Day: March 23, 2017

FOR: ITHACA ENERGY INCTSX SYMBOL: IAELSE SYMBOL: IAEDate issue: March 24, 2017Time in: 3:00 AM eAttention:
ABERDEEN, SCOTLAND–(Marketwired – March 24, 2017) – Ithaca Energy Inc (TSX:
IAE) (LSE: IAE)
(TSX: IAE; LSE: IAE)
THIS ANNOUNCEMENT CONTAINS INSI…

FOR: WESTERN ENERGY SERVICES CORP.TSX SYMBOL: WRGDate issue: March 23, 2017Time in: 10:30 PM eAttention:
CALGARY, ALBERTA–(Marketwired – March 23, 2017) –
NOT FOR DISTRIBUTION TO UNITED STATES NEWSWIRE SERVICES OR FOR DISSEMINATION IN
THE UNITED STATE…

FOR: CHINOOK ENERGY INC.
TSX SYMBOL: CKE

Date issue: March 23, 2017
Time in: 10:21 PM e

Attention:

CALGARY, ALBERTA–(Marketwired – March 23, 2017) – Chinook Energy Inc. (“our”,
“we”, or “us”) (TSX:CKE) is pleased to announce its fourth quarter 2016
financial and operating results and provide an operations update, including in
respect of its most recent three well Birley/Umbach drilling program.

Our operational and financial highlights for the three months and year ended
December 31, 2016 are noted below and should be read in conjunction with our
consolidated financial statements for the years ended December 31, 2016 and
2015 and our related management’s discussion and analysis which have been
posted on the SEDAR website (www.sedar.com) and our website
(www.chinookenergyinc.com).

Fourth Quarter 2016 Financial and Operating Highlights

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Three months ended Year ended
December 31 December 31
—————————————————————————-
2016 2015 2016 2015
—————————————————————————-
OPERATIONS
—————————————————————————-
Production Volumes
—————————————————————————-
Crude oil (bbl/d) 451 922 768 1,187
Natural gas liquids (boe/d) 613 364 637 510
Natural gas (mcf/d) 21,548 15,851 24,631 23,642
—————————————————————————-
Average daily production (boe/d) 4,655 3,928 5,510 5,637
—————————————————————————-
Sales Prices
—————————————————————————-
Average oil price ($/bbl) $ 71.98 $ 47.93 $ 52.01 $ 53.08
Average natural gas liquids
price ($/boe) $ 40.70 $ 30.59 $ 26.35 $ 35.83
Average natural gas price
($/mcf) $ 3.31 $ 2.09 $ 2.06 $ 2.50
—————————————————————————-
Netback (1)
—————————————————————————-
Average commodity pricing
($/boe) $ 27.67 $ 22.51 $ 19.51 $ 24.89
Royalties ($/boe) $ (2.84) $ 2.39 $ (1.19) $ (0.73)
Net production expenses ($/boe)
(1) $ (11.88) $ (14.17) $ (13.61) $ (15.92)
G&A expense ($/boe) $ (5.80) $ (8.31) $ (4.58) $ (4.76)
—————————————————————————-
Netback ($/boe) (1) $ 7.15 $ 2.42 $ 0.13 $ 3.48
—————————————————————————-
Wells Drilled (net)
—————————————————————————-
Total natural gas wells drilled
(net) 2.63 – 2.63 2.75
—————————————————————————-

Three months ended Year ended
December 31 December 31
—————————————————————————-
2016 2015 2016 2015
—————————————————————————-
FINANCIAL ($ thousands, except
per share amounts)
—————————————————————————-
Petroleum & natural gas
revenues, net of royalties $ 10,631 $ 9,000 $ 36,943 $ 49,701
Funds (outflow) from operations
(1) $ 1,713 $ 1,516 $ (1,004) $ 9,033
Per share – basic and diluted
($/share) $ 0.01 $ 0.01 $ (0.00) $ 0.04
Net income (loss) $ 6,427 $ (5,303) $ (54,773) $ (83,606)
Per share – basic and diluted
($/share) $ 0.03 $ (0.02) $ (0.25) $ (0.39)
Capital expenditures $ 4,177 $ 9,998 $ 9,211 $ 44,325
Net surplus (1) $ (15,138) $ (29,614) $ (15,138) $ (29,614)
Total assets $ 139,975 $ 321,564 $ 139,975 $ 321,564
—————————————————————————-
Common Shares (thousands)
—————————————————————————-
Weighted average during period
– basic 216,443 215,337 215,860 215,197
– diluted 216,621 215,337 215,860 215,197
Outstanding at period end 216,443 215,349 216,443 215,349
—————————————————————————-

(1) Funds (outflow) from operations, Funds (outflow) from operations per

share, net debt (surplus), netback, and net production expense are non-
GAAP measures. These terms do not have any standardized meanings as
prescribed by IFRS and, therefore, may not be comparable with the
calculations of similar measures presented by other companies. See
headings entitled “Funds (outflow) from Operations”, “Net Debt
(Surplus)”, “Netback” and “Net Production Expense” in the Reader
Advisory below for further information on such terms.

/T/

2016 Highlights (Exclusive of assets disposed to Craft Oil Ltd.)

/T/

— Through several strategic transactions, we completed our transformation

to a well-financed company focussing on our large contiguous Montney
liquids-rich natural gas position at Birley/Umbach in northeast British
Columbia.
— Our total proved (“1P”) reserves, net of acquisition & divestiture
increased by 33% from 2015 to 2016 with record low finding and
development (“F&D”) costs of $6.65/Boe (1P additions replaced 330% of
production).
— Our total proved plus probable (“2P”) reserves, net of acquisition &
divestiture increased by 45% from 2015 to 2016 with record low F&D costs
of $4.76/Boe (2P additions replaced 660% of production).
— The net present value (NPV 10%) of our 1P reserves was $65.8 million at
the end of 2016, an increase of 216% compared to 2015.
— The net present value (NPV 10%) of our 2P reserves was $127.7 million at
the end of 2016, an increase of 178% compared to 2015.
— Reserves have been booked over only 15% of our 38,802 gross acres
(32,054 net acres) of Montney rights in the Birley/Umbach area, not
including 13,593 gross acres (11,755 net acres) of offsetting Montney
rights in the Martin Creek area.
— Our 2016 operating costs per boe related to the properties that we
currently still own (exclusive of our 2016 dispositions, including
Craft, and our 2017 disposition at Gold Creek), decreased by about 35%
to approximately $15.00/boe compared to our 2015 operating costs for
these same properties of approximately $23.00/boe.
— During the fourth quarter, we began to realize the benefits of a new gas
handling agreement which has significantly improved our go-forward
economics and reduced our operating costs by an additional $2.70/boe.
— During the fourth quarter, we drilled three wells (2.63 net) at
Birley/Umbach at an average cost of $1.28 million per well, a decrease
of 43% from our previous average cost of $2.25 million per well.
— Capital investment was $9.2 million during 2016 including $2.0 million
to complete the construction of our new 25 mmcf/d Birley/Umbach
compression facility. We ended 2016 with a strong balance sheet,
including a net surplus of $15.1 million (including cash of $16.1
million).
— During the fourth quarter, we negotiated an $8.0 million demand
revolving credit facility with a Canadian chartered bank, which was
signed during the first quarter of 2017.
— We continue to layer in commodity price hedges and diversify our natural
gas sales points with approximately 42% of forecast 2017 natural gas
production currently hedged and 20% of forecast 2017 natural gas
production sold at Alliance Chicago Pricing.

/T/

2017 Recent Operations Highlights

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— We completed, equipped and tied-in three (2.63 net) horizontal Montney

wells at Birley/Umbach at an average cost to drill and complete of $3.7
million per well, a 30% decrease from the previous six (5.0 net) wells
which averaged $5.3 million per well.
— Including production from the following new Birley wells, our current
production is approximately 5,350 boe/d.
— A-071-F/094-H-03 (0.75 net) tested at a final rate of 1,288 boe/d
(approximately 96% gas, 4% free condensate).
— C-095-F/094-H-03 (0.90 net) tested at a final rate of 1,364 boe/d
(approximately 88% gas, 12% free condensate).
— D-095-F/094-H-03 (0.98 net) tested at a final rate of 1,094 boe/d
(approximately 94% gas, 6% free condensate).
— We have commenced construction of a new drilling pad to drill four (3.67
net) wells through spring break-up and will complete all four shortly
after spring break-up.

/T/

Strategic Transactions

Craft Oil Ltd.

On June 10, 2016, we completed the conveyance of the majority of our Alberta
oil and natural gas assets, excluding our Montney assets, and the associated
decommissioning obligations in addition to $0.9 million cash (collectively, the
“Subject Assets”) to a predecessor of Craft Oil Ltd. (“Craft”), a private
Calgary-based petroleum and natural gas production company, for 70% of its
issued and outstanding common shares pursuant to an asset purchase and sale
agreement dated and effective May 1, 2016. On December 12, 2016 we completed
the distribution of all of the Craft shares held by us to our shareholders as
at the close of business pursuant to a plan of arrangement under the Business
Corporations Act (Alberta) (the “Craft Share Distribution”). Following the
Craft Share Distribution, we no longer had any ownership in Craft and, as a
result, for subsequent reporting periods, the results of Craft are no longer
required to be consolidated into our results.

2017 Non-Core Asset Dispositions

Effective January 23, 2017, we completed the sale of certain of our non-core
assets located in the Knopcik/Pipestone area of Alberta for net consideration
of approximately $7.5 million, subject to customary closing adjustments.

Effective February 1, 2017, we completed the disposition of certain of our
non-core assets located in the Gold Creek area of Alberta for net consideration
of approximately $10.5 million, subject to customary closing adjustments.

The foregoing dispositions further strengthened our company to pursue a more
aggressive drilling program on our core Birley/Umbach acreage.

2016 Financial Results

Our production in the fourth quarter of 2016 averaged 4,655 boe/d, up almost
19% from the same period in 2015. This increase is attributed to the completion
of our Birley/Umbach compressor expansion during the first quarter of 2016, in
addition to improved commodity pricing and a new gas handling agreement which
enabled us to reactivate wells in the Martin Creek and Black Conroy areas of
northeastern British Columbia, adding 1,100 boe/d of production during the
fourth quarter. These increases were partially offset by Craft’s disposition of
certain Alberta assets in October 2016 followed by our completion of the Craft
Share Distribution in December 2016, in addition to natural declines,
additional property dispositions and voluntary shut-ins. On an unconsolidated
basis (excluding results from Craft), our fourth quarter 2016 production
averaged 2,593 boe/d.

Our 2016 petroleum and natural gas revenues were down approximately 23% from
2015 primarily as a result of both decreased volumes and realized commodity
prices. However, our fourth quarter petroleum and natural gas revenues
increased almost 46% from the same period of 2015 primarily as a result of
increased natural gas and natural gas liquids volumes and increased realized
commodity prices. On an unconsolidated basis, our fourth quarter petroleum and
natural gas revenues were down approximately 41% from the same period of 2015
primarily as a result of decreased crude oil production. On an unconsolidated
basis, we had lower natural gas and natural gas liquids production during the
fourth quarter; however, these production decreases were offset by higher
commodity prices which led to an increase of approximately 11% and 23% in our
natural gas and natural gas liquids revenues, respectively, during the fourth
quarter compared to the same quarter of 2015, despite the decrease in volumes.

Our 2016 net production expense (operating costs net of processing income)
decreased by approximately 16% to $27.4 million from $32.8 million in the same
period of 2015. This decrease primarily resulted from disposing or shutting-in
high operating cost/lower netback properties during the year. On an
unconsolidated basis, our fourth quarter net production expense of $9.39/boe
benefited from the disposition of higher operating cost assets and a new gas
handling agreement which we entered into during the third quarter of 2016. For
2017 we forecast our operating costs to be approximately $10.00/boe ($9.50/boe
net of processing income.)

We have focused on improving our G&A cost structure and implementing cost
cutting initiatives. Our year over year G&A costs decreased by approximately 6%
despite including $1.6 million of Craft G&A costs. Although personnel were
transferred to Craft on conveyances of the Subject Assets, we will not report
this significant G&A cost reduction until the first quarter of 2017. During
2016, $2.4 million of our total G&A costs related to rent expense incurred on
our head office lease which expires June 30, 2019. Assuming current rental
market conditions remain the same or similar, we expect a favourable rent
adjustment commencing in 2019 upon our lease expiration, based on our
anticipated office space requirements.

Our fourth quarter funds from operations were $1.7 million an increase of
approximately 13% compared to the same quarter of 2015 as a result of increases
in our production volumes and corporate netbacks. On an unconsolidated basis,
our fourth quarter funds from operations were $0.2 million. For the year ended
2016, we reported an outflow from operations of $1.0 million compared to funds
from operations of $9.0 million during the year ended 2015 as a result of lower
production volumes and corporate netbacks. Our lower corporate netback was
primarily due to lower realized commodity pricing.

We reported a net loss for the year ended 2016 of $54.8 million compared to a
loss of $83.6 million for the year ended 2015. During 2016, we reported a lower
impairment charge of $58.1 million related to development and production assets
held by Craft, as well as a recovery of prior period impairments of $17.0
million related to our remaining assets at December 31, 2016, compared to an
impairment charge of $75.0 million during the year ended 2015.

Operational Results

We have transformed into a pure play Montney focused company. Completing the
foregoing non-core asset dispositions at Gold Creek and Knopcik/Pipestone
during the first quarter of 2017 raised capital which we are actively deploying
to develop and expand our Birley/Umbach property.

During mid-February 2016, we brought on-stream three (2.75 net) additional
wells at Birley/Umbach upon the commissioning of our new compression facility.
During the fourth quarter of 2016, we successfully completed a three well (2.63
net) drilling program at Birley/Umbach which was on schedule and under budget
by approximately 26%, with average drilling costs of approximately $1.28
million per well ($1.12 million, net).

During the first quarter of 2017, we completed and tied-in the three wells (the
a-71-F, d-95-F and c-95-F wells) drilled during the fourth quarter of 2016. The
gross test results for the three wells, as compared to gross test rates for all
our Birley/Umbach wells drilled to date, are as follows:

/T/

24 Hour Test
Working Lateral Frac’d Rate End
Interest Length Stages Flow Time Date
Well (%) (metres) (gross) (hours) (MM/DD/YYYY)
—————————————————————————-
A-060-K/094-H-03 74.55 1,220 18 154 3/9/2014
B-071-F/094-H-03 74.55 1,553 23 211 10/4/2014
A-073-L/094-H-03 74.55 1,230 18 252 2/16/2015
C-073-K/094-H-03 100.00 1,210 18 145 9/23/2015
B-072-F/094-H-03 74.55 1,225 18 69 9/24/2015
B-004-K/094-H-03 100.00 1,200 16 119 9/24/2015
—————————————————————————-
A-071-F/094-H-03 74.55 1,517 24 113 2/8/2017
D-095-F/094-H-03 98.38 1,509 24 197 2/14/2017
C-095-F/094-H-03 90.38 1,498 24 98 2/15/2017
—————————————————————————-

Final 24 Final 24
Hour Hour
Average Average
Test Total Test Total
Gas Rates FCGR (1) IP30 IP60
Well (mcf/d) (bbl/mmcf) (mcf/d) (mcf/d) IP90 (mcf/d)
—————————————————————————-
A-060-K/094-H-03 5,276 54 3,726 3,754 3,923
B-071-F/094-H-03 8,870 6 4,489 4,375 4,348
A-073-L/094-H-03 3,827 23 3,712 3,417 3,459
C-073-K/094-H-03 5,281 49 4,228 4,094 3,851
B-072-F/094-H-03 3,908 30 3,991 4,104 4,227
B-004-K/094-H-03 4,127 17 3,364 3,082 2,921
—————————————————————————-
A-071-F/094-H-03 7,319 8 N/A N/A N/A
D-095-F/094-H-03 6,756 11 N/A N/A N/A
C-095-F/094-H-03 8,202 25 N/A N/A N/A
—————————————————————————-

(1) Free condensate gas ratio.

/T/

The a-71-F well has been on production for 8 days and is currently producing at
a restricted gross rate of 3.9 mmcf/d and 77 bbls of free condensate per day
(gross – 724 boe/d; net – 540 boe/d). The d-95-F well has been on production
for 8 days and is currently producing at a restricted gross rate of 3.7 mmcf/d
and 154 bbls of free condensate per day (gross – 774 boe/d; net – 761 boe/d).
The c-95-F well has been on production for 4 days and is currently producing at
a restricted gross rate of 3.5 mmcf/d and 111 bbls of free condensate per day
(gross – 690 boe/d; net – 624 boe/d).

Our future growth potential at Birley/Umbach is significant with 52,395 acres
(43,809 net) of Montney rights with an upper Montney drilling inventory of over
270 (227 net) management identified locations along with additional potential
to reduce inter-well spacing in the upper Montney (from four to five or six
horizontal wells per section) and also develop middle and lower Montney layers
throughout a 250 meter thick Montney interval.

Hedging

We use commodity price hedges to support our capital investment and growth by
providing more certainty regarding our funds flow and balance sheet management.
Our internal policy permits us to hedge up to a maximum period of 24 months,
based on our total estimated oil and natural gas production volumes, consisting
of no more than 50% for the first 12 months and 25% for the last 12 months. Our
current hedges in place are as follows:

/T/

Indexed Price Notional Volumes Company’s Received Price Contractual Term
—————————————————————————-
AECO 7,500 GJ/d $3.205/GJ January 1, 2017 to
December 31, 2017
AECO 4,000 GJ/d $2.50/GJ April 1, 2017 to
October 31, 2017
—————————————————————————-

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Outlook

On January 23, 2017, we announced a $40 million capital program for 2017 which
included the expansion of our facility at Birley/Umbach to 50 mmcf/d and the
drilling of six (4.5 net) wells which were anticipated to be 1,600 meters in
length with frac spacing of 60 to 65 meters. We are optimizing our drilling and
completion program which has been revised to now include the drilling of four
(3.67 net) wells, two (2.0 net) of which will have lateral sections of 1,600
meters in length and two (1.67 net) will have 1,800 meter length laterals. All
four wells will have tighter frac spacing of approximately 52 meters from the
original 60 to 65 meters. The additional length of two of the wells is
anticipated to add to the recoverability of hydrocarbons while increased frac
density is anticipated to result in increased initial well rates. This change
in our drilling program will result in 10% more net frac stages despite
resulting in 0.83 fewer net wells. As a result of the longer length of two of
the wells and the decreased frac spacing, the amount of our capital program
will be maintained at $40 million. We are also marginally increasing our
previously announced average and ending production for 2017 and marginally
decreasing our working capital surplus at December 31, 2017 as follows:

/T/

Original 2017 Revised 2017
($ millions, except boe/d) Guidance (1) Guidance(2)
—————————————————————————-
Average production (boe/d) 4,070 – 4,170 4,200 – 4,300
Exit production (boe/d) 6,000 – 6,150 6,300 – 6,500
Capital expenditures $ 40 $ 40
Net surplus as at December 31, 2017 $ 3 $ 2
—————————————————————————-

(1) Original 2017 guidance assumptions: AECO natural gas price $2.93/mmbtu,

Station 2 natural gas price $2.26/mmbtu and Chicago Alliance natural gas
price $3.20/mmbtu.
(2) Revised 2017 guidance assumptions: AECO natural gas price $2.64/mmbtu,
Station 2 natural gas price $2.11/mmbtu and Chicago Alliance natural gas
price $2.92/mmbtu.

