CALGARY, ALBERTA — (Marketwire) — 03/08/12 — Commenting on fourth quarter and year end results, Canadian Natural–s Chairman, Allan Markin stated, “In Q4/11 we drilled a record number of crude oil wells and achieved record quarterly production of over 657,000 BOE/d. We increased our barrel of oil equivalent reserves on a Company Gross proved plus probable basis by 9% to 7.54 billion barrels, replacing 390% of our 2011 production. Our vast, diverse asset base continues to grow economically and will provide value and upside to shareholders for years to come.”
John Langille, Vice-Chairman of Canadian Natural continued, “In Q4/11 we generated record cash flow from operations of approximately $2.2 billion representing an increase of 31% from Q4/10. We exited 2011 with improved balance sheet metrics, increased financial liquidity and a strengthened ability to create value for our shareholders through the development of our diverse asset base. This strong financial position contributed to the Company–s decision to increase the quarterly dividend to $0.105 per common share, an approximate 17% increase over 2010 representing the twelfth consecutive year of increases for the Company.”
Steve Laut, President of Canadian Natural concluded, “Canadian Natural–s well balanced and diverse asset base, in combination with our ability to optimize capital allocation to maximize value, sets us apart from our peers. Canadian Natural–s diverse production base allows us to withstand swings in commodity pricing and occasional production outages, while maintaining a strong balance sheet and ensuring cost effective development of our vast asset base. Although the current Horizon outage is significant for our oil sands mining area, on a company basis, the outage impacts full year production by less than 2%, highlighting the soundness of our strategy and the strength of our asset base.
The start up of Horizon is tracking to our original schedule of mid to late March and with our third Ore Preparation Plant ready for operations, we expect steady reliable production from Horizon going forward.”
QUARTERLY HIGHLIGHTS
(1) Adjusted net earnings from operations is a non-GAAP measure that the Company utilizes to evaluate its performance. The derivation of this measure is discussed in Management–s Discussion and Analysis (“MD&A”).
(2) Cash flow from operations is a non-GAAP measure that the Company considers key as it demonstrates the Company–s ability to fund capital reinvestment and debt repayment. The derivation of this measure is discussed in the MD&A.
(3) A barrel of oil equivalent (“BOE”) is derived by converting six thousand cubic feet of natural gas to one barrel of crude oil (6 Mcf:1 bbl). This conversion may be misleading, particularly if used in isolation, since the 6 Mcf:1 bbl ratio 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 comparing the value ratio using current crude oil prices relative to natural gas prices, the 6 Mcf:1 bbl conversion ratio may be misleading as an indication of value.
Fourth Quarter
– Average Q4/11 production growth over Q4/10 was driven by:
— Primary heavy crude oil production increased approximately 20%
— North America light crude oil and NGL production increased approximately 19%
— Horizon synthetic crude oil (“SCO”) production increased approximately 11%
— Pelican Lake crude oil production increased approximately 7%
– Canadian Natural (“the Company”) achieved record total crude oil and NGLs production of 444,286 bbl/d for Q4/11. Q4/11 crude oil production volumes increased 1% from Q4/10 and 10% from Q3/11 as a result of increased production from Horizon, the impact of record primary heavy crude oil and light crude oil drilling programs offset by the timing of steaming cycles in Bitumen (“thermal in situ”).
– Total natural gas production for Q4/11 was 1,280 MMcf/d. Q4/11 natural gas production volumes increased 2% over Q4/10 and Q3/11. The increase in production reflects the impact of natural gas producing properties acquired during 2011 and strong performance from the Company–s natural gas drilling program.
– Canadian Natural generated record quarterly cash flow from operations of $2.16 billion representing an increase of 31% from Q4/10 and an increase of 22% from Q3/11. The increase in cash flow from Q4/10 was primarily related to higher North America crude oil and NGL sales volumes and higher crude oil and NGL netbacks. The increase in cash flow from Q3/11 was primarily a result of increased production from Horizon.
– Adjusted net earnings from operations for Q4/11 was $972 million, compared to adjusted net earnings of $585 million in Q4/10 and $719 million in Q3/11. Changes in adjusted net earnings reflect the changes in cash flow from operations.
– The Company has finalized its Horizon coker fire business interruption insurance claim for $333 million and its property damage insurance claim for $393 million for a total of $726 million. To date, the Company has received total combined insurance proceeds of approximately $400 million, and expects to receive the remaining balance by the end of Q1/12.
Annual
– Total crude oil and NGLs production for the year averaged 389,053 bbl/d representing a decrease of 8% from 2010. Increased production from primary heavy crude oil, thermal in situ and light crude oil and NGL was more than offset by reduced production from Horizon and the Company–s international operations.
– Total natural gas production for the year averaged 1,257 MMcf/d representing an increase of 1% from 2010. The increase in production was a result of natural gas producing properties acquired in 2010 and 2011 and strong results from a modest, liquids rich drilling program offset by expected production declines. The acquired properties provide opportunities to lower operating costs and capture synergies with existing infrastructure. Canadian Natural drilled 86 net natural gas wells in 2011, a reduction of 12% from 2010 reflecting the Company–s strategic decision to allocate capital to higher return crude oil projects.
– Cash flow from operations was approximately $6.5 billion in 2011 compared to approximately $6.3 billion in 2010. The increase in cash flow was primarily a result of higher crude oil and NGL netbacks and higher North America exploration and production crude oil and NGL sales volumes offset by reduced production from Horizon.
– Adjusted net earnings from operations in 2011 increased to $2.5 billion compared to $2.4 billion in 2010. Changes in adjusted net earnings reflect the changes in cash flow from operations.
-Canadian Natural–s crude oil and natural gas reserves were reviewed and evaluated by independent qualified reserves evaluators. The following are highlights based on the Company–s gross reserves using forecast prices and costs as at December 31, 2011:
— Company Gross proved crude oil, SCO, bitumen and NGL reserves increased 8% to 4.09 billion barrels. Company Gross proved natural gas reserves increased 4% to 4.45 Tcf. Total proved reserves increased 7% to 4.83 billion BOE.
— Company Gross proved plus probable crude oil, SCO, bitumen and NGL reserves increased 10% to 6.52 billion barrels. Company Gross proved plus probable natural gas reserves increased 6% to 6.10 Tcf. Total proved plus probable reserves increased 9% to 7.54 billion BOE.
— Company Gross proved reserve additions, including acquisitions, were 437 million barrels of crude oil, SCO, bitumen and NGL and 644 billion cubic feet of natural gas for 545 million BOE. The total proved reserve replacement ratio was 249%. The total proved reserve life index is 21.4 years.
