CALGARY, ALBERTA--(Marketwire - Aug. 6, 2009) - Canadian Natural Resources Limited (TSX:CNQ) (NYSE:CNQ)
Canadian Natural's Chairman, Allan Markin, stated, "The ramp-up of production at Horizon continued to go well during the second quarter with production of SCO exceeding our corporate guidance. While we have made significant progress and remain optimistic about ramp-up, we are cognizant of the challenges associated with getting a facility of this size and complexity operating consistently and reliably at design capacity. Horizon and Offshore West Africa contributed to an 11% crude oil production growth quarter over quarter."
John Langille, Vice-Chairman of Canadian Natural continued, "For the first half of the year we benefited from favorable heavy oil differentials and our hedging program contributed to strong cash flow. During the quarter, the commencement of SCO sales from Horizon added to cash flow which helped offset the impact of weak natural gas prices and the expected declines in natural gas production. We continue to focus on internally generated cash flow, our flexible capital allocation and balance sheet strength."
Steve Laut, President and Chief Operating Officer of Canadian Natural concluded, "The strength and value of Canadian Natural's strategy, our balanced asset base and ability to quickly respond to changing market conditions has never been more clear. Our current focus remains on crude oil as returns continue to be more attractive than natural gas. We have increased drilling on heavy crude oil which benefited from narrow pricing differentials relative to WTI during the second quarter. We are also concentrating on ramping up production at Horizon which is providing high-quality, high-value crude oil. For natural gas we will continue to position the Company by maintaining our extensive land base, building an even stronger inventory of prospects and focusing on cost reduction and control until economics significantly improve for natural gas projects."
HIGHLIGHTS
Three Months Ended Six Months Ended
($ millions, -------------------------------------------------
except as noted) Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
2009 2009 2008 2009 2008
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Net earnings (loss) $ 162 $ 305 $ (347) $ 467 $ 380
per common share, basic
and diluted $ 0.30 $ 0.56 $ (0.65) $ 0.86 $ 0.70
Adjusted net earnings from
operations (1) $ 637 $ 727 $ 960 $ 1,364 $ 1,832
per common share, basic
and diluted $ 1.18 $ 1.34 $ 1.78 $ 2.52 $ 3.39
Cash flow from
operations (2) $ 1,365 $1,516 $ 1,859 $ 2,881 $ 3,584
per common share, basic
and diluted $ 2.52 $ 2.80 $ 3.44 $ 5.32 $ 6.63
Capital expenditures, net
of dispositions $ 473 $1,256 $ 2,127 $ 1,729 $ 3,880
Daily production, before
royalties
Natural gas (mmcf/d) 1,352 1,369 1,526 1,360 1,532
Crude oil and NGLs
(bbl/d) 365,672 330,017 319,077 347,943 323,147
Equivalent production
(boe/d) 590,984 558,142 573,437 574,654 578,461
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(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 the 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.
HIGHLIGHTS
- Total crude oil and NGLs production for Q2/09 was 365,672 bbl/d, an increase of 11% from the previous quarter. Volumes in Q2/09 reflect production from Horizon and Baobab, the commencement of production from Olowi, and continued conversion of production wells to polymer injection wells at Pelican Lake. Increased volumes were offset by the transition between steam and production cycles for Primrose thermal wells and a temporary curtailment at Primrose East.
- Natural gas production for Q2/09 averaged 1,352 mmcf/d, down 1% from the previous quarter, as expected. The decrease in volumes for Q2/09 from previous quarters reflects the continuing reallocation of capital towards higher return crude oil projects.
- Quarterly cash flow from operations was $1,365 million, a decrease of 10% from the previous quarter. The decrease from Q1/09 reflects lower natural gas price realizations and lower natural gas sales volumes, partially offset by the impact of higher crude oil price realizations and higher crude oil sales volumes.
- Quarterly net earnings for Q2/09 of $162 million included the effects of unrealized risk management activities, stock-based compensation and fluctuations in foreign exchange rates. Excluding these items, quarterly adjusted net earnings from operations for Q2/09 were $637 million, a decrease of 12% from the previous quarter.
- The drilling program at Baobab in Offshore Cote d'Ivoire was completed and the fourth well was brought on production in early Q2/09. The four re-drilled wells restored production of approximately 11,000 bbl/d net to Canadian Natural.
- First crude oil production was achieved at the Olowi Field in Offshore Gabon on April 28, 2009. Initial production volumes from Platform C are below the Company's expectations. Platforms A, B and D will be drilled and completed during the next 18 months.
- Horizon production averaged 59,599 bbl/d of SCO ("Synthetic Crude Oil") for Q2/09, with production ramp-up exceeding expectations in May and June. The overall production schedule remains unchanged, with reliable and consistent production at design capacity targeted for Q4/09.
- Declared a quarterly cash dividend on common shares of $0.105 per common share payable October 1, 2009.
