CALGARY, ALBERTA-(Marketwire - Nov. 14, 2011) - Chinook Energy Inc. (“Chinook” or the “Company”) (TSX:CKE) is pleased to announce its third quarter (“Q3”) results.

Chinook’s Q3 results showed improvements in both production volumes and cash flow relative to the Q2 of the year as Tunisian oil production that commenced in June impacted the full quarter for the first time. Supported by strong pricing and exceptional netbacks for its Brent-priced Tunisian oil production and successful dispositions from its non-core assets in Canada, Chinook has been able to fund an increased capital program, decrease its leverage and upgrade its opportunity profile.

Production increased in Q3 and averaged 14,443 boe per day, up two percent from the Q2 volumes on the strength of Tunisian oil weighted volumes, which increased to nine percent of overall corporate production, and despite the loss of production associated with asset sales with forecast Q3 production of 723 boe per day. Q3 sales volumes of 14,514 boe per day were weighted 35% to liquids supporting an average commodity price of $45.63 per boe. Costs (royalties, net operating and cash G&A) increased to $27.29 per boe and the cumulative effect of a 2% increase in prices and slightly higher costs was a 3% decrease in the average netback to $18.34 per boe. The material positive impact of increasing Tunisian volumes is reflected in a segment comparison of Q3 revenue and netbacks which for Tunisia were $111.50 per boe and $82.99 per boe respectively and for the Canadian business segment averaged $38.68 per boe and $11.58 per boe, respectively. For the balance of 2011 and looking forward to next year, the capital program will be weighted approximately 60% towards oil development projects in Tunisia while Canadian activity will continue to pursue conventional light oil opportunities and mature its resource play exposure within a budget based on domestic cash flow.

Operating costs for the quarter were $20.82 per boe, up 13% from the year-to-date average due to a combination of higher operating costs than forecast, recompletions and prior period adjustments on non- operated properties. Operating costs are unacceptably high and they need to come down for the Company to be both profitable and competitive and we will be working to show improvement through increased operated production being processed through company-owned facilities in core areas and through the continued divestiture of minor non-operated properties.

Cash flow for the quarter increased 24% over the second quarter to $22.1 million ($0.10 per share). Tunisian cash flow represented 48% of Q3 cash flow versus 22% in Q2. Year-to-date capital expenditures of $93.4 million were split between Tunisia (24%) and Canada (76%) and have been funded from $61.1 million of cash flow and a portion of the proceeds of asset sales. To the end of Q3 the Company had signed agreements for 17 transactions which had closed or where closing was pending for the disposition of 1,020 boe per day of forecast Q4 production for total proceeds of $84 million. Net debt at the end of Q3 was $151.0 million. Proforma closing of the transactions mentioned, and inclusive of capital expenditure plans totalling $37 million for the rest of the year, net debt at the end of 2011 should be approximately $135 million, down from our previous guidance of $150 million. Production volumes for 2011 will be in the 14,400-14,600 boe per day range as asset sales will be 25% higher than previously forecast. Cash flow for the full year 2011 is now forecast to be $82-83 million, down 11% from the previous guidance due to higher operating costs, well performance and asset dispositions.

Three months ended Nine months ended
September 30 September 30
2011 2010 2011 2010
Production (3)
Oil (bbl/d) 3,705 3,460 3,578 1,719
Natural gas liquids (bbl/d) 1,343 1,120 1,453 727
Natural gas (mcf/d) 56,364 69,052 56,375 32,846
Average daily production (boe/d) 14,443 16,089 14,428 7,921
Sales Prices
Average oil price ($/bbl) 94.19 68.61 91.25 70.18
Average natural gas liquids price ($/bbl) 67.15 52.32 64.04 51.62
Average natural gas price ($/mcf) 3.84 3.71 3.90 3.93
Corporate Netbacks (1)
Average commodity pricing ($/boe) $ 45.63 $ 33.53 $ 44.08 $ 35.67
Royalties ($/boe) (5.24 ) (2.52 ) (6.96 ) (3.97 )
Net production expense ($/boe) (1) (20.25 ) (10.47 ) (16.91 ) (11.25 )
Cash G&A ($/boe) (1) (1.80 ) (2.70 ) (2.03 ) (5.70 )
Corporate Netback ($/boe) (1) $ 18.34 $ 17.84 $ 18.18 $ 14.75
FINANCIAL ($ thousands, except per share amounts)
Petroleum and natural gas revenue, net of royalties 53,920 44,869 145,489 67,393
Cash flow 22,114 30,643 61,054 29,153
Per share - basic and diluted (1) 0.10 0.14 0.29 0.26
Net income (loss) from continuing operations (3,543 ) 2,496 (5,675 ) (1,106 )
Per share - basic and diluted (0.02 ) 0.01 (0.03 ) (0.01 )
Capital expenditures (2) 30,687 41,371 93,358 514,699
Net debt (1) 151,014 195,916 151,014 195,916
Total assets 870,908 881,390 870,908 881,390
Common Shares (thousands)
Weighted average during period
- basic and diluted 214,188 213,956 214,188 113,381
Outstanding at period end 214,188 214,188 214,188 214,188

