For immediate release
October 23, 2008 (publié également en français)
Execution of Petro-Canada’s Strategy Delivers Another Solid Quarter
Highlights
| · | Robust cash flow, a strong balance sheet and liquidity provide financial stability in a turbulent market |
| · | Reliable upstream operations deliver strong production in line with guidance |
| · | Construction of the Edmonton refinery conversion project (RCP) completed and refinery on track for fourth quarter 2008 startup |
Calgary – Petro-Canada announced today third quarter operating earnings of $1,242 million ($2.56/share), up 97% from $630 million ($1.29/share) in the third quarter of 2007. Third quarter 2008 cash flow from operating activities before changes in non-cash working capital was $2,116 million ($4.37/share), up 72% from $1,229 million ($2.52/share) in the same quarter of last year.
Net earnings were $1,251 million ($2.58/share) in the third quarter of 2008, compared with $776 million ($1.59/share) in the same quarter of 2007.
“Our businesses are running reliably and are generating solid cash flow to help fund our future projects,” said Ron Brenneman, president and chief executive officer.
“We've always been a financially conservative company – in the way we fund our operations and in how we evaluate and finance our growth projects,” added Brenneman. "This prudent, long-term view positions us well during these volatile economic times."
Third Quarter Results
| | | Three months ended September 30, | | | Nine months ended September 30, | |
| (millions of Canadian dollars, except as noted) | | 2008 | | | 2007 | | | 2008 | | | 2007 | |
| Consolidated Results | | | | | | | | | | | | |
Operating earnings 1 | | $ | 1,242 | | | $ | 630 | | | $ | 3,339 | | | $ | 2,015 | |
| – $/share | | | 2.56 | | | | 1.29 | | | | 6.90 | | | | 4.10 | |
| Net earnings | | | 1,251 | | | | 776 | | | | 3,825 | | | | 2,211 | |
| – $/share | | | 2.58 | | | | 1.59 | | | | 7.90 | | | | 4.50 | |
Cash flow from operating activities before changes in non-cash working capital 2 | | | 2,116 | | | | 1,229 | | | | 5,947 | | | | 3,745 | |
| – $/share | | | 4.37 | | | | 2.52 | | | | 12.29 | | | | 7.62 | |
| Dividends – $/share | | | 0.20 | | | | 0.13 | | | | 0.46 | | | | 0.39 | |
| Share buyback program | | | – | | | | 220 | | | | – | | | | 735 | |
| – millions of shares | | | – | | | | 4.0 | | | | – | | | | 14.0 | |
| Capital expenditures | | $ | 1,439 | | | $ | 992 | | | $ | 4,596 | | | $ | 2,508 | |
Weighted-average common shares outstanding (millions of shares) | | | 484.4 | | | | 487.6 | | | | 484.0 | | | | 491.6 | |
Total production net before royalties (thousands of barrels of oil equivalent/day – Mboe/d) 3 | | | 424 | | | | 436 | | | | 422 | | | | 422 | |
Operating return on capital employed (%) 4 | | | | | | | | | | | | | | | | |
| Upstream | | | | | | | | | | | 39.7 | | | | 26.0 | |
Downstream 4 | | | | | | | | | | | 3.1 | | | | 12.5 | |
Total Company 4 | | | | | | | | | | | 23.5 | | | | 19.6 | |
| 1 | Operating earnings (which represent net earnings, excluding gains or losses on foreign currency translation of long-term debt and on sale of assets, excluding the change in fair value of the Buzzard derivative contracts (applies to 2007 and prior only), including the Downstream estimated current cost of supply adjustment and excluding mark-to-market valuations of stock-based compensation, income tax adjustments, asset impairment, insurance proceeds and surcharges and purchased crude oil inventory write-downs – 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. In 2008, Downstream and Total Company operating return on capital employed includes the Downstream estimated current cost of supply adjustment. |
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 sale of assets, excluding the change in fair value of derivative contracts associated with the Buzzard acquisition (applies to 2007 and prior only), 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 surcharges, and purchased crude oil inventory write-downs. 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.