OPERATIONS REVIEW
Activity by core region
---------------------------------------------
Net undeveloped land Drilling activity
as at six months ended
Jun 30, 2009 Jun 30, 2009
(thousands of net acres) (net wells)(1)
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North America conventional
Northeast British Columbia 2,147 15.0
Northwest Alberta 1,222 33.2
Northern Plains 5,944 164.1
Southern Plains 833 8.3
Southeast Saskatchewan 134 3.0
Thermal In-situ Oil Sands 489 242.0
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10,769 465.6
Oil Sands Mining and Upgrading 115 42.0
North Sea 183 0.9
Offshore West Africa 188 4.2
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11,255 512.7
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(1) Drilling activity includes stratigraphic test and service wells.
Drilling activity (number of wells)
Six Months Ended Jun 30
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2009 2008
Gross Net Gross Net
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Crude oil 192 187 284 266
Natural gas 87 64 202 166
Dry 20 19 20 17
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Subtotal 299 270 506 449
Stratigraphic test / service wells 243 243 26 26
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Total 542 513 532 475
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Success rate (excluding stratigraphic
test / service wells) 93% 96%
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North America Conventional
North America natural gas
Three Months Ended Six Months Ended
-------------------------------------------------
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
2009 2009 2008 2009 2008
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Natural gas production
(mmcf/d) 1,322 1,347 1,501 1,334 1,507
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Net wells targeting natural
gas - 72 8 72 175
Net successful wells drilled - 64 5 64 166
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Success rate - 89% 63% 89% 95%
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- Q2/09 North America natural gas production decreased 12% as expected from Q2/08, and decreased 2% from Q1/09, reflecting natural declines in base production and the Company's strategic decision to reduce spending on natural gas drilling due to stronger economics in crude oil projects.
- Canadian Natural chose to not drill any net natural gas wells in Q2/09, however completed all planned tie-ins from wells drilled during Q1/09.
- Planned drilling activity for Q3/09 includes 24 net natural gas wells. Based on near term economics, the Company continues to focus on land expiries, competitive drainage issues and advancing development of key resource projects.
North America crude oil and NGLs
Three Months Ended Six Months Ended
-------------------------------------------------
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
2009 2009 2008 2009 2008
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Crude oil and NGLs
production (bbl/d) 232,139 253,833 245,616 242,926 247,288
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Net wells targeting
crude oil 97 97 94 194 270
Net successful wells
drilled 93 90 92 183 263
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Success rate 96% 93% 98% 94% 97%
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- Q2/09 North America crude oil and NGLs production decreased 5% from Q2/08 and decreased 9% from Q1/09 levels. The majority of the decline in production volumes was in thermal crude oil as Primrose North and South transitioned to a steam cycle and a temporary curtailment of thermal steam/production cycle at Primrose East is in effect.
- As stated previously, in Q1/09 after initial steaming, Canadian Natural discovered oil seepage at the surface on one of the new multi-well pads at Primrose East. A significant amount of diagnostic work has been completed and the Company believes it has identified the issue and the remedial action required. The Company continues to proactively work with the regulators on resolving the issue and returning Primrose East to normal operations. Canadian Natural has received regulatory approval for diagnostic steaming which is targeted to commence August 2009.
- Canadian Natural is continuing its proposed third phase of the thermal growth plan with a development plan for the 45,000 bbl/d Kirby In-Situ Oil Sands Project located approximately 85 km northeast of Lac La Biche in the Regional Municipality of Wood Buffalo. The Company has filed its formal regulatory application documents for this project and is awaiting regulatory approval. Canadian Natural expects to decide in early 2010 on the timing of the development of the project.
- Development of new pads and conversion to tertiary recovery at Pelican Lake continued as expected throughout Q2/09. In Q2/09, the Company drilled 19 horizontal wells and plans to drill one vertical service well and an additional 34 horizontal wells throughout the remainder of 2009. Pelican Lake production averaged approximately 36,000 bbl/d for Q2/09.
- Conventional heavy crude oil production volumes increased slightly in Q2/09 compared to Q1/09, reflecting increased drilling in Q2/09. The Company increased drilling of heavy crude oil wells to take advantage of the pricing and narrow heavy crude oil differentials.
- During Q2/09, drilling activity targeted 97 net wells including 48 wells targeting heavy crude oil, 19 wells targeting Pelican Lake crude oil and 30 wells targeting thermal crude oil.
- Planned drilling activity for Q3/09 includes 238 net crude oil wells, excluding stratigraphic test and service wells.
International
Three Months Ended Six Months Ended
-------------------------------------------------
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
2009 2009 2008 2009 2008
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Crude oil production (bbl/d)
North Sea 40,362 42,369 45,830 41,360 47,699
Offshore West Africa 33,572 30,431 27,631 32,010 28,160
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Natural gas production
(mmcf/d)
North Sea 10 10 10 10 11
Offshore West Africa 20 12 15 16 14
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Net wells targeting crude oil 1.0 3.2 1.6 4.2 3.8
Net successful wells drilled 1.0 3.2 0.8 4.2 3.0
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Success rate 100% 100% 50% 100% 79%
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North Sea
- Production, as expected, was lower than Q1/09 due to planned maintenance shutdowns at the Ninian Field, however still exceeded the top end of the Company's production guidance range. During the quarter, focus continued on lowering costs and high grading inventory and infill drilling opportunities.
- The Deep Banff exploration well did not find commercial hydrocarbons and was plugged and abandoned early in the third quarter. Canadian Natural's net paying interest in the well was approximately 19%.
