Chinook Energy Inc. Announces Its December 31, 2015 Reserves and Provides Operations Update

CALGARY, ALBERTA–(Marketwired – Feb. 8, 2016) – Chinook Energy Inc. (“Chinook” or the “Company”) (TSX:CKE) today announced the results of its year-end reserve evaluation effective December 31, 2015 as prepared by its independent evaluator. The Company has also provided an operations update.

Chinook’s audit of its 2015 annual consolidated financial statements is not yet complete and accordingly all financial amounts referred to in this news release are unaudited and represent management’s estimates. Readers are advised that these financial estimates are subject to audit and may be subject to change as a result.

Operational Update and Unaudited 2015 Year-End Results

Chinook’s average daily production for fiscal year 2015 was 5,637 boe/d. Average production for the fourth quarter of 2015 was 3,928 boe/d and the Company exited 2015 at approximately 4,472 boe/d. Projected funds from operations for 2015 is estimated at $9 million or $0.04 per weighted average basic common share outstanding. Chinook exited 2015 undrawn on its $50 million credit facility and with an approximate $30 million working capital surplus.

During 2015, Chinook focused on the development of its Montney acreage at Birley/Umbach in northeastern British Columbia. Chinook also had net dispositions of $42.1 million, before closing adjustments, of non-strategic Canadian assets representing approximately 932 boe/d.

During 2015, Chinook drilled 3 (2.75 net) horizontal wells in the Birley/Umbach area of northeastern British Columbia, targeting liquids-rich natural gas in the Montney. The first well, a-73-L (0.75 net), was drilled and completed in the first quarter and commenced production late in March 2015 at initial rates of approximately 4.0 mmcf/d and 150 bbls of free condensate per day (817 boe/d). The well has been on production for 138 days during which it has averaged approximately 3.2 mmcf/d and 63 bbls of free condensate per day (596 boe/d). Two additional horizontal wells (2.0 net) at b-4-K/94-H-3 and c-37-K/94-H-3 were drilled during the first quarter and completed in the third quarter. A fourth horizontal well, b-72-F/94-H3 (0.75 net), which was drilled during the fourth quarter of 2014 was also completed during the third quarter of 2015. During 2015, Chinook completed the majority of the 25 mmcf/d expansion of the Birley/Umbach facility.

Chinook will commence production from its new 25 mmcf/d A-72-F compression facility at Birley later this week with transition of its current 5.9 mmcf/d (4.4 mmcf/d net) raw throughput from the original compression facility at D-72-F and incremental raw production of 13.5 mmcf/d (12.4 mmcf/d net) estimating throughput of approximately 19.4 mmcf/d (16.8 mmcf/d net). Capacity at the Birley compressor site from this expansion will be approximately 34 mmcf/d. With the incremental production at Birley, Chinook anticipates corporate production to be approximately 7,000 boe/d.

2015 Independent Reserves Evaluation

McDaniel & Associates Consultants Ltd. (“McDaniel”) evaluated all of Chinook’s properties effective December 31, 2015 pursuant to a report dated February 8, 2016. The independent reserve evaluation was prepared in accordance with the definitions, standards and procedures contained in the Canadian Oil and Gas Evaluation Handbook (“COGE Handbook”) and National Instrument 51-101 (“NI 51-101”). The reserve evaluation was based on McDaniel’s forecast pricing and foreign exchange rates at December 31, 2015. The Reserves, Safety and Environmental Committee of the Board and the Board of Directors of Chinook have reviewed and approved the evaluation prepared by the evaluator.

Reserves included herein are stated on a Company gross basis (working interest before deduction of royalties and without including any royalty interests) unless noted otherwise. This news release contains several cautionary statements that are specifically required by NI 51-101 under the heading “Reader Advisory” and throughout the release. In addition to the information contained in this news release more detailed reserves information will be included in Chinook’s Annual Information Form for the year ended December 31, 2015, which will be filed on SEDAR at www.sedar.com in March 2016.

