Chinook Energy Inc. Announces its December 31, 2013 Reserves, Operations Update and Renewal of Credit Facilities

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CALGARY, ALBERTA--(Marketwired - Feb. 26, 2014) - Chinook Energy Inc. ("Chinook" or the "Company") (TSX:CKE) today announced the results of its year-end reserve evaluations effective December 31, 2013 as prepared by its independent evaluators. The Company has also provided an operations update and an update on the renewal of its credit facilities.

Chinook's audit of its 2013 annual consolidated financial statements is not yet complete and accordingly all financial amounts referred to in this news release are unaudited and represent management's estimates. Readers are advised that these financial estimates are subject to audit and may be subject to change as a result.

Operational Update and Unaudited 2013 Year-End Results

Chinook's average daily production for fiscal year 2013 was 10,156 barrels of oil equivalent per day. Average production for the fourth quarter of 2013 was 9,680 barrels of oil equivalent per day. Projected cash flow from operations (before changes in non-cash working capital) for 2013 is estimated at $88 million or $0.41 per weighted average basic common share outstanding (unaudited). Year end 2013 net debt is $60 million.

The Canadian business continued to focus on crude oil development in the Grande Prairie area of Alberta along with the disposition of $21 million of non-strategic assets representing approximately 580 boe/d of production. The Tunisian business focused on further light oil development and delineation of the Bir Ben Tartar Concession (the "BBT Concession"). The 2013 drilling program consisted of 20 (11.75 net) wells of which 12 (9.44 net) were operated and eight (2.31 net) were non-operated wells. The results are outlined in the table below:

Wells Drilled
Year ended December 31, 2013 Tunisia Canada Total
Gross Net Gross Net Gross Net
Exploration
Oil - - 4.00 2.24 4.00 2.24
Gas - - - - - -
Dry 1.00 0.86 - - 1.00 0.86
1.00 0.86 4.00 2.24 5.00 3.10
Development
Oil 4.00 2.63 11.00 6.02 15.00 8.65
Gas - - - - - -
Dry - - - - - -
4.00 2.63 11.00 6.02 15.00 8.65
Total 5.00 3.49 15.00 8.26 20.00 11.75

Canada - Grande Prairie Area

Chinook drilled six (4.5 net) horizontal wells during 2013 on the newly acquired Albright property which added approximately 800 boe/d (82% oil) to the original acquired production of 280 boe/d (65% oil). These Dunvegan oil wells have commenced production at rates exceeding management's initial budgeted expectations. The Company plans to drill four horizontal wells on the lands in the first quarter of 2014 and management has identified 24 additional locations on Chinook lands.

At Karr, the Company participated in six (1.89 net) wells during 2013 targeting Dunvegan oil, bringing the total number of wells on the Karr property to nine (2.9 net). The operator has continued to reduce the drilling and completion costs and has commenced the construction of a central battery, which will further improve the economics of this project. The wells continue to meet or exceed management's budgeted expectations. Net production from this property is expected to exceed 700 boe/d in the first quarter of 2014. An additional 16 (7.4 net) horizontal wells have been identified on Chinook lands.

A summary of Chinook's Dunvegan 2013 and 2014 activity is captured below:

Location Drilling Days Frac Stages On Production Date Working Interest (%) IP30 (net boe/d) IP90 (net boe/d) % Oil
Karr - 1,700m Total Vertical Depth
Karr 13-8-66-3W6 24 16 January 2013 26 66 161 77
Karr 13-17-66-3W6 22 15 February 2013 37 169 101 86
Karr 15-17-66-3W6 20 14 April 2013 37 128 118 88
Karr 16-17-66-3W6 20 14 April 2013 37 74 111 86
Karr 14-8-66-3W6 19 16 December 2013 26 112
Karr 16-8-66-3W6 17 16 December 2013 26 94
Karr 15-8-66-3W6 19 16 January 2014 26 76
Karr 14-17-66-3W6 17 16 Est. March 2014 37
Karr 13-10-66-3W6 16 TBD Est. March 2014 26
Beaverlodge - 1,150m Total Vertical Depth
Beaverlodge 16-22-72-10W6 16 7 March 2013 50 58 35 77
Beaverlodge 13-22-72-10W6 11 7 March 2013 50 76 50 89
Beaverlodge 1-26-72-10W6 17 15 September
2013
100 240 289 82
Albright - 1,350m Total Vertical Depth
Albright 4-18-71-10W6 16 12 March 2013 50 53 58 85
Albright 13-19-71-10W6 15 12 August 2013 100 150 146 85
Albright 14-19-71-10W6 13 12 August 2013 100 248 220 82
Albright 3-18-71-10W6 13 16 January 2014 50 250
Albright 13-12-71-11W6 16 16 February 2014 100
Albright 4- 30-71-10W6 16 17 Est. March 2014 100
Albright 11-19-71-10W6 TBD Est. March 2014