Original 2017 Guidance Revised 2017 Guidance
Gross Net Gross Net
—————————————————————————-
Drilling program (wells) 6 4.5 4 3.67
Frac stages for drilling
program 144 107.4 130 118.4
—————————————————————————-

/T/

About Chinook Energy Inc.

Chinook is a Calgary-based public oil and natural gas exploration and
development company which is focused on realizing per share growth from its
large contiguous Montney liquids-rich natural gas position at Birley/Umbach,
British Columbia.

Reader Advisory

Abbreviations

/T/

Oil and Natural Gas Liquids Natural Gas
——————————— ——————————————

bbl barrel mmcf/d million cubic feet per day
bbls barrels GJ gigajoules
bbls/d barrels per day GJ/d gigajoules per day
mcf thousand cubic feet mmbtu million British Thermal Units
mmcf million cubic feet

Other
——

boe barrel of oil equivalent on the basis of 6 mcf/1 boe for natural gas
and 1 bbl/1 boe for crude oil and natural gas liquids (this
conversion factor is an industry accepted norm and is not based on
either energy content or current prices)
boe/d barrel of oil equivalent per day

/T/

Forward-Looking Statements

In the interest of providing our shareholders and readers with information
regarding our company, including management’s assessment of our future plans
and operations, certain statements contained in this news release constitute
forward-looking statements or information (collectively “forward-looking
statements”) within the meaning of applicable securities legislation.
Forward-looking statements are typically identified by words such as
“anticipate”, “continue”, “estimate”, “expect”, “forecast”, “may”, “will”,
“project”, “could”, “plan”, “intend”, “should”, “believe”, “outlook”,
“potential”, “target” and similar words suggesting future events or future
performance. In particular, this news release contains, without limitation,
forward-looking statements pertaining to: our expectation that the new gas
handling agreement will significantly improve our go-forward drilling economics
and reduce our operating costs, future G&A cost reductions and the realization
thereof, our expected future production costs, our plans and operations
including our intention to concentrate on our Montney assets, the amount and
composition of our 2017 capital program, future exploration and development
activities and the timing thereof and how we intend to manage our company as
well our revised guidance regarding average and ending production for 2017,
capital expenditures for 2017 and working capital surplus at December 31, 2017
set forth under the heading “Outlook”.

With respect to the forward-looking statements contained in this news release,
we have made assumptions regarding, among other things: that we will continue
to conduct our operations in a manner consistent with that expressed herein,
future capital expenditure levels, future oil and natural gas prices, future
oil and natural gas production levels, future currency, exchange and interest
rates, our ability to obtain equipment in a timely manner to carry out
exploration and development activities, the ability of the operator of the
projects in which we have an interest in to operate in the field in a safe,
efficient and effective manner, the impact of increasing competition, field
production rates and decline rates, anticipated production volumes, our ability
to replace and expand production and reserves through exploration and
development activities, certain cost assumptions, that the budgeted 2017
capital program, which is subject to the discretion of our Board of Directors,
will not be amended in the future, and the continued availability of adequate
debt and cash flow to fund our planned expenditures. Although we believe that
the expectations reflected in the forward-looking statements contained in this
news release, and the assumptions on which such forward-looking statements are
made, are reasonable, there can be no assurance that such expectations will
prove to be correct. Readers are cautioned not to place undue reliance on
forward-looking statements included in this news release, as there can be no
assurance that the plans, intentions or expectations upon which the
forward-looking statements are based will occur.

By their nature, forward-looking statements involve numerous assumptions, known
and unknown risks and uncertainties that contribute to the possibility that
predictions, forecasts, projections and other forward-looking statements will
not occur, which may cause our actual performance and financial results in
future periods to differ materially from any estimates or projections of future
performance or results expressed or implied by such forward-looking statements.
These risks and uncertainties include, without limitation, risks associated
with oil and gas exploration, development, exploitation, production, marketing
and transportation, loss of markets, volatility of commodity prices and
currency fluctuations, our Board of Directors may amend the 2017 capital
program based on its discretion; environmental risks, competition from other
producers, inability to retain drilling rigs and other services, unanticipated
increases in or unforeseen capital expenditure costs, including drilling,
completion and facilities costs, unexpected decline rates in wells, delays in
projects and/or operations resulting from surface conditions, wells not
performing as expected, delays resulting from or inability to obtain the
required regulatory approvals and inability to access sufficient capital from
internal and external sources. As a consequence, actual results may differ
materially from those anticipated in the forward-looking statements. Readers
are cautioned that the forgoing list of factors is not exhaustive. Additional
information on these and other factors that could affect our operations and
financial results are included in reports on file with Canadian securities
regulatory authorities and may be accessed through the SEDAR website
(www.sedar.com) and at our website (www.chinookenergyinc.com). Furthermore, the
forward-looking statements contained in this news release are made as at the
date of this news release and we do not undertake any obligation to update
publicly or to revise any of the forward-looking statements, whether as a
result of new information, future events or otherwise, except as may be
required by applicable securities laws.

Netback

The reader is cautioned that this news release contains the term netback, which
is not a recognized measure under IFRS and is calculated as a period’s sales of
petroleum and natural gas, net of royalties less net production and operating
expenses and G&A expense as divided by the period’s sales volumes. We use this
measure to assist us in understanding our profitability relative to current
commodity prices and it provides an analytical tool to benchmark changes in
operational performance against prior periods. Readers are cautioned, however,
that this measure should not be construed as an alternative to other terms such
as net income determined in accordance with IFRS as a measure of performance.
Our method of calculating this measure may differ from other companies, and
accordingly, it may not be comparable to measures used by other companies. We
include G&A expense in our Netback calculation as it represents the
administrative component of developing the associated production.

Net Production Expense

The reader is cautioned that this news release contains the term net production
expense, which is not a recognized measure under IFRS and is calculated as
production and operating expense less processing and gathering income. We use
net production expense to determine the current periods’ cash cost of operating
expenses and net production and operating expense per boe is used to measure
operating efficiency on a comparative basis. Our method of calculating this
measure may differ from other companies, and accordingly, it may not be
comparable to measures used by other companies.

Funds (Outflow) from Operations

The reader is cautioned that this news release contains the term funds
(outflow) from operations, which is not a recognized measure under IFRS and is
calculated from cash flow from operations adjusted for changes in non-cash
working capital related to operations, exploration and evaluation expenses
related to operations, decommissioning obligation expenditures related to
operations and transaction costs. We believe that funds (outflow) from
operations is a key measure to assess our ability to finance capital
expenditures and when debt is drawn, debt repayments. Funds (outflow) from
operations is not intended to represent cash flow from operating activities,
net earnings or other measures of financial performance calculated in
accordance with IFRS and should not be construed as an alternative to, or more
meaningful than, cash flow from operating activities as determined in
accordance with IFRS as an indicator of our financial performance. Our method
of calculating this measure may differ from other companies, and accordingly,
it may not be comparable to measures used by other companies. We adjust
exploration and evaluation expense as we could otherwise capitalize these
expenses.

Net Debt (Surplus)

The reader is cautioned that this news release contains the term net debt
(surplus), which is not a recognized measure under IFRS and is calculated as
bank debt adjusted for current assets less current liabilities as they appear
on the balance sheets, both of which exclude mark-to-market derivative
contracts and assets and liabilities held for sale and current liabilities
excludes any current portion of debt and decommissioning obligation. We use net
debt (surplus) to assist us in understanding our liquidity at specific points
in time. We exclude the current portion of decommissioning obligation as it is
not a financial instrument and only once it has been incurred and in turn
cycled through accounts payable, accrued liabilities or a reduction in cash, do
we view it as an adjustment to our net debt (surplus). Mark-to-market
derivative contracts are excluded as they are unrealized.

Future Oriented Financial Information

This news release, in particular the information in respect of the anticipated
capital expenditures and net surplus set out in the table under the heading
“Outlook”, may contain Future Oriented Financial Information (“FOFI”) within
the meaning of applicable securities laws. The FOFI has been prepared by our
management to provide an outlook of our activities and results and may not be
appropriate for other purposes. The FOFI has been prepared based on a number of
assumptions including the assumptions discussed under the heading
“Forward-Looking Statements” and assumptions with respect to production rates
and commodity prices. The actual results of our operations and the resulting
financial results may vary from the amounts set forth herein, and such
variations may be material. Our management believes that the FOFI has been
prepared on a reasonable basis, reflecting management’s best estimates and
judgments.

Barrels of Oil Equivalent

Barrels of oil equivalent (boe) is calculated using the conversion factor of 6
mcf (thousand cubic feet) of natural gas being equivalent to one barrel of oil.
Boes may be misleading, particularly if used in isolation. A boe conversion
ratio of 6 mcf:1 bbl (barrel) is based on an energy equivalency conversion
method primarily applicable at the burner tip and does not represent a value
equivalency at the wellhead. Given that the value ratio based on the current
price of crude oil as compared to natural gas is significantly different from
the energy equivalency of 6:1, utilizing a conversion on a 6:1 basis may be
misleading as an indication of value.

Drilling Locations

This news release discloses drilling locations in three categories: (i) proved
locations; (ii) probable locations; and (iii) unbooked locations. Proved
locations and probable locations are derived from our most recent independent
reserves evaluation as prepared by McDaniel & Associates Consultants Ltd. as of
December 31, 2016 and account for drilling locations that have associated
proved and/or probable reserves, as applicable. Unbooked locations are internal
estimates based on our prospective acreage and an assumption as to the number
of wells that can be drilled per section based on industry practice and
internal review. Unbooked locations do not have attributed reserves or
resources. Of the over 270 gross (227 net) additional drilling locations
identified herein, 16 gross (14.2 net) are proved locations, 10 gross (8.5 net)
are probable locations and 244 gross (204.3 net) are unbooked locations.
Unbooked locations have been identified by management as an estimation of our
multi-year drilling activities based on evaluation of applicable geologic,
seismic, engineering, production and reserves information. There is no
certainty that we will drill all unbooked drilling locations and if drilled
there is no certainty that such locations will result in additional oil and
natural gas reserves, resources or production. The drilling locations on which
we actually drill wells will ultimately depend upon the availability of
capital, regulatory approvals, seasonal restrictions, oil and natural gas
prices, costs, actual drilling results, additional reservoir information that
is obtained and other factors. While certain of the unbooked drilling locations
have been de-risked by drilling existing wells in relative close proximity to
such unbooked drilling locations, the majority of other unbooked drilling
locations are farther away from existing wells where management has less
information about the characteristics of the reservoir and therefore there is
more uncertainty whether wells will be drilled in such locations and if drilled
there is more uncertainty that such wells will result in additional oil and gas
reserves, resources or production.

Initial Production Rates

Any reference in this news release to initial, early and/or test or
production/performance rates (including IP30, IP60 and IP90) are useful in
confirming the presence of hydrocarbons, however, such rates are not
determinative of the rates at which such wells will continue production and
decline thereafter. Additionally, such rates may also include recovered “load
oil” fluids used in well completion stimulation. While encouraging, readers are
cautioned not to place reliance on such rates in calculating our aggregate
production. The initial production or test rates may be estimated based on
other third party estimates or limited data available at this time . In all
cases in this news release initial production or test rates are not necessarily
indicative of long-term performance of the relevant well or fields or of
ultimate recovery of hydrocarbons. Well-flow test result data should be
considered to be preliminary until a pressure transient analysis and/or
well-test interpretation has been carried out.

– END RELEASE – 23/03/2017

For further information:
Chinook Energy Inc.
Walter Vrataric
President and Chief Executive Officer
(403) 261-6883
OR
Chinook Energy Inc.
Jason Dranchuk
Vice President, Finance and Chief Financial Officer
(403) 261-6883
www.chinookenergyinc.com

COMPANY:
FOR: CHINOOK ENERGY INC.
TSX SYMBOL: CKE

INDUSTRY: Energy and Utilities – Oil and Gas
RELEASE ID: 20170323CC0087

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: PENGROWTH ENERGY CORPORATIONTSX SYMBOL: PGFNYSE SYMBOL: PGHDate issue: March 23, 2017Time in: 7:10 PM eAttention:
CALGARY, ALBERTA–(Marketwired – March 23, 2017) – Pengrowth Energy Corporation
(TSX:PGF)(NYSE:PGH) today announced that it has enter…

FOR: SAVANNA ENERGY SERVICES CORP.
TSX SYMBOL: SVY

Date issue: March 23, 2017
Time in: 6:04 PM e

Attention:

CALGARY, ALBERTA–(Marketwired – March 23, 2017) – Savanna Energy Services
Corp. (“Savanna”) (TSX:SVY) today reiterates the Savanna board of directors’
(the “Savanna Board”) unanimous rejection of the offer from Total Energy
Services Inc. (“Total”) to purchase all of the Savanna Shares on the basis of
0.13 common shares of Total (“Total Shares”) and $0.20 in cash for each common
share of Savanna (“Savanna Shares”) (the “Total Offer”).

The Savanna Board on recommendation of its Special Committee, unanimously
supports the acquisition of all of the Savanna Shares by Western Energy Service
Corp. (“Western”) pursuant to its previously announced proposed plan of
arrangement (the “Western Arrangement”) on the basis of 0.85 of a common share
of Western (the “Western Shares”) and $0.21 in cash per Savanna Share.

Do not accept the inferior value for your Savanna Shares. Since announcement,
the Western Arrangement has been at a premium to the Total Offer and based on
the respective closing prices on the Toronto Stock Exchange on March 23, 2017,
the Western Arrangement was at a 10.6% premium to the Total Offer. The Western
Arrangement currently provides Savanna shareholders with $2.12 in consideration
while the Total Offer provides $1.92, which is a 3.6% discount to Savanna’s
closing price on the Toronto Stock Exchange on March 23, 2017.

Do not feel pressured into tendering your shares to the inadequate Total Offer
as additional time provides you with optionality.

/T/

— If Total does acquire more than 50% of the outstanding Savanna Shares

(excluding Savanna Shares owned by Total or any person acting jointly or
in concert with Total), Total will be required to extend the Total Offer
for ten days following the initial expiry of the Total Offer.
— Total is paying your broker a solicitation fee to deposit your Savanna
Shares to the Total Offer. Make sure you are getting the appropriate
advice from an independent financial advisor in respect of your
alternatives.
— Time is on the Savanna shareholder’s side. A meeting of Savanna
shareholders to consider the Western Arrangement is scheduled for May,
2017. If you do not tender to the Total Offer, you’ll have the
opportunity to participate in the Western Arrangement or any alternative
proposals that may be made for your Savanna Shares. Do not tender and
inadvertently surrender your option to consider all alternatives.

/T/

Savanna shareholders are urged not to tender their Savanna Shares to the Total
Offer. If you have already tendered your Savanna Shares to the Total Offer, you
can withdraw your Savanna Shares by contacting your broker or D.F. King, North
American Toll Free at 1-800-622-1678 or via email at inquiries@dfking.com.

FINANCIAL ADVISORS

Peters & Co. Limited is acting as financial advisor to Savanna in respect of
the Western Arrangement and has provided the Savanna Board with its verbal
opinion that, subject to certain customary assumptions, qualifications and
limitations, the consideration to be received by holders of Savanna Shares
pursuant to the terms of the Western Arrangement is fair, from a financial
point of view, to the holders of Savanna Shares.

Cormark Securities Inc. has provided the Savanna Board with its verbal opinion
that, subject to certain customary assumptions, qualifications and limitations,
the consideration to be received by holders of Savanna Shares pursuant to the
terms of the Western Arrangement is fair, from a financial point of view, to
the holders of Savanna Shares.

About Savanna

Savanna is a leading contract drilling and oilfield services company operating
in North America and Australia providing a broad range of drilling, well
servicing and related services with a focus on fit for purpose technologies and
industry-leading Aboriginal relationships.

Cautionary Statements

This press release contains forward-looking statements and forward-looking
information within the meaning of applicable securities laws. The use of any of
the words “expect”, “anticipate”, “continue”, “estimate”, “may”, “will”,
“project”, “should”, “believe”, “plans”, “intends” and similar expressions are
intended to identify forward-looking information or statements. More
particularly and without limitation, this press release contains
forward-looking statements and information relating to the proposed acquisition
of Savanna by Western pursuant to a plan of arrangement, the timing of the
Savanna shareholders’ meeting and the opportunity to participate in the Western
Arrangement and any future alternative proposals. These forward-looking
statements and information are based on certain key expectations and
assumptions made by Savanna. Completion of the Western Arrangement is subject
to a number of conditions which are typical for transactions of this nature.
Assumptions have been made with respect to the satisfaction of all conditions
precedent under the arrangement agreement with Western. Although Savanna
believes that the expectations and assumptions on which such forward-looking
statements and information are based are reasonable, undue reliance should not
be placed on the forward-looking statements and information as Savanna cannot
give any assurance that they will prove to be correct. Since forward-looking
statements and information address future events and conditions, by their very
nature they involve inherent risks and uncertainties. Actual results could
differ materially from those currently anticipated due to a number of factors
and risks. These include, but are not limited to, the failure to satisfy any of
the conditions to completion of the Western Arrangement, the emergence of a
superior proposal in respect of either party or the failure to obtain approval
of the Savanna shareholders or Western shareholders may result in the
termination of the arrangement agreement.

Readers are cautioned that the foregoing list of risks and uncertainties is not
exhaustive. Additional information on these and other risks that could affect
completion of the Western Arrangement will be set forth in an information
circular of Savanna to be mailed in connection with the Western Arrangement,
which will be available on SEDAR at www.sedar.com. Other risk factors that
could affect Savanna’s operations or financial results are included in
Savanna’s annual information form and may be accessed through the SEDAR website
(www.sedar.com). The forward-looking statements and information contained in
this press release are made as of the date hereof and Savanna does not
undertake any obligation to update publicly or revise any forward-looking
statements or information, whether as a result of new information, future
events or otherwise, unless so required by applicable securities laws.

