CALGARY, ALBERTA--(Marketwired - Aug 10, 2017) - Chinook Energy Inc. ("our", "we", or "us") CKE is pleased to announce its second quarter 2017 financial and operating results.

Our operational and financial highlights for the three and six months ended June 30, 2017 are noted below and should be read in conjunction with our condensed consolidated financial statements for the three and six months ended June 30, 2017 and 2016 and our related management's discussion and analysis which have been posted on the SEDAR website (www.sedar.com) and our website (www.chinookenergyinc.com).

Second Quarter 2017 Financial and Operating Highlights

			Three months ended								Six months ended
							June 30								June 30
			2017				2016				2017				2016
OPERATIONS
Production Volumes
Natural gas liquids (boe/d)			441				604				461				669
Natural gas (mcf/d)			19,065				22,776				18,546				23,995
Crude oil (bbl/d)			19				769				24				793
Average daily production (boe/d)			3,638				5,169				3,576				5,461
Sales Prices
Average natural gas liquids price ($/boe)		$	44.48			$	25.78			$	48.07			$	26.81
Average natural gas price ($/mcf)		$	2.77			$	1.35			$	2.74			$	1.39
Average oil price ($/bbl)		$	59.55			$	50.59			$	60.01			$	42.76
Netback (1)
Average commodity pricing ($/boe)		$	20.22			$	16.50			$	20.81			$	15.61
Royalties ($/boe)		$	(0.33	)		$	(0.44	)		$	(0.07	)		$	(0.73	)
Realized gains on derivative contracts ($/boe)		$	1.01			$	0.14			$	1.19			$	0.08
Net production expenses ($/boe) (1)		$	(11.82	)		$	(14.75	)		$	(11.55	)		$	(14.95	)
Operating Netback ($/boe) (1)		$	9.08			$	1.45			$	10.38			$	0.01
Wells Drilled (net)
Total natural gas wells drilled (net)			3.63				-				3.63				-

				Three months ended								Six months ended
								June 30							June 30
				2017				2016				2017			2016
FINANCIAL ($ thousands, except per share amounts)
Petroleum & natural gas revenues, net of royalties			$	6,583			$	7,550			$	13,421		$	14,794
Adjusted funds (outflow) from operations(1)			$	1,195			$	(1,721	)		$	3,231		$	(4,611	)
	Per share - basic and diluted ($/share)		$	0.01			$	(0.01	)		$	0.01		$	(0.02	)
Net (loss) income			$	(2,253	)		$	(12,520	)		$	8,169		$	(25,295	)
	Per share - basic and diluted ($/share)		$	(0.01	)		$	(0.06	)		$	0.04		$	(0.12	)
Capital expenditures			$	8,235			$	1,347			$	17,058		$	4,373
Net surplus (1)			$	18,294			$	6,207			$	18,294		$	6,207
Total assets			$	144,891			$	366,586			$	144,891		$	366,586
Common Shares (thousands)
Weighted average during period
	- basic			216,598				215,350				216,521			215,350
	- diluted			216,598				215,350				217,042			215,350
Outstanding at period end				217,115				215,350				217,115			215,350

1. Adjusted funds (outflow) from operations, adjusted funds (outflow) from operations per share, net surplus (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 (outflow) from Operations", "Net Surplus (Debt)", "Operational Netback" and "Net Production Expense" in the Reader Advisory below for further information on such terms.

