Chinook Energy Inc. ("Chinook" or the "Company") (TSX:CKE) today announced the
results of its year-end reserve evaluations effective December 31, 2012 as
prepared by its independent evaluators. The Company has also provided certain
unaudited year-end financial information and an operations update.
Chinook's audit of its 2012 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.
2012 Reserves Highlights
Two 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,
Safety and Environmental 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 28.95 million barrels of oil equivalent. The
proved reserve life index ("RLI") is 7.1 years using annualized December
2012 production.
-- Proved plus probable reserves totaled 51.65 million barrels of oil
equivalent. The proved plus probable RLI is 12.7 years using annualized
December 2012 production.
-- Proved plus probable reserves are down 7.5% from 2011. Assets
representing 11.7% of the 2011 reserves were sold during the year and
Economic Factors and Technical Revisions represented a 0.6% increase
from 2011 reserve levels.
-- The proved finding and development cost, as per NI 51-101 requirements,
was $39.27 per barrel of oil equivalent and the proved plus probable
finding and development cost, as per NI 51-101 requirements, was $40.19
per barrel of oil equivalent. The change in future development costs
("FDC") and revisions was included in the calculation and the effect of
acquisitions and divestitures was excluded.
-- Commodity price forecasts used in the independent evaluation, relative
to the 2011 evaluation period, were down approximately 15% for natural
gas in Canada, which represents 44% of the corporate proved plus
probable reserve volumes and down approximately 3% (6% in Canada and 2%
in Tunisia) for the oil, which represents 51% of the corporate proved
plus probable reserve volumes. As a result of the reduction in the price
forecast, Chinook recorded a 1.33 million barrels of oil equivalent loss
of reserves due to economic factors.
-- The after tax net asset value at December 31, 2012, is $3.11 per basic
share (214.2 million shares) 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 of $100 per acre
for its 357,745 acres of undeveloped land in Canada. On a before tax
basis, with a similar 10% discount rate, the net asset value is $4.21
per basic share.
-- 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 2012, is estimated to be
201.7 million barrels of oil. Proved and probable reserves net to the
Company of 5.1 million barrels of oil represent the Company's 48%
Contractor's share of the 10.7 million barrels of oil remaining
recoverable. Proved and probable reserves have been assigned to areas
representing 44% of the DPIIP up to a 13% recovery, or an average of 5%
recovery for the entire structure. An additional 2.5 million barrels of
oil of possible reserves and a Best Case Contingent Resource of 7.2
million barrels net to the Company's interest is attributable to the
DPIIP area to which proved and probable 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, 44% 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 $163 million or $34.95 per barrel.
2012 Operational Highlights and Unaudited Full Year Results
Chinook's average daily production for fiscal year 2012 was 12,197 barrels of
oil equivalent per day. Production for the last half of 2012 was 11,826 barrels
of oil equivalent per day and for the fourth quarter was 11,688 barrels of oil
equivalent per day. Projected cash flow from operations (before changes in
non-cash working capital) for 2012 is estimated at $78.2 million or $0.37 per
weighted average basic common share outstanding (unaudited). Year end 2012 net
debt is $72.1 million.
The Canadian business focused on crude oil project development in the core areas
of Grande Prairie and the Peace River Arch along with the disposition of $107.4
million of non-strategic assets representing approximately 1,600 boe/d of
production. The Tunisian business focused on further light oil development and
delineation and increased production on the Bir Ben Tartar Concession ("BBT
Concession"). The corporate drilling program consisted of 19 (10.05 net) wells
of which 11 were operated and eight were non-operated wells. The results are
outlined in the table below:
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Wells Drilled
Year ended December 31, 2012 Tunisia Canada Total
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Gross Net Gross Net Gross Net
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Exploration
Oil - - 4 00 1.86 4.00 1.86
Gas - - - - - -
Dry 2.00 0.96 - - 2.00 0.96
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2.00 0.96 4.00 1.86 6.00 2.82
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Development
Oil 6.00 4.35 6.00 1.88 12.00 6.23
Gas - - 1.00 1.00 1.00 1.00
Dry - - - - - -
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6.00 4.35 7.00 2.88 13.00 7.23
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Total 8.00 5.31 11.00 4.74 19.00 10.05
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Revised 2013 Guidance
As a result of higher initial water cuts associated with the most recent
horizontal wells drilled on the BBT Concession, coupled with delays in
commencement of the 2013 BBT Concession drilling program, the Company has
revised its guidance for 2013 as set forth below from the initial 2013 guidance
which was provided on November 13, 2012. The Company has also reduced its
capital program by $38 million to $102-107 million in 2013 as a result.