– END RELEASE – 23/03/2017

For further information:
Savanna Energy Services Corp.
Chris Strong
President and Chief Executive Officer
Telephone: (403) 267-6728
OR
Savanna Energy Services Corp.
Dwayne LaMontagne
Executive Vice President and Chief Financial Officer
Telephone: (403) 214-5959
OR
Media contact:
Trevor Zeck
Longview Communications Inc.
Telephone: (604) 694-6037
OR
Shareholder inquiries:
D.F. King Canada
Telephone (Toll Free): 1-800-622-1678

COMPANY:
FOR: SAVANNA ENERGY SERVICES CORP.
TSX SYMBOL: SVY

INDUSTRY: Energy and Utilities – Equipment, Energy and Utilities –
Oil and Gas
RELEASE ID: 20170323CC0081

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: BLACKBIRD ENERGY INC.TSX VENTURE SYMBOL: BBIDate issue: March 23, 2017Time in: 5:35 PM eAttention:
CALGARY, ALBERTA–(Marketwired – March 23, 2017) – Blackbird Energy Inc.
(“Blackbird”) (TSX VENTURE:BBI) is pleased to report that it has closed the…

FOR: CEIBA ENERGY SERVICES INC.TSX VENTURE SYMBOL: CEBDate issue: March 23, 2017Time in: 5:31 PM eAttention:
CALGARY, ALBERTA–(Marketwired – March 23, 2017) – Ceiba Energy Services Inc.
(“Ceiba” or the “Company”) (TSX VENTURE:CEB) announces that Mr. R…

FOR: DXI ENERGY INC.
TSX SYMBOL: DXI
OTCQB SYMBOL: DXIEF

Date issue: March 23, 2017
Time in: 5:05 PM e

Attention:

VANCOUVER, BRITISH COLUMBIA–(Marketwired – March 23, 2017) – DXI Energy Inc.
(TSX:DXI)(OTCQB:DXIEF) (“DXI” or the “Company”), an upstream oil and gas
exploration and production company operating in Colorado’s Piceance Basin and
the Peace River Arch region in British Columbia, today announced corrections to
the “Revenue” and “Royalties” dollar amounts included in the Q4 and Fiscal 2016
financial results press release announcement disseminated to the public on
March 22, 2017.

The revised numbers are as follows:

/T/

—————————————————————————-

Three months ended Twelve months ended
(CA$ thousands) December 31, December 31,
—————————————————————————-
2016 2015 Change 2016 2015 Change
—————————————————————————-
Revenue 954 2,768 -66% 4,808 8,579 -44%
—————————————————————————-
Royalties 127 517 -75% 735 1,483 -50%
—————————————————————————-

/T/

No corrections were required to be made to the Company’s Audited Consolidated
Financial Statements for the Three and Twelve Months Ended December 31, 2016 or
the related Management’s Discussion and Analysis for the same period and year.

About DXI ENERGY INC.

DXI Energy Inc. is an upstream oil and natural gas exploration and production
company operating projects in Colorado’s Piceance Basin (25,684 net acres) and
the Peace River Arch region in British Columbia (14,444 net acres). DXI Energy
Inc. maintains offices in Calgary and Vancouver, Canada. The company is
publicly traded on the Toronto Stock Exchange (DXI.TO) and the OTCQB (DXIEF).

Statements Regarding Forward-Looking Information: This news release contains
statements about oil and gas production and operating activities that may
constitute “forward-looking statements” or “forward-looking information” within
the meaning of applicable securities legislation as they involve the implied
assessment that the resources described can be profitably produced in the
future, based on certain estimates and assumptions. Forward-looking statements
are based on current expectations, estimates and projections that involve a
number of risks, uncertainties and other factors that could cause actual
results to differ materially from those anticipated by DXI Energy and described
in the forward-looking statements. These risks, uncertainties and other factors
include, but are not limited to, adverse general economic conditions, operating
hazards, drilling risks, inherent uncertainties in interpreting engineering and
geologic data, competition, reduced availability of drilling and other well
services, fluctuations in oil and gas prices and prices for drilling and other
well services, government regulation and foreign political risks, fluctuations
in the exchange rate between Canadian and US dollars and other currencies, as
well as other risks commonly associated with the exploration and development of
oil and gas properties. Additional information on these and other factors,
which could affect DXI Energy Inc.’s operations or financial results, are
included in DXI Energy Inc.’s reports on file with Canadian and United States
securities regulatory authorities. We assume no obligation to update
forward-looking statements should circumstances or management’s estimates or
opinions change unless otherwise required under securities law.

The TSX does not accept responsibility for the adequacy or accuracy of this
news release.

Follow DXI Energy’s latest developments on: Facebook
http://facebook.com/dxienergy and Twitter @dxienergy.

– END RELEASE – 23/03/2017

For further information:
DXI Energy Inc.
Robert L. Hodgkinson
Chairman & CEO
604-638-5055
investor@dxienergy.com
OR
DXI Energy Inc.
Craig Allison
Investor Relations- New York
914-882-0960
callison@dxienergy.com

COMPANY:
FOR: DXI ENERGY INC.
TSX SYMBOL: DXI
OTCQB SYMBOL: DXIEF

INDUSTRY: Energy and Utilities – Oil and Gas
RELEASE ID: 20170323CC0072

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: ENBRIDGE GAS DISTRIBUTION INC.
Date issue: March 23, 2017Time in: 4:31 PM eAttention:
TORONTO, ONTARIO–(Marketwired – March 23, 2017) – Enbridge Gas Distribution
Inc. (Enbridge) has received approval from the Ontario Energy Board (OEB) for
new ra…

FOR: UNITED HUNTER OIL & GAS CORP.
TSX VENTURE SYMBOL: UHO
FRANKFURT SYMBOL: A118VK

Date issue: March 23, 2017
Time in: 12:25 PM e

Attention:

Dual Listing on the Frankfurt Stock Exchange and an Extension to the Exclusive
Option Agreement to Purchase Oil & Gas Interests in Archer County, Texas

VANCOUVER, BRITISH COLUMBIA–(Marketwired – March 23, 2017) – United Hunter Oil
& Gas Corp. (“Corporation”) (TSX VENTURE:UHO)(FRANKFURT:A118VK) announces that
the Corporation’s shares will be dually listed and traded on the Frankfurt
Stock Exchange (Frankfurter Wertpapierborse (FWB(R)). The Frankfurt Exchange is
the largest of Germany’s seven stock exchanges. The Corporation’s security
identification number is A118VK. With the dual listing, the Corporation now
provides German and European investors the ability to have direct access to
participate in the ownership of the Corporation.

Timothy Turner, CEO of the Corporation, stated that, “United Hunter Oil & Gas
Corp is pleased to announce the listing of our shares on the Frankfurt Stock
Exchange. United Hunter is in the beginning stages of an aggressive acquisition
strategy and this is attracting an increasing interest in the Corporation from
several investors in Germany and all across Europe. The cross-listing between
the TSX-Venture Exchange and the Frankfurt Exchange is in direct response to
this investor demand and it will introduce United Hunter to a wider audience of
potential retail and institutional investors. This will certainly improve
liquidity, further diversify our current shareholder base and increase the
visibility and awareness of United Hunter within the global investment
community.”

The Corporation, through its US subsidiary, United Hunter Texas, LLC (“UHT”),
also has received an extension to their exclusive Option Agreement (“Option”)
with Wilson Operating Company and certain other vendors (“Vendors”), for the
option to purchase 100% of the Vendors’ oil and gas interests in the Hull Silk
Sikes 4,300′ Sand Unit (“HSS Unit”) in Archer County, Texas.

The Extension Agreement provides UHT with an additional thirty (30) days to
continue the Company’s due diligence efforts thus extending the exclusive
Option until April 30, 2017. The Vendors have also agreed to provide UHT with
additional time after this date, if necessary.

UHT will continue to conduct its extensive due diligence activities over the
intervening period. The exercise of the Option, by UHT, is still subject to
completion of its due diligence, including final negotiation of the adjusted
purchase price, UHO board approval, financing and TSX Venture Exchange
approval.

Further details will be provided as they become available.

Certain statements in the documents referred to in this press release may
constitute forward-looking statements within the meaning of applicable
securities laws. Forward-looking statements include, but are not limited to,
statements concerning (i) the acquisition of the Property Interest; and (ii)
potential results from the Property Interest. Forward-looking statements
generally can be identified by the use of forward looking terminology such as
“outlook”, “objective”, “may”, “will”, “expect”, “intend”, “estimate”,
“anticipate”, “believe”, “should”, “plans” or “continue”, or similar
expressions suggesting future outcomes or events. Such forward-looking
statements reflect management’s current beliefs and are based on information
currently available to management. Forward-looking statements involve risks and
uncertainties that could cause actual results to differ materially from those
contemplated by such statements. Such forward-looking statements are subject to
risks and uncertainties that may cause actual results, performance or
developments to differ materially from those contained in the statements
including, without limitation, the risks that: (1) UHO may not achieve the
results currently anticipated; and (2) UHO may not be able to obtain financing
in the future. Although UHO believes that the expectations reflected in its
forward-looking information are reasonable, undue reliance should not be placed
on forward-looking information because UHO can give no assurance that such
expectations will prove to be correct. In addition to other factors and
assumptions which may be identified in this press release, assumptions have
been made regarding and are implicit in, among other things, the timely receipt
of required regulatory approvals. Details of the risk factors relating to UHO
and its business are discussed under the heading “Risk Factors” in the
Management Discussion & Analysis dated November 22, 2016, a copy of which is
available on UHO’s SEDAR profile at www.sedar.com. Readers are cautioned that
the foregoing list is not exhaustive of all factors and assumptions which have
been used. Forward-looking information is based on current expectations,
estimates and projections that involve a number of risks and uncertainties
which could cause actual results to differ materially from those anticipated by
UHO and described in the forward looking information. The forward-looking
information contained in this press release is made as of the date hereof and
UHO undertakes no obligation to update publicly or revise any forward-looking
information, whether as a result of new information, future events or
otherwise, unless required by applicable securities laws. The forward looking
information contained in this press release is expressly qualified by this
cautionary statement.

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

– END RELEASE – 23/03/2017

For further information:
Timothy Turner
CEO
(832) 487-0813
info@unitedhunteroil.com
OR
Jeff Ratcliffe
CFO
(778) 987-3925
jratcliffe@unitedhunteroil.com

COMPANY:
FOR: UNITED HUNTER OIL & GAS CORP.
TSX VENTURE SYMBOL: UHO
FRANKFURT SYMBOL: A118VK

INDUSTRY: Energy and Utilities – Oil and Gas
RELEASE ID: 20170323CC0045

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: DIVERGENT ENERGY SERVICES CORP.TSX VENTURE SYMBOL: DVGDate issue: March 23, 2017Time in: 9:00 AM eAttention:
CALGARY, ALBERTA–(Marketwired – March 23, 2017) –
(NOT FOR DISSEMINATION IN THE UNITED STATES OF AMERICA)
DIVERGENT Energy Services Corp….

FOR: EAST WEST PETROLEUM CORP.
TSX VENTURE SYMBOL: EW

Date issue: March 23, 2017
Time in: 8:30 AM e

Attention:

VANCOUVER, BRITISH COLUMBIA–(Marketwired – March 23, 2017) – EAST WEST
PETROLEUM CORP. (TSX VENTURE:EW) (“East West” or the “Company”) Mr. Dylan
Sidoo, Director, is pleased to announce that we have been informed by our JV
Partner, NIS, that drilling of the first well in EX-7 Periam block, in the
Pannonian Basin of Western Romania has been completed. Core and cutting
sampling correlated with wireline logging and other information collected
during drilling will be tested and evaluated. The results will be used in
developing the testing program which will be the next stage of operations. We
will be providing a further update when available. NIS will be funding 100% and
fully carrying East West through the minimum work program of the exploration
phase in return for earning an 85% interest in the blocks.

The Company is also pleased to report that in New Zealand, at the Cheal E site,
PEP 54877, a waterflood project has commenced. It is expected that water
injection rates will increase to 800 b/d, with an initial response projected to
be seen in calendar Q3 2017.

Said CEO, Mr. David Sidoo, “We are pleased with the progress being made by NIS
in Romania and look forward to the results of the testing. In New Zealand the
waterflood project is now underway and we are expecting positive response from
this capital investment. We are also reviewing other oil and gas acquisition
opportunities which are coming available during this period of lower commodity
prices.”

About East West Petroleum Corp.

East West Petroleum (www.eastwestpetroleum.ca) is a TSX Venture Exchange listed
company established in 2010 to invest in international oil & gas opportunities.
East West has built a diverse portfolio of attractive exploration assets
covering a gross area of over one million acres. The Company has its primary
focus on two key areas: New Zealand, where it has established production and
cash flow and is evaluating a low risk exploration play, and Romania where it
is fully carried on a seismic surveying and 12 well exploration program. In New
Zealand, East West holds an interest in three exploration permits near to
existing commercial production in the Taranaki Basin, operated by TAG Oil Ltd.
The Company also has interests in four exploration concessions covering
1,000,000 acres in the prolific Pannonian Basin of western Romania with Naftna
Industrija Srbije (“NIS”).

Forward-looking information is subject to known and unknown risks,
uncertainties and other factors that may cause the Company’s actual results,
level of activity, performance or achievements to be materially different from
those expressed or implied by such forward-looking information. Such factors
include, but are not limited to: the ability to raise sufficient capital to
fund exploration and development; the quantity of and future net revenues from
the Company’s reserves; oil and natural gas production levels; commodity
prices, foreign currency exchange rates and interest rates; capital expenditure
programs and other expenditures; supply and demand for oil and natural gas;
schedules and timing of certain projects and the Company’s strategy for growth;
competitive conditions; the Company’s future operating and financial results;
and treatment under governmental and other regulatory regimes and tax,
environmental and other laws.

Prospective Resources are those quantities of petroleum estimated, as of a
given date, to be potentially recoverable from undiscovered accumulations by
application of future development projects. Prospective resources have both an
associated chance of discovery and a chance of development. Prospective
Resources are further subdivided in accordance with the level of certainty
associated with recoverable estimates assuming their discovery and development
and may be subclassified based on project maturity. Best estimate resources are
considered to be the best estimate of the quantity that will actually be
recovered from the accumulation. If probabilistic methods are used, this term
is a measure of central tendency of the uncertainty distribution (most
likely/mode, P50/median, or arithmetic average/mean). As estimates, there is no
certainty that any portion of the resources will be discovered. If discovered,
there is no certainty that it will be commercially viable to produce any
portion of the resources that the estimated reserves or resources will be
recovered or produced.

BOEs may be misleading, particularly if used in isolation. A BOE conversion
ratio of 6 mcf: 1bbl is based on an energy equivalency conversion method
primarily applicable at the burner tip and does not represent a value
equivalency at the wellhead.

This list is not exhaustive of the factors that may affect our forward-looking
information. These and other factors should be considered carefully and readers
should not place undue reliance on such forward-looking information. The
Company disclaims any intention or obligation to update or revise
forward-looking information, whether as a result of new information, future
events or otherwise.

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

– END RELEASE – 23/03/2017

For further information:
East West Petroleum Corp.
Max Sali
Corporate Development
+1 604 682 1558
+1 604 683 1585 (FAX)
info@eastwestpetroleum.ca

COMPANY:
FOR: EAST WEST PETROLEUM CORP.
TSX VENTURE SYMBOL: EW

INDUSTRY: Energy and Utilities – Oil and Gas
RELEASE ID: 20170323CC0021

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: PAN ORIENT ENERGY CORP.
TSX VENTURE SYMBOL: POE

Date issue: March 23, 2017
Time in: 8:30 AM e

Attention:

CALGARY, ALBERTA–(Marketwired – March 23, 2017) – Pan Orient Energy Corp.
(“Pan Orient”) (TSX VENTURE:POE) reports 2016 year-end and fourth quarter
consolidated financial and operating results. Please note that all amounts are
in Canadian dollars unless otherwise stated and BOPD refers to barrels of oil
per day.

The Corporation is today filing its audited consolidated financial statements
as at and for the year ended December 31, 2016 and related management’s
discussion and analysis with Canadian securities regulatory authorities. Copies
of these documents may be obtained online at www.sedar.com or the Corporation’s
website, www.panorient.ca.

Commenting today on Pan Orient’s 2016 results, President and CEO Jeff Chisholm
stated: “While 2016 was a difficult year for the industry as a whole, Pan
Orient weathered the storm by virtue of a very strong balance sheet, large cash
position, low cost and high net back onshore Thailand oil production and made
progress towards providing shareholders potentially substantial near term
growth at the East Jabung PSC in Indonesia with the completion of the
permitting process and the start of road and well pad construction for the
upcoming AYU-1 exploration well. We now look forward to the drilling of AYU-1
which is anticipated to commence in late April after a modest delay in
construction activities due to very heavy rain”.

2016 HIGHLIGHTS

Indonesia

/T/

— Construction of the road to the AYU-1 exploration well location was

completed on March 9th and well pad construction is currently underway.
Heavy rain has been experienced throughout the construction period and
as a result, the first exploration well at the Anggun prospect of the
East Jabung Production Sharing Contract (“PSC”), is estimated to
commence in late-April 2017.

— The Batu Gajah PSC expired on January 15, 2017. The requested two year

extension to the PSC allowing for drilling throughout the PSC was not
going to be granted and information on nearby wells indicated that the
Akeh-1 accumulation was much more complex and substantially smaller than
first believed. Pan Orient decided not to drill the Akeh-2 appraisal
well and allowed the PSC to expire.

/T/

Thailand

/T/

— Net to Pan Orient’s 50.01% equity interest in the Thailand Joint

Venture, oil sales were 258 BOPD in 2016, (compared with 324 BOPD in
2015) and funds flow from operations was $2.4 million, or $25.89 per
barrel (compared with $3.9 million and $32.92 per barrel in 2015).

— Approval was received from the Government of Thailand, effective January

8, 2016, for a 215.87 square kilometer “reserved area” for exploration
at Concession L53 for a period of up to five years.

— The 2016 exploration and development program included a number of

workovers and the ANE-A1 exploration well at the “A” North East prospect
which failed to encounter hydrocarbons.

— It is expected that the 2017 Thailand capital program will include at

least one exploration well and a multi-well work-over program.

/T/

Sawn Lake, Canada (Pan Orient’s 71.8% subsidiary Andora owns a 50% working
interest and is the operator)

/T/

— The steam assisted gravity drainage (“SAGD”) demonstration project

reached a steady state production level in January and February 2016
with an average of 615 barrels per day (“BOPD”) (307 BOPD net to Andora)
and an average instantaneous steam-oil ratio (“ISOR”) of 2.1 from the
one SAGD wellpair.

— The demonstration project established the viability of the SAGD process

in the Bluesky formation at Sawn Lake, indicated the productive
capability and ISOR, and provided critical information required for well
and facility design associated with potential future commercial
development. The demonstration project was suspended on February 29,
2016.

— Andora’s June 30, 2016 Contingent Resources Report estimated unrisked

“Best Estimate” contingent resources of 231.6 million barrels of
recoverable bitumen (166.3 million barrels net to Pan Orient’s 71.8%
interest in Andora).

— Andora submitted an application for a potential commercial expansion at

Sawn Lake to 3,200 BOPD and is waiting for regulatory approval.
Expansion is dependent on completion of detailed engineering and higher
commodity prices to support project economics and financing.