— Company Gross proved plus probable reserve additions, including acquisitions, were 722 million barrels of crude oil, bitumen, SCO and NGL and 793 billion cubic feet of natural gas for 855 million BOE. The total proved plus probable reserve replacement ratio was 390%. The total proved plus probable reserve life index is 33.3 years.
— Proved undeveloped crude oil, SCO, bitumen and NGL reserves accounted for 29% of the corporate total proved reserves and proved undeveloped natural gas reserves accounted for 4% of the corporate total proved reserves.
– Total net exploration and production reserve replacement expenditures totaled approximately $5.0 billion in 2011, including acquisitions and excluding Horizon. Horizon project capital (including capitalized interest, share-based compensation and other) totaled approximately $530 million and sustaining and turnaround capital totaled approximately $250 million.
Operational and Financial
– Primary heavy crude oil operations achieved record quarterly production in Q4/11 of approximately 111,500 bbl/d which contributed to 11% average annual production growth over 2010. Canadian Natural executed a record drilling program, drilling 783 net primary heavy crude oil wells in 2011. The Company exited December 2011 with production over 115,000 bbl/d representing an increase of approximately 19% compared to the first quarter of 2011.
– Thermal in situ production achieved 9% growth in 2011 over 2010 through the optimization of steaming techniques and the development of low cost pads at Primrose, Canadian Natural–s cyclic steam stimulation project. The Company targets to increase production by another 9% in 2012.
– Construction at the Kirby South Phase 1 project remains on cost and on schedule with first steam in targeted for late 2013. During Q4/11 drilling has been completed on the second of seven pads and has commenced on the third pad with wells confirming geological expectations.
– The application for regulatory approval for Kirby North Phase 1 was submitted in Q4/11 and the application for Grouse was submitted in Q1/12.
– At Pelican Lake, results of the world class polymer flood continue to be positive. As expected the polymer flood delivered a 15% increase in Company Gross crude oil proved reserves over 2010 as a result of optimized well configurations and injection strategies.
– SCO production at the Horizon Oil Sands averaged approximately 103,000 bbl/d in Q4/11, an 11% increase over Q4/10. Production averaged approximately 81,000 bbl/d in January 2012. On February 5, 2012 production was fully suspended for unplanned maintenance on the Fractionating Unit, with full production of SCO targeted to resume in mid to late March. Cost estimates for the repairs are expected to be approximately $35 million.
– Commissioning of the third Ore Preparation Plant (“OPP”) and associated hydro-transport unit began in late Q4/11. In January 2012 the third OPP and associated hydro-transport unit were turned over to operations for startup. The third OPP will increase production reliability and result in higher plant uptime going forward at Horizon.
– Canadian Natural–s commodity hedging program protects investment returns, ensures ongoing balance sheet strength and supports the Company–s cash flow for its capital expenditures programs. The Company has hedged approximately 40% of its forecasted 2012 crude oil volumes through a combination of puts and collars.
– Canadian Natural has increased its cash dividend on common shares for the twelfth year in a row. In 2012, the quarterly dividend on common shares will increase by approximately 17% from $0.09 to $0.105 per common share, payable April 1, 2012. The dividend increase represents a 21% Compound Annual Growth Rate (“CAGR”) since the Company first paid a dividend in 2001.
OPERATIONS REVIEW AND CAPITAL ALLOCATION
In order to facilitate efficient operations, Canadian Natural focuses its activities in core regions where it can own a substantial land base and associated infrastructure. Land inventories are maintained to enable continuous exploitation of play types and geological trends, greatly reducing overall exploration risk. By owning associated infrastructure, the Company is able to maximize utilization of its production facilities, thereby increasing control over production costs. Further, the Company maintains large project inventories and production diversification among each of the commodities it produces; light and medium crude oil, primary heavy crude oil, Pelican Lake heavy crude oil, thermal in situ (Bitumen), SCO, (herein collectively referred to as “crude oil”), natural gas and NGLs. A large diversified project portfolio enables the effective allocation of capital to higher return opportunities.
OPERATIONS REVIEW
Activity by core region
(1) Unproved land refers to a property or part of a property to which no reserves have been specifically attributed.
(2) Drilling activity includes stratigraphic test and service wells.
Drilling activity (number of wells)
North America Exploration and Production
North America natural gas
– North America natural gas production for the year averaged 1,231 MMcf/d representing an increase of 1% from 2010. The increase in production was a result of natural gas producing properties acquired in 2010 and 2011 and strong results from a modest, liquids rich drilling program offset by natural declines. The acquired properties provided opportunities to lower operating costs and capture synergies with existing infrastructure. Canadian Natural drilled 86 net natural gas wells in 2011, a reduction of 12% from 2010 reflecting the Company–s strategic decision to allocate capital to higher return crude oil projects.
– North America natural gas production for Q4/11 was 1,255 MMcf/d. Q4/11 natural gas production volumes increased 3% from Q4/10 and 2% from Q3/11. The increase in production reflects the impact of natural gas producing properties acquired during 2011 and strong performance from the Company–s natural gas drilling program.
– Septimus continues to exceed expectations. In 2011, Canadian Natural drilled 13 net wells and completed a tie-in to a deep cut gas facility to increase liquid recoveries. In 2012, the Company plans to expand the plant at Septimus to 120 MMcf/d yielding approximately 10,000 bbl/d of liquids and targets to drill 17 net wells to maximize facility utilization.
– Reflecting Canadian Natural–s responsible and flexible allocation of capital, the Company has reduced its natural gas capital expenditures for 2012 by $170 million. This reduction in capital spending will reduce natural gas production by approximately 20 MMcf/d and 460 bbl/d of liquids in 2012.
North America crude oil and NGLs
– North America crude oil and NGLs production for the year averaged 295,618 bbl/d representing an increase of 9% from 2010. The increase in production was a result of record drilling programs in primary heavy and light crude oil, optimized steam techniques and the development of new low cost pads at Primrose.
– North America crude oil and NGLs production for Q4/11 was 291,839 bbl/d. Q4/11 crude oil and NGLs production volumes increased 2% from Q4/10 and decreased 4% from Q3/11. The decrease in production from Q3/11 was primarily due to the timing of steaming cycles in thermal in situ partially offset by record quarterly production in primary heavy crude oil.
– Primary heavy crude oil operations achieved record quarterly production in Q4/11 of approximately 111,500 bbl/d which contributed to 11% average annual production growth over 2010. Canadian Natural executed a record drilling program, drilling 783 net primary heavy crude oil wells in 2011. The Company exited December 2011 with production over 115,000 bbl/d representing an increase of approximately 19% compared to the first quarter of 2011. Primary heavy crude oil continues to provide one of the highest return on capital projects in the Company–s portfolio and excellent short term growth to complement longer term projects.
