Canadian Natural Resources Limited Announces 2009 Third Quarter Results and 2010 Budget
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CALGARY, ALBERTA -- (MARKET WIRE) -- 11/05/09 -- Canadian Natural Resources Limited (TSX: CNQ) (NYSE: CNQ)
Canadian Natural's Chairman, Allan Markin, stated, "The third quarter was strong for Canadian Natural as we met all of our production targets, with the exception of Horizon, which encountered certain unexpected challenges during the ramp-up of its production levels. The challenges at Horizon are manageable and our teams are doing a great job in identifying and mitigating these issues. We continue to execute our defined growth plan in 2010, with all areas providing positive free cash flow in the range of $2.6 to $3.0 billion while still delivering 7% production growth."
Canadian Natural's Vice-Chairman, John Langille, continued, "Our balance sheet continued to strengthen during the quarter as we completed the retirement of the $2.3 billion non-revolving syndicated acquisition credit facility, with all payments made from internally generated cash flow. This brings our debt to book capitalization to 36%, essentially at the low end of our targeted range. Our debt to EBITDA is 1.6x, which is below our targeted range. Crude oil prices and the heavy oil differential remained favorable, and along with our hedging program, helped to mitigate the impact of weak natural gas prices. Looking to 2010, overall budget capital spending will be increased over 2009 levels but remains well within targeted cash flow, resulting in even further balance sheet strength."
Steve Laut, President and Chief Operating Officer of Canadian Natural concluded, "Our 2010 budget represents a prudent yet flexible approach to developing our world class assets. For 2010, budgeted capital spending is targeted to increase 26% over 2009 with over 80% of our capital allocated to the development of our crude oil assets. We will continue our disciplined, step-wise development of our vast heavy crude oil properties and start to unlock the significant EOR potential of our light crude oil properties in Canada. We will complete the Olowi development in West Africa and resume platform drilling in the North Sea. Spending at Horizon for the coming year is focused on Tranche 2 of Phases 2/3 and features a significant expenditure on developing a detailed cost estimate for future expansions. This capital budget provides us with the flexibility to react to fluctuations within the business environment. If economic conditions improve significantly during the coming year or other opportunities arise, we have the assets and the ability to focus capital on the projects that provide the greatest value and highest returns."
QUARTERLY HIGHLIGHTS
Three Months Ended Nine Months Ended
--------------------------------------------------
($ millions, except as Sep 30 Jun 30 Sep 30 Sep 30 Sep 30
noted) 2009 2009 2008 2009 2008
----------------------------------------------------------------------------
Net earnings (loss) $ 658 $ 162 $ 2,835 $ 1,125 $ 3,215
per common share, basic
and diluted $ 1.21 $ 0.30 $ 5.25 $ 2.07 $ 5.95
Adjusted net earnings
from operations (1) $ 658 $ 637 $ 963 $ 2,022 $ 2,795
per common share, basic
and diluted $ 1.21 $ 1.18 $ 1.78 $ 3.73 $ 5.17
Cash flow from
operations (2) $ 1,506 $ 1,365 $ 1,815 $ 4,387 $ 5,399
per common share, basic
and diluted $ 2.78 $ 2.52 $ 3.36 $ 8.10 $ 9.99
Capital expenditures, net
of dispositions $ 574 $ 473 $ 1,744 $ 2,303 $ 5,624
Daily production, before
royalties
Natural gas (mmcf/d) 1,293 1,352 1,490 1,338 1,518
Crude oil and NGLs
(bbl/d) 359,269 365,672 306,970 351,760 317,715
Equivalent production
(boe/d) 574,755 590,984 555,356 574,688 570,704
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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.
- Total crude oil and NGLs production for Q3/09 was 359,269 bbl/d, an increase of 17% from Q3/08 volumes. Higher volumes in Q3/09 reflect production increases from Horizon Oil Sands Mining and Upgrading ("Horizon"), Baobab and Olowi offset by the temporary curtailment of steaming/production at Primrose East and planned maintenance in the North Sea.
