CALGARY, ALBERTA — (Marketwire) — 08/09/12 — Canadian Natural Resources Limited (TSX: CNQ) (NYSE: CNQ)
Commenting on second quarter results, Canadian Natural–s Vice-Chairman John Langille stated, “Our strategy to maintain a well balanced portfolio and optimize capital allocation ensures we have the flexibility to maximize returns on capital, generate significant cash flow and maintain a strong balance sheet through commodity price cycles. We continue to deliver strong oil-weighted production growth while preserving our vast natural gas asset base which will provide significant upside when natural gas prices strengthen.”
Steve Laut, President of Canadian Natural continued, “With our balanced and diverse assets, complemented our proven and effective strategy as executed by our strong teams, we delivered a very strong quarter. Overall production was up and operating costs were down across the board in North America. In addition, we have been nimble and effective in optimizing our capital allocation in the quarter in response to market conditions. We have reduced capital spending in 2012 by approximately 10% and at the same time have slightly increased our BOE and crude oil mid-point production guidance for 2012. This demonstrates the strength of Canadian Natural–s assets, our capital flexibility, the effectiveness of our strategies and the ability of our teams to effectively execute.”
QUARTERLY HIGHLIGHTS
– Canadian Natural is committed to operational excellence. In Q2/12 the Company achieved record quarterly production of 679,607 BOE/d and met or exceeded production guidance in all areas of our business.
– Total crude oil and NGLs achieved record quarterly production of 470,523 bbl/d representing an increase of 34% and 19% over Q2/11 and Q1/12 levels respectively. The increase in production from Q2/11 was primarily due to efficient, effective and reliable operations achieved at Horizon and successful results from a strong primary heavy crude oil drilling program. The increase in production from Q1/12 was primarily due to improved reliability at Horizon and the timing of steaming cycles in bitumen (“thermal in situ”).
– Total natural gas production for Q2/12 was 1,255 MMcf/d representing an increase of 1% over Q2/11 and a decrease of 4% from Q1/12. The increase in production from Q2/11 reflects the impact of natural gas producing properties acquired during 2011 and strong results from the Company–s modest, liquids rich drilling program. The decrease in production from Q1/12 was a result of natural declines reflecting the Company–s strategic decision to allocate capital to higher return crude oil projects and 20 MMcf/d of shut-in natural gas volumes year-to-date.
– Canadian Natural generated cash flow from operations for the quarter of $1.75 billion representing an increase of 13% and 37% compared with Q2/11 and Q1/12 cash flow levels respectively. The increase in cash flow was primarily related to higher North America crude oil and synthetic crude oil (“SCO”) sales volumes partially offset by lower crude oil and NGLs and natural gas pricing.
– Adjusted net earnings from operations for the quarter were $606 million, compared with adjusted net earnings of $621 million in Q2/11 and $300 million in Q1/12. The decrease from Q2/11 was primarily due to lower crude oil and NGLs and natural gas pricing partially offset by higher sales volumes from the Company–s North America crude oil and NGLs and oil sands mining operations. The increase from Q1/12 was primarily related to higher North America crude oil and SCO sales volumes partially offset by lower crude oil and NGLs and natural gas pricing.
– Primary heavy crude oil production achieved record quarterly production exceeding 122,000 bbl/d representing an increase of 21% compared with Q2/11 and an increase of 2% compared with Q1/12. Canadian Natural targets to drill 54 additional net primary heavy crude oil wells compared with the previous target, for a targeted record of 872 net wells in 2012 and targets to increase annual production by 21% over 2011. Primary heavy crude oil continues to provide the highest return on capital projects in the portfolio.
– As expected, thermal in situ production averaged approximately 94,000 bbl/d in Q2/12 as pads began to re-enter the production cycle. Production is targeted to ramp up to facility capacity in Q4/12. Operating costs for the quarter were $10.47/bbl as a result of solid production, modest natural gas prices and strong operational performance. The Company targets to achieve full year operating costs of approximately $9.00/bbl in this segment of the Company.
– Kirby South Phase 1 was 53% complete at the end of the second quarter. The project remains on schedule with first steam-in targeted for Q4/13. Drilling is nearing completion on the fourth of seven pads with wells confirming geological expectations.
– Horizon demonstrated strong operational performance in the quarter. Production averaged 115,823 bbl/d, highlighting the Company–s commitment to safe, steady and reliable operations and the positive impact of the third ore preparation plant (“OPP”) being fully operational. The third OPP has increased overall reliability and improved steady operations in the upgrader.
– In response to the uncertain outlook on commodity prices, targeted capital expenditures for 2012 are being re-allocated from natural gas to higher return primary heavy crude oil projects and overall capital expenditures in 2012 are being reduced by approximately $680 million while BOE and crude oil mid-point production guidance was slightly increased. Capital allocation reductions were primarily in the areas of Horizon oil sands expansion and North America natural gas.
– To date in 2012, Canadian Natural has purchased 6,196,600 common shares for cancellation at a weighted average price of $28.91 per common share.
– Declared a quarterly cash dividend on common shares of $0.105 per common share payable October 1, 2012.
