carbon footprint

MONTREAL — The country’s top airlines say resource-rich Canada has the potential to become a biofuel superpower by transforming forest residue and agricultural crops into energy that can help the industry reduce greenhouse gas emissions.

“Canada actually has an opportunity like no other country where it can displace large amounts of fuel and reduce large amounts of carbon,” Mena Salib, Air Canada’s manager of aircraft noise and emissions, said Tuesday after speaking to a global biotech conference.

Salib said the industry wants to procure biofuels from local sources instead of transporting it far to meet demand.

“The prize would be technology from Canada, the feedstock is from Canada and it is used by Canadians.”

The country’s largest airline has been part of several flight tests to study biofuels and is ready to add the lower carbon energy blends when they are readily available.

The aviation industry is looking for ways to cut its environmental footprint and achieve the global goal of becoming carbon neutral after 2020 and to halve net emissions by 2050 compared to 2005.

While Air Canada (TSX:AC) and WestJet (TSX:WJA) don’t have a preference for using farm crops, forest residue or consumer waste, the airlines say the inputs must be sustainable and not displace food or land.

Costs would also have to come down by using government incentives to encourage companies to boost supply.

Geoffrey Tauvette, WestJet’s director of fuel and environment, says while the airline has invested heavily to improve the efficiency of its aircraft, biofuels are the only way to reduce emissions enough to meet global targets.

“We think that Canada has the right ingredients to be that superpower. We just need to get the right sort of instruments in place to be able to make that happen,” he said from Calgary.

While the airline hasn’t tested the use of biofuels, it has supported efforts, for example, to study turning forestry residue to energy.

“If we can get the biofuels, it does help WestJet meet our goal of connecting Canadians to the rest of the world and we can do that without impacting the environment.”

Fernando Preto, a research scientist with the Natural Resources Canada’s Canmet Energy group, said there are huge opportunities for Canada to supply biofuels from different sources.

Studies conducted at the University of British Columbia and in La Tuque, Que., are looking at using forest residue to produce green fuel.

Preto said millions of tonnes of branches, bark and scraps left behind during the cutting process could be a valuable resource.

“I think that it could easily meet the jet fuel requirements in Canada for the Canadian industry,” he said.

Biotechnology is a US$200 billion a year global industry, with about 20 per cent directed to fuels and much of the rest to consumer products, says Paul Winters, spokesman for the Biotechnology Innovation Organization which hosted the annual conference.

Agrisoma Biosciences Inc., a Gatineau-based company, announced on Monday a long-term agreement with biorefiner UPM of Finland to expand the use of the carinata oilseed crop to produce renewable fuels in South America.

The oilseed variety developed in Canada will be grown as a second crop in winter by farmers in Uruguay, followed by Brazil and Argentina. It can be used to produce non-edible oil suitable for low-carbon biofuels and a protein for animal feed.

“We’re on a growth trajectory where we can see really being a major feedstock for things like the aviation industry,” said Agrisoma CEO Steve Fabijanski.

Less than five per cent of flights are flown using biofuel blended with traditional jet fuel. Fabijanski said the use of biofuels will increase as costs decrease and new fuel distribution hubs beyond Los Angeles and Oslo are developed.

 

Follow @RossMarowits on Twitter.

Ross Marowits, The Canadian Press

New SHOWCASE Directory Companies

 

Techmation Electric & Controls
Galloway Construction Group
Environmental Refueling Systems (ERS)
Predator Drilling
Versa-Line
Assetworks
FUELware
Galdos Systems

Petronas-backed Pacific NorthWest LNG megaproject in B.C. scrapped

Malaysian national energy giant Petronas and its partners scrapped the Pacific NorthWest LNG megaproject Tuesday, ending months of anticipation on the fate of what would have been one of Canada’s largest private infrastructure investments.

The decision to cancel the development boiled down to simple economics — a world market awash in liquefied natural gas, which has driven down prices, making Pacific NorthWest LNG no longer financially viable, said Anuar Taib, CEO of Petronas’s oil and gas production division.

“Unfortunately for us, we don’t believe we have that mix of where the sweet spot can be hit,” Taib said.

While Pacific NorthWest LNG worked its way through regulatory channels over the last several years, numerous LNG projects have come online around the world.

The overall project would have cost $36 billion in total, including a 900-kilometre pipeline proposed by TransCanada (TSX:TRP) to a natural gas export terminal on the province’s Lelu Island, as well as the production of gas to supply it.

TransCanada later said it was reviewing its options on the $5-billion Prince Rupert Gas Transmission project, which was dealt its own setback last week after the Federal Court of Appeal ruled that the National Energy Board will need to reconsider whether it requires federal approval.

The export facility, with an estimated cost of $11.4 billion, would have compressed the natural gas into liquid form before it would be shipped to markets in Asia.

The announcement Tuesday came a couple of hours after Prime Minister Justin Trudeau met with British Columbia Premier John Horgan in Ottawa. The federal government gave its conditional approval to the project last September. Horgan voiced opposition to it, though late last month he said his position may be swayed if the concerns of First Nations were taken into consideration.

Both the federal and provincial governments emphasized that the decision was a private sector one.

“The company was very clear: this was a decision they are making because of the economic challenges in the global energy market place,” B.C. Energy Minister Michelle Mungall said.

“The Pacific NorthWest LNG project as proposed in its current state was uneconomical to move forward.”

Mungall said the government would work to make B.C. competitive in the global LNG industry as other proposed West Coast LNG projects sit in various stages of development.

The B.C. Liberal caucus was quick to lay blame on what it called a “closed for business” agenda of the newly sworn-in B.C. NDP government.

But when asked whether the election of the NDP played any role in the decision, Taib gave an unequivocal no. He said Petronas is still committed to working on developing the natural gas assets in northeastern B.C. it bought in part to supply the LNG terminal.

“We actually look forward to working with John Horgan and his government as we develop our vast assets in the Montney joint venture area,” he said.

B.C. Green Leader Andrew Weaver, who is helping prop up the NDP government in a coalition, said the singular pursuit of the LNG industry by the former B.C. Liberal government was a mistake.

“B.C.’s future does not lie in chasing yesterday’s fossil fuel economy,” Weaver said in a statement. “It lies in taking advantage of opportunities in the emerging economy in order to create economic prosperity in B.C.”

Environmentalists and some First Nations welcomed news of Pacific NorthWest LNG’s demise, saying it would have resulted in a spike in greenhouse gas emissions and threatened salmon habitat.

“We’re absolutely thrilled that the Malaysian backers of this liquefied natural gas terminal have backed down from their reckless plan to jeopardize B.C.’s second largest salmon run and blow our provincial climate targets,” Peter McCartney, climate campaigner for the Wilderness Committee, said in a statement.

Ian Bickis and Aleksandra Sagan, The Canadian Press


New SHOWCASE Directory Companies

 

Techmation Electric & Controls
Galloway Construction Group
Environmental Refueling Systems (ERS)
Predator Drilling
Versa-Line
FUELware
Galdos Systems
Assetworks

TransCanada Responds to PNW LNG Decision; Company to be reimbursed for full costs to advance PRGT Project

FOR: TRANSCANADA
TSX SYMBOL: TRP
NYSE SYMBOL: TRP

Date issue: July 25, 2017
Time in: 4:15 PM e

Attention:

CALGARY, ALBERTA–(Marketwired – July 25, 2017) – Media Advisory – TransCanada
Corporation (TSX:TRP)(NYSE:TRP) (TransCanada) today was notified that PETRONAS
affiliate Pacific NorthWest LNG (PNW LNG) would not be proceeding with their
proposed LNG project near Port Edward, British Columbia.

Following is a statement from Karl Johannson, TransCanada’s executive
vice-president and president, Canada and Mexico natural gas pipelines and
energy:

With this news, we are reviewing our options related to our proposed Prince
Rupert Gas Transmission (PRGT) project as we continue to focus on our
significant investments in new and existing natural gas infrastructure to meet
our customers’ needs.

As part of our agreement with PETRONAS affiliate, Progress Energy, following
receipt of a termination notice, TransCanada would be reimbursed for the full
costs and carrying charges incurred to advance the PRGT project. We expect to
receive this payment later in 2017.

We are proud of the work we have done along the PRGT route, which has allowed
us to sign 14 Project Agreements with First Nations and secure the key
regulatory approvals and permits. We have built strong new relationships, and
we look forward to continuing our strong partnerships with First Nations and
communities in B.C. as we develop other natural gas assets, including our North
Montney Mainline project. This important project is backed by independent
20-year commercial service agreements with 11 shippers (including Progress
Energy), and pending regulatory approvals, we remain ready to move forward.

There is still a strong need for Canadian natural gas supplies to get to
market, and the infrastructure we are building in Alberta and British Columbia
– including recently announced multi-billion dollar investments in our NGTL
system and North Montney Mainline – are designed to help move natural gas
supplies to markets where they are needed.

With more than 65 years’ experience, TransCanada is a leader in the responsible
development and reliable operation of North American energy infrastructure
including natural gas and liquids pipelines, power generation and gas storage
facilities. TransCanada operates a network of natural gas pipelines that
extends more than 91,500 kilometres (56,900 miles), tapping into virtually all
major gas supply basins in North America. TransCanada is the continent’s
leading provider of gas storage and related services with 653 billion cubic
feet of storage capacity. A large independent power producer, TransCanada
currently owns or has interests in approximately 6,200 megawatts of power
generation in Canada and the United States. TransCanada is also the developer
and operator of one of North America’s leading liquids pipeline systems that
extends over 4,300 kilometres (2,700 miles), connecting growing continental oil
supplies to key markets and refineries. TransCanada’s common shares trade on
the Toronto and New York stock exchanges under the symbol TRP. Visit
TransCanada.com to learn more, or connect with us on social media and 3BL Media.

– END RELEASE – 25/07/2017

For further information:
Media Enquiries:
Mark Cooper / Shawn Howard
403.920.7859 or 800.608.7859
OR
TransCanada Investor & Analyst Enquiries:
David Moneta / Stuart Kampel
403.920.7911 or 800.361.6522

COMPANY:
FOR: TRANSCANADA
TSX SYMBOL: TRP
NYSE SYMBOL: TRP

INDUSTRY: Energy and Utilities – Oil and Gas
RELEASE ID: 20170725CC0045

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.

New SHOWCASE Directory Companies

 

Techmation Electric & Controls
Galloway Construction Group
Environmental Refueling Systems (ERS)
Predator Drilling
Assetworks
FUELware
Galdos Systems
Versa-Line

Join us on July 28th at Side Street for a fun pub night to support the Enbridge Ride to Conquer Cancer!

RSVP at [email protected]

New SHOWCASE Directory Companies

 

Techmation Electric & Controls
Environmental Refueling Systems (ERS)
Galloway Construction Group
Predator Drilling
Assetworks
Galdos Systems
FUELware
Versa-Line

Oil Rises as Saudis Pledge Deep Export Cuts, Shale Boom Slows

Oil Rises as Saudis Pledge Deep Export Cuts, Shale Boom Slows

July 25, 2017 (Bloomberg)  Oil rose as Saudi Arabia promised deep cuts to crude exports next month while the U.S. shale boom showed signs of slowing. Futures in New York added 1.8 percent, the biggest gain in almost a week. Saudi Arabia will cap shipments at 6.6 million barrels a day in August, 1 million … Read more

New SHOWCASE Directory Companies

 

Galloway Construction Group
Environmental Refueling Systems (ERS)
Techmation Electric & Controls
Predator Drilling
FUELware
Assetworks
Galdos Systems
Versa-Line

Five Things World Business Will be Talking About Today

July 25, 2017 (Bloomberg)  Senate takes another shot at health-care legislation, oil gets a lift from Saudi Arabia, and Goldman downplays risks from a strong euro. Here are some of the things people in markets are talking about today. Healthcare Washington will see U.S. Senator John McCain return to Capitol Hill today as Republicans and President Donald Trump … Read more

New SHOWCASE Directory Companies

 

Environmental Refueling Systems (ERS)
Predator Drilling
Techmation Electric & Controls
Galloway Construction Group
Galdos Systems
Assetworks
Versa-Line
FUELware

While Oil Patch Bleeds, Gas Drillers Race to Unleash Wells

July 25, 2017 (Bloomberg)  Oil prices have been lousy for so long that U.S. producers are hoarding unfinished wells rather than pumping crude out of them. In the natural gas patch, just the opposite is happening. While the energy slump has idled lots of wells for both commodities, their economics have diverged. Oil remains at half … Read more

New SHOWCASE Directory Companies

 

Techmation Electric & Controls
Galloway Construction Group
Environmental Refueling Systems (ERS)
Predator Drilling
FUELware
Assetworks
Versa-Line
Galdos Systems

Pipeline project, wildfires top agenda for first meeting between Trudeau, Horgan

Pipeline project, wildfires top agenda for first meeting between Trudeau, Horgan

OTTAWA — The debate around the future of the planned TransMountain pipeline expansion in British Columbia could intensify today when Prime Minister Justin Trudeau meets new B.C. Premier John Horgan for the first time.