- Natural gas production for Q3/09 averaged 1,293 mmcf/d, down 13% from Q3/08, as expected. The decrease in volumes for Q3/09 from previous quarters reflects the continuing reallocation of capital towards higher return crude oil projects.
- Quarterly cash flow from operations was $1,506 million, an increase of 10% from the previous quarter and a decrease of 17% from Q3/08. The increase from Q2/09 reflects higher crude oil price realizations partially offset by lower natural gas price realizations and lower natural gas sales volumes. The decrease from Q3/08 reflects lower crude oil and natural gas price realizations, partially offset by higher crude oil production.
- Quarterly net earnings and adjusted net earnings for Q3/09 was $658 million.
- Horizon production averaged 66,907 bbl/d of Synthetic Crude Oil ("SCO") for Q3/09 up from 59,599 bbl/d of SCO average production in Q2/09. The volumes were less than targeted due to a number of unforeseen production challenges that arose mid-way through the third quarter.
- Declared a quarterly cash dividend on common shares of $0.105 per common share payable January 1, 2010.
OPERATIONS REVIEW
Activity by core region
----------------------------------------------
Net undeveloped land Drilling activity
as at nine months ended
Sep 30, 2009 Sep 30, 2009
(thousands of net acres) (net wells) (1)
----------------------------------------------------------------------------
North America conventional
Northeast British Columbia 2,068 17.0
Northwest Alberta 1,184 39.5
Northern Plains 5,940 407.3
Southern Plains 813 11.4
Southeast Saskatchewan 138 13.4
Thermal In-situ Oil Sands 487 270.0
----------------------------------------------------------------------------
10,630 758.6
Oil Sands Mining and Upgrading 115 42.0
North Sea 180 1.2
Offshore West Africa 188 6.1
----------------------------------------------------------------------------
11,113 807.9
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Drilling activity includes stratigraphic test and service wells.
Drilling activity (number of wells)
Nine Months Ended Sep 30
-------------------------------------
2009 2008
Gross Net Gross Net
----------------------------------------------------------------------------
Crude oil 476 449 529 500
Natural gas 107 81 304 228
Dry 32 29 32 28
----------------------------------------------------------------------------
Subtotal 615 559 865 756
Stratigraphic test / service wells 249 249 36 34
----------------------------------------------------------------------------
Total 864 808 901 790
----------------------------------------------------------------------------
Success rate (excluding
stratigraphic test / service wells) 95% 96%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
North America Conventional
North America natural gas
Three Months Ended Nine Months Ended
--------------------------------------------------
Sep 30 Jun 30 Sep 30 Sep 30 Sep 30
2009 2009 2008 2009 2008
----------------------------------------------------------------------------
Natural gas production
(mmcf/d) 1,264 1,322 1,467 1,311 1,494
----------------------------------------------------------------------------
Net wells targeting
natural gas 17 - 62 89 237
Net successful wells
drilled 17 - 62 81 228
----------------------------------------------------------------------------
Success rate 100% - 100% 91% 96%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
- Q3/09 North America natural gas production, as expected, decreased 14% from Q3/08 and 4% from Q2/09, 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 targeted 17 net natural gas wells in Q3/09, including 2 wells in Northeast British Columbia, 8 wells in the Northern Plains region, 6 wells in Northwest Alberta, and 1 well in the Southern Plains region.
- Planned drilling activity for Q4/09 includes 25 net natural gas wells. In light of current natural gas economics, including pricing and the impact of Alberta's royalty regime, the Company continues to focus on land expiries, competitive drainage issues and advancing development of key resource projects, such as those identified in the Montney formation of British Columbia.
North America crude oil and NGLs
Three Months Ended Nine Months Ended
--------------------------------------------------
Sep 30 Jun 30 Sep 30 Sep 30 Sep 30
2009 2009 2008 2009 2008
----------------------------------------------------------------------------
Crude oil and NGLs
production (bbl/d) 223,307 232,139 239,973 236,315 244,832
----------------------------------------------------------------------------
Net wells targeting crude
oil 270 97 244 464 514
Net successful wells
drilled 260 93 233 443 496
----------------------------------------------------------------------------
Success rate 96% 96% 95% 95% 96%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
- Q3/09 North America crude oil and NGLs production decreased 7% from Q3/08 and 4% from Q2/09 levels. The majority of the decline in production volumes was in thermal crude oil reflecting Primrose North and South normal steam/production cycles, and the temporary curtailment of the thermal steam/production cycle at Primrose East.