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, bitumen (“thermal in situ”), and 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
Drilling activity (number of wells)
North America Exploration and Production
North America crude oil and NGLs
– Production averaged 316,483 bbl/d in Q2/12 representing an increase of 7% from Q2/11 and an increase of 4% from Q1/12. The increase in production from Q2/11 was a result of successful primary heavy and light crude oil drilling programs offset by the timing of thermal in situ steaming cycles. The increase in production from Q1/12 was a result of the ramp up of thermal in situ production as pads re-entered the production cycle.
– Primary heavy crude oil production achieved record quarterly production exceeding 122,000 bbl/d representing an increase of 21% compared with Q2/11 and an increase of 2% compared with Q1/12. Canadian Natural targets to drill 54 additional net primary heavy crude oil wells compared with the previous target, for a targeted record of 872 net wells in 2012 and targets to increase annual production by 21% over 2011. Primary heavy crude oil continues to provide the highest return on capital projects in the portfolio.
– North America light crude oil and NGLs quarterly production increased 17% from Q2/11 as a result of a successful light oil drilling program and increased liquid recoveries from Septimus following the completion of a tie in to a deep cut facility. North America light crude oil and NGLs is a significant part of Canadian Natural–s balanced portfolio, averaging approximately 62,500 bbl/d in the quarter.
– At Pelican Lake, reservoir performance continues to be positive with July production of approximately 40,000 bbl/d. The Company has commenced construction of a 25,000 bbl/d battery to support targeted production growth from the polymer flood and year-to-date has drilled 30 of the 72 net wells targeted for 2012. Canadian Natural targets to ultimately recover 561 million barrels (363 million barrels of proved plus probable reserves and 198 million barrels of contingent resources) of additional crude oil through a disciplined multi-year expansion plan.
– Canadian Natural–s robust portfolio of thermal in situ projects is a significant part of the Company–s defined plan to transition to a longer-life, more sustainable asset base with the ability to generate significant shareholder value for decades to come. The Company targets to grow thermal in situ production to approximately 500,000 bbl/d of capacity by delivering projects that will add 40,000 bbl/d of production every two to three years.
— As expected, thermal in situ production averaged approximately 94,000 bbl/d in Q2/12 as pads began to re-enter the production cycle. Production is targeted to ramp up to facility capacity in Q4/12. The Company targets to maximize steam plant capacity through the completion of low cost pad-add projects at Primrose; projects currently under construction are on schedule and on budget.
— Thermal in situ operating costs for the quarter were $10.47/bbl as a result of solid production, modest natural gas prices and strong operational performance. The Company targets to achieve full year operating costs of approximately $9.00/bbl in this segment of the Company.
— Kirby South Phase 1 was 53% complete at the end of the second quarter. The project remains on schedule with first steam-in targeted for Q4/13. Drilling is nearing completion on the fourth of seven pads with wells confirming geological expectations.
— On Kirby North Phase 1, the 2012 statigraphic (“strat”) test well drilling program has been completed and procurement of long lead items is progressing. First steam-in is targeted for early 2016.
— At Grouse, design basis memorandum engineering is progressing on track with completion targeted for 2012. First steam-in is targeted for late 2017.
– For Q3/12, the Company plans to drill 42 net thermal in situ wells and 290 net crude oil wells, excluding strat test and service wells.
– As expected, North America crude oil and NGLs operating costs decreased to $13.10/bbl in Q2/12 from $15.40/bbl in Q1/12. The decrease was primarily due to reduced primary heavy crude oil operating costs as a result of strategic capital investments made during the first half of 2012.
– North America natural gas production for the quarter averaged 1,230 MMcf/d representing an increase of 1% from Q2/11 and a decrease of 4% from Q1/12. The increase in production from Q2/11 reflects the impact of natural gas producing properties acquired during 2011 and strong results from the Company–s modest, liquids rich drilling program. The decrease in production from Q1/12 was a result of natural declines reflecting the Company–s strategic decision to allocate capital to higher return crude oil projects.
– Canadian Natural is the second largest producer of natural gas in Canada and an industry leader in low natural gas operating costs. During 2012, the Company has shut-in approximately 20 MMcf/d of natural gas in response to low natural gas prices and currently has approximately 40 MMcf/d of natural gas shut-in.
– The continued weakness in natural gas prices has resulted in a further reduction in capital allocated to natural gas. 2012 drilling has been reduced by 36 net wells compared with the original budget and the completion of 10 Septimus wells has been deferred along with the facility expansion.
– As expected, North America natural gas operating costs decreased to $1.13/Mcf in Q2/12 from $1.33/Mcf in Q1/12 as high operating cost properties acquired in late 2011 were fully integrated with existing operations. Canadian Natural–s extensive infrastructure and land base combined with a disciplined approach is what drives the Company–s ability to create value in a modest commodity price environment.
International Exploration and Production
– North Sea crude oil production averaged 17,619 bbl/d during Q2/12 representing a decrease of 46% compared with Q2/11 and a decrease of 24% compared with Q1/12. The decrease from Q2/11 was primarily a result of a 20 day shut-in of all Ninian platforms and associated fields due to unplanned maintenance on a third party pipeline and suspended operations at Banff/Kyle. In Q4/11 the Banff/Kyle floating production storage offloading vessel (“FPSO”) suffered damage from severe storm conditions. The decrease from Q1/12 was primarily due to unplanned maintenance on the third party pipeline that temporarily shut-in all Ninian platforms and associated fields. Planned turnarounds at Ninian North and Ninian Central and third party pipeline maintenance are scheduled for Q3/12.
