Solid Operations and Strong Liquidity Position Petro-Canada Well for Merger with Suncor
CALGARY, ALBERTA -- (Marketwire) -- 07/30/09 -- Highlights
- Production in line with guidance due to reliable upstream operations
- Maintained strong liquidity through a difficult business environment
- Obtained shareholder, court and Competition Bureau approval for merger with Suncor Energy Inc. (Suncor) to create Canada's premier energy company, effective August 1, 2009
Petro-Canada announced today second quarter operating earnings of $99 million ($0.20/share), down 91% from $1,151 million ($2.38/share) in the second quarter of 2008. Second quarter 2009 cash flow from operating activities before changes in non-cash working capital was $634 million ($1.31/share), down 68% from $1,979 million ($4.09/share) in the same quarter of last year.
Net earnings were $77 million ($0.16/share) in the second quarter of 2009, compared with $1,498 million ($3.10/share) in the same quarter of 2008.
"We continued to manage our business in a prudent manner during the second quarter, as the downturn persisted," said Ron Brenneman, president and chief executive officer. "Staying the course we charted for ourselves at the beginning of this year has us in a strong position heading into our merger with Suncor."
As a result of the merger between Petro-Canada and Suncor, Petro-Canada will not be declaring further dividends. Dividends will now be granted and paid by the new amalgamated Company, subject to the approval of its new Board of Directors.
Second Quarter Results ---------------------------------------------------------------------------- Three months ended Six months ended (millions of Canadian dollars, June 30, June 30, except per share and share amounts) 2009 2008 2009 2008 ---------------------------------------------------------------------------- Consolidated Results Operating earnings(1) $ 99 $ 1,151 $ 210 $ 2,097 - $/share 0.20 2.38 0.43 4.33 Net earnings 77 1,498 30 2,574 - $/share 0.16 3.10 0.06 5.32 Cash flow from operating activities before changes in non-cash working capital(2) 634 1,979 1,336 3,831 - $/share 1.31 4.09 2.76 7.92 Dividends - $/share 0.20 0.13 0.40 0.26 Capital expenditures $ 683 $ 2,141 $ 1,364 $ 3,157 Weighted-average common shares outstanding (millions of shares) 485.0 483.8 484.9 483.8 Total production net before royalties (thousands of barrels of oil equivalent/day - Mboe/d)(3) 374 414 392 421 Operating return on capital employed (%)(4) Upstream 18.3 35.1 Downstream 3.2 3.3 Total Company 11.3 20.6 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- (1) Operating earnings (which represent net earnings, 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 valuation of stock-based compensation, the Libya Exploration and Production Sharing Agreements (EPSAs) ratification adjustment, income tax adjustments, asset impairment charges, insurance proceeds and premium surcharges, and charges due to the deferral of the Fort Hills project - 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, 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 valuation of stock-based compensation, the Libya EPSA ratification adjustment, income tax adjustments, asset impairment charges, insurance proceeds and premium surcharges, and charges due to the deferral of the Fort Hills project. 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.
---------------------------------------------------------------------------- Three months ended June 30, (millions of Canadian dollars, except per share amounts) 2009 ($/share) 2008 ($/share) ---------------------------------------------------------------------------- Net earnings $ 77 $ 0.16 $ 1,498 $ 3.10 ---------------------------------------------------------------------------- Foreign currency translation gain (loss) on long-term debt(1) 273 (13) Loss on sale of assets(2) (5) (99) Downstream estimated current cost of supply adjustment 137 299 Mark-to-market valuation of stock-based compensation (87) (117) Libya EPSA ratification adjustment(3) - 47 Income tax adjustments(4) 2 230 Asset impairment charge(5) (158) - Insurance proceeds and premium surcharges 1 - Charges due to the deferral of the Fort Hills project(6) (185) - ---------------------------------------------------------------------------- Operating earnings $ 99 $ 0.20 $ 1,151 $ 2.38 ---------------------------------------------------------------------------- ----------------------------------------------------------------------------
---------------------------------------------------------------------------- Six months ended June 30, (millions of Canadian dollars, except per share amounts) 2009 ($/share) 2008 ($/share) ---------------------------------------------------------------------------- Net earnings $ 30 $ 0.06 $ 2,574 $ 5.32 ---------------------------------------------------------------------------- Foreign currency translation gain (loss) on long-term debt(1) 174 (61) Loss on sale of assets(2) (3) (96) Downstream estimated current cost of supply adjustment 152 422 Mark-to-market valuation of stock-based compensation (112) (49) Libya EPSA ratification adjustment(3) - - Income tax adjustments(4) 7 256 Asset impairment charge(5) (158) (24) Insurance proceeds and premium surcharges 1 29 Charges due to the deferral of the Fort Hills project(6) (241) - ---------------------------------------------------------------------------- Operating earnings $ 210 $ 0.43 $ 2,097 $ 4.33 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- (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 second quarter of 2008, the North American Natural Gas business unit completed the sale of its Minehead assets in Western Canada, resulting in a loss on sale of $153 million before-tax ($112 million after-tax).
