Pengrowth Energy Corporation

Pengrowth Energy Corporation

February 28, 2012 16:41 ET

Pengrowth Energy Corporation Full Year 2011 Results

CALGARY, ALBERTA--(Marketwire - Feb. 28, 2012) - Pengrowth Energy Corporation (TSX:PGF) (NYSE:PGH) is pleased to report our full year operating and audited financial results for the year ended December 31, 2011. All figures are in Canadian dollars unless otherwise stated.

Our audited financial statements for the year ended December 31, 2011 and related Management's Discussion and Analysis can be accessed immediately on our website at, and have been filed on SEDAR at and Form 40-F on EDGAR at Hard copies of our complete audited financial statements can also be requested free of charge by calling 1-888-744-1111, emailing or requesting copies through


  • Fourth quarter 2011 production averaged 76,691 barrels of oil equivalent per day (boepd), representing an increase of three percent and two percent, respectively, compared to the third quarter of 2011 and fourth quarter of 2010 average production.
  • Production volumes for 2011 were at the high end of guidance at 73,973 boepd, and were essentially flat year-over-year, despite a very challenging start to the year. 2011 exit production volumes were on target at 76,789 boepd.
  • In the fourth quarter of 2011, our Adjusted Net Income was $22.3 million as compared to $40.7 million in the fourth quarter of 2010. The $18.4 million decrease was due primarily to an impairment charge on our Groundbirch assets of $20.4 million net of deferred tax and a higher deferred tax expense of $25.5 million as a result of our conversion from a Trust. These items offset an increase in Funds Flow from Operations of $31.2 million.
  • Adjusted Net Income for the full year of 2011 was $97.5 million lower than the same period in 2010 mainly as a result of the previously described impairment charge of $20.4 million net of deferred tax, and a $77.6 million increase to our deferred income tax expense as a result of our conversion from a Trust. A $6.2 million reduction in Funds Flow from Operations also contributed to the decrease.
  • Reserve additions from internal capital development activities and technical revisions replaced 145 percent of annual production, adding approximately 39.3 million barrels of oil equivalent (MMboe) of additional proved plus probable (2P) reserves. 2P reserves increased by 3.8 percent to total 330.5 MMboe with proved reserves accounting for 71 percent of total 2P reserves.
  • Annual finding, development and acquisition (FD&A) costs of $20.04 per boe for 2P reserves and $20.84 per boe for proved reserves, including changes in future development capital (FDC) ($15.23 per boe and $14.56 per boe, respectively, excluding changes in FDC).
  • Construction was completed on our Lindbergh Steam Assisted Gravity Drainage (SAGD) pilot project on-budget and on-time and steam injection was initiated successfully in early February 2012.
  • Lindbergh SAGD pilot results will be monitored over the coming months with the objective of having GLJ Petroleum Consultants Ltd (GLJ) provide a reserves update in the third quarter of 2012.
  • A $282 million capital program at our Swan Hills property resulted in a production increase of approximately 4,000 boepd year-over-year. At year-end, a total of 12 additional wells, drilled in both the third and fourth quarters, were still waiting to be brought on production.
  • Oil and gas revenues increased to $1.45 billion for the full-year and $389 million for the fourth quarter of 2011, representing increases of six percent and 13 percent, respectively, over the same periods in 2010.
  • We maintained our financial flexibility at year-end 2011, with our $1.25 billion credit facility being essentially undrawn.
  • In November 2011, we announced that we had closed an offering of our common shares which resulted in gross proceeds of approximately Cdn$300 million. The net proceeds from the offering were used to partially fund our 2011 and 2012 capital programs.
  • Our year-end debt-to-earnings before interest, depreciation and amortization remained constant at 1.6 times.
  • Our $625 million 2012 capital program is 100 percent focused on oil and liquids rich gas projects with recycle ratios in excess of 2.0 times, which are expected to result in an increase to the liquids percentage of our production from 51 to 54 percent.
  • Full year 2012 production guidance is between 74,500 and 76,500 boepd with an exit rate of approximately 78,000 boepd, a two percent increase from our 2011 exit rate.

Summary of Financial & Operating Results

Certain comparative figures have changed due to International Financial Reporting Standards and to conform to current presentation.