Reserves Breakdown (Company gross) ⁽¹⁾
(December 31, 2015, McDaniel price forecast)

(mboe)	2015	2014
Proved Producing
Total proved producing	8,893	13,589

Proved
Total proved	19,182	17,947

Proved Plus Probable
Total proved plus probable	30,634	27,383

Note:
(1)	Gross reserves are the Company’s working interest reserves before royalty deductions and do not include royalty interest volumes.

Company Gross and Net Reserves as at December 31, 2015

The following table summarizes the Company’s gross and net reserve volumes utilizing McDaniel’s forecast pricing and cost estimates at December 31, 2015.

		Light and medium oil		Heavy oil		Conventional Natural Gas		Natural gas liquids		Oil equivalent (6:1)
Reserves category		Gross ⁽¹⁾ (mbbl)	Net ⁽²⁾ (mbbl)	Gross ⁽¹⁾ (mbbl)	Net ⁽²⁾ (mbbl)	Gross ⁽¹⁾ (mmcf)	Net ⁽²⁾ (mmcf)	Gross ⁽¹⁾ (mbbl)	Net ⁽²⁾ (mbbl)	Gross ⁽¹⁾ (mboe)	Net ⁽²⁾ (mboe)
Total company
Proved
	Developed producing	1,624	1,419	44	44	38,675	34,210	779	581	8,893	7,745
	Developed non-producing	181	166	13	13	23,966	20,053	688	534	4,877	4,055
	Undeveloped	483	437	0	0	24,700	20,878	813	687	5,413	4,605
Total proved		2,288	2,023	57	56	87,341	75,141	2,280	1,802	19,182	16,405
Probable		1,159	926	33	32	52,644	43,807	1,486	1,159	11,452	9,419
Total proved plus probable		3,447	2,949	91	89	139,985	118,948	3,766	2,961	30,634	25,824

Note:
(1)	Gross reserves are the Company’s working interest reserves before royalty deductions and do not include royalty interest volumes.
(2)	Net reserves are after royalty deductions and include royalty interest volumes.
(3)	Columns may not add due to rounding.


Company Gross Reserve Reconciliation for 2015
(Company gross reserves before deduction of royalties payable)

	6:1 Oil Equivalent (mboe)
	Total Proved		Probable		Proved Plus Probable
December 31, 2014 – opening balance	17,947		9,437		27,383
Additions and extensions	3,286		4,294		7,580
Acquisitions	–		–		–
Dispositions	(1,439	)	(727	)	(2,166	)
Technical revisions	2,547		(698	)	1,849
Economic factors	(1,101	)	(855	)	(1,955	)
Production	(2,058	)	–		(2,058	)
December 31, 2015 – closing balance	19,182		11,452		30,634

Note:
(1)	Columns may not add due to rounding.

During 2015, Chinook completed the sale of petroleum and natural gas properties including undeveloped lands located in the Karr area of northwestern Alberta, in addition to other minor dispositions, acquisitions and customary closing adjustments, for net proceeds of $42.1 million. Dispositions within the Company’s Grande Prairie operating district represented the majority of the proved plus probable reserve reductions of approximately 2.2 mmboe.

Year over year, McDaniel recorded net positive technical revisions related to performance of approximately 1.8 mmboe on a proved plus probable reserves basis.

A downward adjustment in the independent price forecast for both natural gas and North American crude oil, partially offset by improvements in operating costs, resulted in net negative revisions due to economic factors totaling 2.0 mmboe on proved and probable reserves.

Of particular note, Chinook added a total of 7.6 mmboe on a proved plus probable basis. The additions are focused in the Company’s core Montney area of Birley/Umbach, British Columbia.

