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| Share Name | Share Symbol | Market | Type |
|---|---|---|---|
| Petro-Canada | NYSE:PCZ | NYSE | Ordinary Share |
| Price Change | % Change | Share Price | High Price | Low Price | Open Price | Shares Traded | Last Trade | |
|---|---|---|---|---|---|---|---|---|
| 0.00 | 0.00% | 41.37 | 0.00 | 01:00:00 |
From Jun 2019 to Jun 2024
- Reliable upstream operations and production of 410,000 barrels of oil equivalent/day (boe/d), in line with guidance
- Advanced the three major growth projects previously sanctioned by the Company
- Reduced planned 2009 capital expenditures by $600 million to $3.4 billion
- Announced planned merger with Suncor Energy Inc. to create Canada's premier energy company
Petro-Canada announced today first quarter operating earnings of $111 million ($0.23/share), down 88% from $899 million ($1.86/share) in the first quarter of 2008. First quarter 2009 cash flow from operating activities before changes in non-cash working capital was $702 million ($1.45/share), down 62% from $1,852 million ($3.83/share) in the same quarter of last year.
Net losses were $47 million ($(0.10)/share) in the first quarter of 2009, compared with net earnings of $1,076 million ($2.22/share) in the same quarter of 2008.
"A key priority for us during these tough times is to maximize cash flow in order to preserve our strong liquidity," said Ron Brenneman, president and chief executive officer. "Reliable business operations, prudent financial oversight and our cash flow generation capability are helping us weather the downturn.
"Our East Coast Canada, International and Downstream business units all contributed reasonable cash flow even with lower commodity prices and cracking margins," added Brenneman. "This, combined with a reduction in our 2009 capital program below what we indicated in December, enabled us to maintain strong liquidity through a difficult first quarter business environment."
Hot Features
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First Quarter Results
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Three months ended March 31,
(millions of Canadian dollars, except per
share and share amounts) 2009 2008
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Consolidated Results
Operating earnings (1) $ 111 $ 899
- $/share 0.23 1.86
Net earnings (loss) (47) 1,076
- $/share (0.10) 2.22
Cash flow from operating activities before
changes in non-cash working capital (2) 702 1,852
- $/share 1.45 3.83
Dividends - $/share 0.20 0.13
Capital expenditures $ 681 $ 1,016
Weighted-average common shares outstanding
(millions of shares) 484.8 484.0
Total production net before royalties
(thousands of barrels of oil equivalent/day
- Mboe/d) (3) 410 427
Operating return on capital employed (%) (4)
Upstream 27.4 28.1
Downstream 3.6 7.9
Total Company 15.9 18.7
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(1) Operating earnings (which represent net earnings (loss), excluding gains
or losses on foreign currency translation of long-term debt and on sale
of assets, including the Downstream estimated current cost of supply
adjustment and excluding mark-to-market valuations of stock-based
compensation, income tax adjustments, asset impairment charges,
insurance proceeds and premium surcharges, purchased crude oil inventory
writedowns and charges due to the deferral of the Fort Hills final
investment decision (FID) - see page 2 NON-GAAP MEASURES) are used by
the Company to evaluate operating performance.
(2) From operating activities before changes in non-cash working capital
(see page 2 NON-GAAP MEASURES).
(3) Total production includes natural gas converted at six thousand cubic
feet (Mcf) of natural gas for one barrel (bbl) of oil.
(4) Returns calculated on a 12-month rolling basis.
