Day: May 15, 2017

FOR: TAMARACK VALLEY ENERGY LTD.
TSX SYMBOL: TVE

Date issue: May 15, 2017
Time in: 7:10 PM e

Attention:

CALGARY, ALBERTA–(Marketwired – May 15, 2017) – Tamarack Valley Energy Ltd.
(TSX:TVE) (“Tamarack” or the “Company”) is pleased to announce its financial
and operating results for the three months ended March 31, 2017. Selected
financial and operational information is set out below and should be read in
conjunction with Tamarack’s unaudited condensed consolidated interim financial
statements for the three months ended March 31, 2017 and related management’s
discussion and analysis (“MD&A”), which are available for review on SEDAR at
www.sedar.com or on Tamarack’s website at www.tamarackvalley.ca.

Q1 2017 Financial and Operating Highlights

/T/

— Closed the transformational business combination with Spur Resources

Ltd. (the “Viking Acquisition”) on January 11, 2017, positioning
Tamarack as a Cardium and Viking-focused growth entity with control of
key infrastructure across its core areas. Concurrent with closing, the
borrowing base on the Company’s credit facilities was increased by over
80% to $220 million from $120 million, providing greater liquidity for
ongoing development of Tamarack’s high-netback, light oil-weighted asset
base.
— Achieved Q1/17 average production of 17,796 boe/d, up 55% over Q4/16 and
up 86% from Q1/16 and in April 2017, production averaged over 20,000
boe/d (58% liquids), due to the success of the Company’s Cardium and
Viking drilling programs.
— Total funds from operations increased 141% to $32.4 million in Q1/17
($0.15/share basic and diluted), excluding transaction costs, from $11.1
million in Q1/16 ($0.11/share basic and diluted), and increased 58%
compared to Q4/16.
— Continued to achieve reductions in production expenses with per boe
costs declining 6% quarter-over-quarter to $11.42/boe in Q1/17 and 2%
lower than $11.65/boe in Q1/16.
— General and administrative costs per boe decreased by 3% quarter-over-
quarter to $1.83/boe in Q1/17 and declined 10% year-over-year from
$2.03/boe, despite higher activity levels, higher production levels and
the integration of the Viking Acquisition assets.
— Invested $63.7 million in capital expenditures in the quarter drilling a
record 46 (42.4 net) wells.
— Oil weighting increased by 2% to 47% in Q1/17 from 45% in Q4/16, causing
funds flow netback per boe to increase by 5% in Q1/17 compared to Q4/16.
— Tamarack recorded earnings of $2.3 million in Q1/17 compared to a $5.8
million loss in Q1/16.
— Subsequent to the end of the quarter on May 12, 2017, the Company’s
credit facilities were further increased to $265 million from $220
million during the annual banking review, supported by the value created
in its core Cardium and Viking areas since the last mid-year review
completed in November, 2016.

/T/

Financial & Operating Results

/T/

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

Three months ended March
(Cdn$ thousands, except per boe) 31,
—————————————————————————-
2017 2016 % change
—————————————————————————-
($, except per share)
Total Revenue 62,870 19,618 220
Funds from operations (1) 32,356 11,078 190
Per share – basic (1) $ 0.15 $ 0.11 36
Per share – diluted (1) $ 0.15 $ 0.11 36
Net income (loss) 2,290 (5,835) 139
Per share – basic $ 0.01 $ (0.06) 117
Per share – diluted $ 0.01 $ (0.06) 117
Net debt (2) (165,561) (62,696) 164
Capital Expenditures (3) 64,492 17,150 276
—————————————————————————-
Weighted average shares
outstanding(thousands)
Basic 217,655 102,274 113
Diluted 219,679 102,274 115
—————————————————————————-
Share Trading (thousands, except share
price)
High $ 3.59 $ 3.97 (10)
Low $ 2.60 $ 2.16 20
Trading volume 80,868 28,809 181
—————————————————————————-
Average daily production
Light oil (bbls/d) 7,891 3,801 108
Heavy oil (bbls/d) 484 410 18
NGLs (bbls/d) 1,779 1,067 67
Natural gas (mcf/d) 45,852 25,818 78
Total (boe/d) 17,796 9,581 86
—————————————————————————-
Average sale prices
Light oil ($/bbl) 63.02 36.82 71
Heavy oil ($/bbl) 44.64 23.32 91
NGLs ($/bbl) 26.46 12.71 108
Natural gas ($/mcf) 2.89 2.03 42
Total ($/boe) 39.25 22.50 74
—————————————————————————-
Operating netback ($/Boe) (2)
Average realized sales 39.25 22.50 74
Royalty expenses (4.15) (2.04) 103
Production expenses (11.42) (11.65) (2)
—————————————————————————-
Operating field netback ($/Boe)(2) 23.68 8.81 169
Realized commodity hedging gain (loss) (0.77) 7.23 (111)
—————————————————————————-
Operating netback 22.91 16.04 43
—————————————————————————-
Funds flow from operations netback ($/Boe)
(2) 20.19 12.71 59
—————————————————————————-
—————————————————————————-
Notes:
(1) Funds from operations is calculated as cash flow from operating
activities before the change in non-cash working capital and abandonment.
(2) Net debt, operating netback, operating field netback and funds flow from
operations netback do not have any standardized meaning prescribed by
International Financial Reporting Standards (“IFRS”) and therefore may not
be comparable with the calculation of similar measures for other entities.
See “Non-IFRS Measures”.
(3) Capital expenditures include exploration and development expenditures,
but exclude corporate acquisitions.

/T/

Operations review

Early in the first quarter of 2017, the Company closed the Viking Acquisition
and commenced the integration of assets, personnel and processes. The Viking
Acquisition offers significant near and longer term growth for Tamarack, and
provided support for an 80% increase in the borrowing base on the Company’s
credit facilities to $220 million. While new challenges emerged in commodity
markets later in the first quarter, Tamarack’s operational execution from both
a timing and cost perspective remained on track. Production volumes for the
quarter were in-line with guidance as the Company’s Cardium and Viking drilling
results continue to meet expectations, despite minor operational delays due to
challenges in accessing pressure pumping services. For the month of April 2017,
production volumes averaged over 20,000 boe/d (58% liquids) based on field
estimates.

Production of 17,796 boe/d (57% liquids) increased 55% quarter-over-quarter and
86% year-over-year as a direct result of higher production volumes from the
successful Q1/17 drilling program, capital efficiencies that continue to meet
expectations, and the impact of the strategic Viking Acquisition that closed in
January. Base production from the Viking Acquisition averaged 6,102 boe/d (57%
liquids) from the closing date to the end of the first quarter, while
Tamarack’s Viking drilling program added 376 boe/d (68% liquids) of average
production over the same period.

Tamarack’s record level of investment in the first quarter of 2017 included $48
million directed to drilling and completions activities, primarily focused on
Cardium and Viking programs. In Alberta, the Company drilled 17 (16.53 net)
Viking oil wells in Veteran, 7 (6.26 net) Cardium oil wells and one (1.0 net)
Notikewin liquids-rich gas well. In addition, three minor tuck-in acquisitions
at Tamarack’s Penny area were completed during the quarter for $0.8 million,
which included production of approximately 35 bbls/d of oil and 60,954 (33,853
net) acres of land. In early May, the Company closed a $2.1 million
acquisition, which included 14,080 (12,800 net) acres of land west of Wilson
Creek along with 62 square miles of seismic. In Saskatchewan, the Company
drilled 14 (11.6 net) Viking oil wells in Milton, 4 (4.0 net) Viking oil wells
in Hoosier and 3 (3.0 net) Hatton heavy oil wells. While the pressure pumping
suppliers are the busiest the industry has seen since 2014, the Company’s
reservoir stimulation delays in the first quarter were relatively minor and
Tamarack does not anticipate operational inefficiencies or material cost
escalation in the near-term.

The Company also invested $6.1 million in Q1/17 on facilities and
infrastructure, and completed various key enhancement projects related to the
Viking Acquisition assets that are expected to reduce operating costs in the
second half of 2017 while also increasing productive capacity. A new 8 MMcf/d
compressor station and multi-well oil battery was completed at Milton, which
will reduce third party gas handling charges as well as operating costs. At
Veteran, where current oil production is approximately 1,250 bbls/d, the
Company added over 20 km of a mainline oil gathering pipeline system which will
allow Tamarack to utilize a Company-owned oil battery for emulsion gathering
and eliminate third-party trucking and water disposal costs. Given higher than
expected total production fluid volumes from Veteran wells, the Company intends
to increase the pump size for Veteran wells going forward to eliminate current
rate restrictions caused by pump capacity limitations. After the end of the
quarter, a water disposal well was drilled at Veteran that is expected to
generate a four-fold increase in the oil battery’s capacity to over 10,000
bbls/d of fluid handling by the end of June, 2017.

Also during the quarter, the Company constructed a multi-well heavy oil battery
at Hatton to handle the incremental production volumes stemming from Tamarack’s
successful first quarter drilling program and ongoing area development. All of
these infrastructure initiatives support Tamarack’s long-term flexibility and
contribute to the Company’s continued cost reduction efforts and field
efficiency enhancements.

On April 28, 2017, the TransGas Coleville Gas Plant was shut-in, affecting the
Company’s production from the Coleville Gas Unit, Hoosier Gas Unit, Hoosier and
Milton Viking oil wells. Tamarack had nearly 5,000 boe/d (47% oil and NGLs)
connected to the facility which was affected at the time of the plant shut
down. The Tamarack was able to redirect volumes and bring most of the affected
production back on-stream. Currently, the Company has approximately 850 boe/d
(3.0 MMcf/d,25 bbls/d oil and 325 bbls/d of associated natural gas liquids)
that continue to be shut-in. Preliminary information from TransGas indicates
that the plant could be affected for six to eight weeks. Tamarack personnel are
working with TransGas on potential solutions to enable “partial operations” by
the end of June, 2017. The Company estimates that second quarter production
will be lower by approximately 900 boe/d due to the plant shut down.

A key component of the Company’s strategy is to prudently manage its assets and
balance sheet through any cycle, and as needed, adjust capital within the
context of the commodity price environment. Tamarack will continue to focus on
drilling wells that target a capital cost payout of 1.5 years or less, while
striving to optimize capital efficiencies by further reducing capital and
operating costs. Due to the recent decline in crude oil prices, Tamarack has
begun to adjust capital spending to the bottom end of its 2017 guidance range
of $165 to $175 million and will adjust further if oil prices fall below
US$45/bbl WTI. As a result of the third party plant shut down at Coleville, the
Company expects second quarter production to average between 18,000 and 18,500
boe/d, thereby reducing the first half production guidance range to 18,000 to
18,500 boe/d from 18,500 to 19,000 boe/d. Even with the planned lower capital
spending coupled with the expected production impacts through the second
quarter, Tamarack’s 2017 annual average production guidance remains unchanged
at 19,000 to 20,000 boe/d, with a forecast exit production rate of 21,000
boe/d. Through the second half of 2017, the Company plans to drill and complete
eight Cardium wells and three Mannville wells at Wilson Creek, and 44 extended
reach horizontal wells at Veteran and Milton. Tamarack continues to be on
target to achieve 7% – 9% production per share growth (Q4/17 over Q4/16), while
keeping debt to Q4/17 annualized funds flow from operations at 1.0 times.
Tamarack’s priority is to maintain a strong and flexible balance sheet that
enables the Company to capitalize on opportunities to add high-quality drilling
inventory or pursue consolidation acquisitions in core areas which may arise in
a lower commodity price environment.

