BP PLC BP. 3rd Quarter Results
BP PLC (BP.) - 3rd Quarter Results
RNS Number : 8012P
BP PLC
30 October 2012
BP p.l.c.
Group results
Third quarter and nine months 2012
London 30 October 2012
FOR IMMEDIATE RELEASE
Third Second Third Nine Nine
quarter quarter quarter months months
2011 2012 2012 2012 2011
$ million
5,043 (1,385) 5,434 Profit (loss) for the period(a) 9,964 18,015
233 1,623 (747) Inventory holding (gains) losses, (110) (1,721)
net of tax
5,276 238 4,687 Replacement cost profit(b) 9,854 16,294
Net (favourable) unfavourable impact
of non-operating
187 3,447 483 items and fair value accounting 3,800 378
effects, net of tax(c)
5,463 3,685 5,170 Underlying replacement cost 13,654 16,672
profit(b)
Replacement cost profit
27.85 1.25 24.62 - per ordinary share (cents) 51.82 86.28
1.67 0.07 1.48 - per ADS (dollars) 3.11 5.18
Underlying replacement cost profit
28.83 19.37 27.16 - per ordinary share (cents) 71.81 88.28
1.73 1.16 1.63 - per ADS (dollars) 4.31 5.30
· BP's third-quarter replacement cost (RC) profit was $4,687 million,
compared with $5,276 million a year ago. After adjusting for a net loss from
non-operating items of $321 million and net unfavourable fair value accounting
effects of $162 million (both on a post-tax basis), underlying RC profit for
the third quarter was $5,170 million, compared with $5,463 million for the
same period last year. For the nine months, RC profit was $9,854 million,
compared with $16,294 million a year ago. After adjusting for a net loss from
non-operating items of $3,475 million and net unfavourable fair value
accounting effects of $325 million (both on a post-tax basis), underlying RC
profit for the nine months was $13,654 million, compared with $16,672 million
for the same period last year. RC profit or loss for the group, underlying RC
profit or loss and fair value accounting effects are non-GAAP measures and
further information is provided on pages 4, 19 and 21.
· The group income statement included a net adverse impact relating to the
Gulf of Mexico oil spill, on a pre-tax basis, of $59 million for the third
quarter and $882 million for the nine months. All amounts relating to the Gulf
of Mexico oil spill have been treated as non-operating items. For further
information on the Gulf of Mexico oil spill and its consequences see pages
2 - 3, Note 2 on pages 23 - 28 and Legal proceedings on pages 32 - 40.
· Finance costs and net finance income or expense relating to pensions and
other post-retirement benefits were $198 million for the third quarter,
compared with $234 million for the same period last year. For the nine months,
the respective amounts were $640 million and $722 million.
· Including the impact of the Gulf of Mexico oil spill, net cash provided by
operating activities for the third quarter and nine months was $6.3 billion
and $14.1 billion respectively, compared with $6.9 billion and $17.1 billion
in the same periods of last year. Excluding amounts related to the Gulf of
Mexico oil spill, net cash provided by operating activities for the third
quarter and nine months was $6.4 billion and $17.1 billion respectively,
compared with $7.8 billion and $22.8 billion for the same periods of last
year. Reflecting our proposed transaction with Rosneft, we remain confident in
delivering more than 50% growth in net cash provided by operating activities
by 2014(d) assuming an oil price of $100 per barrel.
· Net debt at the end of the quarter was $31.5 billion, compared with
$25.8 billion a year ago. The ratio of net debt to net debt plus equity was
20.9% compared with 18.9% a year ago. Net debt is a non-GAAP measure. See
page 5 for further information.
· On 22 October 2012, BP announced that it had signed heads of terms for a
proposed transaction to sell its 50% share in TNK-BP to Rosneft for cash
consideration of $17.1 billion and Rosneft shares representing a 12.84% stake
in Rosneft. In addition, BP would use $4.8 billion of the cash consideration
to acquire a further 5.66% stake in Rosneft from the Russian government. For
further information, see page 11.
