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Chinook Energy Inc. Announces Its Unaudited 2018 Year End Results and Reserves


CALGARY, Alberta, Feb. 12, 2019 (GLOBE NEWSWIRE) — Chinook Energy Inc. (“Chinook” or the“Company”) (TSX: CKE) today announced its unaudited 2018 year end results and the results of its year end reserve evaluation effective December 31, 2018 as prepared by its independent evaluator.

Chinook’s audit of its 2018 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.

Highlights

  • Proved producing reserves decreased 16% year over year. An amount approximately equal to production during the period.
  • Total proved reserves decreased 1% year over year, and the all-in FD&A costs were $13.42/boe.
  • Total proved plus probable reserves increased 5% year over year, additions replaced 233% of production and the all-in FD&A costs were $8.38/boe.
  • PV10 values for proved producing, total proved and total proved plus probable reserves decreased 38%, 30% and 15%, respectively, driven by an average 25% reduction to forecasted five year BC Plantgate gas prices.

Unaudited 2018 Year-End Results

Chinook’s average daily production for 2018 was 3,719 boe/d and the Company exited 2018 at approximately 3,500 boe/d through December. Chinook’s production was significantly impacted by third party restrictions during 2018. The Company experienced approximately four months of production restriction in the first and second quarters of 2018 due to the Oak pipeline integrity issue previously disclosed. Additionally, the T-South pipeline rupture at the beginning of the fourth quarter has restricted flows physically or by price related elective reductions during the fourth quarter of 2018. During significant portions of these periods of restriction, the Company’s production had been limited to less than half of its productive capacity. Following an unplanned 22 day outage of the McMahon processing facility in January 2019, Chinook has returned its production to a largely unrestricted flow and is currently producing approximately 4,500 boe/d. Projected adjusted funds flow for Chinook for 2018 is estimated at $4.2 million or $0.02 per weighted average basic common share outstanding. Chinook exited 2018 with approximately $2.0 million in working capital deficit.

During 2018, Chinook remained committed to capital discipline and cost control while continuing to develop its large Montney position at its Birley/Umbach property.  The Company drilled and completed two (2.0 net) vertical wells on a 21 (20.5 net) section parcel of contiguous Montney rights at Martin, located five kilometres north of Chinook’s main Montney land block at Birley, to determine the existence, thickness, and quality of pay in the Montney interval.  These vertical wells were drilled six kilometres apart and more than 12 kilometres north and east of the nearest Montney wells drilled to date.  Each well encountered approximately 225 metres of total Montney thickness compared to approximately 238 metres at Birley.  The quality of the reservoir encountered, particularly in the top 75 metres of the Montney, exceeded expectations with some of the best and most consistent hydrocarbon charged porosity seen on wireline log data in the entire area.  Each well was perforated to obtain pressure information, and will be fully abandoned in the first half of 2019 to satisfy flow-through financing obligations.  Chinook is very encouraged by these results and believes a significant extension to the productive Montney fairway exists on Company lands thus further expanding its future horizontal Montney drilling inventory.

Chinook remains committed to improving its cost structure and will see its office related expenses decrease in 2019 primarily through the conclusion of its current office lease and lease of new space at current market rates. Additionally, the Company continues to lever its existing assets and has completed a transportation agreement for the partial use of its 12” Aitken Creek pipeline. The agreement will commence on the initial delivery of gas, anticipated to be late 2019 or early 2020, and will continue for a minimum period of two years. Minimum gathering charges will total approximately $1.6 million annually.

As Western Canadian natural gas price weakness continues related to export capacity constraints, including T-South restrictions, the Company remains cautious in deploying further capital. Consequently, 2019 will see a minimal capital program until such time as commodity prices improve to constructive levels. Management and the Board of Directors will make adjustments to the capital program in response to changing market conditions. Chinook has recently renewed its $10 million Demand Credit Facility. The next scheduled semi-annual review is scheduled for May 2019.

