Chinook Energy Inc. Announces its December 31, 2011 Reserves and Updated 2012 Guidance

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CALGARY, ALBERTA--(Marketwire - Feb. 27, 2012) - Chinook Energy Inc. ("Chinook" or the "Company") (TSX:CKE) today announced the results of its year-end reserve evaluations effective December 31, 2011 as prepared by its independent evaluators. The Company has also provided certain unaudited year end financial information and an update to previously provided guidance for 2012 resulting from adjustments to the capital program in response to natural gas prices and asset dispositions.

Chinook's audit of its 2011 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.

2011 Reserves Highlights

Three evaluators, which were largely responsible for the previous evaluations of the same assets, have evaluated all of Chinook's crude oil, NGL and natural gas reserves in accordance with National Instrument 51-101. Chinook's Reserves Committee and Board of Directors have reviewed and approved the evaluations prepared by the evaluators. Highlights of such evaluations are as follows:

  • Proved reserves totaled 32.2 million barrels of oil equivalent. The proved reserve life index ("RLI") is 5.8 years using fourth quarter 2011 production.
  • Proved plus probable reserves totaled 55.8 million barrels of oil equivalent. The proved plus probable RLI is 10 years using fourth quarter 2011 production.
  • Proved plus Probable reserves are down 11% from 2010. Assets representing 6.7% of the 2010 reserves were sold during the year and Economic Factors and Technical Revisions represented a 5.8% decline from 2010 reserve levels. 2011 reserve additions from drilling exceeded production by 15%.
  • The proved finding and development cost, as per NI 51-101 requirements, was $54.45 per barrel of oil equivalent and the proved plus probable finding and development cost, as per NI 51-101 requirements, was $54.53 per barrel of oil equivalent. The change in future development costs ("FDC") and revisions were included in the calculation and the effect of acquisitions and divestitures was excluded.
  • The net asset value amounted to $773.5 million which results in the estimated net asset value per basic share (214.2 million shares) at December 31, 2011, being $3.61 per share based on the net present value of proved and probable reserves, discounted at 10% after tax and after deducting year end total net debt and adding an estimated value for undeveloped land in Canada. On a before tax basis, with a similar 10% discount rate, the net asset value is $1.1 billion or $5.03 per basic share.
  • Commodity prices used in the independent evaluation were down approximately 13% for natural gas which represents 49% of the corporate reserve volumes and up approximately 11% for the slate of liquids which represent 51% of the corporate reserve volumes.
  • The present value of reserves, and the NAV per share, was largely unchanged from 2010 as the decrease in reserve volumes and natural gas pricing attributable to the natural gas-weighted assets in Canada was offset almost entirely by increased value in the Tunisian oil-weighted assets.
  • Gross Discovered Petroleum Initially in Place ("DPIIP") associated with the Bir Ben Tartar (TT) discovery on the Sud Remada permit in Tunisia, after the addition of five development wells in 2011, is estimated to be 153.7 million barrels of oil. Proven and probable reserves net to the Company of 3.4 million barrels of oil represents the Company's 46% Contractor's share of the 7.3 million barrels of oil remaining recoverable. Proven and probable reserves have been assigned to areas representing 40% of the DPIIP up to a 13 percent recovery, or an average of 5% recovery for the entire structure. An additional 2.0 million barrels of oil of possible reserves and a Best Case Contingent Resource of 6.8 million barrels net to the Company's interest is attributable to the DPIIP area to which 2P reserves have not been assigned up to the date of evaluation. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. There is a 10% probability that the quantities actually recovered will exceed the sum of proved plus probable reserves. On this basis, 28% of the reserve and resource potential recognized on the block is reflected in the Company's NI 51-101 reserves and net asset value. The net present value after tax discounted at 10% for the proved plus probable reserves is $139 million or $41.00 per barrel.
  • The Company established a recycle ratio on a proven plus probable reserve basis, before commodity price contracts, and using NI 51-101 finding and development costs, of 0.4 times in Canada and 0.8 times in Tunisia.
  • Chinook has 28 gross sections of Bitumen rights in the Portage/Thornbury area of NE Alberta proximal to pilot projects being initiated by other operators. An initial evaluation of the Company's bitumen assets has identified Best Case Company Share of Exploitable Bitumen in Place of 271 mboe and Best Case Contingent Resource of 102.6 mboe in the McMurray and Grande Rapids Formations net to the Company's 74.55% working interest.