· BP today announced a quarterly dividend of 9 cents per ordinary share
($0.54 per ADS), which is expected to be paid on 21 December 2012. The
corresponding amount in sterling will be announced on 10 December 2012. A
scrip dividend alternative is available, allowing shareholders to elect to
receive their dividend in the form of new ordinary shares and ADS holders in
the form of new ADSs. Details of the scrip dividend programme are available at
bp.com/scrip.
(a) Profit (loss) attributable to BP shareholders.
(b) See footnote (a) on page 4 for definitions of RC profit and underlying RC
profit.
(c) See pages 20 and 21 respectively for further information on non-operating
items and fair value accounting effects.
(d) This projection reflects our expectation that all required payments into
the $20-billion Deepwater Horizon Oil Spill Trust fund will have been
completed prior to 2014. The projection does not reflect any cash flows
relating to other liabilities, contingent liabilities, settlements or
contingent assets arising from the Gulf of Mexico oil spill which may or
may not arise at that time. As disclosed in Note 2 under Contingent
liabilities on page 28, we are not able at this time to reliably estimate
the amount or timing of a number of contingent liabilities.
The commentaries above and following are based on RC profit and should be read
in conjunction with the cautionary statement on page 13.
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Group headlines (continued)
· The effective tax rate on replacement cost profit for the third quarter
was 34%, compared with 31% a year ago. For the nine months the effective tax
rate on replacement cost profit was 34%, the same as a year ago. Recently
enacted changes to the taxation of UK oil and gas production resulted in a
$256-million deferred tax adjustment in the third quarter 2012. An earlier
change resulted in a $683-million deferred tax adjustment in the first quarter
2011. Excluding these adjustments the effective tax rate for the third quarter
and nine months of 2012 was 30% and 32% respectively and 31% for the
nine-month period for 2011. We now expect the full-year effective tax rate to
be at the lower end of the 34 to 36% range.
· Total capital expenditure for the third quarter and nine months was
$6.1 billion and $17.2 billion respectively, of which organic capital
expenditure was $5.9 billion and $16.5 billion respectively(a). We now expect
2012 full-year organic capital expenditure to be between $22 billion and $23
billion. Disposal proceeds were $1.4 billion for the quarter and $4.6 billion
for the nine months.
· Since the start of 2010, we have announced disposals for over $35 billion
against our target of $38 billion, which includes a total of $6 billion for
Upstream assets and $5 billion for Downstream assets since the end of the
second quarter. In addition, we announced the proposed transaction with
Rosneft for the sale of our share in TNK-BP, as described on page 1. (See
pages 6, 8 and 11 and Note 3 on pages 28 - 29 for further information on these
agreements.)
(a) Organic capital expenditure excludes acquisitions and asset exchanges, and
expenditure associated with deepening our natural gas asset base (see page
18).
Gulf of Mexico oil spill
Completing the response
We remain committed to meeting our responsibilities to the US federal, state
and local governments and communities of the Gulf Coast following the
Deepwater Horizon accident and oil spill in 2010 (the Incident). During the
third quarter of 2012, BP, working under the direction of the US Coast Guard's
Federal On-Scene Coordinator (FOSC), and collaboratively with the individual
federal and state entities, continued to work to meet the applicable clean-up
standards established by the Shoreline Clean-up Completion plan.
In late August 2012, Hurricane Isaac made landfall in the Gulf Coast and
deposits of buried residual oil were exposed by changes in the beach profile
on some Louisiana beaches where deep cleaning had not previously been allowed.
Response teams are continuing to excavate the uncovered residual material and
have submitted for approval plans for deep cleaning across these beach areas.
In other parts of the area of response, clean-up operations have largely
returned to pre-Isaac levels after an initial post-Isaac increase in tar
balls.