NON-GAAP MEASURES
Cash flow and cash flow from operating activities before changes in non-cash working capital are commonly used in the oil and gas industry and by Petro-Canada to assist management and investors in analyzing operating performance, leverage and liquidity. In addition, the Company's capital budget was prepared using anticipated cash flow from operating activities before changes in non-cash working capital, as the timing of collecting receivables or making payments is not considered relevant for capital budgeting purposes. Operating earnings represent net earnings (loss), excluding gains or losses on foreign currency translation of long-term debt and on sale of assets, including the Downstream estimated current cost of supply adjustment and excluding mark-to-market valuations of stock-based compensation, income tax adjustments, asset impairment charges, insurance proceeds and premium surcharges, purchased crude oil inventory writedowns, and charges due to the deferral of the Fort Hills FID. Operating earnings are used by the Company to evaluate operating performance. Cash flow, cash flow from operating activities before changes in non-cash working capital and operating earnings do not have standardized meanings prescribed by Canadian generally accepted accounting principles (GAAP) and, therefore, may not be comparable with the calculations of similar measures for other companies. For a reconciliation of cash flow and cash flow from operating activities before changes in non-cash working capital to the associated GAAP measures, refer to the table on page 4. For a reconciliation of operating earnings to the associated GAAP measures, refer to the table below.
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Three months ended March 31,
(millions of Canadian dollars,
except per share amounts) 2009 ($/share) 2008 ($/share)
----------------------------------------------------------------------------
Net earnings (loss) $ (47) $ (0.10) $ 1,076 $ 2.22
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Foreign currency translation gain
(loss) on long-term debt (1) (99) (48)
Gain on sale of assets 2 3
Downstream estimated current cost
of supply adjustment 15 123
Mark-to-market valuation of
stock-based compensation (25) 68
Income tax adjustments 5 26
Asset impairment charge (2) - (24)
Insurance proceeds and premium
surcharges - 29
Charges due to the deferral of the
Fort Hills FID (3) (56) -
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Operating earnings $ 111 $ 0.23 $ 899 $ 1.86
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(1) Foreign currency translation reflected gains or losses on United States
(U.S.) dollar-denominated long-term debt not associated with the
self-sustaining International business unit and the U.S. Rockies
operations included in the North American Natural Gas business unit.
(2) In the first quarter of 2008, the North American Natural Gas business
unit recorded a depreciation, depletion and amortization (DD&A) charge
of $35 million before-tax ($24 million after-tax) for accumulated
project development costs relating to the proposed liquefied natural gas
(LNG) re-gasification facility at Gros-Cacouna, Quebec, which has been
postponed due to global LNG business conditions.
(3) In the first quarter of 2009, the Oil Sands business unit recorded
expenses of $80 million before-tax ($56 million after-tax) to reflect
further costs incurred terminating certain goods and services agreements
and DD&A charges on certain property, plant and equipment due to the
deferral of the Fort Hills FID.
Earnings Variances
Q1/09 VERSUS Q1/08 FACTOR ANALYSIS
Operating Earnings
(millions of Canadian dollars, after-tax)
To view a graph for the Operating Earnings please visit the following link: http://media3.marketwire.com/docs/428pcae1.pdf
Operating earnings decreased 88% to $111 million ($0.23/share) in the first quarter of 2009, compared with $899 million ($1.86/share) in the first quarter of 2008. Results reflected lower realized upstream prices ($(588) million), decreased upstream volumes(1) ($(62) million) and higher DD&A and exploration ($(62) million), operating, general and administrative (G&A) ($(30) million) and other(3) ($(48) million) expenses. The Downstream margins(2) ($2 million) were relatively unchanged.
(1) Upstream volumes included the portion of DD&A expense associated with changes in upstream production levels.
(2) Downstream margin included the estimated current cost of supply adjustment.
(3) Other mainly included interest expense ($(22) million), foreign exchange ($10 million) and upstream inventory movements ($(40) million).
Operating Earnings by Segment
(millions of Canadian dollars, after-tax)
To view a graph for the Operating Earnings by Segment please visit the following link: http://media3.marketwire.com/docs/428pcae2.pdf
The decrease in first quarter operating earnings on a segmented basis reflected lower operating earnings in International ($(295) million), East Coast Canada ($(241) million) and North American Natural Gas ($(99) million), a decrease from operating earnings to an operating loss in Oil Sands ($(123) million) and higher Shared Services and Eliminations costs ($(35) million). The results in the Downstream ($5 million) were relatively unchanged.