On January 1, 2008, the Company adopted Canadian Institute of Chartered Accountants (CICA) Section 3031, Inventories, and now assigns costs for its crude oil and refined petroleum products inventories on a “first-in, first-out” (FIFO) basis whereas, previously, these costs were assigned on a “last-in, first-out” (LIFO) basis. To facilitate a better understanding of the Company’s Downstream performance, operating earnings for 2008 onward are being presented on an estimated current cost of supply basis, which is a non-GAAP measure. On this basis, cost of sales is determined by estimating the current cost of supply for all volumes sold in the period after making allowance for the estimated tax effect, instead of using a FIFO basis for valuing inventories. Operating earnings calculated on this basis do not represent the application of a LIFO basis of valuing inventories, used prior to 2008, and, therefore, the Downstream estimated current cost of supply adjustment does not have comparatives.
| | | Three months ended September 30, | | | Nine months ended September 30, | |
| (millions of Canadian dollars, except per share amounts) | | 2008 | | | ($/share) | | | 2007 | | | ($/share) | | | 2008 | | | ($/share) | | | 2007 | | | ($/share) | |
| Net earnings | | $ | 1,251 | | | $ | 2.58 | | | $ | 776 | | | $ | 1.59 | | | $ | 3,825 | | | $ | 7.90 | | | $ | 2,211 | | | $ | 4.50 | |
Foreign currency translation gain (loss) on long-term debt 1 | | | (103 | ) | | | | | | | 78 | | | | | | | | (164 | ) | | | | | | | 198 | | | | | |
Change in fair value of Buzzard derivative contracts 2 | | | – | | | | | | | | 70 | | | | | | | | – | | | | | | | | (18 | ) | | | | |
Gain (loss) on sale of assets 3 | | | 91 | | | | | | | | 8 | | | | | | | | (5 | ) | | | | | | | 55 | | | | | |
| Downstream estimated current cost of supply adjustment | | | (128 | ) | | | | | | | – | | | | | | | | 294 | | | | | | | | – | | | | | |
| Mark-to-market valuation of stock-based compensation | | | 160 | | | | | | | | (10 | ) | | | | | | | 111 | | | | | | | | (99 | ) | | | | |
Income tax adjustments 4 | | | (3 | ) | | | | | | | – | | | | | | | | 253 | | | | | | | | 48 | | | | | |
Asset impairment charge 5 | | | – | | | | | | | | – | | | | | | | | (24 | ) | | | | | | | – | | | | | |
| Insurance proceeds net of surcharges | | | – | | | | | | | | – | | | | | | | | 29 | | | | | | | | 12 | | | | | |
Purchased crude oil inventory write-downs 6 | | | (8 | ) | | | | | | | – | | | | | | | | (8 | ) | | | | | | | – | | | | | |
| Operating earnings | | $ | 1,242 | | | $ | 2.56 | | | $ | 630 | | | $ | 1.29 | | | $ | 3,339 | | | $ | 6.90 | | | $ | 2,015 | | | $ | 4.10 | |
| 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 | During the fourth quarter of 2007, the Company entered into derivative contracts to close out the hedged portion of its Buzzard production from January 1, 2008 to December 31, 2010. |
| 3 | In the third quarter of 2008, the International & Offshore business unit completed the sale of its Denmark assets in the International segment, resulting in a gain on sale of $107 million before-tax ($82 million after-tax). 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). In addition to the sale of these assets there were additional, less significant, asset sales resulting in gains of $38 million before-tax ($25 million after-tax) for the nine months ended September 30, 2008. The sale of these assets is aligned with the business units’ strategies to continuously optimize the assets in their portfolio. |
| 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 Exploration and Production Sharing Agreements (EPSAs). |