Current net production from these Dunvegan wells is 1,412 boe/d at 80% oil with estimated total net drilling, completion, equipping and tie-in costs of $27 million. There are five (3.63 net) additional wells scheduled to come on production in the first quarter of 2014.

During the fourth quarter of 2013, Chinook received well licences to evaluate two new Montney prospects. The first horizontal well (0.75 net) was spud on January 20, 2014 in the Birley/Umbach area of northeastern BC, targeting liquids-rich natural gas. The well reached total depth in 12 days, six days faster than originally budgeted, with completion and testing operations currently underway. The success of the first Birley/Umbach well could lead to a large-scale development on Chinook's 35 (24 net) sections of land. The second horizontal Montney well (0.37 net) was spud on January 21, 2014 in the Karr/Gold Creek area, immediately adjacent to a recently completed industry Montney well that reported initial test rates of 2,200 boe/d (50% oil) in 2013. Chinook holds 84 (50 net) sections of Montney land in the greater Gold Creek area and has budgeted a second horizontal well on a separate Montney prospect in the second half of 2014.

Tunisia

Chinook drilled one horizontal and two vertical (2.58 net) wells on the BBT Concession during 2013, bringing the total number of wells on the concession to 15 (12.9 net). The Company expects to drill six (5.16 net) development wells on the BBT Concession in the first half of 2014 and commence the construction of a central gathering facility and oil battery. The third well of the six well program was spud on February 11, 2014 with completion and testing operations on the first two wells, TT-28 and TT-15, currently underway.

In 2014, the Company also plans to participate in one well (0.1 net) on the Borj El Khadra Permit and one well (0.05 net) on the Adam Concession.

2013 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, 2013 and report dated February 26, 2014; and
  • InSite Petroleum Consultants Ltd. ("InSite") evaluated all of the Tunisia interests effective December 31, 2013 and report dated February 26, 2014.

The independent reserve evaluations effective December 31, 2013 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's forecast pricing and foreign exchange rates at December 31, 2013. Chinook's Reserves, Safety and Environmental Committee and Board of Directors have reviewed and approved the evaluations prepared by the evaluators.

Reserves included herein are stated on a Company gross basis (working interest before deduction of royalties and without including any royalty interests) unless noted otherwise. This news release contains several cautionary statements that are specifically required by NI 51-101 under the heading "Reader Advisory" and throughout the release. In addition to the information contained in this news release more detailed reserves information will be included in Chinook's Annual Information Form for the year ended December 31, 2013 ("AIF"), which will be filed on SEDAR at www.sedar.com on or about March 27, 2014.

Reserves Breakdown (Company gross) (1)
(December 31, 2013, escalated price forecast)
(mboe) 2013 2012
Proved Producing
Canada 12,711 14,966
Tunisia 1,424 1,516
Total proved producing 14,136 16,482
Proved
Canada 16,020 19,069
Tunisia 4,846 9,880
Total proved 20,866 28,949
Proved Plus Probable
Canada 25,090 31,207
Tunisia 8,132 20,445
Total proved plus probable 33,222 51,652
Note: (1) Columns may not add due to rounding.

Company Gross and Net Reserves as at December 31, 2013

The following table summarizes the Company's gross and net reserve volumes utilizing McDaniel's forecast pricing and cost estimates at December 31, 2013.