2011 Operational Highlights and Unaudited Full Year Results

Chinook's average daily production for fiscal 2011 was 14,602 barrels of oil equivalent per day. Production for the last half of 2011 was 14,780 barrels of oil equivalent per day and for the fourth quarter was 15,118 barrels of oil equivalent per day. Projected cash flow from operations (before changes in non-cash working capital) for 2011 is estimated at $84.9 million or $0.40 per weighted average basic common share outstanding (unaudited). Year end 2011 net debt is $135 million.

The Canadian business focused on crude oil project development in the core areas of West Central Alberta and Grande Prairie and the sale of non-core assets to improve the ratio of growth assets in the remaining domestic asset base and improve the boe meterics. The Tunisian business focused on the conversion of probable reserves to proven producing and an initial ramp up in production at the Bir Ben Tartar discovery. Tunisian production grew 150% and 2011 was the Company's most active year ever against a backdrop of the Arab spring revolution, a year of civil unrest, and the introduction of a new political system. The corporate drilling program consisted of 43 (26.84 net) wells of which 34 were operated and 9 were non-operated wells. The results are outlined in the table below:

Wells Drilled
Year ended December 31, 2011 Tunisia Canada Total
Gross Net Gross Net Gross Net
Exploration
Oil 2.00 0.15 10 00 5.28 12.00 5.43
Gas - - 5.00 4.00 5.00 4.00
Dry - - - - - -
2.00 0.15 15.00 9.28 17.00 9.43
Development
Oil 6.00 5.16 15.00 8.52 21.00 13.68
Gas - - 5.00 3.73 5.00 3.73
Dry - - - - - -
6.00 5.16 20.00 12.25 26.00 17.41
Total 8.00 5.31 35.00 21.53 43.00 26.84

Revised Guidance

As a result of the continuing downward pressure on the North American natural gas price and the completion of two disposition transactions, it is appropriate to revise the guidance for 2012 from the initial 2012 budget which was prepared in November 2011.

On the basis of current natural gas prices not covering fixed and variable costs and an adequate return on the depletion of certain assets, the Company has shut in a large portion of its Northeast Alberta shallow dry natural gas production which represents approximately 430 boe/d included in the initial 2012 forecast. In addition, given current AECO spot prices, the natural gas price used in the forecast has been adjusted from $3.74/mcf to $2.70/mcf.

Given the near term forecast for natural gas prices the Company has deferred approximately $10 million worth of capital from the Canadian capital program with an effect of eliminating approximately 225 boe/d of volumes previously included in the 2012 forecast.

On February 15, 2012, Chinook closed the previously announced disposition of its Manyberries property, located in southeastern Alberta, to the City of Medicine Hat for consideration of approximately $36.2 million. Chinook has also reached an agreement to sell a package of unit interests for $20 million, subject to normal closing adjustments, with an expected closing date of March 15, 2012. Chinook's current bank debt subsequent to the closing of the Manyberries property disposition is $101 million. The Company intends to use the proceeds from the disposition of the unit interests to further reduce debt such that it expects debt to be approximately $80 million after the completion of the sale, prior to factoring in Q1 2012 capital expenditures which are expected to exceed quarterly cash flow by $15-20 million. The production adjustment to previous 2012 guidance as a result of these two 2012 transactions, and two transactions that closed in December 2011 (after previous guidance was released) is an average reduction of 830 boe/d.

The Company will also reduce the capital program in Tunisia by $15 million in an attempt to better manage the balance sheet early in the year. This will be accomplished with an expected one quarter delay in the commencement of the central facility and pipeline projects but will not effect forecast production.