– Production in Offshore Africa averaged 20,598 bbl/d during Q2/12 representing a decrease of 3% compared with Q2/11 and a decrease of 1% compared with Q1/12. The decrease from Q2/11 and Q1/12 was primarily a result of natural field declines. The Company–s eight well infill drilling program at the Espoir field is targeted to commence in Q4/12. The Company targets additional production of 6,500 BOE/d at the completion of the Espoir drilling program.
– Conversion of the license of the Company–s 100% working interest block in South Africa was completed in the quarter and all regulatory requirements to drill a well are complete. Targeted drilling windows are from Q4/13 to Q1/14 and from Q4/14 to Q1/15.
North America Oil Sands Mining and Upgrading – Horizon
– Horizon demonstrated strong operational performance in the quarter. Production averaged 115,823 bbl/d, highlighting the Company–s commitment to safe, steady and reliable operations and the positive impact of the third OPP being fully operational. The third OPP has increased overall reliability and improved steady operations in the upgrader.
– Enhanced operational discipline and focus on safe, steady and reliable operations allows the Company to be proactive in planned maintenance activities. Performance in Q2/12 along with proactive maintenance scheduled for Q3/12 gives the Company confidence to increase full year mid-point guidance by 4% to 94,000 bbl/d for Horizon.
– As expected, operating costs for the quarter averaged $36.98/bbl. Through future expansion, Canadian Natural targets to reduce operating costs per barrel by increasing production disproportionately to largely fixed operating costs.
– Canadian Natural–s staged expansion to 250,000 bbl/d of SCO production capacity continues to progress on track. Thus far, several lump sum contracts have been awarded and projects currently under construction are trending at or below cost estimates. The Company–s 100% working interest in this project allows for significant capital flexibility; the 2012 project capital for Horizon was reduced by $330 million to $1.55 billion. The decrease in 2012 capital is a result of overall cost reductions and strategic deferrals to achieve greater cost certainty.
MARKETING
– In Q2/12, WTI pricing decreased by 9% from Q2/11 and Q1/12 partially due to supply and demand imbalances.
– The WCS heavy crude oil differential as a percent of WTI averaged 24% in Q2/12, in line with the Company–s long term expectations and well below historical averages. The WCS heavy differential widened from Q1/12 as a result of planned and unplanned maintenance at key refineries in the United States and Canada. The Company anticipates volatility in the differential in 2012 and narrowing of the differential thereafter as additional conversion and pipeline capacity come on stream.
– During Q2/12, Canadian Natural contributed 154,000 bbl/d of its heavy crude oil stream to the WCS blend. The Company is the largest contributor of the WCS blend, accounting for 53%.
– AECO benchmark natural gas prices weakened in Q2/12 compared with Q2/11 and Q1/12 due to supply and demand imbalances in North America. AECO has increased from a low of $1.43/GJ in April primarily due to increased seasonal demand and increased demand from the power generation sector.
REDWATER UPGRADING AND REFINING
Supporting and participating in projects that add incremental conversion capacity is a key part of the Company–s marketing strategy. Canadian Natural, in a partnership agreement with North West Upgrading Inc., continues to move forward with detailed engineering regarding the construction and operation of a bitumen refinery near Redwater, Alberta. 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 in 2012.
FINANCIAL REVIEW
The financial position of Canadian Natural remains strong as the Company continues to implement proven strategies and focuses on disciplined capital allocation. Canadian Natural–s cash flow generation, credit facilities, 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 near, mid and long term.
– The Company–s strategy is to maintain a diverse portfolio balanced across various commodity types. The Company achieved record production of 679,607 BOE/d for the quarter with over 96% of production located in G8 countries.
– Canadian Natural has a strong balance sheet with debt to book capitalization of 26% and debt to EBITDA of 1.0. At June 30, 2012, long-term debt amounted to $8.5 billion compared with $8.6 billion at December 31, 2011.
– During the quarter, the Company issued $500 million of 3.05% medium-term unsecured notes due June 2019 to Canadian investors and extended the $1.5 billion revolving syndicated credit facility to June 2016.
– Canadian Natural maintains significant financial stability and liquidity represented by approximately $4.4 billion in available unused bank lines at the end of the quarter.
– The Company–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 half of the remaining crude oil volumes forecasted for 2012 through a combination of puts and collars.
– In Q2/12, Toronto Stock Exchange accepted notice of Canadian Natural–s renewal of its Normal Course Issuer Bid through the facilities of Toronto Stock Exchange and the New York Stock Exchange. The notice provides that Canadian Natural may, during the 12 month period commencing April 9, 2012 and ending April 8, 2013, purchase for cancellation on Toronto Stock Exchange and the New York Stock Exchange up to 55,027,447 shares.
– To date in 2012, Canadian Natural has purchased 6,196,600 common shares for cancellation at a weighted average price of $28.91 per common share.
– Declared a quarterly cash dividend on common shares of $0.105 per common share payable October 1, 2012.