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 2,947 2,508 65 63 51,435 44,230 1,128 792 12,711 10,735
Developed non-producing 519 436 - - 7,021 6,008 145 102 1,835 1,540
Undeveloped 1,190 1,017 - - 1,539 1,394 28 20 1,474 1,270
Total proved 4,656 3,962 65 63 59,995 51,632 1,301 914 16,020 13,544
Probable 2,375 1,896 22 21 35,088 29,525 825 580 9,070 7,418
Total proved plus probable 7,030 5,857 87 85 95,083 81,157 2,126 1,494 25,090 20,962
Tunisia
Proved
Developed producing 1,248 1,197 - - 1,055 960 - - 1,424 1,357
Developed non-producing 650 603 - - 3,172 2,814 - - 1,179 1,072
Undeveloped 2,002 1,965 - - 1,444 1,312 - - 2,243 2,184
Total proved 3,901 3,766 - - 5,670 5,086 - - 4,846 4,613
Probable 2,938 2,885 - - 2,089 1,854 - - 3,286 3,194
Total proved plus probable 6,839 6,651 - - 7,759 6,939 - - 8,132 7,807
Total company
Proved
Developed producing 4,195 3,705 65 63 52,490 45,190 1,128 792 14,136 12,092
Developed non-producing 1,170 1,040 - - 10,192 8,822 145 102 3,014 2,612
Undeveloped 3,192 2,983 - - 2,983 2,706 28 20 3,716 3,454
Total proved 8,556 7,727 65 63 65,665 56,718 1,301 914 20,866 18,158
Probable 5,313 4,781 22 21 37,176 31,379 825 580 12,356 10,611
Total proved plus probable 13,869 12,508 87 85 102,842 88,097 2,126 1,494 33,222 28,769
Notes:
(1) Gross reserves are the Company's working interest reserves before royalty deductions and do not include royalty interest volumes.
(2) Net reserves are after royalty deductions and include royalty interest volumes.
(3) Columns may not add due to rounding.
Company Gross Reserve Reconciliation for 2013 (1)
(Company gross reserves before deduction of royalties payable)
6:1 Oil Equivalent (mboe)
Total Proved Probable Proved Plus
Probable
December 31, 2012 - opening balance 28,949 22,703 51,652
Additions and extensions 2,195 1,002 3,197
Category transfers 9 (9 ) -
Discoveries 55 14 69
Acquisitions - - -
Dispositions (1,134 ) (578 ) (1,712 )
Technical revisions (32 ) (2,680 ) (2,649 )
Economic factors (2) (5,538 ) (8,095 ) (13,633 )
Production (3,702 ) - (3,702 )
December 31, 2013 - closing balance 20,866 12,356 33,222
Note:
(1) Columns may not add due to rounding.
(2) Reserve volumes at Cosmos and Yasmin in Tunisia have been recategorized from reserves to economic contingent resources due to the inability of the Company to place the volumes on-stream in a reasonable period of time as per COGE guidelines. These recategorized volumes on a proved and on a proved plus probable basis are 5.2 mmboe and 12.6 mmboe, respectively.

In 2013, Chinook completed several dispositions of non-core properties which resulted in net proceeds of $21 million. Dispositions within the Company's West Central Alberta operating district represented the vast majority of the proved and probable reserve reductions of approximately 1.7 mmboe.

Year over year, McDaniel recorded net negative technical revisions related to performance issues of approximately 1.0 mmboe on a proved plus probable reserves basis. Offsetting these revisions, the Company recorded a 1.3 mmboe positive revision related to the proved producing category of reserves. The negative revisions are partially attributed to well performance from the Braeburn and Boundary Lake zones drilled in 2011. In addition to the performance related revisions, the Company elected to remove certain undeveloped reserve bookings totaling approximately 1.9 mmboe on the basis that the timing of the allocation of capital to these projects would not meet guidelines to maintain proved or proved plus probable bookings or in certain circumstances projects generated minimal net present value. On a proved plus probable basis, these reserve volumes were primarily natural gas and held minor net present value in the current price forecast. Chinook has generally good tenure on the lands associated with these reserves and will maintain these opportunities within its portfolio for future evaluation while the Company focuses its attention on its more profitable Dunvegan oil program.

A downward adjustment in the independent price forecast for both natural gas and Brent crude oil resulted in net negative revisions due to economic factors in the Canadian reserves affecting proved and probable reserves and net present values in all areas despite a 4% increase in estimated first year Canadian gas prices. Of particular note, Chinook added a total of 3.2 mmboe (80% oil and NGLs) on a proved plus probable basis. The additions are more than 90% focused in the Company's Canadian core areas of Karr, Albright and Beaverlodge (Dunvegan oil) and the BBT Concession of southern Tunisia. In Canada, production in 2013 was 3.0 mmboe (69% natural gas, 21% oil and 10% NGLs) while the proved plus probable reserves added in the same period were 2.2 mmboe (20% natural gas, 78% oil and 2% NGLs). The success of these core areas will continue to be Chinook's focus for its capital expenditures given the attractive economics while allowing for additional testing of high impact resource plays at Karr and Birley/Umbach.

