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Chinook Energy Inc. Announces Fourth Quarter and 2019 Results and Reserves

Calgary, Alberta – Chinook Energy Inc. (TSX: CKE) (“our”, “we”, or “us”) is pleased to announce our three months and year ended December 31, 2019 (“Q419” and “2019”, respectively) operating and financial results and the results of our year end reserve evaluation effective December 31, 2019 as prepared by our independent evaluator. Our operating and financial highlights for Q419 and 2019 are noted below and should be read in conjunction with our consolidated financial statements for the years ended December 31, 2019 and 2018 and our related management’s discussion and analysis which are available on our website ( and filed on SEDAR (

Reserves included herein are stated on a gross basis (our 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 National Instrument 51-101 (“NI 51-101”) under the heading “Reader Advisory” and throughout this news release. In addition to the information contained in this news release more detailed reserves information will be included in our Annual Information Form for the year ended December 31, 2019, which will be filed on SEDAR at later this month.

Q419 and 2019 Operating Highlights

Three months ended Year ended
December 31 December 31
2019 2018 2019 2018
Production Volumes
Natural gas liquids (boe/d) 555 405 407 565
Natural gas (mcf/d) 16,469 14,641 12,950 18,806
Crude oil (bbl/d) 4 12 7 19
Average daily production (boe/d) (1) 3,304 2,856 2,572 3,719
Sales Prices    
Average natural gas liquids price ($/boe) $ 39.75 $ 43.56 $ 42.26 $ 59.87
Average natural gas price ($/mcf) $ 1.97 $ 2.60 $ 1.69 $ 1.91
Average oil price ($/bbl) $ 62.11 $ 54.13 $ 61.48 $ 69.15
Operating Netback (2)    
Average commodity pricing ($/boe) $ 16.55 $ 19.72 $ 15.33 $ 19.11
Royalty expense ($/boe) $ (0.16 ) $ (0.14 ) $ (0.11 ) $ (0.08 )
Realized gain (loss) on commodity price contracts ($/boe) $ 0.14 $ (2.59 ) $ (0.64 ) $ (0.72 )
Net production expense ($/boe) (2) $ (9.73 ) $ (14.01 ) $ (12.30 ) $ (11.63 )
Operating netback ($/boe) (1) (2) $ 6.80 $ 2.98 $ 2.28 $ 6.68
Wells Drilled  
Exploratory wells (net) 2.00


(1) Amounts may not be additive due to rounding.

(2) Adjusted funds flow, adjusted funds flow per share, net debt, operating netback and net production expense are non-GAAP measures. These terms do not have any standardized meanings as prescribed by IFRS and, therefore, may not be comparable with the calculations of similar measures presented by other companies. See headings entitled “Adjusted Funds Flow”, “Net Debt”, “Operational Netback” and “Net Production Expense” in the Reader Advisory below for further information on such terms.

Q419 and 2019 Financial Highlights

Three months ended Year ended
December 31 December 31
2019 2018 2019 2018
FINANCIAL ($ thousands, except per share amounts)
Petroleum & natural gas revenues, net of royalties $ 4,986 $ 5,146 $ 14,291 $ 25,837
Cash (outflow) inflow from operating activities $ (48 ) $ (378 ) $ (3,634 ) $ 255
Adjusted funds flow (outflow)(2) $ 1,171 $ (413 ) $ (2,034 ) $ 4,179
     Per share – basic and diluted ($/share) $ 0.01 $ $ 0.01 $ 0.02
Net loss $ (13,998 ) $ (21,141 ) $ (42,263 ) $ (27,654 )
     Per share – basic and diluted ($/share) $ (0.06 ) $ (0.09 ) $ (0.19 ) $ (0.12 )
Capital expenditures $ $ 213 $ 29 $ 2,890
Net debt (2)  $ 6,138 $ 1,994 $ 6,138 $ 1,994
Total assets $ 63,797 $ 101,416 $ 63,797 $ 101,416
Common Shares (thousands)    
Weighted average during period    
          Basic & diluted 223,682 223,605 223,672 223,594
Outstanding at year end 223,682 223,605 223,682 223,605


(1) Amounts may not be additive due to rounding.

(2) Adjusted funds flow, adjusted funds flow per share, net debt, operating netback and net production expense are non-GAAP measures. These terms do not have any standardized meanings as prescribed by IFRS and, therefore, may not be comparable with the calculations of similar measures presented by other companies. See headings entitled “Adjusted Funds Flow”, “Net Debt”, “Operational Netback” and “Net Production Expense” in the Reader Advisory below for further information on such terms.