As at 29 September 2012, the FOSC had deemed removal actions complete on 3,941
miles of shoreline out of 4,375 miles in the area of response. A further 143
miles were awaiting approval of removal actions deemed complete or were
pending final monitoring. The remaining 291 miles were undergoing patrolling
and maintenance, which will continue until the shoreline segments meet the
applicable clean-up standards for the FOSC to determine that operational
removal activity is complete.
Economic restoration
As at 30 September 2012, BP had paid a total of over $8.8 billion for
individual, business and government entity claims, advances and other
payments, including payments made by BP prior to the establishment of the
Deepwater Horizon Oil Spill Trust (Trust). The amount includes over $7.1
billion paid to individual and business claimants, and $1.4 billion paid to
federal, state and local government entities for claims and advances. BP has
also paid an additional $298 million for contributions, settlements and other
payments for tourism, seafood testing and marketing, and behavioural health.
During the third quarter the Deepwater Horizon Court-Supervised Settlement
Program (DHCSSP) paid $66 million to individual and business "in-class"
claimants under the proposed economic loss settlement agreement reached
between BP and the Plaintiffs' Steering Committee (PSC). In addition, $21
million was paid to fund the Gulf Region Health Outreach Program and for
administration costs under the medical settlement agreement. The BP claims
programme is processing claims received from claimants not in the class as
determined by the settlement agreement or who have requested to opt out of the
settlement. There were 741 requests to opt out of the settlement class during
the third quarter.
Following the court's preliminary approval in May 2012 of the economic loss
and medical settlement agreements reached between BP and the PSC, we await the
outcome of the court's fairness hearing scheduled for 8 November 2012, which
will determine whether to grant final approval of the agreements.
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Gulf of Mexico oil spill (continued)
Environmental restoration
During the third quarter we continued to work with scientists and trustee
agencies through the Natural Resource Damages (NRD) assessment process to
identify natural resources that may have been exposed to oil or otherwise
impacted by the oil spill, and to look for evidence of injury. To date, BP has
paid $819 million for NRD assessment efforts.
Under an agreement signed with federal and state agencies in April 2011, BP
voluntarily committed to provide up to $1 billion to fund early restoration
projects aimed at accelerating restoration efforts in the Gulf coast areas
that were impacted by the accident. The agreement enables work on restoration
projects to begin at the earliest opportunity, before funding is required by
the Oil Pollution Act 1990 (OPA 90). These projects will be funded from the
Trust. See Note 2 on pages 23 - 28.
As at 30 September 2012, $36 million has been funded towards the $60 million
estimated cost of the first tranche of the early restoration project plan.
This plan, which includes eight projects along the Gulf Coast, was finalized
in April 2012 by the Natural Resource Damage Assessment Trustee Council
following extensive public review. Collectively, these projects are intended
to restore and enhance wildlife and habitats, and provide additional access
for recreational use.
Financial update
The group income statement includes a pre-tax charge of $59 million for the
third quarter in relation to the Incident. The charge for the third quarter
reflects the regular quarterly costs of the Gulf Coast Restoration
Organization and adjustments to provisions. The total cumulative charge
recognized to date for the Incident amounts to $38.1 billion. The cumulative
income statement charge does not include amounts for obligations that BP
considers are not possible, at this time, to measure reliably, namely any
obligation relating to Natural Resource Damages claims under OPA 90 (other
than the estimated costs of the assessment phase and the costs of emergency
and early restoration agreements referred to in Note 2 on page 26) and other
potential litigation, fines, or penalties, other than as described under
Provisions in Note 2 on pages 26 - 28.
The total amounts that will ultimately be paid by BP in relation to all the
obligations relating to the Incident are subject to significant uncertainty
and the ultimate exposure and cost to BP will be dependent on many factors, as
discussed under Contingent liabilities on page 28, including in relation to
any new information or future developments. These could have a material impact
on our consolidated financial position, results of operations and cash flows.