Horgan was sworn into office last week after an unprecedented photo-finish election that saw former premier Christy Clark’s short-lived minority Liberal government defeated and Horgan’s NDP take over with the backing of the Green party.

Trudeau’s government approved the $7.4-billion pipeline expansion project last fall but Horgan campaigned against it and has pledged to fight the project with every tool at his disposal.

The two leaders have sidestepped the issue in official communications thus far, including a news release from Horgan on Monday where he said he intends to discuss the opioid crisis, B.C.’s wildfire emergency and the softwood lumber dispute with the U.S.

But there is little time for Horgan to waste if he wants to stop the project as pipeline-builder Kinder Morgan said just last week construction is on schedule to begin in September.

Following Horgan’s Ottawa trip, he will fly on to Washington, D.C., for meetings with U.S. lawmakers and officials about the softwood lumber dispute.

The Canadian Press

Note to readers: This is a corrected story. A previous version said Horgan was sworn in last month instead of last week.

New SHOWCASE Directory Companies

 

Galloway Construction Group
Techmation Electric & Controls
Environmental Refueling Systems (ERS)
Predator Drilling
FUELware
Galdos Systems
Versa-Line
Assetworks

U.A.E. Sees OPEC Considering Oil-Cuts Extension in November

July 24, 2017 (Bloomberg)  OPEC may need to consider extending its oil-cuts agreement when the group meets in November, as crude markets are taking too long to recover, United Arab Emirates Energy Minister  Suhail Al Mazrouei said. The Organization of Petroleum Exporting Countries, which already prolonged its cuts accord with other major producers through the … Read more

New SHOWCASE Directory Companies

 

Techmation Electric & Controls
Predator Drilling
Galloway Construction Group
Environmental Refueling Systems (ERS)
Assetworks
FUELware
Galdos Systems
Versa-Line

Anadarko Cuts Drilling Plan as Oil Explorers Bow to Slump

July 24, 2017 (Bloomberg)  Anadarko Petroleum Corp. is cutting spending on drilling in another sign that low crude prices may finally be forcing a pullback in the U.S. shale boom. The company, one of the largest oil and natural gas explorers in the U.S., is paring $300 million from its 2017 capital budget, lowering it … Read more

New SHOWCASE Directory Companies

 

Techmation Electric & Controls
Galloway Construction Group
Predator Drilling
Environmental Refueling Systems (ERS)
Assetworks
FUELware
Galdos Systems
Versa-Line

Halliburton Sees Drillers `Tap the Brakes’ on Shale Boom

halliburton-logo

July 24, 2017 (Bloomberg) Halliburton Co., promising to be disciplined in adding more fracking gear to the oilfields, says U.S. explorers are “tapping the brakes” on drilling as the price of oil struggles to breach $50 a barrel. The comments come days after Baker Hughes data found that explorers reduced the number of U.S. rigs … Read more

New SHOWCASE Directory Companies

 

Predator Drilling
Galloway Construction Group
Environmental Refueling Systems (ERS)
Techmation Electric & Controls
Assetworks
Galdos Systems
FUELware
Versa-Line

PrairieSky Announces Second Quarter 2017 Results

FOR: PRAIRIESKY ROYALTY LTD.
TSX SYMBOL: PSK

Date issue: July 24, 2017
Time in: 4:01 PM e

Attention:

CALGARY, ALBERTA–(Marketwired – July 24, 2017) – PrairieSky Royalty Ltd.
(“PrairieSky” or the “Company”) (TSX:PSK) is pleased to announce its second
quarter operating and financial results for the period ended June 30, 2017.

/T/

—————————————————————————-

2017 Second Quarter Highlights:

– Funds from operations of $75.0 million or $0.32 per share, basic and
diluted and net income of $40.5 million or $0.17 per share, basic and
diluted

– Revenues of $102.2 million including $69.0 million of royalty revenue
and $29.5 million of lease bonus consideration generated by leasing land
for new and existing plays

– Average royalty production of 25,706 BOE per day, 48% liquids

– Completed acquisitions of additional producing and non-producing
royalties for cash consideration of $9.7 million

– Maintained a strong balance sheet with $108.0 million of positive
working capital, including $96.9 million of cash on hand and nil debt as
of June 30, 2017

—————————————————————————-

/T/

PRESIDENT’S MESSAGE

It was an active quarter for leasing across our fee land base. PrairieSky
entered into 37 leasing arrangements with 34 different producers on our fee
lands generating record quarterly lease bonus consideration of $29.5 million,
of which $14.3 million was cash. Leasing was particularly active on our over
890 sections of Duvernay rights. Non-cash lease bonus consideration related to
an amended leasing arrangement and provided PrairieSky with new and existing
gross overriding royalties on developed and undeveloped lands as well as
ownership in complementary seismic. Leasing of our undeveloped acreage is a
precursor to drilling activity and future royalty production revenues at no
cost to PrairieSky.

Producers spud 104 wells on PrairieSky’s land base despite a challenging
commodity price environment and spring break-up. Drilling activity focused on
the Viking oil play in both Western Saskatchewan and Central Alberta, the
multi-zone Deep Basin fairway of Alberta and British Columbia and light and
heavy oil plays across Central Alberta. During the quarter, PrairieSky acquired
gross overriding royalties on producing and undeveloped lands for cash proceeds
of $9.7 million which provide exposure to existing and future development for
all commodities, including multi-zonal resource play opportunities in the Deep
Basin. PrairieSky continues to be selective and disciplined in our evaluation
of new royalty opportunities.

PrairieSky’s large undeveloped land position, low cost structure and high
margin royalty production continues to deliver strong funds flow and growth
opportunities with no capital requirements. During the quarter, PrairieSky
declared dividends of $44.5 million and acquired and cancelled 397,200 common
shares for $11.6 million under its normal course issuer bid (“NCIB”). In
addition to dividends declared and the NCIB, PrairieSky generated excess free
cash flow of $18.9 million in the quarter. At June 30, 2017, PrairieSky had
$108.0 million of positive working capital, including $96.9 million of cash on
hand and no debt.

PrairieSky marked its third anniversary during the quarter and we would like to
thank our dedicated group of employees for their efforts as well as our
shareholders for their continued support. Please contact Pam Kazeil, our Chief
Financial Officer, at 587-293-4089 or myself at 587-293-4005 with any questions.

Andrew Phillips, President & CEO

FINANCIAL AND OPERATIONAL INFORMATION

The following table summarizes select operational and financial information of
the Company for the periods noted. All dollar amounts are stated in Canadian
dollars unless otherwise noted.

FINANCIAL RESULTS

/T/

($ Millions,
except per share Three months Three months
or as otherwise ended ended
noted) June 30, 2017 June 30, 2016 YTD 2017 YTD 2016
—————— —————- —————- ———– ———–
FINANCIAL
Revenues $ 102.2 $ 48.1 $ 182.5 $ 97.0
Funds from
Operations 75.0 42.8 142.3 84.2
Per Share –
basic and
diluted(1)(4) 0.32 0.19 0.60 0.37
Net Earnings
(Loss) and
Comprehensive
Income (Loss) 40.5 (5.7) 61.3 (4.0)
Per Share –
basic and
diluted(1) 0.17 (0.02) 0.26 (0.02)
Dividends
declared(2) 44.5 41.2 87.7 104.5
Per Share 0.1875 0.1800 0.3700 0.4567
Acquisitions
including non-
cash
consideration 24.9 24.9 279.4 27.6
Working Capital at
end of period 108.0 171.1 108.0 171.1
Shares Outstanding 236.6 228.8 236.6 228.8
Weighted average
– basic 236.8 228.9 236.7 228.8
Weighted average
– diluted 237.1 229.1 237.0 229.0
OPERATIONAL
Production Volumes
Natural Gas
(MMcf/d) 80.6 75.3 81.1 73.0
Crude Oil
(bbls/d) 9,609 8,213 9,910 8,480
NGL (bbls/d) 2,664 2,395 2,830 2,473
—————— —————- —————- ———– ———–
Total (BOE/d)(3) 25,706 23,158 26,257 23,120
—————— —————- —————- ———– ———–
Realized Pricing
Natural Gas
($/Mcf) $ 2.15 $ 0.67 $ 2.20 $ 1.22
Crude Oil
($/bbl) 52.98 45.01 52.89 39.41
NGL ($/bbl) 28.60 22.79 29.83 20.88
—————— —————- —————- ———– ———–
Total ($/BOE)(3) $ 29.51 $ 20.50 $ 29.99 $ 20.53
—————— —————- —————- ———– ———–

Operating Netback
per BOE(4) $ 25.28 $ 17.18 $ 26.22 $ 16.41
Funds from
Operations per
BOE $ 32.06 $ 20.31 $ 29.94 $ 20.01
Natural Gas Price
Benchmarks
AECO ($/Mcf) 2.77 1.25 2.86 1.67
Oil Price
Benchmarks
West Texas
Intermediate
(WTI) (US$/bbl) 50.27 45.64 51.03 38.99
Edmonton Light
Sweet ($/bbl) 64.81 55.00 64.55 48.59
—————————————————————————-
—————————————————————————-
(1) Net Earnings (Loss) and Comprehensive Income (Loss) and Funds from
Operations per common share are calculated using the weighted average
number of common shares outstanding.
(2) A dividend of $0.0625 per common share was declared on June 15, 2017
and paid on July 17, 2017 to shareholders of record as at June 30,
2017.
(3) See “Conversions of Natural Gas to BOE”.
(4) A Non-GAAP measure which is defined under the Non-GAAP Measures
section in PrairieSky’s MD&A.

/T/

A full version of PrairieSky’s Management’s Discussion and Analysis (“MD&A”)
and unaudited interim condensed financial statements and notes thereto for the
fiscal period ended June 30, 2017 is available on SEDAR at www.sedar.com and
PrairieSky’s website at www.prairiesky.com.

CONFERENCE CALL DETAILS

A conference call to discuss the results will be held for the investment
community on Tuesday, July 25, 2017 beginning at 6:30 a.m. MDT (8:30 a.m. EDT).
To participate in the conference call, approximately 10 minutes prior to the
conference call, please dial:

/T/

(866) 413-7174 (toll free in North America)
(647) 427-2293 (International)

/T/

FORWARD-LOOKING STATEMENTS

This press release includes certain statements regarding PrairieSky’s future
plans and operations and contains forward-looking statements that we believe
allow readers to better understand our business and prospects. 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. Forward-looking statements contained in this press
release include our expectations with respect to PrairieSky’s business and
growth strategy, additional land leasing activities, future royalty production
and development and the linkage between new land leasing activity as a
precursor to drilling or production from the lands.

With respect to forward-looking statements contained in this press release, we
have made several assumptions including those described in detail in our MD&A
and the Annual Information Form for the year ended December 31, 2016. Readers
and investors are cautioned that the assumptions used in the preparation of
such forward-looking information and statements, 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. Our actual
results, performance, or achievements could differ materially from those
expressed in, or implied by, these forward-looking statements. We can give no
assurance that any of the events anticipated will transpire or occur, or if any
of them do, what benefits we will derive from them.