| 5 | 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 third quarter of 2008, the Oil Sands business unit recorded a $38 million before-tax ($26 million after-tax) charge for the write-down of crude oil inventory purchased for line fill for the Edmonton RCP. Partially offsetting this write-down, Shared Services and Eliminations recorded a $26 million before-tax ($18 million after-tax) recovery to recognize the Downstream's expected future margins from refining this crude oil inventory and selling the refined petroleum products. As a result, the Company recorded a net write-down of $12 million before-tax ($8 million after-tax). |
Earnings Variances
| | Q3/08 VERSUS Q3/07 FACTOR ANALYSIS |
| | (millions of Canadian dollars, after-tax) |
| Operating earnings increased 97% to $1,242 million ($2.56/share) in the third quarter of 2008, compared with $630 million ($1.29/share) in the third quarter of 2007. The increase in third quarter operating earnings reflected the positive impact of higher realized upstream prices ($610 million) and lower other expenses1 ($180 million). The gains were partially offset by lower upstream production2 ($(47) million), lower Downstream margins3 ($(9) million) and higher operating, general and administrative (G&A) ($(94) million), and DD&A and exploration expenses ($(28) million). |
| 1 | Other mainly included interest expense, foreign exchange, changes in effective tax rates and upstream inventory movements. |
| 2 | Upstream volumes included the portion of DD&A expense associated with changes in upstream production levels. |
| 3 | Downstream margin included the estimated current cost of supply adjustment. |
| | Operating Earnings by Segment |
| | (millions of Canadian dollars, after-tax) |
| The increase in third quarter operating earnings on a segmented basis reflected higher North American Natural Gas ($101 million), Oil Sands ($125 million), East Coast Canada ($104 million) and International ($281 million) operating earnings and lower Shared Services costs ($4 million). The results were partially offset by slightly lower Downstream operating earnings ($(3) million). |
Net earnings in the third quarter of 2008 increased 61% to $1,251 million ($2.58/share), compared with $776 million ($1.59/share) during the same period in 2007. Net earnings in the third quarter of 2008 were higher than in the third quarter of 2007 due to higher operating earnings, gains on sale of assets, a recovery from the mark-to-market valuation of stock-based compensation and the benefit associated with settling the Buzzard derivative contracts in the fourth quarter of 2007. These factors were partially offset by losses on foreign currency translation of long-term debt.
| | | Three months ended September 30, | | | Nine months ended September 30, | |
| (millions of Canadian dollars) | | 2008 | | | 2007 | | | 2008 | | | 2007 | |
| Cash flow from operating activities | | $ | 1,279 | | | $ | 1,340 | | | $ | 5,193 | | | $ | 3,941 | |
| Increase (decrease) in non-cash working capital related to operating activities | | | 837 | | | | (111 | ) | | | 754 | | | | (196 | ) |
| Cash flow from operating activities before changes in non-cash working capital | | $ | 2,116 | | | $ | 1,229 | | | $ | 5,947 | | | $ | 3,745 | |
During the third quarter of 2008, cash flow from operating activities before changes in non-cash working capital was $2,116 million ($4.37/share), up from $1,229 million ($2.52/share) in the same quarter of 2007. The increase in cash flow from operating activities before changes in non-cash working capital reflected higher net earnings.
Operating Highlights
Third quarter production averaged 424,000 barrels of oil equivalent/day (boe/d) net to Petro-Canada in 2008, down 3% from 436,000 boe/d net in the same quarter of 2007. Lower volumes reflected decreased East Coast Canada and International production, partially offset by increased Oil Sands production. North American Natural Gas production was relatively unchanged.
The Downstream successfully completed construction of the Edmonton refinery for the RCP. Marketing performance was strong in the quarter, partially offset by lower Refining and Supply earnings.
