Chinook Energy Inc. Announces Third Quarter Results

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CALGARY, ALBERTA--(Marketwire - Nov. 12, 2010) - Chinook Energy Inc. ("Chinook" or the "Company") (TSX:CKE) is pleased to announce its financial and operating results for the three and nine months ended September 30, 2010.

The third quarter of 2010 marks the first full quarter of operations for Chinook Energy Inc. The business combination between Iteration Energy Ltd. ("Iteration") and Storm Ventures International Inc. closed on June 29, 2010, and the Company was listed for trading as Chinook Energy Inc. (CKE) on the TSX on July 6, 2010. We have had an opportunity to gain a more complete understanding of the production profile and the opportunities in the asset base and we are developing a focused plan to grow the former Iteration assets. Production declines are consistent with our expectations at approximately 20 percent and we are encouraged by the volume and quality of the prospects we are generating. We have initiated a drilling program with positive early results but will need to ramp up the pace to offset natural declines and grow production. We expect increasing production volumes by the first quarter of 2011. The Chinook story will be transitioning from a natural gas weighted conventional producer, with our international platform expected to deliver a better liquids balance and an increased focus on selected resource opportunities providing improved scale and repeatability in our domestic business.

THIRD QUARTER RESULTS

Production for the third quarter of 2010, averaged 16,089 barrels of oil equivalent per day, comprised of 69 million cubic feet per day of natural gas, 3,460 barrels of oil per day and 1,120 barrels of natural gas liquids per day. Sales volumes averaged 15,729 barrels of oil equivalent per day as there was an inventory build in Tunisia over the third quarter of 2010. Current volumes are approximately 15,800 barrels of oil equivalent per day. 

Revenue for our gas weighted production was $33.53 per barrel of oil equivalent, driven largely by our average gas price of $3.71 per thousand cubic feet. We had 9.2 million cubic feet per day hedged for the third quarter of 2010 at an average price of $5.48 per thousand cubic feet. Our gas hedge/collared volumes decreased to 7.8 million cubic feet per day for the fourth quarter of 2010, at an average minimum price of $6.02 per thousand cubic feet, and to 6.1 million cubic feet per day for 2011, at an average minimum price of $6.54 per thousand cubic feet. We have collars on oil hedges in place for 1,400 and 1,500 barrels of oil per day for the fourth quarter of 2010 and 2011, respectively, with details outlined in the interim Consolidated Financial Report and accompanying notes.

Royalties averaged eight percent and our cash costs (G&A, interest, operating) of $16.72 per barrel of oil left us with a netback of $14.29 per barrel of oil equivalent. Our operating expenses and G&A per barrel of oil equivalent are running lower than what we had forecast and our royalty rate was lower than forecast due to lower prices and a one time adjustment described in the interim MD&A. Our netbacks showed a 110 percent improvement from the second quarter of 2010 but are still stressed at current natural gas price levels. We hope to show improvement into 2011 as we increase the relative percentage of liquids production and realize scale efficiencies on our cash costs.

Cash flow for the third quarter of 2010 of $30.6 million funded our capital expenditure program of 32.3 million, which included the drilling of 17 wells (9.25 net). All wells were cased for completion, one was subsequently abandoned and three were on production by the end of the third quarter of 2010. In our core area at Grande Prairie five of six wells were successful, in encountering both the primary Nikanassin target and at least one other zone and in the Gilby area we cased both wells drilled and encountered some interesting oil results on which we hope to follow up. In Tunisia, we finished two important exploration operations. The well completion operations on the Jenein well were suspended with no commercial hydrocarbon flow. We continue to gather data from the well and other analogous Acacus wells for comparison. Pending an evaluation of produced fluids, potential formation damage and concepts for remediation, we may attempt a workover on the Acacus zone in 2011 prior to a completion attempt on a prospective gas and condensate zone in the Ordovician. This work will be planned to coincide with the gas infrastructure development in 2012. We also completed some post-well analysis that has us encouraged that the Fushia discovery, which we initially reported as a non-commercial gas discovery, is actually a volatile oil discovery based on the re-combination of fluids recovered on test. We are evaluating the potential for Fushia to be developed as a tie back to an offsetting similar field, Maamoura, which is pipeline connected to shore-based gas processing and liquid recovery infrastructure.

Our debt plus working capital position at the time of closing the Iteration acquisition was $185.5 million. We disposed of two properties during the third quarter of 2010 for proceeds of $18.6 million which was used to retire the bridge loan outstanding to Alberta Investment Management Corporation. At September 30, 2010, our debt plus working capital position was $159.5 million and we forecast that we will end 2010 at that level or 1.3 times our annualized third quarter cash flow.

