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Chinook Energy Inc. Announces Initiation of Strategic Review Process and Third Quarter of 2019 Operating and Financial Results

CALGARY, Alberta, Nov. 07, 2019 (GLOBE NEWSWIRE) — Chinook Energy Inc. (“our”, “we”, or “us”) (TSX: CKE) announces that we have initiated a formal process to identify, examine and consider a range of strategic alternatives available to us with a view to enhancing shareholder value. We are also announcing our operating and financial results for the three months ended September 30, 2019 (“Q319”). Our unaudited condensed consolidated financial statements and management’s discussion and analysis for the three and nine months ended September 30, 2019 are available on our website ( and filed on SEDAR (

Initiation of Strategic Review Process

With the expected strengthening of our operating cash flows, in part resulting from the pending return to 100% capacity of the Enbridge T-South pipeline in November 2019, the anticipated commissioning of TC Energy’s North Montney Mainline in January 2020, and numerous additional industry gas export expansions planned in 2020 and 2021 totaling approximately 1.9 bcf/d, we have initiated a review of available strategic alternatives. Strategic alternatives may include, but are not limited to, a sale of all or a material portion of our assets, either in one transaction or in a series of transactions, the outright sale of our company, or merger or other transaction involving us and a third party. For the purposes of considering strategic alternatives, we have established a special committee consisting of directors, Jill T. Angevine (Chair), Robert J. Herdman and Robert J. Iverach to oversee the process.

We have engaged Peters & Co. Limited as our financial advisor in connection with the process.

This strategic alternative review process has not been initiated as a result of receiving any offer and there are no assurances that a transaction will be undertaken. It is our current intention not to disclose developments with respect to the process unless and until our Board of Directors has approved a specific transaction or otherwise determines that disclosure is necessary or appropriate. We caution that there are no assurances or guarantees that the process will result in a transaction or, if a transaction is undertaken, the terms or timing of such a transaction. We have not yet set a definitive schedule to complete its identification, examination and consideration of strategic alternatives.

Q319 Highlights

  • Production returned to unrestricted levels: During September, our production returned to unrestricted levels of approximately 4,000 boe/d.
  • Additional Q319 egress: We obtained additional egress during Q319 that limited our exposure to the BC Station 2 benchmark. This increased the ratio of our natural gas production sold at benchmarks other than Station 2 to 47% compared to 27% during the three months ended September 30, 2018 (“Q218”). These other benchmark prices included Chicago City Gate and Alliance Trading Pool, where we receive a premium to what we would have realized had we sold our natural gas production at spot Station 2 pricing.
  • Preservation of shareholder value: As BC natural gas price weakness continues related to export capacity constraints, we voluntarily restricted our production to preserve shareholders’ value.
  • $2.0 million of annual cost savings: We signed a new Calgary office space lease commencing in June 2019. Cost savings from this lease during Q319 were $0.6 million.
  • Additional $1.6 million of annual gathering revenues commencing in early 2020:  Construction continues by a third party who is on schedule to tie into our Aitken Creek Pipeline as discussed under “Outlook” below.

Q319 Operating and Financial Highlights

Three months ended Nine months ended
September 30 September 30
2019 2018 2019 2018
Production Volumes
Natural gas liquids (boe/d) 337 707 357 620
Natural gas (mcf/d) 11,488 24,454 11,764 20,210
Crude oil (bbl/d) 5 24 8 22
Average daily production (boe/d) (1) 2,256 4,807 2,325 4,010
Sales Prices
Average natural gas liquids price ($/boe) $ 35.58 $ 63.73 $ 43.57 $ 63.46
Average natural gas price ($/mcf) $ 0.97 $ 1.54 $ 1.55 $ 1.74
Average oil price ($/bbl) $ 55.63 $ 71.35 $ 61.36 $ 71.82
Operating Netback (2)
Average commodity pricing ($/boe) $ 10.34 $ 17.59 $ 14.75 $ 18.97
Royalty expense ($/boe) $ (0.05 ) $ $ (0.09 ) $ (0.07 )
Realized loss on commodity price contracts ($/boe) $ (0.24 ) $ (0.17 ) $ (1.02 ) $ (0.28 )
Net production expense ($/boe) (2) $ (13.70 ) $ (9.74 ) $ (13.53 ) $ (11.06 )
Operating netback ($/boe) (1) (2) $ (3.65 ) $ 7.68 $ 0.11 $ 7.56
Wells Drilled
Exploratory wells (net) 2.00
FINANCIAL ($ thousands, except per share amounts)
Petroleum & natural gas revenues, net of royalties $ 2,136 $ 7,778 $ 9,305 $ 20,691
Cash (outflow) inflow from operating activities $ (1,489 ) $ 1,132 $ (3,586 ) $ 633
Adjusted funds (outflow) flow (2) $ (1,691 ) $ 2,285 $ (3,205 ) $ 4,592
Per share – basic and diluted ($/share) $ (0.01 ) $ 0.01 $ (0.01 ) $ 0.02
Net loss $ (3,527 ) $ (1,944 ) $ (28,265 ) $ (6,513 )
Per share – basic and diluted ($/share) $ (0.02 ) $ (0.01 ) $ (0.13 ) $ (0.03 )
Development and exploration expenditures $ $ $ $ 2,677
Net debt (2) $ 6,982 $ 713 $ 6,982 $ 713
Total assets $ 75,920 $ 120,572 $ 75,920 $ 120,572
Common Shares (thousands)
Weighted average during period
  Basic & diluted 223,682 223,605 223,669 223,591
Outstanding at period 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.