– Thermal in situ production achieved 9% growth in 2011 over 2010 through the optimization of steaming techniques and the development of low cost pads at Primrose, Canadian Natural–s cyclic steam stimulation project. The Company targets to increase production by another 9% in 2012.
– Canadian Natural has a robust portfolio of steam assisted gravity drainage (“SAGD”) projects with the potential to grow thermal in situ production to approximately 480,000 bbl/d of capacity. Each project will be used as a template for the projects that follow, allowing the Company to continually refine development and optimize the performance of future projects. The Company targets to add 40,000 to 60,000 bbl/d of production every two to three years through the development of these projects.
— Construction at the Kirby South Phase 1 project remains on cost and on schedule with first steam in targeted for late 2013. Drilling has been completed on the second of seven pads and has commenced on the third pad with wells confirming geological expectations.
— The application for regulatory approval for Kirby North Phase 1 was submitted in Q4/11 and the application for Grouse was submitted in Q1/12.
— Canadian Natural has an active stratigraphic (“strat”) test well drilling program to delineate the reservoir characteristics for future projects. The Company targets to drill over 400 strat wells in 2012.
– At Pelican Lake, results of the world class polymer flood continue to be positive. As expected the polymer flood delivered a 15% increase in gross crude oil proved reserves over 2010 as a result of optimized well configurations and injection strategies.
– North America light crude oil production increased 10% in 2011 over 2010 on the back of a record drilling program. In 2012, Canadian Natural targets to drill 134 net light crude oil wells including nine new pool developments.
– Planned drilling activity for 2012 includes 159 net thermal in situ wells and 956 net crude oil wells, excluding strat test and service wells.
International Exploration and Production
– North Sea crude oil production averaged 26,769 bbl/d during Q4/11 representing a decrease of 16% compared to Q4/10 and an increase of 2% compared to Q3/11. The decrease from Q4/10 was a result of scheduled turnarounds and natural field declines.
– On December 8, 2011, the Banff floating production, storage and offloading vessel (“FPSO”) and subsea infrastructure suffered damage from severe storm conditions. The FPSO has been removed from the field and the extent of the damage including associated costs is being assessed. The resulting effect on 2012 production is approximately 3,500 bbl/d and is reflected in the Company–s updated guidance. The incident is an insurable event for both property damage and profit-based business interruption insurance.
– In 2011 the UK government implemented a tax increase in the North Sea that resulted in a 24% reduction in the UK North Sea after-tax profits. As a result the Company has curtailed much of the long term volume adding investment in the North Sea. The Company will continue to high grade all North Sea prospects for potential future development opportunities.
– Production in Offshore Africa averaged 22,726 bbl/d during Q4/11 representing a decrease of 18% compared to Q4/10 and an increase of 1% compared to Q3/11. The decrease from Q4/10 was a result of natural field declines and lower production entitlements following the payout of the Baobab Field in May 2011. Infill drilling at the Espoir Field is targeted to begin in late 2012, targeting additional production of 6,500 BOE per day at the completion of this drilling program.
North America Oil Sands Mining and Upgrading – Horizon
– SCO production at the Horizon Oil Sands averaged approximately 103,000 bbl/d in Q4/11, an 11% increase over Q4/10. Production averaged approximately 81,000 bbl/d in January 2012. On February 5, 2012 production was fully suspended for unplanned maintenance on the Fractionating Unit, with full production of SCO targeted to resume in mid to late March. Cost estimates for the repairs are expected to be approximately $35 million.
– Commissioning of the third OPP and associated hydro-transport unit began in late Q4/11. In January 2012 the third OPP and associated hydro-transport unit were turned over to operations for startup. The third OPP will increase production reliability and result in higher plant uptime going forward at Horizon.
– Horizon expansion activities continue to progress on track and are at or below cost estimates. Lump sum contracts for the Gasoil Hydrotreater, Froth Treatment and Hydrogen Plant have been awarded and will enhance cost certainty going forward.
MARKETING
(1) West Texas Intermediate (“WTI”).
(2) Synthetic crude oil (“SCO”).
(3) Excludes SCO.
– In Q4/11, WTI pricing increased by 5% from Q3/11 partially due to the announcement of the Seaway pipeline reversal from Cushing, Oklahoma to the US Gulf Coast where a large concentration of heavy crude oil refineries exist, offset by the relative strengthening of the US dollar.
– The Western Canadian Select (“WCS”) heavy crude oil differential as a percent of WTI averaged 11% in Q4/11. The WCS heavy differential narrowed in Q4/11 from Q3/11 as a result of increased heavy crude oil conversion capacity from key refineries in Petroleum Administration for Defence Districts II (“PADD II”).
– In 2011, the Company contributed approximately 162,000 bbl/d of its heavy crude oil streams to the WCS blend. Canadian Natural is the largest contributor accounting for 55% of the WCS blend.
REDWATER UPGRADING AND REFINING
– In Q1/11, Canadian Natural announced that it had entered into a partnership agreement with North West Upgrading Inc. to move forward with detailed engineering regarding the construction and operation of a bitumen refinery near Redwater, Alberta. In addition, the partnership had entered into a 30 year fee-for-service agreement to process bitumen supplied by the Government of Alberta under the Bitumen Royalty In Kind initiative. Project development is dependent upon completion of detailed engineering and final project sanction by the partnership and its partners and approval of the final tolls. Board sanction is currently targeted for 2012.
FINANCIAL REVIEW
– The financial position of Canadian Natural remains strong as the Company continues to focus on capital allocation and the execution of implemented strategies. Canadian Natural–s credit facilities, its diverse asset base and related capital expenditure programs, and commodity hedging policy all support a flexible financial position and provide the right financial resources for the short, mid and long term. Supporting this are:
— A large and diverse asset base spread over various commodity types; average production amounted to 598,526 BOE/d in 2011 and over 96% of production was located in G8 countries.
— A strong balance sheet with debt to book capitalization of 27% and debt to EBITDA of 1.1 times. At December 31, 2011 long-term debt amounted to $8.6 billion compared with $8.5 billion at December 31, 2010.
— Canadian Natural maintained significant financial stability and increased liquidity in 2011, exiting the year with approximately $3.8 billion in available unused bank lines. In Q4/11, the Company issued US$1 billion of debt securities comprised of 3 and 10 year unsecured notes at 1.45% and 3.45% respectively. Proceeds from these securities were used to repay bank indebtedness. The 10 year unsecured notes were subsequently swapped to a Canadian obligation at 3.96%.