Net losses in the first quarter of 2009 were $47 million ($(0.10)/share), compared with net earnings of $1,076 million ($2.22/share) during the same period in 2008. Net losses in the first quarter of 2009 reflected mark-to-market valuation of stock-based compensation expense, versus a recovery in the same period last year, increased losses on foreign currency translation of long-term debt and charges due to the deferral of the Fort Hills FID. Net earnings in the first quarter of 2008 reflected a large positive current cost of supply adjustment in the Downstream, as a result of rising crude oil feedstock costs while using a "first-in, first-out" (FIFO) inventory valuation methodology, compared with a much smaller positive adjustment in the current period.
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Three months ended March 31,
(millions of Canadian dollars) 2009 2008
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Cash flow from operating activities $ 472 $ 1,435
Increase (decrease) in non-cash working
capital related to operating activities 230 417
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Cash flow from operating activities before
changes in non-cash working capital $ 702 $ 1,852
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During the first quarter of 2009, cash flow from operating activities before changes in non-cash working capital was $702 million ($1.45/share), down from $1,852 million ($3.83/share) in the same quarter of 2008. The decrease in cash flow from operating activities before changes in non-cash working capital reflected the decrease from net earnings in the prior year to a net loss in the current quarter.
Operating Highlights
First quarter production in 2009 averaged 410,000 boe/d net to Petro-Canada, down from 427,000 boe/d net in the same quarter of 2008. Volumes reflected decreased North American Natural Gas, East Coast Canada and International production, partially offset by increased Oil Sands production.
In the Downstream, the Edmonton refinery conversion project (RCP) continued to ramp up and strong marketing performance was partially offset by lower Refining and Supply earnings.
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Three months ended March 31,
2009 2008
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Upstream - Consolidated
Production before royalties
Crude oil and natural gas liquids (NGL)
production net (thousands of barrels/day
- Mb/d) 294 308
Natural gas production net, excluding
injectants (millions of cubic feet/day
- MMcf/d) 693 712
Total production net (Mboe/d) (1) 410 427
Average realized prices
Crude oil and NGL ($/barrel - $/bbl) 52.08 93.38
Natural gas ($/thousand cubic feet - $/Mcf) 5.62 7.59
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Downstream
Petroleum product sales (thousands of cubic
metres/day - m3/d) 51.1 52.2
Average refinery utilization (%) 88 101
Downstream operating earnings after-tax
(cents/litre) 1.4 1.2
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(1) Total production included natural gas converted at six Mcf of natural
gas for one bbl of oil.
BUSINESS STRATEGY
Petro-Canada's strategy is to create shareholder value by delivering long-term, profitable growth and improving the profitability of the base business. On March 23, 2009, the Company announced plans to merge with Suncor Energy Inc. (Suncor) to create the premier Canadian energy company.
Petro-Canada's capital program supports bringing on six major projects over the next several years to deliver long-term profitable growth. The Company anticipates upstream production will significantly increase when these major growth projects come on-stream. The Company plans to advance the extension of the White Rose field off the East Coast of Canada, the Syria Ebla gas project and the developments associated with the new Libya Exploration and Production Sharing Agreements (EPSAs), which have been sanctioned by the Company. The other three projects, MacKay River expansion, Fort Hills mining project and the Montreal coker, are not sanctioned and are on hold until commodity prices and financial markets stabilize and the proposed merger with Suncor is completed.
Petro-Canada continually works to strengthen its base business by improving the safety, reliability and efficiency of its operations and is focused on delivering upstream production in line with guidance.
Outlook
Operational Updates
- Syncrude to complete planned turnaround of Coker 8-3 in the second quarter of 2009.
- Hibernia delayed its planned 21-day turnaround until the second quarter of 2009.
- Terra Nova is planning a nine-day turnaround in the second quarter of 2009 to do regular emergency systems testing and a 21-day turnaround in the third quarter of 2009 to complete the planned regulatory and maintenance scope.