- As previously disclosed, in Q1/09 after initial steaming at Primrose East, Canadian Natural discovered oil seepage at surface on one of the new multi well pads. A significant amount of investigative work was completed and the Company formalized and received approval for a plan to begin diagnostic steaming which commenced in August of this year. The Company continues to proactively work with the regulators to identify and resolve the issue and facilitate the prudent return of Primrose East to normal operations.
- Canadian Natural is continuing its proposed third phase of its defined thermal growth plan with development of the Kirby In-Situ Oil Sands Project. Kirby is located approximately 85 km northeast of Lac La Biche in the Regional Municipality of Wood Buffalo and has a targeted capacity of 45,000 bbl/d. The Company has filed its formal regulatory application documents for this project and is awaiting regulatory approval. Preliminary engineering is expected to commence in Q4/09. Upon completion of the engineering, Canadian Natural targets sanctioning of the project in late 2010.
- The development of new pads and conversion to tertiary recovery at Pelican Lake continued as expected throughout Q3/09. In Q3/09, the Company drilled 19 horizontal wells and plans an additional 19 horizontal wells throughout the remainder of 2009. Pelican Lake production averaged approximately 37,000 bbl/d for Q3/09.
- During Q3/09, drilling activity targeted 270 net crude oil wells including 217 wells targeting heavy crude oil, 19 wells targeting Pelican Lake crude oil, 24 wells targeting thermal crude oil and 10 wells targeting light crude oil.
- Planned drilling activity for Q4/09 includes 223 net crude oil wells, excluding stratigraphic test and service wells.
International
Three Months Ended Nine Months Ended
--------------------------------------------------
Sep 30 Jun 30 Sep 30 Sep 30 Sep 30
2009 2009 2008 2009 2008
----------------------------------------------------------------------------
Crude oil production
(bbl/d)
North Sea 34,034 40,362 42,760 38,891 46,041
Offshore West Africa 35,021 33,572 24,237 33,025 26,842
----------------------------------------------------------------------------
Natural gas production
(mmcf/d)
North Sea 8 10 9 9 10
Offshore West Africa 21 20 14 18 14
----------------------------------------------------------------------------
Net wells targeting crude
oil 2.2 1.0 0.6 6.4 4.4
Net successful wells
drilled 1.9 1.0 0.6 6.1 3.6
----------------------------------------------------------------------------
Success rate 86% 100% 100% 95% 82%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
North Sea
- As expected, production was lower in Q3/09 compared to Q2/09 and Q3/08 due to planned maintenance shutdowns at all three of the Ninian platforms and at Tiffany. During the quarter, the Company continued to focus on lowering costs, high grading inventory and identifying infill drilling opportunities.
Offshore West Africa
- Offshore West Africa's crude oil production for Q3/09 was 35,021 bbl/d, an increase of 4% from Q2/09 and an increase of 44% over Q3/08, reflecting strong performance at Baobab and Espoir, and the commencement of operations at Olowi.
- During Q3/09, two new wells were tied in at the Olowi Field. Production to date from the first platform is below expectations. The Company is currently reviewing drilling results and production data to determine the root cause of well performance issues in order to develop appropriate remediation strategies and determine the impact on future production from the field and the impact on recoverable reserves. While the Company continues drilling the next scheduled platform, it is also reviewing ongoing/future development activities, which may result in changes to the scope of the overall plan.
- 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.