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Revised Guidance (1)
($ millions, except
boe/d) Consolidated International Canada
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Production (boe/d) 9,500 - 10,200 2,150 - 2,450 7,350 - 7,750
Cash flow $ 95 - 100 $ 55 - 58 $ 40 - 42
Capital expenditures $ 102 - 107 $ 58 - 60 $ 44 - 47
Net debt $ 60 - 65 - -
Debt facility $ 115 - $ 115
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(1) Revised guidance is based on: AECO gas price of $3.22/mcf; Edmonton
light oil price of $89.80/bbl (CDN); Brent oil price of $104.75/bbl
(CAD); 54% natural gas production; 46% liquids.
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Previous Guidance (2)
($ millions, except
boe/d) Consolidated International Canada
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10,800 -
Production (boe/d) 11,500 3,000 - 3,400 7,800 - 8,100
Cash flow $ 130 - 135 $ 90 - 94 $ 38 - 41
Capital expenditures $ 140 - 145 $ 90 - 95 $ 45 - 50
Net debt $ 95-100 - -
Debt facility $ 115 - $ 115
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(2) Previous guidance was based on: AECO gas price of $3.26/mcf; Edmonton
light oil price of $88.94/bbl (CDN); Brent oil price of $103.00/bbl
(CAD); 47% natural gas production; 53% liquids.
Tunisia Security Update
The operating environment in Tunisia has become more complicated and the
necessity to increase security at the Company's operations has risen since late
last year. The number of local land use concerns continues to rise and the
precedents to resolve them are nonexistent or ineffective in many cases.
Stakeholder frustrations often manifest themselves as "sit ins" that disrupt
Chinook's work or logistics. There are ongoing efforts to resolve the issues and
streamline the process but until material commitments and progress are evident,
the Company is unable to achieve the economies or timeline that had been
planned. Although operations are impacted, production has not been impacted
owing to storage capacity being well in excess of the duration of the stoppages
to date. From a security perspective, Chinook has completed the planning phase
of an audit and upgrade of its capabilities and systems and will be implementing
the majority of the recommendations prior the commencement of its next program
and all before the end of the year. This was in progress prior to the most
recent events that continue to destabilize the political landscape but those
recent events clearly reinforce the necessity that the Company minimizes risk by
increasing its awareness and preparedness.
Canadian Non-Strategic Disposition Update
The Company's ongoing non-strategic asset sale process has resulted in executed
letters of intent for the sale of approximately 580 boe/d and gross proceeds,
before closing adjustments, of approximately $19.5 million to be closed in the
first quarter. The disposition of non-core assets as a means to maintain a
strong balance sheet and increase the per barrel profitability of the Company's
core Canadian assets will be a continued priority for the Company.
2012 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, 2012 and report dated
February 8, 2013;
-- InSite Petroleum Consultants Ltd. ("InSite") evaluated all of the
Tunisia interests effective December 31, 2012 and report dated February
26, 2013; and
The independent reserve evaluations effective December 31, 2012 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, 2012.
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, 2012 ("AIF"), which will be
filed on SEDAR at www.sedar.com on or about March 27, 2013.
Reserves Breakdown (Company interest before royalties) (1)
(December 31, 2012, escalated price forecast)
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(mboe) 2012 2011
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Proved Producing
Canada 14,966 20,906
Tunisia 1,516 1,294
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Total proved producing 16,482 22,200
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Proved
Canada 19,069 25,227
Tunisia 9,880 6,940
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Total proved 28,949 32,167
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Proved Plus Probable Additional
Canada 31,207 38,995
Tunisia 20,445 16,816
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Total proved plus probable additional 51,652 55,811
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Note: (1) Columns may not add due to rounding.