- White Rose is planning a 28-day regulatory and maintenance turnaround in the third quarter of 2009, followed by a further period of reduced production, lasting approximately 40 days, to do subsea work associated with the tie-in of the North Amethyst project.
- Buzzard is planning a 28-day turnaround in the third quarter of 2009 to do regulatory work and to complete tie-ins for the enhancement project. Production will be reduced for a further 14 days during the third quarter due to maintenance work on the Forties pipeline system.
Major Project Milestones
- The Edmonton RCP continued to ramp up production in the first quarter of 2009.
- Development drilling, procurement and fabrication of the North Amethyst portion of the White Rose Extensions project continues and is on schedule to deliver first oil in late 2009 or early 2010. Work on development concepts for West White Rose continues to advance.
- The Syria Ebla gas project is on plan and was 60% complete at the end of the first quarter of 2009. Three wells have been drilled, one of which has been handed over to the engineering, procurement and construction contractor for tie-in. First gas is expected in mid-2010.
- Following the signing of the new Libya EPSAs, work has commenced with a focus on preparing the Amal field development program and initiating the new exploration program. Seismic operations continued in the first quarter of 2009, with approximately 25% of the program completed at the end of the first quarter.
- To preserve the Company's strong liquidity position, the three unsanctioned growth projects (Montreal coker, MacKay River expansion and Fort Hills mining project) are on hold until commodity prices and financial markets stabilize and the proposed merger with Suncor is completed. The Company is reworking these projects' costs to take advantage of the current market environment.
- The Fort Hills Energy Limited Partnership reached an agreement with the Government of Alberta on extending the term of the Fort Hills oil sands leases until 2019. Regulatory approvals for both the amendment to the Fort Hills approved mine plan and approval for the Sturgeon Upgrader have been received. The upgrader portion of the project is on hold.
BUSINESS UNIT RESULTS
UPSTREAM
North American Natural Gas
----------------------------------------------------------------------------
Three months ended March 31,
(millions of Canadian dollars) 2009 2008
----------------------------------------------------------------------------
Net earnings (loss) $ (2) $ 74
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Income tax adjustments 1 -
Gain on sale of assets - 2
Asset impairment charge (1) - (24)
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Operating earnings (loss) $ (3) $ 96
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Cash flow from operating activities before
changes in non-cash working capital $ 118 $ 264
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(1) In the first quarter of 2008, the North American Natural Gas business
unit recorded a DD&A charge of $35 million before-tax ($24 million
after-tax) for accumulated project development costs relating to the
proposed LNG re-gasification facility at Gros-Cacouna, Quebec, which has
been postponed due to global LNG business conditions.
In the first quarter of 2009, North American Natural Gas recorded an operating loss of $3 million, compared with operating earnings of $96 million in the first quarter of 2008. Lower realized prices and volumes, combined with increased DD&A expense were partially offset by lower exploration expense.
North American Natural Gas production averaged 645 million cubic feet of gas equivalent/day (MMcfe/d) in the first quarter of 2009, down from 665 MMcfe/d in the same quarter of 2008. Decreased production reflected reduced capital spending and natural declines.
Oil Sands
----------------------------------------------------------------------------
Three months ended March 31,
(millions of Canadian dollars) 2009 2008
----------------------------------------------------------------------------
Net earnings (loss) $ (68) $ 112
----------------------------------------------------------------------------
Income tax adjustments 1 2
Charges due to the deferral of the Fort Hills
FID (1) (56) -
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Operating earnings (loss) $ (13) $ 110
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Cash flow from (used in) operating activities
before changes in non-cash working capital $ (38) $ 168
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(1) In the first quarter of 2009, the Oil Sands business unit recorded
expenses of $80 million before-tax ($56 million after-tax) to reflect
further costs incurred terminating certain goods and services agreements
and DD&A charges on certain property, plant and equipment due to the
deferral of the Fort Hills FID.