OUTLOOK
The Company forecasts 2012 production levels before royalties to average between 1,220 and 1,235 MMcf/d of natural gas and between 454,000 and 474,000 bbl/d of crude oil and NGLs. Q3/12 production guidance before royalties is forecast to average between 1,170 and 1,190 MMcf/d of natural gas and between 451,000 and 480,000 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 .
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 expansions, Primrose, Pelican Lake, 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 and six months ended June 30, 2012 and the MD&A and the audited consolidated financial statements for the year ended December 31, 2011.
All dollar amounts are referenced in millions of Canadian dollars, except where noted otherwise. The Company–s consolidated financial statements for the period ended June 30, 2012 and this MD&A have been prepared in accordance with International Financial Reporting Standards (“IFRS”), as issued by the International Accounting Standards Board. Unless otherwise stated, 2010 comparative figures have been restated in accordance with IFRS issued as at December 31, 2011. 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 and 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 and six months ended June 30, 2012 in relation to the comparable periods in 2011 and the first quarter of 2012. The accompanying tables form an integral part of this MD&A. This MD&A is dated August 8, 2012. Additional information relating to the Company, including its Annual Information Form for the year ended December 31, 2011, is available on SEDAR at , and on EDGAR at .
FINANCIAL HIGHLIGHTS
Adjusted Net Earnings from Operations
Cash Flow from Operations
SUMMARY OF CONSOLIDATED NET EARNINGS AND CASH FLOW FROM OPERATIONS
Net earnings for the six months ended June 30, 2012 were $1,180 million compared with $975 million for the six months ended June 30, 2011. Net earnings for the six months ended June 30, 2012 included net unrealized after-tax income of $274 million compared with net unrealized after-tax income of $126 million for the six months ended June 30, 2011 related to the effects of share-based compensation, risk management activities, fluctuations in foreign exchange rates, and the impact of statutory tax rate and other legislative changes on deferred income tax liabilities. Excluding these items, adjusted net earnings from operations for the six months ended June 30, 2012 were $906 million compared with $849 million for the six months ended June 30, 2011.
Net earnings for the second quarter of 2012 were $753 million compared with $929 million for the second quarter of 2011 and $427 million for the first quarter of 2012. Net earnings for the second quarter of 2012 included net unrealized after-tax income of $147 million compared with $308 million for the second quarter of 2011 and $127 million for the first quarter of 2012 related to the effects of share-based compensation, risk management activities and fluctuations in foreign exchange rates. Excluding these items, adjusted net earnings from operations for the second quarter of 2012 were $606 million compared with $621 million for the second quarter of 2011 and $300 million for the first quarter of 2012.
The increase in adjusted net earnings for the six months ended June 30, 2012 from the comparable period in 2011 was primarily due to:
– higher crude oil and synthetic crude oil (“SCO”) sales volumes in the North America and Oil Sands Mining and Upgrading segments;
– the impact of a weaker Canadian dollar; and
– fluctuations in realized risk management gains and losses;
partially offset by:
– lower crude oil and NGLs and natural gas netbacks;
– lower SCO prices; and
– higher depletion, depreciation and amortization expense.
The decrease in adjusted net earnings for the second quarter of 2012 from the comparable period of 2011 was primarily due to:
– lower crude oil and NGLs and natural gas netbacks; and
– higher depletion, depreciation and amortization expense;
partially offset by:
– higher crude oil and SCO sales volumes in the North America and Oil Sands Mining and Upgrading segments;
– higher natural gas sales volumes;
– the impact of a weaker Canadian dollar; and
– fluctuations in realized risk management gains and losses.
The increase in adjusted net earnings for the second quarter of 2012 from the first quarter of 2012 was primarily due to:
– higher crude oil and SCO sales volumes in the North America and Oil Sands Mining and Upgrading segments;
– the impact of a weaker Canadian dollar; and
– fluctuations in realized risk management gains and losses;
partially offset by:
– lower crude oil and NGLs and natural gas netbacks;
– lower SCO prices; and
– higher depletion, depreciation and amortization expense.
The impacts of share-based compensation, 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 six months ended June 30, 2012 was $3,034 million compared with $2,622 million for the six months ended June 30, 2011. Cash flow from operations for the second quarter of 2012 was $1,754 million compared with $1,548 million for the second quarter of 2011 and $1,280 million for the first quarter of 2012. The increase in cash flow from operations from the comparable periods was primarily due to the factors noted above relating to the fluctuations in adjusted net earnings, excluding depletion, depreciation and amortization expense.
Total production before royalties for the six months ended June 30, 2012 increased 15% to 645,943 BOE/d from 561,359 BOE/d for the six months ended June 30, 2011. Total production before royalties for the second quarter of 2012 increased 22% to a record 679,607 BOE/d from 556,539 BOE/d for the second quarter of 2011 and 11% from 612,279 BOE/d for the first quarter of 2012. Production for the second quarter of 2012 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:
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 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, a record heavy oil drilling program, 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 and timing 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, acquisitions of natural gas producing properties that have higher operating costs per Mcf than the Company–s existing properties, and the suspension and recommencement of production at Horizon.
– 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 production at Horizon and the impact of impairments at the Olowi field in offshore Gabon.
– Share-based compensation – Fluctuations due to the determination of fair market value based on the Black-Scholes valuation model 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 in the various periods.