Chinook has determined that an appraisal well is required on a separate accumulation within the Cosmos Concession prior to proceeding with installation of permanent facilities. This deferral delays project start-up of both Cosmos and Yasmin, the latter of which is contemplated as a tie back to the former. Following Chinook's advisement of the new timeline for progressing the project, InSite amended the classification of both the Cosmos and Yasmin reserves to Contingent Resources (Economic). Although there are no technical changes from the prior year, the development timeline falls outside the guidelines provided for a reserve categorization.

Reserve Life Index ("RLI")

Chinook's proved plus probable RLI was 9.4 years based upon the McDaniel and InSite reserves reports and the annualized December 2013 production volumes, while the proved RLI was 5.9 years. The following table summarizes the RLI split between Canada and Tunisia:

Proved Consolidated Canada Tunisia
Reserves (mboe) 20,866 16,020 4,846
Annualized December 2013 production (mboe) 3,530 2,904 626
Reserve life index (years) 5.9 5.5 7.7
Proved Plus Probable Consolidated Canada Tunisia
Reserves (mboe) 33,222 25,090 8,132
Annualized December 2013 production (mboe) 3,530 2,904 626
Reserve life index (years) 9.4 8.6 13.0

Consolidated

Net Present Value ("NPV") Summary (before tax) as at December 31, 2013

(December 31, 2013, 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 do 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 330,465 280,713 246,550 221,540 202,350
Proved non-producing 116,481 89,090 71,005 58,323 49,011
Total proved developed 446,946 369,802 317,555 279,863 251,361
Proved undeveloped 141,787 99,987 72,824 53,993 40,363
Total proved 588,734 469,790 390,379 333,857 291,724
Probable 412,877 268,334 191,022 143,664 112,128
Total proved plus probable 1,001,611 738,124 581,401 477,521 403,852
Canada
Net Present Value Summary (before tax) as at December 31, 2013
(December 31, 2013, escalated price forecast)
($ thousands) Undiscounted Discounted at
5%
Discounted at
10%
Discounted at
15%
Discounted at
20%
Proved producing 252,566 208,742 179,419 158,435 142,650
Proved non-producing 39,785 29,586 23,582 19,681 16,942
Total proved developed 292,351 238,328 203,001 178,116 159,592
Proved undeveloped 46,744 29,971 20,416 14,338 10,169
Total proved 339,095 268,299 223,416 192,454 169,761
Probable 223,921 131,503 88,871 65,493 51,088
Total proved plus probable 563,016 399,802 312,287 257,947 220,849
Tunisia
Net Present Value Summary (before tax) as at December 31, 2013
(December 31, 2013, escalated price forecast)
($ thousands) Undiscounted Discounted at
5%
Discounted at
10%
Discounted at
15%
Discounted at
20%
Proved producing 77,899 71,971 67,132 63,105 59,700
Proved non-producing 76,696 59,504 47,423 38,642 32,069
Total proved developed 154,595 131,475 114,555 101,748 91,768
Proved undeveloped 95,043 70,016 52,408 39,655 30,195
Total proved 249,639 201,491 166,963 141,403 121,963
Probable 188,956 136,831 102,151 78,171 61,040
Total proved plus probable 438,595 338,321 269,114 219,574 183,003