| | Three months ended September 30, | Nine months ended September 30, |
| | 2008 | 2007 | 2008 | 2007 |
| Upstream – Consolidated | | | | |
| Production before royalties | | | | |
Crude oil and natural gas liquids (NGL) production net (thousands of barrels/day – Mb/d) | 306 | 315 | 304 | 300 |
Natural gas production net, excluding injectants (millions of cubic feet/day – MMcf/d) | 709 | 723 | 709 | 730 |
Total production net (Mboe/d) 1 | 424 | 436 | 422 | 422 |
| Average realized prices | | | | |
Crude oil and NGL ($/barrel – $/bbl) | 114.11 | 74.32 | 107.85 | 69.42 |
Natural gas ($/thousand cubic feet – $/Mcf) | 8.68 | 5.28 | 8.60 | 6.47 |
| Downstream | | | | |
Petroleum product sales (thousands of cubic metres/day – m3/d) | 52.7 | 53.6 | 52.2 | 52.8 |
Average refinery utilization (%) | 75 | 99 | 90 | 99 |
Downstream operating earnings after-tax (cents/litre) 2 | 2.1 | 2.1 | 1.1 | 3.8 |
| 1 | Total production includes natural gas converted at six Mcf of natural gas for one bbl of oil. |
| 2 | In 2008, Downstream operating earnings after-tax includes the Downstream estimated current cost of supply adjustment. |
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.
Petro-Canada’s capital program supports bringing on seven major projects over the next several years to deliver long-term profitable growth. For the remainder of 2008, the Company expects to start up the project to convert the Edmonton refinery to process lower cost, oil sands-based feedstock, and make a final investment decision (FID) on the Fort Hills mining and upgrading project. These projects are expected to add significant earnings and cash flow.
Petro-Canada continually works to strengthen its base business by improving the safety, reliability and efficiency of its operations. For the remainder of 2008, the Company is focused on delivering upstream production in line with guidance.
Outlook
Operational Updates
| · | MacKay River achieved a new production record, averaging 29,700 barrels/day (b/d) for the month of September 2008. |
| · | No major turnarounds planned for the remainder of 2008 in North American Natural Gas, Oil Sands, East Coast Canada or the Downstream. |
| · | Buzzard had expected to commence its planned maintenance turnaround in August 2008 but, due to adverse weather conditions, this seven- to nine-day turnaround has been delayed to the fourth quarter of 2008. |
Major Project Milestones
| · | Construction of the Edmonton RCP was completed at the end of the third quarter and the refinery is on track for startup in the fourth quarter of 2008. |
| · | The Montreal coker investment decision is pending resolution of the labour dispute. |
| · | Engineering and fabrication of the North Amethyst portion of the White Rose Extensions project is being advanced, with the project on schedule to deliver first oil in late 2009 or early 2010. |
| · | The Syria Ebla gas project is 35% complete, with first gas expected in 2010. Field construction and detailed engineering is in progress. An appraisal well was drilled and tested in the third quarter of 2008, resulting in better than expected production rates, and a second rig was mobilized and 3D seismic operations began in August 2008. |
| · | With six new EPSAs signed by the Libya National Oil Corporation, implementation work is focusing on preparing the Amal field development program, capturing early opportunities to increase production and initiating the new exploration program. Three seismic crews were deployed by the end of the third quarter of 2008. |
| · | The MacKay River expansion project continues with design refinement and receiving and reviewing lump sum construction bid contracts. FID is expected in the first quarter of 2009. |
| · | The estimated all-in capital costs for the Fort Hills project, as currently conceived, are expected to increase by approximately 50% from the initial estimate of $18.8 billion (including third party costs) announced in June 2007. The partners are looking at different configurations and timing options to arrive at the best project combination. In the near-term, the partners contemplate making an investment decision only with respect to the mining portion of the project and deferring a decision to construct the upgrader portion, which would substantially reduce project costs prior to first oil. The partners remain committed to mine production in 2011. Final regulatory decisions on the upgrader and the proposed amendment to the approved mine plan are anticipated by year-end 2008. With a definitive cost estimate, upgrader regulatory approval and partner approvals in place, a decision on how best to proceed is expected by year-end 2008. |
BUSINESS UNIT RESULTS
UPSTREAM
North American Natural Gas
| | | Three months ended September 30, | | | Nine months ended September 30, | |
| (millions of Canadian dollars) | | 2008 | | | 2007 | | | 2008 | | | 2007 | |
| Net earnings | | $ | 165 | | | $ | 55 | | | $ | 339 | | | $ | 248 | |
Gain (loss) on sale of assets 1 | | | 9 | | | | – | | | | (95 | ) | | | 41 | |
| Income tax adjustments | | | – | | | | – | | | | – | | | | 1 | |
Asset impairment charge 2 | | | – | | | | – | | | | (24 | ) | | | – | |
| Operating earnings | | $ | 156 | | | $ | 55 | | | $ | 458 | | | $ | 206 | |
| Cash flow from operating activities before changes in non-cash working capital | | $ | 336 | | | $ | 130 | | | $ | 1,004 | | | $ | 547 | |
| 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). The sale of these assets is aligned with the business unit’s strategy to continuously optimize the assets in its portfolio. |
| 2 | 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 third quarter of 2008, North American Natural Gas contributed $156 million of operating earnings, compared with $55 million in the third quarter of 2007. Higher realized prices and lower exploration expenses were partially offset by higher operating and DD&A expenses.