2018 Independent Reserves Evaluation

McDaniel & Associates Consultants Ltd. (“McDaniel”) evaluated all of Chinook’s properties effective December 31, 2018 pursuant to a report dated February 12, 2019 (the “McDaniel Report”).  The independent reserve evaluation was prepared in accordance with the definitions, standards and procedures contained in the Canadian Oil and Gas Evaluation Handbook (“COGE Handbook”) and National Instrument 51-101 (“NI 51-101”).  The reserve evaluation was based on the average forecast pricing and foreign exchange rates at December 31, 2018 of three evaluators, McDaniel, GLJ Petroleum Consultants Ltd. and Sproule Associates Limited, herein referred to as “the Consultants Average Price Forecast”, whereas the previous year was evaluated using the McDaniel December 31, 2017 price forecast.  The Reserves, Safety and Environmental Committee of the Board and the Board of Directors of Chinook have reviewed and approved the McDaniel Report.

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, 2018, which will be filed on SEDAR at www.sedar.com in March 2019. Values in the following tables may not add due to rounding.

Reserves Breakdown (Company gross) (1)
(utilizing the Consultants Average Price Forecast at December 31, 2018)

 
(mboe) 2018 2017
Proved Producing  
Total proved producing 6,814 8,101
Proved  
Total proved 18,393 18,646
Proved Plus Probable  
Total proved plus probable 35,626 33,910

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

Company Gross and Net Reserves as at December 31, 2018

The following table summarizes the Company’s gross and net reserve volumes utilizing the Consultants Average Price Forecast, and cost estimates, at December 31, 2018.

Light and
medium oil
Heavy oil Conventional
Natural Gas
Natural gas
liquids
Oil equivalent
(6:1)
Reserves category Gross (1)
(mbbl)
Net (2)
(mbbl)
Gross (1)
(mbbl)
Net (2)
(mbbl)
Gross (1)
(mmcf)
Net (2)
(mmcf)
Gross (1)
(mbbl)
Net (2)
(mbbl)
Gross (1)
(mboe)
Net (2)
(mboe)
Total company
Proved
Developed producing 8 7 35,197 31,539 940 789 6,814 6,052
Developed non-producing 10 9 117 102 3 2 33 29
Undeveloped 58,257 50,212 1,837 1,585 11,546 9,954
Total proved 18 16 93,571 81,854 2,780 2,376 18,393 16,035
Probable 6 6 87,754 71,830 2,601 2,152 17,233 14,129
Total proved plus probable 24 22 181,326 153,683 5,381 4,528 35,626 30,164

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.

Company Gross Reserve Reconciliation for 2018
(Company gross reserves before deduction of royalties payable)

  6:1 Oil Equivalent (mboe)
  Total proved Probable additional Total proved plus probable
December 31, 2017 – opening balance 18,646 15,264 33,910
Additions and extensions 3,166 3,166
Acquisitions
Dispositions
Technical revisions 1,104 (1,197) (93)
Economic factors
Production (1,358) (1,358)
December 31, 2018 – closing balance 18,393 17,233 35,626

Chinook added a total of 3.2 mmboe on a probable basis and increased its proved reserves 1.1 mmboe through the category transfer of two (2.0 net) previously booked Probable additional undeveloped locations and two (2.0 net) Proved developed non-producing wells to Probable developed non-producing. The category transfers are included in the Total proved Technical revisions summarized above. The additions are focused in the Company’s core Montney area of Birley/Umbach, British Columbia and include four (3.7 net) probable additional undeveloped locations.  At December 31, 2018, in addition to the 13 (11.3 net) proved developed producing wells, McDaniel recognized a total of 37 undeveloped locations, 21 (18.1 net) proved and 16 (13.1 net) probable undeveloped locations.  As at the date of the McDaniel Report, approximately 19% of Chinook’s greater Birley/Umbach Montney acreage was booked.

Reserve Life Index (“RLI”)

As at December 31, 2018, Chinook’s proved plus probable RLI was 27.2 years based upon the McDaniel Report and the forecast 2019 production volumes from the report, while Chinook’s proved RLI was 14.6 years. The following table summarizes the RLI:

Proved
Reserves (mboe) 18,393
2019 Forecast production – Proved (mboe) (1) 1,262
Reserve life index (years) 14.6
Proved Plus Probable
Reserves (mboe) 35,626
2019 Forecast production – Proved Plus Probable (mboe) (1) 1,311
Reserve Life Index (years) 27.2

Note:
(1) As evaluated by McDaniel, an independent reserve evaluator, as at December 31, 2018.