Consolidated

Net Present Value Summary (after tax) as at December 31, 2013

(December 31, 2013, 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 312,484 265,022 232,609 208,968 190,876
Proved non-producing 81,995 64,070 52,249 43,870 37,611
Total proved developed 394,478 329,092 284,858 252,839 228,487
Proved undeveloped 123,818 87,590 63,857 49,240 35,101
Total proved 518,296 416,682 348,714 300,079 263,588
Probable 346,441 233,088 170,037 130,043 102,663
Total proved plus probable 864,737 649,770 518,752 430,122 366,251
Canada
Net Present Value Summary (after tax) as at December 31, 2013
(December 31, 2013, escalated price forecast)
($ thousands) Undiscounted Discounted at
5%
Discounted at
10%
Discounted at
15%
Discounted at
20%
Proved producing 252,566 208,742 179,419 158,435 142,650
Proved non-producing 39,785 29,586 23,582 19,681 16,942
Total proved developed 292,351 238,328 203,001 178,116 159,592
Proved undeveloped 46,744 29,971 20,416 14,338 10,169
Total proved 339,095 268,299 223,416 192,454 169,761
Probable 187,848 115,647 81,114 61,405 48,810
Total proved plus probable 526,943 383,946 304,531 253,859 218,571
Tunisia
Net Present Value Summary (after tax) as at December 31, 2013
(December 31, 2013, escalated price forecast)
($ thousands) Undiscounted Discounted at
5%
Discounted at
10%
Discounted at
15%
Discounted at
20%
Proved producing 59,917 56,281 53,190 50,533 48,226
Proved non-producing 42,210 34,484 28,667 24,190 20,669
Total proved developed 102,127 90,764 81,857 74,723 68,894
Proved undeveloped 77,074 57,619 43,441 32,902 24,933
Total proved 179,201 148,383 125,298 107,625 93,827
Probable 158,593 117,441 88,923 68,638 53,853
Total proved plus probable 337,794 265,824 214,221 176,262 147,679

McDaniel & Associates Consultants Ltd. Escalating Price Forecast as at December 31, 2013 (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)
2014 95.00 105.00 95.00 4.25 4.00 102.50 50.20 76.60 0.950
2015 95.00 102.50 96.50 4.50 4.25 101.60 50.50 77.80 0.950
2016 95.00 100.20 97.50 4.75 4.55 100.60 50.60 78.60 0.950
2017 95.00 97.70 98.00 5.00 4.75 101.20 51.30 79.00 0.950
2018 95.30 98.00 98.30 5.25 5.00 101.50 52.00 79.20 0.950
95.06 100.68 97.06 4.75 4.51 101.48 50.92 78.24 0.950
Note:
(1) Prices escalate at two percent per year after 2018.

Future Development Costs ("FDC")

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

($ millions)
2013 2012
Proved
Canada 36.8 28.1
Tunisia 86.0 242.3
Total proved 122.8 270.4
Proved Plus Probable
Canada 57.4 66.7
Tunisia 156.3 402.4
Total proved plus probable 213.7 469.1

Chinook's approved 2014 budget includes the drilling of 11 wells (7.0 net) in Canada and 6.0 wells (4.3 net) in Tunisia.

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

NI 51-101 requires that finding and development costs be calculated including changes in undiscounted FDC. Chinook's F&D costs, calculated in accordance with NI 51-101 are set forth below.

Total Finding and Development Cost (Proved Reserves)
($ thousands, except per unit amounts)
2013 2012 2011 Three year total
Exploration and development costs excluding acquisitions and dispositions(unaudited) (1) 87,990 84,316 124,987 297,286
Net change from previously allocated future development capital (147,570 ) 78,689 20,471 (48,410 )
Total exploration and development costs including the net change in FDC (59,581 ) 163,005 145,452 248,876
Reserve additions excluding acquisitions and dispositions (mboe) (3,247 ) 4,151 2,671 3,575
Total proved finding and development costs (per boe) $18.35 $39.27 $54.45 $69.61
Total Finding and Development Cost (Proved plus Probable Reserves)($ thousands, except per unit amounts) 2013 2012 2011 Three year total
Exploration and development costs excluding acquisitions and dispositions(unaudited) (1) 87,990 84,316 124,981 297,286
Net change from previously allocated future development capital (254,271 ) 103,880 31,893 (118,498 )
Total exploration and development costs including the net change in FDC (166,282 ) 188,196 156,874 178,788
Reserve additions excluding acquisitions and dispositions (mboe) (13,016 ) 4,682 2,877 (5,457 )
Total proved plus probable finding and development costs (per boe) $12.78 $40.19 $54.53 $(32.77 )