The risks associated with the Incident could also heighten the impact of the
other risks to which the group is exposed, as further described under
Principal risks and uncertainties on pages 32 - 38 of our second-quarter 2012
results announcement.
Trust update
During the third quarter, BP made a contribution of $1,250 million to the
Trust. As at 30 September 2012, BP's cumulative contributions to the Trust
amounted to $19,140 million with a final payment of $860 million scheduled for
the fourth quarter of 2012. Under the terms of the settlement agreements with
the PSC, qualified settlement funds (QSFs) were established during the second
quarter, funded from the Trust, for the purpose of paying the costs of the
settlements.
Payments from the Trust and QSFs during the third quarter were $378 million
for individual and business claims through both the DHCSSP and the Gulf Coast
Claims Facility, medical settlement programme payments, NRD assessment and
early restoration, state and local government claims, DHCSSP expenses and
other resolved items. As at 30 September 2012, the cumulative amount paid from
the Trust and QSFs since inception was $8.2 billion, and the remaining cash
balances were $10.9 billion.
As at 30 September 2012, the cumulative charges for provisions to be paid from
the Trust and the associated reimbursement asset recognized amounted to $17.8
billion. The increased charge in the third quarter reflects higher provision
estimates for the DHCSSP costs and NRD assessment costs. A further $2.2
billion could be provided in subsequent periods for items covered by the
Trust, with no net impact on the income statement.
Legal proceedings and investigations
See Legal proceedings on pages 32 - 40 for details of legal proceedings,
including external investigations relating to the Incident.
Top of page 4
Analysis of underlying RC profit and RC profit before interest and tax
and reconciliation to profit for the period
Third Second Third Nine Nine
quarter quarter quarter $ million months months
2011 2012 2012 Underlying RC profit before interest 2012 2011
and tax(a)
6,287 4,401 4,369 Upstream 15,060 19,301
1,666 1,129 3,004 Downstream 5,057 5,254
939 452 1,294 TNK-BP(b) 2,903 3,147
(406) (540) (574) Other businesses and corporate (1,550) (1,038)
(213) 457 (64) Consolidation adjustment - UPII(c) (148) (240)
8,273 5,899 8,029 Underlying RC profit before interest 21,322 26,424
and tax
Finance costs and net finance income
or expense
relating to pensions and other
(220) (208) (195) post-retirement benefits (627) (677)
(2,413) (1,961) (2,598) Taxation on an underlying RC basis (6,869) (8,767)
(177) (45) (66) Minority interest (172) (308)
5,463 3,685 5,170 Underlying RC profit attributable to 13,654 16,672
BP shareholders
Non-operating items and fair value
accounting
effects(a)
461 (1,488) 541 Upstream (258) 501
(173) (2,865) (601) Downstream (3,534) (344)
- - (12) TNK-BP, net of tax (105) -
76 18 (523) Other businesses and corporate (741) (368)
(541) (843) (56) Gulf of Mexico oil spill (869) (308)
response(d)
(177) (5,178) (651) Total before interest and taxation (5,507) (519)
(14) (4) (3) Finance costs(e) (13) (45)
4 1,735 171 Taxation credit (charge)(f) 1,720 186
(187) (3,447) (483) Total after taxation for the period (3,800) (378)
RC profit before interest and tax(a)
6,748 2,913 4,910 Upstream 14,802 19,802
1,493 (1,736) 2,403 Downstream 1,523 4,910
939 452 1,282 TNK-BP(b) 2,798 3,147
(330) (522) (1,097) Other businesses and corporate (2,291) (1,406)
(541) (843) (56) Gulf of Mexico oil spill (869) (308)
response(d)
(213) 457 (64) Consolidation adjustment - UPII(c) (148) (240)
8,096 721 7,378 RC profit before interest and tax 15,815 25,905
Finance costs and net finance income
or
expense relating to pensions and
other
(234) (212) (198) post-retirement benefits (640) (722)