Oil Sands had an operating loss of $13 million in the first quarter of 2009, compared with operating earnings of $110 million in the first quarter of 2008. Lower realized prices and higher operating, DD&A and exploration expenses were partially offset by higher production.
Oil Sands production averaged 63,700 barrels/day (b/d) in the first quarter of 2009, up 15% from 55,500 b/d in the first quarter of 2008. Increased production primarily reflected strong reliability and increased capability at MacKay River. Syncrude production was relatively unchanged, as the bitumen production constraints and the start of an earlier than planned turnaround of Coker 8-3 in the current quarter were offset by reduced production due to severe winter weather in the first quarter of 2008.
International & Offshore
East Coast Canada
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Three months ended March 31,
(millions of Canadian dollars) 2009 2008
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Net earnings (1) $ 104 $ 375
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Terra Nova insurance proceeds - 29
Income tax adjustments 1 2
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Operating earnings $ 103 $ 344
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Cash flow from operating activities before
changes in non-cash working capital $ 197 $ 466
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(1) East Coast Canada crude oil inventory movements decreased net earnings
by $39 million before-tax ($27 million after-tax) for the three months
ended March 31, 2009. The same factor decreased net earnings by $6
million before-tax ($4 million after-tax) for the three months ended
March 31, 2008.
In the first quarter of 2009, East Coast Canada contributed $103 million of operating earnings, down from $344 million in the first quarter of 2008. Lower realized prices and production were partially offset by lower DD&A expense.
East Coast Canada production averaged 87,900 b/d in the first quarter of 2009, down 5% from 92,100 b/d in the same period in 2008. Hibernia production was slightly higher due to the positive impact of recent well workovers, strong reliability and the addition of a new production well, which offset natural declines. White Rose production was higher due to the completion of a 13-day turnaround in the first quarter of 2008. Terra Nova production was lower due to natural declines.
International
----------------------------------------------------------------------------
Three months ended March 31,
(millions of Canadian dollars) 2009 2008
----------------------------------------------------------------------------
Net earnings (1) $ 41 $ 336
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Operating earnings $ 41 $ 336
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Cash flow from operating activities before
changes in non-cash working capital $ 254 $ 556
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(1) International crude oil inventory movements increased net earnings by $2
million before-tax ($1 million after-tax) for the three months ended
March 31, 2009. The same factor increased net earnings by $34 million
before-tax ($25 million after-tax) for the three months ended March 31,
2008.
International contributed $41 million of operating earnings in the first quarter of 2009, down from $336 million in the first quarter of 2008. Lower realized crude oil prices and decreased production volumes were partially offset by lower operating and exploration expenses.
International production averaged 150,700 boe/d in the first quarter of 2009, down 10% from 168,200 boe/d in the first quarter of 2008. Decreased production primarily reflected Organization of the Petroleum Exporting Countries (OPEC) quota restraints imposed in Libya, an unplanned shutdown of the Triton facility for compressor repairs and natural declines in several North Sea assets.
Exploration Update
In the first quarter of 2009, Petro-Canada and its partners finished operations on five wells of the up to 12 wells planned in 2009. One well was completed as a gas discovery (L6-7 in the Netherlands sector of the North Sea). This well was started in 2008 but was completed in the first quarter of 2009. One well was completed as an oil discovery (Hobby in the United Kingdom (U.K.) sector of the North Sea). As a result of the discovery, three sidetracks are planned from this wellbore, of which one has been completed so far. The three wells drilled in Alaska (Chandler 1, Wolf Creek 4 and Gubik 4) all encountered natural gas. Drilling operations were completed for the Wolf Creek and Gubik wells so they were plugged and abandoned. The Chandler well was suspended for possible future testing. These wells are part of a multi-season program and the results are being evaluated for incorporation into an overall plan to determine the commerciality of natural gas development in the region.
