Chinook Energy Inc. Announces Its December 31, 2014 Reserves and Provides Operations Update

CALGARY, ALBERTA--(Marketwired - Feb 9, 2015) - Chinook Energy Inc. ("Chinook" or the "Company") (CKE.TO) today announced the results of its year-end reserve evaluation effective December 31, 2014 as prepared by its independent evaluator. The Company has also provided an operations update.

Chinook's audit of its 2014 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 2014 Year-End Results

Chinook's average daily production for fiscal year 2014 was 7,937 boe/d. Average production for the fourth quarter of 2014 was 8,572 boe/d and the Company exited 2014 at approximately 8,000 boe/d, net of volumes associated with the Gilby disposition which closed on December 16, 2014. Projected cash flow for 2014 is estimated at $48 million or $0.22 per weighted average basic common share outstanding. Chinook exited 2014 undrawn on its $125 million credit facility and with an approximate $29 million working capital surplus. On January 6, 2015, Chinook completed the disposition of its Karr property for gross proceeds of $40.9 million, before closing adjustments, increasing its working capital surplus to approximately $70 million.

Chinook focused on the development of its Dunvegan oil assets at Albright/Beaverlodge and the delineation of its Montney acreage at Gold Creek in Alberta and Birley/Umbach in British Columbia. Chinook disposed of $39 million, before closing adjustments, of non-strategic Canadian assets representing approximately 975 boe/d while acquiring approximately 1,200 boe/d and strategic infrastructure in its core area of Birley/Umbach for consideration of $17 million and 3.5 net undeveloped sections of mineral rights in the general Wapiti area. Effective January 1, 2014, the Company disposed of its entire Tunisian business for gross proceeds of US$128.5 million (including US$14.5 million of positive working capital). Chinook's 2014 drilling program in Canada consisted of 15 (9.21 net) wells of which 10 (7.37 net) were operated and five (1.84 net) were non-operated wells. The results of the program are outlined in the table below:

Wells Drilled
Year ended December 31, 2014
		Gross	Net
Exploration
	Oil	-	-
	Gas	3.00	2.25
	Dry	-	-
		3.00	2.25
Development
	Oil	9.00	6.14
	Gas	2.00	0.45
	Dry	-	-
	Water Disposal	1.00	0.37
		12.00	6.96
Total		15.00	9.21

During 2014, Chinook drilled five (4.5 net) horizontal wells on the Albright/Beaverlodge property. The wells cumulatively averaged IP30 of 840 boe/d (or 186 boe/d per well). The Company maintains a drilling inventory of more than 50 (30 net) Dunvegan locations in the Grande Prairie area.

During 2014, Chinook drilled three (2.25 net) horizontal wells in the Birley/Umbach area of northeastern British Columbia, targeting liquids-rich natural gas in the Montney. The first well, a-60-k/94-H-3 (0.75 net), was drilled and completed in the first quarter and commenced production in April 2014 at restricted rates of 3.9 mmcf/d and 135 bbls of free condensate per day (785 boe/d). The well has been on production for 205 days during which it has averaged 3.5 mmcf/d and 68 bbls of free condensate per day (653 boe/d). The second horizontal well, b-71-F (0.75 net), was drilled and completed in the third quarter and has been on production for 68 days at restricted rates during which it has averaged 4.4 mmcf/d and 48 bbls of free condensate per day (782 boe/d). The third horizontal well at b-72-F (0.75 net) was drilled in December 2014 as the first of Chinook's four well drilling program for the first quarter of 2015 and currently awaits completion. Current throughput capacity at Chinook's Birley compressor site is approximately 9 mmcf/d. During the first quarter of 2015, Chinook will complete the installation of a 1.6 kilometre, 12 inch gathering line and the acquisition of long lead equipment and fabrication components to complete a facility expansion to 35 mmcf/d. The Company will complete one (0.75 net) well in the first quarter and one (1.0 net) well in the summer 2015 in anticipation of lower third party service costs.

