CALGARY, ALBERTA--(Marketwire - March 26, 2012) - Chinook Energy Inc. ("Chinook" or the "Company") (TSX:CKE) announced today its fourth quarter and year end 2011 results. A complete copy of the Company's financial statements along with management's discussion and analysis will be filed on SEDAR and will also be available on the Company's website at www.chinookenergyinc.com.
2011 was a challenging but ultimately rewarding year of transition for Chinook. The polarity of crude oil price escalation and deteriorating natural gas prices to near record lows, saw us shift our asset growth and revenue focus away from AECO-priced natural gas to Brent-priced crude oil.
2011 FINANCIAL AND OPERATING RESULTS
2011 annual production averaged 14,602 barrels of oil equivalent per day generating $238 million of revenue and $85 million of cash flow compared to production of 9,795 barrels of oil equivalent per day, revenue of $132 million and cash flow of $52 million in 2010. Cash flow per share grew by 25 percent to $0.40 per share. Average revenue per barrel of oil equivalent was $44.84 per barrel of oil equivalent up 22 percent from $36.76 per barrel of oil equivalent in 2010. Operating netbacks in 2011 increased two percent to $20.99 per barrel of oil equivalent as operating expenses increased to $17.13 per barrel of oil equivalent and cash general and administrative expenses averaged $2.84 per barrel of oil equivalent. Canadian netbacks averaged $16.15 per barrel of oil equivalent and Tunisian netbacks averaged $82.39 per barrel of oil equivalent. In Canada, we continue to focus on improving the gross revenue per barrel of oil equivalent which in the foreseeable future means, shifting capital away from natural gas projects. Operating costs in Canada have the potential to improve as new production in core areas replaces production from some higher cost properties that have been sold.
The increased contribution from premium Brent-priced Tunisian crude production was a significant contributor to the improved financial results in 2011 and will continue to strengthen our per barrel metrics and cash flow in 2012. The growth from the Tunisian business segment offset the natural production declines in the Canadian segment and the loss of production associated with the non-core asset sales in the year. Through 2011, revenue derived from liquids increased to 75 percent as a result of the shift in asset focus and was a major contributing factor to cash flow increasing over the same period. Canadian operations provided 92 percent of Chinook's production, 68 percent of the Company's cash flow and consumed 74 percent of our capital program. Tunisian operations contributed 8 percent of our volumes, 32 percent of our cash flow and attracted 26 percent of our capital as we focused on commercializing our onshore light oil discovery at Sud Remada. Looking forward to 2012, we expect over 50 percent of our cash flow to be generated from Tunisia as its projected production is expected to increase to 15-20 percent of our total production as a result of directing over 50 percent of our capital program to the light oil projects in the Ghadames Basin.
Our capital program was funded 71 percent by the investment of the funds generated from cash flow and the remainder from proceeds on asset sales. We grew production by three percent (fourth quarter 2011 over first quarter 2011) and reduced debt by over $30 million. Our Canadian business focused on crude oil project development in our core areas of West Central Alberta and Grande Prairie and the rationalization of non-core assets which improved the growth potential of our asset base and improved our operating metrics. Our Tunisian production grew 150 percent and we had our most active year ever against a backdrop of the Arab spring revolution, civil unrest, and the introduction of a new political system. The proceeds we recognized on the sale of non-core assets is a strong affirmation of the underlying value of our Canadian assets and our demonstrated performance in Tunisia supports the expectations we have of a material crude oil focused international business.
FOURTH QUARTER 2011 FINANCIAL AND OPERATING RESULTS
Fourth quarter production averaged 15,119 barrels of oil equivalent per day generating $66 million of revenue and $24 million of cash flow compared to production of 15,354 barrels of oil equivalent per day, revenue of $56 million and cash flow of $23 million in the fourth quarter of 2010. Cash flow per share was the same between the comparable quarters. Average revenue per barrel of oil equivalent was $47.00 per barrel of oil equivalent up 22 percent from $38.34 per barrel of oil equivalent in the fourth quarter of 2010. Fourth quarter 2011 operating netbacks increased 16 percent to $23.22 per barrel of oil equivalent as operating expenses increased to $17.75 per barrel of oil equivalent and cash general and administrative expenses averaged $5.13 per barrel of oil equivalent. Canadian netbacks averaged $15.76 per barrel of oil equivalent and Tunisian netbacks averaged $83.92 per barrel of oil equivalent.