(monetary amounts in millions, except Three months ended Twelve months ended
per share amounts or as otherwise stated) Dec 31, 2011 Dec 31, 2010 % Change Dec 31, 2011 Dec 31, 2010 % Change
Oil and gas sales(1) $ 389.2 $ 344.9 13 $ 1,453.7 $ 1,368.7 6
Adjusted Net Income $ 22.3 $ 40.7 (45 ) $ 110.9 $ 208.4 (47 )
Net (loss) income $ (9.0 ) $ (152.0 ) (94 ) $ 84.5 $ 149.8 (44 )
Net (loss) income per share $ (0.03 ) $ (0.47 ) (94 ) $ 0.25 $ 0.50 (50 )
Funds flow from operations (1) $ 171.1 $ 139.9 22 $ 620.0 $ 626.2 (1 )
Funds flow from operations per share (1) $ 0.50 $ 0.44 14 $ 1.87 $ 2.09 (11 )
Net capital expenditures (2) $ 142.1 $ 130.9 9 $ 609.1 $ 333.8 82
Net capital expenditures per share $ 0.41 $ 0.41 - $ 1.83 $ 1.11 65
Dividends paid $ 71.4 $ 67.4 6 $ 277.5 $ 250.6 11
Dividends paid per share $ 0.21 $ 0.21 - $ 0.84 $ 0.84 -
Weighted average number of shares outstanding (000's) 345,163 321,319 7 332,182 299,763 11
Working capital deficiency (1) $ (137.3 ) $ (109.2 ) 26
Property, plant and equipment $ 4,074.4 $ 3,738.0 9
Exploration and evaluation assets $ 563.8 $ 511.6 10
Long term debt $ 1,007.7 $ 1,024.4 (2 )
Shareholders' equity (1) $ 3,347.3 $ 3,182.3 5
Shareholders' equity per share $ 9.29 $ 9.76 (5 )
Currency ($ Cdn = $1 U.S.) (closing rate at period end) $ 0.9833 $ 1.0054
Number of shares outstanding at period end (000's) 360,282 326,024 11
Light oil (bbls) 22,935 21,762 5 21,455 21,743 (1 )
Heavy oil (bbls) 6,448 6,673 (3 ) 6,425 6,789 (5 )
Natural gas liquids (bbls) 10,478 10,177 3 9,659 9,611 1
Natural gas (Mcf) 220,977 218,044 1 218,601 219,302 -
Total production (boe) 76,691 74,953 2 73,973 74,693 (1 )
TOTAL ANNUAL PRODUCTION (Mboe) 7,056 6,896 2 27,000 27,263 (1 )
AVERAGE REALIZED PRICES (after commodity risk management)
Light oil (per bbl) (1) $ 91.58 $ 76.13 20 $ 89.94 $ 76.22 18
Heavy oil (per bbl) $ 76.13 $ 60.42 26 $ 68.24 $ 60.22 13
Natural gas liquids (per bbl) $ 70.54 $ 56.74 24 $ 69.31 $ 56.99 22
Natural gas (per Mcf) $ 3.77 $ 4.87 (23 ) $ 4.08 $ 5.00 (18 )
Average realized price per boe (1) $ 54.28 $ 49.34 10 $ 53.13 $ 49.68 7
Light oil 54 % 45 % 53 % 45 %
Heavy oil 14 % 12 % 12 % 11 %
Natural gas liquids 20 % 16 % 17 % 14 %
Natural gas 12 % 27 % 18 % 30 %

(1) Prior periods restated to conform to presentation in the current period.

(2) Net capital expenditures includes Drilling Royalty Credits and capitalized stock based compensation.

(3) Balance Sheet amounts are at period end.

Reserves Information

GLJ conducted an independent evaluation of reserves and contingent resources effective December 31, 2011. For further information on our December 31, 2011 reserves, please see our 2011 Year End Reserves news release dated February 28, 2012 and our Annual Information Form dated February 28, 2012 which are available at, and which have been filed on Form 40-F on EDGAR at and on SEDAR at


Daily production for 2011 averaged 73,973 boepd, down one percent from our average of 74,693 boepd in 2010. Production was impacted by forest fires and flooding in northern Alberta during the first half of the year, but recovered in the latter half of the year with fourth quarter production increasing to 76,691 boepd. Fourth quarter volumes were positively impacted by production being brought on from completion activities at Swan Hills.