Despite recent commodity price volatility, the Company remains optimistic about
the long-term growth potential of its oil-weighted, high netback and
high-return asset base. The Viking Acquisition provides the Company with a
strong and robust drilling inventory to fuel organic growth and underpin cash
flow and production per share growth for many years. Tamarack also remains well
hedged through 2017 and continues to layer on risk management contracts into
2018 to protect downside risk, which will underpin funds from operations and
help the Company maintain its strong balance sheet and production base.

Tamarack invites all shareholders and other stakeholders to attend the
Company’s Annual Meeting of Shareholders to be held on June 22, 2017 at 9:00
a.m. at The Bow Valley Club located at 370, 250 – 6th Avenue SW, Calgary,
Alberta.

Bank Line Renewal

Tamarack’s credit facilities were increased to $265 million from $220 million
on May 12, 2017 as a result of its annual review. The $265 million facility is
made up of a revolving credit facility in the amount of $245 million and a $20
million operating facility with a syndicate of lenders.

About Tamarack Valley Energy Ltd.

Tamarack is an oil and gas exploration and production company committed to
long-term growth and the identification, evaluation and operation of resource
plays in the Western Canadian Sedimentary Basin. Tamarack’s strategic direction
is focused on two key principles – targeting repeatable and relatively
predictable plays that provide long-life reserves, and using a rigorous, proven
modeling process to carefully manage risk and identify opportunities. The
Company has an extensive inventory of low-risk, oil development drilling
locations focused primarily in the Cardium and Viking fairways in Alberta that
are economic over a range of oil and natural gas prices. With this type of
portfolio and an experienced and committed management team, Tamarack intends to
continue delivering on its strategy to maximize shareholder returns while
managing its balance sheet.

Abbreviations

/T/

bbls barrels
bbls/d barrels per day
boe barrels of oil equivalent
boe/d barrels of oil equivalent per day
mcf thousand cubic feet
MMcf million cubic feet
mcf/d thousand cubic feet per day
MMcf/d million cubic feet per day
NGLs natural gas liquids
WTI West Texas Intermediate, the reference price paid in U.S. dollars
at Cushing, Oklahoma for crude oil of standard grade

/T/

Unit Cost Calculation

For the purpose of calculating unit costs, natural gas volumes have been
converted to a boe using six thousand cubic feet equal to one barrel unless
otherwise stated. A boe conversion ratio of 6:1 is based upon an energy
equivalency conversion method primarily applicable at the burner tip and does
not represent a value equivalency at the wellhead. This conversion conforms
with National Instrument 51-101 – Standards of Disclosure for Oil and Gas
Activities. Boe may be misleading, particularly if used in isolation.

Forward Looking Information

This press release contains certain forward-looking information (collectively
referred to herein as “forward-looking statements”) within the meaning of
applicable Canadian securities laws. Forward-looking statements are often, but
not always, identified by the use of words such as “target”, “plan”,
“continue”, “intend”, “ongoing”, “estimate”, “expect”, “may”, “should”, or
similar words suggesting future outcomes. More particularly, this press release
contains statements concerning: Tamarack’s business strategy, objectives,
strength and focus; the impact of the Viking Acquisition on the Company’s
operations, infrastructure, inventory and opportunities, financial condition,
access to capital and overall strategy; an increase in capital efficiencies and
netbacks; the ability of the Company to achieve drilling success consistent
with management’s expectations; drilling plans and timing of drilling; expected
levels of operating costs, general and administrative costs, costs of services
and other costs and expenses; cost cutting initiatives; oil and natural gas
production levels; and adjustments to the 2017 capital expenditure program and
expected production in the first half of 2017.

The forward-looking statements contained in this document are based on certain
key expectations and assumptions made by Tamarack, including relating to:
prevailing commodity prices; the availability and performance of drilling rigs,
facilities, pipelines and other oilfield services; the timing of past
operations and activities in the planned areas of focus; the drilling,
completion and tie-in of wells being completed as planned; the performance of
new and existing wells; the application of existing drilling and fracturing
techniques; prevailing weather and break-up conditions; royalty regimes and
exchange rates; the application of regulatory and licensing requirements; the
continued availability of capital and skilled personnel; the ability to
maintain or grow the banking facilities; and the accuracy of Tamarack’s
geological interpretation of its drilling and land opportunities.

Although management considers these assumptions to be reasonable based on
information currently available, undue reliance should not be placed on the
forward-looking statements because Tamarack can give no assurances that they
may prove to be correct. By their very nature, forward-looking statements are
subject to certain risks and uncertainties (both general and specific) that
could cause actual events or outcomes to differ materially from those
anticipated or implied by such forward-looking statements. These risks and
uncertainties include, but are not limited to: risks associated with the oil
and gas industry in general (e.g. operational risks in development, exploration
and production; and delays or changes in plans with respect to exploration or
development projects or capital expenditures); commodity prices; the
uncertainty of estimates and projections relating to production, cash
generation, costs and expenses; health, safety, litigation and environmental
risks; and access to capital. Due to the nature of the oil and natural gas
industry, drilling plans and operational activities may be delayed or modified
to react to market conditions, results of past operations, regulatory approvals
or availability of services causing results to be delayed. Please refer to
Tamarack’s Annual Information Form (the “AIF”) for additional risk factors
relating to Tamarack. The AIF can be accessed either on Tamarack’s website at
www.tamarackvalley.ca or under the Company’s profile on www.sedar.com.

The forward-looking statements contained in this press release are made as of
the date hereof and the Company does not undertake any obligation to update
publicly or to revise any of the included forward-looking statements, except as
required by applicable law. The forward-looking statements contained herein are
expressly qualified by this cautionary statement.

Non-IFRS Measures

Certain financial measures referred to in this press release, such as net debt,
operating netback, operating field netback and funds flow from operations
netback are not prescribed by IFRS. The Company uses these measures to help
evaluate its performance. These non-IFRS financial measures do not have any
standardized meaning prescribed by IFRS and therefore may not be comparable to
similar measures presented by other issuers. The Company uses net debt as an
alternative measure of outstanding debt. Net debt includes accounts receivable,
prepaid expenses and deposits, bank debt and accounts payable and accrued
liabilities, but excludes the fair value of financial instruments. Operating
field netback equals total petroleum and natural gas sales less royalties and
operating costs calculated on a boe basis. Operating netback is the operating
field netback with realized gains and losses on commodity derivative contracts.
Funds flow from operations netback equals funds flow from operations divided by
the total sales volume and reported on a per boe basis. Tamarack considers
operating netback and funds flow from operations netback as important measures
to evaluate its operational performance as they demonstrate the Company’s field
level profitability relative to current commodity prices. Please refer to the
MD&A for additional information relating to non-IFRS measures. The MD&A can be
accessed either on Tamarack’s website at www.tamarackvalley.ca or under the
Company’s profile on www.sedar.com.

– END RELEASE – 15/05/2017

For further information:
Brian Schmidt
President & CEO
Tamarack Valley Energy Ltd.
403.263.4440
OR
Ron Hozjan
VP Finance & CFO
Tamarack Valley Energy Ltd.
403.263.4440
www.tamarackvalley.ca

COMPANY:
FOR: TAMARACK VALLEY ENERGY LTD.
TSX SYMBOL: TVE

INDUSTRY: Energy and Utilities – Oil and Gas
RELEASE ID: 20170515CC0117

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e…

FOR: STORM RESOURCES LTD.
TSX VENTURE SYMBOL: SRX

Date issue: May 15, 2017
Time in: 5:57 PM e

Attention:

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

Storm has also filed its unaudited condensed interim consolidated financial
statements as at March 31, 2017 and for the three months then ended along with
Management’s Discussion and Analysis (“MD&A”) for the same period. This
information appears on SEDAR at www.sedar.com and on Storm’s website at
www.stormresourcesltd.com.

Selected financial and operating information for the three months ended March
31, 2017 appears below and should be read in conjunction with the related
financial statements and MD&A.

Highlights

/T/

Three Months Three Months
Thousands of Cdn$, except volumetric and Ended Ended
per-share amounts March 31, 2017 March 31, 2016
—————————————————————————-

FINANCIAL

Revenue from product sales(1) 37,045 16,121
—————————————————————————-
Funds flow 17,958 7,855
Per share – basic and diluted ($) 0.15 0.07
—————————————————————————-
Net income (loss) 20,631 (4,984)
Per share – basic and diluted ($) 0.17 (0.04)
—————————————————————————-
Operations capital expenditures(2) 27,357 23,946
—————————————————————————-
Debt including working capital
deficiency(2)(3) 97,864 77,162
—————————————————————————-
Common shares (000s)
Weighted average – basic 121,442 119,591
Weighted average – diluted 121,720 119,591
Outstanding end of period – basic 121,557 119,742
—————————————————————————-
—————————————————————————-

OPERATIONS
(Cdn$ per Boe)
Revenue from product sales 24.29 13.20
Royalties (1.88) (0.76)
Production (5.84) (6.71)
Transportation (0.69) (0.53)
—————————————————————————-
Field operating netback(2) 15.88 5.20
Realized (losses) gains on hedging (2.31) 3.03
General and administrative (1.10) (1.25)
Interest and finance costs (0.71) (0.56)
—————————————————————————-
Funds flow per Boe 11.76 6.42
—————————————————————————-
—————————————————————————-

Barrels of oil equivalent per day (6:1) 16,947 13,418
—————————————————————————-
Gas production
Thousand cubic feet per day 84,093 66,012
Price (Cdn$ per Mcf) 3.23 1.62
—————————————————————————-
Condensate production
Barrels per day 1,758 1,452
Price (Cdn$ per barrel) 64.40 41.54
—————————————————————————-
NGL production
Barrels per day 1,174 964
Price (Cdn$ per barrel) 23.09 10.44
—————————————————————————-
Wells drilled (100% working interest) 6.0 7.0
Wells completed (100% working interest) 4.0 2.0
—————————————————————————-
—————————————————————————-
(1) Excludes gains and losses on commodity price contracts.
(2) Certain financial amounts shown above are non-GAAP measurements,
including field operating netback, operations capital expenditures,
debt including working capital deficiency and all measurements per Boe.
See discussion of Non-GAAP Measurements on page 25 of the MD&A.
(3) Excludes the fair value of commodity price contracts.

/T/

PRESIDENT’S MESSAGE

2017 FIRST QUARTER HIGHLIGHTS

/T/

— Production was a record 16,947 Boe per day (17% condensate and NGL), a

per-share increase of 24% from the first quarter of last year and a per-
share increase of 27% from the previous quarter. The increase was the
result of the start-up of a third field compression facility at Umbach
on January 12, 2017 plus five new horizontal wells (5.0 net) were turned
on during the quarter.