Fourth quarter revenue derived from liquids was 74 percent as a result of the growth in the Tunisia operations both from oil production volumes and oil prices received. Canadian operations provided 90 percent of our production, 48 percent of our cash flow and consumed 61 percent of our capital program. Tunisian operations contributed 10 percent of our volumes, 52 percent of our cash flow and attracted 38 percent of our capital as we focused on completing the wells on the Bir Ben Tartar concession for commercial production.
| Three months ended | Year ended | |||||||
| December 31 | December 31 | |||||||
| 2011 | 2010 | 2011 | 2010 | |||||
| OPERATING | ||||||||
| Production (3) | ||||||||
| Oil (bbl/d) | 4,206 | 3,553 | 3,736 | 2,181 | ||||
| Natural gas Liquids (bbl/d) | 1,591 | 1,410 | 1,488 | 899 | ||||
| Natural gas (mcf/d) | 55,927 | 62,346 | 56,262 | 40,282 | ||||
| Average daily production (boe/d) | 15,119 | 15,354 | 14,602 | 9,795 | ||||
| Sales Prices | ||||||||
| Average oil price ($/bbl) | $ | 97.11 | $ | 76.49 | $ | 92.96 | $ | 73.13 |
| Average natural gas liquids price ($/bbl) | $ | 71.23 | $ | 55.93 | $ | 65.98 | $ | 53.33 |
| Average natural gas price ($/mcf) | $ | 3.31 | $ | 3.47 | $ | 3.75 | $ | 3.75 |
| Corporate Netbacks (1) | ||||||||
| Average commodity pricing ($/boe) | $ | 47.00 | $ | 38.34 | $ | 44.84 | $ | 36.76 |
| Royalties ($/boe) | $ | (6.03) | $ | (6.10) | $ | (6.72) | $ | (4.84) |
| Net production expenses ($/boe) (1) | $ | (17.75) | $ | (11.29) | $ | (17.13) | $ | (11.25) |
| Cash G&A ($/boe) (1) | $ | (5.13) | $ | (3.53) | $ | (2.84) | $ | (4.81) |
| Corporate Netbacks ($/boe) (1) | $ | 18.10 | $ | 17.42 | $ | 18.15 | $ | 15.86 |
| FINANCIAL ($ thousands, except per share amounts) | ||||||||
| Petroleum and natural gas revenue, net of royalties | $ | 57,274 | $ | 47,227 | $ | 202,762 | $ | 114,620 |
| Cash flow | $ | 23,950 | $ | 22,576 | $ | 85,004 | $ | 51,729 |
| Per share - basic and diluted (1) | $ | 0.11 | $ | 0.11 | $ | 0.40 | $ | 0.32 |
| Net loss from continuing operations | $ | (58,077) | $ | (12,218) | $ | (63,752) | $ | (13,324) |
| Per share - basic and diluted | $ | (0.27) | $ | (0.06) | $ | (0.30) | $ | (0.08) |
| Capital expenditures (2) | $ | 26,344 | $ | 25,454 | $ | 119,701 | $ | 235,373 |
| Net debt (1) | $ | 134,900 | $ | 169,639 | $ | 134,900 | $ | 169,639 |
| Total assets | $ | 745,403 | $ | 877,017 | $ | 745,403 | $ | 877,017 |
| Common Shares (thousands) | ||||||||
| Weighted average during period | ||||||||
| - basic and diluted | 214,188 | 214,188 | 214,188 | 162,003 | ||||
| Outstanding at period end | 214,188 | 214,188 | 214,188 | 214,188 |
| Notes: | |
| (1) | Cash flow, net debt, corporate netback, net production expense and cash G&A are non-GAAP measures as defined throughout the MD&A. 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. |
| (2) | Excludes capitalized costs relating to foreign currency translation incurred during the periods and decommissioning obligation. |
| (3) | March and June 2010, include acquisitions of Canadian and Tunisian producing assets from the corporate acquisition of Iteration and SSL from the date of acquisition. |
OPERATIONS UPDATE
Operational highlights from our Canadian projects included exploration success in our Grande Prairie core area where we were successful with 10 of 15 wells drilled, including five Triassic oil wells with average reserve adds of 400,000 barrels of oil equivalent per well including secondary zones. We plan to drill nine wells in this area in 2012 and construct an oil battery at Knopcik. We are actively evaluating liquids- focused resource plays in the Dunvegan (tight sand) and the Nordegg (shale) formations and have an interesting land exposure to the Duvernay (shale) directly offsetting recent industry drilling and infrastructure activity. We participated at a 37.5 percent working interest in two Dunvegan discoveries with initial production 30 day rates of approximately 265 barrels of oil equivalent per day (55% oil) per well and have budgeted to drill 4-6 operated wells on this horizontal oil resource play in 2012 as result of this success. Our analysis of the Muskwa potential on our Rainbow lands did not commercially support