Oil Sands Mining and Upgrading
Three Months Ended Nine Months Ended
--------------------------------------------------
Sep 30 Jun 30 Sep 30 Sep 30 Sep 30
2009 2009 2008 2009 2008
----------------------------------------------------------------------------
Synthetic Crude Oil
Production (bbl/d) 66,907 59,599 - 43,529 -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
- Horizon production in Q3/09 averaged 66,907 bbl/d of SCO. Production was lower than guidance due to a number of challenges arising mid-way through the third quarter after the successful commencement of operations in the second quarter. The challenges related primarily to:
1. Premature equipment failures in the Ore Preparation Plant, Primary Upgrading, the Naphtha Recovery Unit and the Sulphur Plant.
2. Ore processing challenges arising in September resulting from a higher percentage of clays in the second mine bench and the lack of available blending materials from other mine benches associated with early mine operations.
- Canadian Natural believes it has largely resolved the matters associated with equipment and plant reliability. However, the Company remains cautious as it enters the first full winter of operations due to the challenges of operating in the northern Alberta environment. The processing issue from the higher percentage of clays will continue until additional mine benches are completed facilitating better blending of consistent ore qualities. This activity is currently underway with a focus on the third mine bench. The Company anticipates that it may take until the end of the second quarter of 2010 to fully resolve the ore blending issue.
- 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 Nine Months Ended
--------------------------------------------------
Sep 30 Jun 30 Sep 30 Sep 30 Sep 30
2009 2009 2008 2009 2008
----------------------------------------------------------------------------
Crude oil and NGLs pricing
WTI (1) benchmark price
(US$/bbl) $ 68.29 $ 59.61 $ 118.13 $ 57.13 $ 113.38
Western Canadian Select
blend differential from
WTI (%) 15% 13% 15% 15% 18%
SCO price (US$/bbl) $ 67.20 $ 58.42 $ 121.96 $ 56.95 $ 117.20
Corporate average pricing
before risk management
(C$/bbl) $ 62.90 $ 59.56 $ 102.30 $ 54.17 $ 94.72
Natural gas pricing
AECO benchmark price
(C$/GJ) $ 2.87 $ 3.46 $ 8.78 $ 3.88 $ 8.16
Corporate average pricing
before risk management
(C$/mcf) $ 3.80 $ 4.11 $ 8.82 $ 4.46 $ 8.83
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Refers to West Texas Intermediate (WTI) crude oil barrel priced at
Cushing, Oklahoma.
- In Q3/09, the Western Canadian Select ("WCS") heavy crude oil differential as a percent of WTI was 15% compared to 13% in Q2/09. Heavy crude oil differentials remained narrow in Q3/09 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 Q3/09, the Company allocated approximately 124,000 bbl/d of its heavy crude oil streams to the WCS blend, optimizing the pricing for heavy crude oil. WCS is in the early stages of being recognized as a heavy crude oil benchmark for North America.
- The marketing strategy for Horizon SCO remains flexible. There is an active market for Horizon SCO and it has been favorably accepted by refiners.
- Natural gas pricing for Q3/09 continued to weaken compared to prior periods primarily due to supply/demand imbalances. North America natural gas inventory levels remained high during the third quarter due to an oversupply from US producers and lower industrial consumption.
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 approximately 575,000 boe/d in Q3/09, comprised of approximately 38% natural gas and 62% crude oil - with approximately 93% of production located in G8 countries.
-- Financial stability and liquidity - cash flow from operations of $1,506 million for Q3/09, with available unused bank lines of $1,261 million at September 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.
-- A strengthening balance sheet with debt to book capitalization of 36% which is at the low end of the Company's targeted range, and debt to EBITDA of 1.6 times, below the targeted range.
- In Q3/09 the $2.3 billion non-revolving syndicated acquisition credit facility was retired prior to its maturity in October 2009.
- Declared a quarterly cash dividend on common shares of C$0.105 per common share, payable January 1, 2010.
OUTLOOK
- The Company forecasts 2009 production levels before royalties to average between 1,305 and 1,314 mmcf/d of natural gas and between 352,000 and 363,000 bbl/d of crude oil and NGLs. Q4/09 production guidance before royalties is forecast to average between 1,213 and 1,243 mmcf/d of natural gas and between 359,000 and 390,000 bbl/d of crude oil and NGLs. Detailed guidance on production levels and capital allocation can be found on the Company's website at http://www.cnrl.com/investor_info/corporate_guidance/.