In summary, volumes and gas pricing are below our estimates for the second half of 2010 but lower cash costs and royalties kept our cash flow on track and our estimated net debt level at the end of 2010 will be approximately 10 percent lower than originally forecast.

Financial and Operating Results     
           
  Three Months Ended Sept. 30     Nine Months Ended Sept. 30  
($ thousands, except per unit amounts) 2010     2009     2010     2009  
Sales and prices(3)                              
Oil sales (bbl/d)   3,099       83       1,585       59  
Natural gas liquids sales (bbl/d)   1,120       -       727       -  
Natural gas sales (mcf/d)   69,052       -       32,846       -  
Average daily sales 6:1 (boe/d)   15,729       83       7,788       59  
Average oil price ($/bbl)   68.61       66.88       70.18       68.92  
Average natural gas liquids price ($/bbl)   52.32       -       51.62       -  
Average natural gas price ($/mcf)   3.71       -       3.93       -  
Production(4)                              
Oil (bbl/d)   3,460       83       1,719       59  
Natural gas liquids (bbl/d)   1,120       -       727       -  
Natural gas (mcf/d)   69,052       -       32,846       -  
Average daily production (boe/d)   16,089       83       7,921       59  
Financial operations                              
Oil, natural gas and natural gas liquids revenue, net of royalties(3)   44,869       512       67,393       1,115  
Cash flow(1)   30,643       (942 )     29,153       (452 )
  Per share-basic and diluted(1) $ 0.14     $ (0.01 )   $ 0.26     $ (0.01 )
Net loss from continuing operations   (6,125 )     (2,334 )     (19,058 )     (4,667 )
  Per share-basic and diluted $ (0.03 )   $ (0.03 )   $ (0.17 )   $ (0.06 )
Net loss   (6,125 )     (2,303 )     (32,598 )     (3,290 )
  Per share-basic and diluted $ (0.03 )   $ (0.03 )   $ (0.29 )   $ (0.04 )
Capital expenditures(2) (3)   32,260       1,063       501,153       4,079  
Working capital (deficit)(5)   (159,450 )     2,658       (159,450 )     2,658  
Total assets   807,432       429,881       807,432       429,881  
Common shares (thousands)                              
Weighted average during period                              
  - basic   213,956       73,628       113,381       73,628  
  - diluted   213,956       73,628       113,381       73,628  
Outstanding at period end                              
  - basic   214,188       73,724       214,188       73,724  
  - diluted   222,243       77,800       222,243       77,800  
                               
(1) Cash flow is a non-GAAP measurement and is calculated based on cash flow from continuing operating activities before changes in non-cash working capital.
(2) Excludes asset retirement obligations incurred during the period.
(3) Excludes discontinued operations.
(4) Production volumes differ from sales volumes in Tunisia where volumes of oil are stored as inventory until title, responsibility and risk of the oil transfer to a third party occurs.
(5) Working capital deficit consists of debt of $179.8 million offset by a working capital surplus of $20.3 million.

CHINOOK BUSINESS PLAN

Our current producing assets in Canada represent a very diverse natural gas weighted conventional production base. Currently, over 85 percent of our production is from conventional plays in Western Canada and 70 percent of our production is natural gas. Over the next three years, we can see the potential in our undeveloped properties to reposition Chinook into focused projects with significant scale, repeatability and commodity balance. We expect to grow both the domestic resource play and international production to contribute 30 percent each to our volumes by the end of 2013.

Subject to a modest recovery in natural gas prices, we are expecting an increase in the contribution to production from the exploitation of resource play concepts in the Nikanassin and Montney where we have an identified resource on our lands that could be material to our reserves and production. We will exit non- core properties through sales or swaps and focus on our conventional multi-zone core areas at Grande Prairie, Peace River and Gilby. These core areas currently represent 75 percent of our production and are areas where we have a competitive cost structure, facility infrastructure and a strong prospect inventory.

Our international business will focus on our oil development project inventory in Tunisia until that business is cash flow self sufficient, which we hope to demonstrate by the end of 2011. We will then be prepared to expand our platform to include another oil weighted country exposure through a combination of either a production purchase or field development opportunity.

COMMODITY OUTLOOK

Ultimately, we will strive to have a balanced inventory of matured opportunities in both commodities where we can focus short term development capital expenditures on the commodity with the strongest short term recycle ratio, unfortunately we are not quite there yet. In the third quarter of 2010, we realized prices of $3.71 per thousand cubic feet for our natural gas and $68.61 per barrel for our oil, natural gas currently trades at roughly 18:1 on a revenue equivalency. If we look to the current strip for 2011 for Canadian index pricing, that ratio is 20:1. Based on the relative economics we will be directing up to 75 percent of our capital expenditures over the next 15 months to oil and liquids prospects and delaying the delivery of natural gas projects until the natural gas price supports full cycle investment.