(2,409) (226) (2,427) Taxation on a RC basis (5,149) (8,581)
(177) (45) (66) Minority interest (172) (308)
5,276 238 4,687 RC profit attributable to BP 9,854 16,294
shareholders
(372) (2,324) 1,059 Inventory holding gains (losses) 172 2,533
Taxation (charge) credit on
inventory holding gains
139 701 (312) and losses (62) (812)
Profit (loss) for the period
attributable to BP
5,043 (1,385) 5,434 shareholders 9,964 18,015
(a) Replacement cost (RC) profit or loss reflects the replacement cost of
supplies and is arrived at by excluding inventory holding gains and losses
from profit or loss. RC profit or loss is the measure of profit or loss
for each operating segment that is required to be
disclosed under International Financial Reporting Standards (IFRS). RC
profit or loss for the group is not a recognized GAAP measure. For further
information on RC profit or loss, see page 19. Underlying RC profit or
loss is RC profit or loss after adjusting for non-operating items and fair
value accounting effects. Underlying RC profit or loss and fair value
accounting effects are not recognized GAAP measures. On pages 20 and 21
respectively, we provide additional information on the non-operating items
and fair value accounting effects that are used to arrive at underlying RC
profit or loss in order to enable a full understanding of the events and
their financial impact. BP believes that underlying RC profit or loss is a
useful measure for investors because it is a measure closely tracked by
management to evaluate BP's operating performance and to make financial,
strategic and operating decisions and because it may help investors to
understand and evaluate, in the same manner as management, the underlying
trends in BP's operational performance on a comparable basis, period on
period, by adjusting for the effects of these non-operating items and fair
value accounting effects.
(b) Net of finance costs, taxation and minority interest.
(c) The consolidation adjustment - unrealized profit in inventory (UPII) for
the second quarter of 2012 was impacted by lower margins (driven by lower
prices and a higher average cost of production due to a different mix of
equity crude within inventory).
(d) See Note 2 on pages 23 - 28 for further information on the accounting for
the Gulf of Mexico oil spill response.
(e) Finance costs relate to the Gulf of Mexico oil spill. See Note 2 on pages
23 - 28 for further details.
(f) For the Gulf of Mexico oil spill and certain impairment losses in the
second quarter 2012, tax is based on US statutory tax rates. For other
items, with the exception of TNK-BP items (which are reported net of tax),
tax is calculated using the group's discrete quarterly effective tax rate
(adjusted for the Gulf of Mexico oil spill, certain impairment losses in
the second quarter 2012, equity-accounted earnings from the first quarter
2012 onwards and the deferred tax adjustments relating to changes to the
taxation of UK oil and gas production ($683 million for the first quarter
2011 and $256 million for the third quarter 2012)).
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Per share amounts
Third Second Third Nine Nine
quarter quarter quarter months months
2011 2012 2012 2012 2011
Per ordinary share (cents)
26.62 (7.29) 28.54 Profit (loss) for the period 52.40 95.39
27.85 1.25 24.62 RC profit for the period 51.82 86.28
28.83 19.37 27.16 Underlying RC profit for the period 71.81 88.28
Per ADS (dollars)
1.60 (0.44) 1.71 Profit (loss) for the period 3.14 5.72
1.67 0.07 1.48 RC profit for the period 3.11 5.18
1.73 1.16 1.63 Underlying RC profit for the period 4.31 5.30
The amounts shown above are calculated based on the basic weighted average
number of shares outstanding. See Note 6 on page 30 for details of the
calculation of earnings per share.