HIGHLIGHTS OF THE 2010 BUDGET
- Equivalent production target of 586,000 to 643,000 boe/d before royalties, representing a midpoint increase of 7% from the midpoint of 2009 forecasted annual average production guidance. Exit to exit production is targeted to increase 17% in 2010.
- Crude oil and NGLs production target of 400,000 to 445,000 bbl/d before royalties, representing a midpoint increase of 18% from the midpoint of 2009 forecasted annual guidance. The increase reflects the ramp up of operations at the Horizon Oil Sands, the drilling of additional pads in Primrose North and Pelican Lake, and target ramp-up at Primrose East, offset by reduced activity in the North Sea.
- Natural gas production target of 1,117 to 1,185 mmcf/d before royalties, representing a midpoint decrease of 12% from the midpoint of 2009 forecasted annual guidance. The decrease reflects an 18% reduction in drilling activity levels year over year, largely as a result of the economic impacts of low natural gas prices and increased royalties in Alberta.
- Based upon targeted production and forward strip pricing on October 27, 2009 (US$82.00/bbl, Western Canadian Select heavy oil differential of 22%, NYMEX natural gas price of US$6.00/mmbtu and exchange rate of C$1.00 = US$0.94), cash flow from operations is targeted to be between $6.5 billion and $6.9 billion ($12.00 - $12.70 per common share).
- Capital spending in 2010 is budgeted at $3.9 billion, a 26% increase over 2009.
- Free cash flow (cash flow after capital), is targeted between $2.6 billion and $3.0 billion based on October 27, 2009 forward strip pricing. Free cash flow will initially be used to reduce debt facilities.
- Canadian conventional crude oil and natural gas capital expenditures of $2.6 billion in 2010, representing a 50% increase in capital spending from 2009 levels. The increase is due to a record primary heavy crude oil drilling program, a 94% increase in capital allocation to expand polymer flooding at Pelican Lake, increased focus on the Enhanced Oil Recovery program, and the progression of our thermal crude oil development plan.
- Canadian Natural is progressing with initial development stages of the Septimus/Montney natural gas play in British Columbia with 13 wells planned for 2010.
- International conventional crude oil and natural gas capital expenditures are budgeted to be $463 million, a decrease of 36% from 2009. Planned activity includes completing the start up of one drill string in the North Sea and completion of the Olowi development in Offshore Gabon.
- Canadian Natural has significant capital flexibility in the 2010 capital program allowing the Company to quickly adapt our capital spending profile to commodity price environment.
- Included in the 2010 budget is approximately $479 million of capital for Horizon Phase 2/3 Tranche 2 expenditures targeted to increase reliability of the plant while also affording some de-bottlenecking opportunities. Additionally, Canadian Natural has budgeted approximately $95 million for completion of engineering work to provide a higher degree of cost certainty for future expansion.
- Continued strong balance sheet management which provides financial flexibility for operating plans.
Capital and Production Guidance
Canadian Natural continues its strategy of maintaining a large portfolio of varied projects. This enables the Company to provide consistent growth in production and high shareholder returns over an extended period of time. Annual budgets are developed, scrutinized throughout the year and changed if necessary in the context of project returns, product pricing expectations, and balance project risks and time horizons. Canadian Natural maintains a high ownership level and operatorship in its properties and can therefore control the nature, timing and extent of expenditures in each of its project areas.
