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

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Calgary, Alberta–(Newsfile Corp. – March 2, 2020) – 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 (www.chinookenergyinc.com) and filed on SEDAR (www.sedar.com).

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 www.sedar.com later this month.

Q419 and 2019 Operating Highlights

Three months ended Year ended
December 31 December 31
2019 2018 2019 2018
OPERATIONS
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
Proved
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
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 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
probable
December 31, 2018 – opening balance 18,393 17,233 35,626
Additions and extensions
Acquisitions
Dispositions
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:

Proved
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
5%
Discounted at
10%
Discounted at
15%
Discounted at
20%
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)

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$)
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

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
mboe
mmboe
Station 2
WTI

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

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 news release have been prepared in accordance with NI 51-101. Complete NI 51-101 reserves disclosure will be included in our annual information form for the year ended December 31, 2019 which will be filed on SEDAR in March 2020. Listed below are cautionary statements applicable to our 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 our future net revenue from our reserves. Such amounts do not represent the fair market value of our reserves.

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, 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: the Transaction and the anticipated timing of closing; timing of the annual and special meeting of shareholders, and the benefits of the Transaction for our shareholders; the anticipated filing date on SEDAR for our Annual Information Form for the year ended December 31, 2019, the volumes and estimated value of our oil and natural gas reserves, the life of our reserves, the amount of future development costs associated with producing proved undeveloped and probable reserves, the volume and product mix of our oil and natural gas production, and future oil and natural gas prices and future results from operations.

With respect to the forward-looking statements contained in this news release, we have made assumptions regarding, among other things: the time required to prepare meeting materials for mailing to our shareholders, the timing of receipt of the necessary court and shareholder approvals and the satisfaction of and time necessary to satisfy the conditions to the closing of the Transaction and that the Transaction will be completed on the terms contemplated by the Arrangement Agreement, that we will continue to conduct our operations in a manner consistent with that expressed herein, 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, and the continued availability of adequate debt and cash flow to fund our company. 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, the anticipated dates in this news release may change for a number of reasons, including unforeseen delays in preparing shareholder meeting materials, inability to secure necessary court or shareholder approvals in the time assumed or the need for additional time to satisfy the conditions to the completion of the Transaction, 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 Flow (Outflow)

The reader is cautioned that this news release contains the term adjusted funds flow (outflow), which is not a recognized measure under IFRS and is calculated from cash inflow (outflow) 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 flow (outflow) is a key measure to assess our ability to finance capital expenditures and when debt is drawn, debt repayments. Adjusted funds flow (outflow) is not intended to represent cash inflow (outflow) 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 inflow (outflow) 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 inflow (outflow) 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.

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. Our method of calculating this measure may differ from other companies, and accordingly, they may not be comparable to measures used by other companies.

To view the source version of this press release, please visit https://www.newsfilecorp.com/release/53029