DOWNSTREAM
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Three months ended March 31,
(millions of Canadian dollars) 2009 2008
----------------------------------------------------------------------------
Net earnings $ 82 $ 184
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Gain on sale of assets 2 1
Downstream estimated current cost of supply
adjustment 15 123
Income tax adjustments 2 2
----------------------------------------------------------------------------
Operating earnings $ 63 $ 58
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Cash flow from operating activities before
changes in non-cash working capital $ 279 $ 308
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In the first quarter of 2009, the Downstream business contributed $63 million of operating earnings, up from $58 million in the same quarter of 2008.
Refining and Supply recorded first quarter 2009 operating earnings of $8 million, down slightly compared with operating earnings of $9 million in the same quarter of 2008. Lower operating earnings reflected lower distillate cracking margins, unfavourable crude price differentials and lower refinery yields in Edmonton. These factors were partially offset by an increase in realized refining margins for lubricants, asphalt and coke, heavy fuel oil, liquid petroleum gases and light oil products, higher gasoline cracking margins, as well as positive foreign exchange impacts.
Marketing contributed first quarter 2009 operating earnings of $55 million, up compared with $49 million in the same quarter of 2008. In the first quarter of 2009, Marketing results reflected higher fuel margins, partially offset by overall lower volume demand.
CORPORATE
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Shared Services and Eliminations Three months ended March 31,
(millions of Canadian dollars) 2009 2008
----------------------------------------------------------------------------
Net loss $ (204) $ (5)
----------------------------------------------------------------------------
Foreign currency translation loss on
long-term debt (99) (48)
Stock-based compensation (expense) recovery (1) (25) 68
Income tax adjustments - 20
----------------------------------------------------------------------------
Operating loss $ (80) $ (45)
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Cash flow from (used in) operating activities
before changes in non-cash working capital $ (108) $ 90
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(1) Reflected the change in the mark-to-market valuation of stock-based
compensation.
Shared Services and Eliminations recorded an operating loss of $80 million in the first quarter of 2009, compared with a loss of $45 million for the same period in 2008. The increase in operating loss was due to higher interest expense and the elimination of profits in the upstream business units for crude oil sales to Downstream where the crude oil still resides in Downstream's inventories, versus a recovery of losses on these sales in the same period last year.
The Company's financial capacity and flexibility remain strong despite the recent turmoil in the financial markets. This is due to Petro-Canada being able to generate cash flow, having access to existing cash balances and significant credit facility capacity and requiring no near-term refinancing. For 2009, the Company expects to cover its capital program with cash flow and, if necessary, from cash balances and available credit facilities. The Company will monitor energy and financial markets through the year and take advantage of the flexibility in its capital program to pace projects and adjust capital expenditures as necessary.
Petro-Canada is one of Canada's largest oil and gas companies, operating in both the upstream and downstream sectors of the industry in Canada and internationally. The Company creates value by responsibly developing energy resources and providing world class petroleum products and services. Petro-Canada is proud to be a National Partner to the Vancouver 2010 Olympic and Paralympic Winter Games. Petro-Canada's common shares trade on the Toronto Stock Exchange (TSX) under the symbol PCA and on the New York Stock Exchange (NYSE) under the symbol PCZ.
The full text of Petro-Canada's first quarter release, including Management's Discussion and Analysis (MD&A), can be accessed on Petro-Canada's website at http://www.petro-canada.ca/en/investors/845.aspx and will be available through SEDAR at http://www.sedar.com/.
Petro-Canada will hold a conference call to discuss these results with investors on Tuesday, April 28, 2009 at 9:00 a.m. eastern daylight time (EDT). To participate, please call 1-800-769-8320 (toll-free in North America), 00-800-4222-8835 (toll-free internationally), or 416-695-6622 at 8:55 a.m. EDT. Media are invited to listen to the call by dialing 1-800-952-4972 (toll-free in North America) or 416-695-7848. Media are invited to ask questions at the end of the call. A live audio broadcast of the conference call will be available on Petro-Canada's website at http://www.petro-canada.ca/en/investors/845.aspx on April 28, 2009 at 9:00 a.m. EDT. Those who are unable to listen to the call live may listen to a recording of the call approximately one hour after its completion by dialing 1-800-408-3053 (toll-free in North America) or 416-695-5800 (pass code number 4003670#). Approximately one hour after the call, a recording will be available on Petro-Canada's website.