— Condensate and NGL production increased 21% from the first quarter of

last year to average 2,932 barrels per day. Revenue from liquids was 34%
of total revenue.

— Montney horizontal well performance at Umbach continues to improve as

length and the number of fracs are increased. The five wells completed
in 2016 with enough production history averaged 4.8 Mmcf per day gross
raw gas over the first 180 calendar days, a 14% improvement from the
average 2015 wells. The four wells completed to date in 2017 are
approximately 25% longer and three of them have been producing for 30 to
60 days with encouraging early data.

— Controllable cash costs (production, general and administrative,

interest and finance) were $7.65 per Boe, a decrease of 10% year over
year. Production costs declined by 13% from the same period in 2016 and
16% from the fourth quarter of 2016 as a result of the new processing
arrangement at Umbach which started on January 1, 2017.

— Funds flow was $18.0 million ($11.76 per Boe), an increase of 129% from

a year ago. The increase was driven by an 84% increase in revenue per
Boe and a 26% increase in production volumes which was partially offset
by a realized hedging loss of $3.5 million or $2.31 per Boe.

— Net income was $20.6 million or $0.17 per share which includes an

unrealized mark to market hedging gain of $16.1 million. Notably,
excluding the effect of the unrealized hedging gain, net income was $4.5
million, or $0.04 per share.

— Capital investment was $27.4 million including $19.0 million to drill

six horizontal wells (6.0 net) and complete four horizontal wells (4.0
net) plus $1.5 million to complete the third field compression facility
at Umbach.

— At the end of the quarter, there was an inventory of ten horizontal

wells (10.0 net) that had not started producing (includes two completed
wells).

— Debt including working capital deficiency was $97.9 million which is 1.4

times annualized first quarter funds flow. Subsequent to quarter end,
the bank credit facility was increased to $165.0 million from $130.0
million.

— Commodity price hedges continue to be layered in with approximately 43%

of forecast 2017 production currently hedged.

/T/

OPERATIONS REVIEW

Umbach, Northeast British Columbia

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

Production in the first quarter of 2017 was 16,582 Boe per day and liquids
recovery was 36 barrels per Mmcf sales with 60% being higher priced field
condensate plus pentanes recovered at the gas plant. Compared to the previous
quarter, production increased by 28% while liquids recovery was the same.

During the first quarter, six horizontal wells (6.0 net) were drilled, four
horizontal wells (4.0 net) were completed and five horizontal wells (5.0 net)
started production. At the end of the quarter, there was an inventory of ten
horizontal wells (10.0 net) that had not started producing which included two
completed wells.

Activity in the second quarter of 2017 will include completing four to six
horizontal wells (4.0 to 6.0 net).

Field compression totals 115 Mmcf per day raw gas after start-up of a third
facility on January 12, 2017. Throughput in the first quarter averaged 88 Mmcf
per day raw gas. The third facility had a final cost of $24.6 million for
initial capacity of 35 Mmcf per day and will be expanded to 70 Mmcf per day by
adding a second compressor for an additional $7.0 million. Preliminary timing
for the expansion is the first half of 2018 and, once completed, total capacity
will be 150 Mmcf per day which supports growth in corporate production to
approximately 27,000 Boe per day.

Raw gas from Storm’s field compression facilities is sent to the McMahon and
Stoddart Gas Plants where firm processing commitments average 75 Mmcf per day
raw gas in 2017. On January 1, 2017, a new processing arrangement started at
the McMahon Gas Plant which has a total commitment of 65 Mmcf per day of raw
gas for 5 to 15 years and has reduced corporate production costs in the first
quarter by 16% from the fourth quarter of 2016. The arrangement supports future
growth with an option to increase contracted capacity and allows continued
diversification of natural gas sales with access to three sales pipelines
(Alliance Pipeline to Chicago, TCPL system to AECO, T-north to BC Station 2).

A summary of horizontal well performance and costs is provided below. Three of
the wells completed in 2017 have started producing and have 30 to 60 days of
history. The majority of wells are rate restricted when coming on production to
control fluid rates and adding frac stages has increased ‘flush’ production,
therefore, additional production data is required to get an indication as to
longer term performance. Future horizontal wells are expected to have completed
lengths of 1,700 to 2,100 metres with the newest ball drop completion systems
allowing for up to 44 fracs within 4.5 inch casing.

/T/

IP90 IP180 IP365
Year of Frac Completed Actual Drill & Cal Day Cal Day Cal Day
Completion Stages Length Complete Cost Mmcf/d Raw Mmcf/d Raw Mmcf/d Raw
—————————————————————————-
2013 $4.6 million 3.5 Mmcf/d 2.9 Mmcf/d 2.2 Mmcf/d
6 hz’s 17 1,190 m $270 K/stage 6 hz’s 6 hz’s 6 hz’s
—————————————————————————-
2014 $4.6 million 4.9 Mmcf/d 4.4 Mmcf/d 3.5 Mmcf/d
12 hz’s(i) 19 1,170 m $240 K/stage 12 hz’s 12 hz’s 12 hz’s
—————————————————————————-
2015 $4.4 million 4.7 Mmcf/d 4.2 Mmcf/d 3.3 Mmcf/d
11 hz’s 22 1,360 m $200 K/stage 11 hz’s 11 hz’s 10 hz’s
—————————————————————————-
2016 $3.8 million 5.1 Mmcf/d 4.8 Mmcf/d
10 hz’s 25 1,300 m $152 K/stage 10 hz’s 5 hz’s
—————————————————————————-
2017 $4.3 million
4 hz’s 35 1,670 m $123 K/stage
—————————————————————————-
—————————————————————————-

/T/

(i) 2014 wells exclude a middle Montney well (this table provides analysis of
upper Montney wells only).

Horn River Basin, Northeast British Columbia

Storm has a 100% working interest in 119 sections in the Horn River Basin
(78,000 net acres) which are prospective for natural gas from the Muskwa, Otter
Park and Evie/Klua shales. Storm’s one horizontal well averaged 302 Boe per day
in the first quarter (previous quarter averaged 310 Boe per day). Cumulative
production to date from this well is 5.5 Bcf raw.

HEDGING AND TRANSPORTATION

Commodity price hedges are used to support longer term growth by providing some
certainty regarding future revenue and funds flow. The objective is to hedge
50% of most recent quarterly or monthly production for the next 12 months and
25% for 13 to 24 months forward. Anticipated production growth is not hedged.
The WTI price is also hedged given that approximately 80% of Storm’s liquids
production is priced in reference to WTI (condensate, plant pentane and
butane). The hedge position is updated periodically in the presentation posted
on Storm’s website. Approximately 43% of forecast 2017 production is currently
hedged.

/T/

—————————————————————————-
Q2 – Q4 2017 Hedges
—————————————————————————-
Crude Oil 1,050 Bopd WTI Cdn$64.75/Bbl floor, Cdn$69.60/Bbl
ceiling
—————————————————————————-
Natural Gas 36,400 GJ/d (29,200 AECO Cdn$2.68/GJ ($3.34/Mcf)
Mcf/d)
—————————————————————————-
11,500 Mmbtu/d (9,700 Chicago Cdn$4.17/Mmbtu ($4.94/Mcf)(1)
Mcf/d)
—————————————————————————-
2018 Hedges
—————————————————————————-
Crude Oil 410 Bopd WTI Cdn$65.99/Bbl floor, Cdn$70.54/Bbl
ceiling
—————————————————————————-
Natural Gas 750 GJ/d (600 Mcf/d) AECO Cdn$2.80/GJ ($3.50/Mcf)
—————————————————————-
18,400 Mmbtu/d (15,500 Chicago Cdn$4.00/Mmbtu ($4.75/Mcf)(1)
Mcf/d)
—————————————————————————-
(1) Hedge price in Chicago doesn’t include the Alliance Pipeline tariff to
Chicago which was Cdn$1.66 per Mcf in the first quarter including the
cost of fuel.

/T/

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

The strategy with respect to natural gas transportation commitments is to
mitigate risk by diversifying sales and selling at multiple points. In the
first quarter of 2017, 62% of natural gas sales were at Chicago, 32% at BC
Station 2 and 6% at Alliance Transfer Point (“ATP”). Approximately 82% of
forecast natural gas production in 2017 is covered by firm transportation
commitments with the remainder directed to Chicago and/or BC Station 2 using
interruptible pipeline capacity (sales point depends on price). Note that the
cost of transportation to Chicago and ATP on the Alliance Pipeline is presented
as a deduction from revenue with $7.3 million deducted from revenue in the
first quarter of 2017. Further information on pipeline tariffs and price
deductions is provided in the presentation on Storm’s website.

/T/

—————————————————————————-
2017 Firm Transportation 2018 Firm Transportation
—————————————————————————-
Alliance Pipeline(1) Alliance Pipeline(1)
51 Mmcf/d Chicago price 55 Mmcf/d Chicago price
5 Mmcf/d ATP price 5 Mmcf/d ATP price
—————————————————————————-
T-north T-north
16 Mmcf/d BC Station 2 price 29 Mmcf/d BC Station 2 price
—————————————————————————-
T-north & TCPL
13 Mmcf/d AECO price
—————————————————————————-
2017 Total 72 Mmcf per day 2018 Total 102 Mmcf per day
—————————————————————————-
(1) Interruptible capacity on the Alliance Pipeline adds up to 25% of
contracted capacity.

/T/

ORGANIZATIONAL UPDATE

On May 16, 2017, Mr. Michael Hearn will assume the role of Chief Financial
Officer and will replace Mr. Donald McLean who has been associated with Storm
and its predecessor companies for 17 years. Mr. Hearn is a Chartered Accountant
with 14 years of experience and joined Storm on November 1, 2016 after six
years with an independent energy investment bank with his last position being
equity research analyst. Prior to that, Mr. Hearn was employed at a junior
international producer and also spent six years at a multi-national accounting
firm.

On May 16, 2017, Ms. Emily Wignes will assume the role of Vice President,
Finance and will replace Mr. John Devlin who has been associated with Storm and
its predecessor companies for 13 years. Ms. Wignes is a Chartered Accountant
with 15 years of experience and joined Storm on December 1, 2016 after two
years at an intermediate producer where her most recent position was Manager,
Financial Reporting. Prior to that, Ms. Wignes was employed at other
intermediate and large producers and prior thereto at a multi-national
accounting firm.

Both Mr. Donald McLean and Mr. John Devlin will continue to provide advisory
services on an as needed basis in the near term. Their contributions to Storm
and its predecessor companies have been significant and much appreciated.

OUTLOOK

For the second quarter of 2017, production is anticipated to be 14,000 to
15,000 Boe per day which includes the effect of a maintenance turnaround at the
McMahon Gas Plant which will result in approximately 75% of Storm’s production
being shut in for 21 days. Note that production in April averaged approximately
18,400 Boe per day based on field estimates. Capital investment in the second
quarter is expected to be approximately $13 to $18 million which includes
completing four to six horizontal wells at Umbach.

