CALGARY, ALBERTA – March 6, 2019 – Chinook Energy Inc. (“our”, “we”, or “us”) (TSX: CKE) is pleased to announce its fourth quarter and 2018 financial and operating results.

Our operational and financial highlights for the three months and year ended December 31, 2018 are noted below and should be read in conjunction with our consolidated financial statements for the years ended December 31, 2018 and 2017 and our related management’s discussion and analysis which have been posted on the SEDAR website ( and our website (

Fourth Quarter and 2018 Financial and Operating Highlights

Three months endedYear ended
 December 31December 31
Production Volumes
Natural gas liquids (boe/d)                    405                    551                    565                    470
Natural gas (mcf/d)              14,641              19,240              18,806              17,602
Crude oil (bbl/d)                      12                      21                      19                      22
Average daily production (boe/d) (1)                2,856                3,779                3,719                3,425
Sales Prices
Average natural gas liquids price ($/boe) $             43.56 $             51.87 $             59.87 $             47.89
Average natural gas price ($/mcf) $               2.60 $               0.99 $               1.91 $               1.95
Average oil price ($/bbl) $             54.13 $             76.96 $             69.15 $             62.27
Operating Netback (2)
Average commodity pricing ($/boe) $             19.72 $             13.02 $             19.11 $             16.97
Royalty (expense) recovery ($/boe) $              (0.14) $              (0.08) $              (0.08) $               0.05
Realized (loss) gain on commodity price contracts ($/boe) $              (2.59) $               3.83 $              (0.72) $               3.02
Net production expense ($/boe) (2) $           (14.01) $           (11.06) $           (11.63) $           (11.57)
Operating Netback ($/boe) (1) (2) $               2.98 $               5.71 $               6.68 $               8.47
Wells Drilled
Exploratory wells (net)                       -                       -                   2.00                       -
Natural gas wells (net)                       -                       -                       -                     3.63
Three months endedYear ended
 December 31December 31
FINANCIAL ($ thousands, except per share amounts)
Petroleum & natural gas revenues, net of royalties $             5,146 $             4,499 $           25,837 $           21,271
Cash (outflow) inflow from operating activities $               (378) $             2,635 $                255 $             6,118
Adjusted funds (outflow) flow (2) $               (413) $             1,100 $             4,179 $             4,978
     Per share - basic and diluted ($/share) $                    -   $               0.01 $               0.02 $               0.02
Net loss $         (21,141) $         (21,160) $         (27,654) $         (16,914)
     Per share - basic and diluted ($/share) $              (0.09) $              (0.10) $              (0.12) $              (0.08)
Capital expenditures $                213 $             7,253 $             2,890 $           39,044
Net debt (2)  $             1,994 $                711 $             1,994 $                711
Total assets $        101,416 $        130,571 $        101,416 $        130,571
Common Shares (thousands)
Weighted average during period
          - basic & diluted            223,605            218,517            223,594            217,174
Outstanding at period end            223,605            223,565            223,605            223,565

(1) Amounts may not be additive due to rounding.
(2) Adjusted funds flow (outflow), adjusted funds flow (outflow) 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 (Outflow)”, “Net Debt”, “Operational Netback” and “Net Production Expense” in the Reader Advisory below for further information on such terms.

2018 Highlights
• 2018 corporate production increased by 9%, or 294 boe/d, compared to 2017 despite significant third party production restrictions and no capital investment during 2018.
• 2018 adjusted funds flow of $4.2 million resulted from higher than expected average commodity pricing for much of the year, somewhat offsetting the aforementioned production restrictions.
• We drilled and completed two (2.0 net) vertical exploratory wells in the Birley/Umbach area for $2.2 million. These wells delineate 21 gross (20.5 net) undrilled contiguous sections of Montney rights which are located eight kilometres from the nearest well drilled into the Montney. The reservoir quality throughout the entire 225 metre thick Montney zone was evaluated with these wells.
• We renewed our $10.0 million demand revolving credit facility with a Canadian chartered bank. Net debt at December 31, 2018 was $2.0 million.
• We continue to layer in commodity price hedges and diversify our natural gas sales points with approximately 30% of forecast 2019 natural gas production currently hedged and greater than 33% of forecast 2019 natural gas production sold at Chicago pricing.
• 2018 net production expenses remained relatively flat at $11.63/boe compared to 2017. Specifically, production expenses averaged approximately $9.00/boe in our Birley/Umbach area.
• 2018 general and administrative expenses of $3.03/boe represented a decrease of $1.13 million, or 22%, compared to 2017 and reflected the impact of ongoing reductions in staffing, employee benefits and information system costs.

President’s Message
We believe that our previous capital programs which saw us drill and complete 13 (11.23 net) wells on our Birley/Umbach property as well as construct our 50 mmcf/d Birley facility puts us in an excellent position to accelerate activity when commodity prices recover. Our additional delineation work in the 2018 first quarter has increased the extension confidence of the Montney resource on our Martin lands. Although we are encouraged with our results to date, we remain cautious on making further significant capital expenditures until such time as commodity prices improve to a more constructive level.

Unfortunately, Enbridge’s (October 9, 2018) pipeline rupture near Prince George, BC has negatively impacted the natural gas price at Station 2. Enbridge subsequently issued a notice that this Westcoast pipeline has been repaired and returned to service in early November, albeit at a reduced operating pressure of approximately 80%. This reduced service is likely to have a continued negative impact on Station 2 gas prices for the duration of the restriction, understood to be for the remainder of the gas year. Although we continue to explore and contract additional egress options, most transport services are currently fully contracted or are not economically favourable. Prior to the pipeline rupture, commodity prices in 2018 had been higher than our internal forecasts, and should this pricing return to pre-pipeline rupture levels, they would serve to strengthen our balance sheet and facilitate future drilling activity.