($ millions) Revised Guidance(1 ) Previous Guidance(2 )
Production (boe/d) 13,500-14,000 15,000-15,400
Cash flow $120 - 125 $135 - 140
Capital expenditures $165 $190
Net debt (year end 2012) $120 - 125 $180 - 190
Debt facility $182 $194
Net operating expenses ($/boe) $16.53 $17.50
G&A expense ($/boe) $2.80 $2.50
Cash flow per share (fully diluted) $0.54 $0.61
Notes:
  1. Revised guidance is based on: AECO gas price of $2.70/mcf; Edmonton light oil price of $96.20/bbl (CDN); Brent oil price of $104.00/bbl (CAD); 55% natural gas production; 45% liquids.
  2. Previous guidance was based on: AECO gas price of $3.74/mcf; Edmonton light oil price of $95.00/bbl (CDN); Brent oil price of $104.00/bbl (CAD); 55% natural gas production; 45% liquids.

Asset sales and natural gas price related technical revisions were key contributors to decreasing reserves in Canada. The increased value of the light oil assets in Tunisia supported the Net Asset Value being unchanged from year end 2010. Chinook's balance sheet is in very good shape and able to support the forecast capital program of 1.3 times cash flow which will be focused on developing Chinook's Brent priced oil production in Tunisia. In Canada, the Company will continue to work to improve the netbacks of its domestic natural gas weighted production, focus capital on oil prospects, and dispose of assets as it has successfully done over the last 15 months.

2011 Independent Reserves Evaluation
The independent evaluators of the Company's year-end reserves are as follows:
  • McDaniel & Associates Consultants Ltd. ("McDaniel") evaluated all of the Canadian properties effective December 31, 2011 and report dated February 27, 2012;
  • InSite Petroleum Consultants Ltd. ("InSite") evaluated all of the Tunisia interests, except Cosmos effective December 31, 2011 and report dated February 24, 2012; and
  • Sproule International Limited ("Sproule") evaluated Cosmos in Tunisia effective December 31, 2011 and report dated January 30, 2012.

The independent reserve evaluations effective December 31, 2011 were prepared in accordance with 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 forecast pricing and foreign exchange rates at December 31, 2011.

Reserves included herein are stated on a company gross basis (working interest before deduction of royalties 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 information will be included in Chinook's Annual Information Form for the year ended December 31, 2011 ("AIF"), which will be filed on SEDAR at www.sedar.com on or before March 30, 2012.