Guidance for 2017 includes an increase to forecast production as a result of
well performance exceeding expectations and a reduction to forecast royalty
rates. As well, forecast commodity prices are updated to reflect actual first
quarter pricing.

/T/

2017 Guidance Updated Updated Updated
November 15, 2016 March 2, 2017 May 15, 2017
—————————————————————————-
$Cdn/$US exchange rate 0.77 0.77 0.75
—————————————————————————-
Chicago spot natural
gas (US$/Mmbtu) $3.00 $3.00 $3.00
—————————————————————————-
AECO spot natural gas
(Cdn$/GJ) $2.65 $2.50 $2.50
—————————————————————————-
BC Stn 2 spot natural
gas (Cdn$/GJ) $2.20 $2.00 $2.10
—————————————————————————-
Edmonton light oil
(Cdn$/bbl) $55.00 $59.00 $62.00
—————————————————————————-
Estimated average
operating costs
($/Boe) $5.50 – $5.75 $5.50 – $6.00 $5.50 – $6.00
—————————————————————————-
Estimated average
royalty rate (%
production revenue
before hedging) 9% – 11% 9% – 11% 7% – 10%
—————————————————————————-
Estimated operations
capital ($ million)
(excluding
acquisitions &
dispositions) $75.0 – $80.0 $75.0 – $80.0 $75.0 – $80.0
—————————————————————————-
Estimated cash G&A
– $ million $5.3 $5.3 $5.3
– $/Boe $0.85 $0.85 $0.85
—————————————————————————-
Forecast fourth
quarter production
(Boe/d) 18,000 – 20,000 18,000 – 20,000 19,000 – 21,000
% condensate and NGL 17% 17% 17%
—————————————————————————-
Forecast annual
production (Boe/d) 16,500 – 18,000 16,500 – 18,000 17,000 – 18,000
% condensate and NGL 17% 17% 17%
—————————————————————————-
Umbach horizontal 12 gross (12.0 12 gross (12.0 12 gross (12.0
wells drilled net) net) net)
Umbach horizontal 14 gross (14.0 14 gross (14.0 14 gross (14.0
wells completed net) net) net)
Umbach horizontal 15 gross (15.0 15 gross (15.0 15 gross (15.0
wells connected net) net) net)
—————————————————————————-
—————————————————————————-

/T/

2017 Guidance History

/T/

Chicago BC Station 2 AECO
(US$/mmbtu) (Cdn$/GJ) (Cdn$/GJ)
—————————————————————————-
September 7, 2016 $3.00 $2.25 $2.65
—————————————————————————-
November 15, 2016 $3.00 $2.20 $2.65
—————————————————————————-
March 2, 2017 $3.00 $2.00 $2.50
—————————————————————————-
May 15, 2017 $3.00 $2.10 $2.50
—————————————————————————-
—————————————————————————-

Estimated Forecast
Operations Fourth Quarter Forecast Annual
Capital Production Production
($ million) (Boe/d) (Boe/d)
—————————————————————————
September 7, 2016 $75.0 – $80.0 18,000 – 20,000 16,500 – 18,000
—————————————————————————
November 15, 2016 $75.0 – $80.0 18,000 – 20,000 16,500 – 18,000
—————————————————————————
March 2, 2017 $75.0 – $80.0 18,000 – 20,000 16,500 – 18,000
—————————————————————————
May 15, 2017 $75.0 – $80.0 19,000 – 21,000 17,000 – 18,000
—————————————————————————
—————————————————————————

/T/

There is flexibility to adjust 2017 capital investment depending on commodity
prices and funds flow which may affect forecast production. The current hedge
position will provide some cushion in the event of a material decline in
commodity prices. Note that some cost inflation is expected based on 2017 first
quarter results and capital investment assumes the cost to drill and complete a
horizontal well at Umbach is $4.3 million, an increase of 13% from the 2016
actual cost.

The outlook for natural gas prices remains positive as a result of a growing
supply/demand deficit in the United States. Data from the Energy Information
Administration (“EIA”) shows 2016 demand (consumption) exceeded supply (dry gas
production plus net imports) by 0.9 Bcf per day. So far in 2017, January and
February supply is 1.1 Bcf per day lower than the 2016 average which further
widens the deficit. Longer term, demand continues to increase as a result of
five LNG export facilities currently operating or under construction on the US
Gulf Coast. In addition, US pipeline capacity to Mexico is expected to increase
by more than 6 Bcf per day by the end of 2018 from six new pipelines.

Most of Storm’s firm transportation commitments have been added over the last
two years with the intent of reducing risk by diversifying natural gas sales
(not betting for or against pricing in any single market). A good example
supporting the diversification of sales is the continued narrowing of the AECO
– BC Station 2 price differential which is contrary to the consensus view that
the differential would widen with continued production growth from northeast
British Columbia (“NE BC”). Since late 2015, the differential has narrowed to
average -$0.19 per GJ in the first quarter of 2017 versus -$0.41 per GJ in 2016
and -$0.85 per GJ in 2015. Although production growth has continued, the
differential has not been impacted as most of the growth has been directed onto
the TCPL system to AECO (the differential can be temporarily affected by
outages and/or constraints on the TCPL system or Alliance Pipeline where more
natural gas is redirected to BC Station 2). Also helping was the Alliance
Pipeline re-contracting in late 2015 where most of the capacity was taken up by
producers instead of marketers. TCPL is planning to further increase capacity
out of NE BC with the North Montney extension which adds 1.5 Bcf per day of
takeaway in early 2019 if a variance application is approved by the National
Energy Board (“NEB”). It is unlikely that production can grow this much over
the next two years, so some of the incremental volume for this expansion is
likely to be sourced from natural gas redirected away from BC Station 2 which
further supports a narrower differential. In the first quarter of 2017,
approximately 32% of Storm’s natural gas sales benefitted from the narrowing
differential.

There continues to be an effort directed toward reducing Storm’s cost structure
to improve competitiveness in the continuing lower price environment.
Production costs per Boe have decreased by 16% from the fourth quarter of 2016
with the new processing arrangement at Umbach. Further reductions in per-Boe
costs are expected with continued production growth at Umbach. Reserve addition
costs are being reduced with longer horizontal wells that access more gas in
place plus adding fracs on tighter spacing is increasing recovery. Recent
results from longer 2017 wells are encouraging and further improvement is
expected as longer wells are drilled and brought on production.

Current commodity prices are supportive of the near-term plan to grow average
2017 production by more than 30% from 2016 levels by investing $75 to $80
million which will result in year-end net debt of approximately $95 to $100
million, a year-over-year increase of 5% to 10%. The preliminary plan for 2018
is for a further 25% to 35% increase in production volumes. Growth in 2017 and
2018 is further supported by firm transportation commitments, hedging and the
infrastructure at Umbach which supports growth to 27,000 Boe per day (after
adding a second compressor at the third field compression facility).

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

Respectfully,

Brian Lavergne, President and Chief Executive Officer

May 15, 2017

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

Non-GAAP Measures – This document contains the terms “debt including working
capital deficiency”, “field operating netbacks”, “field operating netbacks
including hedging”, the terms “cash” and “non-cash”, “cash costs”, and
measurements “per commodity unit” and “per Boe” which are not recognized under
Generally Accepted Accounting Principles (“GAAP”) and are regarded as non-GAAP
measures. These non-GAAP measures may not be comparable to the calculation of
similar amounts for other entities and readers are cautioned that use of such
measures to compare enterprises may not be valid. Non-GAAP terms are used to
benchmark operations against prior periods and peer group companies and are
widely used by investors, analysts and other parties. These measurements are
also used by lenders to measure compliance with debt covenants and thus set
interest costs. Additional information relating to certain of these non-GAAP
measures can be found in Storm’s MD&A for the three months ended March 31,
2017, which is available on Storm’s SEDAR profile at www.sedar.com and on
Storm’s website at www.stormresourcesltd.com.

Oil and Gas Metrics – This press release may contain a number of oil and gas
metrics, including FD&A, recycle ratio, FDC, and reserves life index or RLI,
which do not have standardized meanings or standard methods of calculation and
therefore such measures may not be comparable to similar measures used by other
companies. Such metrics have been included herein to provide readers with
additional measures to evaluate the Company’s performance; however, such
measures are not reliable indicators of the future performance of the Company
and future performance may not compare to the performance in previous periods.

Initial Production Rates – References in this press release to initial
production rates, and other short-term production rates are useful in
confirming the presence of hydrocarbons, however such rates are not
determinative of the rates at which such wells will commence production and
decline thereafter and are not indicative of long term performance or of
ultimate recovery. Additionally, such rates may also include recovered “load
oil” fluids used in well completion stimulation. Readers are cautioned not to
place reliance on such rates in calculating the aggregate production for the
Company. A pressure transient analysis or well-test interpretation has not been
carried out in respect of all wells. Accordingly, the Company cautions that the
test results should be considered to be preliminary.

DPIIP – Original Oil in Place (OOIP) is the equivalent to Discovered Petroleum
Initially In Place (DPIIP) for the purposes of this press release. DPIIP is
defined as quantity of hydrocarbons that are estimated to be in place within a
known accumulation. There is no certainty that it will be commercially viable
to produce any portion of the resources. A recovery project cannot be defined
for this volume of DPIIP at this time, and as such it cannot be further
sub-categorized.

Forward-Looking Information – This press release contains forward-looking
statements and forward-looking information within the meaning of applicable
securities laws. The use of any of the words “will”, “would”, “expect”,
“anticipate”, “intend”, “believe”, “plan”, “potential”, “outlook”, “forecast”,
“estimate”, “budget” and similar expressions are intended to identify
forward-looking statements or information. More particularly, and without
limitation, this press release contains forward-looking statements and
information concerning: production; drilling and completion plans; the third
field compression facility and expansion plans in connection therewith; the
January 2017 transportation arrangement; hedging; transportation;
organizational and personnel changes; 2017 and 2018 guidance in respect of
certain operational and financial metrics, including, but not limited to,
commodity pricing, estimated average operating costs, estimated average royalty
rate, estimated operations capital, estimated general and administrative costs,
estimated quarterly and annual production and estimated number of Umbach
horizontal wells drilled, completed and connected, capital investment plans,
infrastructure plans, anticipated United States exports, pipeline capacity,
price volatility mitigation strategy and cost reductions. Statements of
“reserves” are also deemed to be forward-looking statements, as they involve
the implied assessment, based on certain estimates and assumptions, that the
reserves described exist in the quantities predicted or estimated and that the
reserves can be profitably produced in the future.