Highlights for the three months ended June 30, 2017

• We ended the second quarter of 2017 with a strong balance sheet and a net surplus of $18.3 million.
• We generated funds from operations of $1.2 million compared to outflow from operations of $1.7 million in the second quarter of 2016. This is our fourth consecutive quarter of reported positive funds flow since we started our transition to a pure Montney company.
• Our operating costs were reduced by 20% to $11.82 per boe over the same period in 2016 and will continue to decrease as we bring on more profitable volumes at Birley/Umbach in 2017.
• We secured an increased credit facility of $8.0 million from the previous $2.0 million which provides us with further financial flexibility. We remain undrawn on this facility and anticipate remaining undrawn through 2017.
• We are reinvesting the proceeds from our first quarter 2017 dispositions at Gold Creek and Knopcik/Pipestone into our Montney drilling program. We incurred $8.2 million of capital reinvestment during the second quarter which included drilling another four (3.63 net) horizontal wells at Birley/Umbach as well as engineering and purchasing of long lead items for our Birley/Umbach facility expansion.
• We are currently preparing these four (3.63 net) wells for completions operations and fracking equipment is scheduled to arrive shortly. Two of the wells have approximately 1,800 metre lateral sections and the other two have approximately 1,600 metre lateral sections with a frac density of 35 stages and 30 stages, respectively. Each stage will be stimulated with nitrified slick water placing 55 tonnes of sand per stage.
• Preparations for our Birley/Umbach facility expansion are ongoing with an expected construction commencement date of September 1, 2017 and an on-stream date of December 1, 2017.
• We are maintaining our 2017 production guidance of 4,200 - 4,300 boe/d despite lower production volumes during June and July which resulted from delays in the McMahon Plant turnaround, which took an additional unscheduled three weeks to complete and carried over into July.

Second Quarter 2017 Financial Results

Our production during the second quarter of 2017 averaged 3,638 boe/d, an increase of 3.5% from the previous quarter primarily due to additional production from our three (2.64 net) Birley/Umbach wells which were drilled in the fourth quarter of 2016 and came on production at the end of the first quarter of 2017. During the second quarter, these wells added 1,450 boe/d of production during the days that they were producing. This increase in second quarter volumes was despite June's volumes decreasing by 4,300 boe/d compared to May as a result of a planned McMahon Plant turnaround. This planned turnaround was expected and we have included the majority of the production decreases in our 2017 forecasted volumes. Our Montney production was back on-stream in mid-July immediately following the completion of the McMahon Plant turnaround. We averaged approximately 4,850 boe/d of production from July 18 - 24, 2017, but these volumes have since been impacted by further McMahon Plant restrictions. We still expect to meet our 2017 guidance production of 4,200 - 4,300 boe/d.

Our production in the second quarter of 2017 decreased 30% from the same quarter of 2016 primarily as a result of the disposition of the majority of our Alberta assets through the 2016 distribution of a subsidiary's shares to our shareholders (the "Share Distribution") and various other property dispositions.

For the second quarter of 2017, our operating netback increased 526% to $9.08/boe compared to the same quarter of 2016. This increase was driven by improvements in each component of the operating netback. Our realized commodity price increases generally trended with the increase in benchmark pricing resulting in a realized price of $20.22/boe for the second quarter. Royalties per boe of $0.33/boe decreased from the same quarter of 2016 primarily as a result of royalty credits that we were granted from the BC's Infrastructure Royalty Credit Program in addition to the absence of comparatively higher Alberta royalty rate production due to the Share Distribution and divestitures. Our net production expense of $11.82/boe during the second quarter decreased from the same period of 2016 primarily due to the divestiture of higher cost properties and the signing of a new BC gas handling agreement during the third quarter of 2016. However, our net production expense was higher than our expectations mostly due to higher fluid hauling costs resulting from weather induced road bans and seasonal costs including the repair and maintenance of our processing plants and our Birley/Umbach access road. We expect our on-going operations to incur production costs under $10/boe once production volumes from our 2017 four well drilling campaign are brought on-stream.

Our adjusted funds from operations for second quarter of 2017 of $1.2 million increased from an adjusted outflow from operations of $1.7 million during the second quarter of 2016, but decreased from an adjusted funds from operations of $2.0 million in the first quarter of 2017. This increase from the prior year resulted from higher commodity benchmark prices, realized gains on commodity price contracts and a lower cash-based cost structure for our Montney focused operations. The decrease from the first quarter was primarily driven by the expected decrease in production volumes, and correspondingly lower petroleum and natural gas revenue, driven by the McMahon Plant turnaround.

We reported a net loss for the second quarter of 2017 of $2.3 million compared to a loss of $12.5 million during the same quarter of 2016. This improvement reflects higher commodity prices, a lower cost structure associated with our transition to a pure Montney play in addition to a $0.6 million gain on commodity price contracts.