During 2014, in the Karr/Gold Creek area, Chinook drilled two (1.13 net) horizontal wells targeting oil and associated natural gas in the Montney and one (0.37 net) water disposal well. The Montney wells, 100/16- 30-067-03W6 (0.38 net) and 100/14-12-069-06W6 (0.75 net), tested average production rates of 1,480 boe/d (42% oil) and 543 boe/d (42% oil), over seven days and nine days, respectively with final test rates of 1,500 boe/d (30% oil) and 870 boe/d (40% oil) respectively. The 16- 30 well commenced production in November and has been on production for 82 days during which it has averaged 281 bbls/d of oil and 3.6 mmcf/d of natural gas (881 boe/d). Chinook drilled a water disposal well (0.37 net) offsetting the 16- 30 well to reduce high operating costs associated with the trucking of water associated with production from the mid-Montney in this area. The water cut in the 16- 30 well has been stable at 80% since being brought on production and Chinook anticipates receiving its water disposal permit sometime in the first quarter of 2015. Chinook holds 50 (35 net) sections of Montney land in the greater Gold Creek area and has budgeted an additional horizontal Montney well in the second half of 2015, pending its review of commodity prices and service costs in the second quarter.

2014 Independent Reserves Evaluation

McDaniel & Associates Consultants Ltd. ("McDaniel") evaluated all of Chinook's properties effective December 31, 2014 pursuant to a report dated February 9, 2015. 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, 2014. 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, 2014, which will be filed on SEDAR at www.sedar.com in March 2015.

Reserves Breakdown (Company gross) (1)
(December 31, 2014, McDaniel price forecast)
(mboe)	2014	2013 (2)
Proved Producing
Total proved producing	13,589	12,711
Proved
Total proved	17,947	16,020
Proved Plus Probable
Total proved plus probable	27,383	25,090

Notes:

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

(2) Excludes volumes associated with the Tunisian disposition completed effective January 1, 2014 (Proved Producing of 1,424 mboe, Proved of 4,846 mboe and Proved Plus Probable of 8,132 mboe).

Company Gross and Net Reserves as at December 31, 2014

The following table summarizes the Company's gross and net reserve volumes utilizing McDaniel's forecast pricing and cost estimates at December 31, 2014.

		Light and medium oil		Heavy oil		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	2,759	2,322	53	51	56,816	48,897	1,309	962	13,589	11,484
	Developed non-producing	516	443	-	-	9,928	8,151	209	157	2,380	1,958
	Undeveloped	566	487	-	-	7,084	6,269	231	196	1,978	1,728
Total proved		3,841	3,252	53	51	73,828	63,317	1,749	1,315	17,947	15,170
Probable		1,911	1,475	43	41	39,118	32,989	963	720	9,437	7,734
Total proved plus probable		5,752	4,727	95	92	112,946	96,305	2,712	2,034	27,383	22,904

Notes:

(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 2014
(Company gross reserves before deduction of royalties payable)
	6:1 Oil Equivalent (mboe)
	Total Proved		Probable		Proved Plus Probable
December 31, 2013 - opening balance (1)	16,020		9,070		25,090
Additions and extensions	2,902		1,944		4,846
Acquisitions	3,177		705		3,883
Dispositions (1)	(1,827	)	(1,662	)	(3,489	)
Technical revisions	742		(542	)	200
Economic factors	(171	)	(78	)	(249	)
Production (1)	(2,897	)	-		(2,897	)
December 31, 2014 - closing balance	17,947		9,437		27,383

Notes:
(1) Excludes the following volumes associated with the Tunisian disposition completed effective January 1, 2014:
		Opening balance: Total Proved of 4,846 mboe, Probable of 3,286 mboe and Total Proved Plus Probable of 8,132 mboe.
		Dispositions: Total Proved of (4,407) mboe, Probable of (3,286) mboe and Total Proved Plus Probable of (7,693) mboe.
		Production: Total Proved of (439) mboe, Total Proved Plus Probable of (439) mboe.
(2) Columns may not add due to rounding.

Chinook completed the disposition of its Tunisian business effective January 1, 2014. In addition, during 2014, Chinook completed several dispositions of non-core Canadian properties for net proceeds of $35.6 million. Dispositions within the Company's West Central Alberta operating district represented the vast majority of the proved and probable reserve reductions of approximately 3.5 mmboe. However, Chinook also completed the acquisition of proved and probable reserves of 3.9 mmboe and strategic infrastructure in its core area of Birley/Umbach.

Year over year, McDaniel recorded net positive technical revisions related to performance of approximately 0.2 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 resulted in net negative revisions due to economic factors totaling 0.25 mmboe on proved and probable reserves.

Of particular note, Chinook added a total of 4.85 mmboe on a proved plus probable basis. The additions are primarily focused in the Company's core Montney areas of Gold Creek, Alberta and Birley/Umbach, British Columbia. Production in 2014 was 2.9 mmboe (64% natural gas, 26% oil and 10% NGLs) while the proved plus probable reserves added in the same period were 4.85 mmboe (77% natural gas, 8% oil and 15% NGLs).