— Standard and Poor–s Financial Services LLC upgraded the Company–s unsecured credit rating to BBB+ (Stable outlook) from BBB (Positive outlook) in 2011.
— Canadian Natural–s commodity hedging program protects investment returns, ensures ongoing balance sheet strength and supports the Company–s cash flow for its capital expenditures programs. The Company has hedged approximately 40% of its forecasted 2012 crude oil volumes through a combination of puts and collars.
— In 2011, the Canadian Natural acquired 3.071 million common shares at an average cost of $33.68/share under the Company–s Normal Course Issuer Bid.
— Canadian Natural has increased its cash dividend on common shares for the twelfth year in a row. In 2012, the quarterly dividend on common shares will increase by approximately 17% from $0.09 to $0.105 per common share, payable April 1, 2012. The dividend increase represents a 21% CAGR since the Company first paid a dividend in 2001.
OUTLOOK
The Company forecasts 2012 production levels before royalties to average between 1,247 and 1,297 MMcf/d of natural gas and between 440,000 and 480,000 bbl/d of crude oil and NGLs. Q1/12 production guidance before royalties is forecast to average between 1,300 and 1,320 MMcf/d of natural gas and between 367,000 and 400,000 bbl/d of crude oil and NGLs. Detailed guidance on production levels, capital allocation and operating costs can be found on the Company–s website at .
YEAR-END RESERVES
Determination of Reserves
For the year ended December 31, 2011 the Company retained Independent Qualified Reserves Evaluators (“Evaluators”), Sproule Associates Limited (“Sproule”) and GLJ Petroleum Consultants Ltd. (“GLJ”), to evaluate and review all of the Company–s proved and proved plus probable reserves. Sproule evaluated the Company–s North America and International crude oil, bitumen, natural gas and NGL reserves. GLJ evaluated the Company–s Horizon synthetic crude oil reserves. The Evaluators conducted the evaluation and review in accordance with the standards contained in the Canadian Oil and Gas Evaluation Handbook (“COGE Handbook”). The reserves disclosure is presented in accordance with NI 51-101 requirements using forecast prices and escalated costs.
The Reserves Committee of the Company–s Board of Directors has met with and carried out independent due diligence procedures with the Evaluators as to the Company–s reserves.
Corporate Total
– Company Gross proved crude oil, SCO, bitumen and NGL reserves increased 8% to 4.09 billion barrels. Company Gross proved natural gas reserves increased 4% to 4.45 Tcf. Total proved reserves increased 7% to 4.83 billion BOE.
– Company Gross proved plus probable crude oil, SCO, bitumen and NGL reserves increased 10% to 6.52 billion barrels. Company Gross proved plus probable natural gas reserves increased 6% to 6.10 Tcf. Total proved plus probable reserves increased 9% to 7.54 billion BOE.
– Company Gross proved reserve additions, including acquisitions, were 437 million barrels of crude oil, SCO, bitumen and NGL and 644 billion cubic feet of natural gas for 545 million BOE. The total proved reserve replacement ratio was 249%. The total proved reserve life index is 21.4 years.
– Company Gross proved plus probable reserve additions, including acquisitions, were 722 million barrels of crude oil, bitumen, SCO and NGL and 793 billion cubic feet of natural gas for 855 million BOE. The total proved plus probable reserve replacement ratio was 390%. The total proved plus probable reserve life index is 33.3 years.
– Proved undeveloped crude oil, SCO, bitumen and NGL reserves accounted for 29% of the corporate total proved reserves and proved undeveloped natural gas reserves accounted for 4% of the corporate total proved reserves.
North America Exploration and Production
– North America Company Gross proved crude oil, bitumen and NGL reserves increased 10% to 1.63 billion barrels. Company Gross proved natural gas reserves increased 4% to 4.27 Tcf. Total proved BOE increased 8% to 2.35 billion barrels.
– North America Company Gross proved plus probable crude oil, bitumen and NGL reserves increased 6% to 2.65 billion barrels. Company Gross proved plus probable natural gas reserves increased 6% to 5.84 Tcf. Total proved plus probable BOE increased 6% to 3.63 billion barrels.
– North America Company Gross proved reserve additions, including acquisitions, were 251 million barrels of crude oil, bitumen and NGL and 623 billion cubic feet of natural gas for 355 million BOE. The total proved reserve replacement ratio is 194%. The total proved reserve life index in 13.9 years.
– Proved undeveloped crude oil, bitumen and NGL reserves accounted for 39% of the North America total proved reserves and proved undeveloped natural gas reserves accounted for 8% of the North America total proved reserves.
– Pelican Lake heavy crude oil Company Gross proved reserves increased 15% to 276 million barrels due to continued expansion and improved performance from the polymer flood project. Proved reserve additions were 51 million barrels.
– Thermal oil Company Gross proved reserves increased 6% to 974 million barrels primarily due to category transfers from probable undeveloped to proved undeveloped at Kirby North and new proved undeveloped additions at Primrose. Proved reserve additions were 91 million barrels.
North America Oil Sands Mining and Upgrading
– Company Gross proved synthetic crude oil reserves increased 10% to 2.12 billion barrels and proved plus probable reserves increased 16% to 3.36 billion barrels.
– Proved reserve additions were 202 million barrels primarily due to additional stratigraphic wells drilled in the north pit. Probable reserve additions were 280 million barrels from expansion of the north pit.
International Exploration and Production
– North Sea Company Gross proved reserves decreased 8% to 244 million barrels of oil equivalent due to cancellation of the Company–s activity in response to the changes in the UK fiscal structure. North Sea Company Gross proved plus probable reserves are 371 million barrels of oil equivalent.
– Offshore Africa Company Gross proved reserves decreased 9% to 123 million barrels of oil equivalent due to production and technical revisions. Offshore Africa Company Gross proved plus probable reserves are 187 million barrels of oil equivalent.
Summary of Company Gross Crude Oil, Bitumen, Natural Gas & NGL Reserves
As of December 31, 2011
Forecast Prices and Costs
Summary of Company Net Crude Oil, Bitumen, Natural Gas & NGL Reserves
As of December 31, 2011
Forecast Prices and Costs
Reconciliation of Company Gross Reserves by Product
As of December 31, 2011
Forecast Prices and Costs
Reconciliation of Company Gross Reserves by Product
As of December 31, 2011
Forecast Prices and Costs
Reconciliation of Company Gross Reserves by Product
As of December 31, 2011
Forecast Prices and Costs
(1) Company Gross reserves are working interest share before deduction of royalties and excluding any royalty interests.