All-In Finding, Development and Acquisition Costs

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

All-In Finding, Development and Acquisition Cost Including FDC, Acquisitions, Dispositions and Revisions (Proved Reserves)
($ thousands, except per unit amounts)
2013 2012 2011 Three year total
Exploration and development costs including acquisitions and dispositions(unaudited) (1) 74,474 11,861 50,978 137,313
Net change from previously allocated future development capital (147,656 ) 84,418 17,452 (45,786 )
Total exploration and development costs including the net change in FDC (73,182 ) 96,279 68,430 91,527
Reserve additions including acquisitions, dispositions and revisions (mboe) (4,381 ) 1,246 64 (3,071 )
All-in total proved finding, development and acquisition costs (per boe) $16.70 $77.25 $1,074.93 $29.80
All-In Finding, Development and Acquisition Cost Including FDC, Acquisitions, Dispositions and Revisions (Proved plus Probable Reserves)
($ thousands, except per unit amounts)
2013 2012 2011 Three year total
Exploration and development costs including acquisitions and dispositions(unaudited) (1) 74,474 11,861 50,978 137,313
Net change from previously allocated future development capital (255,383 ) 107,738 23,573 (124,072 )
Total exploration and development costs including the net change in FDC (180,909 ) 119,599 74,551 13,242
Reserve additions including acquisitions, dispositions and revisions (mboe) (14,728 ) 305 (1,335 ) (15,758 )
All-in total proved plus probable finding and development costs (per boe) $12.28 $391.53 $(55.84 ) $(0.84 )
Note: (1) Excludes non-cash costs, including decommissioning liabilities.

Adjusted Finding and Development Costs

Chinook's adjusted F&D costs after giving effect to revisions and economic factors is set forth below. This has been provided in order to reflect the Company's pure capital efficiency with respect to the reserve additions achieved through organic capital expenditures.

Adjusted Finding and Development Cost Including FDC, excluding Acquisitions, Dispositions, Revisions, and Economic Factors (Proved Reserves)
($ thousands, except per unit amounts)
2013 2012 2011 Three year total
Exploration and development costs excluding acquisitions and dispositions(unaudited) (1) 87,990 84,316 124,981 297,286
Net change from previously allocated future development capital 12,750 52,099 12,685 77,534
Total exploration and development costs including the net change in FDC 100,739 136,415 137,666 374,820
Reserve additions including acquisitions, dispositions and revisions (mboe) 2,259 2,145 3,942 8,346
Adjusted total proved finding and development costs (per boe) $44.59 $63.61 $34.92 $44.91
Adjusted Finding and Development Cost Including FDC, excluding Acquisitions, Dispositions, Revisions, and Economic Factors (Proved plus Probable Reserves)
($ thousands, except per unit amounts)
2013 2012 2011 Three year total
Exploration and development costs excluding acquisitions and dispositions(unaudited) (1) 87,990 84,316 124,981 297,286
Net change from previously allocated future development capital 11,120 95,915 39,390 146,425
Total exploration and development costs including the net change in FDC 99,110 180,230 164,371 443,711
Reserve additions including acquisitions, dispositions and revisions (mboe) 3,266 4,339 6,480 14,085
Adjusted total proved plus probable finding and development costs (per boe) $30.35 $41.54 $25.37 $31.50

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

Recycle Ratio

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

Total Proved Consolidated Canada Tunisia
Operating netback before commodity price contracts ($/boe)(unaudited) (1) 28.88 18.04 75.97
51-101 F&D costs ($/boe)(unaudited) 18.35 44.91 25.01
Recycle ratio 1.6x 0.4x 3.0x
Total Proved Plus Probable Consolidated Canada Tunisia
Operating netback before commodity price contracts ($/boe)(unaudited) (1) 28.88 18.04 75.97
51-101 F&D costs ($/boe)(unaudited) 12.78 (22.78 ) 17.07
Recycle ratio 2.3x (0.8x ) 4.5x
Note: (1) Operating netback is calculated by deducting royalties and net production expenses from revenue.

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

Total Proved Consolidated Canada Tunisia
Operating netback before commodity price contracts ($/boe)(unaudited) (1) 28.88 18.04 75.97
All-in F&D costs ($/boe)(unaudited) 16.70 (745.45 ) 24.91
Recycle ratio 1.7x 0.0x 3.1x
Total Proved Plus Probable Consolidated Canada Tunisia
Operating netback before commodity price contracts ($/boe)(unaudited) (1) 28.88 18.04 75.97
All-in F&D costs ($/boe)(unaudited) 12.28 (5.41 ) 17.03
Recycle ratio 2.4x (3.3x ) 4.5x
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.