By their nature, forward-looking statements are subject to numerous risks and
uncertainties, some of which are beyond our control, including the impact of
general economic conditions, industry conditions, volatility of commodity
prices, lack of pipeline capacity, currency fluctuations, imprecision of
reserve estimates, royalties, environmental risks, taxation, regulation,
changes in tax or other legislation, competition from other industry
participants, the lack of availability of qualified personnel or management,
stock market volatility, political and geopolitical instability and our ability
to access sufficient capital from internal and external sources. In addition,
PrairieSky is subject to numerous risks and uncertainties in relation to
acquisitions. These risks and uncertainties include risks relating to the
potential for disputes to arise with counterparties, and limited ability to
recover indemnification under certain agreements. The foregoing and other risks
are described in more detail in PrairieSky’s MD&A, and the Annual Information
Form for the year ended December 31, 2016 under the headings “Risk Management”
and “Risk Factors”, respectively, each of which is available at www.sedar.com.

Further, any forward-looking statement is made only as of the date of this
press release, and PrairieSky undertakes no obligation to update or revise any
forward-looking statement or statements to reflect events or circumstances
after the date on which such statement is made or to reflect the occurrence of
unanticipated events, except as required by applicable securities laws. New
factors emerge from time to time, and it is not possible for PrairieSky to
predict all of these factors or to assess in advance the impact of each such
factor on PrairieSky’s business or the extent to which any factor, or
combination of factors, may cause actual results to differ materially from
those contained in any forward-looking statements.

The forward-looking information contained in this document is expressly
qualified by this cautionary statement.

CONVERSIONS OF NATURAL GAS TO BOE

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). PrairieSky 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 either energy content or 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.

NON-GAAP MEASURES

Certain measures in this document and PrairieSky’s MD&A do not have any
standardized meaning as prescribed by International Financial Reporting
Standards (“IFRS”) and, therefore, are considered non-GAAP measures. Non-GAAP
measures are commonly used in the oil and gas industry and by PrairieSky to
provide potential investors with additional information regarding the Company’s
liquidity and its ability to generate funds to conduct its business. Further
information can be found in the Non-GAAP Measures section of PrairieSky’s MD&A.

ABOUT PRAIRIESKY ROYALTY LTD.

PrairieSky is a royalty-focused company, generating royalty revenues as
petroleum and natural gas are produced from its properties. PrairieSky has a
diverse portfolio of properties that have a long history of generating free
cash flow and that represent the largest and most concentrated
independently-owned fee simple mineral title position in Canada. PrairieSky’s
common shares trade on the Toronto Stock Exchange under the symbol PSK.

– END RELEASE – 24/07/2017

For further information:
PrairieSky Royalty Ltd.
Andrew Phillips
President & Chief Executive Officer
587-293-4005
OR
PrairieSky Royalty Ltd.
Pamela Kazeil
Vice President, Finance & Chief Financial Officer
587-293-4089
OR
PrairieSky Royalty Ltd.
Investor Relations
(587) 293-4000
www.prairiesky.com

COMPANY:
FOR: PRAIRIESKY ROYALTY LTD.
TSX SYMBOL: PSK

INDUSTRY: Energy and Utilities – Oil and Gas
RELEASE ID: 20170724CC0043

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.

New SHOWCASE Directory Companies

 

Techmation Electric & Controls
Galloway Construction Group
Environmental Refueling Systems (ERS)
Predator Drilling
Galdos Systems
FUELware
Versa-Line
Assetworks

Supporters, foes clash over underwater oil pipeline’s future

TRAVERSE CITY, Mich. — An engineering company’s report on the future of twin oil pipelines beneath the Straits of Mackinac is flawed and biased in favour of continuing the existing system, critics said Monday. A business coalition said keeping oil flowing through the 64-year-old pipes is essential to Michigan’s economy.

Supporters and opponents of Enbridge Inc.’s Line 5 made their cases as officials convened a series of public feedback sessions on a draft analysis performed for the state of Michigan. The report submitted in June by Dynamic Risk Assessment Systems Inc. outlined six alternatives for the line, which transports about 23 million gallons daily between Superior, Wisconsin, and Sarnia, Ontario. A nearly 5-mile-long (8-kilometre) segment divides into two pipes at the bottom of the waterway connecting Lakes Huron and Michigan.

“The report is unreliable and should not be used,” said Liz Kirkwood, executive director of For Love of Water, an environmental advocacy group that wants the underwater portion of Line 5 decommissioned. “Instead, the state should protect the Great Lakes from the potential of a catastrophic oil spill and exercise its legal authority to revoke Enbridge’s permission to use the waters and lakebed that belong to the people of Michigan.”

Dynamic Risk Assessment Systems is based in the Canadian city of Calgary, Alberta — as is Enbridge, which paid for the study although the state requested it. State officials and representatives of the engineering company were hosting public discussions of the draft Monday in Holt and Traverse City and Tuesday in St. Ignace. A final version is due this fall.

Protesters demanding the shutdown of Line 5 waved placards at passing cars before the Traverse City session, which drew more than 300 people to Northwestern Michigan College on the shore of Lake Michigan’s Grand Traverse Bay.

“The thought of oil bubbling up in this beautiful lake is more than I can bear,” local resident Barbara Schneider said. “We can’t eat oil, we can’t drink oil and water is life.”

Rob Kitchen, an Enbridge area supervisor from Okemos, said the Canadian company employs Michigan residents who also love the Great Lakes.

“We’re Michigan people working every day like everybody else to make sure Line 5 is safe,” he said.

Kirkwood said the draft’s six options did not include diverting Line 5’s oil to other pipelines in service. It downplayed the likelihood of an eventual pipeline failure and used a best-case scenario to estimate potential damage to shorelines and the economy, she said. And it assumed no reduction could be made in the volume of oil and liquid natural gas the line carries.

Ed Timm, a retired Dow Chemical Co. engineer and Line 5 opponent, said the report also glosses over bends in the lines that could signal damage caused by strong currents and erosion of sediment beneath the pipes.

Enbridge spokesman Ryan Duffy said the bends reflect natural drop-offs in the lake floor’s elevation that the pipeline was designed to accommodate. The company is seeking state permission to install 22 additional supports for the line, including five in a 200-foot sloping area.

“We have tested the pipe and have not found any integrity issue anywhere,” Duffy said.

Several business organizations, including the Michigan Chamber of Commerce and representatives of manufacturers and energy suppliers, said the Dynamic Risk Assessment Systems study provided more evidence that Line 5 should stay in operation.

“The fact is that pipelines are proven to be the safest, smartest way to transport energy,” said Erin McDonough, president of the Michigan Oil and Gas Association. “They reduce risk by moving product off roads and rails that run through the hearts of Michigan communities. We need Line 5 to remain in service, and we need it independently inspected, diligently maintained and operated safely.”

___

Follow John Flesher on Twitter at http://twitter.com/JohnFlesher

John Flesher, The Associated Press

New SHOWCASE Directory Companies

 

Techmation Electric & Controls
Predator Drilling
Environmental Refueling Systems (ERS)
Galloway Construction Group
FUELware
Galdos Systems
Assetworks
Versa-Line

Weekly Canadian Oil & Gas Industry Highlights – July 24, 2017

POIM Feature Image

July 24, 2017 Presented by POIM Consulting Group Major /Interesting Projects CNRL Six New Bitumen battery BONNYVILLE, LINDBERGH area Canadian International Oil Operating Corporation New Compressor existing facility GRANDE PRAIRIE – KARR Westbrick Energy Ltd Compressor install New Battery WILLESDEN GREEN CNRL 25 New Well License most located BONNYVILLE-LINDBERGH Devon Canada New Well PAD WAINWRIGHT … Read more

New SHOWCASE Directory Companies

 

Galloway Construction Group
Environmental Refueling Systems (ERS)
Techmation Electric & Controls
Predator Drilling
FUELware
Versa-Line
Galdos Systems
Assetworks

New Methane Gas Emission Rules Raise Questions​ – MNP LLP

MNP-Feature

​​ New regulations to cut methane gas emissions might address some of Ottawa’s concerns about climate change but leave some in the oil and gas industry with questions and concerns about the process. At issue is the analysis in the government’s Regulatory Impact Analysis Statement released on May 25.  Questions include the source of the … Read more

New SHOWCASE Directory Companies

 

Predator Drilling
Techmation Electric & Controls
Environmental Refueling Systems (ERS)
Galloway Construction Group
FUELware
Versa-Line
Galdos Systems
Assetworks

Saudis Plan to Tackle Lagging Compliance With Oil Cuts `Head On’

July 24, 2017 (Bloomberg)  Saudi Arabia, OPEC’s biggest oil producer, plans to step up pressure on nations that aren’t complying with their commitment to cut output, including a proposal to start monitoring exports. “Some countries continue to lag” in their compliance, Saudi Oil Minister Khalid Al-Falih said Monday in St. Petersburg, Russia, where he’s attending … Read more

New SHOWCASE Directory Companies

 

Predator Drilling
Techmation Electric & Controls
Galloway Construction Group
Environmental Refueling Systems (ERS)
Versa-Line
Assetworks
Galdos Systems
FUELware

This Obscure NAFTA Chapter Could Be Canada’s Deal-Breaker Again

July 24, 2017 (Bloomberg)  On Oct. 1, 1987, days before the U.S. and Canada signed their biggest-ever trade deal, then-Prime Minister Brian Mulroney shocked the Americans by walking away from the negotiating table. It was a high-stakes gamble designed to ensure the Free Trade Agreement contained a dispute-settlement mechanism — what Mulroney called his essential condition … Read more

New SHOWCASE Directory Companies

 

Environmental Refueling Systems (ERS)
Techmation Electric & Controls
Predator Drilling
Galloway Construction Group
Galdos Systems
Assetworks
Versa-Line
FUELware

Oil Rises as Saudi Arabia Pledges Deep Cut to August Exports

Saudi Aramco

July 24, 2017 (Bloomberg)  Oil rose as Saudi Arabia said it would make deep cuts to its crude exports in August and encourage better compliance with supply reductions from other producers. Futures rose as much as 1.2 percent in New York. Saudi Arabia, OPEC’s largest producer, will limit exports to 6.6 million barrels a day … Read more

New SHOWCASE Directory Companies

 

Predator Drilling
Galloway Construction Group
Techmation Electric & Controls
Environmental Refueling Systems (ERS)
FUELware
Galdos Systems
Assetworks
Versa-Line

Five Things World Business Will be Talking About Today

July 24, 2017 (Bloomberg)  It’s PMI day, no change at OPEC meeting, and no end in sight to dollar bearishness. Here are some of the things people in markets are talking about today. Europe growth A composite Purchasing Managers’ Index for the euro area fell to 55.8 in July, the weakest pace in six months, according … Read more

New SHOWCASE Directory Companies

 

Environmental Refueling Systems (ERS)
Predator Drilling
Techmation Electric & Controls
Galloway Construction Group
Assetworks
Versa-Line
Galdos Systems
FUELware

IMF Sees 2017 Saudi Growth `Close to Zero’ on Oil Prices, Cuts

July 23, 2017 Saudi Arabia’s economy will stall this year with growth “close to zero” due to lower oil revenue, the International Monetary Fund said. The fund lowered its 2017 growth forecast to 0.1 percent from 0.4 percent, citing OPEC production cuts, uncertainty over oil prices and the structural reforms the country is undertaking to … Read more

New SHOWCASE Directory Companies

 

Galloway Construction Group
Environmental Refueling Systems (ERS)
Techmation Electric & Controls
Predator Drilling
Assetworks
Galdos Systems
FUELware
Versa-Line

Five things to watch for in Canadian business this week

TORONTO — Five things to watch for in the Canadian business world in the coming week:

John, meet Justin: John Horgan is expected to head to Ottawa this week to meet Prime Minister Justin Trudeau for the first time since he became British Columbia’s premier. Horgan and Trudeau don’t see eye-to-eye on the Trans Mountain pipeline expansion. Trudeau has endorsed the project, while Horgan has vowed to do what he can to prevent it from proceeding.

