Solid Operations and Strong Liquidity Position Petro-Canada Well for Merger with Suncor

CALGARY, ALBERTA, Jul 30 (MARKET WIRE) --
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
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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
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(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.

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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
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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) -
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Operating earnings $ 99 $ 0.20 $ 1,151 $ 2.38
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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
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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) -
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Operating earnings $ 210 $ 0.43 $ 2,097 $ 4.33
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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 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.

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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)
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Cash flow from operating activities
before changes in non-cash
working capital $ 634 $ 1,979 $ 1,336 $ 3,831
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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.

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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
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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
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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 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

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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
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(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

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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
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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
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(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

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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
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(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

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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
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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

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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 1-800-769-8320 (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 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 1-800-408-3053 (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

Copyright 2009, Market Wire, All rights reserved.

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