moving to a test horizontal stage and we are not pursuing the play actively at present. We had disappointing results from our Red Creek Doig oil/gas discovery and continue to evaluate the Montney play on and adjacent to our acreage. We tested a Montney natural gas resource concept at Birley in northeast British Columbia where the results appear very encouraging. We will test Montney oil prospects at Kaybob and Gold Creek during the first half of 2012. In West Central Alberta, we successfully tested the mid- Mannville natural gas resource concept at Brazeau and drilled four wells at Gilby with a 75 percent commercial success rate.
In Tunisia, we completed two drilling and completion campaigns despite logistical challenges resulting from the Arab spring revolution early in January, civil unrest throughout the year in Tunisia, the refugee situation and war zone resulting from the Libyan crisis, and finally, the campaigning and successful completion of free and fair elections in late October. The effectiveness and focus of the agencies upon which we rely for our license to practice were operating at minimally acceptable levels and it was through the extreme effort and diligence of our Tunis-based staff that we were able to complete the work that we did. We experienced only minor disruptions to our operations and no loss of production that extended beyond 48 hours. The new government is led by the moderate Islamist party Ennahda that has articulated their intention to honor lawful contracts between the state and foreign companies and their continued support for direct foreign investment. We expect 2012 will continue to present challenges with respect to the effectiveness of the bureaucracy and potential for non-violent civil unrest, but believe that it will be a year that will demonstrate less instability than 2011 and we expect to see gradual improvement.
Based on the initial delineation of the Sud Remada discovery we were awarded the Bir Ben Tartar concession totaling 86,981 acres for a term of 30 years on April 27, 2011, which was subsequently gazetted in Tunisia on October 25, 2011. We drilled and completed five wells at Bir Ben Tartar in 2011 and increased production from approximately 100 barrels of oil per day from the TT2 discovery well to 2,200 - 2,400 barrels of oil per day gross from six of seven wells by year end.
Late in December, we announced that we signed a farmout agreement with a wholly-owned subsidiary of New Zealand Oil and Gas Ltd., NZOG Hammamet Pty. Limited ("NZOG"), whereby NZOG will participate in the development of the offshore Cosmos concession. Under the terms of the farmout agreement, NZOG paid US$3 million to acquire an undivided 40% participating interest in the Cosmos concession. Subject to a positive final investment decision ("FID") to proceed with the development of the concession after the detailed engineering and costing has been completed, NZOG would pay 100% of our share of development costs up to US$19 million (in addition to its own share). Subject to a positive FID, it is anticipated that first oil will be produced mid-2014. If there is a negative FID, NZOG will re-assign its interest in the concession to us for nominal consideration.
2011 RESERVES
Canadian proved plus probable finding and development costs, as calculated under NI 51-101 averaged $41.80 per barrel of oil equivalent for a recycle rate of 0.4 times. For Canada, reserve additions through drilling replaced 1.1 times the 2011 production. Canadian proved plus probable reserves decreased 15 percent as we sold assets representing nine percent of opening reserves and also experienced downward economic and technical revisions of seven percent of opening reserves largely in natural gas reserves in response to lower prices and higher operating expenses. Liquids by percent of total barrels of oil equivalent reserves increased to 34 percent from 33 percent. Proved reserves represent 65 percent of total reserves and proved undeveloped reserves represent only four percent of our Canadian reserves. Our corporate net asset value after tax discounted at 10 percent is $3.61 per basic share with $1.75 per basic share (or 48%) represented by proved reserves in Canada.