The earnings parade: It’s going to be a heavy earnings week, with many companies in the forestry, mining and oil and gas sectors reporting. Among those releasing their latest quarterly results are Barrick Gold, Goldcorp, Suncor Energy, Cenovus Energy and Canfor.

Taking over Tembec: Shareholders in Quebec forestry products firm Tembec will vote Thursday on a friendly takeover offer by Florida-based Rayonier Advanced Materials. But the deal appears in doubt. Two of Tembec’s largest shareholders have come out against the agreement and have been trying to sway others to reject it.

Bombardier reports: Interest in Bombardier’s financial performance extends beyond the investment community, particularly given the public money the company has received to support its CSeries aircraft. The plane and train manufacturer reports its second-quarter results on Friday.

Keeping an eye on the economy: Statistics Canada comes out Friday with the GDP figures for May. Steady economic growth this year helped convince the central bank to raise its key interest rate earlier this month, and you can bet all eyes will be on this latest batch of data to see if that’s continuing and whether another hike is in store.

The Canadian Press

New SHOWCASE Directory Companies

 

Environmental Refueling Systems (ERS)
Galloway Construction Group
Techmation Electric & Controls
Predator Drilling
Galdos Systems
FUELware
Versa-Line
Assetworks

Oil Slides Most in Two Weeks as OPEC Production Is Seen Rising

July 21, 2017 (Bloomberg)  Oil dropped the most in two weeks as a report that OPEC’s July supply will be the highest this year fueled worries over a global glut. Futures tumbled 2.5 percent in New York on Friday, erasing gains from earlier this week. Supply from OPEC is set to exceed 33 million barrels a day … Read more

New SHOWCASE Directory Companies

 

Techmation Electric & Controls
Environmental Refueling Systems (ERS)
Galloway Construction Group
Predator Drilling
Assetworks
FUELware
Galdos Systems
Versa-Line

Core Inflation Uptick Backs Case for Second Canada Rate Hike

Core Inflation Uptick Backs Case for Second Canada Rate Hike

July 21, 2017 (Bloomberg)  Canada’s core consumer prices and retail sales came in faster than expected, signaling that overall inflation may turn around to clear the way for another rate increase this year. The average of the central bank’s three core inflation measures rose to 1.4 percent in June, Statistics Canada said Friday from Ottawa, up … Read more

New SHOWCASE Directory Companies

 

Predator Drilling
Environmental Refueling Systems (ERS)
Techmation Electric & Controls
Galloway Construction Group
FUELware
Galdos Systems
Assetworks
Versa-Line

Boss, I’d Sell More if Only You Would… – Sandler Training

Sandler Training Featured Image

      Written by Hamish Knox; President of Sandler in Calgary, Canada Creating accountable, sales focused organizations in Calgary   Too often, especially when the economy slows, sales leaders hear, “boss, I’d sell more if only you would…” from their team. These “if onlys” tend to fall into three categories – more, better and/or different … Read more

New SHOWCASE Directory Companies

 

Techmation Electric & Controls
Environmental Refueling Systems (ERS)
Galloway Construction Group
Predator Drilling
Galdos Systems
FUELware
Assetworks
Versa-Line

US rig count decreases by 2 last week to 950: 462 rigs were active last year

Baker_Hughes_Logo_Feature

HOUSTON — The number of rigs exploring for oil and natural gas in the U.S. decreased by two this week to 950.

A year ago, just 462 rigs were active.

Houston oilfield services company Baker Hughes said Friday that 764 rigs sought oil and 186 explored for natural gas this week.

Among major oil- and gas-producing states, Louisiana gained four rigs, California increased by two and North Dakota and Utah each gained one.

Oklahoma and Texas each declined by three, New Mexico fell by two and Alaska decreased by one.

Arkansas, Colorado, Ohio, Pennsylvania, 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

New SHOWCASE Directory Companies

 

Techmation Electric & Controls
Predator Drilling
Environmental Refueling Systems (ERS)
Galloway Construction Group
Versa-Line
Galdos Systems
Assetworks
FUELware

The Latest: Opponents criticize pipeline assessment

RICHMOND, Va. — The Latest on the proposed Atlantic Coast Pipeline (all times local):

1:30 p.m.

Organizations that oppose the proposed Atlantic Coast Pipeline say the three-state project is far from a done deal, despite the release of an environmental review by federal regulators that’s largely favourable for developers.

The Federal Energy Regulatory Commission released its final environmental impact statement for the natural gas pipeline Friday. It found the project would have some negative impacts, though most could be reduced to insignificant levels.

The Allegheny-Blue Ridge Alliance, a coalition of community groups and legal and technical experts who oppose the pipeline, pointed out that state-level water quality approvals are still pending in West Virginia, Virginia and North Carolina. Other federal approvals are still pending and legal challenges have also been filed.

The Southern Environmental Law Center, which also opposes the project, said FERC had glossed over important environmental impacts in favour of green-lighting “another unneeded natural gas pipeline.”

____

11:50 a.m.

The lead developer of the proposed Atlantic Coast Pipeline says a “favourable” environmental review by federal regulators has paved the way for final approval of the $5 billion project.

The Federal Energy Regulatory Commission released its final environmental impact statement for the natural gas pipeline Friday. It found the project would have some negative impacts, though most could be reduced to insignificant levels.

Leslie Hartz, a vice-president of Dominion Energy, said in a statement that the report “provides a clear path for final approval” in the fall.

She notes the company made more than 300 route adjustments to protect the environment or important features of individual properties.

The 600-mile pipeline would carry natural gas across West Virginia, Virginia and North Carolina.

___

An environmental assessment of the proposed Atlantic Coast natural gas pipeline finds the three-state project would have some adverse effects, including impacts on water resources, forest and other habitats, as well as endangered species.

The assessment was published Friday by the Federal Energy Regulatory Commission, which oversees interstate natural gas pipelines. It says if developers use proper construction and mitigation techniques, most of those impacts could be reduced to “less-than-significant” levels.

The agency’s commissioners will consider the analysis in making their final decision about whether to approve the 600-mile (965-kilometre) pipeline that would cross West Virginia, Virginia and North Carolina.

The Atlantic Coast Pipeline has drawn opposition from environmental groups and many landowners. But many political and business leaders say it will provide cleaner energy and boost economic development.

The Associated Press

New SHOWCASE Directory Companies

 

Environmental Refueling Systems (ERS)
Predator Drilling
Galloway Construction Group
Techmation Electric & Controls
Galdos Systems
Versa-Line
FUELware
Assetworks

Dakota Access developer gets OK to replace trees

BISMARCK, N.D. — North Dakota regulators approved a plan by the developer of the Dakota Access oil pipeline to replace trees removed during construction, but the permission won’t impact an upcoming decision on whether Texas-based Energy Transfer Partners is fined for removing too many.

Meanwhile, the tree work has been stalled by drought and won’t be completed for another year.

Public Service Commission Public Utilities Director Patrick Fahn earlier this month signed off on the company’s plan to plant two trees for every one removed — a total of about 94,000 along the route of the $3.8 billion pipeline that on June 1 began moving oil from North Dakota to Illinois.

A law firm representing numerous North Dakota landowners in May filed a consultant’s report that said ETP’s plan had flaws, including planting far fewer species than were removed. Landowner attorney Derrick Braaten said in an interview Friday that talks continue with the company to resolve numerous issues. While taking the company to court remains an option, “that’s certainly not the direction I’d want to go,” he said.

ETP spokeswoman Lisa Dillinger said the company continues to work with landowners to address concerns. The tree work began in May but has been put on hold due to drought and won’t be completed until next spring, she said.

A report last December from a third-party inspector for the Public Service Commission identified 83 sites along the 380-mile (610-kilometre) pipeline corridor in North Dakota where trees might have been cleared in violation of the commission’s orders. The commission has scheduled an Aug. 17 public hearing. ETP, which could face fines of up to $200,000, maintains it did nothing wrong.

The tree replacement plan isn’t part of the discussion and the company’s double planting of trees won’t be a possible mitigating factor in any decision on fines, according to Commissioner Julie Fedorchak. The ratio is standard, she said, and it’s also impossible to know how many of the new trees will survive.

“The concern in this whole tree removal issue is that there is a good portion of North Dakota where growing trees is a challenge,” she said. “If you’ve got trees in existence that are helping prevent erosion and providing wildlife habitat, we want to minimize the amount that are removed.”

___

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

Blake Nicholson, The Associated Press

New SHOWCASE Directory Companies

 

Techmation Electric & Controls
Environmental Refueling Systems (ERS)
Predator Drilling
Galloway Construction Group
Galdos Systems
Versa-Line
Assetworks
FUELware

Market Your Company on EnergyNow.ca – See July Specials & Pricing Options HERE

  Market Your Products/Services on EnergyNow.ca Get Brand Exposure  . Market your Services & Products  . Generate Leads  . Find Employees OPTIONS: Option  1: Featured Premium SHOWCASE with Company Article – $2,500 (one-time annual cost) + Applicable Taxes   (Save $1,250 this month) Premium Listing (Click Here For Example)   Publish Content on EnergyNow.ca for … Read more

New SHOWCASE Directory Companies

 

Predator Drilling
Galloway Construction Group
Environmental Refueling Systems (ERS)
Techmation Electric & Controls
FUELware
Galdos Systems
Assetworks
Versa-Line

Environmental report on pipeline favourable for developers

RICHMOND, Va. — The Atlantic Coast Pipeline intended to carry natural gas across West Virginia, Virginia and North Carolina would have some adverse environmental effects, including impacts on water resources, forest and other habitats, but most could be reduced to insignificant levels, an assessment by federal regulators found.

The Federal Energy Regulatory Commission, which oversees interstate natural gas pipelines, released its final environmental impact statement Friday for the proposed 600-mile (965-kilometre) pipeline, which has broad support from political and business leaders but is staunchly opposed by environmentalists and many affected landowners.

The assessment is a major milestone in the approval process for the project that will cross hundreds of bodies of water, mountainous terrain, national forest, and the Appalachian Trail. Its findings were largely favourable for developers.

The impact statement did find that construction in steep terrain could increase the potential for landslides and that the project was likely to adversely affect seven species protected under the Endangered Species Act. It found that the greatest impact on vegetation would be on forested areas, with more than 3,400 acres having long-term or permanent effects.

But overall, the assessment said that if developers use proper construction and mitigation techniques, most of environmental impacts could be reduced to “less-than-significant” levels.

The leading company behind the project said FERC’s assessment “provides a clear path” for final approval later this year.

“While some impacts on the environment and landowners are unavoidable with any infrastructure project, the report demonstrates that we’ve taken all necessary steps to minimize those impacts and balance them with the urgent public need for the project,” Leslie Hartz, Dominion Energy’s vice-president for engineering and construction, said in a statement.

Environmental groups, which argue that FERC’s approval process is inadequate and biased in favour of pipeline developers, criticized the assessment, saying it glossed over important environmental impacts.

“Regardless of FERC’s decision, the Atlantic Coast Pipeline is not a done deal. Far from it,” said Lew Freeman, director of the Allegheny-Blue Ridge Alliance, a coalition of community groups and legal and technical experts who oppose the pipeline.

He pointed out that state level water-quality permits are still pending. Legal challenges have also been filed, and more could come.

Initially proposed in 2014, the underground pipeline, parts of which would be 42 inches in diameter, would be capable of delivering up to 1.5 billion cubic feet of fracked natural gas from the Utica and Marcellus shale deposits per day to customers in Virginia and North Carolina.

It would originate in north-central West Virginia, cross Virginia’s Shenandoah Valley and run south of the Virginia capital of Richmond to a compressor station near the North Carolina border. An extension would run to the Hampton Roads area along the coast while the main pipeline would continue into North Carolina, ending near the South Carolina line.

Pipeline proponents — including union leaders, economic development officials and top lawmakers of both parties in all three states — have said it would deliver cheap and abundant energy that is cleaner than coal.

“The ACP will be built and operated in an environmentally responsible manner, and it will bring much needed American energy to Virginia consumers,” Republican leaders of the Virginia General Assembly said in a statement.