Our 2012 guidance for daily production volumes is between 74,500 and 76,500 boepd, with anticipated exit production of approximately 78,000 boepd. Volumes from the Lindbergh pilot project, which are expected to reach 1,000 barrels of oil per day (bopd) by year-end, have not been included in our 2012 full year guidance estimate nor our 2012 exit guidance.

Oil and Gas Revenues

Full year 2011 oil and gas revenues increased by six percent to $1.45 billion compared to $1.37 billion for the full-year of 2010 and by 13 percent to $389 million in the fourth quarter of 2011, compared to $345 million for the fourth quarter of 2010. Revenues from oil and liquids sales increased to 77 percent of total sales in 2011, up from 70 percent in 2010, while accounting for only 51 percent of production volumes in 2011. Higher prices for oil and liquids helped offset the weaker natural gas prices experienced throughout 2011, even after benefitting from favourable gas commodity risk management contracts. Our operated 2012 drilling and completions program is focused entirely on oil and liquids-rich gas projects.

Realized Commodity Prices

Our average realized price per boe in 2011, including realized risk management activities, increased seven percent to $53.13 per boe versus $49.68 per boe in 2010. The increase in realized prices year-over-year is primarily a result of higher benchmark prices for crude oil offset by lower natural gas prices and lower natural gas hedge volumes. Our full year operating netbacks increased six percent to $28.45 per boe compared to $26.92 per boe in 2010. Fourth quarter 2011 combined operating netbacks increased by 20 percent to $29.99 per boe compared to an average fourth quarter of 2010 netback of $25.02 per boe. The increase is mainly a result of higher oil and liquids prices, which made up 51 percent of our total production in 2011. In 2012, liquids as a percentage of production are expected to increase from 51 percent to 54 percent.

Funds Flow from Operations

Funds Flow from Operations was approximately $171 million ($0.50 per share) in the fourth quarter of 2011. This represents an increase of 14 percent and 22 percent, respectively, compared to the third quarter of 2011 at $150 million ($0.46 per share) and fourth quarter of 2010 at $140 million ($0.44 per share). The increase in funds flow from operations compared to the earlier periods is primarily a result of higher production volumes and higher realized prices for oil and liquids, resulting in higher netbacks.

Operating Expenses

Operating expenses of approximately $100 million ($14.13 per boe) in the fourth quarter of 2011 were essentially unchanged from the third quarter expenses of $100 million. Operating expenses on a dollar per boe basis in the fourth quarter were approximately two percent lower due to higher production volumes in the fourth quarter. Comparing net operating expenses in the fourth quarter of 2011 to the fourth quarter of 2010, they were down five percent in aggregate and seven percent on a per boe basis, primarily due to lower sub-surface and maintenance costs and higher production volumes in the fourth quarter of 2011.

Full year 2011 net operating expenses were $382 million or $14.15 per boe compared to $357 million or $13.10 per boe in 2010. Approximately two-thirds of the increase in costs year-over- year resulted from higher power prices throughout 2011. In addition, increased road, lease and right-of-way maintenance attributable to flooding and extreme wet weather conditions, as well as increased subsurface maintenance and optimization, contributed to higher 2011 operating expenses.

Development Capital

Our 2011 total capital spending totalled $612 million compared to $358 million in 2010, excluding net acquisitions and before deducting Alberta Drilling Royalty Credits. Approximately 87 percent of 2011 capital was spent on drilling, completions and facilities work targeted at oil and liquids-rich gas projects, while participating in the drilling of 241 gross (123 net) wells in 2011, 70 (48 net) of which were drilled in the Swan Hills area.

Swan Hills

Total development capital of approximately $282 million was spent at Swan Hills in 2011, resulting in the addition of approximately 4,000 boepd.

In the fourth quarter of 2011, $65 million was spent at Swan Hills to drill 16 gross (10.5 net) operated wells. 11 gross (10.3 net) wells, drilled prior to the quarter, were also tied-in and brought on production. Average five day initial production (IP) rates for new wells brought on production was approximately 700 boepd. At year-end, a total of 12 additional wells were still waiting to be brought on production and we had two rigs drilling in the Swan Hills area. We anticipate that a multi-rig drilling program will continue in the area throughout 2012.