Reserves Breakdown (Company interest before royalties) (1)
(December 31, 2011, escalated price forecast)
(mboe) 2011 2010
Proved Producing
Canada 20,906 26,224
Tunisia 1,294 555
Total proved producing 22,200 26,780
Proved
Canada 25,227 31,283
Tunisia 6,940 6,133
Total proved 32,167 37,416
Proved Plus Probable Additional
Canada 38,995 45,803
Tunisia 16,816 16,655
Total proved plus probable additional 55,811 62,459
Note: (1) Columns may not add due to rounding.
Gross and Net Company Interest Reserves as at December 31, 2011
The following table summarizes the Company's gross and net interest reserve volumes utilizing McDaniel's forecast pricing and cost estimates at December 31, 2011.
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
)
Canada
Proved
Developed producing 4,648 3,931 154 149 83,241 69,332 2,231 1,613 20,906 17,249
Developed non-producing 780 663 40 37 11,277 9,493 181 134 2,880 2,417
Undeveloped 468 403 - - 5,010 3,970 138 109 1,441 1,174
Total proved 5,895 4,997 194 186 99,527 82,796 2,550 1,857 25,227 20,840
Probable additional 2,962 2,404 66 63 56,405 45,768 1,340 965 13,769 11,060
Total proved plus probable 8,857 7,402 260 249 155,931 128,564 3,890 2,821 38,995 31,900
Tunisia
Proved
Developed producing 1,105 1,048 - - 1,131 1,029 - - 1,294 1,219
Developed non-producing 434 397 - - 2,274 2,074 - - 813 742
Undeveloped 4,503 4,152 - - 1,358 1,322 - - 4,834 4,456
Total proved 6,042 5,596 - - 4,763 4,425 - - 6,940 6,417
Probable additional 9,526 8,387 - - 2,727 2,387 - - 9,876 8,701
Total proved plus probable 15,568 13,983 - - 7,490 6,812 - - 16,816 15,118
Total company
Proved
Developed producing 5,753 4,979 154 149 84,372 70,362 2,331 1,613 22,200 18,468
Developed non-producing 1,213 1,060 40 37 13,550 11,567 181 134 3,692 3,159
Undeveloped 4,971 4,555 - - 6,368 5,292 138 109 6,275 5,630
Total proved 11,937 10,594 194 186 104,290 87,221 2,550 1,857 32,167 27,257
Probable additional 12,488 10,791 66 63 59,132 48,155 1,340 965 23,644 19,761
Total proved plus probable 24,425 21,385 260 249 163,421 135,376 3,890 2,821 55,811 47,018
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.
Gross Company Reserve Reconciliation for 2011 (1)
(Gross company interest reserves before deduction of royalties payable)
6:1 Oil Equivalent (mboe)
Total Proved Probable Proved Plus
Probable
December 31, 2010 - opening balance 37,415 25,044 62,459
Additions and extensions 2,840 3,272 6,112
Improved performance - - -
Discoveries 273 95 368
Acquisitions - - -
Dispositions (2,596 ) (1,605 ) (4,200 )
Technical revisions 701 (3,145 ) (2,444 )
Economic factors (1,141 ) (18 ) (1,159 )
Production (5,324 ) - (5,324 )
December 31, 2011 - closing balance 32,167 23,644 55,811
Note: (1) Columns may not add due to rounding.
Consolidated
Net Present Value ("NPV") Summary (before tax) as at December 31, 2011
(December 31, 2011, escalated 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 does not include a provision for interest, debt service charges and general and administrative expenses. It should not be assumed that the NPV estimated represents the fair market value of the reserves.
($ thousands) Undiscounted Discounted at 5 % Discounted at 10 % Discounted at 15 % Discounted at 20 %
Proved producing 556,191 458,4356 393,751 347,502 312,702
Proved non-producing 116,845 90,562 73,293 61,163 52,201
Total proved developed 673,035 548,997 467,044 408,665 364,903
Proved undeveloped 236,834 190,527 155,656 128,486 106,803
Total proved 909,869 739,524 622,700 537,151 471,706
Probable additional 1,014,038 722,284 544,496 426,004 342,459
Total proved plus probable 1,923,907 1,461,808 1,167,196 963,154 814,165
Canada
Net Present Value Summary (before tax) as at December 31, 2011
(December 31, 2011, escalated price forecast)
($ thousands) Undiscounted Discounted at 5 % Discounted at 10 % Discounted at 15 % Discounted at 20 %
Proved producing 468,820 378,214 319,286 277,759 246,898
Proved non-producing 67,193 50,613 40,369 33,448 28,450
Total proved developed 536,014 428,827 359,655 311,206 275,348
Proved undeveloped 33,962 25,828 20,160 16,029 12,919
Total proved 569,975 454,655 379,815 327,236 288,266
Probable additional 359,780 223,928 155,167 115,201 89,687
Total proved plus probable 929,755 678,583 534,982 442,436 377,954
Tunisia
Net Present Value Summary (before tax) as at December 31, 2011
(December 31, 2011, escalated price forecast)
($ thousands) Undiscounted Discounted at 5 % Discounted at 10 % Discounted at 15 % Discounted at 20 %
Proved producing 87,371 80,222 74,465 69,743 65,804
Proved non-producing 49,651 39,949 32,924 27,715 23,752
Total proved developed 137,022 120,170 107,388 97,459 89,555
Proved undeveloped 202,872 164,700 135,497 112,456 93,885
Total proved 339,894 284,870 242,885 209,915 183,440
Probable additional 654,259 498,355 389,329 310,803 252,772
Total proved plus probable 994,153 783,225 632,214 520,718 436,211
Consolidated
Net Present Value Summary (after tax) as at December 31, 2011
(December 31, 2011, escalated 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 ("MD&A") 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 producing 543,337 447,679 384,494 339,356 305,401
Proved non-producing 87,566 69,329 56,993 48,100 41,385
Total proved developed 630,902 517,007 441,487 387,456 346,787
Proved undeveloped 163,670 130,458 105,073 85,118 69,118
Total proved 794,572 647,465 546,560 472,574 415,905
Probable additional 601,009 421,960 316,340 247,324 199,212
Total proved plus probable 1,395,581 1,069,425 862,899 719,897 615,117
Canada
Net Present Value Summary (after tax) as at December 31, 2011
(December 31, 2011, escalated price forecast)
($ thousands) Undiscounted Discounted at 5 % Discounted at 10 % Discounted at 15 % Discounted at 20 %
Proved producing 468,820 378,214 319,286 277,759 246,898
Proved non-producing 60,222 46,956 38,360 32,300 27,772
Total proved developed 529,042 425,170 357,646 310,059 274,670
Proved undeveloped 25,419 20,171 16,317 13,362 11,032
Total proved 554,461 445,340 373,963 323,421 285,702
Probable additional 270,556 169,028 118,110 88,646 69,853
Total proved plus probable 825,018 614,368 492,074 412,066 355,555
Tunisia
Net Present Value Summary (after tax) as at December 31, 2011
(December 31, 2011, escalated price forecast)
($ thousands) Undiscounted Discounted at 5 % Discounted at 10 % Discounted at 15 % Discounted at 20 %
Proved producing 74,516 69,465 65,208 61,597 58,503
Proved non-producing 27,344 22,373 18,633 15,800 13,613
Total proved developed 101,860 91,838 83,841 77,397 72,117
Proved undeveloped 138,251 110,288 88,756 71,756 58,086
Total proved 240,111 202,125 172,596 149,153 130,203
Probable additional 330,453 252,931 198,230 158,678 129,359
Total proved plus probable 570,563 455,056 370,826 307,831 259,562
McDaniel & Associates Consultants Ltd. Escalating Price Forecast as at December 31, 2011 (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
)
2012 97.50 107.50 99.00 3.75 3.50 106.00 54.60 76.20 0.975
2013 97.50 102.60 99.00 4.50 4.20 104.10 56.40 79.80 0.975
2014 100.00 102.60 101.50 5.05 4.70 104.60 58.90 81.80 0.975
2015 100.80 103.50 102.30 5.50 5.10 105.50 60.40 82.40 0.975
2016 101.70 104.40 103.20 5.95 5.55 106.40 62.00 83.20 0.975
99.50 104.12 101.00 4.95 4.61 105.32 58.46 80.68 0.975
Note: (1) Prices escalate at two percent per year after 2016.