Developers have also promised construction alone would create will create 17,000 new jobs and $2.7 billion in economic activity across the region, and once the pipeline is operational, they say the reliable supply of natural gas will attract heavy manufacturers that have previously passed over Virginia and North Carolina.

EnergySure, a coalition of individuals, businesses and organization in the three states, called the project “a once-in-a-generation opportunity to revitalize our region’s manufacturing economy.”

Opponents, however, say the pipeline would infringe on landowners’ property rights, damage pristine areas and commit the region to a fossil fuel just when global warming makes it essential to invest in renewable energy instead. They also argue the demand for gas has been overstated and the capacity of existing infrastructure has been underestimated by developers, who are guaranteed a financial return on the project.

“FERC still hasn’t addressed the most basic question hanging over this project: Is it even needed?” Southern Environmental Law Center Senior Attorney Greg Buppert said in a statement. “It’s FERCs responsibility to determine if this pipeline is a public necessity before it allows developers to take private property, clear forests, and carve up mountainsides.”

FERC’s commissioners will weigh the environmental impact statement as well as whether the project meets a public need and whether its proposed gas rates are just and reasonable in making a final decision on whether the pipeline can proceed, according to spokeswoman Tamara Young-Allen.

Ordinarily, a final decision can come any time after a pipeline’s final environmental impact statement is complete, but the five-member panel currently lacks a quorum, with only one commissioner currently serving.

President Donald Trump has announced four nominees, who still must be approved by the Senate.

In addition to Dominion, the pipeline is being developed by Duke Energy, Piedmont Natural Gas, and Southern Company Gas. It is estimated to cost between $5 billion and $5.5 billion to construct.

Sarah Rankin, The Associated Press



New SHOWCASE Directory Companies

 

Environmental Refueling Systems (ERS)
Predator Drilling
Techmation Electric & Controls
Galloway Construction Group
Versa-Line
FUELware
Galdos Systems
Assetworks

Regulators release environmental assessment of pipeline

RICHMOND, Va. — The Atlantic Coast Pipeline intended to carry natural gas across West Virginia, Virginia and North Carolina would have some adverse environmental effects, including impacts on water resources, forest and other habitats, but most could be reduced to insignificant levels, an assessment by federal regulators found.

The Federal Energy Regulatory Commission, which oversees interstate natural gas pipelines, released its final environmental impact statement Friday for the proposed 600-mile (965-kilometre) pipeline, which has broad support from political and business leaders but is staunchly opposed by environmentalists and many affected landowners.

The assessment found that the pipeline would also impact some endangered species in its path. But it concluded that if developers use proper construction and mitigation techniques, most of environmental impacts could be reduced to “less-than-significant” levels.

The leading company behind the $5 billion project called the assessment “favourable” and said it paved the way for final approval later this year.

“While some impacts on the environment and landowners are unavoidable with any infrastructure project, the report demonstrates that we’ve taken all necessary steps to minimize those impacts and balance them with the urgent public need for the project,” Leslie Hartz, Dominion Energy’s vice-president for engineering and construction, said in a statement.

Environmental groups have argued that FERC’s process for approving pipelines is broken and doesn’t adequately evaluate the true need for additional infrastructure.

“FERC still hasn’t addressed the most basic question hanging over this project: Is it even needed?” Southern Environmental Law Center Senior Attorney Greg Buppert said in a statement. “It’s FERCs responsibility to determine if this pipeline is a public necessity before it allows developers to take private property, clear forests, and carve up mountainsides. Mounting evidence shows that it is not.”

The agency’s commissioners will weigh the environmental impact statement as well as whether the project meets a public need and whether its proposed gas rates are just and reasonable in making that decision, according to FERC spokeswoman Tamara Young-Allen.

Ordinarily, a final decision can come any time after a pipeline’s final environmental impact statement is complete, but the five-member panel currently lacks a quorum, with only one commissioner currently serving.

President Donald Trump has announced four nominees, who still must be approved by the Senate.

Initially proposed in 2014, the underground pipeline would originate in north-central West Virginia, cross Virginia’s Shenandoah Valley and run south of the Virginia capital of Richmond to a compressor station near the North Carolina border. An extension would run to the Hampton Roads area along the coast while the main pipeline would continue into North Carolina, ending near the South Carolina line.

Pipeline proponents — including union leaders, economic development officials and top lawmakers of both parties in all three states — have said it would deliver cheap and abundant energy that is cleaner than coal.

Developers also promised construction alone would create will create 17,000 new jobs and $2.7 billion in economic activity across the region, and once the pipeline is operational, they say the reliable supply of natural gas will attract heavy manufacturers that have previously passed over Virginia and North Carolina.

Opponents, however, said the pipeline would infringe on landowners’ property rights, damage pristine areas and commit the region to a fossil fuel just when global warming makes it essential to invest in renewable energy instead. They also argue the demand for gas has been overstated and the capacity of existing infrastructure has been underestimated.

The pipeline is being developed by four energy companies: Richmond-based Dominion Energy, Duke Energy, Piedmont Natural Gas, and Southern Company Gas.

The Associated Press



New SHOWCASE Directory Companies

 

Galloway Construction Group
Techmation Electric & Controls
Predator Drilling
Environmental Refueling Systems (ERS)
FUELware
Versa-Line
Galdos Systems
Assetworks

First Nations lawsuit blames government inaction for Husky oil spill

A First Nation’s lawsuit says government inaction is at least partly behind a Husky Energy oil spill that fouled water supplies for tens of thousands of people along the North Saskatchewan River last summer.

The James Smith band in Melfort, Sask., says the province ignored recommendations from its own auditor general on pipeline safety made four years before the accident.

The 2012 report concluded that the government didn’t have the resources to ensure its pipeline rules were being followed and that some were being ignored.

About 40 per cent of a 225,000-litre spill from the Husky (TSX:HSE) pipeline reached the river and forced three cities to shut off their water intake for almost two months.

The James Smith First Nation says oil from the spill remains in water, soil, vegetation and debris on its land.  

The Canadian Press

New SHOWCASE Directory Companies

 

Galloway Construction Group
Techmation Electric & Controls
Environmental Refueling Systems (ERS)
Predator Drilling
Galdos Systems
Assetworks
FUELware
Versa-Line

Petrolia Obtains Order to Extend the Deadline to hold its Annual General Shareholders’ Meeting and Announces Second Amendment to Arrangement Agreement

FOR: PETROLIA INC.TSX VENTURE SYMBOL: PEADate issue: July 21, 2017Time in: 4:11 PM eAttention:
QUEBEC CITY, QUEBEC–(Marketwired – July 21, 2017) – Petrolia Inc. (TSX
VENTURE:PEA) (“Petrolia” or the “Company”) is pleased to announce that it has
obtain…

New SHOWCASE Directory Companies

 

Galloway Construction Group
Techmation Electric & Controls
Predator Drilling
Environmental Refueling Systems (ERS)
Assetworks
Versa-Line
FUELware
Galdos Systems

Encana reports US$331M profit on earlier than expected ‘production bounce’

CALGARY — Higher production of more profitable products in the second quarter allowed oil and gas producer Encana Corp. (TSX:ECA) to handily beat analyst expectations while posting a US$331-million net profit.

“Our core assets have returned to growth, delivering our planned mid-year production bounce ahead of schedule,” said CEO Doug Suttles on a conference call Friday.

“We continue to enhance well productivity across the portfolio and, as a result, we now expect the core assets will deliver 25 to 30 per cent growth in the fourth quarter of 2017 as compared with the fourth quarter of 2016.”

The Calgary-based oil and gas company, which presents its results in U.S. dollars, reported Friday net earnings per share of 34 cents, compared with a loss of US$601 million, or 71 cents per share, in the same period last year.

Its operating earnings were 18 cents per share, well ahead of analysts’ average estimate of four cents, according to Thomson Reuters.

Encana has sold non-core assets over the past four years to reduce debt, with the result that production has fallen from 528,000 barrels of oil equivalent per day in 2012 to 353,000 boe/d last year.

Its updated guidance shows that overall production this year is expected to average about 315,000 boe/d as growth in its core four production areas — the Montney and Duvernay in Western Canada and the Eagle Ford and Permian in the United States — is offset by the sale of assets in Colorado and Louisiana that would have contributed about 18,000 boe/d.

Encana said it produced about 316,000 boe/d in the three months ended June 30, slightly above analyst predictions, of which about 40 per cent was higher value liquid hydrocarbons like oil and condensate and 60 per cent was less profitable natural gas.

In the same quarter last year, its production of 368,000 boe/d was weighted 64 per cent to gas.

The company expects to increase its oil and liquids ratio to about 41 per cent by the end of 2017.

Encana said it would leave its 2017 capital budget at between $1.6 billion and $1.8 billion despite recent oil price volatility.

 

Follow @HealingSlowly on Twitter.

Dan Healing, The Canadian Press

Note to readers: This is a corrected story. An earlier version said Encana’s annual shareholder meeting would be held today, but it was on May 2.

New SHOWCASE Directory Companies

 

Galloway Construction Group
Techmation Electric & Controls
Predator Drilling
Environmental Refueling Systems (ERS)
Assetworks
FUELware
Versa-Line
Galdos Systems

“Dirty, Difficult, And Dangerous”: Why Millennials Won’t Work In Oil

July 21, 2017  Oilprice.com Like many industries today, the oil industry is trying to sell its many job opportunities to the fastest growing portion of the global workforce: Millennials. But unlike any other industry, oil and gas is facing more challenges in persuading the environmentally-conscious Millennials that oil is “cool”.During the Super Bowl earlier this year, … Read more

New SHOWCASE Directory Companies

 

Predator Drilling
Galloway Construction Group
Environmental Refueling Systems (ERS)
Techmation Electric & Controls
Assetworks
Galdos Systems
FUELware
Versa-Line

Expander Receives Alberta Energy Regulator Approval to Build Canada’s First Commercial Gas to Liquids Plant

CALGARY, ALBERTA (July 12, 2017) – James Ross, CEO of Expander Energy Inc. (“Expander”), is pleased to announce that Expander has received Alberta Energy Regulator approval to build and operate Canada’s first commercial gas to liquids (“GTL”) plant. Expander, through its subsidiary, Rocky Mountain GTL Inc., intends to build the Enhanced GTL® (“EGTL™”) plant at … Read more

New SHOWCASE Directory Companies

 

Environmental Refueling Systems (ERS)
Predator Drilling
Techmation Electric & Controls
Galloway Construction Group
FUELware
Assetworks
Versa-Line
Galdos Systems

Canada Inflation Slows to 1% in June, Core Rises: Key Takeaways

July 21, 2017 (Bloomberg)  Canada’s inflation rate fell to 1 percent in June, the slowest since October 2015 on declines in energy and clothing, while core measures accelerated. Retail sales rose 0.6 percent in May, twice as fast as economists predicted. Statistics Canada said Friday the average of three measures of core inflation picked up … Read more

New SHOWCASE Directory Companies

 

Galloway Construction Group
Techmation Electric & Controls
Predator Drilling
Environmental Refueling Systems (ERS)
Galdos Systems
Versa-Line
FUELware
Assetworks

U.S. Owns 700 Million Barrels of Oil. Trump Wants to Sell It

July 21, 2017 (Bloomberg)  The weather was hot and humid on July 21, 1977, the day the U.S. government began stockpiling oil. It started small. Just 412,000 barrels of Saudi Arabian light crude stashed in a Southeast Texas salt cavern. In the wake of the Arab oil embargo, which sent prices through the roof and … Read more

New SHOWCASE Directory Companies

 

Techmation Electric & Controls
Environmental Refueling Systems (ERS)
Predator Drilling
Galloway Construction Group
Assetworks
FUELware
Galdos Systems
Versa-Line

OPEC, Russia to Stand Pat on Oil Deal Even as Glut Persists

July 21, 2017 (Bloomberg)  OPEC and Russia’s plan to clear the global oil glut hasn’t worked as they hoped, but there’s little expectation the world’s largest producers will act more aggressively when they meet this weekend. Oil has slumped into a bear market and inventories remain stubbornly high despite a deal between OPEC and 10 … Read more

New SHOWCASE Directory Companies

 

Predator Drilling
Environmental Refueling Systems (ERS)
Galloway Construction Group
Techmation Electric & Controls
FUELware
Versa-Line
Assetworks
Galdos Systems

Five Things World Business Will be Talking About Today

 July 21, 2017 (Bloomberg)  Mueller widens probe, post-Brexit transition plan wins cabinet support, and banks profit like it’s 2007. Here are some of the things people in markets are talking about today. Mueller probe Special Counsel Robert Mueller has expanded his probe into possible ties between the Donald Trump campaign and Russia to include a … Read more

New SHOWCASE Directory Companies

 

Environmental Refueling Systems (ERS)
Techmation Electric & Controls
Predator Drilling
Galloway Construction Group
FUELware
Galdos Systems
Assetworks
Versa-Line

Oil Declines as OPEC’s Supply Is Seen at Highest Level This Year

July 21, 2017 (Bloomberg)  Oil declined after tanker-tracker Petro-Logistics SA said OPEC’s supply in July will be the highest this year. Futures fell as much as 0.5 percent in New York, erasing a weekly gain. Supply from OPEC members is set to exceed 33 million barrels a day this month, more than 600,000 barrels a day … Read more

New SHOWCASE Directory Companies

 

Galloway Construction Group
Predator Drilling
Techmation Electric & Controls
Environmental Refueling Systems (ERS)
FUELware
Assetworks
Galdos Systems
Versa-Line

Husky Energy set to repair pipeline that spilled crude into river a year ago

CALGARY — Husky Energy (TSX:HSE) says it has been granted permission to repair and replace a section of pipeline that leaked 225,000 litres of crude in Saskatchewan just over a year ago.