BUSINESS ENVIRONMENT
Commodity Prices
Crude oil sales contracts in the North America segment are typically based on WTI benchmark pricing. WTI averaged US$98.22 per bbl for the six months ended June 30, 2012 and was comparable with the six months ended June 30, 2011. WTI averaged US$93.50 per bbl for the second quarter of 2012, a decrease of 9% from US$102.55 per bbl for the second quarter of 2011 and US$102.94 per bbl for the first quarter of 2012. WTI pricing was reflective of the political instability in the Middle East offset by declining optimism in the United States economy, the European debt crisis, and lower than expected growth in Asian demand.
Crude oil sales contracts for the Company–s North Sea and Offshore Africa segments are typically based on Dated Brent (“Brent”) pricing, which is representative of international markets and overall world supply and demand. Brent averaged US$113.34 per bbl for the six months ended June 30, 2012, an increase of 2% compared with US$111.20 per bbl for the six months ended June 30, 2011. Brent averaged US$108.21 per bbl for the second quarter of 2012, a decrease of 8% compared with US$117.33 per bbl for the second quarter of 2011 and a decrease of 9% from US$118.47 per bbl for the first quarter of 2012. The higher Brent pricing relative to WTI was due to logistical constraints and high inventory levels of crude oil at Cushing.
The WCS Heavy Differential averaged 23% for the six months ended June 30, 2012 compared with 20% for the six months ended June 30, 2011. The WCS Heavy Differential averaged 24% for the second quarter of 2012 compared with 17% in the second quarter of 2011, and 21% for the first quarter of 2012. The WCS Heavy Differential widened in the second quarter of 2012, relative to the comparable periods, as a result of planned and unplanned maintenance at key refineries accessible by Canadian crude oil.
The Company uses condensate as a blending diluent for heavy crude oil pipeline shipments. During the second quarter of 2012, condensate prices continued to trade at a premium to WTI, similar to prior periods, reflecting normal seasonality.
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, changes in transportation logistics, and refinery utilization and shutdowns.
NYMEX natural gas prices averaged US$2.52 per MMBtu for the six months ended June 30, 2012, a decrease of 41% from US$4.24 per MMBtu for the six months ended June 30, 2011. NYMEX natural gas prices averaged US$2.26 per MMBtu for the second quarter of 2012, a decrease of 48% from US$4.36 per MMBtu for the second quarter of 2011, and a decrease of 18% from US$2.77 per MMBtu for the first quarter of 2012.
AECO natural gas prices for the six months ended June 30, 2012 averaged $2.06 per GJ, a decrease of 42% from $3.56 per GJ for the six months ended June 30, 2011. AECO natural gas prices for the second quarter of 2012 averaged $1.74 per GJ, a decrease of 51% from $3.54 per GJ for the second quarter of 2011, and a decrease of 27% from $2.39 per GJ for the first quarter of 2012.
During the second quarter of 2012, natural gas prices continued to be weak in response to the strong North America supply position, primarily from the highly productive shale areas. However, the AECO natural gas price has increased from its low of $1.43 per GJ in April 2012 due to higher weather related gas demand resulting from warmer than normal spring and summer temperatures, together with a shift to higher utilization of gas fired electric generators due to the low natural gas prices.
DAILY PRODUCTION, before royalties
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 six months ended June 30, 2012 increased 23% to 432,993 bbl/d from 353,433 bbl/d for the six months ended June 30, 2011. Crude oil and NGLs production for the second quarter of 2012 increased 34% to 470,523 bbl/d from 349,915 bbl/d for the second quarter of 2011 and increased 19% from 395,461 bbl/d for the first quarter of 2012. The increase in production from the comparable periods was primarily related to increased production at Horizon, the impact of a strong heavy crude oil drilling program, and the cyclic nature of the Company–s thermal operations. Crude oil and NGLs production in the second quarter of 2012 was within the Company–s previously issued guidance of 453,000 to 482,000 bbl/d.
Natural gas production for the six months ended June 30, 2012 increased by 2% to 1,277 MMcf/d from 1,248 MMcf/d for the six months ended June 30, 2011. Natural gas production for the second quarter of 2012 increased by 1% to 1,255 MMcf/d from 1,240 MMcf/d from the second quarter of 2011 and decreased by 4% from 1,302 MMcf/d for the first quarter of 2012. The increase in natural gas production from the comparable periods in 2011 reflects the impact of natural gas producing properties acquired during 2011. The decrease in natural gas production for the second quarter of 2012 from the first quarter of 2012 was primarily a result of expected production declines due to the allocation of capital to higher return crude oil projects, which continue to result in a strategic reduction of natural gas drilling activity. The Company shut in approximately 20 MMcf/d of natural gas production in 2012 and overall has shut in 40 MMcf/d due to the decrease in natural gas prices. Natural gas production in the second quarter of 2012 was within the Company–s previously issued guidance of 1,250 to 1,270 MMcf/d.
For 2012, annual production guidance is targeted to average between 454,000 and 474,000 bbl/d of crude oil and NGLs and between 1,220 and 1,235 MMcf/d of natural gas. Third quarter 2012 production guidance is targeted to average between 451,000 and 480,000 bbl/d of crude oil and NGLs and between 1,170 and 1,190 MMcf/d of natural gas.