North American Natural Gas production averaged 674 million cubic feet of gas equivalent/day (MMcfe/d) in the third quarter of 2008, relatively unchanged from 675 MMcfe/d in the same quarter of 2007. Production reflected higher natural gas production in the U.S. Rockies and strong performance in Western Canada.
Oil Sands
| | | Three months ended September 30, | | | Nine months ended September 30, | |
| (millions of Canadian dollars) | | 2008 | | | 2007 | | | 2008 | | | 2007 | |
| Net earnings | | $ | 209 | | | $ | 110 | | | $ | 498 | | | $ | 187 | |
| Gain on sale of assets | | | – | | | | – | | | | – | | | | 1 | |
| Income tax adjustments | | | – | | | | – | | | | 2 | | | | 7 | |
Purchased crude oil inventory write-downs 1 | | | (26 | ) | | | – | | | | (26 | ) | | | – | |
| Operating earnings | | $ | 235 | | | $ | 110 | | | $ | 522 | | | $ | 179 | |
| Cash flow from operating activities before changes in non-cash working capital | | $ | 285 | | | $ | 192 | | | $ | 684 | | | $ | 406 | |
| 1 | In the third quarter of 2008, Oil Sands recorded a $38 million before-tax ($26 million after-tax) write-down of crude oil inventory purchased for line fill for the Edmonton RCP. This write-down was partially offset by a recovery of $26 million before-tax ($18 million after-tax) recorded in Shared Services and Eliminations. |
Oil Sands delivered operating earnings of $235 million in the third quarter of 2008, up from $110 million in the third quarter of 2007. Higher realized prices and production were partially offset by higher operating costs.
Oil Sands production averaged 66,900 b/d in the third quarter of 2008, up 5% from 63,800 b/d in the third quarter of 2007. Increased production primarily reflected increased reliability and capability at MacKay River, partially offset by a planned 45-day turnaround of Coker 8-2 at Syncrude that began in early September 2008.
International & Offshore
East Coast Canada
| | | Three months ended September 30, | | | Nine months ended September 30, | |
| (millions of Canadian dollars) | | 2008 | | | 2007 | | | 2008 | | | 2007 | |
Net earnings 1 | | $ | 397 | | | $ | 293 | | | $ | 1,157 | | | $ | 883 | |
| Terra Nova insurance proceeds | | | – | | | | – | | | | 29 | | | | 7 | |
| Income tax adjustments | | | – | | | | – | | | | 2 | | | | 5 | |
| Operating earnings | | $ | 397 | | | $ | 293 | | | $ | 1,126 | | | $ | 871 | |
| Cash flow from operating activities before changes in non-cash working capital | | $ | 501 | | | $ | 387 | | | $ | 1,431 | | | $ | 1,164 | |
| 1 | East Coast Canada crude oil inventory movements increased (decreased) net earnings by $3 million before-tax ($2 million after-tax) and $(60) million before-tax ($(41) million after-tax) for the three and nine months ended September 30, 2008, respectively. The same factor increased net earnings by $23 million before-tax ($15 million after-tax) and $48 million before-tax ($32 million after-tax) for the three and nine months ended September 30, 2007, respectively. |
In the third quarter of 2008, East Coast Canada contributed $397 million of operating earnings, up from $293 million in the third quarter of 2007. Higher realized prices and lower exploration expenses were partially offset by lower production and higher royalty payments.