(3) In the second quarter of 2008, the Company signed six new EPSAs with the Libya National Oil Corporation (NOC) to replace existing concession agreements and one EPSA. The new EPSAs were ratified as of the signing, with an effective date of January 1, 2008. Net earnings for the three months ended June 30, 2008 included a $47 million after-tax adjustment to recognize incremental earnings on the new EPSAs relating to the period from January 1 to March 31, 2008, which could not be recognized until ratification on June 19, 2008.
(4) In the second quarter of 2008, the International business segment recorded a $230 million future income tax recovery due to the ratification of the Libya EPSAs.
(5) In the second quarter of 2009, the North American Natural Gas business unit recorded a charge of $244 million before-tax ($158 million after-tax) for impairments primarily related to the coal bed methane (CBM) assets in the U.S. Rockies due to production performance combined with lower prices. 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.
(6) In the second quarter of 2009, the Oil Sands business unit recorded expenses of $252 million before-tax ($185 million after-tax) primarily related to writedowns of property, plant and equipment due to the indefinite deferral of the upgrading portion of the Fort Hills project.
In the first quarter of 2009, the Oil Sands business unit recorded expenses of $80 million before-tax ($56 million after-tax) to reflect costs incurred terminating certain goods and services agreements and writedowns of certain property, plant and equipment due to the deferral of the Fort Hills final investment decision (FID).
Earnings Variances
Q2/09 VERSUS Q2/08 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/730pcae1.jpg.
Operating earnings decreased 91% to $99 million ($0.20/share) in the second quarter of 2009, compared with $1,151 million ($2.38/share) in the second quarter of 2008. The decrease in second quarter operating earnings reflected lower realized upstream prices ($(768) million), decreased upstream volumes(1) ($(184) million), decreased Downstream margin and volumes(2) ($(10) million), and higher DD&A and exploration ($(47) million), operating, general and administrative (G&A) ($(28) million) and other(3) ($(15) million) expenses.
(1) Upstream volumes included the portion of DD&A expense associated with changes in upstream production levels.
(2) Downstream margin included the estimated current cost of supply adjustment.
(3) Other mainly included changes in the elimination of profits in the upstream business units for crude oil sales to Downstream, where the crude oil still resides in Downstream's inventories ($(56) million), decreased sulphur sales ($(28) million), foreign exchange ($(14) million) and upstream inventory movements ($77 million).
Operating Earnings by Segment
(millions of Canadian dollars, after-tax)
To view a graph for the Operating Earnings by Segment please visit the following link: http://media3.marketwire.com/docs/730pcae2.jpg.
The decrease in second quarter operating earnings on a segmented basis reflected lower operating earnings in East Coast Canada ($(248) million) and International ($(241) million), a decrease from operating earnings to an operating loss in North American Natural Gas ($(287) million, Oil Sands ($(181) million) and Downstream ($(18) million), and higher Shared Services and Eliminations costs ($(77) million).