Gross and Net Company Interest Reserves as at December 31, 2012
The following table summarizes the Company's gross and net interest reserve
volumes utilizing McDaniel's forecast pricing and cost estimates at December 31,
2012.
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Light and
medium oil Heavy oil Natural Gas
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Gross Gross Gross
(1) Net (2) (1) Net (2) (1) Net (2)
Reserves category (mbbl) (mbbl) (mbbl) (mbbl) (mmcf) (mmcf)
----------------------------------------------------------------------------
Canada
Proved
Developed producing 2,720 2,314 187 181 63,125 53,164
Developed non-producing 714 588 34 31 11,839 10,190
Undeveloped 902 752 - - 1,541 1,356
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Total proved 4,337 3,654 221 212 76,505 64,710
Probable additional 2,487 1,995 77 72 50,583 41,393
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Total proved plus probable 6,824 5,649 298 284 127,088 106,103
----------------------------------------------------------------------------
Tunisia
Proved
Developed producing 1,308 1,255 - - 1,246 1,121
Developed non-producing 466 414 - - 2,498 2,265
Undeveloped 7,138 6,643 - - 2,067 1,874
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Total proved 8,912 8,311 - - 5,810 5,260
Probable additional 10,212 9,290 - - 2,116 1,904
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Total proved plus probable 19,124 17,601 - - 7,926 7,165
----------------------------------------------------------------------------
Total company
Proved
Developed producing 4,029 3,569 187 181 64,371 54,285
Developed non-producing 1,180 1,001 34 31 14,337 12,454
Undeveloped 8,040 7,395 - - 3,607 3,230
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Total proved 13,248 11,965 221 212 82,315 69,970
Probable additional 12,700 11,285 77 72 52,699 43,297
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Total proved plus probable 25,948 23,250 298 284 135,014 113,267
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Natural gas liquids Oil equivalent (6:1)
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Gross(1) Net (2) Gross(1) Net (2)
Reserves category (mbbl) (mbbl) (mboe) (mboe)
----------------------------------------------------------------------------
Canada
Proved
Developed producing 1,538 1,107 14,966 12,462
Developed non-producing 202 151 2,923 2,468
Undeveloped 22 16 1,181 994
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Total proved 1,761 1,274 19,069 15,925
Probable additional 1,143 825 12,138 9,791
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Total proved plus probable 2,904 2,099 31,207 25,716
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Tunisia
Proved
Developed producing - - 1,516 1,442
Developed non-producing - - 882 790
Undeveloped - - 7,482 6,955
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Total proved - - 9,880 9,187
Probable additional - - 10,565 9,608
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Total proved plus probable - - 20,445 18,795
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Total company
Proved
Developed producing 1,538 1,107 16,482 13,904
Developed non-producing 202 151 3,805 3,259
Undeveloped 22 16 8,663 7,949
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Total proved 1,761 1,274 28,949 25,112
Probable additional 1,143 825 22,703 19,399
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Total proved plus probable 2,904 2,099 51,652 44,511
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----------------------------------------------------------------------------
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.
Gross Company Reserve Reconciliation for 2012 (1)
(Gross company interest reserves before deduction of royalties payable)
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6:1 Oil Equivalent (mboe)
Proved Plus
Total Proved Probable Probable
----------------------------------------------------------------------------
December 31, 2011 - opening balance 32,167 23,644 55,811
Additions and extensions 1,413 2,721 4,134
Category transfers 731 (731) -
Discoveries - 204 204
Acquisitions 1,459 686 2,145
Dispositions (4,364) (2,159) (6,522)
Technical revisions 3,164 (1,488) 1,675
Economic factors (1,157) (174) (1,332)
Production (4,464) - (4,464)
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December 31, 2012 - closing balance 28,949 22,703 51,652
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Note: (1) Columns may not add due to rounding.