East Coast Canada production averaged 90,600 b/d in the third quarter of 2008, down 11% from 102,100 b/d in the same period in 2007. Terra Nova’s production was lower due to a planned overhaul of a main power generator, seal repairs in a gas lift riser and natural declines. White Rose production was lower due to the impact of an unplanned shutdown in September 2008 due to tanker offloading issues. These reductions were partially offset by slightly higher Hibernia production due to the positive impact of recent well workovers and strong reliability, which offset natural declines.
International
| | | Three months ended September 30, | | | Nine months ended September 30, | |
| (millions of Canadian dollars) | | 2008 | | | 2007 | | | 2008 | | | 2007 | |
Net earnings 1 | | $ | 483 | | | $ | 200 | | | $ | 1,491 | | | $ | 404 | |
Change in fair value of Buzzard derivative contracts 2 | | | – | | | | 70 | | | | – | | | | (18 | ) |
Gain on sale of assets 3 | | | 82 | | | | 7 | | | | 88 | | | | 7 | |
| Scott insurance proceeds | | | – | | | | – | | | | – | | | | 5 | |
Income tax adjustments 4 | | | (3 | ) | | | – | | | | 227 | | | | 30 | |
| Operating earnings | | $ | 404 | | | $ | 123 | | | $ | 1,176 | | | $ | 380 | |
| Cash flow from operating activities before changes in non-cash working capital | | $ | 653 | | | $ | 388 | | | $ | 1,844 | | | $ | 1,027 | |
| 1 | International crude oil inventory movements increased net earnings by $12 million before-tax ($7 million after-tax) and $88 million before-tax ($18 million after-tax) for the three and nine months ended September 30, 2008, respectively. The same factor increased net earnings by $58 million before-tax ($13 million after-tax) and $28 million before-tax ($6 million after-tax) for the three and nine months ended September 30, 2007, respectively. |
| 2 | During the fourth quarter of 2007, the Company entered into derivative contracts to close out the hedged portion of its Buzzard production from January 1, 2008 to December 31, 2010. |
| 3 | In the third quarter of 2008, the International & Offshore business unit completed the sale of its Denmark assets in the International segment, resulting in a gain on sale of $107 million before-tax ($82 million after-tax). |
| 4 | 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 $404 million of operating earnings in the third quarter of 2008, up from $123 million recorded in the third quarter of 2007. Higher realized prices, foreign exchange gains and lower operating and DD&A expenses were partially offset by lower production volumes and increased exploration expenses. Higher exploration expenses were due to well write-offs in Trinidad and Tobago, and Norway.
Net earnings in the third quarter of 2007 included a $70 million unrealized gain and an $87 million realized loss on the Buzzard derivative contracts.
International production averaged 154,100 boe/d in the third quarter of 2008, down 2% from 157,200 boe/d in the third quarter of 2007. Decreased production primarily reflected natural declines in several North Sea assets and a planned turnaround of the Triton facility in August. These factors were partially offset by higher Buzzard production due to strong operating performance and the weather-related deferral of a seven- to nine-day turnaround planned for August.
Exploration Update
For the nine months ended September 30, 2008, Petro-Canada and its partners finished operations on 14 of the up to 17 wells planned for the year. Three of the wells were completed as natural gas discoveries (Gubik-3 in the Alaska Foothills, Sancoche on Block 22 offshore Trinidad and Tobago, and van Ghent in the Netherlands sector of the North Sea). One well was completed as an oil discovery (Pink in the United Kingdom (U.K.) sector of the North Sea). Two successful appraisal wells were completed (Cassra 2 on Block 22 offshore Trinidad and Tobago, and Farigh 14-12 in Libya). Two wells were completed as non-commercial discoveries (Maria in the U.K. sector of the North Sea and L5a-11 in the Netherlands sector of the North Sea). Drilling of the Chandler-1 well in the Alaska Foothills was suspended, as planned, for re-entry next season. Five wells were dry and abandoned (Kwijika in the Northwest Territories, Gemini in the U.K. sector of the North Sea, Tegu in Block 1a offshore Trinidad and Tobago, Bene on Block 22 offshore Trinidad and Tobago, and Trow in the Norwegian sector of the North Sea).