Net earnings in the second quarter of 2009 were $77 million ($0.16/share), compared with $1,498 million ($3.10/share) during the same period in 2008. Net earnings in the second quarter of 2009 were lower than in the second quarter of 2008 due to significantly lower operating earnings, expenses from the deferral of the Fort Hills project, impairment charges in North American Natural Gas and a smaller current cost of supply adjustment in the Downstream. Net earnings for the second quarter of 2008 included a $230 million future income tax recovery on the ratification of the Libya EPSAs. These factors were partially offset by lower expenses from the mark-to-market valuation of stock-based compensation, smaller losses on the sale of assets and foreign currency translation gains on long-term debt during the second quarter of 2009, versus foreign currency translation losses in the same period of the prior year.
---------------------------------------------------------------------------- Three months ended Six months ended June 30, June 30, (millions of Canadian dollars) 2009 2008 2009 2008 ---------------------------------------------------------------------------- Cash flow from operating activities $ 465 $ 2,479 $ 937 $ 3,914 Increase (decrease) in non-cash working capital related to operating activities 169 (500) 399 (83) ---------------------------------------------------------------------------- Cash flow from operating activities before changes in non-cash working capital $ 634 $ 1,979 $ 1,336 $ 3,831 ---------------------------------------------------------------------------- ----------------------------------------------------------------------------
During the second quarter of 2009, cash flow from operating activities before changes in non-cash working capital was $634 million ($1.31/share), down significantly from $1,979 million ($4.09/share) in the same quarter of 2008. The decrease in cash flow from operating activities before changes in non-cash working capital reflected significantly lower net earnings.
2009 Consolidated Net Production and Capital Expenditure Outlooks
The Company updates its annual production and capital and exploration expenditure outlooks at mid-year. Full-year upstream production is expected to be in the 355,000 barrels of oil equivalent/day (boe/d) to 375,000 boe/d range in 2009, in line with the 345,000 boe/d to 385,000 boe/d production outlook previously provided. The 2009 capital and exploration expenditure program is expected to be $3.2 billion, down $200 million from the prior guidance of $3.4 billion announced on April 28, 2009.
Operating Highlights
Second quarter production in 2009 averaged 374,000 boe/d net to Petro-Canada, down from 414,000 boe/d net in the same quarter of 2008. Volumes reflected decreased North American Natural Gas, East Coast Canada and International production while Oil Sands production was relatively unchanged.
In the Downstream, earnings were negatively impacted by a weaker business environment in the second quarter of 2009.
---------------------------------------------------------------------------- Three months ended Six months ended June 30, June 30, 2009 2008 2009 2008 ---------------------------------------------------------------------------- Upstream - Consolidated Production before royalties Crude oil and natural gas liquids (NGL) production net (thousands of barrels/day - Mb/d) 267 296 281 303 Natural gas production net, excluding injectants (millions of cubic feet/day - MMcf/d) 645 705 670 709 Total production net (Mboe/d)(1) 374 414 392 421 Average realized prices Crude oil and NGL ($/barrel - $/bbl) 65.37 117.22 58.38 104.67 Natural gas ($/thousand cubic feet - $/Mcf) 3.44 9.55 4.56 8.56 ---------------------------------------------------------------------------- Downstream Petroleum product sales (thousands of cubic metres/day - m3/d) 50.0 51.8 50.5 52.0 Average refinery utilization (%) 85 96 87 99 Downstream operating earnings (loss) after-tax (cents/litre) (0.4) - 0.5 0.6 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- (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 to create the premier Canadian energy company.
The Company continues to advance the three major growth projects previously sanctioned by the Company: 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 EPSAs. The other three major growth projects, MacKay River expansion, Fort Hills mining project and the Montreal coker, are not sanctioned by the Company and are on hold until the merger with Suncor is completed. After the close of the merger all capital projects for the merged company will be reviewed in the context of capital investment being directed toward projects with the strongest near-term cash flow potential, highest anticipated return on capital and lowest risk.
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
- Terra Nova successfully completed a nine-day turnaround in the second quarter of 2009 and is planning a 21-day turnaround in the third quarter of 2009 to complete 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.
- Syncrude is planning a 15-day turnaround in the third quarter of 2009 that will be significantly smaller in scope than the spring turnaround.
- MacKay River is planning a 14-day slowdown in the third quarter of 2009 for planned maintenance of the third-party co-generation unit.