The budgeted capital expenditures in 2009 and 2010 are as follows:
--------------------------------
($ millions) 2009 Forecast 2010 Budget
----------------------------------------------------------------------------
Conventional crude oil and natural gas
----------------------------------------------------------------------------
North American natural gas $ 495 $ 674
North American crude oil and NGLs 1,220 1,900
North Sea 170 199
Offshore West Africa 550 264
Property acquisitions, dispositions and
midstream 85 100
----------------------------------------------------------------------------
$ 2,520 $ 3,137
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Horizon Oil Sands Mining and Upgrading
Phase 1 - Construction $ 90 $ -
Phase 1 - Operating inventory, capital
inventory and commissioning 200 -
Phase 2/3 - Tranche 2 135 479
Phase 2/3 - Engineering - 95
Sustaining capital 100 164
Capitalized interest and other costs 75 47
----------------------------------------------------------------------------
600 785
----------------------------------------------------------------------------
$ 3,120 $ 3,922
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The above capital expenditure budget incorporates the following levels of
drilling activity:
--------------------------------
Drilling activity (number of net wells) 2009 Forecast 2010 Budget
----------------------------------------------------------------------------
Targeting natural gas 114 93
Targeting crude oil 695 966
Stratigraphic test / service wells -
conventional 220 227
Stratigraphic test wells - mining 107 166
----------------------------------------------------------------------------
Total 1,136 1,452
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The production guidance for 2010 is as follows:
--------------------------------
Daily production volumes, before royalties 2010 Budget
----------------------------------------------------------------------------
Natural gas (mmcf/d)
North America 1,080 - 1,140
North Sea 17 - 21
Offshore West Africa 20 - 24
---------------------------------------------------------------------------
1,117 - 1,185
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Crude oil and NGLs (mbbl/d)
North America - Conventional 250 - 270
North America - Oil Sands Mining and Upgrading 90 - 105
North Sea 31 - 36
Offshore West Africa 29 - 34
----------------------------------------------------------------------------
400 - 445
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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 Mining and Upgrading operations, Primrose East, Pelican Lake, Gabon (Offshore West Africa), and the Kirby Thermal 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. 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 nine months ended September 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 nine and three months ended September 30, 2009 in relation to the comparable periods in 2008 and the second quarter of 2009. The accompanying tables form an integral part of this MD&A. This MD&A is dated November 3, 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 Nine Months Ended
--------------------------------------------------
Sep 30 Jun 30 Sep 30 Sep 30 Sep 30
2009 2009 2008 2009 2008
----------------------------------------------------------------------------
Revenue, before royalties $ 2,823 $ 2,750 $ 4,583 $ 7,759 $ 13,662
Net earnings $ 658 $ 162 $ 2,835 $ 1,125 $ 3,215
Per common share - basic
and diluted $ 1.21 $ 0.30 $ 5.25 $ 2.07 $ 5.95
Adjusted net earnings from
operations (1) $ 658 $ 637 $ 963 $ 2,022 $ 2,795
Per common share - basic
and diluted $ 1.21 $ 1.18 $ 1.78 $ 3.73 $ 5.17
Cash flow from operations
(2) $ 1,506 $ 1,365 $ 1,815 $ 4,387 $ 5,399
Per common share - basic
and diluted $ 2.78 $ 2.52 $ 3.36 $ 8.10 $ 9.99
Capital expenditures, net
of dispositions $ 574 $ 473 $ 1,744 $ 2,303 $ 5,624
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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 Nine Months Ended
--------------------------------------------------
Sep 30 Jun 30 Sep 30 Sep 30 Sep 30
($ millions) 2009 2009 2008 2009 2008
----------------------------------------------------------------------------
Net earnings as reported $ 658 $ 162 $ 2,835 $ 1,125 $ 3,215
Stock-based compensation
expense (recovery), net of
tax (a) 126 67 (221) 196 107
Unrealized risk management
loss (gain), net of tax (b) 217 676 (1,750) 1,213 (677)
Unrealized foreign
exchange (gain) loss, net
of tax (c) (343) (268) 99 (493) 191
Effect of statutory tax
rate and other legislative
changes on future income
tax liabilities (d) - - - (19) (41)
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Adjusted net earnings from
operations $ 658 $ 637 $ 963 $ 2,022 $ 2,795
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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 $22 million in Cote
d'Ivoire, Offshore West Africa.