LEGAL NOTICE - FORWARD-LOOKING INFORMATION
This news release contains forward-looking information. You can usually identify this information by such words as "plan," "anticipate," "forecast," "believe," "target," "intend," "expect," "estimate," "budget" or other terms that suggest future outcomes or references to outlooks. Listed below are examples of references to forward-looking information:
- business strategies and goals
- future investment decisions
- outlook (including operational updates and strategic milestones)
- future capital, exploration and other expenditures
- future cash flows
- future resource purchases and sales
- anticipated construction and repair activities
- anticipated turnarounds at refineries and other facilities
- anticipated refining margins
- future oil and natural gas production levels and the sources of their growth
- project development, and expansion schedules and results
- future exploration activities and results, and dates by which certain areas may be developed or come on-stream
- anticipated retail throughputs
- anticipated pre-production and operating costs
- reserves and resources estimates
- future royalties and taxes payable
- production life-of-field estimates
- natural gas export capacity
- future financing and capital activities (including purchases of Petro-Canada common shares under the Company's normal course issuer bid (NCIB) program)
- contingent liabilities (including potential exposure to losses related to retail licensee agreements)
- the impact and cost of compliance with existing and potential environmental matters
- future regulatory approvals
- expected rates of return
Such forward-looking information is based on a number of assumptions and analysis made by the Company. These assumptions and analysis are described in greater detail throughout this news release and include, without limitation, assumptions with respect to future commodity prices, the state of the economy, required capital expenditures, levels of cash flow, regulatory requirements, industry capacity, the results of exploration and development drilling and the ability of suppliers to meet commitments.
Undue reliance should not be placed on forward-looking information. Such forward-looking information is subject to known and unknown risks and uncertainties, which may cause actual results, levels of activity and achievements to differ materially from those expressed or implied by such information. Such risks and uncertainties include, but are not limited to:
- the possibility of corporate amalgamations and reorganizations
- changes in industry capacity
- imprecise reserves estimates of recoverable quantities of oil, natural gas and liquids from resource plays, and other sources not currently classified as reserves
- the effects of weather and climate conditions
- the results of exploration and development drilling, and related activities
- the ability of suppliers to meet commitments
- decisions or approvals from administrative tribunals
- risks associated with domestic and international oil and natural gas operations
- changes in general economic, market and business conditions
- competitive action by other companies
- fluctuations in oil and natural gas prices
- changes in refining and marketing margins
- the ability to produce and transport crude oil and natural gas to markets
- fluctuations in interest rates and foreign currency exchange rates
- actions by governmental authorities (including changes in taxes, royalty rates and resource-use strategies)
- changes in environmental and other regulations
- international political events
- nature and scope of actions by stakeholders and/or the general public
Many of these and other similar factors are beyond the control of Petro-Canada. Petro-Canada discusses these factors in greater detail in filings with the Canadian provincial securities commissions and the United States (U.S.) Securities and Exchange Commission (SEC).
Readers are cautioned that this list of important factors affecting forward-looking information is not exhaustive. Furthermore, the forward-looking information in this news release is made as of April 28, 2009 and, except as required by applicable law, will not be publicly updated or revised. This cautionary statement expressly qualifies the forward-looking information in this news release.
Petro-Canada disclosure of reserves
Petro-Canada's qualified reserves evaluators prepare the reserves estimates the Company uses. The Canadian provincial securities commissions do not consider Petro-Canada's reserves staff and management as independent of the Company. Petro-Canada has obtained an exemption from certain Canadian reserves disclosure requirements that allows Petro-Canada to make disclosure in accordance with SEC standards where noted in this news release. This exemption allows comparisons with U.S. and other international issuers.