At Lindbergh, construction was completed on our SAGD pilot project on-budget and on-time, with steam injection initiated in early February. The Environmental Protection and Enhancement Act (EPEA) application for the first phase of the 12,500 bopd commercial project was submitted to the Energy Resources Conservation Board (ERCB) and Alberta Environment at the end of December, and up to three core-hole rigs were drilling in December, with ten core- holes completed as part of the continuing resource assessment and validation in the Lindbergh area.

We will monitor and analyze SAGD pilot results over the next several months with the objective of having GLJ provide a material reserves update late in the third quarter of 2012.


In the Olds area, throughout 2011 we continued with the liquids-rich Elkton gas program, drilling three wells and tying-in a fourth well drilled late in 2010. These four wells had average 30 day IP rates of 480 boepd, consisting of 2.2 MMcf per day (MMcfpd) of gas and 110 bbl per day (bblpd) of natural gas liquids (NGL). The positive results from the Elkton liquids-rich gas wells have provided additional drilling locations for 2012. A new liquids-rich gas play concept was tested in the third quarter with the drilling and completion of a Mannville gas well. The well was tied-in early in the fourth quarter and had a 30 day IP rate in excess of 500 boepd, consisting of approximately 1.9 MMcfpd of gas and 190 bblpd of NGL.

2012 Capital Program

In late January 2012, we announced a $625 million capital program with 100 percent of the operated drilling and completions component of the program being targeted toward oil and liquids-rich gas projects. Building on the successes achieved in 2011, the 2012 capital program will focus on the development of oil and liquids-rich gas plays in three key areas: Swan Hills light oil, the Lindbergh SAGD project, and Olds area liquids-rich gas. These operated projects have recycle ratios in excess of 2.3 times and are expected to result in an increase in the liquids percentage of our production from 51 percent to 54 percent, and overall production growth of two percent in 2012.

Our 2012 production guidance is expected to be between 74,500 and 76,500 boepd, with an anticipated exit production of approximately 78,000 boepd. Volumes from the Lindbergh pilot project, which are expected to reach 1,000 bopd by year-end, have not been included in our 2012 full year guidance estimate nor our 2012 exit guidance. Approximately $136 million of the 2012 capital program will be allocated to projects and maintenance activities, including Lindbergh and Bodo, which are not expected to contribute to production volumes in 2012 but which are expected to yield production growth in 2013 and beyond.

2012 Full-Year Guidance Summary

Average daily production volume (boepd) 74,500 - 76,500 (1)
Total Capital Expenditures ($ millions) $625
Net Operating costs (per boe) $13.89(2)
General and Administrative costs (per boe) $2.68(2)
(1) The 2012 guidance excludes potential acquisitions or dispositions
(2) Assumes mid-point of production guidance

Investor Days

We are pleased to announce that we will host Investor Days in both Calgary and Toronto on February 29, 2012 and March 1, 2012, respectively, during which management will provide an update to our investor community on our corporate strategy and development plans for 2012. The Calgary Investor Day will be held at Livingston Place Conference Centre located at 222, Third Ave. SW, Calgary, Alberta beginning at 10:00 A.M. Mountain Standard Time (MST) and the Toronto Investor Day will be held at One King West Hotel & Residence located at 1 King Street West, Toronto, Ontario beginning at 10:00 A.M. Eastern Standard Time (EST).

A live webcast of the Calgary Investor Day Presentation will be available to the general public beginning at 10:00 A.M. MST on Wednesday, February 29, 2012. The live presentation and question and answer period is expected to last approximately three hours.

To participate in the webcast, participants may register by visiting The webcast will also be archived and available on our website at

The webcast portion of the presentation will be listen-only, however listeners are encouraged to follow-up with our investor relations department should they have additional questions.

Annual General Meeting

We are also pleased to announce that our 2012 Annual Meeting of shareholders will be held on May 2, 2012 at 3:00 P.M. Mountain Daylight Time (MDT) in the Glen 206 room of the TELUS Convention Centre located at 120 Ninth Avenue SE, Calgary, Alberta. Information circulars and proxy forms pertaining to this meeting are expected to be mailed out to shareholders of record as of March 26, 2012, in late March.