Recent Developments

Arrangement Agreement

As previously announced on February 24, 2020, we entered into an arrangement agreement (the “Arrangement Agreement”) pursuant to which Tourmaline Oil Corp. (the “Purchaser”) has agreed to acquire all of the outstanding common shares (“Chinook Shares”) of our company for cash consideration of $0.0675 per share (the “Transaction”). The Purchaser will assume our net debt upon closing of the Transaction. The Transaction is subject to various closing conditions, including receipt of Court approval and approval by our shareholders. An annual and special meeting of our shareholders has been called on April 20, 2020, to consider, among other things, the Transaction. The Transaction will require the approval of 66²/3% of the votes cast by our shareholders at the Meeting. The Transaction is anticipated to close thereafter in late April upon satisfaction of all conditions precedent thereto.

The Transaction offers a liquidity event and cash consideration to our shareholders. Upon closing of the Transaction, the Chinook Shares will be de-listed from the Toronto Stock Exchange. We can provide no assurances that the Transaction will close.

Demand Credit Facility Renewal

Following the execution of the Arrangement Agreement, our lender renewed our demand credit facility agreement with an unchanged maximum availability of $10.0 million. During 2019, we drew $4.7 million of debt to finance our operating activities while there was an extended ongoing review of our demand credit facility. This extended review occurred during a very challenging environment as demonstrated by depressed natural gas pricing and continued weakness in general Canadian exploration and production industry and capital market conditions. We believe our lender provided us with the renewed demand credit facility because of our ongoing discussions with the Purchaser which resulted in the Arrangement Agreement.

Although in our facility renewal we received waivers of past and forecasted financial covenant breaches, we are forecasting that we will be in breach of the net debt to cash flow financial covenant per the terms of the renewed demand credit facility agreement as at June 30, 2020. In the event that the Transaction is not completed, when the next borrowing base redetermination commences as scheduled on (or before or later) May 31, 2020, because of the aforementioned market conditions and forecasted breach, no assurance can be provided that the borrowing base will be renewed at the same or a similar amount or on the same or similar terms, nor can any assurance be provided that our lender will not call our debt as a result of these market conditions and forecasted breach or for any other reason. In such event, these material uncertainties cast significant doubt with respect to our ability to continue as a going concern.

2019 Independent Reserves Evaluation

McDaniel & Associates Consultants Ltd. (“McDaniel”) evaluated all of our properties effective December 31, 2019 pursuant to a report dated February 25, 2020 (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 NI 51-101. The reserve evaluation was based on the average forecast pricing and foreign exchange rates at December 31, 2019 of three evaluators, McDaniel, GLJ Petroleum Consultants Ltd. and Sproule Associates Limited, herein referred to as “the Consultants Average Price Forecast”. The Reserves, Safety and Environmental Committee of our Board and our Board of Directors have reviewed and approved the McDaniel Report.

Reserves Breakdown (gross)(1)
(utilizing the Consultants Average Price Forecast at December 31, 2019)

(mboe) 2019 2018
Proved Producing
Total proved producing 6,170 6,814
Total proved 17,407 18,393
Proved Plus Probable
Total proved plus probable 33,790 35,626

(1) Gross reserves are our working interest reserves before royalty deductions and do not include royalty interest volumes.

Gross and Net Reserves as at December 31, 2019
The following table summarizes our gross and net reserve volumes utilizing the Consultants Average Price Forecast, and cost estimates, at December 31, 2019.

Light and
medium oil
Heavy oil Conventional
Natural Gas
Natural gas
Oil equivalent
Reserves category Gross (1)
Net (2)
Gross (1)
Net (2)
Gross (1)
Net (2)
Gross (1)
Net (2)
Gross (1)
Net (2)
Total company
   Developed producing 10 10 31,272 28,066 948 803 6,170 5,491
   Developed non-producing 6 6 40 38 14 12
   Undeveloped 56,318 49,129 1,837 1,599 11,223 9,787
Total proved 17 16 87,631 77,233 2,785 2,402 17,407 15,290
Probable 6 5 82,669 68,404 2,599 2,163 16,383 13,569
Total proved plus probable 23 21 170,300 145,637 5,383 4,565 33,790 28,859

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

(2) Net reserves are after royalty deductions and include royalty interest volumes.

Gross Reserve Reconciliation for 2019
(gross reserves before deduction of royalties payable)

6:1 Oil Equivalent (mboe)
Total proved Probable additional Total
proved plus
December 31, 2018 – opening balance 18,393 17,233 35,626
Additions and extensions
Technical revisions 631 (383) 248
Economic factors (678) (468) (1,146)
Production (939) (939)
December 31, 2019 – closing balance 17,407 16,383 33,790

Our Total proved and Total proved plus probable reserves decreased by 986 mboe and 1,836 mboe, respectively. The decreases were predominantly the result economic factors given the approximate 20% decrease to BC Plantgate gas price forecast as well as production through the period, partially offset by positive technical revisions.