President’s Message

Since being repaired following a pipeline rupture near Prince George, BC, Enbridge has operated its Westcoast pipeline at reduced pressures which has negatively impacted the natural gas price at Station 2. Starting on November 1, 2019, Enbridge began to increase this pipeline’s maximum operating pressure and associated capacity with an expectation of it returning to full service by the end of the month. From November 2018 to the present period of restricted Westcoast pipeline capacity, Station 2 has experienced prices averaging approximately $0.72/GJ. Comparable prices have not been seen in more than two decades. We have persevered through this challenging environment and are poised to take advantage of price improvements that are anticipated with the previously mentioned return of Enbridge’s Westcoast pipeline capacity in addition to TC Energy’s North Montney Mainline which is expected to commence transporting natural gas in January 2020. Several other projects over the next two years should serve to improve regional egress and pricing. These projects include TC Energy’s Foothills System expansion (2019), TC Energy’s West Path expansion (2020), Enbridge’s T-South Expansion (2021) and TC Energy’s EGAT Expansions (2020-2021). In all, it is anticipated that these projects will increase Western Canadian export capacity by approximately 1.9 bcf/d.

We are not in compliance with our lender’s net debt to cash flow financial covenant and minimum hedging requirement contained in our demand credit facility. The net debt to cash flow financial covenant allows a maximum ratio of three times and was not in compliance due to a cash flow deficit over the previous 12 months for the reasons set forth below. Cash flows, as defined by our lender, approximate adjusted funds flow less provision expenditures and lease payments. Third party outages and our reaction to depressed Station 2 pricing through voluntary restricting our production combined to reduce our adjusted funds flow over this previous period. Because this financial covenant is calculated on a trailing 12 months basis, the effect of these previous production restrictions are punitive in its calculation over the next forecasted eight months and outweigh the effect from expected higher pricing. Our forecast may materially change if the Station 2 benchmark exceeds current strip pricing during the upcoming winter season resulting from the previously discussed increase in take away capacity anticipated from the expansion of TC Energy’s North Montney Mainline combined with Enbridge’s Westcoast pipeline returning to normal operating pressures. We are also not in compliance with the minimum hedging requirement because we have deferred entering into additional commodity price contracts until we have more clarity from our lender on the facility’s availability.

While we continue constructive discussions with our lender, the borrowing base redetermination and waiver of the breaches remain outstanding. We anticipate our lender to reduce the $10 million availability of our demand credit facility given recent decreases in forward natural gas benchmark pricing, issue waivers for these breaches and revise the terms of our agreement by removing the net debt to cash flow financial covenant and minimum hedging requirement. However 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 the debt as a result of these breaches.


Our remaining development program in 2019 will be minimal until such time as commodity prices improve to constructive levels. We also anticipate the following to occur during the remainder of 2019 or early 2020:

  • Production to return to unrestricted levels: We forecast our production to return to unrestricted levels and average approximately 3,650 boe/d for this winter season. However, we continue to be hindered by volatile Station 2 pricing which forced us to temporarily shut-in production at our Birley area from mid-October to early November. Production was returned to approximately 4,000 boe/d on November 6.
  • Additional $1.6 million of annualized gathering revenues: We continue to lever our existing assets and recently completed a transportation agreement for the partial use of our 12” Aitken Creek pipeline. The agreement will commence on the initial delivery of gas, anticipated to be early 2020, and will continue for a minimum period of two years. Minimum gathering charges will total approximately $1.6 million annually.
  • Borrowing base redetermination discussions with our lender: While these discussions are currently ongoing, we are evaluating other financing options including restructuring our operations, the disposition of natural gas assets, the sale/leaseback of midstream assets and other alternative sources of debt.

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 Jason Dranchuk
President and Chief Executive Officer Vice President, Finance and Chief Financial Officer
Chinook Energy Inc. Chinook Energy Inc.
Telephone: (403) 261-6883 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)
boe/d barrel of oil equivalent per day
Station 2 Market point for BC natural gas
Chicago City Gate Market point for eastern US natural gas

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