Consolidated
Net Present Value ("NPV") Summary (before tax) as at December 31, 2012
(December 31, 2012, 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.
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Discounted Discounted Discounted Discounted
($ thousands) Undiscounted at 5% at 10% at 15% at 20%
----------------------------------------------------------------------------
Proved producing 335,042 285,878 250,968 224,947 204,803
Proved non-
producing 99,764 80,735 67,458 57,718 50,289
----------------------------------------------------------------------------
Total proved
developed 434,806 366,613 318,426 282,665 255,092
Proved
undeveloped 252,823 197,646 158,232 128,034 103,942
----------------------------------------------------------------------------
Total proved 687,630 564,259 476,657 410,699 359,034
Probable
additional 843,405 606,581 461,209 362,612 291,843
----------------------------------------------------------------------------
Total proved
plus probable 1,531,035 1,170,840 937,867 773,311 650,877
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Canada
Net Present Value Summary (before tax) as at December 31, 2012
(December 31, 2012, escalated price forecast)
----------------------------------------------------------------------------
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Discounted Discounted Discounted Discounted
($ thousands) Undiscounted at 5% at 10% at 15% at 20%
----------------------------------------------------------------------------
Proved producing 259,435 215,015 184,098 161,483 144,280
Proved non-
producing 51,720 40,995 33,880 28,836 25,068
----------------------------------------------------------------------------
Total proved
developed 311,154 256,010 217,979 190,319 169,348
Proved
undeveloped 43,837 27,532 18,670 13,165 9,439
----------------------------------------------------------------------------
Total proved 354,991 283,542 236,649 203,484 178,786
Probable
additional 259,321 152,488 101,040 72,055 53,987
----------------------------------------------------------------------------
Total proved
plus probable 614,313 436,030 337,689 275,539 232,773
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Tunisia
Net Present Value Summary (before tax) as at December 31, 2012
(December 31, 2012, escalated price forecast)
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Discounted Discounted Discounted Discounted
($ thousands) Undiscounted at 5% at 10% at 15% at 20%
----------------------------------------------------------------------------
Proved producing 75,608 70,863 66,870 63,464 60,523
Proved non-
producing 48,045 39,740 33,577 28,882 25,221
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Total proved
developed 123,652 110,603 100,447 92,346 85,745
Proved
undeveloped 208,986 170,114 139,562 114,869 94,503
----------------------------------------------------------------------------
Total proved 332,639 280,717 240,009 207,215 180,248
Probable
additional 584,083 454,094 360,169 290,557 237,856
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Total proved
plus probable 916,722 734,810 600,178 497,772 418,103
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Consolidated
Net Present Value Summary (after tax) as at December 31, 2012
(December 31, 2012, 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.
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Discounted Discounted Discounted Discounted
($ thousands) Undiscounted at 5% at 10% at 15% at 20%
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Proved producing 320,508 272,832 239,105 214,042 194,689
Proved non-
producing 76,864 62,053 51,838 44,393 38,728
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Total proved
developed 397,372 334,885 290,943 258,435 233,417
Proved
undeveloped 177,286 133,276 102,307 78,794 60,152
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Total proved 574,658 468,161 393,250 337,229 293,569
Probable
additional 573,538 409,305 309,563 242,414 194,482
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Total proved
plus probable 1,148,196 877,466 702,813 579,643 488,051
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Canada