Second Quarter 2017 Operational Results

During the second quarter, we drilled four (3.63 net) horizontal Montney gas wells with various downhole locations on our Birley/Umbach property in northeastern BC on our D-93-F pad. Two of the wells have approximately 1,800 metre horizontal lateral sections. Drilling costs of these wells were consistent with our guidance despite road restrictions that delayed operations and increased transportation costs. Completions and equipping are scheduled for the third quarter of 2017. All four wells will use 55 tonne fracs at 52 metre spacing and are scheduled to be on-stream during the fourth quarter of 2017 bringing our exit production to our guidance of 6,300 - 6,500 boe/d.

We budgeted $10 million of our 2017 capital program for the expansion of our Birley/Umbach facility to 50 mmcf/d, of which we spent $2.3 million during the first half of 2017.

Production from our Birley/Umbach property is as follows:

Well		Working Interest (%)		Lateral Length (metres)		Frac'd Stages (gross)		Flow Time (hours)		24 Hour Test Rate End Date (MM/DD/YYYY)		Final 24 Hour Average Test Total Gas Rates (mcf/d)		Final 24 Hour Average Test Total FCGR (1) (bbl/mmcf)		IP30 (mcf/d)		IP60 (mcf/d)		IP90 (mcf/d)
A-060-K/094-H-03		74.55		1,220		18		154		3/9/2014		5,276		54		3,726		3,754		3,923
B-071-F/094-H-03		74.55		1,553		23		211		10/4/2014		8,870		6		4,489		4,375		4,348
A-073-L/094-H-03		74.55		1,230		18		252		2/16/2015		3,827		23		3,712		3,417		3,459
C-037-K/094-H-03		100.00		1,210		18		145		9/23/2015		5,281		49		4,228		4,094		3,851
B-072-F/094-H-03		74.55		1,225		18		69		9/24/2015		3,908		30		3,991		4,104		4,227
B-004-K/094-H-03		100.00		1,200		16		119		9/24/2015		4,127		17		3,364		3,082		2,921
A-071-F/094-H-03		74.55		1,457		24		113		2/8/2017		7,319		8		3,271		3,433		3,344
D-095-F/094-H-03		98.20		1,430		24		197		2/14/2017		6,756		11		3,404		3,554		3,454
C-095-F/094-H-03		89.20		1,437		24		98		2/15/2017		8,202		25		2,957		2,665		2,549 (2)

1. Free condensate gas ratio.
2. Production for well C-095-F is for 83 days.

Financial Commodity Price Contracts

We use financial commodity price contracts to support our capital investment and growth by providing more certainty regarding our adjusted funds from operations and balance sheet management. Our internal policy permits us to hedge up to a maximum period of 24 months, based on our total estimated oil and natural gas production volumes, consisting of no more than 50% for the first 12 months and 25% for the last 12 months. Our current financial commodity price contracts in place are as follows:

Indexed Price		Notional Volumes		Company's Received Price		Remaining Contractual Term
AECO		7,500 GJ/d		$3.205/GJ		July 1, 2017 to December 31, 2017
AECO		4,000 GJ/d		$2.50/GJ		July 1, 2017 to October 31, 2017

Outlook

We continue to execute on our previously announced $40 million capital program for 2017 and remain excited about the growth it will provide. As we implement this capital program we will continue to closely monitor our balance sheet and commodity prices. As in previous years, we will remain prudent in how we deploy our capital in order to defend our strong balance sheet.

We have made great strides over the past 12 months to improve our cost structure, including completing the Craft Share Distribution and executing a new gas handling agreement in BC. On a per boe basis, for fourth quarter of 2017, our net production expense is expected to approximate $8.00/boe. As we begin to increase our production at Birley/Umbach, our cost structure and profitability significantly improve.

We forecasted the McMahon Plant outages during the second quarter of 2017, resulting in us achieving production guidance for the quarter. However, this McMahon Plant turnaround continued past our expectations in July. Additionally, we have been experiencing some Enbridge downstream line issues and TCPL maintenance issues upstream of James River that may negatively impact our Birley/Umbach production volumes and/or field prices during the latter part of August. We are evaluating the impact of these unbudgeted proposed production outages and their impact on field prices. However, for the interim, we are maintaining our previously announced production guidance for 2017 as follows:

($ millions, except boe/d)	2017 Guidance (1)
Average production (boe/d)		4,200 - 4,300
Exit production (boe/d)		6,300 - 6,500
Capital expenditures (2)	$	40
Net surplus as at December 31, 2017	$	2

1. 2017 guidance assumptions: AECO natural gas price $2.64/mmbtu, Station 2 natural gas price $2.11/mmbtu and Chicago Alliance natural gas price $2.92/mmbtu.
2. Includes decommissioning obligation expenditures and capitalized general and administrative costs.