As we did not deploy any capital in the development of our assets, we did not add any developed or undeveloped locations during 2019. At December 31, 2019, 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. These locations remain unchanged from the report ending December 31, 2018. As at the date of the McDaniel Report, approximately 19% of our greater Birley/Umbach Montney acreage was booked.

Given the lack of development capital spent and no undeveloped locations booked, we have not included Finding and Developing Cost analysis or related Recycle Ratios in this news release.

Reserve Life Index (“RLI”)

As at December 31, 2019, our proved plus probable RLI was 31.0 years based upon the McDaniel Report and the forecast 2020 production volumes from the report, while our proved RLI was 16.2 years. The following table summarizes the RLI:

  Reserves (mboe) 17,407
  2020 Forecast production – Proved (mboe) (1) 1,072
  Reserve life index (years) 16.2
Proved Plus Probable
  Reserves (mboe) 33,790
  2020 Forecast production – Proved Plus Probable (mboe) (1) 1,090
  Reserve Life Index (years) 31.0

(1) As evaluated by McDaniel, an independent reserve evaluator, as at December 31, 2019.

Net Present Value (“NPV”) Summary (before and after tax) as at December 31, 2019
(utilizing the Consultants Average Price Forecast at December 31, 2019)

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 facilities abandonment and reclamation but do not include a provision for interest, debt service charges, general and administrative expenses. It should not be assumed that the NPV estimates represent the fair market value of the reserves.

For the 2019 year-end reserves report, as recommended by the Canadian Oil and Gas Evaluation Handbook (“COGEH”), all of our abandonment, decommissioning and reclamation costs (“ADR”) for active and inactive wells have been included. This is a significant change to the prior years’ practices, when such ADR was not included in the reserves evaluation. Previously, exclusion of these costs was common across our industry.

Given the extent of our unrecognized tax pools, the results of before tax and after tax NPVs are the same and have been presented in a single table.

($ thousands) Undiscounted Discounted at
Discounted at
Discounted at
Discounted at
Proved developed producing 1,633 17,161 20,431 20,679 20,004
Proved developed non-producing 150 135 122 111 102
Total proved developed 1,783 17,296 20,553 20,790 20,106
Proved undeveloped 55,197 35,686 22,345 13,105 6,590
Total proved 56,980 52,983 42,898 33,895 26,696
Probable additional 154,243 92,177 58,246 38,597 26,589
Total proved plus probable 211,224 145,159 101,144 72,492 53,285

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, 2019(1)

Crude Oil
Crude Oil
Henry Hub
Natural Gas
Natural Gas
British Columbia Average Plantgate Gas (Cdn$/mmbtu) Edmonton
and Natural
2020 61.00 72.64 2.62 2.04 1.46 76.83 6.42 26.36 42.10 0.760
2021 63.75 76.06 2.87 2.32 1.79 79.82 7.41 29.80 47.03 0.770
2022 66.18 78.35 3.06 2.62 2.12 82.30 8.33 32.94 50.66 0.785
2023 67.91 80.71 3.17 2.71 2.26 84.72 8.65 34.00 52.21 0.785
2024 69.48 82.64 3.24 2.81 2.35 86.71 8.98 34.88 53.48 0.785
Average 65.66 78.08 2.99 2.50 2.00 82.08 7.96 31.60 49.10 0.777

(1) Prices escalate at two percent per year after 2024.

The foregoing pricing table was utilized by McDaniel in its evaluation of our reserves as at December 31, 2019. When compared to the December 31, 2018 price forecast, commodity pricing for the year 2020 has decreased for Edmonton Light Crude Oil, AECO Natural Gas and British Columbia Average Plantgate Gas by 4%, 12% and 20%, respectively. The longer term BC Plantgate gas price forecast decreased on average over the following 10 years by 18% 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.

($ millions)
2019 2018
Total proved 94.5 94.9
Total proved plus probable 160.5 161.2

About Chinook Energy Inc.

We are a Calgary-based public oil and natural gas exploration and development company with a 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

Jason Dranchuk
Vice President, Finance and Chief Financial Officer
Chinook Energy Inc.
Telephone: (403) 261-6883


Reader Advisory


Oil and Natural Gas Liquids Natural Gas
barrels per day
thousand cubic feet
million cubic feet
NGLs Natural gas liquids mcf/d
thousand cubic feet per day
million cubic feet per day
billion cubic feet per day
million British Thermal Units
million British Thermal Units per day
GJ Gigajoules
GJ/d gigajoules per day
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)
Station 2
barrel of oil equivalent per day
1,000 barrels of oil equivalent
1,000,000 barrels of oil equivalent
Market point for BC natural gas
West Texas Intermediate, the reference price paid in U.S. dollars at Cushing, Oklahoma for crude oil of standard grade
Chicago City Gate Market point for eastern US natural gas

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