Net Present Value Summary (after tax) as at December 31, 2012
(December 31, 2012, escalated price forecast)
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Discounted Discounted Discounted Discounted
($ thousands) Undiscounted at 5% at 10% at 15% at 20%
----------------------------------------------------------------------------
Proved producing 259,435 215,015 184,098 161,483 144,280
Proved non-
producing 51,720 40,995 33,880 28,836 25,068
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Total proved
developed 311,154 256,010 217,979 190,319 169,348
Proved
undeveloped 43,837 27,532 18,670 13,165 9,439
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Total proved 354,991 283,542 236,649 203,484 178,786
Probable
additional 218,033 133,729 91,546 66,894 51,032
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Total proved
plus probable 573,025 417,272 328,194 270,378 229,818
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Tunisia
Net Present Value Summary (after tax) as at December 31, 2012
(December 31, 2012, escalated price forecast)
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Discounted Discounted Discounted Discounted
($ thousands) Undiscounted at 5% at 10% at 15% at 20%
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Proved producing 61,073 57,817 55,007 52,560 50,409
Proved non-
producing 25,144 21,058 17,958 15,557 13,660
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Total proved
developed 86,217 78,875 72,965 68,116 64,069
Proved
undeveloped 133,449 105,744 83,637 65,629 50,713
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Total proved 219,667 184,619 156,602 133,745 114,783
Probable
additional 355,504 275,575 218,017 175,520 143,450
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Total proved
plus probable 575,171 460,194 374,619 309,265 258,233
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McDaniel & Associates Consultants Ltd. Escalating Price Forecast as at December
31, 2012 (1)
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Edmonton
WTI Crude Light Henry Hub AECO Natural
Oil Brent Crude Oil Natural Gas Gas
(US$/bbl) (US$/bbl) (Cdn$/bbl) (US$/mmbtu) (Cdn$/mmbtu)
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2013 92.50 107.50 87.50 3.75 3.35
2014 92.50 102.50 90.50 4.30 3.85
2015 93.60 101.40 92.60 4.85 4.35
2016 95.50 100.80 94.50 5.25 4.70
2017 97.40 100.10 96.40 5.70 5.10
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94.30 102.46 92.30 4.77 4.27
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Edmonton
Condensate
and Natural US/Cdn
Gasoline Propane Butane Exchange
(Cdn$/bbl) (Cdn$/bbl) (Cdn$/bbl) (US$/Cdn)
----------------------------------------------------------------------------
2013 97.50 34.90 64.10 1.000
2014 95.60 44.20 69.60 1.000
2015 95.70 52.00 74.60 1.000
2016 97.70 53.70 76.20 1.000
2017 99.60 55.60 77.70 1.000
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97.22 48.08 72.44 1.000
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Note: (1) Prices escalate at two percent per year after 2017.
Future Development Costs ("FDC")
NI 51-101 requires that future development costs be calculated including changes
in FDC. Changes in forecast FDC occur annually as a result of development
activities, acquisition and disposition activities and capital cost estimates
that reflect the independent evaluators' best estimate of what it will cost to
bring the proved undeveloped and probable reserves on production.
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($ millions)
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2012 2011
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Proved
Canada 28.1 27.4
Tunisia 242.3 158.6
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Total proved 270.4 186.0
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Proved Plus Probable
Canada 66.7 60.4
Tunisia 402.4 301.0
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Total proved plus probable 469.1 361.4
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Chinook's approved 2013 budget includes the drilling of 13 wells (7.5 net) in
Canada and 8.0 wells (6.1 net) in Tunisia.