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

Since forward-looking statements and information address future events and
conditions, by their very nature they involve inherent risks and uncertainties.
Actual results could differ materially from those currently anticipated due to
a number of factors and risks. These include, but are not limited to the risks
associated with the oil and gas industry in general such as: general economic
conditions in Canada, the United States and internationally; operational risks
in development, exploration and production; delays or changes in plans with
respect to exploration or development projects or capital expenditures; the
uncertainty of reserve estimates; the uncertainty of estimates and projections
relating to reserves, production, costs and expenses; health, safety and
environmental risks; commodity price and exchange rate fluctuations; marketing
and transportation of petroleum and natural gas and loss of markets;
competition; ability to access sufficient capital from internal and external
sources; geopolitical risk; stock market volatility; and changes in
legislation, including but not limited to tax laws, royalty rates and
environmental regulations.

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

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

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

– END RELEASE – 15/05/2017

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

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

INDUSTRY: Energy and Utilities – Oil and Gas
RELEASE ID: 20170515CC0108

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.

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

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

Attention:

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

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

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

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

– END RELEASE – 15/05/2017

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

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

INDUSTRY: Energy and Utilities – Oil and Gas
RELEASE ID: 20170515CC0086

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.

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

FOR: ESREY ENERGY LTD.
TSX VENTURE SYMBOL: EEL

Date issue: May 15, 2017
Time in: 2:01 PM e

Attention:

VANCOUVER, BRITISH COLUMBIA–(Marketwired – May 15, 2017) – Further to its news
release of May 1, 2017 (the “May 1 Release”), Esrey Energy Ltd. (“Esrey” or the
“Company”) (TSX VENTURE:EEL) is pleased to announce that both Esrey and PRG Plc
(“PRG”) have completed a satisfactory due diligence review of the other and
have entered into a definitive agreement providing for the acquisition by Esrey
of the shares of Power Zinc Limited from PRG (the “Acquisition”), on
substantially the terms of the LOI as detailed in the May 1 Release.

In connection with the Acquisition, the Company has agreed to grant 4,183,000
options to designates of PRG and Company participants on closing of the
Acquisition, to be priced in accordance with the policies of the TSX Venture
Exchange.

Closing of the Acquisition remains subject to the acceptance of the TSX Venture
Exchange and trading in the shares of the Company will remain halted pending
satisfaction of the requirements of section 5.6(d) of the TSX Venture Exchange
Policy 5.3.

On behalf of the Board of Directors

David Nelson, President & CEO

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 – 15/05/2017

For further information:
Investor Relations
1-778-373-0103
info@esreyenergy.com

COMPANY:
FOR: ESREY ENERGY LTD.
TSX VENTURE SYMBOL: EEL

INDUSTRY: Energy and Utilities – Oil and Gas
RELEASE ID: 20170515CC0074

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.

FOR: EAGLE ENERGY INC.TSX SYMBOL: EGLDate issue: May 15, 2017Time in: 1:34 PM eAttention:
CALGARY, ALBERTA–(Marketwired – May 15, 2017) – Eagle Energy Inc. (“Eagle”)
(TSX:EGL) announced that its corporate presentation is now available at
www.EagleEne…

FOR: DIVERGENT ENERGY SERVICES CORP.TSX VENTURE SYMBOL: DVGDate issue: May 15, 2017Time in: 12:00 PM eAttention:
CALGARY, ALBERTA–(Marketwired – May 15, 2017) –
NOT FOR DISSEMINATION IN THE UNITED STATES OF AMERICA
DIVERGENT Energy Services Corp. (TS…

FOR: CANADIAN ASSOCIATION OF PETROLEUM PRODUCERS (CAPP)
Date issue: May 15, 2017Time in: 11:45 AM eAttention:
CALGARY, ALBERTA–(Marketwired – May 15, 2017) – The Canadian Association of
Petroleum Producers (CAPP) is disappointed with the Government o…

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

Date issue: May 15, 2017
Time in: 11:41 AM e

Attention:

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

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

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

CRESCENT POINT ENERGY CORP.

Scott Saxberg, President and Chief Executive Officer

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

– END RELEASE – 15/05/2017

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

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

INDUSTRY: Energy and Utilities – Oil and Gas
RELEASE ID: 20170515CC0058

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.

FOR: PNG GOLD CORPORATIONTSX VENTURE SYMBOL: PGKDate issue: May 15, 2017Time in: 11:28 AM eAttention:
VANCOUVER, BRITISH COLUMBIA–(Marketwired – May 15, 2017) – PNG Gold
Corporation (the “Company”) (TSX VENTURE:PGK) is pleased to announce that it
has…

FOR: RAZOR ENERGY CORP.
TSX VENTURE SYMBOL: RZE

Date issue: May 15, 2017
Time in: 9:11 AM e

Attention:

CALGARY, ALBERTA–(Marketwired – May 15, 2017) –

NOT FOR DISTRIBUTION IN THE UNITED STATES. ANY FAILURE TO COMPLY WITH THIS
RESTRICTION MAY CONSTITUTE A VIOLATION OF U.S. SECURITIES LAW.

Razor Energy Corp. (“Razor” or the “Company”) (TSX VENTURE:RZE)
(www.razor-energy.com) is pleased to announce that it has closed its previously
announced short form prospectus offering of subscription receipts of Razor
(“Subscription Receipts”) conducted on a reasonable efforts agency basis (the
“Subscription Receipt Offering”). The Company issued 5,750,000 Subscription
Receipts, including 750,000 Subscription Receipts issued on full exercise of
the over-allotment option, at a price of $3.00 per Subscription Receipt for
gross proceeds of $17.25 million. The Subscription Receipt Offering was co-led
by Haywood Securities Inc. and Jett Capital Advisors, LLC, together with
Canaccord Genuity Corp., Eight Capital, National Bank Financial Inc., Acumen
Capital Finance Partners Limited and Macquarie Capital Markets Canada Ltd.

Each Subscription Receipt entitles the holder thereof, without payment of any
additional consideration and without further action on the part of the holder,
to receive one common share of the Company (a “Common Share”) and one-half of
one Common Share purchase warrant of the Company (a “Warrant”) upon closing of
the previously announced acquisition by the Company of strategic assets in west
central Alberta for cash consideration of $9.6 million, subject to customary
adjustments (the “Acquisition”). Each whole Warrant will be exercisable into
one Common Share at an exercise price of $3.50 per Common Share for a period of
12 months following the closing of the Acquisition.

The gross proceeds from the Subscription Receipt Offering will be placed in
escrow (the “Escrowed Proceeds”) and released to Razor (together with any
interest earned thereon) upon Haywood Securities Inc., on behalf of the Agents,
being satisfied and receiving a certificate from the Company to the effect
that: (i) there is no impediment to completion of the Acquisition, other than
the payment of the purchase price, in all material respects in accordance with
the terms of the acquisition agreement in respect of the Acquisition, without
material amendment or waiver adverse to Razor; and (ii) receipt by the Company
of all necessary regulatory and other approvals regarding the Acquisition
(together, the “Escrow Release Conditions”).

If: (i) the Escrow Release Conditions are not satisfied at or before 5:00 p.m.
(Calgary time) on June 30, 2017 (the “Escrow Release Deadline”); (ii) the
Company, prior to the Escrow Release Deadline, has provided notice to Haywood
Securities Inc. or announced to the public, that it does not intend to proceed
with the Acquisition; or (iii) the acquisition agreement in respect of the
Acquisition is terminated, then the Escrowed Proceeds will be reimbursed pro
rata to each holder of the Subscription Receipts at the original subscription
price, plus such holder’s pro rata portion of the interest earned thereon, if
any (payable out of the Escrowed Proceeds).

The net proceeds of the Subscription Receipt Offering will be used to fund the
purchase price in respect of the Acquisition and to fund the Company’s capital
expenditure program.

This press release is not an offer of the securities for sale in the United
States. The securities have not been registered under the U.S. Securities Act
of 1933, as amended, and may not be offered or sold in the United States absent
registration or an exemption from registration. This press release shall not
constitute an offer to sell or the solicitation of an offer to buy nor shall
there be any sale of the securities in any state in which such offer,
solicitation or sale would be unlawful.

ABOUT RAZOR

Razor Energy Corp. is a light oil focused company operating predominantly in
Alberta. Razor’s full-cycle business plan provides an opportunity to reposition
the Company as a disciplined and high-growth junior E&P company. With an
experienced management team and a strong, committed Board, growth is
anticipated to occur through timely strategic acquisitions and operations.
Razor currently trades on TSX Venture Exchange under the ticker “RZE”.

READER ADVISORIES

FORWARD-LOOKING STATEMENTS: This press release contains forward-looking
statements. More particularly, this press release contains statements
concerning, but not limited to: the timing of the Acquisition, payment of the
purchase price in respect of the Acquisition, the use of proceeds from the
Subscription Receipt Offering and the issuance of the Common Shares and
Warrants underlying the Subscription Receipts. In addition, the use of any of
the words “anticipate”, “believe”, “expect”, “plan”, “intend”, “estimate”,
“propose”, “project”, “can”, “will”, “should”, “continue”, “may”, and similar
expressions are intended to identify forward-looking statements.

The forward-looking statements contained herein are based on certain key
expectations and assumptions made by the Company, including but not limited to
receipt of required regulatory approvals. Although the Company believes that
the expectations and assumptions on which the forward-looking statements are
based are reasonable, undue reliance should not be placed on the
forward-looking statements because the Company can give no assurance that they
will prove to be correct. Since forward-looking statements address future
events and conditions, by their very nature they involve inherent risks and
uncertainties including, without limitation. Actual results could differ
materially from those currently anticipated due to a number of factors and
risks. These include, but are not limited to, risk that all necessary approvals
for the closing of the Acquisition are not received, other conditions to the
closing of the Acquisition are not satisfied or any other events occur that
delay or prevent the closing of the Acquisition. Please refer to additional
risk factors relating to Razor’s operations and financial results identified in
the annual information form and management discussion and analysis of the
Company for the period ended December 31, 2016, each of which are available on
SEDAR at www.sedar.com.

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

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

– END RELEASE – 15/05/2017

For further information:
Doug Bailey
President and Chief Executive Officer
OR
Kevin Braun
Chief Financial Officer
OR
Razor Energy Corp.
1250, 645 7th Avenue S.W.
Calgary, Alberta T2P 4G8
(403) 262-0242
www.razor-energy.com

COMPANY:
FOR: RAZOR ENERGY CORP.
TSX VENTURE SYMBOL: RZE

INDUSTRY: Energy and Utilities – Oil and Gas
RELEASE ID: 20170515CC0043

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.

FOR: PRECISION DRILLING CORPORATION
TSX SYMBOL: PD
NYSE SYMBOL: PDS

Date issue: May 15, 2017
Time in: 8:30 AM e

Attention:

CALGARY, ALBERTA–(Marketwired – May 15, 2017) – Precision Drilling Corporation
(“Precision”) (TSX:PD)(NYSE:PDS) is hosting its Analyst and Investor Day today
at its Technical Services Center in Houston. Key items that will be discussed
at the event are highlighted below and a full presentation of the event can be
found on Precision’s website.

This news release contains “forward-looking information and statements” within
the meaning of applicable securities laws. For a full disclosure of the
forward-looking information and statements and the risks to which they are
subject, see the “Cautionary Statement Regarding Forward-Looking Information
and Statements” later in this news release.