Net debt ratio - net debt: net debt + equity
Third Second Third Nine Nine
quarter quarter quarter months months
2011 2012 2012 2012 2011
$ million
45,283 47,662 49,077 Gross debt 49,077 45,283
1,454 1,067 1,572 Less: fair value asset of 1,572 1,454
hedges related to finance debt
43,829 46,595 47,505 47,505 43,829
17,997 14,881 16,041 Less: Cash and cash equivalents 16,041 17,997
25,832 31,714 31,464 Net debt 31,464 25,832
110,659 113,323 118,773 Equity 118,773 110,659
18.9% 21.9% 20.9% Net debt ratio 20.9% 18.9%
See Note 7 on page 31 for further details on finance debt.
Net debt and net debt ratio are non-GAAP measures. Net debt includes the fair
value of associated derivative financial instruments that are used to hedge
foreign exchange and interest rate risks relating to finance debt, for which
hedge accounting is claimed. The derivatives are reported on the balance sheet
within the headings 'Derivative financial instruments'. We believe that net
debt and net debt ratio provide useful information to investors. Net debt
enables investors to see the economic effect of gross debt, related hedges and
cash and cash equivalents in total. The net debt ratio enables investors to
see how significant net debt is relative to equity from shareholders.
Dividends
Dividends payable
BP today announced a dividend of 9 cents per ordinary share expected to be
paid in December. The corresponding amount in sterling will be announced on
10 December 2012, calculated based on the average of the market exchange rates
for the four dealing days commencing on 4 December 2012. Holders of American
Depositary Shares (ADSs) will receive $0.54 per ADS. The dividend is due to be
paid on 21 December 2012 to shareholders and ADS holders on the register on
9 November 2012. A scrip dividend alternative is available, allowing
shareholders to elect to receive their dividend in the form of new ordinary
shares and ADS holders in the form of new ADSs. Details of the third-quarter
dividend and timetable are available at bp.com/dividends and details of the
scrip dividend programme are available at bp.com/scrip.
Dividends paid
Third Second Third Nine Nine
quarter quarter quarter months months
2011 2012 2012 2012 2011
Dividends paid per ordinary share
7.000 8.000 8.000 cents 24.000 21.000
4.316 5.150 5.017 pence 15.263 12.934
42.00 48.00 48.00 Dividends paid per ADS (cents) 144.00 126.00
Scrip dividends
14.8 11.1 15.0 Number of shares issued 65.7 154.2
(millions)
101 73 105 Value of shares issued ($ 484 1,136
million)
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Upstream
Third Second Third Nine Nine
quarter quarter quarter months months
2011 2012 2012 2012 2011
$ million
6,763 2,877 4,922 Profit before interest and tax 14,694 19,896
(15) 36 (12) Inventory holding (gains) losses 108 (94)
6,748 2,913 4,910 RC profit before interest and tax 14,802 19,802
Net (favourable) unfavourable impact
of non-operating
(461) 1,488 (541) items and fair value accounting 258 (501)
effects
6,287 4,401 4,369 Underlying RC profit before interest 15,060 19,301
and tax(a)
(a) See footnote (a) on page 4 for information on underlying RC profit and see
page 7 for a reconciliation to segment RC profit before interest and tax
by region.
The replacement cost profit before interest and tax for the third quarter and
nine months was $4,910 million and $14,802 million respectively, compared with
$6,748 million and $19,802 million for the same periods in 2011. The third
quarter was impacted by a net non-operating gain of $516 million, primarily
due to gains on disposals, compared with a net gain of $500 million in 2011.
For the nine months, the net non-operating charge was $157 million, mainly
relating to impairment charges offset by gains on disposals, compared with a
net gain of $546 million in the same period last year. In the third quarter,
fair value accounting effects had a favourable impact of $25 million compared
with an unfavourable impact of $39 million in 2011. For the nine months, fair
value accounting effects had an unfavourable impact of $101 million compared
with an unfavourable impact of $45 million in 2011.