Future Development Costs ("FDC")

NI 51-101 requires that future development costs be calculated including changes in 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 evaluators' best estimate of what it will cost to bring the proved undeveloped and probable reserves on production.

($ millions)
2011 2010
Proved
Canada 27.4 37.4
Tunisia 158.6 131.1
Total proved 186.0 168.6
Proved Plus Probable
Canada 60.4 59.3
Tunisia 301.0 278.5
Total proved plus probable 361.4 337.8
Chinook's approved 2012 budget includes the drilling of 31 wells (20.5 net) in Canada and 17 wells (10.6 net) in Tunisia.
NI 51-101 Finding and Development Costs ("F&D")
Total Proved Finding and Development Cost($ thousands, except per unit amounts) 2011 2010 Two year total
Capital expenditures excluding acquisitions and dispositions,abandonment and furniture and fixtures (unaudited) 124,981 45,861 170,842
Net change from previously allocated future development capital 20,471 19,107 39,578
Total capital including the net change in future capital 145,452 64,968 210,420
Reserve additions excluding acquisitions and dispositions (mboe) 2,671 2,404 5,075
Total proved finding and development costs (per boe) 54.45 27.02 41.46
Total Proved Plus Probable Finding and Development Cost($ thousands, except per unit amounts) 2011 2010 Two year total
Capital expenditures excluding acquisitions and dispositions,abandonment and furniture and fixtures (unaudited) 124,981 44,994 169,975
Net change from previously allocated future development capital 31,893 30,026 61,919
Total capital including the net change in future capital 156,874 75,020 231,894
Reserve additions excluding acquisitions and dispositions(mboe) 2,877 4,090 6,967
Total proved plus probable finding and development costs (per boe) 54.53 18.34 33.28
Finding and Development Costs ("F&D")
Total Proved Finding and Development Cost Including FDC, excluding Acquisitions, Dispositions, Revisions, and Economic Factors($ thousands, except per unit amounts) 2011 2010 Two year total
Capital expenditures excluding acquisitions and dispositionsabandonment and furniture and fixtures (unaudited) (1) 124,981 59,139 184,120
Net change from previously allocated future development capital 12,685 4,782 17,467
Total capital including the net change in future capital 137,666 63,921 201,587
Reserve additions including acquisitions, dispositions and revisions (mboe) 3,942 2,353 6,295
All-in total proved finding and development costs (per boe) 34.92 27.17 32.02
Note: (1) Excludes non-cash costs, including Asset Retirement Obligations.
Total Proved Plus Probable Finding and Development Cost Including FDC, excluding Acquisitions, Dispositions, Revisions, and Economic Factors($ thousands, except per unit amounts) 2011 2010 Two year total
Capital expenditures excluding acquisitions and dispositions,abandonment and furniture and fixtures (unaudited) (1) 124,981 59,139 184,120
Net change from previously allocated future development capital 39,390 9,232 48,622
Total capital including the net change in future capital 164,371 68,371 232,742
Reserve additions including acquisitions, dispositions and revisions (mboe) 6,480 3,654 10,134
All-in total proved plus probable finding and development costs (per boe) 25.37 18.71 22.97
Note: (1) Excludes non-cash costs, including Asset Retirement Obligations.