(2) Company Net reserves are working interest share after deduction of royalties and including any royalty interests.
(3) Forecast pricing assumptions utilized by the independent qualified reserves evaluators in the reserve estimates were provided by Sproule Associates Limited:
A foreign exchange rate of US$1.012/C$1.000 was used in the 2011 evaluation.
(4) Reserve additions are comprised of all categories of Company Gross reserve changes, exclusive of production.
(5) Reserve replacement ratio is the Company Gross reserve additions divided by the Company Gross production in the same period.
(6) A barrel of oil equivalent (“BOE”) is derived by converting six thousand cubic feet of natural gas to one barrel of crude oil (6 Mcf:1 bbl). This conversion may be misleading, particularly if used in isolation, since the 6 Mcf:1 bbl ratio 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 comparing the value ratio using current crude oil prices relative to natural gas prices, the 6 Mcf:1 bbl conversion ratio may be misleading as an indication of value.
MANAGEMENT–S DISCUSSION AND ANALYSIS
Forward-Looking Statements
Certain statements relating to Canadian Natural Resources Limited (the “Company”) in this document or documents incorporated herein by reference constitute forward-looking statements or information (collectively referred to herein as “forward-looking statements”) within the meaning of applicable securities legislation. Forward-looking statements can be identified by the words “believe”, “anticipate”, “expect”, “plan”, “estimate”, “target”, “continue”, “could”, “intend”, “may”, “potential”, “predict”, “should”, “will”, “objective”, “project”, “forecast”, “goal”, “guidance”, “outlook”, “effort”, “seeks”, “schedule” or expressions of a similar nature suggesting future outcome or statements regarding an outlook. Disclosure related to expected future commodity pricing, forecast or anticipated production volumes and costs, royalties, operating costs, capital expenditures, income tax expenses and other guidance provided throughout this Management–s Discussion and Analysis (“MD&A”), constitute forward-looking statements. Disclosure of plans relating to and expected results of existing and future developments, including but not limited to the Horizon Oil Sands operations and future expansion, recommencement of production at Horizon, ability to recover insurance proceeds, Primrose, Pelican Lake, Olowi field (Offshore Gabon), the Kirby Thermal Oil Sands Project, the Keystone XL Pipeline US Gulf Coast expansion, and the construction and future operations of the North West Redwater bitumen upgrader and refinery also constitute forward-looking statements. This forward-looking information is based on annual budgets and multi-year forecasts, and is reviewed and revised throughout the year as necessary in the context of targeted financial ratios, project returns, product pricing expectations and balance in project risk and time horizons. These statements are not guarantees of future performance and are subject to certain risks. The reader should not place undue reliance on these forward-looking statements as there can be no assurances that the plans, initiatives or expectations upon which they are based will occur.
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 can be profitably produced in the future. There are numerous uncertainties inherent in estimating quantities of proved and proved plus probable crude oil and natural gas reserves and in projecting future rates of production and the timing of development expenditures. The total amount or timing of actual future production may vary significantly from reserve and production estimates.
The forward-looking statements are based on current expectations, estimates and projections about the Company and the industry in which the Company operates, which speak only as of the date such statements were made or as of the date of the report or document in which they are contained, and are subject to known and unknown risks and uncertainties that could cause the actual results, performance or achievements of the Company to be materially different from any future results, performance or achievements expressed or implied by such forward-looking statements. Such risks and uncertainties include, among others: general economic and business conditions which will, among other things, impact demand for and market prices of the Company–s products; volatility of and assumptions regarding crude oil and natural gas prices; fluctuations in currency and interest rates; assumptions on which the Company–s current guidance is based; economic conditions in the countries and regions in which the Company conducts business; political uncertainty, including actions of or against terrorists, insurgent groups or other conflict including conflict between states; industry capacity; ability of the Company to implement its business strategy, including exploration and development activities; impact of competition; the Company–s defense of lawsuits; availability and cost of seismic, drilling and other equipment; ability of the Company and its subsidiaries to complete capital programs; the Company–s and its subsidiaries– ability to secure adequate transportation for its products; unexpected disruptions or delays in the resumption of the mining, extracting or upgrading of the Company–s bitumen products; potential delays or changes in plans with respect to exploration or development projects or capital expenditures; ability of the Company to attract the necessary labour required to build its thermal and oil sands mining projects; operating hazards and other difficulties inherent in the exploration for and production and sale of crude oil and natural gas and in mining, extracting or upgrading the Company–s bitumen products; availability and cost of financing; the Company–s and its subsidiaries– success of exploration and development activities and their ability to replace and expand crude oil and natural gas reserves; timing and success of integrating the business and operations of acquired companies; production levels; imprecision of reserve estimates and estimates of recoverable quantities of crude oil, natural gas and natural gas liquids (“NGLs”) not currently classified as proved; actions by governmental authorities; government regulations and the expenditures required to comply with them (especially safety and environmental laws and regulations and the impact of climate change initiatives on capital and operating costs); asset retirement obligations; the adequacy of the Company–s provision for taxes; and other circumstances affecting revenues and expenses.
The Company–s operations have been, and in the future may be, affected by political developments and by federal, provincial and local laws and regulations such as restrictions on production, changes in taxes, royalties and other amounts payable to governments or governmental agencies, price or gathering rate controls and environmental protection regulations. Should one or more of these risks or uncertainties materialize, or should any of the Company–s assumptions prove incorrect, actual results may vary in material respects from those projected in the forward-looking statements. The impact of any one factor on a particular forward-looking statement is not determinable with certainty as such factors are dependent upon other factors, and the Company–s course of action would depend upon its assessment of the future considering all information then available.
Readers are cautioned that the foregoing list of factors is not exhaustive. Unpredictable or unknown factors not discussed in this report could also have material adverse effects on forward-looking statements. Although the Company believes that the expectations conveyed by the forward-looking statements are reasonable based on information available to it on the date such forward-looking statements are made, no assurances can be given as to future results, levels of activity and achievements. All subsequent forward-looking statements, whether written or oral, attributable to the Company or persons acting on its behalf are expressly qualified in their entirety by these cautionary statements. Except as required by law, the Company assumes no obligation to update forward-looking statements, whether as a result of new information, future events or other factors, or the foregoing factors affecting this information, should circumstances or Management–s estimates or opinions change.
Management–s Discussion and Analysis
This MD&A of the financial condition and results of operations of the Company should be read in conjunction with the unaudited interim consolidated financial statements for the three months and year ended December 31, 2011 and the MD&A and the audited consolidated financial statements for the year ended December 31, 2010.