We have been trading recently at roughly 41 percent of our after tax net asset value per basic share while at the same time we were able to sell Canadian assets representing seven percent of our year end 2010 reserves at 110 percent of their engineered reserve value with total proceeds approaching 25 percent of our market capitalization. In 2011, we sold properties with year end 2010 reserves of 4.2 million barrels of oil equivalent and January 1, 2011 production of 1,325 barrels of oil equivalent per day (70 percent natural gas) for net proceeds of $83.8 million over a total of 15 transactions. The average per dollar flowing barrel of oil metric achieved through these sales of $63,200 represents good value when compared with industry average metrics for 2011 of $36,411 per barrel of oil equivalent for natural gas weighted deals and our enterprise value per flowing barrel of oil equivalent at year end of approximately $31,000 per barrel of oil equivalent. The reality of these results is our Canadian assets have considerably more value than attributed by the enterprise value of our stock and debt. We are targeting the sale of an additional 1,000 barrels of oil equivalent per day of non-core assets in 2012 that have some combination of limited growth potential, limited scale, limited control or higher than average costs or liabilities. These assets are not part of our planned future growth and we are monetizing the value to improve our balance sheet and allow us to internally finance growth in our core areas through drilling or acquisition. Subsequent to year end we have announced the sale of a package of small unit interests and our Manyberries property, with combined year end 2011 production of 845 barrels of oil equivalent per day (27 percent gas), for proceeds of $56 million, before closing adjustments.
Tunisian finding and development costs were $107.10 per barrel of oil equivalent, supporting a recycle rate of 0.8 times. In Tunisia, finding and development costs and the resulting recycle ratio were skewed by our 2011 capital program focusing on the development areas that had proved plus probable reserves assigned to them at year end 2010 and the inclusion of increased future development costs related to major facility construction associated with the building of the planned oil sales pipeline. During 2012, we will ensure more of the probable and possible reserve areas, and the exploration opportunities are evaluated which will see us test at least one new exploration feature at Sud Remada and two at Borj El Khadra.
Proved, producing and probable reserves assigned to the Bir Ben Tartar wells at year end 2011 averaged 300,000 barrels of oil per well. Total reserves assigned on a proved plus probable basis at Sud Remada were essentially flat, net of production, at 3.4 million barrels as a result of the wells evaluated being assigned reserves based on spacing units and pay columns encountered in the later wells which were thinner than the earlier wells on which the previous forecast was based. The estimate of Discovered Petroleum Initially-in-Place ("DPIIP") dropped with the thinner pays encountered, to 153.7 million barrels and total recoverable inclusive of contingent resource in a best estimate case, net to our 39% contractor share, is 12.2 million barrels. When looking at the future development of the block it is important to note that at present only 28 percent of the potential reserve upside quantified as proved plus probable, possible and contingent is currently booked. The economics of the Tunisian operations are strong. Crude oil from Bir Ben Tartar is trucked to a coastal terminal facility at La Skhira where we are able to sell the crude at Brent prices as a result of the quality of the oil and receive payment in US dollars. In addition to the positive operating netbacks, the present value per barrel of oil equivalent under the terms of our production sharing contract exceeds $41 per barrel, using an after tax present value discounted at 10 percent. We plan to drill 11 development wells, six of which are planned to be horizontal and will commence the construction of the facility and sales pipeline projects once we exceed 5,000 barrels of oil per day gross from the project. It is anticipated that this could be as early as summer or early fall of 2012. We will also drill the first of seven remaining seismically identified undrilled structures on the Sud Remada permit at BJA.
OUTLOOK
Catalysts to recognizing increased value that we will be focused on delivering over the first half of 2012 include drilling results from the Sud Remada exploration well, an initial Bir Ben Tartar horizontal development well, drilling and completion results from our Dunvegan and Montney oil horizontal tests and securing a floating production storage and offtake vessel ("FPSO") contract for Cosmos.