Offshore West Africa
- Offshore West Africa's crude oil production for Q2/09 was 33,572 bbl/d, an increase of 10% from Q1/09. This was largely due to the fourth and final well in the Baobab drilling program coming on line and first crude oil production from the Olowi Field.
- Progress on the Facility Upgrade Project at Espoir to increase processing capacity of the Floating Production Storage and Offtake Vessel ("FPSO") has reverted to the original schedule to accommodate effective utilization of the installation vessel at Olowi.
- At the Olowi Project in Offshore Gabon, one further production well and one gas injector well were completed. The FPSO and Conductor Supported Platform were commissioned and first production of crude oil was achieved April 28, 2009. Further drilling and development activity of Olowi will continue through 2010. Initial production volumes from Platform C are below the Company's expectations. Platforms A, B and D will be drilled and completed during the next 18 months.
Oil Sands Mining and Upgrading
Three Months Ended Six Months Ended
-------------------------------------------------
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
2009 2009 2008 2009 2008
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Synthetic Crude Oil
Production (bbl/d) 59,599 3,384 - 31,647 -
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- Horizon production in Q2/09 averaged 59,599 bbl/d of SCO, above the guidance range previously provided.
- During the quarter, the Company experienced better than expected production. The Horizon operation has tested production over the design capacity of 110,000 bbl/d of SCO on several occasions helping determine debottleneck opportunities. All major components of the plant have been tested and to date have shown no significant long term issues with design or capacity limitations.
- During the initial stages of ramp-up, as expected, production volumes continue to fluctuate. The plant continues to be fine tuned with a focus on safety, reliability, and cost control with targeted stability approaching design capacity in Q4/09.
- Engineering and procurement is underway for Tranche 2 of the Phase 2/3 expansion with a focus on increasing reliability and uptime. Tranches 3 and 4 of Phase 2/3 continue to be re-profiled. The Company continues to work on completing its lessons learned from the construction of Phase 1 and implementing these into the development of future expansions.
MARKETING
Three Months Ended Six Months Ended
-------------------------------------------------
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
2009 2009 2008 2009 2008
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Crude oil and NGLs pricing
WTI (1) benchmark price
(US$/bbl) $ 59.61 $ 43.21 $ 124.00 $ 51.46 $ 110.98
Western Canadian Select
blend differential from
WTI (%) 13% 21% 17% 16% 19%
SCO (discount) premium
from WTI (US$/bbl) $ (1.19) $ 1.76 $ 4.78 $ 0.28 $ 3.80
Corporate average pricing
before risk management
(C$/bbl) $ 59.56 $ 41.25 $ 103.73 $ 50.12 $ 91.11
Natural gas pricing
AECO benchmark price
(C$/GJ) $ 3.46 $ 5.34 $ 8.86 $ 4.40 $ 7.81
Corporate average
pricing before risk
management (C$/mcf) $ 4.11 $ 5.46 $ 9.89 $ 4.78 $ 8.83
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(1) Refers to West Texas Intermediate (WTI) crude oil barrel priced at
Cushing, Oklahoma.
- In Q2/09, the Western Canadian Select ("WCS") heavy crude oil differential as a percent of WTI was 13% compared to 21% in Q1/09. Heavy crude oil differentials continued to narrow in Q2/09 due to stronger demand from the US refineries for heavy crude oil. The US refineries are experiencing weak refinery margins and this tends to increase the demand for the lowest cost crude oil, which is generally heavier crude oil.
- During Q2/09, the Company allocated approximately 138,000 bbl/d of its heavy crude oil streams to the WCS blend, optimizing the pricing for heavy crude oil.
- The marketing strategy for Horizon SCO remains flexible. There is an active market for the product and Horizon SCO has been favorably accepted by refiners.
- Natural gas pricing for Q2/09 weakened compared to prior periods primarily due to supply/demand imbalances. North America natural gas inventory levels remained high during the second quarter due to lower industrial consumption and an oversupply from US producers.
FINANCIAL REVIEW
- The Company continues to believe that its internally generated cash flow from operations supported by the implementation of its commodity hedge policy, the flexibility of its capital expenditure programs supported by its multi-year financial plans, its existing credit facilities and its ability to raise new debt on commercially acceptable terms, will provide sufficient liquidity to sustain its operations in the short, medium and long-term and support its growth strategy. A brief summary of the Company's strengths are:
-- A diverse asset base geographically and by product - produced in excess of 590,000 boe/d in Q2/09, comprised of approximately 38% natural gas and 62% crude oil - with approximately 94% of production located in G8 countries.
-- Financial stability and liquidity - cash flow from operations of $1,365 million for Q2/09, with available unused bank lines of $1,749 million at June 30, 2009.
-- Reduced volatility of commodity prices - a proactive commodity hedging program to reduce the downside risk of volatility in commodity prices supporting cash flow for its capital expenditure program.
-- In Q2/09 the Company repaid $560 million on the non-revolving syndicated acquisition credit facility maturing in October 2009. An additional $350 million has been repaid to date in Q3/09.
-- A strengthening balance sheet with debt to book capitalization of 39% and debt to EBITDA of 1.8 times, both within targeted ranges.
- Declared a quarterly cash dividend on common shares of C$0.105 per common share, payable October 1, 2009.