Reserve Life Index ("RLI")

As at December 31, 2014, Chinook's proved plus probable RLI was 8.6 years based upon the McDaniel reserves report and the Company's annualized December 2014 production volumes (adjusted for volumes associated with December asset disposition), while its proved RLI was 5.6 years. The following table summarizes the RLI:

Proved
	Reserves (mboe)	17,947
	December 2014 production (mboe) (1)	3,201
	Reserve life index (years)	5.6
Proved Plus Probable
	Reserves (mboe)	27,383
	December 2014 production (mboe) (1)	3,201
	Reserve Life Index (years)	8.6

Note:

(1) December 2014 production excludes volumes that were disposed of in the same month.

Net Present Value ("NPV") Summary (before tax) as at December 31, 2014

(December 31, 2014, 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 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	229,664	186,682	157,576	136,867	121,483
Proved developed non-producing	33,656	22,253	15,426	11,014	7,977
Total proved developed	263,320	208,935	173,002	147,881	129,460
Proved undeveloped	27,059	14,712	7,720	3,288	267
Total proved	290,379	223,647	180,722	151,169	129,726
Probable additional	195,662	119,034	80,769	58,860	45,058
Total proved plus probable	486,040	342,681	261,491	210,029	174,784

Net Present Value Summary (after tax) as at December 31, 2014

(December 31, 2014, 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	229,664	186,682	157,576	136,867	121,483
Proved developed non-producing	33,656	22,253	15,426	11,014	7,977
Total proved developed	263,320	208,935	173,002	147,881	129,460
Proved undeveloped	27,059	14,712	7,720	3,288	267
Total proved	290,379	223,647	180,722	151,169	129,726
Probable additional	182,094	113,895	78,651	57,929	44,627
Total proved plus probable	472,473	337,542	259,372	209,098	174,353

McDaniel & Associates Consultants Ltd. Price Forecast as at December 31, 2014 (1)
	WTI Crude Oil (US$/bbl)	Brent (US$/bbl)	Edmonton Light Crude Oil (Cdn$/bbl)	Henry Hub Natural Gas (US$/mmbtu)	AECO Natural Gas (Cdn$/mmbtu)	Edmonton Condensate and Natural Gasoline (Cdn$/bbl)	Propane (Cdn$/bbl)	Butane (Cdn$/bbl)	US/Cdn Exchange (US$/Cdn)
2015	65.00	70.00	68.60	3.30	3.50	72.60	26.10	52.80	0.860
2016	75.00	77.60	83.20	3.80	4.00	87.30	36.50	67.00	0.860
2017	80.00	82.60	88.90	4.05	4.25	93.10	44.50	71.60	0.860
2018	84.90	87.60	94.60	4.30	4.50	98.80	49.30	76.20	0.860
2019	89.30	92.00	99.60	4.55	4.70	103.90	51.80	80.30	0.860
Average	78.84	81.96	86.98	4.00	4.19	91.14	41.64	69.58	0.860

Note:

(1) Prices escalate at two percent per year after 2019.

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)
	2014	2013
Total proved	42.6	36.8
Total proved plus probable	71.0	57.4

Chinook's 2015 budget includes the drilling of four wells (3.6 net).

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 2013 and 2012 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 during 2014 Chinook incurred a total of $20.1 million of capital largely unrelated to the reserve additions reflected in its year end independent reserves evaluation. These expenses included $16.4 million of crown land, $1.5 million related to its facility expansion including engineering, licencing and long lead equipment, $1.6 million related to access road upgrades, and $0.6 million in future drilling location surveys and lease work, all in its core area of Birley/Umbach.

Total Finding and Development Costs (Proved Reserves) ($ thousands, except per unit amounts)	2014	2013	2012		Three-Year Total
Exploration and development costs excluding acquisitions and dispositions (unaudited) (1)	77,542	40,120	27,549		145,210
Net change from previously allocated future development capital	6,820	8,732	(5,057	)	10,495
Total exploration and development costs including the net change in FDC	84,362	48,851	22,492		155,705
Reserve additions excluding acquisitions, dispositions (mboe)	3,473	1,088	470		5,031
NI 51-101 total proved finding and development costs (per boe)	24.29	44.91	47.87		30.95