Reserve Life Index (“RLI”)

As at December 31, 2015, Chinook’s proved plus probable RLI was 18.8 years based upon the McDaniel reserves report and the Company’s annualized December 2015 production volumes, while its proved RLI was 11.8 years. The following table summarizes the RLI:

Proved
	Reserves (mboe)	19,182
	December 2015 production (mboe) ⁽¹⁾	1,627
	Reserve life index (years)	11.8

Proved Plus Probable
	Reserves (mboe)	30,634
	December 2015 production (mboe) ⁽¹⁾	1,627
	Reserve Life Index (years)	18.8

Note:
⁽¹⁾	December 2015 production excludes volumes that were disposed of in the same month and are net of shut-in volumes.

Net Present Value (“NPV”) Summary (before tax) as at December 31, 2015

(December 31, 2015, McDaniel price forecast)

Benchmark oil and NGL prices used are adjusted for quality of oil or NGL produced and for transportation costs. The calculated NPVs include a deduction for estimated future well abandonment and reclamation but do not include a provision for interest, debt service charges and general and administrative expenses. It should not be assumed that the NPV estimate represents the fair market value of the reserves.

($ thousands)	Undiscounted	Discounted at 5%	Discounted at 10%	Discounted at 15%	Discounted at 20%
Proved developed producing	127,787	100,552	82,720	70,443	61,571
Proved developed non-producing	44,236	35,284	28,933	24,325	20,882
Total proved developed	172,023	135,836	111,653	94,767	82,453
Proved undeveloped	52,344	29,510	16,716	8,796	3,556
Total proved	224,367	165,345	128,369	103,563	86,009
Probable additional	194,041	110,463	70,385	48,466	35,251
Total proved plus probable	418,408	275,809	198,753	152,029	121,261

Net Present Value Summary (after tax) as at December 31, 2015

(December 31, 2015, McDaniel price forecast)

The after-tax NPV of Chinook’s oil and natural gas properties reflects the tax burden on the properties on a stand-alone basis and does not consider the business-entity-level tax situation, or tax planning. It does not provide an estimate of the value at the level of the business entity, which may be significantly different. The financial statements and the management’s discussion and analysis of Chinook should be consulted for information at the level of the business entity.

($ thousands)	Undiscounted	Discounted at 5%	Discounted at 10%	Discounted at 15%	Discounted at 20%
Proved developed producing	127,787	100,552	82,720	70,443	61,571
Proved developed non-producing	44,236	35,284	28,933	24,325	20,882
Total proved developed	172,023	135,836	111,653	94,767	82,453
Proved undeveloped	52,344	29,510	16,716	8,796	3,556
Total proved	224,367	165,345	128,369	103,563	86,009
Probable additional	194,041	110,463	70,385	48,466	35,251
Total proved plus probable	418,408	275,809	198,753	152,029	121,261

McDaniel & Associates Consultants Ltd. Price Forecast as at December 31, 2015 ⁽¹⁾

	WTI Crude Oil (US$/bbl)	Edmonton Light Crude Oil (Cdn$/bbl)	Henry Hub Natural Gas (US$/mmbtu)	AECO Natural Gas (Cdn$/mmbtu)	British Columbia Average Plantgate Gas (Cdn$/mmbtu)	Edmonton Condensate and Natural Gasoline (Cdn$/bbl)	Ethane (Cdn$/bbl)	Propane (Cdn$/bbl)	Butane (Cdn$/bbl)	US/Cdn Exchange (US$/Cdn$)
2016	45.00	56.60	2.50	2.70	2.10	60.60	10.00	10.60	35.20	0.730
2017	53.60	66.40	2.95	3.20	2.60	70.50	12.00	18.00	41.30	0.750
2018	62.40	72.80	3.40	3.55	3.15	77.00	13.40	25.90	48.00	0.800
2019	69.00	80.90	3.70	3.85	3.45	85.10	14.60	30.30	56.30	0.800
2020	73.10	83.20	3.90	3.95	3.55	87.50	15.00	31.20	61.00	0.825
Average	60.62	71.98	3.29	3.45	2.97	76.14	13.00	23.20	48.36	0.781

Note:
⁽¹⁾	Prices escalate at two percent per year after 2020.