About Pengrowth:

Pengrowth Energy Corporation is a dividend-paying, intermediate Canadian producer of oil and natural gas, headquartered in Calgary, Alberta. Pengrowth's focus is on the development of conventional and unconventional resource-style plays in the Western Canadian Sedimentary Basin. Pengrowth's projects include the Swan Hills (light oil) play in north-central Alberta, the Olds (light oil/gas) play in south-central Alberta, the Lindbergh (Steam Assisted Gravity Drainage) project in east-central Alberta, the Bodo (EOR polymer) play in east-central Alberta and the Groundbirch (Montney gas) play in north-eastern British Columbia. Pengrowth's shares trade on both the Toronto Stock Exchange under the symbol "PGF" and on the New York Stock Exchange under the symbol "PGH".


Derek Evans, President and Chief Executive Officer

Advisory Regarding Reserves and Production Information

All amounts are stated in Canadian dollars unless otherwise specified. All reserves, reserve life index, and production information herein is based upon Pengrowth's company interest (Pengrowth's working interest share of reserves or production plus Pengrowth's royalty interest, being Pengrowth's interest in production and payment that is based on the gross production at the wellhead), before royalties and using GLJ Petroleum Consultants Ltd.'s December 31, 2011 forecast prices and costs as disclosed herein.

Caution Regarding Engineering Terms

When used herein, the term "boe" means barrels of oil equivalent on the basis of one boe being equal to one barrel of oil or NGLs or 6,000 cubic feet of natural gas (6 Mcf: 1 bbl). Barrels of oil equivalent may be misleading, particularly if used in isolation. A conversion ratio of six Mcf of natural gas to one bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. In addition, given that the value ratio based on the current price of crude oil as compared to the current price of 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.

The estimates of reserves and future net revenue for individual properties may not reflect the same confidence level as estimates of reserves and future net revenue for all properties, due to the effects of aggregation.

In addition, Pengrowth uses the following frequently-recurring industry terms in this press release: "bbls" refers to barrels, "Mbbls" refers to a thousand barrels, "MMbbls" refers to a million barrels, "Mboe" refers to a thousand barrels of oil equivalent, "MMboe" refers to a million barrels of oil equivalent, "Mcf" refers to thousand cubic feet, "MMcf" refers to million cubic feet, and "Bcf" refers to billion cubic feet.

Caution Regarding Well Test Results

This news release makes references to well test results for certain properties. These results are not necessarily representative of long-term well performance or ultimate recoveries and are subject to various performance factors including geological formation, duration of test, pressure and production declines. Some wells will experience immediate and significant declines in production.

Caution Regarding Forward Looking Information

This press release contains forward-looking statements within the meaning of securities laws, including the "safe harbour" provisions of Canadian securities legislation and the United States Private Securities Litigation Reform Act of 1995. Forward-looking information is often, but not always, identified by the use of words such as "anticipate", "believe", "expect", "plan", "intend", "forecast", "target", "project", "guidance", "may", "will", "should", "could", "estimate", "predict" or similar words suggesting future outcomes or language suggesting an outlook. In particular, forward-looking statements in this press release include, but are not limited to, statements with respect to; 2012 production and product mix expectations, reserves, expected capital program and focus and allocation of capital expenditures, drilling and completion plans, anticipated operating costs and general and administrative costs, the tie- in of wells, volumes from the Lindbergh pilot project, the possibility of receiving a mid-year reserves update at Lindbergh and available credit facilities. Statements relating to reserves are 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 profitably be produced in the future.

Forward-looking statements and information contained in this press release are based on Pengrowth's current beliefs as well as assumptions made by, and information currently available to, Pengrowth concerning general economic and financial market conditions; anticipated financial performance; business prospects, strategies; regulatory developments; including in respect of taxation; royalty rates and environmental protection; future capital expenditures and the timing thereof; future oil and natural gas commodity prices and differentials between light, medium and heavy oil prices; future oil and natural gas production levels; future exchange rates and interest rates; the proceeds of anticipated divestitures; the amount of future cash dividends paid by Pengrowth; the cost of expanding our property holdings; our ability to obtain labour and equipment in a timely manner to carry out development activities; our ability to market our oil and natural gas successfully to current and new customers; the impact of increasing competition; our ability to obtain financing on acceptable terms and our ability to add production and reserves through our development and exploration activities. Although management considers these assumptions to be reasonable based on information currently available to it, they may prove to be incorrect.