All dollar amounts are referenced in millions of Canadian dollars, except where noted otherwise. Common share data and per common share amounts have been restated to reflect the two-for-one common share split in May 2010. The Company–s consolidated financial statements for the period ended December 31, 2011 and this MD&A have been prepared in accordance with International Financial Reporting Standards (“IFRS”), as issued by the International Accounting Standards Board (“IASB”). Unless otherwise stated, 2010 comparative figures have been restated in accordance with IFRS issued as at December 31, 2011. Comparative figures for 2009 have not been restated from Canadian GAAP as previously reported and may not be prepared on a basis consistent with IFRS as adopted. This MD&A includes references to financial measures commonly used in the crude oil and natural gas industry, such as adjusted net earnings from operations, cash flow from operations, and cash production costs. These financial measures are not defined by IFRS and therefore are referred to as non-GAAP measures. The non-GAAP measures used by the Company may not be comparable to similar measures presented by other companies. The Company uses these non-GAAP measures to evaluate its performance. The non-GAAP measures should not be considered an alternative to or more meaningful than net earnings, as determined in accordance with IFRS, as an indication of the Company–s performance. The non-GAAP measures adjusted net earnings from operations and cash flow from operations are reconciled to net earnings, as determined in accordance with IFRS, in the “Financial Highlights” section of this MD&A. The derivation of cash production costs is included in the “Operating Highlights – Oil Sands Mining and Upgrading” section of this MD&A. The Company also presents certain non-GAAP financial ratios and their derivation in the “Liquidity and Capital Resources” section of this MD&A.
A Barrel of Oil Equivalent (“BOE”) is derived by converting six thousand cubic feet of natural gas to one barrel of crude oil (6 Mcf:1 bbl). This conversion may be misleading, particularly if used in isolation, since the 6 Mcf:1 bbl ratio 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 comparing the value ratio using current crude oil prices relative to natural gas prices, the 6 Mcf:1 bbl conversion ratio may be misleading as an indication of value. In addition, for the purposes of this MD&A, crude oil is defined to include the following commodities: light & medium crude oil, primary heavy crude oil, Pelican Lake heavy crude oil, bitumen (thermal oil), and synthetic crude oil.
Production volumes and per unit statistics are presented throughout this MD&A on a “before royalty” or “gross” basis, and realized prices are net of transportation and blending costs and exclude the effect of risk management activities. Production on an “after royalty” or “net” basis is also presented for information purposes only.
The following discussion refers primarily to the Company–s financial results for the three months and year ended December 31, 2011 in relation to the comparable periods in 2010 and the third quarter of 2011. The accompanying tables form an integral part of this MD&A. This MD&A is dated March 6, 2012. Additional information relating to the Company, including its Annual Information Form for the year ended December 31, 2010, is available on SEDAR at , and on EDGAR at .
FINANCIAL HIGHLIGHTS
($ millions, except per common share amounts)
(1) Adjusted net earnings from operations is a non-GAAP measure that represents net earnings adjusted for certain items of a non-operational nature. The Company evaluates its performance based on adjusted net earnings from operations. The reconciliation “Adjusted Net Earnings from Operations” presented below lists the after-tax effects of certain items of a non-operational nature that are included in the Company–s financial results. Adjusted net earnings from operations may not be comparable to similar measures presented by other companies.
(2) Cash flow from operations is a non-GAAP measure that represents net earnings adjusted for non-cash items before working capital adjustments. The Company evaluates its performance based on cash flow from operations. The Company considers cash flow from operations a key measure as it demonstrates the Company–s ability to generate the cash flow necessary to fund future growth through capital investment and to repay debt. The reconciliation “Cash Flow from Operations” presented below lists certain non-cash items that are included in the Company–s financial results. Cash flow from operations may not be comparable to similar measures presented by other companies.
Adjusted Net Earnings from Operations
(a) The Company–s employee stock option plan provides for a cash payment option. Accordingly, the fair value of the outstanding vested options is recorded as a liability on the Company–s balance sheets and periodic changes in the fair value are recognized in net earnings or are capitalized to Oil Sands Mining and Upgrading construction costs.
(b) Derivative financial instruments are recorded at fair value on the balance sheets, with changes in fair value of non-designated hedges recognized in net earnings. The amounts ultimately realized may be materially different than reflected in the financial statements due to changes in prices of the underlying items hedged, primarily crude oil and natural gas.
(c) Unrealized foreign exchange gains and losses result primarily from the translation of US dollar denominated long-term debt to period-end exchange rates, offset by the impact of cross currency swaps, and are recognized in net earnings.
(d) During the third quarter of 2011, the Company repaid US$400 million of US dollar debt securities bearing interest at 6.70%.
(e) All substantively enacted or enacted adjustments in applicable income tax rates and other legislative changes are applied to underlying assets and liabilities on the Company–s consolidated balance sheets in determining deferred income tax assets and liabilities. The impact of these tax rate and other legislative changes is recorded in net earnings during the period the legislation is substantively enacted. During the first quarter of 2011, the UK government enacted an increase to the corporate income tax rate charged on profits from UK North Sea crude oil and natural gas production from 50% to 62%. The Company–s deferred income tax liability was increased by $104 million with respect to this tax rate change. During 2010, changes in Canada to the taxation of stock options surrendered by employees for cash payments resulted in a $132 million charge to deferred income tax expense.
Cash Flow from Operations
SUMMARY OF CONSOLIDATED NET EARNINGS AND CASH FLOW FROM OPERATIONS
Net earnings for the year ended December 31, 2011 were $2,643 million compared to $1,673 million for the year ended December 31, 2010. Net earnings for the year ended December 31, 2011 included net after-tax income of $103 million related to the effects of share-based compensation, risk management activities, fluctuations in foreign exchange rates, the impact of realized foreign exchange gain on repayment of long-term debt and the impact of statutory tax rate and other legislative changes on deferred income tax liabilities, compared to net after-tax expenses of $771 million for the year ended December 31, 2010. Excluding these items, adjusted net earnings from operations for the year ended December 31, 2011 were $2,540 million, compared to $2,444 million for the year ended December 31, 2010.
Net earnings for the fourth quarter of 2011 were $832 million compared to a net loss of $309 million for the fourth quarter of 2010 and net earnings of $836 million for the third quarter of 2011. Net earnings for the fourth quarter of 2011 included net after-tax expenses of $140 million related to the effects of share-based compensation, risk management activities, and fluctuations in foreign exchange rates, compared to net after-tax expenses of $894 million for the fourth quarter of 2010 and net after-tax income of $117 million for the third quarter of 2011. Excluding these items, adjusted net earnings from operations for the fourth quarter of 2011 were $972 million compared to $585 million for the fourth quarter of 2010 and $719 million for the third quarter of 2011.
