Chinook Energy Inc. ("our", "we", or "us") (TSX: CKE) is pleased to announce our operating and financial results for the three months ended June 30, 2019 (“Q219”). Our unaudited condensed consolidated financial statements and management’s discussion and analysis for the three and six months ended June 30, 2019 are available on our website (www.chinookenergyinc.com) and filed on SEDAR (www.sedar.com).

Q219 Highlights

• Additional Q219 egress: We obtained additional egress during Q219 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 66% compared to 22% during the three months ended June 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 voluntary 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.
• 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.
• New price risk contracts: We continue to layer in commodity price hedges and diversify our natural gas sales points with approximately 28% of forecast 2019 natural gas production currently hedged at Chicago or Station 2 pricing.

Q219 Operating and Financial Highlights

		Three months ended June 30						Six months ended June 30
			2019			2018			2019			2018
OPERATIONS
Production Volumes
Natural gas liquids (boe/d)			279			680			367			575
Natural gas (mcf/d)			8,457			22,253			11,904			18,053
Crude oil (bbl/d)			10			23			9			21
Average daily production (boe/d) (1)			1,698			4,413			2,360			3,605
Sales Prices
Average natural gas liquids price ($/boe)		$	43.02		$	66.65		$	47.31		$	63.29
Average natural gas price ($/mcf)		$	1.38		$	1.40		$	1.84		$	1.87
Average oil price ($/bbl)		$	67.20		$	75.11		$	62.82		$	72.09
Operating Netback (2)
Average commodity pricing ($/boe)		$	14.33		$	17.75		$	16.89		$	19.90
Royalty expense ($/boe)		$	(0.22	)	$	(0.07	)	$	(0.11	)	$	(0.11	)
Realized (loss) gain on commodity price contracts ($/boe)		$	(0.89	)	$	0.17		$	(1.40	)	$	(0.35	)
Net production expense ($/boe) (2)		$	(17.26	)	$	(10.17	)	$	(13.44	)	$	(11.96	)
Operating netback ($/boe) (1) (2)		$	(4.04	)	$	7.68		$	1.94		$	7.48
Wells Drilled
Exploratory wells (net)			-			-			-			2.00
FINANCIAL ($ thousands, except per share amounts)
Petroleum & natural gas revenues, net of royalties		$	2,178		$	7,098		$	7,169		$	12,913
Cash (outflow) inflow from operating activities		$	(1,940	)	$	1,223		$	(2,097	)	$	(499	)
Adjusted funds (outflow) flow (2)		$	(1,708	)	$	1,836		$	(1,514	)	$	2,307
Per share - basic and diluted ($/share)		$	(0.01	)	$	0.01		$	(0.01	)	$	0.01
Net loss		$	(22,242	)	$	(2,471	)	$	(24,738	)	$	(4,569	)
Per share - basic and diluted ($/share)		$	(0.10	)	$	(0.01	)	$	(0.11	)	$	(0.02	)
Development and exploration expenditures		$	-		$	180		$	-		$	2,677
Net debt (2)		$	5,207		$	2,654		$	5,207		$	2,654
Total assets		$	77,284		$	123,637		$	77,284		$	123,637
Common Shares (thousands)
Weighted average during period
Basic & diluted			223,681			223,603			223,662			223,584
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. 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 until this October. Although we responded by acquiring additional egress allowing us to realize a premium over Station 2 spot pricing, most transport services are currently fully contracted or are not economically favourable. We will continue to focus on capital preservation and optionality until we observe more constructive BC Station 2 benchmark pricing or are otherwise able to secure more favorable natural gas pricing which would serve to strengthen our balance sheet and facilitate future drilling activity.

We are not in compliance with one of our lender’s financial covenants: net debt to cash flow that allows a maximum ratio of three times 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 BC 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 nine months and outweigh the effect from expected higher pricing. Our forecast may materially change if the BC Station 2 benchmark exceeds current strip pricing during the upcoming winter season resulting from the expected increase in BC take away capacity anticipated from the expansion of TCPL’s North Montney Pipeline combined with Westcoast’s pipeline returning to normal operating pressures.

Although our debt is drawn under a demand agreement resulting in all such draws always being classified as a current liability, the noncompliant net debt to cash flow financial covenant and recent decreases in forward BC natural gas strip pricing creates uncertainty as to the likelihood that our lender will provide us a waiver for the noncompliance with this financial covenant. We expect our lender to reduce the $10 million availability of our credit facility given recent decreases in forward natural gas benchmark pricing. While we continue discussions with our lender, the borrowing base redetermination and resolution of the financial covenant breach remain outstanding. These discussions include requesting that our lender provide us a waiver for the financial covenant breach and/or remove (modify) it from (within) the terms of our demand credit facility agreement. While these discussions are ongoing, we are evaluating other financing options that may inject additional liquidity including the disposition of natural gas assets, the sale/leaseback of midstream assets and other alternative sources of debt.

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

Contractual Term	Notional Volumes	Index and Company's Received Price
Natural gas swap
January 1, 2020 to March 31, 2020	2,000 GJ/d	Westcoast Station 2 CAD$1.785/GJ
Natural gas collars
January 1, 2020 to March 31, 2020	4,000 mmbtu/d	Chicago City Gate Monthly US$2.15/mmbtu to US$4.11/mmbtu

Board of Director Resignation

P.Grant Wierzba resigned from our Board effective August 8, 2019. “We would like to thank Mr. Wierzba for the significant contribution he made to our Board since inception and wish him all the best” stated Jill Angevine, Chairman of Chinook.

Outlook

We are uncertain about our ability to access sufficient capital to finance our future operations given the continued weakness in the BC natural gas price related to export capacity constraints. Consequently, our development program in 2019 will be minimal until such time as commodity prices improve to constructive levels. We also expect the following to occur during 2019 or early 2020:

• Production to return to unrestricted levels: We continued to restrict our production throughout July 2019 but forecast sufficient natural gas price improvements by this upcoming September or October for our production to return to unrestricted levels of approximately 4,000 boe/d. However, we continue to be hindered by third party outages including Enbridge’s McMahon processing facility that unexpectedly has shut-in all of our production since July 30th. This facility is expected to be operational the week of August 12th.
• $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.
• New commodity price contracts: We intend to layer in additional commodity price risk contracts to guarantee the price we will receive on our future production.
• Borrowing base redetermination discussions with our lender: While these discussions are currently ongoing, we are evaluating other financing options including 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                                              President and Chief Executive Officer          Chinook Energy Inc.                          Telephone: (403) 261-6883   

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

Website: www.chinookenergyinc.com

Reader Advisory

Abbreviations

Oil and Natural Gas Liquids					Natural Gas
bblbbl/d	barrelsbarrels per day				mcfmmcf	thousand cubic feetmillion cubic feet
NGLs	Natural gas liquids				mcf/dmmcf/dmmbtummbtu/d	thousand cubic feet per daymillion cubic feet per daymillion British Thermal Unitsmillion 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/dStation 2Chicago City Gate			barrel of oil equivalent per dayMarket point for BC natural gasMarket 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: forecasted breaches of a financial covenant in our credit facility over the next 12 months, that our new office space lease which commenced in June 2019 will result in estimated annual cost savings of $2.0 million, our belief that Station 2 gas prices will be negatively impacted through to this October due to reduced pressures on the Enbridge Westcoast pipeline, that thereafter our production will return to unrestricted levels of approximately 4,000 boe/d, that our capital plan for 2019 will be minimal, 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 we expect our lender to reduce the $10 million availability of our credit facility given recent decreases in forward natural gas benchmark pricing 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 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.