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 fourth quarter netback per barrel divided by the finding and development costs (excluding acquisitions and dispositions, abandonment and furniture and fixtures). It is a measure of the profitability and efficiency of the Company.

Total Proved Consolidated Canada Tunisia
Operating netback before commodity price contracts ($/boe) (unaudited) (1) 23.15 15.69 83.92
51-101 F&D costs ($/boe) (unaudited) 54.45 55.01 53.77
Recycle ratio 0.4x 0.3x 1.6x
Total Proved Plus Probable Consolidated Canada Tunisia
Operating netback before commodity price contracts ($/boe) (unaudited) (1) 23.15 15.69 83.92
51-101 F&D costs ($/boe) (unaudited) 54.53 41.80 107.10
Recycle ratio 0.4x 0.4x 0.8x
Note: (1) Operating netback is calculated by deducting royalties and production expenses from revenue.

Corporate Net Asset Value

The Company's net asset value as of December 31, 2011, 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 2011 year-end reserve reports.

December 31, 2011 Before Tax NPV 5% Before Tax NPV 10% Before Tax NPV 15%
($ thousands ) $/share ($ thousands ) $/share ($ thousands ) $/share
Proved plus probable reserves NPV(1,2) 1,461,807 6.82 1,167,195 5.45 963,155 4.50
Undeveloped acreage(3) 45,484 0.21 45,484 0.21 45,484 0.21
Net debt(4) (134,931 ) (0.63 ) (134,931 ) (0.63 ) (134,931 ) (0.63 )
Net asset value (basic)(5) 1,372,361 6.41 1,077,749 5.03 873,708 4.08
December 31, 2011 After Tax NPV 5% After Tax NPV 10% After Tax NPV 15%
($ thousands ) $/share ($ thousands ) $/share ($ thousands ) $/share
Proved plus probable reserves NPV(1,2) 1,069,425 4.99 862,900 4.03 719,897 3.36
Undeveloped acreage(3) 45,484 0.21 45,484 0.21 45,484 0.21
Net debt(4) (134,931 ) (0.63 ) (134,931 ) (0.63 ) (134,931 ) (0.63 )
Net asset value (basic)(5) 979,979 4.58 773,453 3.61 630,451 2.91
Notes:
  1. Evaluated by independent reserve evaluators as at December 31, 2011. 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, 2011 escalated price forecast.
  3. Undeveloped land value has been calculated based on internal estimates of $100/acre for all Canadian lands.
  4. Net debt as at December 31, 2011, including working capital deficit (estimated and unaudited).
  5. Basic shares at December 31, 2011 total 214,187,681 common shares.

Chinook's audited consolidated financial statements and its annual information form for the year ended December 31, 2011, which will include more detailed reserves information, are expected to be filed on SEDAR (www.sedar.com) on or about March 22, 2012.