After adjusting for non-operating items and fair value accounting effects, the
underlying replacement cost profit before interest and tax for the third
quarter and nine months was $4,369 million and $15,060 million respectively,
compared with $6,287 million and $19,301 million a year ago. The results in
both periods of 2012 were impacted by lower realizations, higher costs
(primarily the impact of higher depreciation, depletion and amortization, as
well as ongoing sector inflation), and lower production. The persistently low
Henry Hub gas price means that our North American gas business is continuing
to operate at a loss.
Production for the quarter was 2,259mboe/d, 2.7% lower than the third quarter
of 2011. After adjusting for the effect of divestments and entitlement impacts
in our production-sharing agreements (PSAs), production increased by 3.4%.
This primarily reflected major project start-ups and improved operating
performance in Angola, and increased volumes in other areas, partly offset by
natural field decline and the seasonal impacts of maintenance activity. For
the nine months, production was 2,328mboe/d, 5.3% lower than in the same
period last year. After adjusting for the effect of divestments and PSA
entitlement impacts, production for the nine months was 1.0% higher than a
year ago.
Looking ahead we expect fourth-quarter reported production to be higher than
the third quarter as we exit the maintenance season, and see the continuing
benefit of our major project start-ups. The extent of the increased production
will likely be muted by the timing of Gulf of Mexico and North Sea divestments
expected to be completed during the fourth quarter.
We continue to expect full-year production in 2012 to be broadly flat with
2011, after adjusting for divestments, and the impact of entitlement effects
in our PSAs.
Reported production for the full year is expected to be lower than 2011 due to
the impact of divestments which we estimate at around 120mboe/d. The actual
reported production outcome for the year will depend on the exact timing of
divestments and project start-ups, OPEC quotas, and entitlement impacts in
PSAs.
We continued to make strategic progress. In August, we announced the sale of
the Sunray and Hemphill gas processing plants in Texas, together with their
associated gas gathering system, to Eagle Rock Energy Partners for $228
million in cash. The transaction closed on 1 October.
In September, we announced the sanction of the Clair Ridge development, west
of Shetland, UK. This is the first major project using our proprietary reduced
salinity water injection technology (LoSal®).
Also in September, we announced the agreement to sell our interests in the
Marlin hub, Horn Mountain, Holstein, Ram Powell and Diana Hoover assets in the
deepwater Gulf of Mexico to Plains Exploration and Production Company for
$5.55 billion, subject to regulatory approvals, certain pre-emption rights and
customary post-closing adjustments. Additionally we announced the agreement to
sell our interest in the Draugen field in the Norwegian Sea to AS Norske Shell
for $240 million.
In October, we announced the successful start-up of the Devenick gas project
in the central North Sea, which will provide an important new source of
domestic gas for the UK. We also signed PSAs for three deepwater exploration
blocks offshore Uruguay following our successful bids in their second offshore
licensing round in March 2012.
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Upstream
Third Second Third Nine Nine
quarter quarter quarter $ million months months
2011 2012 2012 Underlying RC profit before interest 2012 2011
and tax
By region
1,473 628 741 US 3,027 4,798
4,814 3,773 3,628 Non-US 12,033 14,503
6,287 4,401 4,369 15,060 19,301
Non-operating items
(32) (2,273) 465 US (861) (758)
532 778 51 Non-US 704 1,304
500 (1,495) 516 (157) 546
Fair value accounting effects(a)
(9) 61 (28) US (38) (2)
(30) (54) 53 Non-US (63) (43)
(39) 7 25 (101) (45)
RC profit (loss) before interest and
tax
1,432 (1,584) 1,178 US 2,128 4,038
5,316 4,497 3,732 Non-US 12,674 15,764
6,748 2,913 4,910 14,802 19,802
Exploration expense
52 413 35 US(b) 510 985
48 203 255 Non-US(c) 656 193
100 616 290 1,166 1,178
Production (net of royalties)(d)
Liquids (mb/d)(e)
388 350 356 US 387 458
120 119 95 Europe 112 145
684 681 697 Rest of World 683 688
1,192 1,150 1,148 1,182 1,291
Natural gas (mmcf/d)
1,819 1,648 1,545 US 1,670 1,852
214 478 339 Europe 439 325
4,516 4,399 4,559 Rest of World 4,541 4,590
6,549 6,525 6,443 6,650 6,767
Total hydrocarbons (mboe/d)(f)
702 635 622 US 675 778
157 201 153 Europe 188 201
1,462 1,439 1,483 Rest of World 1,466 1,478
2,321 2,275 2,259 2,328 2,457
Average realizations(g)
103.53 100.89 99.00 Total liquids ($/bbl) 102.79 101.11
4.95 4.54 4.77 Natural gas ($/mcf) 4.67 4.56
63.74 60.17 60.68 Total hydrocarbons ($/boe) 61.69 61.91
(a) These effects represent the favourable (unfavourable) impact relative to
management's measure of performance. Further information on fair value
accounting effects is provided on page 21.