Chief executive Robert Peabody said that it will be applying lessons learned from the spill on the rebuild.

“My mother used to tell me this, learn from your mistakes and don’t do it again,” Peabody told a conference call Friday to discuss Husky’s latest financial results.

With the pipeline out of commission, Husky has been relying on tanker trucks to transport crude the final leg to Lloydminster, Sask., until it is repaired and permission is granted by the government to resume operations.

The company said it plans to include more monitoring equipment that will measure ground movement, as well as add thicker and higher grades of steel pipe to the section of pipe that burst near the North Saskatchewan River.

The spill sent about 40 per cent of the leaked crude into the waterway, forcing communities downstream to shut off a main source of water for almost two months.

“There’s a lot of changes that’s going to take place there, changes to the design, changes to monitoring equipment,” Peabody said.

Husky has been criticized for its slow response to the spill.

The company said two leak detection systems indicated pressure anomalies at 8 p.m. on July 20, 2016, but it didn’t start shutting down the line until 6 a.m. the following morning.

A government investigation found that pipeline’s alarms were warning of potential problems and continued until the line was shut down for scheduled maintenance at 7:15 a.m. on July 21.

Peabody said the many variables including temperature, pressure and flow in pipelines make it hard for standard leak detection systems to know for sure when a leak has happened, as was the case in the North Saskatchewan spill.

“It’s not that the systems failed, it’s just that there wasn’t an unambiguous message coming from the system,” he said.  

The planned extra equipment for the section, including fibre optic cables to detect pipeline and ground movement, will help make it clear when a spill has happened.

Husky’s investigation determined the pipeline buckled because of ground movement. The company has said it accepts full responsibility and is using what it learned to improve operations.

The Saskatchewan Justice Department said recently it was still reviewing Husky’s response to the spill to decide whether charges should be laid.

The government is itself under scrutiny on its spill prevention measures, with the James Smith First Nation launching a lawsuit alleging the province ignored recommendations from its own auditor general on pipeline safety and so is at least partly to blame for the spill.

Talk of the spill came after a lacklustre quarter for the company, which reported a $93-million loss for its second quarter and just $10 million of adjusted earnings, well below analyst expectations of $80 million in adjusted earnings according to Thomson Reuters data.

The results were, however, a boost from the same quarter last year when the company had a net loss of $196 million and a $91-million adjusted loss.

Ian Bickis, The Canadian Press

New SHOWCASE Directory Companies

 

Predator Drilling
Techmation Electric & Controls
Galloway Construction Group
Environmental Refueling Systems (ERS)
Versa-Line
Galdos Systems
Assetworks
FUELware

Encana reports US$331 million profit, says 5-year plan ahead of schedule

Encana reports US$331 million profit, says 5-year plan ahead of schedule

CALGARY — Encana Corp. (TSX:ECA) says its core operations will grow their production even more than expected this year, following a strong second quarter that included a US$331 million net profit.

The Calgary-based oil and gas producer, which reports in U.S. currency, says the profit amounted to 34 cents per share.

During last year’s second quarter, Encana had a $601-million net loss, equal to 71 cents per share.

The company says it now expects 2017 production from its core operations will be between 25 and 30 per cent above last year’s fourth quarter level.

Encana had previously estimated the production from core operations would grow 20 per cent or better.

 

The Canadian Press

Note to readers: This is a corrected story. An earlier version said Encana’s annual shareholder meeting would be held today, but it was on May 2.

New SHOWCASE Directory Companies

 

Techmation Electric & Controls
Predator Drilling
Galloway Construction Group
Environmental Refueling Systems (ERS)
Galdos Systems
Assetworks
FUELware
Versa-Line

Alimentation Couche-Tard looks to Norway for guidance to adapt to electric cars

MONTREAL — Alimentation Couche-Tard, one of the largest gas retailers in Canada, is looking to Norway for guidance on how to adapt to growing electric car sales, a trend that some investors fear could threaten its current raison d’etre.

The Quebec-based convenience store company, which established a foothold in the Scandinavian country five years ago with its purchase of Statoil ASA’s fuel and retail operations, says it wants to ensure it will still appeal to customers if they no longer need to fill up on gas.

“We’ll look at Norway as a laboratory to the future,” CEO Brian Hannasch said during an earnings conference call earlier this month.

“We’re very much engaged to see how we can win there.”

When it comes to embracing electric vehicles, Norwegians are in a class of their own. In a country of about five million people, there are about 120,000 full-electric or plug-in hybrid automobiles on the road — a per capita ownership ratio 23 times larger than in Canada.

About 43 per cent of all auto sales in Norway last month were for electric vehicles. In Canada, that figure was less than one per cent.

Still, if Canadians ever do take up electric vehicles in large numbers, that could spell doom for service station operators if their business models don’t evolve.

Couche-Tard relied on fuel to deliver 40 per cent of its gross profits and 69 per cent of its revenues in its last fiscal year.

It did not return repeated requests for information on whether it has any charging stations in Canada. But according to Flo, which runs a network of charging stations, Couche-Tard has at least 15 of them.

While it takes just a few minutes to fill up on gas, it can take anywhere from half an hour to several hours to fully charge an electric vehicle, which raises a question: will Canadians want to charge their cars the same way they buy gas and what does that mean for Couche-Tard and other similar businesses?

Hannasch said convenience retailers that sell gas have overcome other obstacles to customer traffic. Increased automobile fuel efficiency is the latest challenge, but they have also had to contend with falling cigarette sales and the convenience of paying at the pump that has allowed customers to avoid entering stores altogether.

In a bid to address the potential threat from electric vehicles, Couche-Tard is testing new food offerings at some of its 300-plus locations in Norway in the hopes that customers will stop to spend time and money at their stations.

The head of the Norwegian Electric Vehicle Association said she is increasingly getting calls from companies around the world seeking advice on how to prepare.

“Big companies are waking up,” secretary-general Christina Bu said from Oslo.

Restaurants, grocers, malls and large retailers like Ikea are installing chargers to attract customers.

“If the gas station chains don’t adapt quickly enough, there will be other players that sort of take this market,” Bu said.

Other gas station banners including Petro-Canada, Irving Oil and Harnois Groupe Petrolier are either testing the use of charging stations or have rolled them out at some of their locations.

“Restaurants are on these sites,” said Claudine Harnois, vice-president of Harnois Groupe Petrolier. “Electric vehicle drivers stop for a little more than 10 minutes to grab a bite to eat or shop at the convenience store.”

Industry analysts say they’ve heard from nervous Couche-Tard (TSX:ATD.B) investors who fear that rising demand for electric cars will choke gasoline sales.

“Investor concern regarding the impact of electric vehicles has picked up recently, but we believe this remains in the distance,” analyst Mark Petrie of CIBC World Markets wrote in a report to analysts.

In another report, Keith Howlett of Desjardins Capital Markets added: “Investor anxiety over the timing of the impact of electric and hybrid vehicles has escalated.”

Several big oil companies have left the gas station business, including Imperial Oil (TSX:IMO), which sold nearly 500 Esso stations. More than half of those stations went to Couche-Tard.

In a report released this week, the U.S. Fuels Institute said sales of vehicles powered by fuels other than gas or diesel are expected to grow by 28 per cent annually in North America over the next eight years. But it added that the internal combustion engine will continue to dominate the light-duty vehicle market.

There were more than 4,500 electric vehicle chargers across the country as of Dec. 31, according to Plug’n Drive, a Canadian non-profit organization that is working to speed up the adoption of electric vehicles.

 

Follow @RossMarowits on Twitter.

Ross Marowits, The Canadian Press

New SHOWCASE Directory Companies

 

Environmental Refueling Systems (ERS)
Techmation Electric & Controls
Galloway Construction Group
Predator Drilling
FUELware
Galdos Systems
Versa-Line
Assetworks

Canada Energy Partners Updates Appeal Process for Water Disposal

FOR: CANADA ENERGY PARTNERS INC.
TSX VENTURE SYMBOL: CE

Date issue: July 21, 2017
Time in: 7:30 AM e

Attention:

VANCOUVER, BRITISH COLUMBIA–(Marketwired – July 21, 2017) – Canada Energy
Partners Inc.’s (TSX VENTURE:CE) (the “Company”) has made its final submission
required under the appeal procedures to the Oil & Gas Appeal Tribunal of
British Columbia (the “Tribunal”). The Tribunal now has all the pleadings,
responses, and evidence and will begin deliberating toward a decision. There is
no specified time frame for a decision from the Tribunal. All of the Company’s
submissions to the Tribunal can be viewed on our website at:
www.canadaenergypartners.com.

On June 16, 2017, the Company received a letter from the BC Oil & Gas
Commission (the “OGC”) which stated, “I write to advise that the Commission is
considering taking action under Section 26(1)(c) of the Oil and Gas Activity
Act to cancel the above noted well permit.” The OGC still has this matter under
consideration and has not made a decision.

Also on June 16, 2017, the OGC concluded and released the results of its
Technical Review of the Company’s water disposal well and the potential of
induced seismicity related thereto. The OGC engaged an outside consultant to
evaluate the risk of damage to the Peace Canyon Dam (the “PCD”) from induced
seismic event related to the Company’s water disposal operations, which
concluded in part, “A pulse type motion, as is expected from a low to moderate
induced seismic event, is considered to have a reduced probability of causing
failure or damage to the PCD….We have not identified any compelling reason
for induced seismicity to result in significant damage to, or an outright
failure, of the PCD. Based on the recorded history of fracking and injection
well induced seismic events in northeast BC, and provided that reinjection
conditions remain similar to the practice to date, the probability of
significant damage or a failure occurring is within expected norms for life
safety, based on the British Columbia Building Code and our present
understanding of the stability of the PCD structure.” The Company believes that
this study supports the preservation of its disposal well permit and the
reinstatement of its water disposal rights.

The Company will announce the Tribunal’s decision and/or the OGC decision as
soon as it is received.

On behalf of the Board of Directors of

Canada Energy Partners Inc.

Benjamin Jones, President & CEO

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

This press release contains forward-looking statements within the meaning of
applicable securities laws. Forward-looking statements are frequently
characterized by words such as “plan”, “expect”, “project”, “intend”,
“believe”, “anticipate”, “estimate” and other similar words or statements that
certain events or conditions “may” or “will” occur, including, without
limitation, estimated revenues.