/T/

Corporate

/T/

— On February 16, 2016, Pan Orient returned $22.0 million ($0.40 per

common share) to shareholders.

— Corporate funds flow used in operations for 2016 was $1.3 million with

$2.5 million used in the first nine months of 2016, corporate funds flow
from operations was $1.2 million in the fourth quarter of 2016.
Corporate funds flow in the fourth quarter resulted from increased oil
sales and oil prices associated with Pan Orient’s 50.01% equity interest
in the Thailand Joint Venture and foreign exchange gains on United
States dollar holdings.

— The net loss attributable to common shareholders in 2016 was $82.8

million, with a $78.1 million net loss attributable to common
shareholders in the fourth quarter of 2016, primarily due to the net
impairment expense associated with the expiry of the Batu Gajah PSC.

— Pan Orient has a strong financial position at December 31, 2016 for

planned exploration activities in Indonesia and Thailand with working
capital and non-current deposits of $49.8 million and no long-term debt.

/T/

2016 FOURTH QUARTER OPERATING RESULTS

The financial statements reflect that on February 2, 2015 the Company sold a
49.99% equity interest in its subsidiary Pan Orient Energy (Siam) Ltd. (“POS”)
and retained a 50.01% equity interest. From February 2, 2015 forward the
retained 50.01% equity interest is reclassified as a jointly controlled Joint
Venture and Pan Orient’s 50.01% equity interest in the working capital, assets,
capital expenditures, liabilities and operations of POS are recorded as
Investment in Thailand Joint Venture.

/T/

— Net loss attributable to common shareholders for the fourth quarter of

2016 of $78.1 million ($1.42 loss per share) compared with $0.9 million
loss ($0.02 loss per share) in the third quarter of 2016 and $4.0
million loss ($0.07 loss per share) in the fourth quarter of 2015. In
the fourth quarter of 2016 the Company reported a $102.3 million
impairment charge of Batu Gajah Exploration and Evaluation assets offset
by the $22.6 million associated reduction in accumulated other
comprehensive income related to foreign currency translation for a net
impairment expense of $79.7 million.

— For the fourth quarter of 2016, the Company recorded total corporate

funds flow from operations, which includes the economic results of the
50.01% interest in the Thailand joint venture, of $1.2 million ($0.02
per share). This compares with total corporate funds flow from
operations for the third quarter of 2016 of $0.3 million ($0.01 per
share). Compared with corporate funds flow from operations from the
third quarter of 2016, the fourth quarter of 2016 had:

— economic funds flow from Thailand operations were 71% higher driven
by an 19% increase in the realized crude oil price and a 23%
increase in oil sales volume.

— foreign exchange gains in Canada of $696 thousand ($242 thousand
gain in the third quarter) from the stronger United States dollar.

— Indonesia exploration expense recovery of $101 thousand ($4 thousand
expense in the third quarter) from receiving refund of government
deposit associated with the Citarum PSC.

— Pan Orient had capital expenditures of $0.4 million in the fourth

quarter of 2016, with $0.2 million in Indonesia and $0.2 million in
Canada at the Sawn Lake SAGD demonstration project of Andora. In
addition, Pan Orient’s share of Thailand joint venture capital
expenditures was $1.0 million, which was recorded in Investment in
Thailand Joint Venture.

— Capital expenditures for 2016, net of dispositions, were $5.2 million,

with $1.9 million in Indonesia, $1.8 million in Canada at the Sawn Lake
SAGD demonstration project of Andora, and $1.5 million for Pan Orient’s
share of Thailand joint venture capital expenditures.

— At December 31, 2016, Pan Orient had $49.8 million of working capital

and non-current deposits. Working capital and non-current deposits were
comprised of $46.9 million cash, $4.4 million of non-current deposits,
other receivables of $0.3 million and less Canadian taxes payable of
$0.1 million and accounts payable of $1.7 million. In addition, Pan
Orient’s Investment in Thailand Joint Venture includes $3.0 million of
Thailand working capital and non-current deposits and $1.9 million of
equipment inventory to be utilized for future Thailand Joint Venture
operations.

— Pan Orient had outstanding capital commitments as at December 31, 2016

of $2.0 million in Indonesia associated with the Company’s 49%
participating interest in the East Jabung PSC. In Canada, capital
commitments are $0.3 million with respect to contracted natural gas
pipeline tie-in and tariff charges associated with the Sawn Lake SAGD
demonstration project of Andora.

— Results net to Pan Orient’s 50.01% Interest in the Thailand Joint

Venture for Concession L53

— Average oil sales of 290 BOPD during the fourth quarter of 2016 and
generated $1.0 million in funds flow from operations, or $37.30 per
barrel. This compares with 2016 third quarter results of 236 BOPD (a
23% increase) and $26.74 per barrel in funds flow from operations (a
39% increase). The average realized sales price per barrel has
increased to $60.22 in the fourth quarter from $37.07 in the first
quarter and $50.68 in the third quarter.

— Per barrel amounts during the fourth quarter of 2016 were a realized
price for oil sales of $60.22, transportation expenses of $1.54,
operating expenses of $10.81, general and administrative expenses of
$7.57 and a 5% royalty to the Thailand government of $3.00. Oil
sales revenue during this period was allocated 33% to expenses for
transportation, operating, and general & administrative, 5% to the
government of Thailand for royalties, and 62% to the Thailand Joint
Venture. No Thailand petroleum income taxes or Special Remuneratory
Benefit tax was recorded during the quarter.

— Capital expenditures were $1.0 million during the fourth quarter of
2016 and $1.5 million for 2016. Capital expenditures for 2016 were
comprised of $0.9 million for drilling of the ANE-A1 exploration
well at the “A” North East prospect, $0.5 million for workovers and
other capital expenditures and $0.1 million for capitalized general
and administrative expenses. The ANE-A1 exploration well at the “A”
North East prospect did not encounter hydrocarbons.

— Oil sales in January and February 2017 at Concession L53, net to Pan
Orient’s 50.01% interest, averaged 254 BOPD.

— The December 31, 2016 independent reserves evaluation for Thailand
on-shore Concession L53 was prepared for POS, a 50.01% owned
subsidiary of Pan Orient, which is the operator and has a 100%
working interest. The evaluation was conducted by Sproule
International Limited of Calgary (“Sproule”) and was prepared in
accordance with Canadian Securities Administrators National
Instrument 51-101 – Standards of Disclosure for Oil and Gas
Activities. Pan Orient has a 50.01% ownership in POS, but does not
have any direct interest in, or control over, the crude oil reserves
or operations of on-shore Concession L53. The values at December 31,
2016 identified as “Net to Pan Orient’s 50.01% Equity Interest in
Pan Orient Energy (Siam) Ltd.” represent 50.01% of POS reserves and
values.

Net to Pan Orient’s 50.01% equity interest in POS, proved plus
probable crude oil reserves of 570,000 barrels at December 31, 2016
from conventional sandstone reservoirs, decreased 5% compared with
the prior year. Net to Pan Orient’s 50.01% equity interest in POS,
net present value (after tax) of Thailand proved plus probable crude
oil reserves at December 31, 2016, using forecast prices and costs
discounted at 10% per year, of Cdn$13.2 million, or $0.24 per Pan
Orient share based on the current 54.9 million Pan Orient shares
outstanding.

— Indonesia

— At the East Jabung PSC, onshore Sumatra, Pan Orient has a 49%
participating interest and is a non-operator. In 2015 Pan Orient
completed a farm-out of a 51% participating interest and
operatorship of the East Jabung PSC to a subsidiary of Repsol S.A.
whereby the farminee funds the first USD$10 million towards the
first exploration well and a contingent commitment to fund the first
USD$5 million towards an appraisal well if the farminee elects to
drill an appraisal well as a follow up to success in the first
exploration well. In addition, the farminee bears 100% of the
general and administrative costs associated with the first
exploration well and for any appraisal well. Efforts in 2016 were
focused towards drilling of the AYU-1 exploration well, the first
exploration well at the Anggun ELOK prospect complex of the East
Jabung PSC. Construction of the five kilometer access road was
completed on March 9 and well pad construction is currently
underway. Drilling rig mobilization is planned to start prior to
month end and the commencement of drilling of the approximately 21
day well is anticipated on or about the end of April. Rain has
impacted timelines throughout the entire period of road and well pad
construction resulting in a departure from the original timelines as
mitigation measures are carried out.

— Pan Orient’s 2016 capital expenditures for the East Jabung PSC were
$0.6 million comprised of $0.5 million at the East Jabung PSC
accrued for the sub-surface portion of the 2012, 2013 and 2014 Land
and Building Tax assessments and $0.1 million for seismic
reprocessing and capitalized G&A expenses.

— At the Batu Gajah PSC, onshore Sumatra, Pan Orient was operator with
a 77% participating interest. During 2016, Pan Orient worked towards
drilling the Akeh-2 appraisal well to the Akeh-1 exploration well
drilled in the fourth quarter of 2015 which resulted in a natural
gas and condensate discovery, but recognizing that the test results
for Akeh-1 are not necessarily indicative of long-term performance,
ultimate recovery or commercial viability. In early 2016 the oil and
gas regulator of the Government of Indonesia (“GOI”) informed the
Company that an additional appraisal well of the Akeh discovery was
required prior to granting of “Release from Exploration Status” as a
“conclusive discovery”. The Batu Gajah PSC 10 year exploration phase
had an expiry date of January 15, 2017 and the Company submitted an
application for a two year extension in June 2016, the earliest date
for an application allowed under oil and gas regulations. The
requested two year extension would provide time to drill the Akeh-2
appraisal well, potentially obtain the “Release from Exploration
Status”, move forward to prepare a Plan of Development to determine
the likelihood of the commerciality of the Akeh-1 discovery and to
undertake other drilling activities within the PSC. Discussions with
the GOI at the end of 2016 indicated the possibility of a one year
extension to the exploration term of the PSC, specifically only
allowing the Akeh-2 appraisal well in early 2017 and no other
drilling activity. Additionally, information at that time indicated
that nearby wells, in close proximity to the Batu Gajah PSC
boundary, have performed in a fashion suggesting that the Akeh-1
accumulation is both much more complex and substantially smaller
than first believed. The implications are that it appears very
unlikely Pan Orient would achieve the required commercial threshold
for an approved Plan of Development for the Akeh structure, and as a
result, it is not possible to justify the expenditures required for
the drilling of the Akeh-2 appraisal well, particularly combined
with the current and foreseeable oil price environment. Pan Orient
notified the GOI that the PSC would expire at the end of the 10 year
term on January 15, 2017. As a result, the Company reported a $102.3
million impairment charge of Batu Gajah Exploration and Evaluation
assets and offset by the $22.6 million associated reduction in
accumulated other comprehensive income related to foreign currency
translation for a net impairment expense of $79.7 million.

— Pan Orient’s 2016 capital expenditures for the Batu Gajah PSC were
$1.3 million comprised of $1.4 million for capitalized G&A expenses,
and less a $0.1 million recovery from the expected refund of
government deposit associated with the Batu Gajah PSC.

— During 2016 Pan Orient recorded $0.8 million of exploration expenses
associated with the Citarum PSC which expired in 2015. These
expenses related to final drilling expenses associated with the PSC,
expenses associated with the relinquishment of the PSC, and less
recovery of $0.1 million from receiving refund of government deposit
associated with the Citarum PSC.

— Sawn Lake Alberta Heavy Oil (Operated by Andora, in which Pan Orient has

a 71.8% ownership)

— Capital expenditures for the Sawn Lake demonstration project during
the fourth quarter of 2016 were $0.1 million and $1.8 million for
2016. Capital expenditures related to suspension of demonstration
project operations at the end of February 2016, costs associated
with filing the application for potential commercial expansion at
the demonstration project site, capitalization of expenses and
revenues of the demonstration project and capitalized G&A. Andora
capitalized $1.1 million of demonstration project expenses less
revenues in 2016.

— The demonstration project successfully captured the key data
associated with its objectives, which was used to update the Sawn
Lake reservoir model and prepare an updated contingent resources
report. Production results to date are not necessarily indicative of
long-term performance or of ultimate recovery and the Sawn Lake
demonstration project has not yet proven that it is commercially
viable.

— The June 30, 2016 Contingent Resources Report is a National
Instrument 51-101 compliant resources evaluation for Andora’s oil
sands interests at Sawn Lake Alberta, Canada, as evaluated by
Sproule Unconventional Limited (“Sproule”). The evaluation included
all of Andora’s Oil Sands Leases at Sawn Lake based on exploitation
using SAGD. Results of the demonstration project increased unrisked
recoverable resources 8%, significantly increased average peak
production rates and decreased the requirement for natural gas by
16%. Andora’s unrisked “Best Estimate” contingent resources
increased 8% to 231.6 million barrels of recoverable bitumen (166.3
million barrels net to Pan Orient’s 71.8% interest in Andora). The
estimated before tax net present value, discounted at 10%, of
Andora’s unrisked “Best Estimate” contingent resources increased 21%
to $568 million ($408 million net to Pan Orient’s 71.8% interest in
Andora), despite a 15% decrease in the forecast average realized
price per barrel for bitumen, given the performance of the
demonstration project in terms of peak production rate and
cumulative steam-oil ratio (“CSOR”). The estimated after tax net
present value, discounted at 10%, of Andora’s unrisked “Best
Estimate” contingent resources increased 26% to $374 million ($268
million net to Pan Orient’s 71.8% interest in Andora). The
evaluation assigned an 85% chance of development for Sawn Lake, or a
15% development risk, and the risked “Best Estimate” contingent
resources for Andora are 196.9 million barrels of bitumen
recoverable (141.4 million barrels net to Pan Orient’s 71.8%
interest in Andora). The risked “Best Estimate” net present value,
discounted at 10%, for Andora’s interests is $482 million on a
before tax basis and $318 million on an after tax basis ($346
million and $228 million net to Pan Orient’s 71.8% interest in
Andora respectively).

— An application for a potential expansion at the demonstration
project site to 3,200 BOPD was submitted in April 2016. It is
expected that a reactivation of the demonstration project facility
and wellpair would be considered as part of a potential commercial
expansion to 3,200 BOPD. The expansion application requests the
drilling of up to seven additional SAGD wellpairs which are tied
into the existing demonstration project facility. The facility would
be expanded to generate the additional necessary steam, and it is
anticipated that additional steam generation would include the test
installation of Andora’s proprietary produced water boiler. Andora
believes that its produced water boiler could achieve significant
benefits for Sawn Lake SAGD field development. An expansion is
dependent on regulatory approval, completion of detailed engineering
and a higher commodity price environment to support project
economics and financing.

— Andora is completing detailed engineering for its proprietary
Thermal System and Process for Producing Steam from Oilfield
Produced Water (“Produced Water Boiler”).

/T/

OUTLOOK

INDONESIA

East Jabung PSC, Onshore Sumatra Indonesia (Pan Orient 49% ownership & Non
Operator)

Drilling of the AYU-1 exploration well, the first exploration well at the
Anggun prospect of the East Jabung Production Sharing Contract (“PSC”), is
estimated to commence in late-April 2017. Construction of the five kilometer
access road has been completed and well pad construction is underway.
Exploration success with AYU-1 could have a significant impact on Pan Orient.
With the expiry of the Batu Gajah PSC, Pan Orient will have substantially
reduced overhead and G&A in Indonesia.

THAILAND

Concession L53 Onshore (Pan Orient Energy (Siam) Ltd., in which Pan Orient has
50.01% ownership)

Concession L53 has continued to generate funds flow from operations throughout
2016 due to its low cost structure. Exploration activities in 2017 are expected
to be financed by Thailand working capital and funds flow from operations. The
2017 Thailand capital program, soon to be finalized with partners, will include
at least one exploration well and a multi-well work-over program.

CANADA

Sawn Lake (Operated by Andora, in which Pan Orient has a 71.8% ownership)

Pan Orient continues to move forward with steps towards potential future
development at Sawn Lake. It is recognized that higher crude oil prices, and
specifically higher Western Canada Select reference prices, will have a
significant impact on any decision regarding the timing of future development.
The first steps will be receiving approval for the Sawn Lake expansion and
completing detailed engineering for its proprietary Produced Water Boiler.

Corporate

The Company maintains a strong financial position to conduct key exploration
and development activities in all three countries during 2017 and ensure
financial flexibility. Pan Orient continues to review its worldwide exploration
and development asset portfolio with the aim of maximizing corporate value and
the best allocation of a substantial net cash balance that is in excess of
future capital commitments. These activities range from the potential
divestment of existing assets to the ongoing screening of new venture
opportunities.

Pan Orient is a Calgary, Alberta based oil and gas exploration and production
company with operations currently located onshore Thailand, Indonesia and in
Western Canada.

This news release contains forward-looking information. Forward-looking
information is generally identifiable by the terminology used, such as
“expect”, “believe”, “estimate”, “should”, “anticipate” and “potential” or
other similar wording. Forward-looking information in this news release
includes, but is not limited to, references to: renewal, extension or
termination of oil concessions and production sharing contracts; other
regulatory approvals; well drilling programs and drilling plans; the benefits
of patented technology; estimates of reserves and potentially recoverable
resources, information on future production and project start-ups, and
negotiation, agreement, closing and financing and other terms of farmout and
other transactions; potential purchases of common shares under the normal
course issuer bid; and sufficiency of financial resources. By their very
nature, the forward-looking statements contained in this news release require
Pan Orient and its management to make assumptions that may not materialize or
that may not be accurate. The forward-looking information contained in this
news release is subject to known and unknown risks and uncertainties and other
factors, which could cause actual results, expectations, achievements or
performance to differ materially, including without limitation: imprecision of
reserve estimates and estimates of recoverable quantities of oil, changes in
project schedules, operating and reservoir performance, the effects of weather
and climate change, the results of exploration and development drilling and
related activities, demand for oil and gas, commercial negotiations, other
technical and economic factors or revisions and other factors, many of which
are beyond the control of Pan Orient. Although Pan Orient believes that the
expectations reflected in its forward-looking statements are reasonable, it can
give no assurances that the expectations of any forward-looking statements will
prove to be correct.

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.