Over the longer term (hopefully by year end 2011!), we do expect natural gas prices to recover to a 15:1 range above the $5.00 per thousand cubic feet level, driven by a need to cover full cycle economics, an increased demand driven by the economic recovery progressing in the United States, and relative merit of abundant cheap, green, secure energy. In the short term, the 25 percent of capital expenditures directed towards natural gas will progress our most advanced resource play in the Nikanassin and prove up our resource and development inventory on the Montney and Notikewin.

LOOKING TOWARDS 2011

Our forecast activity for the remainder of 2010 and into 2011, is driven by commodity prices and will focus, to the degree possible, on oil. We are forecasting to spend 85-90 percent of our cash flow in 2011 and grow our volumes by an average of 6-8 percent. We will look to allocate up to the $100.0 million of balance sheet capacity we have defined by our current facility of $240.0 million as we see the results of our oil appraisal activities, identify acquisition opportunities, or see field gas prices improve to levels closer to the $5.00 per thousand cubic feet range. We have a potentially large scale oil development in Tunisia that we will move through the regulatory approval and appraisal stage and hope to be at the point of being able to kick off a large scale development of the Ordovician zone at Sud Remada before the end of 2011. Exploration on the Acacus fairway will focus on the Borj El Khadra block where we will participate in exploration wells in the fourth quarter of 2010 and 2011 and shoot an additional 1,200 square kilometres of 3D seismic in partnership with ENI, the operator. In Canada, we have four light oil discoveries (three horizontal) where we are testing the first well and have follow up locations on land that we control. We have had good success to date in our Grande Prairie area combining Nikanassin prospectivity with Triassic Charlie Lake or Halfway oil prospects that will support progressing a long term natural gas growth objective without sacrificing short term profitability. The quality and depth of our oil prospect inventory has been a welcome and a pleasant surprise as we have become more familiar with the suite of domestic assets in Chinook.

For the fourth quarter of 2010, we forecast production will average between 15,600-15,900 barrels of oil equivalent per day and our revised guidance for 2011 is for production to average between 16,700-17,100 barrels of oil equivalent per day. With commodity prices of $3.75 per thousand cubic feet at AECO and $82.35 per barrel for Edmonton light crude, cash flow is estimated to range between $130 and $140 million. Our initial capital expenditure forecast for 2011 is $120 million which we anticipate our debt being reduced to approximately $140-150 million. Our credit facility, which is currently under review, is expected to be reconfirmed at $240 million which leaves us with substantial balance sheet capacity. We have completed, and will continue to pursue, property rationalization efforts aimed at redeploying proceeds from approximately 25 percent of our Canadian production from areas outside of our long term core growth assets.

SUMMARY

We recognize we need to begin to grow volumes, and confirm the timing of the Sud Remada field development over the next two quarters as a catalyst to improved market performance for our shares. We will endeavor to do that as efficiently and quickly as possible.

We would like to recognize the Herculean efforts of our staff over the first three months of the newly integrated Chinook to deliver the results presented here in the face of start up teething issues, systems integration, relocations on the merger, and most recently, new moves into what we hope are semi permanent premises. Their patience and performance are greatly appreciated.

We thank you for your support through these transactions and remain committed to delivering value to you through your investment in Chinook Energy Inc.

Chinook will post an updated corporate presentation on its website Monday, November 15, 2010.

About Chinook Energy Inc.

Chinook is a Calgary-based public oil and gas exploration and development company that combines high quality gas-weighted 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 "reserves" are deemed to be forward-looking statements as they involved the implied assessment, based on certain estimates and assumptions, that the reserves 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: the ability to achieve future production, the receipt of forecasted prices, reliance on partners to conduct and participate in capital operations, the confirmation of the credit facility and Chinook's operational and business plans.

With respect to the forward-looking statements contained in this news release, Chinook has made assumptions regarding, among other things: future capital expenditure levels, future oil and natural gas prices, future oil and natural gas production levels, confirmation of receipt of the credit facility re-determination, 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, 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 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 (www.sedar.com) and at Chinook's 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 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.



Chinook Energy Inc.
Matthew Brister
President and Chief Executive Officer
(403) 261-6883
or
Chinook Energy Inc.
L. Geoff Barlow
Vice-President, Finance and Chief Financial Officer
(403) 261-6883
www.chinookenergyinc.com