OUTLOOK
- The Company forecasts 2009 production levels before royalties to average between 1,289 and 1,330 mmcf/d of natural gas and between 346,000 and 382,000 bbl/d of crude oil and NGLs. Q3/09 production guidance before royalties is forecast to average between 1,274 and 1,304 mmcf/d of natural gas and between 363,000 and 389,000 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 http://www.cnrl.com/investor_info/corporate_guidance/.
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, production volumes, royalties, operating costs, capital expenditures 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 Horizon Oil Sands, Primrose East, Pelican Lake, Gabon Offshore West Africa, and the Kirby Oil Sands Project 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 if 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 and 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 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 difficulties in mining, extracting or upgrading 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; 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, bitumen, natural gas and liquids 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 should circumstances or Management's estimates or opinions change.
Management's Discussion and Analysis
Management's Discussion and Analysis 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 six months ended June 30, 2009 and the MD&A and the audited consolidated financial statements for the year ended December 31, 2008.
All dollar amounts are referenced in millions of Canadian dollars, except where noted otherwise. The financial statements have been prepared in accordance with generally accepted accounting principles in Canada ("GAAP"). 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 GAAP 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 GAAP, 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 GAAP, 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.
The calculation of barrels of oil equivalent ("boe") is based on a conversion ratio of six thousand cubic feet ("mcf") of natural gas to one barrel ("bbl") of crude oil to estimate relative energy content. This conversion may be misleading, particularly when used in isolation, since the 6 mcf:1 bbl ratio is based on an energy equivalency at the burner tip and does not represent the value equivalency at the wellhead.
Production volumes and per barrel 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 six and three months ended June 30, 2009 in relation to the comparable periods in 2008 and the first quarter of 2009. The accompanying tables form an integral part of this MD&A. This MD&A is dated August 4, 2009. Additional information relating to the Company, including its Annual Information Form for the year ended December 31, 2008, is available on SEDAR at www.sedar.com.
FINANCIAL HIGHLIGHTS
($ millions, except per common share amounts)
Three Months Ended Six Months Ended
-------------------------------------------------
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
2009 2009 2008 2009 2008
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Revenue, before royalties $ 2,750 $ 2,186 $ 5,112 $ 4,936 $ 9,079
Net earnings (loss) $ 162 $ 305 $ (347) $ 467 $ 380
Per common share - basic
and diluted $ 0.30 $ 0.56 $ (0.65) $ 0.86 $ 0.70
Adjusted net earnings from
operations(1) $ 637 $ 727 $ 960 $ 1,364 $ 1,832
Per common share - basic
and diluted $ 1.18 $ 1.34 $ 1.78 $ 2.52 $ 3.39
Cash flow from
operations(2) $ 1,365 $ 1,516 $ 1,859 $ 2,881 $ 3,584
Per common share - basic
and diluted $ 2.52 $ 2.80 $ 3.44 $ 5.32 $ 6.63
Capital expenditures, net
of dispositions $ 473 $ 1,256 $ 2,127 $ 1,729 $ 3,880
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(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
Three Months Ended Six Months Ended
-------------------------------------------------
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
($ millions) 2009 2009 2008 2009 2008
----------------------------------------------------------------------------
Net earnings (loss) as
reported $ 162 $ 305 $ (347) $ 467 $ 380
Stock-based compensation
expense, net of tax(a) 67 3 328 70 328
Unrealized risk management
loss, net of tax(b) 676 320 997 996 1,073
Unrealized foreign exchange
(gain) loss, net of tax(c) (268) 118 (18) (150) 92
Effect of statutory tax rate
and other legislative
changes on future income
tax liabilities(d) - (19) - (19) (41)
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Adjusted net earnings from
operations $ 637 $ 727 $ 960 $ 1,364 $ 1,832
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(a) The Company's employee stock option plan provides for a cash payment
option. Accordingly, the intrinsic value of the outstanding vested
options is recorded as a liability on the Company's balance sheet and
periodic changes in the intrinsic 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 sheet, 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) 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 sheet in
determining future 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 or
enacted. Income tax rate changes in the first quarter of 2009 resulted
in a reduction of future income tax liabilities of approximately $19
million in North America. Income tax rate changes in the first quarter
of 2008 resulted in a reduction of future income tax liabilities of
approximately $19 million in North America and $22 million in Cote
d'Ivoire, Offshore West Africa.