Total Proved Consolidated Canada Tunisia
Operating netback before commodity price contracts ($/boe)(unaudited) (1) 28.88 18.04 75.97
Adjusted F&D costs net of acquisitions, revisions and economic factors ($/boe)(unaudited) 44.59 34.56 65.15
Recycle ratio 0.6x 0.5x 1.2x
Total Proved Plus Probable Consolidated Canada Tunisia
Operating netback before commodity price contracts ($/boe)(unaudited) (1) 28.88 18.04 75.97
Adjusted F&D costs net of acquisitions, revisions and economic factors ($/boe)(unaudited) 30.35 22.09 48.35
Recycle ratio 1.0x 0.8x 1.6x
Note: (1) Operating netback is calculated by deducting royalties and net production expenses from revenue.

Corporate Net Asset Value

The Company's net asset value as of December 31, 2013, 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 2013 year-end reserve reports.

December 31, 2013 Before Tax NPV 5% Before Tax NPV 10% Before Tax NPV 15%
($ thousands) $/share ($ thousands) $/share ($ thousands) $/share
Total Company
Proved developed producing reserves NPV (1,2) 280,713 1.31 246,550 1.15 221,540 1.03
Total proved reserves NPV (1,2) 469,790 2.19 390,379 1.82 333,857 1.56
Proved plus probable reserves NPV (1,2) 738,124 3.45 581,401 2.71 477,521 2.23
Undeveloped acreage (3) 52,217 0.24 52,217 0.24 52,217 0.24
Net debt (4) (59,432 ) (0.28 ) (59,432 ) (0.28 ) (59,432 ) (0.28 )
Net asset value (basic) (5) 730,909 3.41 574,186 2.68 470,306 2.19
Canada
Proved developed producing reserves NPV (1,2) 208,742 0.97 179,419 0.84 158,435 0.74
Total proved reserves NPV (1,2) 268,299 1.25 223,416 1.04 194,454 0.91
Proved plus probable reserves NPV (1,2) 399,802 1.87 312,287 1.46 257,947 1.20
Undeveloped acreage (3) 52,217 0.24 52,217 0.24 52,217 0.24
Net debt (4) (59,432 ) (0.28 ) (59,432 ) (0.28 ) (59,432 ) (0.28 )
Net asset value (basic) (5) 392,588 1.83 305,072 1.42 250,733 1.16
Tunisia
Proved developed producing reserves (NPV) (1,2) 71,971 0.34 67,132 0.31 63,105 0.29
Total proved reserves NPV (1,2) 201,491 0.94 169,963 0.78 141,403 0.66
Proved plus probable reserves NPV (1,2) 338,321 1.58 269,114 1.26 219,574 1.03
Net asset value (basic) (5) 338,321 1.58 269,114 1.26 219,574 1.03
December 31, 2013 After Tax NPV 5% After Tax NPV 10% After Tax NPV 15%
($ thousands) $/share ($ thousands) $/share ($ thousands) $/share
Total Company
Proved developed producing reserves NPV (1,2) 265,022 1.24 232,609 1.09 208,968 0.98
Total proved reserves NPV (1,2) 416,682 1.95 348,714 1.63 300,079 1.40
Proved plus probable reserves NPV (1,2) 649,770 3.03 518,752 2.42 430,122 2.01
Undeveloped acreage (3) 52,217 0.24 52,217 0.24 52,217 0.24
Net debt (4) (59,432 ) (0.28 ) (59,432 ) (0.28 ) (59,432 ) (0.28 )
Net asset value (basic) (5) 642,555 3.00 511,537 2.39 422,907 1.97
Canada
Proved developed producing reserves NPV (1,2) 208,742 0.97 179,419 0.84 158,435 0.74
Total proved reserves NPV (1,2) 268,299 1.25 223,416 1.04 192,454 0.90
Proved plus probable reserves NPV (1,2) 383,946 1.79 304,531 1.42 253,859 1.19
Undeveloped acreage (3) 52,217 0.24 52,217 0.24 52,217 0.24
Net debt (4) (59,432 ) (0.28 ) (59,432 ) (0.28 ) (59,432 ) (0.28 )
Net asset value (basic) (5) 376,731 1.76 297,316 1.39 246,645 1.15
Tunisia
Proved developed producing reserves NPV (1,2) 56,281 0.26 53,190 0.25 50,533 0.24
Total proved reserves NPV (1,2) 148,383 0.69 125,298 0.58 107,625 0.50
Proved plus probable reserves NPV (1,2) 265,824 1.24 214,221 1.00 176,262 0.82
Net asset value (basic) (5) 265,824 1.24 214,221 1.00 176,262 0.82
Notes:
(1) Evaluated by independent reserve evaluators as at December 31, 2013. 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, 2013 escalated price forecast.
(3) Undeveloped land value has been valued by an independent evaluator for all Canadian lands.
(4) Net debt as at December 31, 2013, including working capital deficit (estimated and unaudited). See "Net Debt" discussion below.
(5) Basic shares at December 31, 2013 totaled 214,187,681 common shares.

