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

/EIN News/ -- 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 (www.chinookenergyinc.com) and filed on SEDAR (www.sedar.com).

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  
OPERATIONS          
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.

Outlook

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

Website: www.chinookenergyinc.com

Reader Advisory

Abbreviations

Oil and Natural Gas Liquids   Natural Gas  
           
bbl
bbl/d
barrels
barrels per day
  mcf
mmcf
thousand cubic feet
million cubic feet
 
NGLs Natural gas liquids   mcf/d
mmcf/d
bcf/d
mmbtu
mmbtu/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  
           
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
Station 2 Market point for BC natural gas
Chicago City Gate Market point for eastern US natural gas

Forward-Looking Statements

In the interest of providing our shareholders and readers with information regarding our company, including management's assessment of our future plans and operations and a strategic alternative review process, 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 particular, this news release contains, without limitation, forward-looking statements pertaining to: anticipated annual cost savings of $2.0 million from our new office lease, anticipated improvements in natural gas pricing due to the return of Enbridge's Westcoast pipeline capacity in addition to TC Energy's North Montney Mainline expected to commence transporting natural gas by mid-January 2020, anticipated improved regional egress and natural gas pricing due to several other projects being completed over the next two years which is anticipated to increase Western Canadian export capacity by approximately 1.9 bcf/d, forecasted breaches of a financial covenant in our demand credit facility over the next eight months, we expect our lender will reduce the $10 million availability of our demand credit facility given the recent decreases in forward natural gas benchmark pricing, that our capital program for 2019 will be minimal, we forecast our production will return to unrestricted levels and average approximately 3,650 boe/d for this winter season, the anticipated initial delivery date of gas for the purposes of the transportation agreement for the partial use of our 12" Aitken Creek pipeline together with the expected additional $1.6 million of annualized gathering revenues realized therefrom and how we intend to manage our company.

With respect to the forward-looking statements contained in this news release, we have made assumptions regarding, among other things: that we will continue to conduct our operations in a manner consistent with that expressed herein, that we will not make significant future capital expenditures in 2019, future oil and natural gas prices, anticipated oil and natural gas production levels, future currency, exchange and interest rates, our ability to obtain equipment in a timely manner to carry out exploration and development activities, the ability of the operator of the projects in which we have an interest in to operate in the field in a safe, efficient and effective manner, the impact of increasing competition, field production rates and decline rates, our ability to replace and expand production and reserves through exploration and development activities, certain cost assumptions and the continued availability of adequate debt and cash flow to fund our planned expenditures. Although we believe 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 our 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, that our lender may reduce the availability of our $10.0 million demand credit facility or demand repayment of all outstanding debt and undrawn letters of credit precipitated by a financial covenant breach and that covenant’s forecasted breaches over the next 12 months, and, in such event, that no sufficient alternative financing will be completed, that there are material uncertainties that may cast significant doubt with respect to our ability to continue as a going concern, that the budgeted capital program for 2019, which is subject to the discretion of our Board of Directors, will not be amended in the future, there is no certainty in the amount of our borrowing base redetermination, risks associated with oil and gas exploration, development, exploitation, production, marketing and transportation, loss of markets, volatility of commodity prices and currency fluctuations,  environmental risks, competition from other producers, inability to retain drilling rigs and other services, unanticipated increases in or unforeseen 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 inability to access sufficient capital from internal and external sources. As a consequence, actual results may differ materially from those anticipated in the forward-looking statements. Readers are cautioned that the forgoing list of factors is not exhaustive. Additional information on these and other factors that could affect our 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 our 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 we do 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.

Operating Netback

The reader is cautioned that this news release contains the term operating netback, which is not a recognized measure under IFRS and is calculated as a period’s sales of petroleum and natural gas, net of realized gains or losses on commodity price contracts, royalties and net production expenses, divided by the period’s sales volumes. We use this non-GAAP measure to assist us in understanding our production profitability relative to current and fixed commodity prices and it provides an analytical tool to benchmark changes in field operational performance against prior periods. Readers are cautioned, however, that this measure should not be construed as an alternative to other terms such as net income determined in accordance with IFRS as a measure of performance. Our method of calculating this measure may differ from other companies, and accordingly, it may not be comparable to measures used by other companies.

Net Production Expense

The reader is cautioned that this news release contains the term net production expense, which is not a recognized measure under IFRS and is calculated as production and operating expense less processing and gathering income. We use net production expense to determine the current periods' cash cost of operating expenses and net production and operating expense per boe is used to measure operating efficiency on a comparative basis. This measure approximates our operating costs relative to only our volumes by excluding the approximated operating costs resulting from third party processing and gathering services. Our method of calculating this measure may differ from other companies, and accordingly, it may not be comparable to measures used by other companies.

Adjusted Funds (Outflow) Flow

The reader is cautioned that this news release contains the term adjusted funds (outflow) flow, which is not a recognized measure under IFRS and is calculated from cash (outflow) inflow from operations adjusted for changes in non-cash working capital related to operations, exploration and evaluation expenses related to operations, provision expenditures related to operations and severance/transaction costs. We believe that adjusted funds (outflow) flow is a key measure to assess our ability to finance capital expenditures and when debt is drawn, debt repayments. Adjusted funds (outflow) flow is not intended to represent cash (outflow) inflow from operating activities, net earnings or other measures of financial performance calculated in accordance with IFRS and should not be construed as an alternative to, or more meaningful than, cash (outflow) inflow from operating activities as determined in accordance with IFRS as an indicator of our financial performance. Our method of calculating this measure may differ from other companies, and accordingly, it may not be comparable to measures used by other companies. Adjustments to cash (outflow) inflow from operations are for changes in non-cash operating working capital which are expected to reverse and for those costs that are not directly caused by lifting production volumes.

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 current assets less current liabilities as they appear on the balance sheets, both of which exclude mark-to-market derivative contracts and assets and liabilities held for sale and current liabilities excludes any current portion of debt, deferred customer obligations, lease liabilities and provisions. We use net debt to assist us in understanding our liquidity at specific points in time. We exclude the current portion of provisions, lease liabilities and the deferred customer obligation as they are not financial instruments. Mark-to-market derivative contracts and assets and liabilities held for sale are excluded as they are unrealized.

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.

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