Technology Update

Today’s technology discussion is focused on several field-ready technology
building blocks: Drilling Equipment Control System, Process Automation Control,
Directional Guidance System, High Speed Downhole Data, Optimization and Apps.
Beta-style field trials of these technologies are ongoing and Precision is
pleased with its progress to date including:

/T/

— Drilling Equipment Control System: largest installed fleet of AMPHION

control systems
— Process Automation Control: 15 rigs installed with NOVOS
— Directional Guidance System: 121 wells and 1.5 million feet drilled
— High Speed Downhole Data Communication (wired drill pipe): 384 thousand
feet drilled representing more than 96% of the total footage drilled on
land to date utilizing wired drill pipe

/T/

Precision is at the forefront of automation and is uniquely positioned with its
existing Super Series drilling rig fleet to achieve scalability and cost
efficient execution of these technologies. Management expects to commercialize
these automation features in 2017.

Precision’s 2017 Strategic Priorities

At the beginning of the year, Precision published three strategic priorities
for 2017:

/T/

— Deliver High Performance, High Value service offerings in an improving

demand environment while demonstrating fixed cost leverage.
— Commercialize rig automation and efficiency-driven technologies across
our Super Series fleet.
— Maintain strict financial discipline in pursuing growth opportunities
with a focus on free cash flow and debt reduction.

/T/

Activity Update

In Canada, Precision has averaged 30 active rigs quarter-to-date with 21 rigs
currently active with six additional rigs temporarily waiting on location for
better weather before moving to the next pad. Precision expects current
Canadian activity to be at trough levels for the year due to the Canadian
market’s annual spring break up. In the U.S., Precision currently has 55 active
rigs and quarter-to-date average active rig count in the U.S. is 58 rigs.
Precision expects to have five additional rigs contracted and activated over
the next three weeks. Internationally, activity continues to progress as
expected with eight rigs active in the quarter.

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION AND STATEMENTS

Certain statements contained in this release, including statements that contain
words such as “achieve”, “expect” and similar expressions and statements
relating to matters that are not historical facts constitute “forward-looking
information” within the meaning of applicable Canadian securities legislation
and “forward-looking statements” within the meaning of the “safe harbor”
provisions of the United States Private Securities Litigation Reform Act of
1995 (collectively, “forward-looking information and statements”).

In particular, forward looking information and statements include, but are not
limited to, the following:

/T/

— our anticipated commercialization of certain automation features in

2017;
— rigs temporarily waiting on location for better weather before moving to
the next pad; and
— our expectation of five additional rigs contracted and activated over
the next three weeks.

/T/

These forward-looking information and statements are based on certain
assumptions and analysis made by Precision in light of our experience and our
perception of historical trends, current conditions, expected future
developments and other factors we believe are appropriate under the
circumstances. These include, among other things:

/T/

— the status of current negotiations with our customers;
— existing term contracts are neither renewed nor terminated prematurely;
— our ability to deliver rigs to customers on a timely basis; and
— the general stability of the economic and political environments in the

jurisdictions where we operate.

/T/

Undue reliance should not be placed on forward-looking information and
statements. Whether actual results, performance or achievements will conform to
our expectations and predictions is subject to a number of known and unknown
risks and uncertainties which could cause actual results to differ materially
from our expectations. Such risks and uncertainties include, but are not
limited to:

/T/

— volatility in the price and demand for oil and natural gas;
— fluctuations in the demand for contract drilling, well servicing and

ancillary oilfield services;
— Our customers’ inability to obtain adequate credit or financing to
support their drilling and production activity;
— changes in drilling and well servicing technology which could reduce
demand for certain rigs or put us at a competitive disadvantage;
— shortages, delays and interruptions in the delivery of equipment
supplies and other key inputs;
— the effects of seasonal and weather conditions on operations and
facilities;
— the availability of qualified personnel and management;
— a decline in our safety performance which could result in lower demand
for our services;
— changes in environmental laws and regulations such as increased
regulation of hydraulic fracturing or restrictions on the burning of
fossil fuels and greenhouse gas emissions, which could have an adverse
impact on the demand for oil and gas;
— terrorism, social, civil and political unrest in the foreign
jurisdictions where we operate;
— fluctuations in foreign exchange, interest rates and tax rates; and
— other unforeseen conditions which could impact the use of services
supplied by Precision and Precision’s ability to respond to such
conditions.

/T/

Readers are cautioned that the forgoing list of risk factors is not exhaustive.
Additional information on these and other factors that could affect our
business, operations or financial results are included in reports on file with
applicable securities regulatory authorities, including but not limited to
Precision’s Annual Information Form for the year ended December 31, 2016, which
may be accessed on Precision’s SEDAR profile at www.sedar.com or under
Precision’s EDGAR profile at www.sec.gov. The forward-looking information and
statements contained in this news release are made as of the date hereof and
Precision undertakes no obligation to update publicly or revise any
forward-looking statements or information, whether as a results of new
information, future events or otherwise, except as required by law.

About Precision

Precision is a leading provider of safe and High Performance, High Value
services to the oil and gas industry. Precision provides customers with access
to an extensive fleet of contract drilling rigs, directional drilling services,
well service and snubbing rigs, camps, rental equipment, and wastewater
treatment units backed by a comprehensive mix of technical support services and
skilled, experienced personnel.

Precision is headquartered in Calgary, Alberta, Canada. Precision is listed on
the Toronto Stock Exchange under the trading symbol “PD” and on the New York
Stock Exchange under the trading symbol “PDS”.

– END RELEASE – 15/05/2017

For further information:
Carey Ford
Senior Vice President & Chief Financial Officer
403.716.4566
403.716.4755 (FAX)
www.precisiondrilling.com

COMPANY:
FOR: PRECISION DRILLING CORPORATION
TSX SYMBOL: PD
NYSE SYMBOL: PDS

INDUSTRY: Energy and Utilities – Equipment, Energy and Utilities –
Oil and Gas
RELEASE ID: 20170515CC0031

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.

FOR: H2O INNOVATION INC.
TSX VENTURE SYMBOL: HEO
EURONEXT PARIS SYMBOL: ALHEO
OTCQX SYMBOL: HEOFF

Date issue: May 15, 2017
Time in: 8:00 AM e

Attention:

QUEBEC CITY, QUEBEC–(Marketwired – May 15, 2017) – H2O Innovation Inc. (TSX
VENTURE:HEO)(ALTERNEXT:MNEMO:ALHEO)(OTCQX:HEOFF)

Key highlights

/T/

— Continuous revenue growth of 49.9% to reach $21.3 M, compared to $14.2 M

for the same period of the previous fiscal year;
— 81.4% of the revenues recorded in this third quarter are coming from O&M
and SP&S activities, which are recurring in nature;
— Consolidated backlog reached new high of $117.1 M as at March 31, 2017,
boosted by new projects bookings and renewal of O&M contract;
— Adjusted EBITDA(1) stood at $411,737, compared to $1,245,324 for the
same quarter last year, impacted by lower revenues coming from Projects,
and investment in selling expenses and product development;
— Net (loss) earnings amounted to ($1,345,695), compared to $646,422 for
the same period of the previous fiscal year, impacted by acquisition-
related costs and integration costs of Utility Partners;
— Operating activities used ($1,135,127) in cash, compared with ($318,078)
of cash used during the same quarter of the previous fiscal year.

/T/

All amounts in Canadian dollars unless otherwise stated.

/T/

(1)The definition of adjusted earnings before interest, tax depreciation

and amortization (adjusted EBITDA) does not take into account the
Corporation’s finance costs – net, stock-based compensation costs, gain
on purchase price adjustment, unrealized exchange (gains) / losses and
acquisition and integration costs. See reconciliation of this non-IFRS
measure below. The definition of adjusted EBITDA used by the Corporation
may differ from those used by other companies.

/T/

H2O Innovation Inc. (“H2O Innovation” or the “Corporation”) (TSX
VENTURE:HEO)(ALTERNEXT:MNEMO:ALHEO)(OTCQX:HEOFF) announces its results for the
third quarter of fiscal year 2017 ended March 31, 2017. During this quarter,
the Corporation’s revenues increased by 49.9% to $21.3 M, up from $14.2 M for
the same quarter of fiscal year 2016. This increase is largely attributable to
the acquisition of Utility Partners, effective July 1, 2016, which added
significant revenues coming from Operation & Maintenance (“O&M”) activities.

“On this third quarter, the integration of Utility Partners reached a new
level. We can now consider this entity fully merged into H2O Innovation. We
recently captured our first bookings from cross selling generated by Utility
Partners. The Corporation, through Utility Partners, has been able to renew or
extend all of its O&M contracts coming up for renewal and has secured a new
one, using the support of the Projects and SP&S resources. The strategy to grow
O&M and SP&S business pillars is proven to be efficient since it minimizes the
impact of revenue volatility associated with water treatment projects and thus
increase predictability in our business model. With three strong business
pillars, the Corporation is very well balanced and not dependent on a single
source of revenues”, stated Frederic Dugre, President and Chief Executive
Officer of H2O Innovation.

For this third quarter, 40.9% of the revenues came from O&M activities, 40.5%
of the revenues came from the SP&S and 18.6% came from water treatment
projects. “As our project backlog enters into manufacturing phase, we expect to
see our revenues coming from this pillar in the neighborhood to 25% to 30%”,
added Mr. Dugre. The consolidated backlog as of March 31, 2017 stood at $117.1
M, with $56.7 M coming from our projects business pillar and $60.4 M from the
O&M activities.

Revenues from water treatment projects have declined momentarily to $4.0 M
compared to $4.8 M in the corresponding period of the previous fiscal year,
representing a 17.0% decrease. This is not unusual since revenues from water
treatment projects vary from quarter to quarter and depends on the different
milestones reached for revenue recognition. Over the last twelve months,
revenues for projects reached $17.9 M, which represent a decrease of 27.8%
decrease compared to the previous twelve months, where revenues were at $24.8
M. This decrease is explained by the fact that the nature of projects has
changed. The actual water treatment projects backlog consists of municipal
projects that have a more extensive engineering phase, which phase generates
less revenue under the revenue recognition accounting method and this phase
tends to spread out over longer periods than what we were used to with our past
projects. Once projects are entering into the manufacturing phase, it allows
recognition of significantly more revenues as fabrication and assembly moves
forward. Also, project execution is sometimes postponed due to situations
outside of the control of the Corporation, and therefore impacts revenue
recognition.

Even though revenues are slower and lumpy, the water treatment projects are
still a growth vehicle of the Corporation. The water treatment projects order
backlog stood at $56.7 M as at March 31, 2017, compared to $42.1 M a year ago,
representing a 34.7% increase over the last twelve months. The increase of
bookings is not converting into revenue growth at the same pace, due to the
longer period of execution per contract. “Since July 1st 2016, we secured $20.9
M in bookings, with a current pipeline of water treatment projects rich in
opportunities, which should allow the Corporation to continue to increase its
project order backlog and support its revenue growth. We maintain strong
bidding activities and business development mainly in Canada and in United
States”, added Mr. Dugre.