Cash Flow from Operations
Three Months Ended Six Months Ended
-------------------------------------------------
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
($ millions) 2009 2009 2008 2009 2008
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Net earnings (loss) $ 162 $ 305 $ (347) $ 467 $ 380
Non-cash items:
Depletion, depreciation
and amortization 664 646 670 1,310 1,358
Asset retirement
obligation accretion 24 19 17 43 34
Stock-based compensation
expense 92 4 459 96 459
Unrealized risk management
loss 946 463 1,415 1,409 1,523
Unrealized foreign
exchange (gain) loss (320) 138 (20) (182) 106
Deferred petroleum revenue
tax recovery (2) (3) (34) (5) (55)
Future income tax recovery (201) (56) (301) (257) (221)
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Cash flow from operations $ 1,365 $ 1,516 $ 1,859 $ 2,881 $ 3,584
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SUMMARY OF CONSOLIDATED NET EARNINGS AND CASH FLOW FROM OPERATIONS
Net earnings for the six months ended June 30, 2009 were $467 million compared to $380 million for the six months ended June 30, 2008. Net earnings for the six months ended June 30, 2009 included net unrealized after-tax expenses of $897 million related to the effects of risk management activities, fluctuations in foreign exchange rates, fluctuations in stock-based compensation expense, and the impact of statutory tax rate changes on future income tax liabilities, compared to net unrealized after-tax expenses of $1,452 million for the six months ended June 30, 2008. Excluding these items, adjusted net earnings from operations for the six months ended June 30, 2009 were $1,364 million compared to $1,832 million for the six months ended June 30, 2008. The decrease in adjusted net earnings from the six months ended June 30, 2008 was primarily due to the impact of lower realized pricing, lower natural gas sales volumes, higher production expenses, higher interest expense, and higher realized foreign exchange losses, partially offset by the impact of higher crude oil sales volumes related to the commencement of operations of Horizon Oil Sands ("Horizon"), higher realized risk management gains, lower depletion, depreciation and amortization expense, lower royalty expense, and the impact of the weaker Canadian dollar relative to the US dollar.
Net earnings for the second quarter of 2009 were $162 million compared to a net loss of $347 million for the second quarter of 2008 and net earnings of $305 million for the prior quarter. Net earnings for the second quarter of 2009 included net unrealized after-tax expenses of $475 million related to the effects of risk management activities, fluctuations in foreign exchange rates, and fluctuations in stock-based compensation expense, compared to net unrealized after-tax expenses of $1,307 million for the second quarter of 2008 and net unrealized after-tax expenses of $422 million for the prior quarter. Excluding these items, adjusted net earnings from operations for the second quarter of 2009 were $637 million compared to $960 million for the second quarter of 2008 and $727 million for the prior quarter. The decrease in adjusted net earnings from the second quarter of 2008 was primarily due to the impact of lower realized pricing, lower natural gas sales volumes, higher production expense, and higher interest expense, partially offset by the impact of higher realized risk management gains, lower royalty expense, and the impact of the weaker Canadian dollar relative to the US dollar. The decrease in adjusted net earnings from the prior quarter was primarily due to the impact of lower natural gas sales volumes and realized pricing, lower realized risk management gains, higher depletion, depreciation and amortization expense, higher royalty and production expense, higher interest expense, and the impact of the stronger Canadian dollar relative to the US dollar, partially offset by the impact of higher crude oil sales volumes related to the commencement of operations of Horizon and higher realized crude oil pricing.
The impacts of unrealized risk management activities, stock-based compensation, and changes in foreign exchange rates are expected to continue to contribute to significant 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, 2009 was $2,881 million compared to $3,584 million for the six months ended June 30, 2008. Cash flow from operations for the second quarter of 2009 was $1,365 million compared to $1,859 million for the second quarter of 2008 and $1,516 million for the prior quarter. The decrease in cash flow from operations from the comparable periods in 2008 was primarily due to the impact of lower realized pricing, lower natural gas sales volumes, higher production expense, higher interest expense, and higher realized foreign exchange losses, partially offset by the impact of higher crude oil sales volumes related to the commencement of operations of Horizon, higher realized risk management gains, lower royalty expense, lower current income tax and current Production Revenue Tax ("PRT") expense, and the impact of the weaker Canadian dollar relative to the US dollar. The decrease in cash flow from operations from the prior quarter was primarily due to the impact of lower natural gas sales volumes, lower realized natural gas pricing, lower realized risk management gains, higher royalty and production expense, higher interest expense, higher realized foreign exchange losses, higher current PRT, and the impact of the stronger Canadian dollar relative to the US dollar, partially offset by the impact of higher crude oil sales volumes related to the commencement of operations of Horizon, higher realized crude oil pricing, and lower current income tax expense.
During 2009, the Company achieved first production of synthetic crude oil ("SCO") at Horizon in connection with the commencement of operations. The Company continues to focus on stabilizing and ramping up production as the plant is fine tuned with a focus on safety, reliability, and cost control. The results of operations for Horizon are included in the Oil Sands Mining and Upgrading segment.
Total production before royalties for the six months ended June 30, 2009 decreased 1% to 574,654 boe/d from 578,461 boe/d for the six months ended June 30, 2008. Total production before royalties for the second quarter of 2009 increased 3% to 590,984 boe/d from 573,437 boe/d for the second quarter of 2008 and increased 6% from 558,142 boe/d for the prior quarter. Total production for the second quarter of 2009 was above the Company's previously issued guidance.
For a discussion of the impact of current worldwide financial and economic events, please refer to the "Liquidity and Capital Resources" section of this MD&A.