North America – Exploration and Production
North America crude oil and NGLs production for the six months ended June 30, 2012 increased 6% to average 311,048 bbl/d from 292,938 bbl/d for the six months ended June 30, 2011. For the second quarter of 2012, crude oil and NGLs production increased 7% to average 316,483 bbl/d compared with 295,715 bbl/d for the second quarter of 2011 and increased 4% from 305,613 bbl/d for the first quarter of 2012. Increases in crude oil and NGLs production from comparable periods were primarily due to the impact of a strong heavy crude oil drilling program. The increase in crude oil production for the second quarter was also impacted by the cyclic nature of the Company–s thermal operations. Production of crude oil and NGLs was within the Company–s previously issued guidance of 312,000 bbl/d to 325,000 bbl/d for the second quarter of 2012. Third quarter 2012 production guidance is targeted to average between 322,000 and 335,000 bbl/d of crude oil and NGLs.
Natural gas production for the six months ended June 30, 2012 increased 3% to 1,255 MMcf/d compared with 1,221 MMcf/d for the six months ended June 30, 2011. Natural gas production increased 1% to 1,230 MMcf/d for the second quarter of 2012 compared with 1,218 MMcf/d in the second quarter of 2011 and decreased 4% compared with 1,281 MMcf/d in the first quarter of 2012. Natural gas production for the six months ended June 30, 2012 increased from the comparable period in 2011 due to the impact of natural gas producing properties acquired during 2011. The decrease in natural gas production for the second quarter of 2012 from the first quarter of 2012 was primarily a result of expected production declines due to the allocation of capital to higher return crude oil projects, which continue to result in a strategic reduction of natural gas drilling activity. The Company has reduced its drilling activities and shut in approximately 40 MMcf/d of gas volumes due to the decline in natural gas prices.
North America – Oil Sands Mining and Upgrading
Production averaged 80,957 bbl/d for the six months ended June 30, 2012 from 3,615 bbl/d for the six months ended June 30, 2011. For the second quarter of 2012, SCO production averaged a record 115,823 bbl/d compared with no production for the second quarter of 2011 and 46,090 bbl/d for the first quarter of 2012, related to suspension of production during these periods.
On March 13, 2012 the Company successfully and safely completed the unplanned maintenance on the fractionating unit in the primary upgrading facility. The positive impact of the third ore preparation plant (“OPP”) and continued emphasis on safe, steady and reliable operations resulted in strong operational performance across Horizon, with production exceeding the Company–s previously issued guidance of between 105,000 and 115,000 bbl/d of SCO for the second quarter of 2012.
North Sea
North Sea crude oil production for the six months ended June 30, 2012 decreased 39% to 20,333 bbl/d from 33,480 bbl/d for the six months ended June 30, 2011. Second quarter 2012 North Sea crude oil production decreased 46% to 17,619 bbl/d from 32,866 bbl/d for the second quarter of 2011, and decreased 24% from 23,046 bbl/d for the first quarter of 2012. The decrease in production volumes from the comparable periods in 2011 was primarily due to a 20- day shut in of the third-party operated pipeline to Sullom Voe for unplanned maintenance, which caused all Ninian and associated fields to be shut in, the suspension of production at Banff/Kyle, and natural field declines due to curtailment of development activities in the North Sea as a result of corporate tax increases that were enacted in 2011. The decrease in production volumes from the first quarter of 2012 was the result of the temporary shut in of the third-party operated pipeline. In December 2011, the Banff Floating Production, Storage and Offloading Vessel (“FPSO”) and subsea infrastructure suffered storm damage. Operations at Banff/Kyle, with combined net production of approximately 3,500 bbl/d, were suspended and appropriate shut-down procedures were activated. The FPSO and associated floating storage unit have subsequently been removed from the field. The extent of the damage, including associated costs and related property damage, are not expected to be significant. The timing of returning to the field is currently being assessed.
Offshore Africa
Offshore Africa crude oil production decreased 12% to 20,655 bbl/d for the six months ended June 30, 2012 from 23,400 bbl/d for the six months ended June 30, 2011. Second quarter crude oil production averaged 20,598 bbl/d, decreasing 3% from 21,334 bbl/d for the second quarter of 2011, and was comparable to 20,712 bbl/d in the first quarter of 2012. The decrease in production volumes from the comparable periods in 2011 was due to natural field declines.
International Guidance
The Company–s North Sea and Offshore Africa second quarter 2012 crude oil and NGLs production was within the Company–s previously issued guidance of 36,000 to 42,000 bbl/d. Third quarter 2012 production guidance is targeted to average between 34,000 and 40,000 bbl/d of crude oil.