The above pricing table was utilized by McDaniel in their evaluation of Chinook’s reserves as at December 31, 2015. When compared to the December 31, 2014 price forecast, commodity pricing for the year 2016 has decreased for Edmonton Light Crude Oil, AECO Natural Gas and British Columbia Average Plantgate Gas by 32%, 33% and 43% respectively.

Future Development Costs (“FDC”)

Changes in forecast FDC occur annually as a result of development activities, acquisition and disposition activities and capital cost estimates that reflect the independent evaluator’s best estimate of what it will cost to bring the proved undeveloped and probable reserves on production using forecast prices and costs.

($ millions)
	2015	2014
Total proved	61.8	42.6

Total proved plus probable	95.0	71.0

NI 51-101 Finding and Development Costs (“F&D”)

NI 51-101 requires that finding and development costs be calculated including changes in undiscounted FDC. Chinook’s F&D costs, calculated in accordance with NI 51-101 are set forth below. Comparative F&D costs for 2014 and 2013 set forth in the tables below, including Chinook’s three-year average F&D costs, do not include F&D costs associated with its former business operations in Tunisia. It is worth noting that Chinook incurred $16.5 million related to the construction of its facility expansion in its core area of Birley/Umbach during 2015.

Total Finding and Development Costs (Proved Reserves) ($ thousands, except per unit amounts)	2015	2014	2013	Three-Year Total
Exploration and development costs excluding acquisitions and dispositions(unaudited) ⁽¹⁾	44,281	77,542	40,120	161,942
Net change from previously allocated future development capital	25,618	6,820	8,732	41,170
Total exploration and development costs including the net change in FDC	69,899	84,362	48,851	203,112
Reserve additions excluding acquisitions and dispositions (mboe)	4,732	3,473	1,088	9,293
NI 51-101 total proved finding and development costs (per boe)	14.77	24.29	44.91	21.86

Total Finding and Development Costs (Proved plus Probable Reserves) ($ thousands, except per unit amounts)	2015	2014	2013	Three-Year Total
Exploration and development costs excluding acquisitions and dispositions(unaudited) ⁽¹⁾	44,281	77,542	40,120	161,942
Net change from previously allocated future development capital	30,530	19,910	(8,170)	42,270
Total exploration and development costs including the net change in FDC	74,811	97,452	31,950	204,213
Reserve additions excluding acquisitions and dispositions (mboe)	7,474	4,797	(1,402)	10,868
NI 51-101 total proved plus probable finding and development costs (per boe)	10.01	20.32	(22.78)	18.79

Note:
⁽¹⁾	Excludes non-cash costs, including decommissioning liabilities.

All-In Finding, Development and Acquisition Costs

NI 51-101 specifies how F&D costs should be calculated if they are reported. Essentially NI 51-101 requires that exploration and development costs incurred in the year along with the change in estimated FDC be aggregated and then divided by the applicable reserve additions. The calculation specifically excludes the effects of acquisition and dispositions on both reserves and costs. By excluding acquisitions and dispositions, the Company believes that the provisions of NI 51-101 may not fully reflect the Company’s ongoing reserve replacement costs. Since acquisitions and dispositions can have an impact on the Company’s annual reserve replacement costs, excluding these amounts could result in an inaccurate portrayal of the Company’s costs. Accordingly, the Company also provides “all-in” F&D costs that incorporate all acquisitions net of any dispositions in the year.