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.

Reader Advisory

Abbreviations

Oil and Natural Gas Liquids			Natural Gas
bbl	barrel		mcf	thousand cubic feet
bbls	barrels		mcf/d	thousand cubic feet per day
bbls/d	barrels 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

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 we expect to remain undrawn on our demand revolving credit facility through 2017, the scheduled arrival time of fracking equipment and our completions strategy for our 2017 four well drilling program at Birley/Umbach, that all four wells from our 2017 four well drilling program at our Birley/Umbach area are scheduled to be completed during the third quarter of 2017 and on-stream during the fourth quarter of 2017, the expected commencement date and on-stream date of our Birley/Umbach facility expansion, the expected decrease in our operating costs, net production expense and G&A in the fourth quarter of 2017 and our expectation that as we begin to increase our production at Birley/Umbach our cost structure and profitability will improve significantly, the amount of our 2017 capital program, future exploration and development activities and the timing thereof and how we intend to manage our company as well our guidance regarding average and ending production for 2017, capital expenditures for 2017 and net surplus at December 31, 2017 set forth under the heading "Outlook".

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, future capital expenditure levels, future oil and natural gas prices, future 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, anticipated production volumes, our ability to replace and expand production and reserves through exploration and development activities, certain cost assumptions, that the budgeted 2017 capital program, which is subject to the discretion of our Board of Directors, will not be amended in the future, 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, risks associated with oil and gas exploration, development, exploitation, production, marketing and transportation, loss of markets, volatility of commodity prices and currency fluctuations, our Board of Directors may amend the 2017 capital program based on its discretion; 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. 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) from Operations

The reader is cautioned that this news release contains the term adjusted funds (outflow) from operations, 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, decommissioning obligation expenditures related to operations and transaction costs. We believe that adjusted funds (outflow) from operations is a key measure to assess our ability to finance capital expenditures and when debt is drawn, debt repayments. Adjusted funds (outflow) from operations 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 Surplus (Debt)

The reader is cautioned that this news release contains the term net surplus (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 and decommissioning obligation. We use net surplus (debt) to assist us in understanding our liquidity at specific points in time. We exclude the current portion of decommissioning obligation as it is not a financial instrument. Mark-to-market derivative contracts are excluded as they are unrealized.

Future Oriented Financial Information

This news release, in particular the information in respect of the anticipated capital expenditures, operating costs per boe, net production expense per boe, G&A per boe and net surplus set out in the table under the heading "Outlook", may contain Future Oriented Financial Information ("FOFI") within the meaning of applicable securities laws. The FOFI has been prepared by our management to provide an outlook of our activities and results and may not be appropriate for other purposes. The FOFI has been prepared based on a number of assumptions including the assumptions discussed under the heading "Forward-Looking Statements" and assumptions with respect to production rates and commodity prices. The actual results of our operations and the resulting financial results may vary from the amounts set forth herein, and such variations may be material. Our management believes that the FOFI has been prepared on a reasonable basis, reflecting management's best estimates and judgments.

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.

Initial Production Rates

Any reference in this news release to initial, early and/or test or production/performance rates (including IP30, IP60 and IP90) are useful in confirming the presence of hydrocarbons, however, such rates are not determinative of the rates at which such wells will continue production and decline thereafter. Additionally, such rates may also include recovered "load oil" fluids used in well completion stimulation. While encouraging, readers are cautioned not to place reliance on such rates in calculating our aggregate production. The initial production or test rates may be estimated based on other third party estimates or limited data available at this time . In all cases in this news release initial production or test rates are not necessarily indicative of long-term performance of the relevant well or fields or of ultimate recovery of hydrocarbons. Well-flow test result data should be considered to be preliminary until a pressure transient analysis and/or well-test interpretation has been carried out.