Net Present Value (“NPV”) Summary (before tax) as at December 31, 2018
(utilizing the Consultants Average Price Forecast at December 31, 2018)

Benchmark commodity prices used are adjusted for the quality of the commodities produced and for transportation costs.  The calculated NPVs include a deduction for estimated future well and certain facilities abandonment and reclamation but do not include a provision for interest, debt service charges, general and administrative expenses, or estimated future well abandonment and reclamation costs for those wells with no attributable reserves and other facilities.  It should not be assumed that the NPV estimates represent the fair market value of the reserves.

($ thousands) Undiscounted Discounted at
5%
Discounted at
10%
Discounted at
15%
Discounted at
20%
Proved developed producing 33,690 30,674 27,143 24,057 21,509
Proved developed non-producing 62 88 99 103 102
Total proved developed 33,752 30,762 27,242 24,160 21,611
Proved undeveloped 74,000 47,591 30,295 18,674 10,642
Total proved 107,752 78,353 57,538 42,834 32,253
Probable additional 198,671 116,219 72,879 48,388 33,605
Total proved plus probable 306,423 194,571 130,417 91,222 65,858


Net Present Value Summary (after tax) as at December 31, 2018

(utilizing the Consultants Average Price Forecast at December 31, 2018)

($ thousands) Undiscounted Discounted at
5%
Discounted at
10%
  Discounted at
15%
Discounted at
20%
Proved developed producing 33,690 30,674 27,143 24,057 21,509
Proved developed non-producing 62 88 99 103 102
Total proved developed 33,752 30,762 27,242 24,160 21,611
Proved undeveloped 74,000 47,591 30,295 18,674 10,642
Total proved 107,752 78,353 57,538 42,834 32,253
Probable additional 198,671 116,219 72,879 48,388 33,605
Total proved plus probable 306,423 194,571 130,417 91,222 65,858

 

Average of McDaniel & Associates Consultants Ltd., GLJ Petroleum Consultants Ltd. And Sproule Associates Limited Price Forecasts (the Consultants Average Price Forecast) as at December 31, 2018 (1)

  WTI
Crude Oil
(US$/bbl)
Edmonton
Light
Crude Oil
(Cdn$/bbl)
Henry Hub
Natural Gas
(US$/mmbtu)
AECO
Natural Gas
(Cdn$/mmbtu)
British Columbia Average Plantgate Gas (Cdn$/mmbtu) Edmonton
Condensate
and Natural
Gasoline
(Cdn$/bbl)
Ethane
(Cdn$/bbl)
Propane
(Cdn$/bbl)
Butane
(Cdn$/bbl)
US/Cdn
Exchange
(US$/Cdn$)
2019 58.58 67.30 3.00 1.88 1.31 70.10 6.82 26.13 27.32 0.757
2020 64.60 75.84 3.13 2.31 1.82 79.21 8.40 31.27 41.10 0.782
2021 68.20 80.17 3.33 2.74 2.29 83.33 9.98 34.58 49.28 0.797
2022 71.00 83.22 3.51 3.05 2.63 86.20 11.22 37.25 55.65 0.803
2023 72.81 85.34 3.62 3.21 2.81 88.16 11.89 38.73 57.92 0.807
Average 67.04 78.37 3.32 2.64 2.17 81.40 9.66 33.59 46.25 0.789

Note:
(1) Prices escalate at two percent per year after 2023.

The above pricing table was utilized by McDaniel in its evaluation of Chinook’s reserves as at December 31, 2018. When compared to the December 31, 2017 price forecast, commodity pricing for the year 2019 has decreased for Edmonton Light Crude Oil, AECO Natural Gas and British Columbia Average Plantgate Gas by 6%, 29% and 39%, respectively. The longer term gas price forecasts decreased on average over the following 10 years by 14% as compared to the prior year forecast.

Future Development Costs (“FDC”)

Changes in forecast FDC occur annually as a result of development activities, acquisition and disposition activities and capital cost estimates that reflect the independent evaluator’s best estimate of what it will cost to bring the proved undeveloped and probable reserves on production using forecast prices and costs. In addition to the Total proved FDC increase resulting from the category transfer of the aforementioned two Probable additional undeveloped locations to Proved undeveloped, and the Total proved plus probable FDC increase resulting from the four Probable undeveloped location additions, 2018 COGE guidelines now require the inclusion of maintenance capital which added $2.4 million undiscounted on a Total proved basis and $3.7 million on a Total proved plus probable basis.