/T/

———————————————
Twelve Months
Three Months Ended Ended %
Financial and Operating Summary December 31, December 31, Change
————————————–
(thousands of Canadian dollars
except where indicated) 2016 2015 2016 2015
—————————————————————————-
FINANCIAL
—————————————————————————-
Financial Statement Results –
Excluding 50.01% Interest in
Thailand Joint Venture from
February 2, 2015 onwards (Note
1)
Net income (loss) attributed to
common shareholders (78,149) (3,980) (82,837) 29,053 -385%
Per share – basic and diluted $ (1.42) $ (0.07) $ (1.51) $ 0.52 -390%
Cash flow from operating
activities (Note 2) 82 80 8,620 1,439 499%
Per share – basic and diluted $ 0.00 $ 0.00 $ 0.16 $ 0.03 424%
Cash flow from (used in)
investing activities (Note 2) (65) (6,057) (5,864) 40,342 -115%
Per share – basic and diluted $ (0.00) $ (0.11) $ (0.11) $ 0.72 -115%
Working capital 45,447 74,901 45,447 74,901 -39%
Working capital & non-current
deposits 49,818 79,160 49,818 79,160 -37%
Long-term debt – – – – 0%
Shares outstanding (thousands) 54,885 54,885 54,885 54,885 0%
Capital commitments (Note 3) 2,318 2,399 2,318 2,399 59%
Contingencies (Note 4)
—————————————————————————-
Working Capital and Non-current
Deposits
Beginning of period 49,945 81,128 79,160 40,854 94%
Corporate funds flow from
(used in) operations (Note
6) 251 558 (3,778) 1,088 -447%
Special distribution – – (21,954) – 100%
Funds flow from sale of
Thailand interest – – – 48,877 -100%
Working capital and non-
current deposits
derecognized on sale of
Thailand interest and
recorded in Investment in
Joint Venture – – – (3,151) -100%
Consolidated capital
expenditures (Note 8) (431) (4,301) (3,905) (17,055) -77%
Amounts received from
Thailand Joint Venture 40 1,391 172 1,293 -87%
Disposal of petroleum and
natural gas assets (Note 9) 56 – 161 9,764 -98%
Normal course issuer bid – – – (2,691) -100%
Foreign operations –
unrealized foreign exchange
gain (loss) (43) 384 (38) 181 -121%
———————————————
End of period 49,818 79,160 49,818 79,160 -37%
—————————————————————————-
—————————————————————————-
Economic Results – Including
50.01% Interest in Thailand
Joint Venture from February 2,
2015 onwards (Note 5)
Total corporate funds flow from
(used in) operations (Note 6) 1,249 1,837 (1,301) 4,676 -128%
Per share – basic and diluted $ 0.02 $ 0.03 $ (0.02) $ 0.08 -130%
Corporate funds flow from (used
in) operations by region (Note
6)
Canada (Note 7) 255 1,063 (2,424) 4,222 -157%
Thailand – 100% to February
1, 2015 (Note 1) (2) 19 (29) 305 -110%
Indonesia (2) (524) (1,325) (3,439) -61%
———————————————
Funds flow from (used in)
consolidated operations 251 558 (3,778) 1,088 -447%
Share of funds flow from
Thailand Joint Venture (Note
5) 998 1,279 2,477 3,588 -31%
———————————————
Total corporate funds flow
from (used in) operations 1,249 1,837 (1,301) 4,676 -128%
———————————————
———————————————
Funds flow from sale of
Thailand interest – – – 48,877 -100%
—————————————————————————-
Petroleum and natural gas
properties
Capital expenditures (Note 8) 1,444 4,538 5,400 20,997 -74%
Dispositions – excluding sale
of Thailand interest (Note
9) (56) – (161) (9,764) -98%
Capital Expenditures (Note 8)
Canada (Note 7) 176 703 1,980 4,669 -58%
Thailand – 100% to February
1, 2015 (Note 1) – – – 60 -100%
Indonesia 255 3,598 1,925 12,326 -84%
———————————————
Consolidated capital
expenditures 431 4,301 3,905 17,055 -77%
Share of Thailand Joint
Venture capital expenditures 1,013 237 1,495 3,942 -62%
———————————————
Total capital expenditures 1,444 4,538 5,400 20,997 -74%
—————————————————————————-
—————————————————————————-
Investment in Thailand Joint
Venture
—————————————————————————-
Beginning of period 33,316 36,328 35,088 – 100%
Investment retained on sale
of Thailand interest – – – 38,587 -100%
Net loss from Joint Venture (226) (928) (1,542) (1,992) -23%
Other comprehensive gain
(loss) from Joint Venture (255) 1,078 (579) (214) 171%
Amounts received from Joint
Venture (40) (1,391) (172) (1,293) -87%
———————————————
End of period 32,795 35,088 32,795 35,088 -7%
—————————————————————————-
—————————————————————————-

———————————————
Twelve Months
Three Months Ended Ended
December 31, December 31,
(thousands of Canadian dollars
except where indicated) 2016 2015 2016 2015 Change
—————————————————————————-
—————————————————————————-
Thailand Operations
—————————————————————————-
Economic Results – Including
50.01% Interest in Thailand
Joint Venture from February 2,
2015 onwards (Note 5)
Oil sales (bbls) 26,702 38,740 94,539 118,269 -20%
Average daily oil sales (BOPD)
by Concession L53 290 421 258 324 -20%
Average oil sales price, before
transportation (CDN$/bbl) $ 60.22 $ 49.61 $ 48.95 $ 57.94 -16%
Reference Price (volume
weighted) and differential
Crude oil (Brent $US/bbl) $ 49.12 $ 44.02 $ 43.51 $ 50.84 -14%
Exchange Rate $US/$Cdn 1.34 1.35 1.34 1.28 4%
Crude oil (Brent $Cdn/bbl) $ 65.72 $ 59.34 $ 58.33 $ 65.23 -11%
Sale price / Brent reference
price 92% 84% 84% 89% -6%
Funds flow from (used in)
operations (Note 6)
Crude oil sales 1,608 1,922 4,628 6,853 -32%
Government royalty (80) (94) (229) (336) -32%
Transportation expense (41) (56) (143) (186) -23%
Operating expense (289) (371) (1,057) (1,626) -35%
———————————————
Field netback 1,198 1,401 3,199 4,705 -32%
General and administrative
expense (Note 10) (202) (102) (756) (777) -3%
Interest income 5 2 11 9 22%
Foreign exchange loss (5) (3) (5) (44) -89%
Current income tax – – (1) – 100%
———————————————
Funds flow from operations –
Thailand 996 1,298 2,448 3,893 -37%
———————————————
———————————————
Funds flow from (used in)
operations / barrel (CDN$/bbl)
(Note 6)
Crude oil sales $ 60.22 $ 49.61 $ 48.95 $ 57.94 -16%
Government royalty (3.00) (2.43) (2.42) (2.84) -15%
Transportation expense (1.54) (1.45) (1.51) (1.57) -4%
Operating expense (10.81) (9.58) (11.18) (13.75) -19%
———————————————
Field netback $ 44.87 $ 36.16 $ 33.84 $ 39.78 -15%
General and administrative
expense (Note 10) (7.57) (2.63) (8.01) (6.57) 22%
Interest Income 0.19 0.05 0.12 0.08 53%
Foreign exchange loss (0.19) (0.08) (0.05) (0.37) -86%
Current income tax – – (0.01) – 100%
———————————————
Funds flow from operations –
Thailand $ 37.30 $ 33.51 $ 25.89 $ 32.92 -21%
———————————————
———————————————
Government royalty as
percentage of crude oil sales 5% 5% 5% 5%
Income tax & SRB as percentage
of crude oil sales – – – –
As percentage of crude oil
sales
Expenses – transportation,
operating, G&A and other 33% 28% 42% 38% 4%
Government royalty, SRB and
income tax 5% 5% 5% 5% 0%
Funds flow from operations,
before interest income 62% 68% 53% 57% -4%
Wells drilled
Gross 1 – 1 3 -67%
Net 0.5 – 0.5 1.5 -67%
—————————————————————————-
Financial Statement
PresentationResults –
Excluding 50.01% Interest in
Thailand Joint Venture from
February 2, 2015 onwards (Note
1)
Crude oil sales – – – 809 -100%
Government royalty – – – (38) -100%
Transportation expense – – – (24) -100%
Operating expense – – – (257) -100%
———————————————
Field netback – – – 490 -100%
General and administrative
expense (Note 10) (3) (2) (30) (199) -85%
Interest income – – – 1 -100%
Foreign exchange gain 1 21 1 13 -92%
———————————————
Funds flow from (used in)
consolidated operations (2) 19 (29) 305 -110%
———————————————
———————————————
Funds flow included in
Investment in Thailand Joint
Venture
Net loss from Thailand Joint
Venture (226) (928) (1,542) (1,992) -23%
Add back non-cash items in
net loss 1,224 2,207 4,019 5,580 -28%
———————————————
Funds flow from Thailand
Joint Venture 998 1,279 2,477 3,588 -31%
———————————————
Thailand – Economic funds flow
from operations 996 1,298 2,448 3,893 -37%
—————————————————————————-
—————————————————————————-

/T/

/T/

———————————————
Twelve Months
Three Months Ended Ended
December 31, December 31,
(thousands of Canadian dollars
except where indicated) 2016 2015 2016 2015 Change
—————————————————————————-
Canada Operations (Note 7)
—————————————————————————-
Interest income 46 32 173 149 16%
General and administrative
expenses (Note 10) (637) (604) (2,303) (2,425) -5%
Foreign exchange gain (loss) 696 1,635 (165) 6,498 -103%
Current income tax 150 – (129) – 100%
———————————————
Canada – Funds flow from
(used in) operations 255 1,063 (2,424) 4,222 -157%
—————————————————————————-
—————————————————————————-
Indonesia Operations
—————————————————————————-
General and administrative
expense (Note 10) (110) (430) (516) (1,678) -69%
Exploration expense (Note 11) 101 (58) (831) (464) 79%
Foreign exchange gain (loss) 7 (76) 22 (881) -102%
Current income tax – 40 – (416) -100%
———————————————
Indonesia – Funds flow used
in operations (2) (524) (1,325) (3,439) -61%
———————————————
———————————————
Wells drilled
Gross – – – 1 -100%
Net – – – 0.8 -100%
—————————————————————————-
—————————————————————————-
———————————-
Year Ended
December 31, Change

(thousands of Canadian dollars except
where indicated) 2016 2015
—————————————————————————-
RESERVES AND CONTINGENT RESOURCES
—————————————————————————-

Onshore Thailand – Concession L53 (50.01%
economic interest) (Note 1) (Note 12) (Note 13)
Proved oil reserves (thousands of
barrels) 273 253 8%
Proved plus probable oil reserves
(thousands of barrels) 570 599 -5%
Net present value of proved + probable
reserves, after tax discounted at 10% 13,187 13,051 1%
Per Pan Orient share – basic (Note 14) $0.24 $ 0.24 0%
Canada (Pan Orient’s 71.8% share of the
oil sands leases of Andora at Sawn Lake,
Alberta) (Note 15) (Note 16)
—————————————————————————-
INTERNATIONAL INTERESTS AT DECEMBER 31, 2016
—————————————————————————-
All amounts reflect Pan December 31, 2016
Orient’s economic interest Net Square Financial Commitments
Status Kilometers (Cdn thousands)
—————————————————————————-
Onshore Thailand Concession (Recorded
in Investment in Joint Venture)
—————————————
L53/48 (Pan Orient 50.01% to January
ownership as at December Partially 2021 (Note
31, 2016) (Note 1 & 17) developed 108 – 17)
————————
Onshore Indonesia PSCs (Consolidated
subsidiaries)
—————————————
East Jabung PSC, South Undeveloped 1,445 $ 2,049 to November
Sumatra (49% interest & 2017
non-operator) (Note 18, 10
& 20)
Batu Gajah PSC, South Undeveloped – – PSC expired
Sumatra (77% interest & January 15,
operator) (Note 21) 2017
————————
1,553 $ 2,049
————————
————————

—————————————————————————-

INTERNATIONAL INTERESTS AT
DECEMBER 31, 2016
—————————————————–
All amounts reflect Pan 2016 Avg. P+P Reserves
Orient’s economic interest Production (thousands
(BOPD) of barrels)
—————————————————–
Onshore Thailand Concession
(Recorded in Investment in
Joint Venture)
—————————
L53/48 (Pan Orient 50.01%
ownership as at December
31, 2016) (Note 1 & 17) 258 570

Onshore Indonesia PSCs
(Consolidated
subsidiaries)
—————————
East Jabung PSC, South
Sumatra (49% interest &
non-operator) (Note 18, 10
& 20)
Batu Gajah PSC, South
Sumatra (77% interest &
operator) (Note 21)

—————————————————–

(1) On February 2, 2015 the Company sold a 49.99% equity interest in its

subsidiary Pan Orient Energy (Siam) Ltd. and retained a 50.01% equity
interest in the company. The transaction resulted in Pan Orient Energy
(Siam) Ltd. changing from a wholly-owned and controlled subsidiary to a
joint arrangement where the Company shares joint control with the
purchaser of the 49.99% equity interest. The resulting joint arrangement
is classified as a Joint Venture under IFRS 11 and is required to be
accounted for using the equity method of accounting rather than
consolidated as it had previously been when Pan Orient Energy (Siam)
Ltd. was a controlled subsidiary. The change in accounting from
consolidation to the equity method has resulted in the accounts of Pan
Orient Energy (Siam) Ltd. being derecognized from the consolidated
financial statements and a net investment related to the portion of the
interest retained being recognized at its estimated fair value upon
initial recognition. Pan Orient’s 50.01% equity interest in the assets,
liabilities, working capital, operations and capital expenditures of Pan
Orient Energy (Siam) Ltd. from February 2, 2015 forward are recorded in
Investment in Joint Venture.
(2) As set out in the Consolidated Statements of Cash Flows in the
Consolidated Financial Statements of Pan Orient Energy Corp.
(3) Refer to Commitments in Note 19 of the December 31, 2016 and December
31, 2015 Consolidated Financial Statements.
(4) Refer to Contingencies in Note 20 of the December 31, 2016 and December
31, 2015 Consolidated Financial Statements.
(5) For the purpose of providing more meaningful economic results from
operations for Thailand, and for comparison to previous period, the
amounts presented consist of:
(a) Company’s share of Thailand funds flow from operation at 100% from
January 1, 2015 to February 1, 2015 (being the beginning of the year
to the last date before the equity interest was completed as
discussed in note 1)
(b) Company’s share of Thailand funds flow from operating at 50.01%
subsequent to February 2, 2015 (when the Company completed the
equity sale transaction).
(6) Corporate funds flow from operations is cash flow from operating
activities prior to changes in non-cash working capital, and reclamation
costs plus the corresponding amount from the Thailand operations which
is recorded in Investment in Joint Venture for financial statement
purposes. This measure is used by management to analyze operating
performance and leverage. Funds flow as presented does not have any
standardized meaning prescribed by IFRS and therefore it may not be
comparable with the calculation of similar measures of other entities.
Funds flow is not intended to represent operating cash flow or operating
profits for the period nor should it be viewed as an alternative to cash
flow from operating activities, net earnings or other measures of
financial performance calculated in accordance with IFRS.
(7) The Sawn Lake Demonstration Project in Alberta has not yet proven that
it is commercially viable and all related costs and revenues are being
capitalized as exploration and evaluation assets until commercial
viability is achieved.
(8) Cost of capital expenditures, excluding decommissioning provision and
the impact of changes in foreign exchange rates.
(9) During the second quarter of 2015 the Company completed a farmout of a
51% interest of the East Jabung PSC in Indonesia and received an upfront
cash payment of USD $8.0 million, less 5% withheld for transfer taxes,
plus USD $181 thousand reimbursed for G&A, which has been recorded as a
disposal of E&E assets with no gain or loss recorded on the transaction.
(10)General & administrative expenses, excluding non-cash accretion on
decommissioning provision and stock-based payments.
(11)Exploration expense relates to exploration costs associated with the
Citarum and South CPP PSCs in Indonesia.
(12)Thailand reserves as at December 31, 2016 as evaluated by Sproule
International Limited of Calgary assessed at forecast crude oil
reference prices and costs. The US$ reference price for crude oil per
barrel (US$ UK Brent per barrel) in the evaluation is $55.00 for 2017,
$65.00 for 2018, $70.00 for 2019, $71.40 for 2020, $72.83 for 2021 and
prices increase at 2.0% per year thereafter. Foreign exchange rate used
of Cdn$1=US$0.78 for 2017, Cdn$1=US$0.82 for 2018 and Cdn$1=US$0.85
thereafter. The engineered values disclosed may not represent fair
market value.
(13)Thailand reserves as at December 31, 2015 as evaluated by Sproule
International Limited of Calgary assessed at forecast crude oil
reference prices and costs. The US$ reference price for crude oil per
barrel (US$ UK Brent per barrel) in the evaluation is $45.00 for 2016,
$60.00 for 2017, $70.00 for 2018, $80.00 for 2019, $81.20 for 2020,
$82.42 for 2021 and prices increase at 1.5% per year thereafter. Foreign
exchange rate used of Cdn$1=US$0.75 for 2016, Cdn$1=US$0.80 for 2017,
Cdn$1=US$0.83 for 2018 and Cdn$1=US$0.85 thereafter. The engineered
values disclosed may not represent fair market value.
(14)Per share values calculated based on 54,885,407 Pan Orient Shares
outstanding at December 31, 2016 and December 31, 2015.
(15)The evaluation of the Andora’s contingent resources of the oil sands
project at Sawn Lake Alberta, Canada as at June 30, 2016 was conducted
by Sproule Unconventional Limited. The evaluation assigned an 85% chance
of development for Sawn Lake, or a 15% development risk, and the risked
“Best Estimate” contingent resources for Andora were 196.9 million
barrels of bitumen recoverable (141.4 million barrels net to Pan
Orient’s interest in Andora). Andora’s unrisked “Best Estimate”
contingent resources were 231.6 million barrels (166.3 million net to
Pan Orient’s interest in Andora) of recoverable bitumen as at June 30,
2016. The June 30, 2016 report has been updated for results of the Sawn
Lake demonstration project, the June 30, 2016 price forecasts for crude
oil, bitumen, natural gas and exchange rates, and a revised date of 2020
for the estimated commencement of commercial production.
(16)A contingent resource report was not prepared for December 31, 2015. Pan
Orient’s 71.8% share as at December 31, 2014 of the “Best Case”
contingent resources of Andora, a private company as evaluated by
Sproule Unconventional Limited assessed at forecast crude oil reference
prices and costs. The “Best Case” company gross contingent resources at
Sawn Lake were 214 million barrels of bitumen recoverable attributed to
Andora’s working interest, which is 154 million barrels attributed to
the 71.8% ownership interest of Pan Orient in Andora. The reference
prices for crude oil per barrel (Western Canada Select WCS 20.5 API in
Canadian dollars) is $60.50 for 2015, $75.13 for 2016, $84.52 for 2017,
$85.79 for 2018, $87.07 for 2019, $89.31 for 2020 and prices for the
reference price (WCS) increase at 1.5% per year thereafter. Undiscounted
future capital expenditures for Pan Orient’s 71.8% share are estimated
at $1,578 million. The engineered values disclosed may not represent
fair market value and there is no certainty that it will be commercially
viable to produce any portion of the resources.
(17)At December 31, 2016 Concession L53/48 in Thailand consisted of 20
square kilometers associated with the L53-A, L53-D and L53-G fields held
through production licenses (with a 20 year primary term to 2036 plus an
additional 10 year renewal period that can be applied for) and 215.87
square kilometers of “reserved area” exploration lands.
The original nine year exploration period for Concession L53 expired on
January 7, 2016. The Government of Thailand approved a 215.87 square
kilometer “reserved area” within Concession L53 for up to five years,
with the payment of a surface reservation fee of $0.8 million gross
($0.4 million net to Pan Orient), for each year the Company elects to
retain the reserved area. The Company is entitled to receive a refund of
the surface reservation fee for a particular year in an amount equal to
the petroleum exploration expenditures spent in that year within the
reserved area up to the reservation fee paid. The Company intends to
spend at least the full amount each year the reserved area is renewed
and, therefore, it is expected that the annual reservation fee will be
fully refunded.
(18)Pan Orient’s share of commitments in Indonesia reflects amounts to be
paid by Pan Orient in respect of the East Jabung Production Sharing
Contract (“PSC”). Commitments in Indonesia include the completion of a
work program as well as the Company’s estimated amount of the
expenditure. Financial commitments as provided above represent
management’s assessment of the costs of the work program required under
the initial 3-year firm commitment exploration period of the PSC. The
work program commitment is based on the original contract and timing is
subject to Government of Indonesia (“GOI”) approval. With respect to the
East Jabung PSC, the extension of this initial exploration period has
been agreed to with the GOI to the date indicated. If Pan Orient
exercises its options to continue beyond the initial exploration period,
additional commitments will be determined on a year-by-year basis
through submission of a work program and approval from the GOI. Although
extension of the exploration period is a departure from the original
contract, it is considered standard practice in Indonesia.
(19)In the fourth quarter of 2014 the Company entered into a farmin
agreement for the transfer of a 51% direct working interest and
operatorship of the East Jabung PSC. The agreement includes a firm
commitment by the farminee to fund the first USD $10.0 million towards
the first exploration well and a contingent commitment to fund the first
USD $5.0 million towards an appraisal well, if justified. The
transaction closed on June 1, 2015 and the Company transferred the
operatorship of the PSC to the farminee and reduced its interest to 49%.
The commitment provided above represents the Company’s 49% interest in
the two exploration wells and its share of the outstanding geological
studies.
(20)The Company relinquished the East Jabung PSC’s offshore area of 3,279.96
square kilometers in 2013, and this relinquishment was finalized in
2014. The result of the relinquishment does not impact the PSC’s onshore
exploration activities. As at December 31, 2016 Pan Orient had a 49%
interest in the East Jabung PSC, which had a gross area of 2,947.76
square kilometers (1,445 square kilometers net).
(21)At December 31, 2016 Pan Orient held a 77% interest in the Batu Gajah
PSC, which had a gross area of 791.71 square kilometers (610 square
kilometers net). On January 15, 2017 the Batu Gajah PSC expired.
(22)Tables may not add due to rounding.