As a result, Petro-Canada formally discloses its proved reserves data using U.S. requirements and practices, and these may differ from Canadian domestic standards and practices. The use of the terms such as "probable," "possible," "resources" and "life-of-field production" in this news release does not meet the SEC guidelines for SEC filings. To disclose reserves in SEC filings, oil and gas companies must prove they are economically and legally producible under existing economic and operating conditions. Note that when the term barrels of oil equivalent (boe) is used in this news release, it may be misleading, particularly if used in isolation. A boe conversion ratio of six Mcf to one bbl is based on an energy equivalency conversion method. This method primarily applies at the burner tip and does not represent a value equivalency at the wellhead. The table below describes the industry definitions that Petro-Canada currently uses:
Definitions Petro-Canada uses Reference
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Proved oil and natural gas reserves SEC reserves definition (Accounting
(includes both proved developed Rules Regulation S-X 210.4-10,
and proved undeveloped) U.S. Financial Accounting Standards
Board Statement No. 69)
SEC Guide 7 for Oil Sands Mining
Unproved reserves, probable and Canadian Securities Administrators:
possible reserves Canadian Oil and Gas Evaluation
Handbook (COGEH), Vol. 1 Section 5
prepared by the Society of
Petroleum Evaluation Engineers (SPEE)
and the Canadian Institute of
Mining Metallurgy and Petroleum (CIM)
Contingent and Prospective Petroleum Resources Management System:
Resources Society of Petroleum
Engineers, SPEE, World Petroleum
Congress and American
Association of Petroleum Geologist
definitions (approved March 2007)
Canadian Securities Administrators:
COGEH Vol. 1 Section 5
Although the Society of Petroleum Engineers resource classification has categories of 1C, 2C and 3C for Contingent Resources, and low, best and high estimates for Prospective Resources, Petro-Canada will only refer to the unrisked 2C for Contingent Resources and the partially risked best estimate for Prospective Resources when referencing resources in this news release. Estimates of resources in this news release include Contingent Resources that have not been adjusted for risk based on the chance of development and partially risked Prospective Resources that have been risked for chance of discovery, but have not been risked for chance of development. Such estimates are not estimates of volumes that may be recovered and actual recovery is likely to be less and may be substantially less or zero. If a discovery is made, there is no certainty that it will be developed or, if it is developed, there is no certainty as to the timing of such development.
Canadian Oil Sands represents approximately 68% of Petro-Canada's total for Contingent and Prospective Resources. The balance of Petro-Canada's resources is spread out across the business, most notably in the North American frontier and International areas. Also, when Petro-Canada references resources for the Company, unrisked Contingent Resources are approximately 70% of the Company's total resources and partially risked Prospective Resources are approximately 30% of the Company's total resources.
Cautionary statement: In the case of discovered resources or a subcategory of discovered resources other than reserves, there is no certainty that it will be commercially viable to produce any portion of the resources. In the case of undiscovered resources or a subcategory of undiscovered resources, there is no certainty that any portion of the resources will be discovered. If discovered, there is no certainty that it will be commercially viable to produce any portion of the resources.
For movement of resources to reserves categories, all projects must have an economic depletion plan and may require:
- additional delineation drilling and/or new technology for unrisked Contingent Resources
- exploration success with respect to partially risked Prospective Resources
- project sanction and regulatory approvals
Reserves and resources information contained in this news release is as at December 31, 2008.
Contacts: Investor and analyst inquiries: Ken Hall, Investor Relations Petro-Canada, Calgary (403) 296-7859 Email: investor@petro-canada.ca Lisa McMahon, Investor Relations Petro-Canada, Calgary (403) 296-3764 Email: investor@petro-canada.ca Media and general inquiries: Andrea Ranson, Corporate Communications Petro-Canada, Calgary (403) 296-4610 Email: corpcomm@petro-canada.ca Website: www.petro-canada.ca
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