Major Project Update
- Development drilling has commenced and installation of subsea infrastructure is underway for the North Amethyst portion of the White Rose Extensions, with the project on schedule to deliver first oil in early 2010. The West White Rose development will be divided into two stages. Stage 1 was approved in the second quarter of 2009 and development drilling and subsea installation of this stage will take place in 2010, with first oil expected in late 2010 or early 2011. Results of Stage 1, combined with ongoing evaluation, will help define the scope of Stage 2.
- In the second quarter of 2009, co-venturers in the ExxonMobil Canada Properties (ExxonMobil) operated Hibernia South project signed a non-binding Memorandum of Understanding (MOU) with the Government of Newfoundland and Labrador establishing the key fiscal, equity and operational principles for the development of the Hibernia Southern Extension satellite (Petro-Canada's working interest is 20%), with anticipated production starting in late 2009 or early 2010.
- The Syria Ebla gas project is on plan and was 70% complete at the end of the second quarter of 2009. Three wells have been drilled and handed over to the engineering, procurement and construction contractor for tie-in. The 910 km2 Ash Shaer 3D seismic shoot was completed in the second quarter of 2009 and the seismic crew moved on to Petro-Canada Cherrife acreage. 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 second quarter of 2009, with approximately 55% of the program completed at the end of the second quarter.
BUSINESS UNIT RESULTS
UPSTREAM
North American Natural Gas
---------------------------------------------------------------------------- Three months ended Six months ended June 30, June 30, (millions of Canadian dollars) 2009 2008 2009 2008 ---------------------------------------------------------------------------- Net earnings (loss) $ (239) $ 100 $ (241) $ 174 ---------------------------------------------------------------------------- Loss on sale of assets (1) - (106) - (104) Income tax adjustments - - 1 - Asset impairment charge (2) (158) - (158) (24) ---------------------------------------------------------------------------- Operating earnings (loss) $ (81) $ 206 $ (84) $ 302 ---------------------------------------------------------------------------- Cash flow from operating activities before changes in non-cash working capital $ 42 $ 404 $ 160 $ 668 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- (1) In the second quarter of 2008, the North American Natural Gas business unit completed the sale of its Minehead assets in Western Canada, resulting in a loss on sale of $153 million before-tax ($112 million after-tax).
(2) In the second quarter of 2009, the North American Natural Gas business unit recorded a charge of $244 million before-tax ($158 million after- tax) for impairments primarily related to the CBM assets in the U.S.
Rockies due to production performance combined with lower prices. 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 second quarter of 2009, North American Natural Gas recorded an operating loss of $81 million, compared with operating earnings of $206 million in the second quarter of 2008. Results reflected lower realized prices, volumes and sulphur sales, combined with higher exploration and DD&A expenses.
North American Natural Gas production averaged 608 million cubic feet of gas equivalent/day (MMcfe/d) in the second quarter of 2009, down 8% from 660 MMcfe/d in the same quarter of 2008. Decreased production reflected reduced capital spending and natural declines.
Oil Sands
---------------------------------------------------------------------------- Three months ended Six months ended June 30, June 30, (millions of Canadian dollars) 2009 2008 2009 2008 ---------------------------------------------------------------------------- Net earnings (loss) $ (188) $ 177 $ (256) $ 289 ---------------------------------------------------------------------------- Income tax adjustments 1 - 2 2 Charges due to the deferral of the Fort Hills project (1) (185) - (241) - ---------------------------------------------------------------------------- Operating earnings (loss) $ (4) $ 177 $ (17) $ 287 ---------------------------------------------------------------------------- Cash flow from (used in) operating activities before changes in non-cash working capital $ (12) $ 231 $ (50) $ 399 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- (1) In the second quarter of 2009, the Oil Sands business unit recorded expenses of $252 million before-tax ($185 million after-tax) primarily related to writedowns of property, plant and equipment due to the indefinite deferral of the upgrading portion of the Fort Hills project.
In the first quarter of 2009, the Oil Sands business unit recorded expenses of $80 million before-tax ($56 million after-tax) to reflect costs incurred terminating certain goods and services agreements and writedowns on certain property, plant and equipment due to the deferral of the Fort Hills FID.