SUMMARY OF QUARTERLY RESULTS
The following is a summary of the Company's quarterly results for the eight most recently completed quarters:
($ millions, except per Jun 30 Mar 31 Dec 31 Sep 30
common share amounts) 2009 2009 2008 2008
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Revenue, before royalties $ 2,750 $ 2,186 $ 2,511 $ 4,583
Net earnings $ 162 $ 305 $ 1,770 $ 2,835
Net earnings per common share
- Basic and diluted $ 0.30 $ 0.56 $ 3.27 $ 5.25
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($ millions, except per Jun 30 Mar 31 Dec 31 Sep 30
common share amounts) 2008 2008 2007 2007
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Revenue, before royalties $ 5,112 $ 3,967 $ 3,200 $ 3,073
Net earnings (loss) $ (347) $ 727 $ 798 $ 700
Net earnings (loss) per common share
- Basic and diluted $ (0.65) $ 1.35 $ 1.48 $ 1.30
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Volatility in quarterly net earnings (loss) over the eight most recently completed quarters was primarily due to:
- Crude oil pricing - The impact of fluctuating demand and geopolitical uncertainties on worldwide benchmark pricing, and the fluctuations in the Heavy Crude Oil Differential from WTI ("Heavy Differential") in North America.
- Natural gas pricing - The impact of seasonal 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 - Increased production from the Company's Primrose thermal projects, the results from the Pelican Lake water and polymer flood projects, and the commencement of operations of Horizon. Sales volumes also reflected fluctuations due to timing of liftings and maintenance activities in the North Sea and Offshore West Africa and the impact of the shut in, and subsequent restoration, of some of the Baobab Field production.
- Natural gas sales volumes - Production declines due to the Company's strategic decision to reduce natural gas drilling activity in North America due to the allocation of capital to higher return crude oil projects, as well as natural decline rates.
- Production expense - Fluctuations company wide, primarily due to the impact of the demand for services, industry-wide inflationary cost pressures experienced in prior quarters in all segments, fluctuations in product mix, and the impact of seasonal costs that are dependent on weather.
- Depletion, depreciation and amortization - Fluctuations due to changes in sales volumes, finding and development costs associated with crude oil and natural gas exploration, and estimated future costs to develop the Company's proved undeveloped reserves.
- Stock-based compensation - Fluctuations due to the mark-to-market movements of the Company's stock-based compensation liability. Stock-based compensation expense (recovery) reflected fluctuations in the Company's share price over the eight most recently completed quarters.
- Risk management - Fluctuations due to the recognition of realized and unrealized gains and losses from the mark-to-market and subsequent settlement of the Company's risk management activities.
- Foreign exchange rates - Fluctuations in the Canadian dollar relative to the US dollar 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. Similarly, unrealized foreign exchange gains and losses were recorded with respect to US dollar denominated debt and the re-measurement of North Sea future income tax liabilities denominated in UK pounds sterling to US dollars, partially offset by the impact of cross currency swap hedges.
- Changes in income tax expense (recovery) - Fluctuations in income tax expense (recovery) include statutory tax rate and other legislative changes substantively enacted or enacted in the various periods.
BUSINESS ENVIRONMENT
Three Months Ended Six Months Ended
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Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
2009 2009 2008 2009 2008
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WTI benchmark price
(US$/bbl) $ 59.61 $ 43.21 $ 124.00 $ 51.46 $ 110.98
Dated Brent benchmark
price (US$/bbl) $ 58.78 $ 44.45 $ 121.39 $ 51.65 $ 109.17
WCS blend differential
from WTI (US$/bbl) $ 7.43 $ 8.98 $ 21.62 $ 8.20 $ 21.51
WCS blend differential
from WTI(%) 13% 21% 17% 16% 19%
SCO (discount) premium
from WTI (US$/bbl) $ (1.19) $ 1.76 $ 4.78 $ 0.28 $ 3.80
Condensate benchmark
price (US$/bbl) $ 58.30 $ 43.44 $ 124.64 $ 50.91 $ 111.52
NYMEX benchmark price
(US$/mmbtu) $ 3.59 $ 4.87 $ 10.80 $ 4.23 $ 9.44
AECO benchmark price
(C$/GJ) $ 3.46 $ 5.34 $ 8.86 $ 4.40 $ 7.81
US / Canadian dollar
average exchange rate $ 0.8571 $ 0.8028 $ 0.9900 $ 0.8293 $ 0.9929
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Commodity Prices
Crude oil sales contracts in the North America segment are typically based on WTI benchmark pricing. WTI averaged US$51.46 per bbl for the six months ended June 30, 2009, a decrease of 54% from US$110.98 per bbl for the six months ended June 30, 2008. WTI averaged US$59.61 per bbl for the second quarter of 2009, a decrease of 52% from US$124.00 per bbl for the second quarter of 2008, and an increase of 38% from US$43.21 per bbl for the prior quarter. Despite the increase in WTI pricing from the prior quarter, WTI pricing during the second quarter of 2009 continued to be impacted by a significant decrease in demand as a result of worldwide financial and economic events and ongoing geopolitical uncertainty resulting in increased market volatility.
Crude oil sales contracts for the Company's North Sea and Offshore West Africa segments are typically based on Dated Brent ("Brent") pricing, which also continued to be impacted by worldwide financial and economic events during the second quarter of 2009. Brent averaged US$51.65 per bbl for the six months ended June 30, 2009, a decrease of 53% compared to US$109.17 per bbl for the six months ended June 30, 2008. Brent averaged US$58.78 per bbl for the second quarter of 2009, a decrease of 52% compared to US$121.39 per bbl for the second quarter of 2008, and an increase of 32% from US$44.45 per bbl for the prior quarter.