/T/

– END RELEASE – 23/03/2017

For further information:
Pan Orient Energy Corp.
Jeff Chisholm
President and CEO (located in Bangkok, Thailand)
jeff@panorient.ca
OR
Pan Orient Energy Corp.
Bill Ostlund
Vice President Finance and CFO
(403) 294-1770, Extension 233

COMPANY:
FOR: PAN ORIENT ENERGY CORP.
TSX VENTURE SYMBOL: POE

INDUSTRY: Energy and Utilities – Oil and Gas
RELEASE ID: 20170323CC0020

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: INPLAY OIL CORP.
TSX Symbol: IPO
OTCQX Symbol: IPOOF

Date issue: March 23, 2017
Time in: 8:00 AM e

Attention:

CALGARY, AB –(Marketwired – March 23, 2017) – InPlay Oil Corp. (TSX: IPO)
(OTCQX: IPOOF) (“InPlay” or the “Company”) announces its financial and
operating results for the three months and year ended December 31, 2016.
InPlay’s full audited financial statements and notes, as well as management’s
discussion and analysis (“MD&A”) for the three and twelve month periods ended
December 31, 2016 will be available shortly on the System for Electronic
Document Analysis and Retrieval (“SEDAR”).

Financial and Operating Highlights

/T/

—————————————————————————-
For the Three and Twelve Three months ended Twelve months ended
Months Ended December 31 December 31
(CDN$) (000’s)
2016 2015 2016 2015
—————————————————————————-
Financial (CDN $)
—————————————————————————-
Petroleum and natural
gas revenue 10,578 7,655 27,850 32,556
—————————————————————————-
Funds flow from
Operations (1) (29) 4,500 6,407 15,792
—————————————————————————-
Per share — basic
and diluted (1) (2) 0.00 0.37 0.33 1.31
—————————————————————————-
Per boe(1) (0.12) 25.39 9.02 23.20
—————————————————————————-
Comprehensive Income
(Loss) 36,077 (9,862) 20,019 (30,101)
—————————————————————————-
Per share — basic
and diluted (2) 0.86 (0.82) 1.02 (2.50)
—————————————————————————-
Exploration and
Development Capital
expenditures 7,340 3,196 11,083 22,513
—————————————————————————-
Property Acquisitions 45,450 – 45,450 885
—————————————————————————-
Corporate Acquisitions 33,212 – 33,212 –
—————————————————————————-
(Net Debt)/Working
Capital (1) (34,556) (59,159) (34,556) (59,159)
—————————————————————————-
Shares outstanding (2) 62,396,169 12,063,110 62,396,169 12,063,110
—————————————————————————-
Basic & fully diluted
weighted-average
shares (2) 42,153,526 12,063,110 19,626,821 12,052,898
—————————————————————————-

—————————————————————————-
Operational
—————————————————————————-

Daily production
volumes
—————————————————————————-
Crude oil (bbls/d) 1,522 1,593 1,318 1,598
—————————————————————————-
Natural gas liquids
(bbls/d) 258 50 143 49
—————————————————————————-
Natural gas (Mcf/d) 5,592 1,701 2,871 1,305
—————————————————————————-
Total (boe/d) 2,712 1,926 1,940 1,865
—————————————————————————-
Realized prices
—————————————————————————-
Crude Oil & NGLs
($/bbls) 58.64 48.31 49.71 52.18
—————————————————————————-
Natural gas ($/Mcf) 3.33 2.27 2.53 2.50
—————————————————————————-
Total ($/boe) 42.40 43.20 39.22 47.84
—————————————————————————-
Operating netbacks ($
per boe) (1)
—————————————————————————-
Oil and Gas sales 42.40 43.20 39.22 47.84
—————————————————————————-
Royalties (3.75) (4.03) (3.48) (4.39)
—————————————————————————-
Transportation
expense (0.79) (0.33) (0.83) (0.24)
—————————————————————————-
Operating costs (17.61) (16.00) (17.36) (16.80)
—————————————————————————-
Operating Netback
(prior to realized
derivative contracts) 20.25 22.84 17.55 26.41
—————————————————————————-
Realized gain on
derivative
contracts (1.04) 12.18 3.74 5.73
—————————————————————————-
Operating Netback
(including realized
derivative contracts) 19.21 35.02 21.29 32.14
—————————————————————————-

/T/

/T/

(1) “Funds flow from operations”, “Funds flow from operations per share”,
“Funds flow from operations per boe”, “Net Debt”, “Working Capital”,
“Operating netback per boe” and “Operating income” do not have a
standardized meaning under international financial Reporting
standards (IFRS) and GAAP. Please refer to Non-GAAP Financial
Measures and BOE equivalent at the end of this news release.
(2) All weighted average share amounts are converted retrospectively at
the exchange rate of 0.1303 in accordance with the terms of the
Arrangement Agreement as outlined in note 5 & 13 in the audited
annual December 31, 2016 financial statements. This is done in
accordance with IAS 33.64.

/T/

We are pleased to present InPlay’s financial and operating results for the
three months and year ended December 31, 2016. This was a transformational
year which saw InPlay transition into a publicly traded entity following the
November 7, 2016 private placement financing, asset acquisition in Pembina
(the “Asset Acquisition”) and the closing of the reverse take-over transaction
(the “Arrangement”) with Anderson Energy Inc. (“Anderson”). These transactions
have positioned InPlay as a well-financed light oil producer (65% oil &
liquids) with 74% of our current field estimated production of 4,100 boed in
the Cardium and providing ample opportunities for growth and development in
our expanded core areas.

The Company’s 2016 drilling program included a total of six (5.7 net) wells.
Two (1.7 net) Belly River horizontal wells were drilled in the first quarter
of 2016 and four (3.9 net) Pembina Cardium horizontals were drilled in the
fourth quarter. Two (1.9 net) of the Cardium horizontals came on production in
late December 2016 while the others began production in mid-February 2017. The
drilling and completion program carried over into 2017 with an additional six
(4.1 net) wells being drilled and five (3.1 net) wells are expected to be
completed and brought on production through March and April of 2017.

Fourth quarter 2016 production averaged 2,712 boe/day, reflecting limited
production from the newly acquired assets as of November 7, 2016. Capital
expenditures in 2016 amounted to $86.0 million comprised of $7.3 million
related to the quarterly E&D capital program and $78.7 million as
consideration for the Arrangement with Anderson as well as the Pembina Asset
Acquisition. Funds flow from operations for the fourth quarter was ($29)
thousand net of $2.4 million of transaction related expenses. We exited the
year with $34.6 million in net debt with a draw of $29.8 million on our $60.0
million syndicated credit facility. At year end, following these transactions,
proved plus probable reserves increased 180% to 24.5 mmboe from the previous
year’s 8.7 mmboe resulting in an asset base with a long reserve life of 19.3
years. Complete details of the results of our independent reserves evaluation
prepared by Sproule Associates Limited effective as of December 31, 2016 were
contained in our press release issued March 14, 2017.

Outlook

In 2017 we have a focused plan in place that will allow InPlay to achieve its
targeted production growth per share of greater than 20% (December 2017 over
December 2016) through an efficient development program in our core areas. In
2017 we anticipate drilling a total of 12.0 net wells in our two core Cardium
areas of Pembina and Willesden Green. We recently started drilling our first
(1.0 net) Willesden Green Cardium horizontal well that is expected to be
completed and placed on production in the second quarter which will leave
approximately seven net wells to be drilled for the second half of the year.
Capital expenditures are forecast to be $28.0 million for this program which
is expected to be less than forecasted funds flow from operations, assuming a
$55 WTI yearly average oil price. This program is forecast to generate net
debt to funds flow from operations for the fourth quarter annualized of
approximately 0.8 times. At a stress tested $45 WTI price for the remainder of
2017 this program is forecast to generate fourth quarter 2017 net debt to
adjusted funds flow from operations of approximately 1.1 times ensuring that
the 2017 capital program can be maintained in a lower commodity price
environment. This production growth is expected to yield top quartile
production per share growth within our oil weighted peers.

InPlay is in a very strong position with low debt levels, high operating
netback assets and a solid set of commodity hedges that will allow us to
continue to develop our asset base in the current volatile commodity price
environment, while always focusing on meaningful and sustainable per share
growth for our shareholders.

We thank our employees and directors for their commitment and dedication
through the past year, and we thank all of our shareholders for their
continued interest in InPlay.

Reader Advisories

Non-GAAP Financial Measures

InPlay uses certain terms within this news release that do not have a
standardized prescribed meaning under GAAP and these measurements may not be
comparable with the calculation of similar measurements of other entities. The
terms “Funds flow from operations”, “Funds flow from operations per share”,
“Funds flow from operations per boe” and “Operating netbacks” and “netback per
boe” in this news release are not recognized measures under GAAP. Management
believes that in addition to net earnings and cash flow from operating
activities as defined by GAAP, these terms are useful supplemental measures to
evaluate operating performance and assess leverage. Funds flow from operations
is calculated by adjusting for changes in non-cash working capital from
operating activities and from cashflow from operating activities. Funds flow
from operations per share is calculated using the same weighted average number
of shares outstanding used in calculating earnings per share. Users are
cautioned, however, that these measures should not be construed as an
alternative to net earnings or cash flow from operating activities determined
in accordance with GAAP as an indication of InPlay’s performance. The term
“net debt” is not recognized under GAAP and is calculated as bank debt plus
working capital deficiency adjusted for risk management fair values and
deferred lease credits. Net debt is used by management to analyze the
financial position and leverage of InPlay. InPlay also uses “netback per boe”
as a key performance indicator. Netback per boe is utilized by InPlay to
evaluate the operating performance of its petroleum and natural gas assets,
and is determined by deducting royalties and operating and transportation
expenses from petroleum and natural gas revenue (all on a per boe basis).
Acquisition capital amounts to the total amount of cash and share
consideration net of any working capital balances assumed with an acquisition
on closing.

Forward-Looking Information and Statements

This news release contains certain forward-looking information and statements
within the meaning of applicable securities laws. The use of any of the words
“expect”, “anticipate”, “continue”, “estimate”, “may”, “will”, “project”,
“should”, “believe”, “plans”, “intends” “forecast” and similar expressions are
intended to identify forward-looking information or statements. In particular,
but without limiting the foregoing, this news release contains forward-looking
information and statements pertaining to the following: the volume and product
mix of InPlay’s oil and gas production; production estimates; targeted
production growth; reserve estimates; future oil and natural gas prices and
InPlay’s commodity risk management programs; forecasted funds flow from
operations and net debt to funds flow from operations; future liquidity and
financial capacity; future results from operations and operating metrics
including forecasts of operating netbacks, cash flow and well payouts; future
costs, expenses and royalty rates; future interest costs; the exchange rate
between the $US and $Cdn; future development, exploration, acquisition,
development and infrastructure activities and related capital expenditures,
including our 2017 capital budget, and the timing thereof; the number of wells
to be drilled, completed and tied-in and the timing thereof; the amount and
timing of capital projects; and methods of funding our capital program.
Forward-looking statements or information are based on a number of material
factors, expectations or assumptions of InPlay which have been used to develop
such statements and information but which may prove to be incorrect. Although
InPlay believes that the expectations reflected in such forward-looking
statements or information are reasonable, undue reliance should not be placed
on forward-looking statements because InPlay can give no assurance that such
expectations will prove to be correct. In addition to other factors and
assumptions which may be identified herein, assumptions have been made
regarding, among other things: the impact of increasing competition; the
general stability of the economic and political environment in which InPlay
operates; the timely receipt of any required regulatory approvals; the ability
of InPlay to obtain qualified staff, equipment and services in a timely and
cost efficient manner; drilling results; the ability of the operator of the
projects in which InPlay has an interest in to operate the field in a safe,
efficient and effective manner; the ability of InPlay to obtain financing on
acceptable terms; field production rates and decline rates; the ability to
replace and expand oil and natural gas reserves through acquisition,
development and exploration; the timing and cost of pipeline, storage and
facility construction and the ability of InPlay to secure adequate product
transportation; future commodity prices; currency, exchange and interest
rates; regulatory framework regarding royalties, taxes and environmental
matters in the jurisdictions in which InPlay operates; the ability of InPlay
to successfully market its oil and natural gas products.

The forward-looking information and statements included herein are not
guarantees of future performance and should not be unduly relied upon. Such
information and statements, including the assumptions made in respect thereof,
involve known and unknown risks, uncertainties and other factors that may
cause actual results or events to defer materially from those anticipated in
such forward-looking information or statements including, without limitation:
changes in commodity prices; the potential for variation in the quality of the
reservoirs in which we operate; changes in the demand for or supply of our
products; unanticipated operating results or production declines; changes in
tax or environmental laws, royalty rates or other regulatory matters; changes
in development plans of InPlay or by third party operators of our properties,
increased debt levels or debt service requirements; inaccurate estimation of
our oil and gas reserve and resource volumes; limited, unfavorable or a lack
of access to capital markets; increased costs; a lack of adequate insurance
coverage; the impact of competitors; and certain other risks detailed from
time-to-time in InPlay’s disclosure documents. The forward-looking information
and statements contained in this news release speak only as of the date hereof
and InPlay does not assume any obligation to publicly update or revise any of
the included forward-looking statements or information, whether as a result of
new information, future events or otherwise, except as may be required by
applicable securities laws.

BOE equivalent

Barrel of oil equivalents or BOEs may be misleading, particularly if used in
isolation. A BOE conversion ratio of 6 mcf: 1 bbl is based on an energy
equivalency conversion method primarily applicable at the burner tip and does
not represent a value equivalency at the wellhead. Given that the value ratio
based on the current price of crude oil as compared to natural gas is
significantly different than the energy equivalency of 6:1, utilizing a 6:1
conversion basis may be misleading as an indication of value.

– END RELEASE – 23/03/2017

For further information:

For further information please contact:

Doug Bartole
President and Chief Executive Officer
InPlay Oil Corp.
Telephone: (587) 955-0632

Darren Dittmer
Chief Financial Officer
InPlay Oil Corp.
Telephone: (587) 955-0634

COMPANY:
FOR: INPLAY OIL CORP.
TSX Symbol: IPO
OTCQX Symbol: IPOOF

INDUSTRY: Energy and Utilities – Oil and Gas
RELEASE ID: 20170323CC001

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: PRAIRIE PROVIDENT RESOURCES INC.
TSX SYMBOL: PPR

Date issue: March 23, 2017
Time in: 7:00 AM e

Attention:

CALGARY, ALBERTA–(Marketwired – March 23, 2017) –

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

Prairie Provident Resources Inc. (“Prairie Provident” or “PPR” or the
“Company”) (TSX:PPR) is pleased to announce the completion of its previously
announced acquisition of strategic assets in the Greater Red Earth area of
northern Alberta (the “Assets”) for cash consideration of $41.0 million (the
“Acquisition”). The Assets include high-quality and low-decline oil production
which is complementary to Prairie Provident’s existing operations at Evi in the
Peace River Arch and further enhances the Company’s size and competitive
position. The Acquisition reinforces the Company’s growth profile by adding a
stable and predictable base of cash flow that is capable of funding repeatable
growth.

The Acquisition was funded through Prairie Provident’s credit facility, which
has been increased by $10.0 million to $65.0 million following closing of the
Acquisition, and through proceeds from the recently closed $4.0 million bought
deal equity financing of subscription receipts (“Subscription Receipts”).

Highlights of the Assets:

/T/

— Approximately 1,100 boe/d (98% oil and liquids) of production with a low

base decline rate of approximately 10%;
— Forecast 2017 operating netbacks of approximately $31.00 / boe(1);
— Forecast 12-month run rate funds from operations of approximately $12
million(1); and
— Potential to optimize PPR’s existing waterflood with seven approved
schemes.

/T/

Impact of the Acquisition:

/T/

— Approximately 6,500 boe/d (64% oil and liquids) of current production,

with annual 2017 average volumes expected between 6,100 and 6,600 boe/d
(60 – 65% oil and liquids) and exit production expected between 7,500
boe/d and 8,000 boe/d;
— 2017 capital budget is maintained at $25 million to $35 million, which
will flex depending on commodity prices;
— Forecast 2017 funds from operations anticipated between $31 to $35
million(1), primarily directed to funding the 2017 capital program, with
excess funds from operations directed to debt repayment;
— Debt to 12-month forward adjusted EBITDAX ratio is estimated at
approximately 1.3 times, with the intention to bring that ratio in line
with PPR’s target run-rate level of approximately 1.0 times over the
coming quarters; and
— Proximity to PPR’s existing asset base provides operational and
technical synergies, while economies of scale and operational
optimization in the area are expected to reduce operating costs by
$2.00/boe while improving the Company’s ability to compete for services.