Forward-looking statements 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. These
factors include, without limitation, regulatory approvals, mechanical integrity
of the water disposal well, receptivity of the disposal zone, variability of
operating costs, risks associated with oil and gas production and exploration,
retention of and ability to attract company personnel, volatility of commodity
prices, currency and interest rate fluctuations, environmental risk, inability
to access sufficient capital from internal and external sources and changes in
legislation, including income tax, environmental and regulatory matters.

This press release, in particular the information in respect of estimated
revenues, may contain future-oriented financial information or financial
outlook within the meaning of applicable securities laws. Such future-oriented
financial information or financial outlook has been prepared for the purpose of
providing information about management’s reasonable expectations as to the
anticipated results of its proposed business activities. Readers are cautioned
that reliance on such information may not be appropriate for other purposes.

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, whether as a result of new information,
future events or otherwise, unless so required by law.

– END RELEASE – 21/07/2017

For further information:
Canada Energy Partners Inc.
(778) 725-1489
(604) 428-1124 (FAX)
[email protected]
OR
Ben Jones
President and CEO
+1 225.388.9900 ext 101
www.canadaenergypartners.com

COMPANY:
FOR: CANADA ENERGY PARTNERS INC.
TSX VENTURE SYMBOL: CE

INDUSTRY: Energy and Utilities – Oil and Gas
RELEASE ID: 20170721CC0006

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.

New SHOWCASE Directory Companies

 

Predator Drilling
Environmental Refueling Systems (ERS)
Galloway Construction Group
Techmation Electric & Controls
Versa-Line
Galdos Systems
FUELware
Assetworks

Federal Court of Appeal ruling deals setback for Pacific NorthWest LNG project

VANCOUVER — The National Energy Board must reconsider whether a proposed natural gas pipeline critical to the development of the Pacific NorthWest liquefied natural gas project falls within provincial or federal jurisdiction, the Federal Court of Appeal has ruled.

The judgment marks a setback for the $36-billion LNG development, which secured conditional approval from the federal government last year.

“The board did not ask itself whether an arguable case for federal jurisdiction had been made out,” wrote Justice Donald J. Rennie in his decision Wednesday in response to a proceeding launched by Michael Sawyer, who received funding support from the SkeenaWild Conservation Trust.

Sawyer argued the Prince Rupert Gas Transmission Project, a roughly 900-kilometre pipeline from Hudson’s Hope, B.C., to a natural gas terminal on the province’s Lelu Island, required federal and not provincial approvals.

The province has green-lighted the pipeline project proposed by TransCanada Corp. (TSX:TRP). But the overall venture is still waiting for a final commitment from Pacific NorthWest LNG, which would build and operate the $11-billion facility on Lelu Island, if it proceeds.

Pacific NorthWest LNG, whose majority owner is Malaysia-based Petronas, could not be reached for comment. On its website, it says it is conducting an internal review of the project and will then table it to shareholders for a final investment decision.

Prior to launching the case, Sawyer had filed an application to the NEB asking it to hold a hearing to determine what jurisdiction the pipeline project falls under. He argued that while the pipeline’s route falls fully within the province, it would ship gas destined to be exported to markets overseas, and therefore should be under federal jurisdiction.

The NEB rejected his application, but now must reconsider it due to Rennie’s ruling.

“The board is reviewing the court decision and will consider next steps after doing so,” NEB spokesman James Stevenson said Thursday in an email.

TransCanada has 60 days to apply for leave to appeal. Spokesman Matthew John said in an email that the company is still reviewing the ruling and considering its options.

“It is notable that this decision is not a determination that federal jurisdiction applies,” he said, adding that the NEB only needs to reconsider Sawyer’s case.

 

Follow @AleksSagan on Twitter.

Aleksandra Sagan, The Canadian Press

New SHOWCASE Directory Companies

 

Techmation Electric & Controls
Galloway Construction Group
Predator Drilling
Environmental Refueling Systems (ERS)
Versa-Line
FUELware
Assetworks
Galdos Systems

Wavefront Gains 15 New Well Stimulations in Kuwait

FOR: WAVEFRONT TECHNOLOGY SOLUTIONS INC.
TSX VENTURE SYMBOL: WEE
OTCQX SYMBOL: WFTSF

Date issue: July 20, 2017
Time in: 6:21 PM e

Attention:

EDMONTON, ALBERTA–(Marketwired – July 20, 2017) – Wavefront Technology
Solutions Inc. (Wavefront or the Company)(TSX VENTURE:WEE)(OTCQX:WFTSF) a
global leader in the advancement of fluid injection technology for oil and gas
well stimulation and Improved/Enhanced oil (“IOR/EOR”) recovery is pleased to
announce that the Company, through its local distributor, has been issued a
campaign of 15 well stimulations in Kuwait.

The 15 well stimulation campaign consists of 10 Powerwave-driven acid
stimulations on water injection wells and 5 Powerwave-driven acid stimulations
on oil producing wells. Well candidates have been chosen and Powerwave
stimulation modeling is to be completed. The timing of individual stimulations
has not been set but the initial work is anticipated to commence within ten
days. Revenues from the well stimulations are variable and relate to the length
of the well interval being stimulated.

“We are very pleased to have the confidence of the client and receive this
stimulation package” said Wavefront President and CEO Brett Davidson. “The
Company anticipates that this first campaign will be one of many in a field
that has over 250 wells identified for stimulation.”

ON BEHALF OF THE BOARD OF DIRECTORS

WAVEFRONT TECHNOLOGY SOLUTIONS INC.

D. Brad Paterson, CFO & Director

About Wavefront:

Wavefront is a technology based world leader in fluid injection technology for
improved/enhanced oil recovery and groundwater restoration. Wavefront publicly
trades on the TSX Venture Exchange under the symbol WEE and on the OTCQX under
the symbol WFTSF. The Company’s website is www.onthewavefront.com.

Cautionary Disclaimer – Forward Looking Statement

Certain statements contained herein regarding Wavefront and its operations
constitute “forward-looking statements” within the meaning of Canadian
securities laws and the United States Private Securities Litigation Reform Act
of 1995. All statements that are not historical facts, including without
limitation statements regarding future estimates, plans, objectives,
assumptions or expectations or future performance, are “forward-looking
statements”. In some cases, forward-looking statements can be identified by
terminology such as “may”, “will”, “should”, “expect”, “plan”, “anticipate”,
“believe”, “estimate”, “predict”, “potential”, “believe”, “continue” or the
negative of these terms or other comparable terminology. We caution that such
“forward-looking statements” involve known and unknown risks and uncertainties
that could cause actual results and future events to differ materially from
those anticipated in such statements. Such factors include fluctuations in the
acceptance rates of Wavefront’s Powerwave and Primawave Processes, demand for
products and services, fluctuations in the market for oil and gas related
products and services, the ability of Wavefront to attract and maintain key
personnel, technology changes, global political and economic conditions, and
other factors that were described in further detail in Wavefront’s continuous
disclosure filings, available on SEDAR at www.sedar.com. Wavefront expressly
disclaims any obligation to up-date any “forward-looking statements”, other
than as required by law.

(C)2017 Wavefront Technology Solutions Inc. All rights reserved.

From Bit To Last Drop(TM), WaveAxe(TM), Powerwave(TM) and Primawave(TM) are
registered trademarks of Wavefront Technology Solutions Inc., or its
subsidiaries, or affiliates.

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 RELEASE.

– END RELEASE – 20/07/2017

For further information:
D. Brad Paterson
CFO
780-486-2222
[email protected]

COMPANY:
FOR: WAVEFRONT TECHNOLOGY SOLUTIONS INC.
TSX VENTURE SYMBOL: WEE
OTCQX SYMBOL: WFTSF

INDUSTRY: Energy and Utilities – Oil and Gas
RELEASE ID: 20170720CC0082

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.

New SHOWCASE Directory Companies

 

Environmental Refueling Systems (ERS)
Techmation Electric & Controls
Galloway Construction Group
Predator Drilling
FUELware
Versa-Line
Assetworks
Galdos Systems

NC governor on Trump drilling plan: ‘Not off our coast’

ATLANTIC BEACH, N.C. — Under pressure from President Donald Trump, North Carolina’s governor announced his opposition on Thursday to drilling for natural gas and oil off the Atlantic coast, saying it poses too much of a threat to the state’s beaches and tourism economy.

Up against a Friday deadline for comment from elected officials on the Trump administration’s request for companies to perform seismic testing under Atlantic waters, Democratic Gov. Roy Cooper held a news conference at a coastal state park to announce he’ll be registering the state’s opposition.

“There is a threat looming over this coastline that we love and the prosperity it brings, and that’s the threat of offshore drilling,” Cooper said at the Fort Macon State Park in Carteret County, where he said he visited as a child and as a parent.

“As governor, I’m here to speak out and take action against it. I can sum it up in four words: ‘not off our coast.'”

State Republican leaders, including former Gov. Pat McCrory, have pressed for exploration both offshore and inland through hydraulic fracturing. GOP legislators have passed laws laying the groundwork for collecting royalties from oil and gas that’s mined below the ocean surface.

In April, Trump signed an executive order to expand oil drilling in the Arctic and Atlantic oceans, reversing restrictions imposed by President Barack Obama, and the Interior Department is rewriting a five-year drilling plan. A federal agency is now seeking permits for five businesses to use seismic air guns to find oil and gas formations deep under the Atlantic, despite the harm environmentalists say this technology does to marine mammals. Maryland GOP Gov. Larry Hogan also announced his opposition this month.

Cooper, who took office in January, said an oil spill could be catastrophic to commercial fishermen and the tourism industry, which provides more than $3 billion in spending and 30,000 jobs in coastal counties. North Carolina Petroleum Council Executive Director David McGowan said offshore energy could bring thousands of new jobs and more local revenues. The governor disagreed.

“There is little evidence that offshore drilling would be a financial boon for our state,” Cooper said. If drilling does happen, he said jobs and revenue sharing won’t likely be plentiful, and he said potential cuts to federal regulations also raise environmental risks.

North Carolina environmental groups were thrilled with Cooper’s announcement, attended by a favourable crowd of supporters. Cooper, the attorney general for the past 16 years, said very little about offshore drilling during last fall’s gubernatorial campaign against McCrory.

Cooper’s office said more than 30 municipalities have passed resolutions opposing the drilling and testing.

Cooper “listened to all of North Carolina’s coastal communities who’ve been calling for the protection of our coast,” Southern Environmental Law Center attorney Sierra Weaver said in a release. Erin Carey with the North Carolina Sierra Club added the governor “sent a strong, clear message to the Trump administration and the fossil fuel industry that our coast is not for sale.”

U.S. Rep. Richard Hudson, R-N.C., a leader in a congressional caucus seeking to advance offshore energy, criticized Cooper’s decision and said energy exploration and environmental protection aren’t mutually exclusive.

“To put it simply, Gov. Cooper is wrong,” Hudson said in a release. “This is not an either-or situation.”

The Associated Press

New SHOWCASE Directory Companies

 

Environmental Refueling Systems (ERS)
Predator Drilling
Techmation Electric & Controls
Galloway Construction Group
Versa-Line
Galdos Systems
Assetworks
FUELware

State trade group can weigh in on Dakota Access pipeline

BISMARCK, N.D. — A judge deciding whether to temporarily shut down the disputed Dakota Access oil pipeline said Thursday that he will allow North Dakota’s main energy trade group to weigh in.

U.S. District Judge James Boasberg might also allow some national energy and manufacturing groups to have a say, though he didn’t immediately rule. The groups, including the North Dakota Petroleum Council, maintain their input is important because none of the parties in a lawsuit over the $3.8 billion pipeline to move North Dakota oil to Illinois speaks for the general oil industry.

The pipeline has been operating nearly two months, but Boasberg in mid-June ordered the Army Corps of Engineers to further review its impact on the Standing Rock Sioux tribe, which has sued along with three other tribes over fears of environmental harm. Boasberg is mulling whether to shut down the pipeline while the work is completed.

“Ceasing (pipeline) operations would seriously harm businesses throughout the energy industry in the United States,” David Coburn, an attorney representing several of the trade groups, said in court documents.