Oil Sands had an operating loss of $4 million in the second quarter of 2009, compared with operating earnings of $177 million in the second quarter of 2008. Results reflected lower realized prices, lower production from Syncrude and higher operating expense, partially offset by increased production from MacKay River.
Oil Sands production averaged 53,000 barrels/day (b/d) in the second quarter of 2009, relatively unchanged from 53,900 b/d in the second quarter of 2008. Increased production at MacKay River reflected strong reliability and increased capability as well as planned maintenance in the second quarter of 2008. Decreased Syncrude production reflected operational upsets and the longer than planned completion of the turnaround of Coker 8-3 in the current quarter.
International & Offshore
East Coast Canada
---------------------------------------------------------------------------- Three months ended Six months ended June 30, June 30, (millions of Canadian dollars) 2009 2008 2009 2008 ---------------------------------------------------------------------------- Net earnings (1) $ 137 $ 385 $ 241 $ 760 ---------------------------------------------------------------------------- Terra Nova insurance proceeds - - - 29 Income tax adjustments - - 1 2 ---------------------------------------------------------------------------- Operating earnings $ 137 $ 385 $ 240 $ 729 ---------------------------------------------------------------------------- Cash flow from operating activities before changes in non-cash working capital $ 221 $ 464 $ 418 $ 930 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- (1) East Coast Canada crude oil inventory movements increased (decreased) net earnings by $35 million before-tax ($24 million after-tax) and $(4) million before-tax ($(3) million after-tax) for the three and six months ended June 30, 2009, respectively. The same factor decreased net earnings by $57 million before-tax ($39 million after-tax) and $63 million before-tax ($43 million after-tax) for the three and six months ended June 30, 2008, respectively.
In the second quarter of 2009, East Coast Canada contributed $137 million of operating earnings, down from $385 million in the second quarter of 2008. Results reflected lower realized prices and production.
East Coast Canada production averaged 69,200 b/d in the second quarter of 2009, down 23% from 90,400 b/d in the same period in 2008. Hibernia production was lower due to the completion of a 25-day turnaround and natural declines, which were partially offset by strong reservoir performance and reliability. Terra Nova production was lower due to natural declines and the completion of a nine-day maintenance turnaround, while White Rose production was lower due to natural declines.
International
---------------------------------------------------------------------------- Three months ended Six months ended June 30, June 30, (millions of Canadian dollars) 2009 2008 2009 2008 ---------------------------------------------------------------------------- Net earnings (1) $ 143 $ 672 $ 184 $ 1,008 ---------------------------------------------------------------------------- Gain (loss) on sale of assets (5) 6 (5) 6 Libya EPSA ratification adjustment (2) - 47 - - Income tax adjustment (3) - 230 - 230 ---------------------------------------------------------------------------- Operating earnings $ 148 $ 389 $ 189 $ 772 ---------------------------------------------------------------------------- Cash flow from operating activities before changes in non-cash working capital $ 304 $ 635 $ 558 $ 1,191 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- (1) International crude oil inventory movements decreased net earnings by $5 million before-tax ($1 million after-tax) and $3 million before-tax ($nil after-tax) for the three and six months ended June 30, 2009, respectively. The same factor increased (decreased) net earnings by $42 million before-tax ($(14) million after-tax) and $76 million before-tax ($11 million after-tax) for the three and six months ended June 30, 2008, respectively.
(2) In the second quarter of 2008, the Company signed six new EPSAs with the Libya NOC to replace existing concession agreements and one EPSA. The new EPSAs were ratified as of the signing, with an effective date of January 1, 2008. Net earnings for the three months ended June 30, 2008 included a $47 million after-tax adjustment to recognize incremental earnings on the new EPSAs relating to the period from January 1 to March 31, 2008, which could not be recognized until ratification on June 19, 2008.
(3) In the second quarter of 2008, the International business unit recorded a $230 million future income tax recovery due to the ratification of the Libya EPSAs.
International contributed $148 million of operating earnings in the second quarter of 2009, down from $389 million in the second quarter of 2008. Lower realized crude oil prices, decreased production volumes, and higher operating and DD&A expenses were partially offset by lower exploration expense and foreign exchange gains.