Renewal of Credit Facilities

Chinook's Canadian revolving term credit facility was maintained at $115 million during the semi-annual redetermination in December 2013. The Company had drawn $78.5 million pursuant to its Canadian revolving term facility as at December 31, 2013 and is currently drawn the same amount under this facility. As at December 31, 2013 the Company's net debt, which is calculated as bank debt adjusted for working capital excluding mark-to-market derivative contracts, was $60 million. The next review and renewal of this facility is scheduled to take place in June 2014.

Chinook's borrowing base amount available under the international credit facility was redetermined to be USD$23.8 million at the semi-annual review in January 2014, down from the previous USD$46.5 million. The reduction in the borrowing base amount reflects the delay in bringing production on-stream as a result of the deferred 2013 capital program and a short term increase in operating costs until a gathering facility is constructed. The Company has never drawn on this facility and the next review and renewal is scheduled to take place in June 2014.

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.

Oil and Gas Advisory

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

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

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

The reserves information contained in this press release has been prepared in accordance with NI 51-101. Complete NI 51-101 reserves disclosure will be included in the Company's Annual Information Form for the year ended December 31, 2013 which is expected to be filed on or about March 27, 2014. Listed below are cautionary statements applicable to the Company's reserves information that are specifically required by NI 51-101:

  • Individual properties may not reflect the same confidence level as estimates of reserves for all properties due to the effects of aggregation.

  • This news release contains estimates of the net present value of the Company's future net revenue from its reserves. Such amounts do not represent the fair market value of the Company's reserves.

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" and "resources" are deemed to be forward-looking statements as they involve the implied assessment, based on certain estimates and assumptions, that the reserves and/or resources described exist in the quantities predicted or estimated and can be profitably produced in the future. In particular, this news release contains, without limitation, forward-looking statements pertaining to: estimated cash flows, drilling plans at certain of the Company's core areas, anticipated filing dates for the Company's annual filings, 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; estimated on-production dates for certain drilled wells; estimated total costs for the Company's Dunvegan wells; future oil and natural gas prices and Chinook's commodity risk management program; future results from operations and operating metrics; scheduled reviews of the Company's credit facilities; and future development, exploration, acquisition and development activities (including drilling plans) and related production expectations.

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 Company's lenders reviewing Chinook's credit facilities in the time periods currently scheduled, 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, all costs in respect of certain wells being accurately estimated. 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 risks 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, 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 and increased costs or unforeseen costs. As a consequence, actual results may differ materially from those anticipated in the forward-looking statements. Readers are cautioned that the forgoing list of factors is not exhaustive. Additional information on these and other factors that could effect Chinook's operations and financial results are included in reports on file with Canadian securities regulatory authorities and may be accessed through the SEDAR website (www.sedar.com) and at Chinook's website (www.chinookenergyinc.com). Furthermore, the forward-looking statements contained in this news release are made as at the date of this news release and Chinook does not undertake any obligation to update publicly or to revise any of the forward-looking statements, whether as a result of new information, future events or otherwise, except as may be required by applicable securities laws.

Barrels of Oil Equivalent

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

Initial Production Rates

Any reference in this news release to initial, early and/or test or production/performance rates (including IP30 and IP90) are useful in confirming the presence of hydrocarbons, however, such rates are not determinative of the rates at which such wells will continue production and decline thereafter. Additionally, such rates may also include recovered "load oil" fluids used in well completion stimulation. While encouraging, readers are cautioned not to place reliance on such rates in calculating the aggregate production for Chinook. The initial production rate may be estimated based on other third party estimates or limited data available at this time. In all cases in this news release initial production or test rates are not necessarily indicative of long-term performance of the relevant well or fields or of ultimate recovery of hydrocarbons.

Reserve Life Index

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

Cash flow 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 IFRS 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.

Net Debt

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

Future Oriented Financial Information

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



Chinook Energy Inc.
Walter Vrataric
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