The disposition of non-core assets is targeted at improving the boe metrics, focusing our operations in the areas that have been identified as profitable growth opportunities and strengthening the balance sheet. Canadian production volumes may shrink in the next few quarters as the Company re-tools for improved profitability and growth. We are over halfway towards the targeted sale of a minimum $150 million in assets by year end 2012 and will initially apply the proceeds to reduce debt but as the Company moves into 2012, the balance sheet flexibility that these sales create will allow us to internally finance the major capital outlay forecast for the early stage development of our TT discovery in Tunisia. By late 2012, cash flow from TT is expected to support accelerated exploration in Tunisia, sanctioning of the offshore Cosmos development and potentially our initial commitments in a second international project.

During the quarter we drilled 12 wells, including ten in Canada, and completed the construction and startup of a sour gas rated facility at Red Creek. Performance to date from this Doig discovery has been disappointing, averaging at 185 boe per producing day in October, roughly 65% of what had been expected. A second well on the play has been cased and we will design the completion for late in the first quarter of 2012 after receiving results of some detailed core analysis. Industry activity is heating up in the immediate area and a second zone being actively explored offsetting our acreage is prospective on our lands as well. Given well costs in excess of $6 million, the economics of the play are very sensitive to liquids rates and we will gauge our pace of development dependent on the results from the next few operations. At Winmore in SE Saskatchewan, we drilled seven wells during Q3 and now have a total of 14 wells producing 550 boe per day gross (300 boe per day net). At Knopcik, we completed the drilling of two wells, including the first of four commitment wells on a farm-in where we have access to over 125 sections of land in our core area.

Both wells were cased and will be completed in the fourth quarter as will the drilling of the final three commitment wells.

In Tunisia, we commenced a four well development program with two drilling rigs that should be finished drilling by early November. Fracture stimulation and flow testing of the wells commenced in late October and we are still hopeful of seeing gross production volumes in the 2,700 to 3,000 barrels per day range from the TT discovery by year end. The stratigraphic and well test information we are gathering from this program will more than double our control and allow construction of a reservoir model that will be the basis of the development plan we will propose and hopefully come to agreement on with the Tunisian authorities. In parallel with this, we are working on preliminary engineering of the oil production facility, the flow assurance and routing of a 140 km oil sales pipeline, gas conservation strategies and the trajectory, well engineering and rig specifications required to execute a successful horizontal test well. We are actively engaged with ETAP in the project management process and will be proposing a 10 to 12 well development program with gross expenditures in excess of $115 million for 2012. Production from the TT discovery averaged 1,575 boe per day (840 boe per day net) for Q3 from three wells and current production is 2,400 boe per day at a water cut of 11% and gas to oil ratio of 1,200 scf/bbl from five wells with two wells left to be completed.

As we are writing this quarterly report we are just weeks into the first democratically elected government to emerge from the “Arab Spring” movement. Open, transparent and peaceful elections were held October 23rd and Ennahda, a moderate Islamic party that points to governments of Turkey and Indonesia as working models, won the largest percentage of seats (40%) in the assembly. The mandate includes reviewing the constitution, appointing a new Prime Minister, President and Cabinet, as well as setting up Presidential elections and laying the groundwork for parliamentary elections within two years. The party has signalled their support for direct foreign investment and enforcement of existing contracts and we await the reconfirmation of existing or naming of new ministers and senior bureaucrats that will follow over the next few months. There have been sporadic incidents of road closures, work stoppages or protests that are labour related but only very limited issues attributable to the outcome of elections. In general, activity in the oil industry and daily production has declined since the revolution in January. Against that trend, we have been pursuing our regulatory, operational and production activity with reasonable stability through the entire period and although full stability is still elusive and “business as usual” will continue to evolve as the new administration and the bureaucracy’s response to the new order gets increasing definition over the next weeks and months, we have moved from optimistic to expectant that things will settle successfully from these early critical steps towards a more representative government that will continue to provide the stability to execute our business plan. Development of our discoveries and continued follow up exploration of our 3 million acre position has the potential to be material for Chinook AND for Tunisia.

Our Board of Directors has approved a preliminary budget for 2012 that will see the Company spend $195 million, $112 million of which will be spent in Tunisia with 85% of that amount focused on the development drilling, central facility and pipeline construction at our TT discovery on the Bir Ben Tartar Concession. This level of expenditure is expected to increase net Tunisian production to an average of 2,400-2,600 boe per day for the year. The budget is expected to be funded from forecast cash flow of $135- 140 million and the $55-60 million capacity available on our credit facility thanks in large part to the successful divestitures completed in 2011. Additional asset sales have not been factored into the budget plan and, if completed, will initially be applied to reducing 2012 debt which is currently forecast to rise to as high as $180-190 million, or 1.3-1.4 times our forecast 2012 cash flow. Volumes are forecast to average 15,000-15,400 boe per day (45% liquids, 18% priced off Brent). This forecast is based on an average AECO natural gas price of $3.74/mcf, an average oil Edmonton price of $95.00/bbl and an average Brent oil price of $104.00/bbl.