All-In Finding, Development and Acquisition Cost Including FDC, Acquisitions, Dispositions and Revisions (Proved Reserves) ($ thousands, except per unit amounts)	2015	2014	2013	Three-Year Total
Exploration and development costs including acquisitions and dispositions(unaudited) ⁽¹⁾	6,477	63,358	26,133	95,968
Net change from previously allocated future development capital	19,178	5,890	8,646	33,714
Total exploration and development costs including the net change in FDC	25,656	69,247	34,779	129,682
Reserve additions including acquisitions, dispositions and revisions (mboe)	3,293	4,824	(47)	8,070
All-in total proved finding, development and acquisition costs (per boe)	7.79	14.36	(745.45)	16.07

All-In Finding, Development and Acquisition Cost Including FDC, Acquisitions, Dispositions and Revisions (Proved plus Probable Reserves) ($ thousands, except per unit amounts)	2015	2014	2013	Three-Year Total
Exploration and development costs including acquisitions and dispositions (unaudited) ⁽¹⁾	6,477	63,358	26,133	95,968
Net change from previously allocated future development capital	24,054	13,581	(9,282)	28,354
Total exploration and development costs including the net change in FDC	30,532	76,939	16,851	124,322
Reserve additions including acquisitions, dispositions and revisions (mboe)	5,308	5,191	(3,115)	7,384
All-in total proved plus probable finding and development costs (per boe)	5.75	14.82	(5.41)	16.84

Note:
⁽¹⁾	Excludes non-cash costs, including decommissioning liabilities.

Total exploration and development costs incurred in the most recent financial year and the change during that year in estimated future development costs, generally will not reflect the total cost of reserve additions in that year.

Recycle Ratio

The recycle ratio is calculated as the annual netback per barrel divided by the non-adjusted F&D costs set forth above. The recycle ratio is comparing the netback from existing reserves to the cost of finding new reserves and may not accurately indicate investment success unless the replacement reserves are of equivalent quality as the produced reserves.

Total Proved
Operating netback before commodity price contracts ($/boe)(unaudited) ⁽¹⁾	8.24
51-101 F&D costs ($/boe)(unaudited)	14.77
Recycle ratio	0.6x

Total Proved Plus Probable
Operating netback before commodity price contracts ($/boe)(unaudited) ⁽¹⁾	8.24
51-101 F&D costs ($/boe)(unaudited)	10.01
Recycle ratio	0.8x

Note:
⁽¹⁾	Operating netback is calculated by deducting royalties and net production expenses from revenue.

Presented below is the recycle ratio as calculated by using the annual netback per barrel divided by the calculated all-in finding, development and acquisition costs (excluding abandonment and furniture and fixtures) and including the effects of revisions.

Total Proved
Operating netback before commodity price contracts ($/boe)(unaudited) ⁽¹⁾	8.24
All-in F&D costs ($/boe)(unaudited)	7.79
Recycle ratio	1.1x

Total Proved Plus Probable
Operating netback before commodity price contracts ($/boe)(unaudited) ⁽¹⁾	8.24
All-in F&D costs ($/boe)(unaudited)	5.75
Recycle ratio	1.4x

Note:
⁽¹⁾	Operating netback is calculated by deducting royalties and net production expenses from revenue.

Corporate Net Asset Value

The Company’s net asset value as of December 31, 2015 is detailed in the following table. This net asset value determination is a “point-in-time” measurement and does not take into account the possibility of Chinook being able to recognize additional reserves through successful future capital investment in its existing properties beyond those included in the 2015 year-end reserve reports.

December 31, 2015	Before Tax NPV 5%		Before Tax NPV 10%		Before Tax NPV 15%
	($ thousands)	$/share	($ thousands)	$/share	($ thousands)	$/share

Proved developed producing reserves NPV ⁽¹⁾⁽²⁾	100,552	0.47	82,720	0.38	70,443	0.33
Total proved reserves NPV ⁽¹⁾⁽²⁾	165,345	0.77	128,369	0.60	103,563	0.48
Proved plus probable reserves NPV ⁽¹⁾⁽²⁾	275,809	1.28	198,753	0.92	152,029	0.71
Undeveloped acreage ⁽³⁾	27,684	0.13	27,684	0.13	27,684	0.13
Net surplus ⁽⁴⁾	29,614	0.14	29,614	0.14	29,614	0.14
Net asset value (basic) ⁽⁵⁾⁽⁶⁾	333,107	1.55	256,051	1.19	209,327	0.97