/T/

Note:

(1) Assumes 2017 average WTI US$54.00, and FX rate of C$0.76 per US$1.00. See
“Oil and Gas Metrics and Non-IFRS Measures” below.

Given the complementary nature of the Acquisition, integration of the Assets
into PPR’s existing operations at Evi have already commenced. The Company will
announce its fourth quarter and year-end 2016 financial and operating results
on March 29, 2016. The results will include an operations update on first
quarter 2017 activity to date, including further information on the first four
Ellerslie wells from the 2017 budget which the Company has now drilled and
cased.

As previously announced, the Company issued 5,971,000 Subscription Receipts at
a price of $0.67 per Subscription Receipt, and 5,195,000 common shares issued
on a “flow-through” basis pursuant to the Income Tax Act (Canada)
(“Flow-Through Shares”) at a price of $0.77 per Flow-Through Share, for total
gross proceeds of approximately $8.0 million (the “Offering”). In accordance
with their terms, each Subscription Receipt was automatically exchanged, for no
additional consideration and without any action required on the part of the
holder, for one common share of the Company (an “Underlying Share”) and
one-half of one common share purchase warrant (each whole warrant, an
“Underlying Warrant”) in connection with closing of the Acquisition, and the
net proceeds of approximately $3.9 million from the sale of Subscription
Receipts under the Offering were released to the Company from escrow. Each
Underlying Warrant entitles the holder to acquire one common share at an
exercise price of $0.87 per share until March 16, 2019. The Underwriters led by
Mackie Research Capital Corporation have an over-allotment option exercisable
in whole or in part at any time prior to April 15, 2017 to purchase up to an
additional 15% of the number of Subscription Receipts and Flow-Through Shares
sold at the Offering prices, for total additional gross proceeds of up to
approximately $1.2 million. In the event and to the extent the Underwriters
exercise the option to purchase additional Subscription Receipts, an equal
number of Underlying Shares and one-half of such number of Underlying Issues
will be issued in lieu of the Subscription Receipts.

Further details regarding PPR, the Acquisition and the Offering are set out in
the Company’s short form prospectus dated March 8, 2017, which is available
under Prairie Provident’s profile on the SEDAR website and on the Company’s
website at www.ppr.ca .

This news release does not constitute an offer to sell or the solicitation of
an offer to buy any securities of the Company in the United States or in any
other jurisdiction in which any such offer, solicitation or sale would be
unlawful. The securities to be offered under the Offering have not been and
will not be registered under the United States Securities Act of 1933, as
amended (the “1933 Act”) or any state securities laws, and may not be offered
or sold in the United States or to U.S. Persons (as that term is defined in
Regulation S under the 1933 Act) except in transactions exempt from the
registration requirements of the 1933 Act and applicable state securities laws.

READER ADVISORIES

BOE Disclosure. We have adopted the industry-standard conversion ratio of six
Mcf to one bbl when converting natural gas quantities to “barrels of oil
equivalent” (BOEs). BOEs may be misleading, though, particularly if used in
isolation. A BOE conversion ratio of 6 mcf: 1 bbl is based on an energy
equivalency conversion method primarily applicable at the burner tip and does
not represent a value equivalency at the wellhead. Although the six-to-one
conversion factor is an industry accepted norm, it is not reflective of price
or market value differentials between product types. Based on current commodity
prices, the value ratio between natural gas and oil is significantly different
than the 6:1 ratio based on energy equivalency. Accordingly, a 6:1 conversion
ratio may be misleading as an indication of value.

Forward-Looking Information. Certain information included in this press release
constitutes forward-looking information under applicable securities
legislation. All statements other than statements of current or historical fact
constitute forward-looking information. Forward-looking information typically
contains statements with words such as “anticipate”, “believe”, “expect”,
“intend”, “plan”, “budget”, “forecast”, “target”, “estimate”, “propose”,
“potential”, “project”, “continue”, “may”, “will”, “should” or similar words
suggesting future outcomes or events or statements regarding an outlook.
Forward-looking information in this press release includes, but is not limited
to, statements concerning: cash flows from the Assets (and their capability to
fund growth); forecast 2017 operating netback for the Assets; forecast 2017
funds from operations for the Assets and the Company; waterflood optimization
potential; expected annual 2017 production volumes; expected 2017 exit
production; estimated forward adjusted EBITDAX ratio and target run-rate level;
operational and technical synergies from the Acquisition; expected operating
cost reductions; improved ability to compete for services; asset integration
expectations; timing for announcement of the Company’s fourth quarter and
year-end 2016 financial and operating results; and the potential exercise of
the Underwriters’ over-allotment option to purchase additional Underlying
Shares, Underlying Warrants and Flow-Through Shares.

The forward-looking information contained in this press release is based on
certain key expectations and assumptions made by Prairie Provident, including
expectations and assumptions concerning, among other things: commodity prices
and foreign exchange rates for 2017 and beyond; the timing and success of
future drilling, development and completion activities (and the extent to which
the results thereof meet Management’s expectations); the continued availability
of financing (including borrowings under the Company’s credit facility) and
cash flow to fund current and future expenditures, with external financing on
acceptable terms; future capital expenditure requirements and the sufficiency
thereof to achieve the Company’s objectives; the performance of both new and
existing wells; the stability of production from the Assets and capital and
operating costs in respect thereof; the timely availability and performance of
facilities, pipelines and other infrastructure in areas of operation; the
geological characteristics and quality of Prairie Provident’s properties
(including the Assets) and the reservoirs in which the Company conducts oil and
gas activities (including field production and decline rates); successful
integration of the Assets into the Company’s operations; the successful
application of drilling, completion and seismic technology; future exploration,
development, operating, transportation, royalties and other costs; the
Company’s ability to economically produce oil and gas from its properties and
the timing and cost to do so; the predictability of future results based on
past and current experience; prevailing weather conditions; prevailing
legislation and regulatory requirements affecting the oil and gas industry
(including royalty regimes); the timely receipt of required regulatory
approvals; the availability of capital, labour and services on timely and
cost-effective basis; the creditworthiness of industry partners and the ability
to source and complete acquisitions; and the general economic, regulatory and
political environment in which the Company operates.

Although Prairie Provident believes that the expectations and assumptions upon
which the forward-looking information in this press release is based are
reasonable based on currently available information, undue reliance should not
be placed on such information, which is inherently uncertain, relies on
assumptions and expectations, and is subject to known and unknown risks,
uncertainties and other factors, both general and specific, many of which are
beyond the Company’s control, that may cause actual results or events to differ
materially from those indicated or suggested in the forward-looking
information. Prairie Provident can give no assurance that the forward-looking
information contained herein will prove to be correct or that the expectations
and assumptions upon which they are based will occur or be realized. These
include, but are not limited to: risks inherent to oil and gas exploration,
development, exploitation and production operations and the oil and gas
industry in general, including geological, technical, engineering, drilling,
completion, processing and other operational problems and potential delays,
cost overruns, production or reserves loss or reduction in production, and
environmental, health and safety implications arising therefrom; uncertainties
associated with the estimation of reserves, production rates, product type and
costs; adverse changes in commodity prices, foreign exchange rates or interest
rates; the ability to access capital when required and on acceptable terms; the
ability to secure required services on a timely basis and on acceptable terms;
increases in operating costs; environmental risks; changes in laws and
governmental regulation (including with respect to royalties, taxes and
environmental matters); adverse weather or break-up conditions; competition for
labour, services, equipment and materials necessary to further the Company’s
oil and gas activities; and changes in plans with respect to exploration or
development projects or capital expenditures in respect thereof. These and
other risks are discussed in more detail in the Company’s short form prospectus
dated March 8, 2017 and its Annual Information Form for the year ended December
31, 2015, copies of which are available under Prairie Provident’s issuer
profile on the SEDAR website and on the Company’s website at www.ppr.ca. This
list is not exhaustive.

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

Oil and Gas Metrics and Non-IFRS Measures. This press release includes
reference to certain metrics commonly used in the oil and gas industry but
which do not have standardized meanings or methods of calculation under
International Financial Reporting Standards (IFRS), the Canadian Oil and Gas
Evaluation Handbook or applicable law, namely “operating netback” and “funds
from operations” and “adjusted EBITDAX ratio”. Accordingly, such metrics, as
determined by the Company and presented in this news release (or in other
documents published by Prairie Provident), may not be comparable to similarly
defined or described measures presented by other entities, and should not be
used for any such comparisons. These metrics are provided as supplementary
information by which readers may wish to consider the Company’s performance,
but should not be relied upon for comparative or investment purposes. With
respect to the metrics referred to herein:

/T/

— Operating Netback. The Company calculates “operating netback” as

production revenues (excluding realized and unrealized gains and losses
on commodity hedging) less royalties and operating expenses, calculated
on a per boe basis. Management considers operating netback to provide a
useful measure by which to evaluate operational performance as an
indicator of field-level profitability relative to current commodity
prices. The forecast 2017 operating netback for the Assets of $31.00 per
boe assumes 2017 average WTI US$54.00 and a foreign exchange rate of
C$0.76 per US$1.00, and is based on the Company’s current operating
costs in the area, a royalty rate based on the current Crown royalty
regime in Alberta applicable to the Assets, and a selling price
differential to WTI that is consistent with recent average price
realization for area production.

— Funds from Operations. The Company calculates funds from operations as

cash flow from operating activities (as determined in accordance with
IFRS) adjusted for changes in non-cash working capital, transaction
costs, restructuring costs, decommissioning expenditures and other non-
recurring items. Run rate cash flow for the Assets is calculated based
on annualized production and operating netback. The forecast 12-month
run rate funds from operations in respect of the Assets is based on the
assumptions relating to forecast 2017 operating netback for the Assets
set forth above and the further assumption that production from the
Assets (both as the volumes and product type) will remain stable at
approximately 1,100 boe/d (98% oil and liquids) for the next 12 months.
Management believes that these are useful supplemental measures for
assessing Prairie Provident’s operational performance on a continuing
basis by eliminating certain non-cash charges and charges that are non-
recurring, and utilizes the measure to assess the Company’s ability to
generate the cash necessary to finance operating activities, capital
expenditures and debt repayments. Funds from operations as presented
does not and is not intended to represent, and should not be considered
an alternative to or more meaningful than, cash flow from operating
activities, net earnings or other measures of financial performance
calculated in accordance with IFRS.

— Adjusted EBITDAX. The Company monitors its capital structure and

liquidity based on the ratio of Debt to Adjusted EBITDAX, which provides
a measure of the Company’s ability to manage its debt levels under
current operating conditions. For purposes of this calculation, “Debt”
refers to the Company’s borrowings under its credit facility, while
“Adjusted EBITDAX” corresponds to defined terms in the Company’s credit
facility agreement and means net earnings before financing charges,
foreign exchange gain (loss), E&E expense, income taxes, depreciation,
depletion, amortization, other non-cash items of expense and non-
recurring items, adjusted for major acquisitions and material
dispositions assuming that such transactions had occurred on the first
day of the applicable calculation period. As transaction costs are non-
recurring costs, Adjusted EBITDAX has been calculated, excluding
transaction costs, as a meaningful measure of continuing operating cash
flows. For purposes of calculating covenants under the Company’s credit
facility, Adjusted EBITDAX is determined using financial information
from the most recent four consecutive fiscal quarters.

/T/

Financial Outlook Information. The information disclosed in this press release
regarding forecast operating netback and forecast run rate funds from
operations in respect of the Assets, and corporate-level forecast 2017 funds
from operations and adjusted EBITDAX, constitutes financial outlook information
within the meaning of applicable Canadian securities laws. Statements
containing a financial outlook constitute forward-looking information and are
therefore subject to the assumptions, risk factors, limitations and
qualifications set forth under “Forward-Looking Information” above. All such
financial outlook information is made as of the date hereof and is provided for
the sole purpose of describing the Company’s internal expectations as to the
effect of the Acquisition on its cash flows for the stated period. Readers are
cautioned that the financial outlook information contained herein should not be
used, and may be inappropriate for, any other purpose.

– END RELEASE – 23/03/2017

For further information:
Prairie Provident Resources Inc.
Tim Granger
President and Chief Executive Officer
(403) 292-8110
tgranger@ppr.ca
OR
Prairie Provident Resources Inc.
Mimi Lai
Chief Financial Officer
(403) 292-8171
mlai@ppr.ca
www.ppr.ca

COMPANY:
FOR: PRAIRIE PROVIDENT RESOURCES INC.
TSX SYMBOL: PPR

INDUSTRY: Energy and Utilities – Oil and Gas
RELEASE ID: 20170323CC0009

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: TAMARACK VALLEY ENERGY LTD.
TSX SYMBOL: TVE

Date issue: March 23, 2017
Time in: 6:00 AM e

Attention:

CALGARY, ALBERTA–(Marketwired – March 23, 2017) – Tamarack Valley Energy Ltd.
(TSX:TVE) (“Tamarack” or the “Company”) is pleased to announce its financial
and operating results for the three and twelve months ended December 31, 2016,
along with the appointment of Mr. Ian Currie to Tamarack’s Board of Directors.

2016 Financial and Operating Highlights

/T/

— Achieved record Q4/16 average production of 11,453 boe/d, up 6% from

Q3/16 and up 15% over Q4/15, and grew annual average production by 22%
to average 10,344 boe/d in 2016 compared to 8,448 boe/d in 2015.
— Total funds from operations increased 23% to $20.5 million in Q4/16 from
$16.7 million in Q3/16, and increased 10% compared to Q4/15.
— Enhanced financial flexibility by reducing net debt by 47% at year end
2016 compared to year end 2015, and reduced by 17% compared to the
previous quarter, resulting in year end 2016 net debt to Q4 2016
annualized funds from operations of 0.6x, down from 1.3x at year end
2015.
— Improved field efficiencies combined with a continued focus on cost
reductions resulted in production expense declining 9% to $11.64/boe in
2016 compared to $12.81/boe in 2015.
— General and administrative (“G&A”) costs per boe decreased by 17% in
2016 over 2015, declining to $1.95/boe from $2.35/boe, despite higher
activity levels, closing two strategic acquisitions and achieving 22%
growth in production.
— As announced on February 27, 2017, delivered 5% growth per fully diluted
share in proved developed producing reserves (“PDP”), and increased
reserves on an absolute basis by 43% for PDP, 34% for total proved
(“1P”) and 26% for proved plus probable (“2P”) reserves.
— Achieved attractive capital efficiencies through the 2016 development
program, generating a 2P finding and development cost (“F&D”) recycle
ratio of 2.3 times and a 2P finding, development and acquisition cost
(“FD&A”) recycle ratio of 1.5 times based on the 2016 field netback
(excluding hedges) of $16.55/boe. Using the Q4 2016 field netback of
$22.03/boe, generated a 2P F&D recycle ratio of 3.1 times and a 2P FD&A
recycle ratio of 1.9 times.
— Announced the transformative transaction with Spur Resources, Ltd. (the
“Viking Acquisition”) on November 2, 2016, positioning Tamarack as a
Cardium and Viking-focused growth entity with forecast 2017 annual
production between 19,000-20,000 boe/d (approximately 55-60% liquids),
as well as 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 ample liquidity for ongoing development of Tamarack’s high-
netback, light oil-weighted asset base.

/T/

Financial & Operating Results

/T/

Three months ended

December 31,
—————————————————————————-
2016 2015 % change
—————————————————————————-
($, except share numbers)
Total Revenue 39,793,215 27,725,228 44
Funds from operations 20,453,183 18,614,626 10
Per share – basic $ 0.15 $ 0.19 (21)
Per share – diluted $ 0.15 $ 0.19 (21)
Net income (loss) (8,424,255) 5,118,919 (265)
Per share – basic $ (0.06) $ 0.05 (220)
Per share – diluted $ (0.06) $ 0.05 (220)
Net debt (1) (52,316,066) (97,940,880) (47)
Capital Expenditures (2) 12,416,830 10,817,509 (46)
—————————————————————————-
Weighted average shares
outstanding
Basic 137,043,779 99,945,577 37
Diluted 137,043,779 99,945,577 37
—————————————————————————-
Share Trading
High $ 3.89 $ 3.25 20
Low $ 3.00 $ 2.22 35
Trading volume 39,341,999 26,929,737 46
—————————————————————————-
Average daily production
Light oil (bbls/d) 4,858 4,258 14
Heavy oil (bbls/d) 316 620 (49)
NGLs (bbls/d) 1,075 1,218 (12)
Natural gas (mcf/d) 31,226 23,229 34
Total (boe/d) 11,453 9,968 15
—————————————————————————-
Average sale prices
Light oil ($/bbl) 58.71 47.16 24
Heavy oil ($/bbl) 44.60 26.79 66
NGLs ($/bbl) 28.99 18.22 59
Natural gas ($/mcf) 3.27 2.66 23
Total ($/boe) 37.76 30.23 25
—————————————————————————-
Operating netback ($/Boe) (3)
Average realized sales 37.76 30.23 25
Royalty expenses (3.56) (2.80) 27
Production expenses (12.17) (12.20) (0)
—————————————————————————-
Operating field netback ($/Boe)
(3) 22.03 15.23 45
Realized commodity hedging
gain (loss) (0.15) 8.16 (102)
Operating netback 21.88 23.39 (6)
—————————————————————————-
Funds flow from operations
netback ($/Boe) (3) 19.41 20.30 (4)
—————————————————————————-

Years ended

December 31,
—————————————————————————-
2016 2015 % change
—————————————————————————-
($, except share numbers)
Total Revenue 115,516,949 106,145,723 9
Funds from operations 63,567,478 60,161,226 6
Per share – basic $ 0.52 $ 0.66 (21)
Per share – diluted $ 0.52 $ 0.66 (21)
Net income (loss) (27,822,948) (17,328,368) (61)
Per share – basic $ (0.23) $ (0.19) (21)
Per share – diluted $ (0.23) $ (0.19) (21)
Net debt (1) (52,316,066) (97,940,880) (47)
Capital Expenditures (2) 140,777,100 107,431,198 46
—————————————————————————-
Weighted average shares
outstanding
Basic 122,235,231 90,661,207 35
Diluted 122,235,231 90,661,207 35
—————————————————————————-
Share Trading
High $ 4.28 $ 4.80 (11)
Low $ 2.16 $ 1.83 18
Trading volume 122,074,351 94,324,264 29
—————————————————————————-
Average daily production
Light oil (bbls/d) 4,215 3,703 14
Heavy oil (bbls/d) 363 602 (40)
NGLs (bbls/d) 1,035 803 29
Natural gas (mcf/d) 28,388 20,038 42
Total (boe/d) 10,344 8,448 22
—————————————————————————-
Average sale prices
Light oil ($/bbl) 50.53 52.06 (3)
Heavy oil ($/bbl) 35.45 41.98 (16)
NGLs ($/bbl) 20.74 19.49 6
Natural gas ($/mcf) 2.41 2.85 (15)
Total ($/boe) 30.51 34.43 (11)
—————————————————————————-
Operating netback ($/Boe) (3)
Average realized sales 30.51 34.43 (11)
Royalty expenses (2.32) (3.43) (32)
Production expenses (11.64) (12.81) (9)
—————————————————————————-
Operating field netback ($/Boe)
(3) 16.55 18.19 (9)
Realized commodity hedging
gain (loss) 3.25 5.67 (43)
Operating netback 19.80 23.86 (17)
—————————————————————————-
Funds flow from operations
netback ($/Boe) (3) 16.79 19.51 (14)
—————————————————————————-

/T/

Notes:

/T/

(1) Net debt does not have any standard meaning prescribed by International

Financial Reporting Standards (“IFRS”) and therefore may not be
comparable with the calculation of similar measures for other entities.
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.
(2) Capital expenditures include property acquisitions and are presented net
of disposals, but exclude corporate acquisitions.
(3) Operating netback, operating field netback and funds flow from
operations netback does not have any standardized meaning prescribed by
IFRS and therefore may not be comparable with the calculation of similar
measures for other entities. 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 it demonstrates its field level profitability relative to
current commodity prices.