Revenues from SP&S reached $8.6 M compared to $9.4 M in the comparable quarter
of the previous fiscal year. Even though it is a decrease of 8.5% compared to
the same quarter last year, it is the second best quarterly result of the
Corporation’s history for the SP&S pillar. Over the last twelve months,
revenues reached $28.1 M, which represents an increase of 6.3% compared to the
previous twelve months where revenues were at $26.6 M. This increase in SP&S
revenues is the direct result of investments made during the last few years in
our operating and selling functions to support the growth of this business line.

Revenues coming from O&M amounted to $8.7 M. These revenues are recurring sales
and came mainly from the recently acquired Utility Partners. The backlog
related to these O&M contracts stood at $60.4 M as at March 31, 2017 and
consists of long-term contracts, mainly with municipalities, which contain
multi-year renewal options. The backlog increased by $5.5 M in this quarter,
from $54.9 M as at December 31, 2016 to $60.4 M as at March 31, 2017.

In this third quarter of fiscal year 2017, the Corporation generated a 23.8%
gross profit before depreciation and amortization, a lower level than the 31.8%
gross profit before depreciation and amortization generated in the third
quarter of fiscal year 2016. The revenue mix has been modified with the
acquisition of Utility Partners which operates in a different model than our
previous core activities. Indeed, O&M activities generally generates lower
gross margin. Therefore, the integration of Utility Partners into H2O
Innovation, which in this quarter represents 40.9% of the total revenues, puts
pressure on the overall gross margin of the Corporation, although increasing
the predictability and stability of the financial results, and ultimately
profitability.

/T/

Three-month periods Nine-month periods
CONSOLIDATED RESULTS ended on March 31, ended on March 31,
Selected financial data (Unaudited) (Unaudited)
2017 2016 2017 2016
$ $ $ $
————————————————
Revenues 21,284,643 14,199,860 61,111,336 39,624,778
Gross profit before
depreciation and
amortization 5,060,641 4,522,640 14,358,617 11,853,728
Gross profit before
depreciation and
amortization 23.8% 31.8% 23.5% 29.9%
Operating expenses 523,721 356,160 1,448,128 1,009,026
Selling expenses 1,975,348 1,679,681 5,186,872 4,648,798
Administrative expenses 2,307,189 1,289,659 6,300,002 3,521,379
Research and development
expenses – net 16,075 24,126 131,319 144,300
Net (loss) earnings (1,345,695) 646,422 (3,521,051) 872,972
Basic and diluted (loss) (0.034) 0.031 (0.104) 0.042
earnings per share 411,737 1,245,324 1,850,377 2,717,600
Adjusted EBITDA
Adjusted EBITDA over
revenues (%) 1.9% 8.8% 3.0% 6.9%

/T/

The Corporation’s ratio of selling, operating and administrative expenses
(“SG&A”) as a whole over revenues amounted to 22.6% for this quarter, down from
23.4% for the corresponding quarter of the previous fiscal year. This decrease
is mostly attributable to the acquisition of Utility Partners in July 2016
which increased the overall revenues without impacting proportionally the
selling and operating expenses.

Adjusted EBITDA for the quarter was recorded at $411,737, compared with
$1,245,324 for the same period ended March 31, 2016. The adjusted EBITDA over
revenues represents 1.9%, compared to 8.8% for the same quarter in fiscal year
2016. The decrease in the adjusted EBITDA over revenues ratio is essentially
due to the lower volume coming from revenues of water treatment projects.
Moreover, the shift in product mix and the addition of Utility Partners results
impacted negatively the overall gross margin, decreasing the adjusted EBITDA.
Once the volume of revenues will increase, the Corporation expects this
percentage to increase accordingly since all the fixed charges are already
covered.

The net loss amounted to ($1,345,695) or ($0.034) per share for the third
quarter of fiscal year 2017 compared with net earnings of $646,422 or $0.031
per share for the third quarter of fiscal year 2016. The net loss is largely
due to the acquisition of Utility Partners and the related acquisition and
integration costs and to a higher level of SG&A expenses, aimed to support the
constant growth of the Corporation.

Operating activities used ($1,135,127) in cash for the three-month period ended
March 31, 2017, compared with ($318,078) of cash used during the corresponding
period ended March 31, 2016. The increase is mostly due to the net loss before
income taxes generated during this quarter, to the addition of Utility
Partners, and the increase in non-cash items.

Reconciliation of adjusted EBITDA to net (loss) earnings

Even though adjusted EBITDA is a non-IFRS measure, it is used by management to
make operational and strategic decisions. Providing this information to the
stakeholders, in addition to the GAAP measures, allows them to see the
Corporation’s results through the eyes of management, and to better understand
the financial performance, notwithstanding the impact of GAAP measures.

/T/

Three-month periods Nine-month periods
ended March 31, ended March 31,
2017 2016 2017 2016
————————————————
$ $ $ $
Net (loss) earnings for the
period (1,345,695) 646,422 (3,521,051) 872,972
Finance costs – net 328,485 233,260 984,780 597,514
Income taxes (189,262) 205,077 (580,855) 417,930
Depreciation of property,
plant and equipment 191,850 175,192 548,314 447,178
Amortization of intangible
assets 1,272,620 276,852 2,774,142 744,957
Gain on purchase price
adjustment – – – (375,977)
Unrealized exchange loss (59,586) (292,260) 118,282 (35,173)
Acquisition and integration
costs 45,867 781 1,066,696 48,199
Stock-based compensation
costs 167,458 – 460,069 –
————————————————
Adjusted EBITDA 411,737 1,245,324 1,850,377 2,717,600
————————————————
————————————————

/T/

H2O Innovation Conference Call

Frederic Dugre, President and Chief Executive Officer and Marc Blanchet, Chief
Financial Officer, will hold an investor conference call to discuss the
financial results for 2017 third quarter in further details at 10:00 a.m. (EDT)
on Monday, May 15, 2017.

To access the call, please call (877) 223-4471 or (647) 788-4922, five to ten
minutes prior to the start time. Presentation slides for the conference call
will be made available on the Corporate Presentations page of the Investors
section of the Corporation’s website.

The third quarter financial report is available on www.h2oinnovation.com and on
SEDAR (www.sedar.com).

Prospective disclosures

Certain statements set forth in this press release regarding the operations and
the activities of H2O Innovation as well as other communications by the
Corporation to the public that describe more generally management objectives,
projections, estimates, expectations or forecasts may constitute
forward-looking statements within the meaning of securities legislation.
Forward-looking statements concern analysis and other information based on
forecast future results, performance and achievements and the estimate of
amounts that cannot yet be determined. Forward-looking statements include the
use of words such as “anticipate”, “if”, “believe”, “continue”, “could”,
“estimate”, “expect”, “intend”, “may”, “plan”, “potential”, “predict”,
“project”, “should” or “will”, and other similar expressions, as well as those
usually used in the future and the conditional, notably regarding certain
assumptions as to the success of a venture. Those forward-looking statements,
based on the current expectations of management, involve a number of risks and
uncertainties, known and unknown, which may result in actual and future
results, performance and achievements of the Corporation to be materially
different than those indicated. Information about the risk factors to which the
Corporation is exposed is provided in the Annual Information Form dated
September 26, 2016 available on SEDAR (www.sedar.com). Unless required to do so
pursuant to applicable securities legislation, H2O Innovation assumes no
obligation to update or revise forward-looking statements contained in this
press release or in other communications as a result of new information, future
events and other changes.

About H2O Innovation

H2O Innovation designs and provides state-of-the-art, custom-built and
integrated water treatment solutions based on membrane filtration technology
for municipal, industrial, energy and natural resources end-users. The
Corporation’s activities rely on three pillars which are i) water and
wastewater projects; ii) specialty products and services, including a complete
line of specialty chemicals, consumables, specialized products for the water
treatment industry as well as control and monitoring systems; and iii)
operation and maintenance services for water and wastewater treatment systems
For more information, visit www.h2oinnovation.com.

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

– END RELEASE – 15/05/2017

For further information:
Source:
H2O Innovation Inc.
www.h2oinnovation.com
OR
Contact:
Marc Blanchet
+1 418-688-0170
marc.blanchet@h2oinnovation.com

COMPANY:
FOR: H2O INNOVATION INC.
TSX VENTURE SYMBOL: HEO
EURONEXT PARIS SYMBOL: ALHEO
OTCQX SYMBOL: HEOFF

INDUSTRY: Environment – Air Pollution Control
RELEASE ID: 20170515CC0014

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.

FOR: CEIBA ENERGY SERVICES INC.
TSX VENTURE SYMBOL: CEB

AND SECURE ENERGY SERVICES INC.
TSX SYMBOL: SES

Date issue: May 15, 2017
Time in: 8:00 AM e

Attention:

CALGARY, ALBERTA–(Marketwired – May 15, 2017) – SECURE Energy Services Inc.
(“SECURE”) (TSX:SES) and Ceiba Energy Services Inc. (“Ceiba”) (TSX VENTURE:CEB)
are pleased to announce that they have entered into an arrangement agreement
dated May 14, 2017 (the “Arrangement Agreement”) pursuant to which SECURE has
agreed to acquire all of the issued and outstanding common shares of Ceiba (the
“Ceiba Shares”), a service provider of stand-alone water disposal and oil
treating facilities in the Canadian energy sector (the “Transaction”).

Under the terms of the Arrangement Agreement, SECURE will pay approximately $26
million for all of the issued and outstanding Ceiba Shares. Ceiba shareholders
will receive $0.205 for each share, to be paid in cash or by the issuance of
0.02115 of a SECURE common share, at their election, provided that a maximum of
approximately 1.3 million SECURE common shares will be issued (representing
approximately 50% of the consideration to be paid to Ceiba shareholders). The
exchange ratio reflects a SECURE share price of $9.6912, being SECURE’s
trailing 3-trading day volume weighted average trading price on the Toronto
Stock Exchange. The $0.205 per share consideration represents a 64% premium
over the closing price of Ceiba Shares on the TSX Venture Exchange on May 12,
2017. The aggregate Transaction value is approximately $37 million, which
includes the assumption of approximately $11 million in Ceiba debt.

As part of the Transaction, SECURE will acquire approximately $1 million of net
working capital excluding debt and approximately $30 million of fixed assets
consisting of tanks, pumps, pipelines, treaters, disposal wells and various
other equipment.

“Adding Ceiba’s stand-alone water disposal and oil treating facilities to
SECURE’s expansive network of facilities provides our customers with more
options for their water, waste and oil handling needs,” said Rene Amirault,
SECURE’s Chairman and Chief Executive Officer. “This Transaction will add 10
new locations to our existing footprint of 39 facilities in the Western
Canadian Sedimentary Basin. There are numerous opportunities at the Ceiba
facilities to optimize and expand existing services and throughput, thereby
enhancing customer value.”