	After Tax NPV 5%		After Tax NPV 10%		After Tax NPV 15%
	($ thousands)	$/share	($ thousands)	$/share	($ thousands)	$/share

Proved developed producing reserves NPV ⁽¹⁾⁽²⁾	100,552	0.47	82,720	0.38	70,443	0.33
Total proved reserves NPV ⁽¹⁾⁽²⁾	165,345	0.77	128,369	0.60	103,563	0.48
Proved plus probable reserves NPV ⁽¹⁾⁽²⁾	275,809	1.28	198,753	0.92	152,029	0.71
Undeveloped acreage ⁽³⁾	27,684	0.13	27,684	0.13	27,684	0.13
Net surplus ⁽⁴⁾	29,614	0.14	29,614	0.14	29,614	0.14
Net asset value (basic) ⁽⁵⁾⁽⁶⁾	333,107	1.55	256,051	1.19	209,327	0.97

Notes:
(1)	Evaluated by the independent reserve evaluator as at December 31, 2015. Net present value of future net revenue does not represent the fair market value of the reserves.
(2)	Net present values for before and after tax are based on McDaniel’s December 31, 2015 price forecast.
(3)	Undeveloped land value has been valued internally by Chinook at an average of $131 per acre over 212,025 net undeveloped acres.
(4)	Net surplus as at December 31, 2015, including positive working capital (estimated and unaudited). See “Net Surplus” in the Reader Advisory below.
(5)	Net asset value is the sum of Proved plus probable reserves, Undeveloped acreage and Net surplus
(6)	Basic shares as at December 31, 2015 totaled 215,349,412 common shares.

About Chinook Energy Inc.

Chinook is a Calgary-based public oil and gas exploration and development company with multi-zone conventional production and resource plays in western Canada.

Advisories & Contact

Reader Advisory

Abbreviations

Oil and Natural Gas Liquids		Natural Gas

bbl	barrel	mmcf/d	million cubic feet per day
bbls	barrels	mmbtu	million British Thermal Units
bbls/d	barrels per day
mbbl	thousand barrels
NGLs	natural gas liquids
mcf	thousand cubic feet
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

mboe	1,000 barrels of oil equivalent
mmboe	1,000,000 barrels of oil equivalent
WTI	West Texas Intermediate, the reference price paid in U.S. dollars at Cushing, Oklahoma for crude oil of standard grade

Oil and Gas Advisory

Reserves are estimated remaining quantities of oil and natural gas and related substance anticipated to be recoverable from known accumulations, as of a given date, based on the analysis of drilling, geological, geophysical and engineering data; the use of established technology, and specified economic conditions, which are generally accepted as being reasonable. Reserves are classified according to the degree of certainty associated with the estimates as follows:

Proved Reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves.

Probable Reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves.

The reserves information contained in this news release has been prepared in accordance with NI 51-101. Complete NI 51-101 reserves disclosure will be included in the Company’s Annual Information Form for the year ended December 31, 2015 which will be filed on SEDAR in March 2016. Listed below are cautionary statements applicable to the Company’s reserves information that are specifically required by NI 51-101:

Individual properties may not reflect the same confidence level as estimates of reserves for all properties due to the effects of aggregation.
This news release contains estimates of the net present value of the Company’s future net revenue from its reserves. Such amounts do not represent the fair market value of the Company’s reserves.