Our crystal ball prediction of recovering natural gas prices by early 2012, which was made in last year's report, looks unlikely to materialize as North American production continues to grow, storage remains well above average and spot prices sink below $2.00 per thousand cubic feet. We started our budgeting for 2012 with an estimate of $3.75 for AECO gas last November and have since lowered our forecast average price to $2.70 per thousand cubic feet. We have shut in approximately 2.5 million cubic feet per day of dry natural gas production in northeast Alberta during the first quarter of 2012 in response to low prices received on properties with high operating expenses. Fortunately, on average, we have a strong contribution to the short term viability of our natural gas assets from the natural gas liquids recovered. During 2011, we averaged 28 barrels of natural gas liquids recovery per million cubic feet of natural gas production with an average liquid price equal to 70 percent of the Edmonton light crude oil reference price. Average liquids recoveries clearly drive the economics of natural gas production in the current market and the liquids prices can vary from approximately 52 percent of the crude price for C3 (propane) to 103 percent for condensates (C5+). At a $2.50 per thousand cubic feet natural gas price, $95.00 reference crude price and our natural gas liquid pricing staying consistent at 70 percent, over 43 percent of the revenue from gas production would be derived from the associated natural gas liquids and inclusive of the value of the liquids our total revenue from natural gas would be $4.36 per thousand cubic feet.
For 2012, our budgeted production is 13,500 - 14,000 barrels of oil equivalent per day (net of planned asset sales) comprised of 36 percent oil, nine percent natural gas liquids and 55 percent natural gas with Tunisia comprising 18 percent on a total barrel of oil equivalent per day basis. Revenue is budgeted at $245 - 255 million which is made up of 71 percent oil, 11 percent natural gas liquids and 18 percent natural gas with Tunisia comprising 35 percent of total revenue. Production revenue for 2012 will be negatively impacted by a much lower natural gas price but positively impacted by increasing crude oil volumes priced off Brent. Brent prices have traded at a $10 - $20 premium to West Texas Intermediate ("WTI") over the year and our Tunisian crude has averaged 98 percent of dated Brent prices. Canadian crude has started to see a discount to WTI of as much as $20 per barrel due to pipeline capacity constraints which suggest a Brent premium could reach 40 percent on a per barrel basis. Cash flow is estimated to be $120 - 125 million with 57 percent coming from Tunisia and 43 percent from Canada. Capital expenditures are estimated to be $165 million with 58 percent invested in Tunisia and 42 percent invested in Canada. Year end debt is estimated to be $120 - 125 million. Currently we are drawn at $101.5 million on the $186 million credit facility and intend to be drawn at $80 million upon completion of the disposition of the unit interests, prior to factoring in the capital expenditure program for the first quarter, as the proceeds of the sale will be put toward reducing the debt and strengthening the balance sheet.
We anticipate being able to demonstrate the continued commerciality of our Tunisian light oil asset with increasing volumes which will increase revenue and profitability given the current oil price environment. We will continue to focus on improving the profitability and cost structure of our Canadian assets through a focus on oil projects. In addition, we will continue with our sale of non-core assets which have confirmed the underlying value of the Canadian assets but expect that the activity level will not match the level of sales in 2011.
Alberta Oil Sands - Exploitable Bitumen in Place
Further to our news release on February 26, 2012, the following summary of our updated Contingent Bitumen Resources as evaluated by McDaniel & Associates Consultants Ltd. ("McDaniel") in respect of our 74.55% working interest in our oil sands leases in the Portage and Thornbury areas of Alberta. McDaniel's evaluation was prepared based on the resource being exploited using steam assisted gravity drainage. There is no certainty that it will be commercially viable to produce any portion of the resources and there is no guarantee that the estimated resources or any resources will be recovered. The size of the resource estimate could be positively or negatively impacted if the size, quality, and/or thickness of the reservoir is different than what is currently estimated. Actual resources may be greater than or less than the estimates provided herein.