Cash Flow from Operations
Three Months Ended Nine Months Ended
--------------------------------------------------
Sep 30 Jun 30 Sep 30 Sep 30 Sep 30
($ millions) 2009 2009 2008 2009 2008
----------------------------------------------------------------------------
Net earnings $ 658 $ 162 $ 2,835 $ 1,125 $ 3,215
Non-cash items:
Depletion, depreciation
and amortization 673 664 659 1,983 2,017
Asset retirement
obligation accretion 24 24 18 67 52
Stock-based compensation
expense (recovery) 172 92 (308) 268 151
Unrealized risk
management loss (gain) 274 946 (2,506) 1,683 (983)
Unrealized foreign
exchange (gain) loss (391) (320) 113 (573) 219
Deferred petroleum
revenue tax (recovery)
expense 13 (2) (7) 8 (62)
Future income tax expense
(recovery) 83 (201) 1,011 (174) 790
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Cash flow from operations $ 1,506 $ 1,365 $ 1,815 $ 4,387 $ 5,399
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SUMMARY OF CONSOLIDATED NET EARNINGS AND CASH FLOW FROM OPERATIONS
Net earnings for the nine months ended September 30, 2009 were $1,125 million compared to $3,215 million for the nine months ended September 30, 2008. Net earnings for the nine months ended September 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, and the impact of statutory tax rate changes on future income tax liabilities, compared to net unrealized after-tax income of $420 million for the nine months ended September 30, 2008. Excluding these items, adjusted net earnings from operations for the nine months ended September 30, 2009 were $2,022 million compared to $2,795 million for the nine months ended September 30, 2008. The decrease in adjusted net earnings from the nine months ended September 30, 2008 was primarily due to the impact of lower realized pricing, lower natural gas sales volumes, higher production expenses, higher interest expense, and 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"), 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 third quarter of 2009 were $658 million compared to net earnings of $2,835 million for the third quarter of 2008 and net earnings of $162 million for the prior quarter. Net earnings for the third quarter of 2008 included net unrealized after-tax income of $1,872 million related to the effects of risk management activities, fluctuations in foreign exchange rates, and fluctuations in stock-based compensation, compared to net unrealized after-tax expenses of $475 million for the second quarter of 2009. Adjusted net earnings from operations for the third quarter of 2009 were $658 million compared to $963 million for the third quarter of 2008 and $637 million for the prior quarter. The decrease in adjusted net earnings from the third 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 crude oil sales volumes related to the commencement of operations of Horizon, higher realized risk management gains, lower royalty expense, and the impact of the weaker Canadian dollar relative to the US dollar. The increase in adjusted net earnings from the prior quarter was primarily due to the impact of higher crude oil sales volumes related to Horizon, higher realized crude oil pricing, and realized foreign exchange gains, partially offset by the impact of lower natural gas sales volumes, lower realized risk management gains, higher royalty and production expenses, and the impact of the stronger Canadian dollar relative to the US dollar.
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 nine months ended September 30, 2009 was $4,387 million compared to $5,399 million for the nine months ended September 30, 2008. Cash flow from operations for the third quarter of 2009 was $1,506 million compared to $1,815 million for the third quarter of 2008 and $1,365 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 the impact of realized foreign exchange, partially offset by the impact of higher crude oil sales volumes related to the commencement of operations of Horizon, 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 increase in cash flow from operations from the prior quarter was primarily due to the impact of higher crude oil sales volumes related to Horizon, higher realized crude oil pricing, lower current PRT, and the impact of realized foreign exchange gains, partially offset by the impact of lower natural gas sales volumes, lower realized natural gas pricing, lower realized risk management gains, higher royalty and production expense, and the impact of the stronger Canadian dollar relative to the US dollar.
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 nine months ended September 30, 2009 increased 1% to 574,688 boe/d from 570,704 boe/d for the nine months ended September 30, 2008. Total production before royalties for the third quarter of 2009 increased 3% to 574,755 boe/d from 555,356 boe/d for the third quarter of 2008 and decreased 3% from 590,984 boe/d for the prior quarter. Total production for the third quarter of 2009 was at the low end of the Company's previously issued guidance due to lower than anticipated SCO production at Horizon.