Bir Ben Tartar - Discovered Petroleum Initially-in-Place

Insite assigned 153.7 million barrels of Discovered Petroleum Initially-In-Place to the Bir Ben Tartar (TT) discovery.

DPIIP is the quantity of petroleum that is estimated, as of a given date, to be contained in known accumulations prior to production. The recoverable portion of DPIIP is divided into commercial (reserves), and sub-commercial (Contingent Resources); the remainder is by definition unrecoverable. Contingent Resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies.

Contingencies in respect of the Bir Ben Tartar (TT) discovery that prevent such Contingent Resources to be classified as reserves include the lack of a reasonable expectation that all internal and external approvals will be forthcoming to fully develop the asset, further reservoir studies, delineation drilling, facility design, preparation of firm development plans and regulatory applications. Other commercial considerations that may preclude the classification of contingent resources as reserves include factors such as legal, environmental, political and regulatory matters or a lack of markets. Estimates of DPIIP and Contingent Resources described herein are estimates only; the actual resources may be higher or lower than those calculated in Insite's report. There is no certainty that it will be commercially viable to produce any portion of the resources described herein.

The most significant positive and negative factors with respect to the Contingent Resource estimates in respect of the Bir Ben Tartar (TT) discovery relate to fact that the field is currently at an evaluation/delineation stage.

The table below summarizes the DPIIP, Reserves, Cumulative Production, Contingent Resources and portion of the unrecoverable portion of DPIIP associated with the Bir Ben Tartar (TT) discovery.

Category MBbls
DPIIP 157,300
Gross Proved + Probable Reserves 3,360.8
Cumulative Production 458.8
Contingent Resource (Best Estimate) 6,800.6
Unrecoverable DPIIP 128,900

Alberta Oil Sands - Exploitable Bitumen in Place

The table below reflects the Company's Contingent Bitumen Resources as of December 31, 2011, as evaluated by McDaniel reflected the Company's 74.55% working interest in its oil sands leases in the Portage and Thornbury areas of Alberta.

Actual resources may be greater than or less than the estimates provided herein. Contingent Resources can be sub-classified into economic and uneconomic factors based on a number of assumptions such as capital costs, timing, price forecasts and other considerations. Currently sub-classification of these estimates has not been completed pending a determination of the above parameters. The contingencies which currently prevent the classification of the Contingent Resources disclosed in the tables below as reserves consist of: further reservoir studies, delineation drilling, facility design, preparation of firm development plans, regulatory applications and corporate approvals. There is no certainty that it will be commercially viable for the Corporation to produce any portion of the Contingent Resources on any of its properties. The most significant positive and negative factors with respect to the Contingent Resource estimates relates to the fact that property is currently at an evaluation/delineation stage.

The information provided hereunder for Thornbury is based on an evaluation conducted by McDaniel effective December 31, 2011. The information provided hereunder for Portage is based on an evaluation conducted by McDaniel effective June 1, 2010. McDaniel carried out the evaluations in accordance with standards established by the Canadian Securities Administrators in NI 51-101.

Contingent Resources - Thornbury Oil Sands
Volumes (mboe) Gross Net
High 74,738 61,044
Best 46,285 39,674
Low 30,835 27,490
Contingent Resources - Portage Oil Sands
Volumes (mboe) Gross Net
High 90,173 73,251
Best 56,333 48,379
Low 40,609 36,449
Contingent Resources - Portage & Thornbury Oil Sands
Volumes (mboe) Gross Net
High 164,911 134,295
Best 102,618 88,053
Low 71,444 63,939
Note: (1) See "Definitions of Oil and Gas Resources and Reserves" herein.
(2) Net volumes are defined as gross volumes, less royalty deductions payable.
(3) There is no certainty that it will be commercially viable to produce any portion of the resources.

About Chinook Energy Inc.

Chinook is a Calgary-based public oil and gas exploration and development company that combines high quality natural gas-weighted assets in Western Canada with an exciting high growth oil business onshore and offshore Tunisia in North Africa.

Definitions of Oil and Gas Resources and Reserves

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.