Ronald Sifton, Interim CEO of Ceiba, stated, “We are very pleased with this
outcome of our strategic process review. The Transaction provides our
shareholders the opportunity to participate in the future potential of a well
capitalized leading North American energy services company which has a track
record of successful project execution and corporate growth. The combined
entity is much better positioned to deploy capital and realize significant
operating synergies to maximize the value of Ceiba’s operating assets.”

TRANSACTION RATIONALE

/T/

— Expands SECURE’s PRD network: The Transaction adds 10 facilities that

fit within, and add capacity to, SECURE’s PRD network which provides
multiple services for processing, recovery, treatment, and disposal of
oil and gas by-products. The additional facilities will provide
customers with more options to reduce their overall transportation for
custom treating of crude oil, crude oil marketing, produced and waste
water disposal and oilfield waste processing;

— Accelerates growth and expansion opportunities: SECURE obtains immediate

access to areas of interest, including the opportunity to add
incremental capital to enhance throughput and service capabilities;

— Significant operational and administration synergies: SECURE will absorb

and optimize the Ceiba facilities into its existing PRD network, sharing
resources related to senior management, sales and general and
administration;

— Utilization of Non-Capital Losses: SECURE anticipates being able to

utilize Ceiba’s existing non-capital loss tax pools in existing PRD
operations. Ceiba has approximately $49 million in total tax pools
including approximately $27 million in non-capital losses; and

— After the consideration of operational and administrative synergies, and

including an initial capital injection of $5.0 to $6.0 million, SECURE
expects the contribution to consolidated adjusted EBITDA from the Ceiba
acquisition to be approximately $7.0 to $8.0 million on an annualized
basis.

/T/

DETAILS OF THE TRANSACTION

The SECURE Board has unanimously approved the Transaction. The board of
directors of Ceiba (the “Ceiba Board”) has unanimously approved the Transaction
and recommends that holders of Ceiba Shares vote in favour of the special
resolution approving the Transaction. Peters & Co. Limited is acting as
financial advisor to Ceiba in respect of the Transaction and has provided the
Ceiba Board with its verbal opinion that, subject to the assumptions,
qualifications and limitations contained therein, the consideration to be
received by holders of Ceiba Shares pursuant to the terms of the Arrangement
Agreement is fair, from a financial point of view, to the holders of Ceiba
Shares.

Securityholders holding approximately 40% of the combined outstanding shares
and warrants of Ceiba have signed lock up agreements in support of the
Arrangement.

Under the terms of the Arrangement Agreement, the Transaction will be effected
by way of a plan of arrangement of Ceiba under the Business Corporations Act
(Alberta). The SECURE shares to be issued on the exchange of Ceiba Shares
pursuant to the Arrangement Agreement will be available to Ceiba shareholders
on a tax deferred basis for Canadian tax purposes. The Transaction will require
approval by at least 66 2/3 percent of holders of the Ceiba Shares and Ceiba
warrants, voting together as a single class, at a special meeting to be called
to consider the Transaction. The Transaction is expected to be completed in the
third quarter of 2017 and is subject to TSX, TSX Venture Exchange and Alberta
Court of Queen’s Bench approval, regulatory approvals and the satisfaction of
other customary closing conditions. The Transaction is an arm’s length
transaction for the purposes of the policies of the TSX Venture Exchange.

The Arrangement Agreement contains customary terms and conditions for a
transaction of this nature, including a prohibition upon Ceiba from soliciting
or initiating any discussion concerning any other business combination or
similar transaction, subject to compliance with fiduciary duties, the right of
SECURE to match any unsolicited superior proposal received by Ceiba, and a
termination fee of $1.0 million payable to SECURE in certain circumstances.

ABOUT SECURE ENERGY SERVICES INC.

SECURE is a TSX publicly traded energy services company that provides safe,
innovative, efficient and environmentally responsible fluids and solids
solutions to the oil and gas industry. The Corporation owns and operates
midstream infrastructure and provides environmental services and innovative
products to upstream oil and natural gas companies operating in western Canada
and certain regions in the United States (“U.S.”).

The Corporation operates three divisions:

Processing, Recovery and Disposal Division (“PRD”): The PRD division owns and
operates midstream infrastructure that provides processing, storing, shipping
and marketing of crude oil, oilfield waste disposal and recycling. More
specifically these services are clean oil terminalling and rail transloading,
custom treating of crude oil, crude oil marketing, produced and waste water
disposal, oilfield waste processing, landfill disposal, and oil purchase/resale
service. SECURE currently operates a network of facilities throughout Western
Canada and in North Dakota, providing these services at its full service
terminals (“FST”), landfills, stand-alone water disposal facilities (“SWD”) and
full service rail facilities (“FSR”).

Drilling and Production Services Division (“DPS”): The DPS division provides
equipment and product solutions for drilling, completion and production
operations for oil and gas producers in Western Canada. The drilling service
line comprises the majority of the revenue for the division which includes the
design and implementation of drilling fluid systems for producers drilling for
oil, bitumen and natural gas. The drilling service line focuses on providing
products and systems that are designed for more complex wells, such as medium
to deep wells, horizontal wells and horizontal wells drilled into the oil
sands. The production services line focuses on providing equipment and chemical
solutions that optimize production, provide flow assurance and maintain the
integrity of production assets.

Onsite Services Division (“OS”): The operations of the OS division include
Projects which include pipeline integrity (inspection, excavation, repair,
replacement and rehabilitation), demolition and decommissioning, and
reclamation and remediation of former wellsites, facilities, commercial and
industrial properties, and environmental construction projects (landfills,
containment ponds, subsurface containment walls, etc.); Environmental services
which provide pre-drilling assessment planning, drilling waste management,
remediation and reclamation assessment services, Naturally Occurring
Radioactive Material (“NORM”) management, waste container services, and
emergency response services; and Integrated Fluid Solutions (“IFS”) which
include water management, recycling, pumping and storage solutions.

ABOUT CEIBA ENERGY SERVICES INC.

Ceiba provides specialized services to the energy sector, specifically to
companies involved in the exploration, extraction and production of oil and
natural gas in Western Canada. Ceiba develops and constructs facilities in
proximity to its customers to provide treatment of crude oil emulsion,
terminalling, storage and marketing of oil and disposal of production water.

FORWARD-LOOKING STATEMENTS

Certain statements contained in this new release constitute “forward-looking
statements” and/or “forward-looking information” within the meaning of
applicable securities laws (collectively referred to as forward-looking
statements). When used in this document, the words “may”, “would”, “could”,
“will”, “intend”, “plan”, “anticipate”, “believe”, “estimate”, “expect”, and
similar expressions, as they relate to SECURE, or its management, are intended
to identify forward-looking statements. Such statements reflect the current
views of SECURE with respect to future events and operating performance and
speak only as of the date of this document. In particular, this document
contains or implies forward-looking statements pertaining to: anticipated
benefits of the Transaction, expected synergies with SECURE’s business,
services expansion and optimization, EBITDA contribution from the Transaction
and anticipated Transaction timing.

Forward-looking statements concerning expected operating and economic
conditions are based upon prior year results as well as the assumption that
levels of market activity and growth will be consistent with industry activity
in Canada and the U.S. and similar phases of previous economic cycles.
Forward-looking statements concerning the relative future competitive position
of the Corporation are based upon the assumption that economic and operating
conditions, including commodity prices, crude oil and natural gas storage
levels, interest and foreign exchange rates, the regulatory framework regarding
oil and natural gas royalties, environmental regulatory matters, the ability of
the Corporation and its subsidiaries to successfully market their services and
drilling and production activity in North America will lead to sufficient
demand for the Corporation’s services and its subsidiaries’ services including
demand for oilfield services for drilling and completion of oil and natural gas
wells, that the current business environment will remain substantially
unchanged, and that present and anticipated programs and expansion plans of
other organizations operating in the energy industry may change the demand for
the Corporation’s services and its subsidiaries’ services. Forward-looking
statements concerning the nature and timing of growth are based on past factors
affecting the growth of the Corporation, past sources of growth and
expectations relating to future economic and operating conditions.

Forward-looking statements involve significant risks and uncertainties, should
not be read as guarantees of future performance or results, and will not
necessarily be accurate indications of whether such results will be achieved.
Readers are cautioned not to place undue reliance on these statements as a
number of factors could cause actual results to differ materially from the
results discussed in these forward-looking statements, including but not
limited to those factors referred to and under the heading “Business Risks” in
SECURE’s latest Management’s Discussion and Analysis and under the heading
“Risk Factors” in the Corporation’s Annual Information Form (for the year ended
December 31, 2016 and also includes the risks associated with the possible
failure to realize the anticipated synergies in integrating the assets acquired
in the Acquisition with the operations of SECURE. Although forward-looking
statements contained in this document are based upon what the Corporation
believes are reasonable assumptions, the Corporation cannot assure investors
that actual results will be consistent with these forward-looking statements.
The forward-looking statements in this document are expressly qualified by this
cautionary statement. Unless otherwise required by law, SECURE does not intend,
or assume any obligation, to update these forward-looking statements.

NON-GAAP MEASURES, OPERATIONAL DEFINITIONS AND ADDITIONAL SUBTOTALS

The Corporation uses accounting principles that are generally accepted in
Canada (the issuer’s “GAAP”), which includes International Financial Reporting
Standards (“IFRS”). Certain supplementary measures in this document do not have
any standardized meaning as prescribed by IFRS, including the non-GAAP measure
adjusted EBITDA. These non-GAAP measures, operational definitions and
additional subtotals used by the Corporation may not be comparable to similar
measures presented by other reporting issuers. These non-GAAP financial
measures, operational definitions and additional subtotals are included because
management uses the information to analyze operating performance, leverage and
liquidity. Therefore, these non-GAAP financial measures, operational
definitions and additional subtotals should not be considered in isolation or
as a substitute for measures of performance prepared in accordance with GAAP.
See the management’s discussion and analysis available at www.sedar.com for a
reconciliation of the Non-GAAP financial measures, operational definitions and
additional subtotals.

– END RELEASE – 15/05/2017

For further information:
SECURE Energy Services Inc.
Rene Amirault
Chairman, President and Chief Executive Officer
(403) 984-6100
(403) 984-6101 (FAX)
OR
SECURE Energy Services Inc.
Allen Gransch
Executive Vice President and Chief Financial Officer
(403) 984-6100
(403) 984-6101 (FAX)
www.secure-energy.com
OR
Ceiba Energy Services Inc.
Ronald Sifton
Interim Chief Executive Officer
403-850-9080
www.ceibaenergy.com

COMPANY:
FOR: CEIBA ENERGY SERVICES INC.
TSX VENTURE SYMBOL: CEB

AND SECURE ENERGY SERVICES INC.
TSX SYMBOL: SES

INDUSTRY: Energy and Utilities – Oil and Gas
RELEASE ID: 20170515CC0018

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.

FOR: SAN ANGELO OIL LIMITEDNEX BOARD SYMBOL: SAO.HTSX VENTURE SYMBOL: SAO.HDate issue: May 15, 2017Time in: 7:30 AM eAttention:
VANCOUVER, BRITISH COLUMBIA–(Marketwired – May 15, 2017) –
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