 ($ millions)
2018 2017
Total proved 94.9 83.7
Total proved plus probable 161.2 139.1


Finding and Development Costs (“F&D”)

Finding and development costs below are calculated as the Exploration and Development costs excluding the acquisitions, dispositions, abandonment and furniture and fixtures plus the change in undiscounted FDC excluding that FDC associated with acquisitions and dispositions, divided by the reserve additions excluding acquisition and divestiture. Chinook’s F&D costs, net of acquisition, disposition, abandonment and furniture and fixture costs, which indicates the capital spent per barrel of oil equivalent added, net of acquisition and disposition changes in volume, are below.  It is relevant to note that the Company drilled two (2.0 net) vertical exploration wells in 2018 resulting in no reserve additions with a total capital expense of $2.5 million. Completion operations were partially conducted in 2019 and information gathered may result in reserve additions at end of the current calendar year.

Total Finding and Development Costs (Proved Reserves)
($ thousands, except per unit amounts)
2018 2017 2016 Three-Year Total
Exploration and development costs excluding acquisitions, dispositions and abandonments (unaudited) (1) 2,879 39,405 7,465 49,748
Net change from previously allocated future development capital 11,200 9,501 22,102 42,803
Total exploration and development costs including the net change in FDC 14,079 48,906 29,567 92,551
Reserve additions excluding acquisitions and dispositions (mboe) 1,104 5,264 4,449 10,817
Total proved finding and development costs (per boe) 12.75 9.29 6.65 8.56

 

Total Finding and Development Costs (Proved plus Probable Reserves)
($ thousands, except per unit amounts)
2018 2017 2016 Three-Year Total
Exploration and development costs excluding acquisitions, dispositions and  abandonments (unaudited) (1) 2,879 39,405 7,465   49,748
Net change from previously allocated future development capital 22,142 23,995 35,391   81,527
Total exploration and development costs including the net change in FDC   25,021   63,399   42,856   131,275
Reserve additions excluding acquisitions and dispositions (mboe)   3,073   8,801   9,006   20,881
Total proved plus probable finding and development costs (per boe)   8.14   7.20   4.76   6.29

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

Chinook’s F&D costs, including acquisition, disposition, abandonment and furniture and fixture costs, which indicates the capital spent per barrel of oil equivalent added, including acquisition and disposition changes in volume, are below.

Total Finding and Development Costs (Proved Reserves)
($ thousands, except per unit amounts)
2018 2017 2016 Three-Year Total
Exploration and development costs including acquisitions, dispositions and abandonments (unaudited) (1) 3,621 21,616 3,345 28,582
Net change from previously allocated future development capital 11,200 9,501 12,400 33,101
Total exploration and development costs including the net change in FDC 14,821 31,117 15,745 61,683
Reserve additions including acquisitions and dispositions (mboe) 1,104 5,150 (3,076 ) 3,178
Total proved finding and development costs (per boe) 13.42 6.04 (5.12 ) 19.41

 

Total Finding and Development Costs (Proved plus Probable Reserves)
($ thousands, except per unit amounts)
2018 2017 2016 Three-Year Total
Exploration and development costs including acquisitions, dispositions and abandonments (unaudited) (1) 3,621 21,616 3,345 28,627
Net change from previously allocated future development capital 22,142 23,995 20,095 66,231
Total exploration and development costs including the net change in FDC 25,762 45,611 23,440 94,857
Reserve additions including acquisitions and dispositions (mboe) 3,073 8,672 (2,786 ) 8,960
Total proved plus probable finding and development costs (per boe) 8.38 5.26 (8.41 ) 10.59

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 ratios are calculated as the 2018 operating netback before commodity price contracts per boe divided by the 2018 F&D costs per boe set forth above. The recycle ratio is comparing the netback as reported by the Company for 2018 to the cost of finding new reserves in 2018.