Contingent Resources can be further sub-classified as economic and sub-economic and are affected by a number of factors such as capital costs, timing, price forecasts and other considerations. In both Portage and Thornbury, the Low Estimates of Contingent Resources are sub-economic while the Best and High Estimates of Contingent Resources are economic. The contingencies which currently prevent the classification of the Contingent Resources disclosed in the tables below as reserves consist of: further reservoir studies, delineation drilling, facility design, preparation of firm development plans, regulatory applications and corporate approvals. There is no certainty that it will be commercially viable for us to produce any portion of the Contingent Resources on any of our properties. The most significant positive and negative factors with respect to the Contingent Resource estimates relates to the fact that property is currently at an evaluation/delineation stage.
The information provided hereunder for Portage and Thornbury is based on an evaluation conducted by McDaniel effective December 31, 2011 using January 1, 2012 forecast prices and costs. McDaniel carried out the evaluations in accordance with standards established by the Canadian Securities Administrators in NI 51-101.
| Thornbury Oil Sands | |||||||
| Gross | |||||||
| Discovered | Economic | Gross | |||||
| Exploitable | Contingent Resources | Sub-economic | |||||
| Category / Level of | Bitumen In Place (1) | (2) | Contingent Resources (2) | ||||
| Certainty(3)(4)(5) | (Mbbl) | (Mbbl) | (Mbbl) | ||||
| High | 110,708 | 55,717 | - | ||||
| Best | 92,451 | 34,505 | - | ||||
| Low | 73,956 | - | 22,987 | ||||
| Portage Oil Sands | |||||||
| Gross | |||||||
| Discovered | Economic | Gross | |||||
| Exploitable | Contingent Resources | Subeconomic | |||||
| Category / Level of | Bitumen In Place (1) | (2) | Contingent Resources (2) | ||||
| Certainty (3)(4)(5) | (Mbbl) | (Mbbl) | (Mbbl) | ||||
| High | 279,531 | 123,677 | - | ||||
| Best | 211,273 | 78,825 | - | ||||
| Low | 171,437 | - | 55,253 | ||||
| Portage and Thornbury Oil Sands | |||||||
| Gross | |||||||
| Discovered | Economic | Gross | |||||
| Exploitable | Contingent Resources | Subeconomic | |||||
| Category / Level of | Bitumen In Place (1) | (2) | Contingent Resources (2) | ||||
| Certainty(3)(4)(5) | (Mbbl) | (Mbbl) | (Mbbl) | ||||
| High | 390,240 | 179,395 | - | ||||
| Best | 303,724 | 113,330 | - | ||||
| Low | 245,392 | - | 78,240 | ||||
| Notes: | ||
| (1) | Discovered Exploitable Bitumen in Place is the estimated volume of bitumen, as of a given date, which is contained in a subsurface stratigraphic interval of a known accumulation that meets or exceeds certain reservoir characteristics, such as minimum continuous net pay, porosity, and mass bitumen content, considered necessary for the commercial application of known recovery technologies. There is no certainty that it will be commercially viable to produce any portion of the resources. | |
| (2) | Contingent Resources are defined in the COGE Handbook as those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies. Contingencies may include factors such as economic, legal, environmental, political and regulatory matters or a lack of markets. It is also appropriate to classify as "Contingent Resources" the estimated discoverable quantities as associated with a project in the early evaluation stage. Contingent Resources are further classified in accordance with the level of certainty associated with the estimates and may be sub-classified based on project maturity and/or characterized by their economic status. | |
| (3) | Low Estimate: This is considered to be a conservative estimate of the quantity that will actually be recovered. It is likely that the actual remaining quantities recovered will exceed the low estimate. If probabilistic methods are used, there should be at least a 90 percent probability (P90) that the quantities actually recovered will equal or exceed the low estimate. | |
| (4) | Best Estimate: This is considered to be the best estimate of the quantity that will actually be recovered. It is equally likely that the actual remaining quantities recovered will be greater or less than the best estimate. If probabilistic methods are used, there should be at least a 50 percent probability (P50) that the quantities actually recovered will equal or exceed the best estimate. | |
| (5) | High Estimate: This is considered to be an optimistic estimate of the quantity that will actually be recovered. It is unlikely that the actual remaining quantities will exceed the high estimate. If probabilistic methods are used, there should be at least a 10 percent probability (P10) that the quantities actually recovered will equal or exceed the high estimate. |
About Chinook Energy Inc.