DOWNSTREAM
| | | Three months ended September 30, | | | Nine months ended September 30, | |
| (millions of Canadian dollars) | | 2008 | | | 2007 | | | 2008 | | | 2007 | |
| Net earnings (loss) | | $ | (27 | ) | | $ | 105 | | | $ | 457 | | | $ | 548 | |
| Gain on sale of assets | | | – | | | | 1 | | | | 2 | | | | 6 | |
Downstream estimated current cost of supply adjustment 1 | | | (128 | ) | | | – | | | | 294 | | | | – | |
| Income tax adjustments | | | – | | | | – | | | | 2 | | | | 6 | |
| Operating earnings | | $ | 101 | | | $ | 104 | | | $ | 159 | | | $ | 536 | |
| Cash flow from operating activities before changes in non-cash working capital | | $ | 111 | | | $ | 187 | | | $ | 852 | | | $ | 860 | |
| 1 | On January 1, 2008, the Company adopted CICA Section 3031, Inventories, and now assigns costs for its crude oil and refined petroleum products inventories on a FIFO basis whereas, previously, these costs were assigned on a LIFO basis. To facilitate a better understanding of the Company’s Downstream performance, operating earnings for 2008 onward are being presented on an estimated current cost of supply basis, which is a non-GAAP measure (see page 2 NON-GAAP MEASURES). On this basis, cost of sales is determined by estimating the current cost of supply for all volumes sold in the period after making allowance for the estimated tax effect, instead of using a FIFO basis for valuing inventories. Operating earnings calculated on this basis do not represent the application of a LIFO basis of valuing inventories, used prior to 2008, and, therefore, the Downstream estimated current cost of supply adjustment does not have comparatives. |
In the third quarter of 2008, the Downstream business contributed $101 million of operating earnings, down slightly from $104 million in the same quarter of 2007.
Refining and Supply recorded third quarter 2008 operating earnings of $49 million, down compared with operating earnings of $58 million in the same quarter of 2007. Lower operating earnings reflected four key items discussed in order of impact. First, refinery yields in Edmonton were lower due to operational upsets and planned turnaround activity for the RCP. Second, operating costs increased because of maintenance and repair activity, planned turnarounds and environmental costs associated with the Quebec green levy. Third, fuel costs were higher. Fourth, gasoline cracking margins were lower. These four key items were partially offset by an increase in realized refining margins for asphalt, lubricants, and petrochemical and light oil products, as well as higher distillate cracking margins.
Marketing contributed third quarter 2008 operating earnings of $52 million, up compared with $46 million in the same quarter of 2007. In the third quarter of 2008, Marketing results reflected higher fuel margins, an increase in lubricants sales volumes and rising non-petroleum revenue, partially offset by increased operating expenses due to higher fuel costs associated with delivery and card fees.
CORPORATE
| Shared Services and Eliminations | | Three months ended September 30, | | | Nine months ended September 30, | |
| (millions of Canadian dollars) | | 2008 | | | 2007 | | | 2008 | | | 2007 | |
| Net earnings (loss) | | $ | 24 | | | $ | 13 | | | $ | (117 | ) | | $ | (59 | ) |
| Foreign currency translation gain (loss) on long-term debt | | | (103 | ) | | | 78 | | | | (164 | ) | | | 198 | |
Stock-based compensation recovery (expense) 1 | | | 160 | | | | (10 | ) | | | 111 | | | | (99 | ) |
| Income tax adjustments | | | – | | | | – | | | | 20 | | | | (1 | ) |
Purchased crude oil inventory write-downs 2 | | | 18 | | | | – | | | | 18 | | | | – | |
| Operating loss | | $ | (51 | ) | | $ | (55 | ) | | $ | (102 | ) | | $ | (157 | ) |
| Cash flow used in operating activities before changes in non-cash working capital | | $ | 230 | | | $ | (55 | ) | | $ | 132 | | | $ | (259 | ) |
| 1 | Reflected the change in the mark-to-market valuation of stock-based compensation. |
| 2 | In the third quarter of 2008, Shared Services and Eliminations recorded a $26 million before-tax ($18 million after-tax) recovery for the write-down of crude oil inventory purchased for line fill for the Edmonton RCP. The recovery recognized the Downstream’s expected future margins from refining this crude oil inventory and selling the refined petroleum products, and partially offsets write-downs of $38 million before-tax ($26 million after-tax) recorded in Oil Sands. |
Shared Services and Eliminations recorded an operating loss of $51 million in the third quarter of 2008, compared with a loss of $55 million for the same period in 2007. The decrease in operating loss was due to foreign exchange gains from transacting in U.S. dollars during the third quarter of 2008, partially offset by higher interest expense.