The Heavy Differential averaged 16% for the six months ended June 30, 2009 compared to 19% for the six months ended June 30, 2008. The Heavy Differential averaged 13% for the second quarter of 2009 compared to 17% for the second quarter of 2008, and 21% for the prior quarter. The narrowing of the Heavy Differential from the prior periods was primarily due to relatively weak refinery margins and lower supply available from Venezuela and Mexico. The Heavy differential was narrower in the second quarter as economic events resulted in lower demand for finished products and a market oversupplied with crude oil. Generally, reduced refinery margins lead to lower refinery utilization and narrower heavy oil differentials.
During the second quarter of 2009, the Company began marketing SCO production from Horizon. SCO is generally priced using the WTI benchmark.
The Company anticipates continued volatility in the crude oil pricing benchmarks due to the unpredictable nature of supply and demand factors, geopolitical events and the global economic slowdown resulting from worldwide financial and economic events. The Heavy Differential is expected to reflect seasonal demand fluctuations and refinery margins.
NYMEX natural gas prices averaged US$4.23 per mmbtu for the six months ended June 30, 2009, a decrease of 55% from US$9.44 per mmbtu for the six months ended June 30, 2008. NYMEX natural gas prices averaged US$3.59 per mmbtu for the second quarter of 2009, a decrease of 67% from US$10.80 per mmbtu for the second quarter of 2008, and a decrease of 26% from US$4.87 per mmbtu for the prior quarter. AECO natural gas prices for the six months ended June 30, 2009 decreased 44% to average $4.40 per GJ from $7.81 per GJ for the six months ended June 30, 2008. AECO natural gas prices for the second quarter of 2009 decreased 61% to average $3.46 per GJ from $8.86 per GJ in the second quarter of 2008, and decreased 35% from $5.34 per GJ for the prior quarter. Decreases in natural gas prices from the comparable periods were primarily related to an oversupply in the market. Natural gas production continued to exceed expectations primarily as a result of new shale gas production in the United States.
Update to Alberta Royalty Framework
Effective January 1, 2009, changes to the Alberta royalty regime under the Alberta Royalty Framework ("ARF") include the implementation of a sliding scale for oil sands royalties ranging from 1% to 9% on a gross revenue basis pre-payout and 25% to 40% on a net revenue basis post-payout, depending on benchmark crude oil pricing.
In addition, effective January 1, 2009, new royalty formulas under the ARF for conventional crude oil and natural gas are to operate on sliding scales ranging up to 50%, determined by commodity prices and well productivity.
In March 2009, the Government of Alberta announced new incentive programs to stimulate activity in Alberta. These programs provide for:
- A royalty credit of $200 per meter on new conventional crude oil and natural gas wells drilled between April 1, 2009 and March 31, 2010.
- Reduced royalty rates that set the maximum royalty at 5% for the first 12 months of production, up to a maximum of 50,000 bbl or 500 mmcf, for new conventional crude oil and natural gas wells that commence production between April 1, 2009 and March 31, 2010.
In June 2009, the Government of Alberta extended the two incentive programs described above by one year, to March 31, 2011.
DAILY PRODUCTION, before royalties
Three Months Ended Six Months Ended
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Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
2009 2009 2008 2009 2008
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Crude oil and NGLs (bbl/d)
North America -
Conventional 232,139 253,833 245,616 242,926 247,288
North America - Oil Sands
Mining and Upgrading 59,599 3,384 - 31,647 -
North Sea 40,362 42,369 45,830 41,360 47,699
Offshore West Africa 33,572 30,431 27,631 32,010 28,160
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365,672 330,017 319,077 347,943 323,147
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Natural gas (mmcf/d)
North America 1,322 1,347 1,501 1,334 1,507
North Sea 10 10 10 10 11
Offshore West Africa 20 12 15 16 14
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1,352 1,369 1,526 1,360 1,532
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Total barrels of oil
equivalent (boe/d) 590,984 558,142 573,437 574,654 578,461
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Product mix
Light/medium crude oil
and NGLs 21% 22% 22% 21% 22%
Pelican Lake crude oil 6% 6% 6% 6% 6%
Primary heavy crude oil 14% 15% 16% 15% 16%
Thermal heavy crude oil 11% 15% 12% 13% 12%
Synthetic crude oil 10% 1% - 6% -
Natural gas 38% 41% 44% 39% 44%
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Percentage of gross revenue(1)
(excluding midstream revenue)
Crude oil and NGLs 79% 64% 68% 71% 68%
Natural gas 21% 36% 32% 29% 32%
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(1) Net of transportation and blending costs and excluding risk management
activities.
DAILY PRODUCTION, net of royalties
Three Months Ended Six Months Ended
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Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
2009 2009 2008 2009 2008
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Crude oil and NGLs (bbl/d)
North America -
Conventional 197,281 224,506 202,264 210,819 209,424
North America - Oil Sands
Mining and Upgrading 58,467 3,362 - 31,067 -
North Sea 40,292 42,265 45,734 41,273 47,603
Offshore West Africa 30,470 28,341 24,136 29,411 23,816
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326,510 298,474 272,134 312,570 280,843
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Natural gas (mmcf/d)
North America 1,313 1,180 1,227 1,247 1,243
North Sea 10 10 10 10 11
Offshore West Africa 18 11 13 15 12
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1,341 1,201 1,250 1,272 1,266
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Total barrels of oil
equivalent (boe/d) 550,053 498,740 480,418 524,538 491,835
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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/medium crude oil and NGLs, Pelican Lake crude oil, primary heavy crude oil, thermal heavy crude oil, and SCO.