Our average daily production for 2018 was 3,719 boe/d and we exited 2018 at approximately 3,500 boe/d through December. Our production was significantly impacted by third party restrictions during 2018. We experienced approximately four months of production restriction in the first and second quarters of 2018 due to the Oak pipeline integrity issue. Additionally, the T-South pipeline rupture during the fourth quarter restricted flows physically or by price related elective reductions during the fourth quarter of 2018. During significant portions of these periods of restriction, our production was limited to less than half of our productive capacity.

During 2018, we remained committed to capital discipline and cost control while continuing to develop our large Montney position at our Birley/Umbach property. We 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 our 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 our 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. We are encouraged by these results and believe a significant extension to the productive Montney fairway exists on our lands thus further expanding our future horizontal Montney drilling inventory.

Following an unplanned 22 day outage of the McMahon processing facility in January 2019, our production has returned to a largely unrestricted flow and is currently approximately 4,100 boe/d.

During the first quarter of 2019, we entered into the following commodity price contracts:

Contractual TermNotional VolumesIndex and Company’s Received Price
Natural gas swap
October 1, 2019 to December 31, 2019 3,000 GJ/dWestcoast Station 2 CAD$1.645/GJ
Natural gas collar
October 1, 2019 to December 31, 2019 3,000 mmbtu/dNYMEX US$2.25/mmbtu to US$3.68/mmbtu
Natural gas differential swap
October 1, 2019 to December 31, 2019 3,000 mmbtu/dPrice at Chicago = NYMEX less US$0.125/mmbtu

The combination of the NYMEX natural gas collars and differential swaps provide us a minimum and maximum price on notional volumes sold at Chicago City Gate Monthly pricing during the fourth quarter of 2019.

The production growth potential of our Birley/Umbach area is significant, with approximately 53,200 acres (44,350 net) of Montney rights. There are 587 gross (511 net) management identified locations based on 400 metre inter-well spacing and 1,800 metre lateral lengths in both the upper and middle Montney, with additional potential to develop the lower Montney in areas with sufficient reservoirs.

We are committed to improving our cost structure and will see our office related expenditures decrease in 2019 primarily through the conclusion of our current office lease and lease of new space at current market rates. Additionally, we continue to lever our existing assets and have 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 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, we remain cautious in deploying further capital. Consequently, our capital program in 2019 will be minimal until such time as commodity prices improve to constructive levels. Our management and Board of Directors will make adjustments to the capital program in response to changing market conditions.

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

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


Reader Advisory


Oil and Natural Gas Liquids

bbl - barrels
bbl/d - barrels per day
NGLs - Natural gas liquids

Natural Gas
mcf - thousand cubic feet
mmcf - million cubic feet
mcf/d - thousand cubic feet per day
mmcf/d - million cubic feet per day
mmbtu - million British Thermal Units
mmbtu/d - 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

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: that our previous capital programs during the past five years has put us in an excellent position to accelerate activity when commodity prices recover, our belief that a significant extension to the productive Montney fairway exists on our lands, our belief that the production growth potential of our Birley/Umbach area is significant, the anticipated initial delivery date of gas for the purposes of the transportation agreement for the partial use of our 12” Aitken Creek pipeline, that our capital plan for 2019 will be minimal, 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 the budgeted capital program for 2019, which is subject to the discretion of our Board of Directors, will not be amended in the future, 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 ( and at our website ( 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.

Drilling Locations

This news release discloses drilling locations in three categories: (i) proved locations; (ii) probable locations; and (iii) unbooked locations. Proved locations and probable locations are derived from the Company’s most recent independent reserves evaluation as prepared by McDaniel & Associates Consultants Ltd. as of December 31, 2018 and account for drilling locations that have associated proved and/or probable reserves, as applicable. Unbooked locations are internal estimates based on Chinook’s prospective acreage and an assumption as to the number of wells that can be drilled per section based on industry practice and internal review. Unbooked locations do not have attributed reserves or resources. Of the 587 gross (511 net) drilling locations identified herein (based on 400 metre inter-well spacing and 1,800 metre lateral lengths in both the upper and middle Montney), 21 gross (18.1 net) are proved locations, 16 gross (13.1 net) are probable locations and 550 gross (479.8 net) are unbooked locations. Unbooked locations have been identified by management as an estimation of our multi-year drilling activities based on evaluation of applicable geologic, seismic, engineering, production and reserves information. There is no certainty that Chinook will drill all unbooked drilling locations and if drilled there is no certainty that such locations will result in additional oil and natural gas reserves, resources or production. The drilling locations on which we actually drill wells will ultimately depend upon the availability of capital, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, actual drilling results, additional reservoir information that is obtained and other factors. While the majority of the unbooked drilling locations have been derisked by drilling existing wells in relative close proximity to such unbooked drilling locations, certain unbooked drilling locations are farther away from existing wells where management has less information about the characteristics of the reservoir and therefore there is more uncertainty whether wells will be drilled in such locations and if drilled there is more uncertainty that such wells will result in additional oil and gas reserves, resources or production.

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 flow 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 flow 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 flow 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 flow 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 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 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.