Summarizing our forecast full year’s performance for 2011 after nine months of actuals, we expect production net of asset sales to be flat and expenditures, net of sales proceeds, to be 55% of cash flow. The residual improvement in our balance sheet to a year end debt level that is 1.6 times our 2011 cash flow and 1.0 times our forecast 2012 estimate will provide us with the financial flexibility to manage an aggressive capital program in 2012 of 140% of our cash flow with no expectation for a new equity requirement or excessive leverage. The planned program for 2012 will see liquids approach 45% of boe volumes, volumes increase by 5%, and cash flow per share grow by more than 50%. We will continue to address cost control, profitability and focus in our core areas in the Canadian business and follow on progress made through dispositions and successful exploration of our substantial undeveloped land position. In addition to the transition to profitability we hope to achieve organically in Canada, we recognize our Canadian operation provides balance sheet and cash flow support in the short term to allow us to develop exciting light oil opportunities in Tunisia that will solidify the foundation for value delivery for our shareholders.

About Chinook Energy Inc.

Chinook is a Calgary-based public oil and natural gas exploration and development company that combines high quality gas and liquids balanced assets in Western Canada with an exciting high growth oil business onshore and offshore Tunisia in North Africa.

Reader Advisory

Certain information regarding Chinook in this news release including management’s assessment of the future plans and operations of Chinook and the timing thereof constitute forward-looking statements under applicable securities laws. In addition, statements relating to “resources” are deemed to be forward-looking statements as they involve the implied assessment, based on certain estimates and assumptions, that the resources described exist in the quantities predicted or estimated and be profitably produced in the future. In particular, this news release contains, without limitation, forward-looking statements pertaining to the following: management’s assessment of the future plans and operations of Chinook and the timing thereof, anticipated divestiture activities and future production volumes of oil and natural gas.

With respect to the forward-looking statements contained in this news release, Chinook has made assumptions regarding, among other things: the ability of Chinook to continue to operate in Tunisia with limited logistical security and operational issues, future capital expenditure levels, future oil and natural gas prices, future oil and natural gas production levels, Chinook’s ability to obtain equipment in a timely manner to carry out development activities, the impact of increasing competition, the ability of Chinook to add production and reserves through development and exploitation activities. Although Chinook believes 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 Chinook’s 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, political and security risk associated with Chinook’s Tunisian operations, risks associated with oil and gas exploration, development, exploitation, production, marketing and transportation, loss of markets, volatility of commodity prices, currency fluctuations, imprecision of reserve and resource estimates, environmental risks, competition from other producers, inability to retain drilling rigs and other services, 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 ability 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 effect Chinook’s 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 Chinook’s website ( Furthermore, the forward-looking statements contained in this news release are made as at the date of this news release and Chinook does 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.

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. Boe 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.

Discovered Petroleum Initially-In-Place

DPIIP (equivalent to discovered resources) is defined in the Canadian Oil and Gas Evaluation Handbook as that quantity of petroleum that is estimated, as of a given date, to be contained in known accumulations prior to production. The recoverable portion of discovered petroleum initially-in-place includes production, reserves, and contingent resources; the remainder is unrecoverable. There is no certainty that it will be economically viable or technically feasible to produce any portion of the DPIIP except for those portions already produced or identified as reserves.

Non-GAAP Measures

The term cash flow does not have any standardized meaning as prescribed by IFRS and previous GAAP and, therefore, are considered non-GAAP measures. Cash flow is calculated based on cash flow from continuing operating activities before changes in non-cash working capital. Cash flow per share is calculated based on cash flow from continuing operating activities before changes in non-cash working capital from continuing operations. Management believes that cash flow is a supplemental measure and utilizes it as a key measure to assess the ability of the Company to finance operating activities, capital expenditures and debt repayments. Cash flow as presented is not intended to represent cash flow from operating activities, net earnings or other measures of financial performance calculated in accordance with GAAP and should not be construed as an alternative to cash flow from operations.

Corporate netback is a non-GAAP measure and is calculated as a period’s sales of petroleum and natural gas, net of royalties less net production and operating expenses and cash G&A as divided by the period’s sales volumes. Management uses this non-GAAP measure to assist them in understanding the Company’s profitability relative to current commodity prices and it provides an analysis tool to benchmark changes in operational performance against prior periods on a comparable basis.

Net debt is calculated as bank debt adjusted for working capital excluding mark-to-market derivative contracts. Working capital excluding mark-to-market derivative contacts is calculated as current assets less current liabilities both of which exclude derivative contracts and current liabilities excludes the current portion of debt. Management use net debt to assist them in understanding the Company’s liquidity at specific points in time. Mark-to-market derivative contracts are excluding from working capital, in addition to net debt, as management intends to hold each contract through to maturity of the contract’s term as opposed to liquidating each contract’s intrinsic value or loss.