Texas-based pipeline developer Energy Transfer Partners says it would cost at least $20 million and as much as $234 million to shut down the line. It says a shutdown would cost the company $90 million in revenue each month and would impact 16 other pipelines that support the Dakota Access system.

Trade group attorneys maintain a shutdown would have even broader impacts by cutting oil production, increasing less-safe rail shipping, increasing shipping expenses for companies, cutting refinery supplies, harming state tax revenue and impacting royalty owners. The North Dakota Petroleum Council, which represents more than 500 companies including ETP, said a shutdown “would pull the rug out from under the North Dakota oil industry,” which is shipping half of its daily production through the pipeline.

The trade groups also maintain Boasberg’s decision could have consequences far beyond Dakota Access.

“Any decision by this court to vacate the Corps’ approvals and order (the pipeline) to cease operations could result in similar rulings in other pipeline cases,” Coburn wrote.

The national groups seeking a say are the American Petroleum Institute, American Fuel and Petrochemical Manufacturers, Association of Oil Pipe Lines, national Chamber of Commerce and National Association of Manufacturers.

___

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

Blake Nicholson, The Associated Press

New SHOWCASE Directory Companies

 

Predator Drilling
Environmental Refueling Systems (ERS)
Galloway Construction Group
Techmation Electric & Controls
Versa-Line
FUELware
Assetworks
Galdos Systems

Suncor Energy to release second quarter 2017 financial results

FOR: SUNCOR ENERGY INC.
TSX SYMBOL: SU
NYSE SYMBOL: SU

Date issue: July 20, 2017
Time in: 6:00 PM e

Attention:

CALGARY, ALBERTA–(Marketwired – July 20, 2017) – Suncor will release its
second quarter financial results on Wednesday, July 26, 2017 before 8:00 p.m.
MT (10:00 p.m. ET).

A webcast to review the second quarter will be held on Thursday, July 27, 2017
at 7:30 a.m. MT (9:30 a.m. ET). Representing management will be Steve Williams,
president and chief executive officer and Alister Cowan, executive vice
president and chief financial officer. A question and answer period will follow
brief remarks from management. Steve Douglas, vice president, Investor
Relations will host the call.

Please note, telephone lines are limited and reserved for those who intend to
ask a question.

To participate in the webcast, go to suncor.com/webcasts.
An archive will be available on suncor.com/webcasts.

If you are an analyst or media and would like to participate in the Q&A period:

/T/

— If calling from North America: 1-866-219-5885
— If calling from outside North America: +1-209-905-5918

/T/

Suncor has scheduled its third quarter financial release date for Wednesday,
October 25, 2017.

Suncor Energy is Canada’s leading integrated energy company. Suncor’s
operations include oil sands development and upgrading, conventional and
offshore oil and gas production, petroleum refining, and product marketing
under the Petro-Canada brand. A member of Dow Jones Sustainability indexes,
FTSE4Good and CDP, Suncor is working to responsibly develop petroleum resources
while also growing a renewable energy portfolio. Suncor is listed on the UN
Global Compact 100 stock index and the Corporate Knights’ Global 100. Suncor’s
common shares (symbol: SU) are listed on the Toronto and New York stock
exchanges.

For more information about Suncor, visit our web site at suncor.com, follow us
on Twitter @SuncorEnergy or together.suncor.com.

– END RELEASE – 20/07/2017

For further information:
Investor inquiries:
800-558-9071
[email protected]
OR
Media inquiries:
403-296-4000
[email protected]

COMPANY:
FOR: SUNCOR ENERGY INC.
TSX SYMBOL: SU
NYSE SYMBOL: SU

INDUSTRY: Energy and Utilities – Oil and Gas
RELEASE ID: 20170720CC0078

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.

New SHOWCASE Directory Companies

 

Predator Drilling
Galloway Construction Group
Environmental Refueling Systems (ERS)
Techmation Electric & Controls
Assetworks
Versa-Line
Galdos Systems
FUELware

Dakota Access developer’s new pipeline rankling regulators

NEW WASHINGTON, Ohio — The company that developed the Dakota Access oil pipeline is entangled in another fight, this time in Ohio where work on its multi-state natural gas pipeline has wrecked wetlands, flooded farm fields and flattened a 170-year-old farmhouse.

The federal commission that oversees gas pipelines told Dallas-based Energy Transfer Partners last week to clean up its mess before it will allow the Rover Pipeline to flow. New drilling on unfinished sections also remains halted after 2 million gallons (7.6 million litres) of drilling mud seeped into a wetland in the spring.

While the $4.2 billion pipeline that will carry gas from Appalachian shale fields to Canada, and states in the Midwest and Gulf Coast, hasn’t been besieged by protests that erupted in North Dakota, opponents say the spills and snags highlight the risks that come with building huge pipelines needed for growing the natural gas and oil industries.

Much of the 700-mile (1,126-kilometre) Rover Pipeline is being built across Ohio and will extend into Michigan, Pennsylvania and West Virginia.

Ohio’s environmental regulators and landowners say construction crews have been laying pipe at warp speed since March to meet the company’s ambitious plan of finishing the first phase this month and the entire project by November.

“As soon as they started, they began having problems,” said Craig Butler, director of Ohio’s Environmental Protection Agency. “It’s just a function of them moving too quickly, trying to meet a deadline and cutting corners.”

The state EPA has proposed nearly $1 million in fines over violations that include allowing drilling mud to spill into wetlands, ponds and streams along with pumping storm water into streams and fields. Most of the violations were in March and April but some problems continue.

Just last week, the Federal Energy Regulatory Commission ordered Energy Transfer Partners to clean up and restore 6 acres (2.4 hectares) of wetlands coated with more than a foot (30 centimetres) of drilling mud, remove mud contaminated with diesel fuel from two quarries and monitor water wells near those sites.

The federal agency is continuing to investigate and could issue more orders. It also accused the company of not being truthful about its intention to demolish a 170-year-old farmhouse that stood in the pipeline’s path.

Energy Transfer Partners later agreed to pay $3.8 million to Ohio’s historic preservation efforts for knocking down the house last year.

The company now is working to comply with regulators on the cleanup orders, said spokeswoman Alexis Daniel. But doing that will delay completing the pipeline’s first phase until later this summer, she said Wednesday.

“Our pipelines are always constructed to the highest standards, so I would unequivocally deny any assertion to the contrary,” Daniels said.

In Michigan, the state’s two U.S. senators want federal regulators to pause construction and consider moving the path of the pipeline away from a popular lake and summer camp for children.

Dozens of Ohio farmers have complained that their fields have been flooded after heavy rains by crews pumping storm water out of open trenches. Some have asked a federal judge to tell the company to stop doing it, arguing it violates their land agreements.

Those agreements compensate the owners for putting the pipeline on their land, but farmers say it doesn’t give the company the right to flood their adjacent land. Energy Transfer Partners said it has been dealing with unprecedented rainfall and is trying to avoid and minimize impact on crops.

Doug Phenicie, whose family farms about 1,800 acres (728 hectares) near New Washington in northern Ohio, said he watched this spring as a bulldozer pushed standing water onto a neighbour’s field. “It looked like waves at the ocean,” he said.

A muddy, brown stream rippled across his soybean field last week following another big storm as crews pumped out more water. It’s become a common sight, he said.

The concern for farmers is that not only will some of this year’s crop be ruined, but that it will be hurt for years to come in areas where the floodwaters have coated the ground with heavy clay and the heavy equipment has packed down the soil.

They’ve been told that the pipeline company will fix the fields and broken drainage tiles and reimburse farmers for future losses, Phenicie said, but he’s not convinced.

“Who’s going to answer the phone when they’re gone?” he said.

John Seewer, The Associated Press










New SHOWCASE Directory Companies

 

Techmation Electric & Controls
Galloway Construction Group
Predator Drilling
Environmental Refueling Systems (ERS)
FUELware
Galdos Systems
Versa-Line
Assetworks

Manitok Energy Inc. Announces Strategic Combination with Questfire Energy Corp. to Form Canada’s Newest Intermediate Energy Producer with Greater than 10,000 boe/d of Production

Manitok Energy Inc

CALGARY, July 7, 2017 /CNW/ – Manitok Energy Inc. (“Manitok“) (TSXV: MEI) and Questfire Energy Corp. (“Questfire“) (TSXV: Q.A) are pleased to announce that on July 5, 2017 they have entered into a definitive agreement (the “Arrangement Agreement“) providing for the acquisition by Manitok of all the issued and outstanding common shares of Questfire (the “Questfire Shares“) pursuant to … Read more

New SHOWCASE Directory Companies

 

Predator Drilling
Techmation Electric & Controls
Galloway Construction Group
Environmental Refueling Systems (ERS)
Galdos Systems
FUELware
Assetworks
Versa-Line

Canadian energy company named in California climate-related lawsuit

A Canadian energy company is named in three large lawsuits that attempt to link damages from climate change to industry’s alleged attempts to hinder action to address it.

In the latest of a growing number of such lawsuits around the world, Calgary-based Encana is one of 20 energy majors and their subsidiaries facing claims from three California communities. They allege the companies have deliberately sown misinformation and doubt on climate change and are at least partially responsible for related damages such as shoreline erosion.

“Defendants … have known for nearly a half century that unrestricted production and use of their fossil fuel products create greenhouse gas pollution that warms the planet and changes our climate,” says the lawsuit filed by the City of Imperial Beach.

“They have nevertheless engaged in a co-ordinated, multi-front effort to conceal and deny their own knowledge of those threats, discredit the growing body of publicly available scientific evidence, and persistently create doubt in the minds of customers, consumers, regulators, the media, journalists, teachers, and the public about the reality and consequences of the impacts of their fossil fuel pollution.”

Encana (TSX:ECA) has not responded to requests for comment.

The lawsuits, filed Monday in California, draw on legal precedents used against tobacco companies, which reached a U.S. settlement of $368.5 billion in 1998.

“The plaintiffs have an uphill battle, but these are plausible claims,” said Michael Burger, director of the Sabin Center for Climate Change Law at Columbia Law School.

Burger said that, like tobacco companies, the energy industry knew its business was creating problems. Reports quoting documents from Exxon’s archives suggest its management was told by its own scientists about greenhouse gases and climate change as early as 1977.

Instead of addressing the problem, the lawsuits allege, industry deployed think tanks, lobbyists and other means to obscure the science and resist regulation — much like the tobacco industry.

“You have a similar history of corporate malfeasance,” said Burger.

But the climate lawsuits will have a much tougher time linking specific damages to industry actions, he said.  

“To get from pulling it out of the ground all the way through the chain of manufacture, marketing, combustion — and through the climate change reality and then to sea-level rise causing specific impacts in these places — is a much longer chain of causation.”

Similar lawsuits have been thrown out.

Vic Sher, the lawyer handling the litigation, said his lawsuits avoid conflicts with federal law that disallowed earlier attempts.

Fresh reports have made industry attempts to block change much clearer, he said. As well, research now allows scientists to make direct links between greenhouse gases, sea-level rise and individual producers.

“That causal connection we can now tie to particular companies.”

The claim alleges the defendants are collectively behind about 20 per cent of total CO2 emissions between 1965 and 2015.

“It’s an enormous volume and a substantial contribution to the problem,” Sher said.

Kate Sears, supervisor for Marin County just north of San Francisco, said her communities are already suffering.

Previously rare flooding tides now occur about 15 times a year, she said. The only roads in and out for some coastal communities have been submerged.

A county assessment concluded in April that within 15 years, tidal flooding could threaten at least $15.5 billion in public and private assets, from homes to schools to wetlands.

“Climate change is not a theoretical problem for us,” Sears said. “It’s very, very real.”

Martin Olszynski, a University of Calgary law professor who has published research on similarities between climate change and tobacco liability, said the cases are highly relevant to Canada as different court systems try to deal with the issue.

“Everyone’s watching to see what different courts are doing, especially countries that share that common law tradition,” he said. “There’s a cumulative effect — you start to see more and more of these.”

A report in March for the United Nations counted 654 cases in 24 countries that dealt with the science of climate change and mitigation efforts.

— Follow Bob Weber on Twitter at @row1960

 

 

 

Bob Weber, The Canadian Press