By their very nature, the forward-looking statements included in this press release involve inherent risks and uncertainties, both general and specific, and risks that predictions, forecasts, projections and other forward-looking statements will not be achieved. We caution readers not to place undue reliance on these statements as a number of important factors could cause the actual results to differ materially from the beliefs, plans, objectives, expectations and anticipations, estimates and intentions expressed in such forward-looking statements. These factors include, but are not limited to: the volatility of oil and gas prices; production and development costs and capital expenditures; the imprecision of reserve and resource estimates and estimates of recoverable quantities of oil, natural gas and liquids; Pengrowth's ability to replace and expand oil and gas reserves; environmental claims and liabilities; incorrect assessments of value when making acquisitions; increases in debt service charges; the loss of key personnel; the marketability of production; defaults by third party operators; unforeseen title defects; fluctuations in foreign currency and exchange rates; inadequate insurance coverage; changes in environmental or other legislation applicable to our operations, and our ability to comply with current and future environmental and other laws and regulations; actions by governmental or regulatory authorities including changes in royalty structures and programs and income tax laws or changes in tax laws and incentive programs relating to the oil and gas industry; our ability to access external sources of debt and equity capital, various risks associated with our Lindbergh SAGD project, and the implementation of greenhouse gas emissions legislation. Further information regarding these factors may be found under the heading "Risk Factors" in our most recent Annual Information Form under the heading "Business Risks" in our most recent year-end Management's Discussion and Analysis and in our most recent consolidated financial statements, management information circular, quarterly reports, material change reports and news releases. Copies of our Canadian public filings are available on SEDAR at Our U.S. public filings, including our most recent Form 40-F as supplemented by our filings on form 6-K, are available at

Readers are cautioned that the foregoing list of factors that may affect future results is not exhaustive. When relying on our forward-looking statements to make decisions with respect to Pengrowth, investors and others should carefully consider the foregoing factors and other uncertainties and potential events. Furthermore, the forward-looking statements contained in this press release are made as of the date of this press release and we do not undertake any obligation to update publicly or to revise any of the included forward-looking statements, whether as a result of new information, future events or otherwise, except as required by applicable law.

The forward-looking statements contained in this press release are expressly qualified by this cautionary statement.

Additional Information - Supplemental Non-IFRS Measures

In addition to providing measures prepared in accordance with International Financial Reporting Standards (IFRS), Pengrowth presents supplemental non-IFRS measures, Adjusted Net Income, operating netbacks and Funds Flow from Operations. These measures do not have any standardized meaning prescribed by IFRS and therefore are unlikely to be comparable to similar measures presented by other companies. These supplemental non-IFRS measures are provided to assist readers in determining Pengrowth's ability to generate cash from operations. Pengrowth believes these measures are useful in assessing operating performance and liquidity of Pengrowth's ongoing business on an overall basis.

These measures should be considered in addition to, and not as a substitute for, net income, funds flow from operating activities and other measures of financial performance and liquidity reported in accordance with IFRS.

Note to US Readers

Current SEC reporting requirements permit oil and gas companies, in their filings with the SEC, to disclose probable and possible reserves, in addition to the required disclosure of proved reserves. Under current SEC requirements, net quantities of reserves are required to be disclosed, which requires disclosure on an after royalties basis and does not include reserves relating to the interests of others. Because we are permitted to prepare our reserves information in accordance with Canadian disclosure requirements, we have included contingent resources, disclosed reserves before the deduction of royalties and interests of others and determined and disclosed our reserves and the estimated future net cash therefrom using forecast prices and costs. See "Presentation of our Reserve Information" in our most recent Annual Information Form or Form 40-F for more information.

We report our production and reserve quantities in accordance with Canadian practices and specifically in accordance with NI 51-101. These practices are different from the practices used to report production and to estimate reserves in reports and other materials filed with the SEC by companies in the United States.

We incorporate additional information with respect to production and reserves which is either not generally included or prohibited under rules of the SEC and practices in the United States. We follow the Canadian practice of reporting gross production and reserve volumes; however, we also follow the United States practice of separately reporting these volumes on a net basis (after the deduction of royalties and similar payments). We also follow the Canadian practice of using forecast prices and costs when we estimate our reserves. The SEC permits, but does not require, the disclosure of reserves based on forecast prices and costs.

We include herein estimates of proved, 2P and possible reserves, as well as contingent resources. The SEC permits, but does not require the inclusion of estimates of probable and possible reserves in filings made with it by United States oil and gas companies. The SEC does not permit the inclusion of estimates of contingent resources in reports filed with it by United States companies.

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