Total crude oil and NGLs production for the six months ended June 30, 2009 increased 8% to 347,943 bbl/d from 323,147 bbl/d for the six months ended June 30, 2008. The increase from the comparable period was primarily due to the commencement of production from Horizon and the Olowi Field in Offshore Gabon.
Total crude oil and NGLs production for the second quarter of 2009 increased 15% to 365,672 bbl/d from 319,077 bbl/d for the second quarter of 2008, and increased 11% from 330,017 bbl/d for the prior quarter. The increase from the second quarter in 2008 and the prior quarter was primarily due to production from Horizon and the commencement of production from the Olowi Field in Offshore Gabon. Crude oil and NGLs production in the second quarter of 2009 was above the Company's previously issued guidance of 321,000 to 359,000 bbl/d.
Natural gas production continued to represent the Company's largest product offering for the six months ended June 30, 2009, accounting for 39% of the Company's total production. Natural gas production for the six months ended June 30, 2009 averaged 1,360 mmcf/d compared to 1,532 mmcf/d for the six months ended June 30, 2008. Natural gas production for the second quarter of 2009 averaged 1,352 mmcf/d compared to 1,526 mmcf/d for the second quarter of 2008 and 1,369 mmcf/d for the prior quarter. The decrease in natural gas production from the comparable periods primarily reflected production declines due to the Company's strategic reduction in natural gas drilling activity. Natural gas production in the second quarter of 2009 was on the high end of the Company's previously issued guidance of 1,318 to 1,353 mmcf/d.
For 2009, revised annual production guidance is targeted to average between 346,000 and 382,000 bbl/d of crude oil and NGLs and between 1,289 and 1,330 mmcf/d of natural gas. Third quarter 2009 production guidance is targeted to average between 363,000 and 389,000 bbl/d of crude oil and NGLs and between 1,274 and 1,304 mmcf/d of natural gas.
North America - Conventional
North America conventional crude oil and NGLs production for the six months ended June 30, 2009 decreased 2% to average 242,926 bbl/d from 247,288 bbl/d for the six months ended June 30, 2008. Second quarter North America conventional crude oil and NGLs production decreased 5% to average 232,139 bbl/d from 245,616 bbl/d for the second quarter of 2008, and decreased 9% from 253,833 bbl/d for the prior quarter. The decrease in crude oil and NGLs production from the prior periods was primarily due to the cyclic nature of the Company's thermal production and was in line with expectations. Production of conventional crude oil and NGLs exceeded the Company's previously issued guidance of 217,000 bbl/d to 227,000 bbl/d for the second quarter of 2009.
Natural gas production for the six months ended June 30, 2009 decreased 11% to 1,334 mmcf/d from 1,507 mmcf/d for the six months ended June 30, 2008. For the second quarter of 2009, natural gas production decreased 12% to 1,322 mmcf/d from 1,501 mmcf/d for the second quarter of 2008, and decreased 2% from 1,347 mmcf/d for the prior quarter. The decreases in natural gas production were consistent with the Company's strategic decision to reduce natural gas drilling activity.
North America - Oil Sands Mining and Upgrading
Horizon Phase 1 achieved first production of synthetic crude oil during 2009. Production for the six months ended June 30, 2009 averaged 31,647 bbl/d and averaged 59,599 bbl/d in the second quarter of 2009. Production volumes fluctuated throughout the quarter as the Company continued to stabilize and ramp up production, and exceeded the Company's previously issued guidance of 35,000 bbl/d to 55,000 bbl/d for the second quarter of 2009.
North Sea
North Sea crude oil production for the six months ended June 30, 2009 decreased 13% to 41,360 bbl/d from 47,699 bbl/d for the six months ended June 30, 2008. Second quarter North Sea crude oil production decreased 12% to 40,362 bbl/d from 45,830 bbl/d for the second quarter of 2008 and 5% from 42,369 bbl/d for the prior quarter. Production in the second quarter of 2009 was at the high end of the Company's previously issued guidance and reflected planned maintenance shutdowns at two of the Ninian platforms.
Offshore West Africa
Offshore West Africa crude oil production increased 14% to 32,010 bbl/d for the six months ended June 30, 2009 from 28,160 bbl/d for the six months ended June 30, 2008. Second quarter Offshore West Africa crude oil production increased 22% to 33,572 bbl/d from 27,631 bbl/d for the second quarter of 2008, and 10% from 30,431 bbl/d for the prior quarter. During the second quarter of 2009, the fourth and final well in the Baobab Field drilling program was completed and came on stream, and first production was achieved at the Olowi Field in Offshore Gabon.
Crude Oil Inventory Volumes
The Company recognizes revenue on its crude oil production when title transfers to the customer and delivery has taken place.