The increase in adjusted net earnings for the year ended December 31, 2011 from the year ended December 31, 2010 was primarily due to:
– higher North America crude oil and NGL sales volumes;
– higher crude oil and NGL netbacks;
– lower net interest and other financing costs;
partially offset by:
– the impact of suspension of production at Horizon, net of business interruption insurance;
– lower natural gas netbacks;
– realized risk management losses; and
– the impact of a stronger Canadian dollar.
The increase in adjusted net earnings for the fourth quarter of 2011 from the fourth quarter of 2010 was primarily due to:
– higher North America and Horizon crude oil and NGL sales volumes;
– higher crude oil and NGL netbacks;
– lower net interest and other financing costs; and
– the impact of a weaker Canadian dollar.
partially offset by lower natural gas netbacks.
The increase in adjusted net earnings for the fourth quarter of 2011 from the third quarter of 2011 was primarily due to:
– higher Horizon crude oil and NGL sales volumes;
– higher crude oil and NGL netbacks; and
– the impact of a weaker Canadian dollar;
partially offset by:
– lower North America crude oil and NGL sales volumes;
– lower natural gas netbacks;
– higher depletion, depreciation and amortization expense; and
– realized risk management losses.
The impacts of share-based compensation, unrealized risk management activities and changes in foreign exchange rates are expected to continue to contribute to quarterly volatility in consolidated net earnings and are discussed in detail in the relevant sections of this MD&A.
Cash flow from operations for the year ended December 31, 2011 was $6,547 million compared to $6,333 million for the year ended December 31, 2010. Cash flow from operations for the fourth quarter of 2011 was $2,158 million compared to $1,652 million for the fourth quarter of 2010 and $1,767 million for the third quarter of 2011. The increase in cash flow from operations for the year ended December 31, 2011 from the year ended December 31, 2010 was primarily due to:
– higher North America crude oil and NGL sales volumes;
– higher crude oil and NGL netbacks; and
– lower net interest and other financing costs;
partially offset by:
– the impact of suspension of production at Horizon, net of business interruption insurance;
– lower natural gas netbacks;
– realized risk management losses;
– the impact of a stronger Canadian dollar; and
– higher cash taxes.
The increase in cash flow from operations from the fourth quarter of 2010 was primarily due to:
– higher North America and Horizon crude oil and NGL sales volumes;
– higher crude oil and NGL netbacks;
– lower net interest and other financing costs; and
– the impact of a weaker Canadian dollar;
partially offset by:
– lower natural gas netbacks; and
– higher cash taxes.
The increase in cash flow from operations from the third quarter of 2011 was primarily due to:
– higher Horizon crude oil and NGL sales volumes;
– higher crude oil and NGL netbacks; and
– the impact of a weaker Canadian dollar;
partially offset by:
– lower North America crude oil and NGL sales volumes;
– lower natural gas netbacks;
– realized risk management losses; and
– higher cash taxes.
Total production before royalties for the year ended December 31, 2011 decreased 5% to 598,526 BOE/d from 632,191 BOE/d for the year ended December 31, 2010. Total production before royalties for the fourth quarter of 2011 increased by 2% to 657,599 BOE/d from 647,441 BOE/d for the fourth quarter of 2010 and increased by 7% from 612,575 BOE/d for the third quarter of 2011. Production for the fourth quarter of 2011 was within the Company–s previously issued guidance.
SUMMARY OF QUARTERLY RESULTS
The following is a summary of the Company–s quarterly results for the eight most recently completed quarters:
(1) Per common share amounts have been restated to reflect a two-for-one common share split in May 2010.
Volatility in the quarterly net earnings (loss) over the eight most recently completed quarters was primarily due to:
– Crude oil pricing – The impact of fluctuating demand, inventory storage levels and geopolitical uncertainties on worldwide benchmark pricing, the impact of the WCS Heavy Differential (“WCS Differential”) from WTI in North America and the impact of the differential between WTI and Dated Brent benchmark pricing in the North Sea and Offshore Africa.
– Natural gas pricing – The impact of fluctuations in both the demand for natural gas and inventory storage levels, and the impact of increased shale gas production in the US, as well as fluctuations in imports of liquefied natural gas into the US.
– Crude oil and NGLs sales volumes – Fluctuations in production due to the cyclic nature of the Company–s Primrose thermal projects, the results from the Pelican Lake water and polymer flood projects, and the impact of the suspension and recommencement of production at Horizon. Sales volumes also reflected fluctuations due to timing of liftings and maintenance activities in the North Sea and Offshore Africa, and payout of the Baobab field in May 2011.
– Natural gas sales volumes – Fluctuations in production due to the Company–s strategic decision to reduce natural gas drilling activity in North America and the allocation of capital to higher return crude oil projects, as well as natural decline rates and the impact of acquisitions.
– Production expense – Fluctuations primarily due to the impact of the demand for services, fluctuations in product mix, the impact of seasonal costs that are dependent on weather, production and cost optimizations in North America, and the suspension and recommencement of production at both Horizon and the Olowi field in Offshore Gabon.
– Depletion, depreciation and amortization – Fluctuations due to changes in sales volumes, proved reserves, finding and development costs associated with crude oil and natural gas exploration, estimated future costs to develop the Company–s proved undeveloped reserves, the impact of the suspension and recommencement of operations at Horizon and the impact of impairments at the Olowi field in Offshore Gabon.
– Share-based compensation – Fluctuations due to the mark-to-market movements of the Company–s share-based compensation liability.
– Risk management – Fluctuations due to the recognition of gains and losses from the mark-to-market and subsequent settlement of the Company–s risk management activities.
– Foreign exchange rates – Changes in the Canadian dollar relative to the US dollar that impacted the realized price the Company received for its crude oil and natural gas sales, as sales prices are based predominately on US dollar denominated benchmarks. Fluctuations in realized and unrealized foreign exchange gains and losses are recorded with respect to US dollar denominated debt, partially offset by the impact of cross currency swap hedges.
– Income tax expense – Fluctuations in income tax expense include statutory tax rate and other legislative changes substantively enacted or enacted in the various periods.