Forward-Looking Statements

In the interest of providing shareholders and potential investors with information regarding Chinook, including management’s assessment of the future plans and operations of Chinook, 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 addition, statements relating to “reserves” are deemed to be forward-looking statements as they involve the implied assessment, based on certain estimates and assumptions, that the reserves described exist in the quantities predicted or estimated and can be profitably produced in the future. In particular, this news release contains, without limitation, forward-looking statements pertaining to: estimated cash flows, drilling and operational plans at certain of the Company’s core areas and the anticipated timing thereof, the anticipated filing date on SEDAR for the Company’s Annual Information Form for the year ended December 31, 2015, the volumes and estimated value of Chinook’s oil and natural gas reserves, the life of Chinook’s reserves, the amount of future development costs associated with producing proved undeveloped and probable reserves, the timing that the new compression facility at Birley will commence production and the resulting associated incremental and total throughput volumes, Chinook’s anticipated production volumes once the new compression facility at Birley commences production, the volume and product mix of Chinook’s oil and natural gas production, future oil and natural gas prices and future results from operations.

With respect to the forward-looking statements contained in this news release, Chinook has made assumptions regarding, among other things: future oil and natural gas prices, future currency, exchange and interest rates, future oil and natural gas production levels, that Chinook will continue to conduct its operations in a manner consistent with past operations, future capital expenditure levels, Chinook’s ability to obtain equipment in a timely manner to carry out development activities, the ability of the operator of the projects in which Chinook has an interest to operate in the field in a safe, efficient and effective manner, the impact of increasing competition, field production rates and decline rates, the ability of Chinook to add production and reserves through development and exploitation activities, certain cost assumptions and the continued availability of adequate debt financing and cash flow to fund its planned expenditures. Although Chinook believes 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 Chinook’s 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, volatility of commodity prices, currency fluctuations, risks associated with oil and gas exploration, development, exploitation, production, marketing and transportation, loss of markets, imprecision of reserve and resource estimates, environmental risks, competition from other producers, inability to retain drilling rigs and other services, 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 ability 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 effect Chinook’s 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 Chinook’s 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 Chinook does 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.

Barrels of Oil Equivalent

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

Initial Production Rates

Any reference in this news release to initial, early and/or test or production/performance rates (including IP30) 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 the aggregate production for Chinook. 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.

Reserve Life Index

The reader is also cautioned that this news release contains the term reserve life index (“RLI”), which is not a recognized measure under International Financial Reporting Standards (“IFRS”). Management believes that this measure is a useful supplemental measure of the length of time the reserves would be produced over at the rate used in the calculation. Readers are cautioned, however, that this measure should not be construed as an alternative to other terms determined in accordance with IFRS as a measure of performance. Chinook’s method of calculating this measure may differ from other companies, and accordingly, they may not be comparable to measures used by other companies.

Funds from Operations

The reader is also cautioned that this news release contains the term funds from operations, which is not a recognized measure under IFRS and is calculated from cash flow from continuing operations adjusted for changes in non-cash working capital, decommissioning expenditures and exploration expenses. Management believes that funds from operations is a key measure to assess the ability of Chinook to finance capital expenditures and debt repayments. Readers are cautioned, however, that this measure should not be construed as an alternative to other terms such as cash flow from operating activities, net income or other measures of financial performance calculated in accordance with IFRS. Chinook’s method of calculating this measure may differ from other companies, and accordingly, they may not be comparable to measures used by other companies.

Net Surplus

The reader is cautioned that this news release contains the term net surplus, which is not a recognized measure under IFRS and is calculated as bank surplus adjusted for working capital excluding mark-to-market derivative contracts. Working capital excluding mark-to-market derivative contracts is calculated as current assets less current liabilities both of which exclude derivative contracts and current liabilities excludes the current portion of debt, if any. Management uses net surplus to assist them in understanding Chinook’s liquidity at specific points in time. Mark-to-market derivative contracts are excluded from working capital, in addition to net surplus, as management intends to hold each contract through to maturity of the contract’s term as opposed to liquidating each contract’s fair value or less.

Future Oriented Financial Information

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

Chinook Energy Inc.
Walter Vrataric
President and Chief Executive Officer
(403) 261-6883

Chinook Energy Inc.
Jason Dranchuk
Vice-President, Finance and Chief Financial Officer
(403) 261-6883
www.chinookenergyinc.com

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