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 common share Sep 30 Jun 30 Mar 31 Dec 31 amounts) 2009 2009 2009 2008 ---------------------------------------------------------------------------- Revenue, before royalties $ 2,823 $ 2,750 $ 2,186 $ 2,511 Net earnings $ 658 $ 162 $ 305 $ 1,770 Net earnings per common share - Basic and diluted $ 1.21 $ 0.30 $ 0.56 $ 3.27 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- ($ millions, except per common share Sep 30 Jun 30 Mar 31 Dec 31 amounts) 2008 2008 2008 2007 ---------------------------------------------------------------------------- Revenue, before royalties $ 4,583 $ 5,112 $ 3,967 $ 3,200 Net earnings (loss) $ 2,835 $ (347) $ 727 $ 798 Net earnings (loss) per common share - Basic and diluted $ 5.25 $ (0.65) $ 1.35 $ 1.48 ---------------------------------------------------------------------------- ----------------------------------------------------------------------------
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 - Fluctuations in 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 production in the Baobab Field.
- 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 primarily due to the impact of the demand for services, industry-wide inflationary cost pressures experienced in prior quarters, fluctuations in product mix, the impact of seasonal costs that are dependent on weather, and the commencement of operations of Horizon.
- Depletion, depreciation and amortization - Fluctuations due to changes in sales volumes, finding and development costs associated with crude oil and natural gas exploration, estimated future costs to develop the Company's proved undeveloped reserves, and the commencement of operations of Horizon.
- 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 Nine Months Ended
--------------------------------------------------
Sep 30 Jun 30 Sep 30 Sep 30 Sep 30
2009 2009 2008 2009 2008
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WTI benchmark price
(US$/bbl) $ 68.29 $ 59.61 $ 118.13 $ 57.13 $ 113.38
Dated Brent benchmark
price (US$/bbl) $ 68.28 $ 58.78 $ 114.96 $ 57.26 $ 111.11
WCS blend differential
from WTI (US$/bbl) $ 10.06 $ 7.43 $ 17.98 $ 8.83 $ 20.33
WCS blend differential
from WTI (%) 15% 13% 15% 15% 18%
SCO price (US$/bbl) $ 67.20 $ 58.42 $ 121.96 $ 56.95 $ 117.20
Condensate benchmark price
(US$/bbl) $ 65.80 $ 58.30 $ 118.57 $ 55.93 $ 113.89
NYMEX benchmark price
(US$/mmbtu) $ 3.42 $ 3.59 $ 10.11 $ 3.96 $ 9.66
AECO benchmark price
(C$/GJ) $ 2.87 $ 3.46 $ 8.78 $ 3.88 $ 8.16
US / Canadian dollar
average exchange rate $ 0.9108 $ 0.8571 $ 0.9605 $ 0.8549 $ 0.9819
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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$57.13 per bbl for the nine months ended September 30, 2009, a decrease of 50% from US$113.38 per bbl for the nine months ended September 30, 2008. WTI averaged US$68.29 per bbl for the third quarter of 2009, a decrease of 42% from US$118.13 per bbl for the third quarter of 2008, and an increase of 15% from US$59.61 per bbl for the prior quarter. WTI pricing was impacted by strong Asian demand, partially offset by declines in the European and North American markets due to weak economic activity.
Crude oil sales contracts for the Company's North Sea and Offshore West Africa segments are typically based on Dated Brent ("Brent") pricing, which is more reflective of international markets and the overall supply and demand balance. Brent averaged US$57.26 per bbl for the nine months ended September 30, 2009, a decrease of 48% compared to US$111.11 per bbl for the nine months ended September 30, 2008. Brent averaged US$68.28 per bbl for the third quarter of 2009, a decrease of 41% compared to US$114.96 per bbl for the third quarter of 2008, and an increase of 16% from US$58.78 per bbl for the prior quarter. The differential between Brent and WTI was impacted by the record high inventory levels at Cushing, Oklahoma during the third quarter of 2009.
The Heavy Differential averaged 15% for the nine months ended September 30, 2009 compared to 18% for the nine months ended September 30, 2008. The Heavy Differential averaged 15% for the third quarter of 2009 and 2008, and 13% for the pr
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