Crude Oil Inventory Volumes
The Company recognizes revenue on its crude oil production when title transfers to the customer and delivery has taken place. Revenue has not been recognized on crude oil volumes that were stored in various tanks, pipelines, or floating production, storage and offloading vessels, as follows:
OPERATING HIGHLIGHTS – EXPLORATION AND PRODUCTION
PRODUCT PRICES – EXPLORATION AND PRODUCTION
North America
North America realized crude oil prices averaged $69.60 per bbl for the six months ended June 30, 2012 and were comparable with $69.92 per bbl for the six months ended June 30, 2011. North America realized crude oil prices averaged $65.10 per bbl for the second quarter of 2012, a decrease of 16% compared with $77.62 per bbl for the second quarter of 2011 and a decrease of 12% compared with $74.27 per bbl for the first quarter of 2012. The decrease in prices for the second quarter of 2012 from the comparable periods was primarily a result of lower benchmark WTI pricing and the widening of the WCS Heavy Differential, partially offset by the impact of a weaker Canadian dollar relative to the US dollar. The Company continues to focus on its crude oil blending marketing strategy, and in the second quarter of 2012 contributed approximately 154,000 bbl/d of heavy crude oil blends to the WCS stream.
In the first quarter of 2011, the Company 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 upgrader refinery near Redwater, Alberta. In addition, the partnership has entered into a 30 year fee-for-service tolling agreement to process bitumen supplied by the Company and 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 in 2012.
North America realized natural gas prices decreased 45% to average $2.05 per Mcf for the six months ended June 30, 2012 from $3.76 per Mcf for the six months ended June 30, 2011. North America realized natural gas prices decreased 54% to average $1.73 per Mcf for the second quarter of 2012 compared with $3.76 per Mcf in the second quarter of 2011, and decreased 27% compared with $2.36 per Mcf for the first quarter of 2012. The decrease in natural gas prices from the comparable periods was primarily due to lower NYMEX and AECO benchmark pricing related to the impact of strong supply from US shale projects and the effects of a warmer than normal winter.
Comparisons of the prices received in North America Exploration and Production by product type were as follows:
North Sea
North Sea realized crude oil prices increased 5% to average $113.24 per bbl for the six months ended June 30, 2012 from $107.75 per bbl for the six months ended June 30, 2011. Realized crude oil prices averaged $108.22 per bbl for the second quarter of 2012, a decrease of 4% from $112.32 per bbl for the second quarter of 2011, and 8% from $117.03 per bbl for the first quarter of 2012. The increase in realized crude oil prices in the North Sea for the six months ended June 30, 2012 from the comparable period in 2011 was primarily the result of higher Brent benchmark pricing and fluctuations in the Canadian dollar. The decreases in realized crude oil prices in the North Sea for the three months ended June 30, 2012 from the comparable periods were primarily the result of lower Brent benchmark pricing and the timing of liftings, partially offset by the weaker Canadian dollar.
Offshore Africa
Offshore Africa realized crude oil prices increased 13% to average $116.09 per bbl for the six months ended June 30, 2012 from $102.56 per bbl for the six months ended June 30, 2011. Realized crude oil prices decreased 4% to average $106.30 per bbl for the second quarter of 2012 from $110.42 per bbl for the second quarter of 2011, and 18% from $128.94 per bbl for the first quarter of 2012. The increase in realized crude oil prices in Offshore Africa for the six months ended June 30, 2012 from the comparable period in 2011 was primarily the result of higher Brent benchmark pricing and the timing of liftings, together with the impact of fluctuations in the Canadian dollar. The decreases in realized crude oil prices in Offshore Africa for the three months ended June 30, 2012 from the comparable periods were primarily the result of lower Brent benchmark pricing, partially offset by the weaker Canadian dollar.
ROYALTIES – EXPLORATION AND PRODUCTION
North America
North America crude oil and natural gas royalties for the six months ended June 30, 2012 compared with the six months ended June 30, 2011 reflected decreases in benchmark commodity prices.
Crude oil and NGLs royalties averaged approximately 13% of product sales for the second quarter of 2012 compared with 17% for the second quarter of 2011 and 19% for the first quarter of 2012. The decrease in royalties from the comparable periods was due to lower bitumen prices. Crude oil and NGLs royalties per bbl are anticipated to average 15% to 17% of product sales for 2012.
Natural gas royalties averaged approximately 1% of product sales for the first and second quarters of 2012 compared with 6% for the second quarter of 2011. The decrease in natural gas royalty rates from the second quarter of 2011 was due to the decline in realized natural gas prices. Natural gas royalties are anticipated to average 1% to 2% of product sales for 2012.
Offshore Africa
Under the terms of the various Production Sharing Contracts, royalty rates fluctuate based on realized commodity pricing, capital costs, the status of payouts, and the timing of liftings from each field.
Royalty rates as a percentage of product sales averaged approximately 26% for the second quarter of 2012 compared with 1% for the second quarter of 2011 and 16% for the first quarter of 2012. The increase in royalty rates from the comparable periods was due to higher crude oil prices during the year, adjustments to royalties and the payout of the Baobab field in May 2011.
Offshore Africa royalty rates are anticipated to average 20% to 25% of product sales for 2012.
PRODUCTION EXPENSE – EXPLORATION AND PRODUCTION
North America
North America crude oil and NGLs production expense for the six months ended June 30, 2012 increased 13% to $14.23 per bbl from $12.57 per bbl for the six months ended June 30, 2011. North America crude oil and NGLs production expense for the second quarter of 2012 increased 2% to $13.10 per bbl from $12.86 per bbl for the second quarter of 2011 and decreased 15% from $15.40 per bbl for the first quarter of 2012. The increase in production expense for the three and six months ended June 30, 2012 from the comparable periods in 2011 was a result of higher overall service costs relating to heavy crude oil production. The decrease in production expense from the first quarter of 2012 was a result of lower primary heavy oil costs and the timing of thermal steam cycles, together with lower normal seasonal costs. North America crude oil and NGLs production expense is anticipated to average $11.00 to $13.00 per bbl for 2012.