Possible Reserves are those additional reserves that are less certain to be recovered than probable reserves. It is unlikely that the actual remaining quantities recovered will exceed the sum of the estimated proved plus probable plus possible reserves. There is 10% probability that the quantities recovered will exceed the sum of proved and probable reserves.

Resources encompasses all petroleum quantities that originally existed on or within the earth's crust in naturally occurring accumulations, including Discovered and Undiscovered (recoverable and unrecoverable) plus quantities already produced. "Total resources" is equivalent to "Total Petroleum Initially-In-Place". Resources are classified in the following categories:

Discovered Petroleum Initially-In-Place ("DPIIP") is that quantity of petroleum that is estimated, as of a given date, to be contained in known accumulations prior to production. The recoverable portion of discovered petroleum initially-in-place includes production, reserves, and contingent resources; the remainder is unrecoverable.

Contingent Resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development but which are not currently considered to be commercially recoverable due to one or more contingencies.

Unrecoverable is that portion of DPIIP and UPIIP quantities which is estimated, as of a given date, not to be recoverable by future development projects. A portion of these quantities may become recoverable in the future as commercial circumstances change or technological developments occur; the remaining portion may never be recovered due to the physical/chemical constraints represented by subsurface interaction of fluids and reservoir rocks.

Uncertainty Ranges are described by the COGE Handbook as low, best, and high estimates for reserves and resources as follows:

Low Estimate: This is considered to be a conservative estimate of the quantity that will actually be recovered. It is likely that the actual remaining quantities recovered will exceed the low estimate. If probabilistic methods are used, there should be at least a 90 percent probability (P90) that the quantities actually recovered will equal or exceed the low estimate.

Best Estimate: This is considered to be the best estimate of the quantity that will actually be recovered. It is equally likely that the actual remaining quantities recovered will be greater or less than the best estimate. If probabilistic methods are used, there should be at least a 50 percent probability (P50) that the quantities actually recovered will equal or exceed the best estimate.

High Estimate: This is considered to be an optimistic estimate of the quantity that will actually be recovered. It is unlikely that the actual remaining quantities will exceed the high estimate. If probabilistic methods are used, there should be at least a 10 percent probability (P10) that the quantities actually recovered will equal or exceed the high estimate.

Reader Advisory

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: the recognition of significant additional reserves under the heading "2011 Independent Reserve Evaluation"; 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 Chinook's commodity risk management program; future results from operations and operating metrics; and future development, exploration, acquisition and development activities (including drilling plans) and related production expectations as well as management's future expectations set out under the heading "Revised Guidance".

With respect to the forward-looking statements contained in this news release, Chinook has made assumptions regarding, among other things: that Chinook will continue to conduct its operations in a manner consistent with past operations, the ability of Chinook to continue to operate in Tunisia with limited logistical security and operational issues, future capital expenditure levels, future oil and natural gas prices, future oil and natural gas production levels, Chinook's ability to obtain equipment in a timely manner to carry out development activities, the impact of increasing competition, the ability of Chinook to add production and reserves through development and exploitation activities, certain commodity price and other cost assumptions, the continued availability of adequate debt and equity 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, political and security risk associated with Chinook's Tunisian operations, risks associated with oil and gas exploration, development, exploitation, production, marketing and transportation, loss of markets, volatility of commodity prices, currency fluctuations, imprecision of reserve and resource estimates, the continued impact of shut-in production, 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.

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 GAAP. 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.

Operating Netback

The reader is also cautioned that this news release contains the term operating netback, which is not a recognized measure under GAAP and is calculated as a period's sales of petroleum and natural gas, net of royalties less net production and operating expenses as divided by the period's sales volumes. Management uses this measure to assist them in understanding Chinook's profitability relative to current commodity prices and it provides an analysis tool to benchmark changes in operational performance against prior periods and to peers on a comparable basis. 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. 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 from operations

The reader is also cautioned that this news release contains the term cash flow from operations, which is not a recognized measure under GAAP and is calculated from cash flow from continuing operations adjusted for changes in non-cash working capital. 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.



Chinook Energy Inc.
Matthew Brister
President and Chief Executive Officer
(403) 261-6883

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