The Company’s financial capacity and flexibility have not been significantly impacted by the recent turmoil in the financial markets due to Petro-Canada’s continuing ability to generate strong cash flow, existing cash balances, significant credit facility capacity and lack of near-term refinancing requirements. For 2009 and beyond, spending on future large projects may result in annual capital expenditures exceeding operating cash flow. The Company anticipates that additional funding requirements will be met by external financing and that additional financial leverage can be managed in the context of Petro-Canada’s target ranges.
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 third 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, October 23, 2008 at 9:00 a.m. eastern daylight time (EDT). To participate, please call 1-866-898-9626 (toll-free in North America), 00-800-8989-6323 (toll-free internationally), or 416-340-2216 at 8:55 a.m. EDT. Media are invited to listen to the call by dialing 1-866-540-8136 (toll-free in North America) or 416-340-8010. 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 October 23, 2008 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 3269226#). 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 · construction and repair activities · 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 | · retail throughputs · pre-production and operating costs · reserves and resources estimates · 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) · environmental matters · future regulatory approvals · expected rates of return |
Such forward-looking information is subject to known and unknown risks and uncertainties. Other factors may cause actual results, levels of activity and achievements to differ materially from those expressed or implied by such information. Such factors include, but are not limited to:
· 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 · general economic, market and business conditions | · competitive action by other companies · fluctuations in oil and natural gas prices · 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 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 October 23, 2008 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 natural gas companies must prove they are economically and legally producible under existing economic and operating conditions. Note that when the term barrel 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 (includes both proved developed and proved undeveloped) | SEC reserves definition (Accounting Rules Regulation S-X 210.4-10, U.S. Financial Accounting Standards Board (FASB) Statement No. 69) SEC Guide 7 for Oilsands Mining |
| | |
| Unproved reserves, probable and possible reserves | Canadian Securities Administrators: Canadian Oil and Gas Evaluation (COGE) Handbook, 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: COGE Handbook Vol. 1 Section 5 |
Although the Society of Petroleum Engineers resource classification has categories of 1C, 2C, 3C for Contingent Resources, and low, best and high estimates for Prospective Resources, Petro-Canada will only refer to the 2C for Contingent Resources and the risked (an assessment of the probability of discovering the resources) best estimate for Prospective Resources when referencing resources in this news release. Canadian Oil Sands represents approximately 71% 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, Contingent Resources are approximately 53% and risked Prospective Resources are approximately 47% 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 oil sands mining, in situ and conventional Contingent and risked Prospective Resources prior to project sanction and regulatory approvals; and |
| · | exploration success with respect to conventional risked Prospective Resources prior to project sanction and regulatory approvals. |
Reserves and resources information contained in this news release is as at December 31, 2007.
For more information, please contact:
| INVESTOR AND ANALYST INQUIRIES | MEDIA AND GENERAL INQUIRIES |
| | |
Ken Hall Investor Relations 403-296-7859 email: investor@petro-canada.ca | Andrea Ranson Corporate Communications 403-296-4610 email: corpcomm@petro-canada.ca |
| | |
Lisa McMahon Investor Relations 403-296-3764 email: investor@petro-canada.ca | |
| | |
| www.petro-canada.ca |