Total Finding and Development Costs (Proved plus Probable Reserves) ($ thousands, except per unit amounts)	2014	2013		2012	Three-Year Total
Exploration and development costs excluding acquisitions and dispositions (unaudited) (1)	77,542	40,120		27,549	145,210
Net change from previously allocated future development capital	19,910	(8,170	)	2,422	14,163
Total exploration and development costs including the net change in FDC	97,452	31,950		29,971	159,373
Reserve additions excluding acquisitions, dispositions (mboe)	4,797	(1,402	)	311	3,706
NI 51-101 total proved plus probable finding and development costs (per boe)	20.32	(22.78	)	96.22	43.00

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)	2014	2013		2012		Three-Year Total
Exploration and development costs including acquisitions and dispositions (unaudited) (1)	63,358	26,133		(45,021	)	44,470
Net change from previously allocated future development capital	5,890	8,646		672		15,208
Total exploration and development costs including the net change in FDC	69,247	34,779		(44,349	)	59,678
Reserve additions including acquisitions, dispositions and revisions (mboe)	4,824	(47	)	(2,435	)	2,343
All-in total proved finding, development and acquisition costs (per boe)	14.36	(745.45	)	18.22		25.48

All-In Finding, Development and Acquisition Cost Including FDC, Acquisitions, Dispositions and Revisions (Proved plus Probable Reserves)
($ thousands, except per unit amounts)	2014	2013		2012		Three-Year Total
Exploration and development costs including acquisitions and dispositions (unaudited) (1)	63,358	26,133		(45,021	)	44,470
Net change from previously allocated future development capital	13,581	(9,282	)	6,280		10,580
Total exploration and development costs including the net change in FDC	76,939	16,851		(38,741	)	55,050
Reserve additions including acquisitions, dispositions and revisions (mboe)	5,191	(3,115	)	(4,065	)	(1,989	)
All-in total proved plus probable finding and development costs (per boe)	14.82	(5.41	)	9.53		(27.68	)

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 ($/boe) (unaudited) (1)	23.35
51-101 F&D costs ($/boe) (unaudited)	24.29
Recycle ratio	1.0x
Total Proved Plus Probable
Operating netback before commodity price contracts ($/boe) (unaudited) (1)	23.35
51-101 F&D costs ($/boe) (unaudited)	20.32
Recycle ratio	1.1x

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 ($/boe) (unaudited) (1)	23.35
All-in F&D costs ($/boe)(unaudited)	14.36
Recycle ratio	1.6x
Total Proved Plus Probable
Operating netback before commodity price contracts ($/boe) (unaudited) (1)	23.35
All-in F&D costs ($/boe)(unaudited)	14.82
Recycle ratio	1.6x

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, 2014 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 2014 year-end reserve reports.

December 31, 2014	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)	186,682		0.87		157,576		0.73		136,867		0.64
Total proved reserves NPV (1)(2)	223,647		1.04		180,722		0.84		151,169		0.70
Proved plus probable reserves NPV (1)(2)	342,681		1.59		261,491		1.22		210,029		0.98
Undeveloped acreage (3)	46,302		0.22		46,302		0.22		46,302		0.22
Net surplus (4)	28,792		0.13		28,792		0.13		28,792		0.13
Net asset value (basic) (5)	417,775		1.94		336,585		1.56		285,123		1.33

	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)	186,682		0.87		157,576		0.73		136,867		0.64
Total proved reserves NPV (1)(2)	223,647		1.04		180,722		0.84		151,169		0.70
Proved plus probable reserves NPV (1)(2)	337,542		1.57		259,372		1.21		209,098		0.97
Undeveloped acreage (3)	46,302		0.22		46,302		0.22		46,302		0.22
Net surplus (4)	28,792		0.13		28,792		0.13		28,792		0.13
Net asset value (basic) (5)	412,635		1.92		334,466		1.56		284,192		1.32

Notes:

(1) Evaluated by the independent reserve evaluator as at December 31, 2014. 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, 2014 price forecast.

(3) Undeveloped land value has been valued internally by Chinook at an average of $190 per acre over 243,159 net undeveloped acres.

(4) Net surplus as at December 31, 2014, including positive working capital (estimated and unaudited). See "Net Surplus" in the Reader Advisory below.

(5) Basic shares as at December 31, 2014 totaled 215,082,199 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.

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
Brent	a blended crude stream produced in the North Sea region which serves as a reference or "marker" for pricing a number of other crude streams
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, 2014 which will be filed in March 2015. 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 for the Company's Annual Information Form for the year ended December 31, 2014, the volumes and estimated value of Chinook's oil and natural gas reserves, the life of Chinook's reserves, 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.

Cash flow

The reader is also cautioned that this news release contains the term cash flow, 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 and decommissioning expenditures. Management believes that cash flow 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 cash flow, 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.