North America natural gas production expense for the six months ended June 30, 2012 increased 11% to $1.24 per Mcf from $1.12 per Mcf for the six months ended June 30, 2011. North America natural gas production expense for the second quarter of 2012 increased 4% to $1.13 per Mcf from $1.09 per Mcf for the second quarter of 2011, and decreased 15% from $1.33 per Mcf for the first quarter of 2012. Natural gas production expense for the three and six months ended June 30, 2012 increased from the comparable periods in 2011 due to the impact of shut-in production and the acquisitions of natural gas producing properties that have higher operating costs per Mcf than the Company–s existing properties. These acquisitions closed late in the fourth quarter of 2011 and costs are expected to decline once the acquisitions are fully integrated into the Company–s operations. Natural gas production expense decreased in the second quarter of 2012 compared to the prior quarter due to normal seasonality. North America natural gas production expense is anticipated to average $1.15 to $1.20 per Mcf for 2012.
North Sea
North Sea crude oil production expense for the six months ended June 30, 2012 increased 55% to $50.21 per bbl from $32.46 per bbl for the six months ended June 30, 2011. North Sea crude oil production expense for the second quarter of 2012 increased to $68.32 per bbl from $34.20 per bbl for the second quarter of 2011, and increased 87% from $36.53 per bbl the first quarter of 2012. Production expense increased on a per barrel basis from the comparable periods due to lower production volumes on relatively fixed costs, partially related to the 20 day shut in of the third-party operated pipeline to Sullom Voe, and higher maintenance costs. North Sea crude oil production expense is anticipated to average $48.00 to $52.00 per bbl for 2012.
Offshore Africa
Offshore Africa crude oil production expense decreased 9% to $18.29 per bbl from $20.04 per bbl for the six months ended June 30, 2012. Offshore Africa crude oil production expense for the second quarter of 2012 averaged $22.94 per bbl, an increase of 7% compared with $21.36 per bbl for the second quarter of 2011 and an increase of 88% compared with $12.17 per bbl for the first quarter of 2012. Production expense for the three and six months ended June 30, 2012 fluctuated from the comparable periods as a result of the timing of liftings from various fields, which have different cost structures. Offshore Africa crude oil production expense is anticipated to average $26.50 to $28.50 per bbl for 2012.
DEPLETION, DEPRECIATION AND AMORTIZATION – EXPLORATION AND PRODUCTION
Depletion, depreciation and amortization expense increased for the six months ended June 30, 2012 compared with 2011 due to higher sales volumes in North America associated with heavy oil drilling and the impact of higher future development costs.
ASSET RETIREMENT OBLIGATION ACCRETION – EXPLORATION AND PRODUCTION
Asset retirement obligation accretion expense represents the increase in the carrying amount of the asset retirement obligation due to the passage of time.
OPERATING HIGHLIGHTS – OIL SANDS MINING AND UPGRADING
OPERATIONS UPDATE
On March 13, 2012 the Company successfully and safely completed the unplanned maintenance on the fractionating unit in the primary upgrading facility. The positive impact of the third OPP and continued emphasis on safe, steady and reliable operations resulted in strong operational performance across Horizon, with production exceeding the Company–s previously issued guidance of between 105,000 and 115,000 bbl/d of SCO.
PRODUCT PRICES AND ROYALTIES – OIL SANDS MINING AND UPGRADING
Realized SCO sales prices averaged $91.84 per bbl for the six months ended June 30, 2012. Realized SCO sales prices averaged $88.11 per bbl for the second quarter of 2012, a decrease of 9% compared with $97.09 per bbl for the first quarter of 2012, reflecting the relative changes in WTI and Brent benchmark pricing.
PRODUCTION COSTS – OIL SANDS MINING AND UPGRADING
The following tables are reconciled to the Oil Sands Mining and Upgrading production costs disclosed in the Company–s unaudited interim consolidated financial statements.
Adjusted cash production costs averaged $39.61 per bbl for the six months ended June 30, 2012 compared with $45.69 per bbl for the six months ended June 30, 2011. Cash production costs for the second quarter of 2012 averaged $36.98 per bbl, a decrease of 20% compared with adjusted cash production costs of $46.24 per bbl in the first quarter of 2012. The decrease in cash production costs per bbl from the comparable periods was primarily due to steady and reliable production during the second quarter of 2012.
DEPLETION, DEPRECIATION AND AMORTIZATION – OIL SANDS MINING AND UPGRADING
Depletion, depreciation and amortization expense for the three and six months ended June 30, 2012 increased from the comparable periods primarily due to higher sales volumes.
ASSET RETIREMENT OBLIGATION ACCRETION – OIL SANDS MINING AND UPGRADING
Asset retirement obligation accretion expense represents the increase in the carrying amount of the asset retirement obligation due to the passage of time.
MIDSTREAM
Midstream operating results were consistent with the comparable periods.
ADMINISTRATION EXPENSE
Administration expe