Total Proved
2018 operating netback before commodity price contracts ($/boe) 6.68
2018 F&D costs net of acquisition, dispositions and abandonments ($/boe) (unaudited) 12.75
Recycle ratio 0.5x
   
Total Proved Plus Probable
2018 operating netback before commodity price contracts ($/boe) 6.68
2018 F&D costs net of acquisition, dispositions and abandonments ($/boe) (unaudited) 8.14
Recycle ratio 0.8x

 

Total Proved
2018 operating netback before commodity price contracts ($/boe) 6.68
2018 F&D costs incl. acquisition, dispositions and abandonments ($/boe) (unaudited) 13.42
Recycle ratio 0.5x
   
Total Proved Plus Probable
2018 operating netback before commodity price contracts ($/boe) 6.68
2018 F&D costs incl. acquisition, dispositions and abandonments ($/boe) (unaudited) 8.38
Recycle ratio 0.8x

 

Corporate Net Asset Value

The Company’s net asset value as of December 31, 2018 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 McDaniel Report.

December 31, 2018 Before Tax NPV 5% Before Tax NPV 10% Before Tax NPV 15%
($ thousands) $/share ($ thousands) $/share ($ thousands) $/share
Proved developed producing reserves NPV (1)(2) 30,674 0.14 27,143 0.12 24,057 0.11
Total proved reserves NPV (1)(2) 78,353 0.35 57,538 0.26 42,834 0.19
Proved plus probable reserves NPV (1)(2) 194,571 0.87 130,417 0.58 91,222 0.41
Undeveloped acreage (3) 26,130 0.12 26,130 0.12 26,130 0.12
Working capital deficit (4) (1,994 ) (0.01 ) (1,994 ) (0.01 ) (1,994 ) (0.01 )
Net asset value (basic) (5)(6) 218,708 0.98 154,553 0.69 115,359 0.52
  After Tax NPV 5% After Tax NPV 10% After Tax NPV 15%
($ thousands) $/share ($ thousands) $/share ($ thousands) $/share
Proved developed producing reserves NPV (1)(2) 30,674 0.14 27,143 0.12 24,057 0.11
Total proved reserves NPV (1)(2) 78,353 0.35 57,538 0.26 42,834 0.19
Proved plus probable reserves NPV (1)(2) 194,571 0.87 130,417 0.58 91,222 0.41
Undeveloped acreage (3) 26,130 0.12 26,130 0.12 26,130 0.12
Working capital deficit (4) (1,994 ) (0.01 ) (1,994 ) (0.01 ) (1,994 ) (0.01 )
Net asset value (basic) (5)(6) 218,708 0.98 154,553 0.69 115,359 0.52

Notes:
(1)  Evaluated by McDaniel, an independent reserve evaluator, as at December 31, 2018. 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 the Consultants Average  Price Forecast at December 31, 2018.
(3)  Undeveloped land value has been valued internally by Chinook at an average of $337 per acre over 77,485 net undeveloped acres.
(4)  Working capital deficit as at December 31, 2018, including positive working capital (estimated and unaudited). See “Working Capital Deficit” in the Reader Advisory below.
(5)  Net asset value is the sum of proved plus probable reserves, undeveloped acreage and working capital deficit.
(6)  Basic shares as at December 31, 2018 totaled 223,604,601 common shares.

About Chinook Energy Inc.

Chinook is a Calgary-based public oil and natural gas exploration and development company which is focused on realizing per share growth from its large contiguous Montney liquids-rich natural gas position at Birley/Umbach, British Columbia.

For further information please contact:

Walter Vrataric
President and Chief Executive Officer
Chinook Energy Inc.
Telephone: (403) 261-6883
Website: www.chinookenergyinc.com
Jason Dranchuk
Vice-President, Finance and Chief Financial Officer
Chinook Energy Inc.
Telephone: (403) 261-6883

 

Reader Advisory

Abbreviations

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

 

Other
boe barrel of oil equivalent on the basis of 6 mcf/1 boe for natural gas and 1 bbl/1 boe for crude oil and natural gas liquids (this conversion factor is an industry accepted norm and is not based on either energy content or current prices)
boe/d barrel of oil equivalent per day
mboe 1,000 barrels of oil equivalent
mmboe 1,000,000 barrels of oil equivalent
WTI West Texas Intermediate, the reference price paid in U.S. dollars at Cushing, Oklahoma for crude oil of standard grade


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