BUSINESS ENVIRONMENT
(1) West Texas Intermediate (“WTI”)
(2) Synthetic Crude Oil (“SCO”)
Commodity Prices
Crude oil sales contracts in the North America segment are typically based on WTI benchmark pricing. WTI averaged US$95.14 per bbl for the year ended December 31, 2011, an increase of 20% from US$79.55 per bbl for the year ended December 31, 2010. WTI averaged US$94.02 per bbl for the fourth quarter of 2011, an increase of 10% from US$85.18 per bbl for the fourth quarter of 2010, and an increase of 5% from US$89.81 per bbl for the third quarter of 2011. The increase in the WTI benchmark price for the year ended December 31, 2011 was reflective of the political instability in the Middle East and North Africa and continued strong Asian demand. The increase in the WTI benchmark price for the fourth quarter of 2011, compared to the third quarter of 2011, was partially due to the announcement of the Seaway pipeline reversal from Cushing to the Gulf Coast, offset by the relative strength of the US dollar.
Crude oil sales contracts for the Company–s North Sea and Offshore Africa segments are typically based on Brent pricing, which is representative of international markets and overall world supply and demand. Brent averaged US$111.29 per bbl for the year ended December 31, 2011, an increase of 40% compared to US$79.50 per bbl for the year ended December 31, 2010. Brent averaged US$109.29 per bbl for the fourth quarter of 2011, an increase of 26% compared to US$86.49 per bbl for the fourth quarter of 2010 and a decrease of 4% from US$113.46 per bbl for the third quarter of 2011. The higher Dated Brent (“Brent”) pricing relative to WTI in 2011 from the comparable periods in 2010 was primarily due to the limited pipeline capacity between Petroleum Administration for Defence Districts II (“PADD II”) and the United States Gulf Coast. This logistical constraint is preventing lower WTI priced barrels delivered into the PADD II from obtaining United States Gulf Coast Brent-based pricing.
The Western Canadian Select (“WCS”) Heavy Differential averaged 18% for the year ended December 31, 2011, comparable to the year ended December 31, 2010. The WCS Heavy Differential averaged 11% for the fourth quarter of 2011, compared to 21% in the fourth quarter of 2010, and 20% for the third quarter of 2011. The WCS Heavy Differential narrowed in the fourth quarter of 2011, compared to the third quarter of 2011, as a result of increased heavy crude oil conversion from new coking capacity added to key PADD II refineries.
The Company uses condensate as a blending diluent for heavy crude oil pipeline shipments. During 2011, condensate prices traded at a premium to WTI, reflecting the tight supply situation.
The Company anticipates continued volatility in crude oil pricing benchmarks due to supply and demand factors, geopolitical events, and the timing and extent of the continuing economic recovery. The WCS Heavy Differential is expected to continue to reflect seasonal demand fluctuations, logistics and refinery margins.
NYMEX natural gas prices averaged US$4.07 per MMBtu for the year ended December 31, 2011, a decrease of 8% from US$4.42 per MMBtu for the year ended December 31, 2010. NYMEX natural gas prices averaged US$3.61 per MMBtu for the fourth quarter of 2011, a decrease of 5% from US$3.81 per MMBtu for the fourth quarter of 2010, and a decrease of 14% from US$4.19 per MMBtu for the third quarter of 2011. AECO natural gas prices for the year ended December 31, 2011 averaged $3.48 per GJ, a decrease of 11% from $3.91 per GJ for the year ended December 31, 2010. AECO natural gas prices for the fourth quarter of 2011 averaged $3.29 per GJ, a decrease of 3% from $3.39 per GJ for the fourth quarter of 2010, and a decrease of 7% from $3.53 per GJ for the third quarter of 2011.
Overall natural gas prices continue to be weak in response to the strong North America supply position, primarily from the highly productive shale areas. Additionally, weather related natural gas demand was lower in the fourth quarter of 2011 as a result of warmer than normal winter temperatures.
DAILY PRODUCTION, before royalties
(1) Net of transportation and blending costs and excluding risk management activities.
DAILY PRODUCTION, net of royalties
The Company–s business approach is to maintain large project inventories and production diversification among each of the commodities it produces; namely natural gas, light and medium crude oil and NGLs, Pelican Lake heavy crude oil, primary heavy crude oil, bitumen (thermal oil), and SCO.
Crude oil and NGLs production for the year ended December 31, 2011 decreased 8% to 389,053 bbl/d from 424,985 bbl/d for the year ended December 31, 2010. Crude oil and NGLs production for the fourth quarter of 2011 increased 1% to 444,286 bbl/d from 438,835 bbl/d for the fourth quarter of 2010 and increased 10% from 403,900 bbl/d for the third quarter of 2011. The decrease in production for the year ended December 31, 2011 from the comparable period in 2010 was primarily related to the suspension of production at Horizon, partially offset by the impact of a record heavy crude oil drilling program and the cyclic nature of the Company–s thermal operations. The increase from the third quarter of 2011 was primarily due to higher production at Horizon. Crude oil and NGLs production in the fourth quarter of 2011 was within the Company–s previously issued guidance of 430,000 to 461,000 bbl/d.
Natural gas production for the year ended December 31, 2011 averaged 1,257 MMcf/d compared to 1,243 MMcf/d for the year ended December 31, 2010. Natural gas production for the fourth quarter of 2011 increased by 2% to 1,280 MMcf/d from 1,252 MMcf/d in both the fourth quarter of 2010 and in the third quarter of 2011. The increase in natural gas production from the comparable periods in 2010 reflects the new production volumes from natural gas producing properties acquired during 2010 and 2011. These increases were partially offset by expected production declines due to the allocation of capital to higher return crude oil projects, which resulted in a strategic reduction of natural gas drilling activity. During the fourth quarter of 2011, the Company completed a pipeline to a deep cut gas facility, which increased Septimus liquids recoveries. Natural gas production in the fourth quarter of 2011 was at the low end of the Company–s previously issued guidance of 1,279 to 1,304 MMcf/d.
For 2012, revised annual production guidance is targeted to average between 440,000 and 480,000 bbl/d of crude oil and NGLs and between 1,247 and 1,297 MMcf/d of natural gas. First quarter 2012 production guidance is targeted to average between 367,000 and 400,000 bbl/d of crude oil and NGLs and between 1,300 and 1,320 MMcf/d of
natural gas.
North America – Exploration and Production
North America crude oil and NGLs production for the year ended December 31, 2011 increased 9% to average 295,618 bbl/d from 270,562 bbl/d for the year ended December 31, 2010. For the fourth quarter of 2011, crude oil and NGLs production increased 2% to average 291,839 bbl/d, compared to 286,698 bbl/d for the fourth quarter of 2010, and decreased 4% compared to 304,671 bbl/d for the third quarter of 2011. Increases in crude oil and NGLs production from comparable periods in 2010 were primarily due to the impact of a record heavy crude oil drilling program and the cyclic nature of the Company–s thermal operations. The Company–s heavy oil drilling continues on track and exited 2011 at over 115,000 bbl/d, an increase of approximately 19% compared to the first quarter