Chinook is a Calgary-based public oil and gas exploration and development company that combines high quality natural gas-weighted assets in Western Canada with an exciting high growth oil business onshore and offshore Tunisia in North Africa.
Definitions of Oil and Gas Resources and Reserves
Reserves are estimated remaining quantities of oil and natural gas and related substance anticipated to be recoverable from known accumulations, as of a given date, based on the analysis of drilling, geological, geophysical and engineering data; the use of established technology, and specified economic conditions, which are generally accepted as being reasonable. Reserves are classified according to the degree of certainty associated with the estimates as follows:
Proved Reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves.
Probable Reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves.
Possible Reserves are those additional reserves that are less certain to be recovered than probable reserves. It is unlikely that the actual remaining quantities recovered will exceed the sum of the estimated proved plus probable plus possible reserves. There is 10% probability that the quantities recovered will exceed the sum of proved and probable reserves.
Resources encompasses all petroleum quantities that originally existed on or within the earth's crust in naturally occurring accumulations, including Discovered and Undiscovered (recoverable and unrecoverable) plus quantities already produced. "Total resources" is equivalent to "Total Petroleum Initially-In-Place". Resources are classified in the following categories:
Discovered Petroleum Initially-In-Place ("DPIIP") is 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.
Contingent Resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development but which are not currently considered to be commercially recoverable due to one or more contingencies.
Unrecoverable is that portion of DPIIP and UPIIP quantities which is estimated, as of a given date, not to be recoverable by future development projects. A portion of these quantities may become recoverable in the future as commercial circumstances change or technological developments occur; the remaining portion may never be recovered due to the physical/chemical constraints represented by subsurface interaction of fluids and reservoir rocks.
Reader Advisory
Forward-Looking Statements
In the interest of providing shareholders and potential investors with information regarding Chinook, including management's assessment of the future plans and operations of Chinook, 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 addition, statements relating to "reserves" are deemed to be forward-looking statements as they involve the implied assessment, based on certain estimates and assumptions, that the reserves described exist in the quantities predicted or estimated and can be profitably produced in the future. In particular, this news release contains, without limitation, forward-looking statements pertaining to: the volumes and estimated value of Chinook's oil and natural gas reserves; the volume and product mix of Chinook's oil and natural gas production; future expectations of oil and natural gas prices; future results from operations and operating metrics; and future development, exploration, acquisition and development activities (including drilling plans) and related production expectations as well as management's future expectations set out under the heading "Outlook".
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 exploration and development activities, the impact of increasing competition, the ability of Chinook to add production and reserves through development and exploitation activities, certain commodity price and other cost assumptions, the continued availability of adequate debt and equity financing and cash flow to fund its planned expenditures. 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, the continued impact of shut-in production, 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. 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.
Operating Netback
The reader is also cautioned that this news release contains the term operating netback, which is not a recognized measure under GAAP and is calculated as a period's sales of petroleum and natural gas, net of royalties less net production and operating expenses as divided by the period's sales volumes. Management uses this measure to assist them in understanding Chinook's profitability relative to current commodity prices and it provides an analysis tool to benchmark changes in operational performance against prior periods and to peers on a comparable basis. 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 GAAP as a measure of performance. Chinook's method of calculating this measure may differ from other companies, and accordingly, they may not be comparable to measures used by other companies.
Cash flow from operations
The reader is also cautioned that this news release contains the term cash flow from operations, which is not a recognized measure under GAAP and is calculated as cash flow from continuing operations adjusted for changes in non-cash working capital. Management believes that cash flow is a key measure to assess the ability of Chinook to finance capital expenditures and debt repayments. Readers are cautioned, however, that this measure should not be construed as an alternative to other terms such as cash flow from operating activities, net income or other measures of financial performance calculated in accordance with GAAP. Chinook's method of calculating this measure may differ from other companies, and accordingly, they may not be comparable to measures used by other companies.
Contact Information:
Matthew Brister
President and Chief Executive Officer
(403) 261-6883
Chinook Energy Inc.
L. Geoff Barlow
Vice-President, Finance and Chief Financial Officer
(403) 261-6883
www.chinookenergyinc.com