NI 51-101 Finding and Development Costs ("F&D")
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Total Proved Finding and Development Three
Cost ($ thousands, except per unit year
amounts) 2012 2011 2010 total
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Capital expenditures excluding
acquisitions and dispositions,
abandonment and furniture and
fixtures (unaudited) 84,316 124,981 45,861 255,158
Net change from previously allocated
future development capital 78,689 20,471 19,107 118,267
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Total capital including the net
change in future capital 163,005 145,452 64,968 373,424
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Reserve additions excluding
acquisitions and dispositions
(mboe) 4,151 2,671 2,404 9,226
Total proved finding and development
costs (per boe) $ 39.27 $ 54.45 $ 27.02 $ 40.47
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Total Proved Plus Probable Finding Three
and Development Cost ($ thousands, year
except per unit amounts) 2012 2011 2010 total
----------------------------------------------------------------------------
Capital expenditures excluding
acquisitions and dispositions,
abandonment and furniture and
fixtures (unaudited) 84,316 124,981 44,994 254,291
Net change from previously allocated
future development capital 103,880 31,893 30,026 165,799
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Total capital including the net
change in future capital 188,196 156,874 75,020 420,090
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Reserve additions excluding
acquisitions and dispositions
(mboe) 4,682 2,877 4,090 11,649
Total proved plus probable finding
and development costs (per boe) $ 40.19 $ 54.53 $ 18.34 $ 36.06
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Finding and Development Costs ("F&D")
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Total Proved Finding and
Development Cost Including FDC,
excluding Acquisitions,
Dispositions, Revisions, and Three
Economic Factors ($ thousands, year
except per unit amounts) 2012 2011 2010 total
----------------------------------------------------------------------------
Capital expenditures excluding
acquisitions and dispositions
abandonment and furniture and
fixtures (unaudited) (1) 84,316 124,981 59,139 268,436
Net change from previously
allocated future development
capital 52,099 12,685 4,782 69,566
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Total capital including the net
change in future capital 136,415 137,666 63,921 338,002
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Reserve additions including
acquisitions, dispositions and
revisions (mboe) 2,145 3,942 2,353 8,439
All-in total proved finding and
development costs (per boe) $ 63.61 $ 34.92 $ 27.17 $ 40.05
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Note: (1) Excludes non-cash costs, including decommissioning liabilities.
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Total Proved Plus Probable
Finding and Development Cost
Including FDC, excluding
Acquisitions, Dispositions,
Revisions, and Economic Factors Three
($ thousands, except per unit year
amounts) 2012 2011 2010 total
----------------------------------------------------------------------------
Capital expenditures excluding
acquisitions and
dispositions,abandonment and
furniture and fixtures
(unaudited) (1) 84,316 124,981 59,139 268,436
Net change from previously
allocated future development
capital 95,915 39,390 9,232 144,537
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Total capital including the net
change in future capital 180,230 164,371 68,371 412,972
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Reserve additions including
acquisitions, dispositions and
revisions (mboe) 4,339 6,480 3,654 14,472
All-in total proved plus
probable finding and
development costs (per boe) $ 41.54 $ 25.37 $ 18.71 $ 28.54
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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
NI 51-101 calculated finding and development costs (excluding acquisitions and
dispositions, abandonment and furniture and fixtures).
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Total Proved Consolidated Canada Tunisia
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Operating netback before
commodity price contracts
($/boe)(unaudited) (1) 23.31 11.86 81.83
51-101 F&D costs
($/boe)(unaudited) 39.27 47.87 38.17
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Recycle ratio 0.6x 0.2x 2.1x
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Total Proved Plus Probable Consolidated Canada Tunisia
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Operating netback before
commodity price contracts
($/boe)(unaudited) (1) 23.31 11.86 81.83
51-101 F&D costs
($/boe)(unaudited) 40.19 96.22 36.20
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Recycle ratio 0.6x 0.1x 2.3x
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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 finding and development costs (excluding
acquisitions and dispositions, abandonment and furniture and fixtures) and
excluding the effects of revisions and economic factors.
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Total Proved Consolidated Canada Tunisia
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Operating netback before
commodity price contracts
($/boe)(unaudited) (1) 23.31 11.86 81.83
F&D costs net of
acquisitions, revisions
and economic factors
($/boe)(unaudited) 63.61 34.76 106.63
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Recycle ratio 0.4x 0.3x 0.8x
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Total Proved Plus Probable Consolidated Canada Tunisia
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Operating netback before
commodity price contracts
($/boe)(unaudited) (1) 23.31 11.86 81.83
F&D costs net of
acquisitions, revisions
and economic factors
($/boe)(unaudited) 41.54 17.23 67.20
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Recycle ratio 0.6x 0.7x 1.2x
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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, 2012, 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 2012 year-end reserve
reports.