International production averaged 150,600 boe/d in the second quarter of 2009, down 6% from 159,500 boe/d in the second quarter of 2008. Decreased production primarily reflected Organization of the Petroleum Exporting Countries (OPEC) quota restraints imposed in Libya and natural declines in some North Sea assets.
Exploration Update
During the first half of 2009, Petro-Canada and its partners finished operations on six wells. 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. In the United Kingdom (U.K.) sector of the North Sea, one well was completed as an oil discovery (Hobby), and one well was plugged and abandoned (appraisal well for the Pink discovery). 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
---------------------------------------------------------------------------- Three months ended Six months ended June 30, June 30, (millions of Canadian dollars) 2009 2008 2009 2008 ---------------------------------------------------------------------------- Net earnings $ 121 $ 300 $ 203 $ 484 ---------------------------------------------------------------------------- Gain on sale of assets - 1 2 2 Downstream estimated current cost of supply adjustment 137 299 152 422 Insurance premium surcharges 1 - 1 - Income tax adjustments 1 - 3 2 ---------------------------------------------------------------------------- Operating earnings (loss) $ (18) $ - $ 45 $ 58 ---------------------------------------------------------------------------- Cash flow from operating activities before changes in non-cash working capital $ 286 $ 433 $ 565 $ 741 ---------------------------------------------------------------------------- ----------------------------------------------------------------------------
In the second quarter of 2009, the Downstream business recorded an operating loss of $18 million, compared with operating earnings of $nil in the same quarter of 2008.
Refining and Supply recorded a second quarter 2009 operating loss of $60 million, down compared with a loss of $16 million in the same quarter of 2008. The increased operating loss reflected lower distillate cracking margins, unfavourable crude price differentials and higher DD&A. These factors were partially offset by an increase in realized refining margins for asphalt and coke, lubricants, heavy fuel oil and light oil products and higher gasoline cracking margins.
Marketing contributed second quarter 2009 operating earnings of $42 million, up compared with $16 million in the same quarter of 2008. Marketing results reflected higher margins and lower expenses, partially offset by lower overall volume demand.
CORPORATE
---------------------------------------------------------------------------- Three months ended Six months ended Shared Services and Eliminations June 30, June 30, (millions of Canadian dollars) 2009 2008 2009 2008 ---------------------------------------------------------------------------- Net earnings (loss) $ 103 $ (136) $ (101) $ (141) ---------------------------------------------------------------------------- Foreign currency translation gain (loss) on long-term debt 273 (13) 174 (61) Stock-based compensation expense (1) (87) (117) (112) (49) Income tax adjustments - - - 20 ---------------------------------------------------------------------------- Operating loss $ (83) $ (6) $ (163) $ (51) ---------------------------------------------------------------------------- Cash flow used in operating activities before changes in non-cash working capital $ (207) $ (188) $ (315) $ (98) ---------------------------------------------------------------------------- ----------------------------------------------------------------------------
(1) Reflected the change in the mark-to-market valuation of stock-based compensation.
Shared Services and Eliminations recorded an operating loss of $83 million in the second quarter of 2009, compared with a loss of $6 million for the same period in 2008. The increase in operating loss was due to foreign currency translation losses on cash and cash equivalents, versus a gain in the same period last year, 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 profits on these sales in the same period last year.
The Company's financial capacity and flexibility remain strong. 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.
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 second 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 Thursday, July 30, 2009 at 9:00 a.m. eastern daylight time (EDT). To participate, please call 1-800-7... (toll-free in North America), 00-800-4222-8835 (toll-free internationally), or 416-69... at 8:55 a.m. EDT. Media are invited to listen to the call by dialing 1-800-9... (toll-free in North America) or 416-69.... 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 July 30, 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 1-800-4... (toll-free in North America) or 416-695-5800 (pass code number 6821571#). 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
- contingent liabilities (including potential exposure to losses related to retail licensee agreements)
- the impact and cost of compliance with existing and potential environmental regulations
- 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 July 30, 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 ---------------------------------------------------------------------------- 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 Resources Petroleum Resources Management System: 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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