/T/

2016 In Review

This past year was one of true transformation and unprecedented growth for
Tamarack, demonstrating continued success in the execution of its strategy
while navigating through another challenging year for commodity markets. The
Company increased annual production volumes by 22% to 10,344 boe/d (54%
liquids), compared to 8,448 boe/d in 2015 as a direct result of higher
production volumes from its successful 2016 drilling program, capital
efficiencies that exceeded expectations, and the impact of the strategic Penny
and Redwater / Wilson Creek acquisitions that closed in July. Tamarack achieved
record production of 11,453 boe/d during the fourth quarter of 2016, a 6%
increase over the 10,790 boe/d produced in the third quarter of 2016, and
higher than the Company’s target 2016 exit rate of 11,000 boe/d.

Year-end 2016 net debt totaled $52 million, a reduction of $46 million from
year-end 2015, resulting in a net debt to fourth quarter 2016 annualized funds
from operations ratio of 0.6 times, a significant improvement over the 1.5
times ratio at December 31, 2015. Tamarack’s debt reduction focus during the
first half of 2016 positioned the Company to close two key acquisitions in July
of 2016, which added approximately 1,900 boe/d of predominantly light oil and
natural gas liquids production. The first was comprised of a producing, light
oil pool at Penny (the “Penny Acquisition”) in southern Alberta, and the second
was the consolidation of assets with significant key infrastructure at
Redwater/Wilson Creek (the “Redwater / Wilson Creek Acquisition”). The assets
acquired through these transactions outperformed during 2016, producing 25%
more to date than originally forecast with decline rates much shallower than
expected. In addition, after investing approximately $90 million in 2016 on
these assets ($84 million for the acquisition and approximately $6 million for
capital), the independent year end 2016 reserves evaluation reflected $110
million of PDP before-tax net present value of future net revenue (discounted
at 10%) (“NPV10BT”) and $247 million of 2P NPV10BT value, increases of 1.2 and
2.7 times, respectively.

The Company’s strong balance sheet and previous experience with Viking oil in
Alberta, set the stage for the Viking Acquisition which closed on January 11,
2017, and elevated Tamarack to the position of an intermediate producer and one
of the largest land bases within the Saskatchewan / Alberta light oil Viking
fairway. The Viking Acquisition, similar to each of the Company’s transactions
completed to date, incorporates Tamarack’s strategy of adding high-quality,
oil-weighted assets which, on a half cycle basis, can achieve a capital cost
payout of 1.3 years or less while maintaining balance sheet flexibility. The
Company’s inventory of identified, high-quality drilling locations that pay out
in 1.5 years or less at current strip prices now totals over 800 net locations,
fueling longer-term organic growth with forecast production and cash flow per
share growth anticipated in 2017 and beyond. The actions and strategic
decisions Tamarack made during 2016 have contributed to securing the Company’s
long-term future sustainability and financial flexibility, while clearly
demonstrating the strength of Tamarack’s unique returns-based growth model.

Operational Update

To date in the first quarter of 2017, Tamarack is pleased to confirm that it
has drilled 35 (32.1 net) horizontal Viking light oil wells, 8 (7.3 net)
extended reach horizontal Cardium light oil wells, 3 (3.0 net) heavy oil wells
in Hatton and one net Notikewin liquids-rich natural gas well. This is the most
active quarter in the Company’s history for drilling and capital activity, and
Tamarack is pleased with the operational and safety performance the team has
achieved thus far. Of these wells, a total of 27 (25.1 net) new wells are
currently on production, which includes 22 (20.5 net) horizontal Viking light
oil wells, 3 (2.6 net) extended reach horizontal Cardium light oil wells, one
net heavy oil well in Hatton and one net Notikewin liquids-rich natural gas
well. Production additions from each of these new wells are contributing to the
Company’s current production of approximately 19,750 boe/d and Tamarack remains
on target to meet its average first half production guidance range of 18,500 to
19,000 boe/d.

Tamarack anticipates completing its first half drilling program early in the
second quarter, pending surface access, by fracture stimulating and equipping
for production the remaining 20 (18.3 net) wells, bolstering the Company’s
positive production momentum through the first half of 2017.

New Board Member Appointment

Tamarack is pleased to announce the appointment of Mr. Ian Currie to its Board
of Directors. Mr. Currie is a professional engineer with over 30 years of oil
and gas experience, and is currently the President and CEO of Spur Petroleum
Ltd., a privately-held oil and gas exploration and production company.
Previously he served as President and CEO of Spur Resources, Ltd. from 2006
until its acquisition by Tamarack in January, 2017. Prior thereto, he was Vice
President, Operations at Profico Energy Management from its inception in 2000
until its acquisition in 2006, and held senior operational roles with
Renaissance Energy Ltd. since 2002.

Tamarack also confirmed it has filed its Annual Information Form (“AIF”) today
on SEDAR, which includes information pursuant to the requirements of National
Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities (“NI
51-101”) of the Canadian Securities Administrators relating to reserves data
and other oil and gas information. In addition, the AIF contains a pro-forma
summary of the Viking Acquisition reserves evaluation with an effective date of
January 31, 2017, combined with a modified look-ahead summary performed by GLJ
Petroleum Consultants, Ltd (“GLJ”) on Tamarack’s year end 2016 reserves
effective January 31, 2017. The AIF can be accessed either on Tamarack’s
website at www.tamarackvalley.ca or under the Company’s profile on SEDAR at
www.sedar.com.

The Company has also filed its audited consolidated financial statements for
the year ended December 31, 2016 (“Financial Statements”) and management’s
discussion and analysis (“MD&A”) on SEDAR. Selected financial and operational
information is outlined above and should be read in conjunction with the
Financial Statements, which were prepared in accordance with IFRS, and the
related MD&A. These documents are also accessible on Tamarack’s website at
www.tamarackvalley.ca or under the Company’s profile on SEDAR at www.sedar.com.

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 development oil locations in the
Pembina, Wilson Creek, Garrington and Lochend Cardium fairway and the Redwater
shallow Viking play in Alberta. With a balanced portfolio and an experienced
and committed management team, Tamarack intends to continue to deliver on its
promise to maximize shareholder return 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
Mboe thousands barrels of oil equivalent
mcf thousand cubic feet
MMcf million cubic feet
Mbbls million barrels
mcf/d thousand cubic feet per day

/T/

Unit Cost Calculation

For the purpose of calculating unit costs, natural gas volumes have been
converted to a barrel of oil equivalent (“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 Canadian Securities Regulators’ NI 51-101. Boe’s may
be misleading, particularly if used in isolation.

Drilling Locations

In this Press Release, the 800 net drilling locations identified include 283
proved locations, 507 proved and probable locations and 293 un-booked
locations. Proved locations and probable locations account for drilling
locations that have associated proved and/or probable reserves, as applicable.
Un-booked locations are internal estimates based on prospective acreage and an
assumption as to the number of wells that can be drilled per section based on
industry practice and internal review. Un-booked locations do not have
attributed reserves or resources. While certain of the un-booked drilling
locations have been de-risked by drilling existing wells in relative close
proximity to such un-booked drilling locations, the majority of un-booked
drilling locations are farther away from existing wells where management has
less information about the characteristics of the reservoir and therefore there
is more uncertainty whether wells will be drilled in such locations and, if
drilled, there is more uncertainty that such wells will result in additional
oil and gas reserves, resources or production.

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 forecast 2017 annual production range and liquid
weighting percentage, first half 2017 production guidance and timing of
completion of first half 2017 drilling program. The forward-looking statements
contained in this document are based on certain key expectations and
assumptions made by Tamarack relating to prevailing commodity prices, the
availability of drilling rigs and other oilfield services, the cost of such
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, 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 to it, 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 (e.g. operational
risks in development, exploration and production; 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 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.

– END RELEASE – 23/03/2017

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

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

INDUSTRY: Energy and Utilities – Oil and Gas
RELEASE ID: 20170323CC0005

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: TAMARACK VALLEY ENERGY LTD.
TSX SYMBOL: TVE

Date issue: March 23, 2017
Time in: 6:00 AM e

Attention:

CALGARY, ALBERTA–(Marketwired – March 23, 2017) – Tamarack Valley Energy Ltd.
(TSX:TVE) (“Tamarack” or the “Company”) is pleased to announce it has filed
today, March 23, 2017, with Canadian securities authorities its 2016 disclosure
documents. Included in the Canadian filings were Tamarack’s Annual Information
Form (“AIF”), including disclosure and reports related to reserves data and
other oil and gas information pursuant to Section 2.1 of National Instrument
51-101; its Financial Statements; and its related Management’s Discussion and
Analysis for the year ended December 31, 2016.

Tamarack’s previously disclosed reserves summary issued on February 27, 2017
did not include the impact of the transformative Spur Resources Ltd.
acquisition which closed subsequent to year end on January 11, 2017 (the
“Viking Acquisition”). Included within the AIF is a pro-forma summary of the
Viking Acquisition reserves evaluation (“Viking Acquisition Reserves Report”)
with an effective date of January 31, 2017, combined with a modified look-ahead
summary performed by GLJ Petroleum Consultants, Ltd (“GLJ”) on Tamarack’s year
end 2016 reserves effective January 31, 2017 (the “Pro-Forma Reserves Report”).
Please see “Information Regarding Disclosure on Oil and Gas Reserves” below.

Pro-Forma Reserves Report Highlights:

/T/

— 81.5 mmboe of Proved plus probable (“2P”) reserves, 47.7 mmboe of total

proved (“1P”) and 30.2 mmboe of proved developed producing (“PDP”)
reserves (all reserves are Company Interest);
— $1.03 billion of net present value of future net revenue discounted at
10% (before tax) (“NPV10 BT) for 2P reserves, $607 million for 1P and
$431 million for PDP;
— Pro-forma debt, after giving effect to the Viking Acquisition at
December 31, 2016, of $128 million represents a draw of only 42% on
Tamarack’s $220 million credit facility, providing ample liquidity to
continue developing its Viking and Cardium oil focused assets;
— Based on pro-forma production at January 11, 2017, of approximately
18,000 boe/d, Tamarack’s 2P Reserve Life Index totals 12.4 years;
— Booked proved undeveloped drilling locations on a 1P and 2P basis were
283, and 507, respectively relative to the more than 800 identified
locations that pay out in 1.5 years or greater at current commodity
prices, demonstrating the long-term sustainability and potential future
upside in Tamarack’s asset base.

/T/

Pro-Forma Reserves Report Data (Forecast Prices and Costs) – Company Interest

/T/

SUMMARY OF PRO-FORMA OIL AND GAS RESERVES AS OF JANUARY 31,
2017
FORECAST PRICES AND COSTS
RESERVES
————————————————————
LIGHT & MEDIUM CRUDE CONVENTIONAL NATURAL
OIL HEAVY CRUDE OIL GAS(1)
————————————————————
Gross Net Gross Net Gross Net
(Mbbls) (Mbbls) (Mbbls) (Mbbls) (Mmcf) (Mmcf)
————————————————————
PROVED:
Developed
Producing 13,171 11,531 417 352 81,865 72,663
Developed Non-
Producing 56 54 92 83 1,945 1,669
Undeveloped 9,669 8,577 182 140 35,023 32,176
————————————————————
TOTAL PROVED 22,896 20,163 691 574 118,833 106,508
PROBABLE 16,636 14,601 547 414 80,255 71,804
————————————————————
TOTAL PROVED
PLUS PROBABLE 39,531 34,764 1,239 988 199,088 178,312
————————————————————
————————————————————

SUMMARY OF PRO-FORMA OIL AND GAS RESERVES AS OF JANUARY 31,
2017
FORECAST PRICES AND COSTS
RESERVES
————————————————————
NATURAL GAS LIQUIDSTOTAL OIL EQUIVALENT
————————————————————
Gross Net Gross Net
(Mbbls) (Mbbls) (Mboe) (Mboe)
————————————————————
PROVED:
Developed
Producing 2,969 2,420 30,201 26,413
Developed Non-
Producing 12 8 485 423
Undeveloped 1,312 1,198 17,001 15,278
————————————————————
TOTAL PROVED 4,294 3,626 47,686 42,114
PROBABLE 3,241 2,794 33,800 29,775
————————————————————
TOTAL PROVED
PLUS PROBABLE 7,535 6,419 81,486 71,890
————————————————————
————————————————————
(1) Immaterial CBM volumes have been included in Conventional Natural Gas.

/T/

Pro-Forma Net Present Values of Future Net Revenue Before Tax (Forecast Prices
and Costs)

/T/

PRO-FORMA NET PRESENT VALUES OF FUTURE NET
REVENUE
BEFORE INCOME TAXES DISCOUNTED AT (%/year)
———————————————
RESERVES 0% 5% 10%
CATEGORY ($000s) ($000s) ($000s)
———————————————
PROVED:
Developed
Producing 698,753 520,506 431,063
Developed Non-
Producing 5,520 4,107 3,396
Undeveloped 297,424 233,401 172,847
———————————————
TOTAL PROVED 1,001,697 758,014 607,306
PROBABLE 939,484 601,454 417,704
———————————————
TOTAL PROVED
PLUS PROBABLE 1,941,180 1,359,468 1,025,011
———————————————
———————————————

PRO-FORMA NET PRESENT VALUES OF FUTURE NET REVENUE
BEFORE INCOME TAXES DISCOUNTED AT (%/year)
————————————————————
Unit Value Unit Value
Before Income Before Income
Tax Discounted Tax Discounted
at 10% Per at 10% Per
RESERVES 15% 20% Year(1) Year(1)
CATEGORY ($000s) ($000s) ($/Boe) ($/Mcfe)
————————————————————
PROVED:
Developed
Producing 373,614 332,414 16.32 2.72
Developed Non-
Producing 2,929 2,573 8.03 1.34
Undeveloped 127,297 93,876 11.31 1.89
————————————————————
TOTAL PROVED 503,839 428,863 14.42 2.4
PROBABLE 307,596 236,535 14.03 2.34
————————————————————
TOTAL PROVED
PLUS PROBABLE 811,435 665,398 14.26 2.38
————————————————————
————————————————————

/T/

Copies of the filed documents may be obtained through SEDAR at www.sedar.com or
on Tamarack’s website at www.tamarackvalley.ca.

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 in the Cardium and Viking fairways primarily in Alberta that
are economic at a variety 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 return 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
Mboe thousands barrels of oil equivalent
mcf thousand cubic feet
MMcf million cubic feet
Mbbls thousand barrels
mcf/d thousand cubic feet per day

/T/

Unit Cost Calculation

For the purpose of calculating unit costs, natural gas volumes have been
converted to a barrel of oil equivalent (“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 Canadian Securities Regulators’ NI 51-101. Boe’s may
be misleading, particularly if used in isolation.

Drilling Locations

In this Press Release, the 800 net drilling locations identified include 283
proved locations, 507 proved and probable locations and 293 un-booked
locations. Proved locations and probable locations account for drilling
locations that have associated proved and/or probable reserves, as applicable.
Un-booked locations are internal estimates based on prospective acreage and an
assumption as to the number of wells that can be drilled per section based on
industry practice and internal review. Un-booked locations do not have
attributed reserves or resources. While certain of the un-booked drilling
locations have been de-risked by drilling existing wells in relative close
proximity to such un-booked drilling locations, the majority of un-booked
drilling locations are farther away from existing wells where management has
less information about the characteristics of the reservoir and therefore there
is more uncertainty whether wells will be drilled in such locations and, if
drilled, there is more uncertainty that such wells will result in additional
oil and gas reserves, resources or production.

Information Regarding Disclosure on Oil and Gas Reserves

The information above provides a summary of the pro-forma combination of
Tamarack and the Viking Acquisition. GLJ conducted a modified look ahead
summary (the “Modified Look Ahead Summary”) on its reserve report as at
December 31, 2016, in which the December 31, 2016 report was mechanically
updated to January 31, 2017 utilizing 3 Consultants’ Average January 1, 2017
pricing. The mechanical update, or “look ahead” was slightly modified so as to
include the conversion of existing reserves entities from undeveloped to
producing or developed non-producing reserves categories to reflect January
2017 activity. Three Cardium wells in Wilson Creek were converted from proved
undeveloped (“PUD”) to proved developed producing (“PDP”) and one Cardium well
in Alder Flats was converted from probable undeveloped (“PBUD”) to probable
developed non-producing (“PBDNP”). No changes were made to technical reserves
volumes or production forecasts for these entities, only their development and
production status category, timing and capital costs were adjusted to reflect
January 2017 activity. The Modified Look Ahead Summary was combined with the
Viking Acquisition Reserves Report, to generate the Pro-Forma Reserves Report
effective January 31, 2017. Readers are cautioned that the Pro-Forma Reserves
Report is comprised of a manual summation of two independently evaluated
reserves reports prepared in accordance with procedures and standards contained
in COGEH and with the reserves definitions contained in COGEH and NI 51-101,
but with two different effective dates, and that the Modified Look Ahead
Summary is a simplified measure that is not consistent with a full reserves
evaluation.

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. More particularly, statements relating to
“reserves” are deemed to be forward-looking statements, as they involve the
implied assessment, based on certain estimates and assumptions, that the
resources and reserves described can be profitably produced in the future. The
forward-looking statements contained in this document are based on certain key
expectations and assumptions made by Tamarack relating to prevailing commodity
prices, the availability of drilling rigs and other oilfield services and
associated cost of such 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, 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 to it,
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 (e.g. operational
risks in development, exploration and production; 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 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.

– END RELEASE – 23/03/2017

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

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

INDUSTRY: Energy and Utilities – Oil and Gas
RELEASE ID: 20170323CC0006

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.