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December 31,
2012 Before Tax NPV 5% Before Tax NPV 10% Before Tax NPV 15%
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($ thousands)$/share ($ thousands)$/share ($ thousands)$/share
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Proved plus
probable
reserves NPV
(1,2) 1,170,840 5.47 937,867 4.38 773,311 3.61
Undeveloped
acreage (3) 35,774 0.17 35,774 0.17 35,774 0.17
Net debt (4) (72,121) (0.34) (72,121) (0.34) (72,121) (0.34)
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Net asset
value
(basic) (5) 1,134,493 5.30 901,520 4.21 736,964 3.44
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December 31,
2012 After Tax NPV 5% After Tax NPV 10% After Tax NPV 15%
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($ thousands)$/share ($ thousands)$/share ($ thousands)$/share
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Proved plus
probable
reserves NPV
(1,2 ) 877,466 4.10 702,813 3.28 579,643 2.71
Undeveloped
acreage (3) 35,774 0.17 35,774 0.17 35,774 0.17
Net debt (4) (72,121) (0.34) (72,121) (0.34) (72,121) (0.34)
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Net asset
value
(basic) (5) 841,119 3.93 666,466 3.11 543,296 2.54
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Notes:
(1) Evaluated by independent reserve evaluators as at December 31, 2012.
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, 2012 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, 2012, including working capital deficit
(estimated and unaudited).
(5) Basic shares at December 31, 2012 total 214,187,681 common shares.
Chinook's audited consolidated financial statements and its annual information
form for the year ended December 31, 2012, which will include more detailed
reserves information, are expected to be filed on SEDAR (www.sedar.com) on or
about March 27, 2013.
Bir Ben Tartar - Discovered Petroleum Initially-in-Place
InSite assigned 201.7 million barrels of Discovered Petroleum Initially-In-Place
("DPIIP") to the Bir Ben Tartar (TT Field) discovery as at December 31, 2012.
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 which must be overcome to enable the reclassification of
Contingent Resources as reserves can be categorized as economic, non-technical
and technical. The Canadian Oil and Gas Evaluation Handbook identifies
non-technical contingencies as legal, environmental, political and regulatory
matters or a lack of markets. There are several non-technical contingencies that
prevent the classification of the Contingent Resources estimated below as being
classified as reserves. Although certain areas of the blocks subject to the
estimates are currently undergoing development under approved plans, these plans
do not include the areas of the reservoirs with which all of the Contingent
Resources summarized in the table below are associated. As of the effective date
of the evaluation, information was not available concerning the regulatory
status or, in certain instances, conceptual development plans under which such
Contingent Resources could be brought on production, nor was information
available regarding the likelihood of any such development plans being approved
by Chinook, by its partners in the field, nor by ETAP. Other non-technical
contingencies may include regulatory application submission with no major issues
raised, access to markets and intent to proceed by the operator and other
partners as evidenced by major capital expenditures planned. Technical
contingencies that prevent the classification of the Contingent Resources as
reserves include the early stage of development, the requirement for further
delineation drilling and testing, lack of full field development plans and the
associated facility design. While it is premature at this time to identify the
economic viability of any of the Contingent Resources since evaluations are
currently incomplete and as such, the economic status of the Contingent
Resources is currently undetermined, Chinook is actively carrying out activities
on the TT Field in order to enable it to complete the necessary economic
assessment(s). Furthermore, certain of the reservoir areas evaluated in the
Contingent Resources estimate cover extensive areas that will require
considerable development activity and investment to fully exploit.
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 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.
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Category mbbls
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DPIIP 201,700
Gross Proved + Probable Reserves 10,663
Gross Cumulative Production 1,884
Gross Contingent Resource (Best Estimate) 15,166
Unrecoverable DPIIP 174,016
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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 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: expectations of future plans regarding the Canadian
non-core asset sale process; 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 regarding
production, cash flow, capital expenditures, net debt and debt facility set out
under the heading "Revised 2013 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 GAAP 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 GAAP 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
GAAP. 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.
FOR FURTHER INFORMATION PLEASE CONTACT:
Chinook Energy Inc.
Walter Vrataric
President
(403) 261-6883
Chinook Energy Inc.
L. Geoff Barlow
Vice-President, Finance and Chief Financial Officer
(403) 261-6883
www.chinookenergyinc.com
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