(b) Second quarter and nine months 2012 include $308 million classified within
the 'other' category of non-operating items (nine months 2011
$395 million).
(c) Nine months 2011 includes $44 million classified within the 'other'
category of non-operating items.
(d) Includes BP's share of production of equity-accounted entities in the
Upstream segment.
(e) Crude oil and natural gas liquids.
(f) Natural gas is converted to oil equivalent at 5.8 billion cubic feet = 1
million barrels.
(g) Based on sales of consolidated subsidiaries only - this excludes
equity-accounted entities.
Because of rounding, some totals may not agree exactly with the sum of their
component parts.
Top of page 8
Downstream
Third Second Third Nine Nine
quarter quarter quarter months months
2011 2012 2012 2012 2011
$ million
1,117 (3,935) 3,385 Profit (loss) before interest and tax 1,801 7,304
376 2,199 (982) Inventory holding (gains) losses (278) (2,394)
1,493 (1,736) 2,403 RC profit (loss) before interest and 1,523 4,910
tax
Net (favourable) unfavourable impact
of non-operating
173 2,865 601 items and fair value accounting 3,534 344
effects
1,666 1,129 3,004 Underlying RC profit before interest 5,057 5,254
and tax(a)
(a) See footnote (a) on page 4 for information on underlying RC profit and see
page 9 for a reconciliation to segment RC profit before interest and tax
by region and by business.
The replacement cost profit before interest and tax for the third quarter and
nine months was $2,403 million and $1,523 million respectively, compared with
a profit of $1,493 million and $4,910 million for the same periods last year.
The results include net non-operating charges of $315 million for the third
quarter, largely reflecting the reassessment of environmental provisions and
$3,099 million for the nine months mainly relating to impairments. For the
same periods last year there were net non-operating charges of $227 million
for the third quarter and $462 million for the nine months (see pages 9 and 20
for further information on non-operating items). Fair value accounting effects
had an unfavourable impact of $286 million for the third quarter and $435
million for the nine months, compared with favourable impacts of $54 million
and $118 million in the same periods a year ago.
After adjusting for non-operating items and fair value accounting effects, the
segment delivered a record quarterly underlying replacement cost profit before
interest and tax of $3,004 million for the third quarter, compared with $1,666
million for the same period in 2011. For the nine months, underlying
replacement cost profit before interest and tax was $5,057 million compared
with $5,254 million a year ago.
Replacement cost profit or loss before interest and tax for the fuels,
lubricants and petrochemicals businesses is set out on page 9.
The fuels business benefited from strong operations in the third quarter, with
refining throughputs at the highest level for seven years and some 10% higher
than the second quarter. This, coupled with a favourable refining environment,
helped us to deliver a record underlying replacement cost profit before
interest and tax of $2,713 million in the third quarter and $3,981 million in
the nine months, compared with $1,184 million and $3,243 million in the same
periods of last year. Compared with the same period a year ago, the third
quarter also benefited from the positive impacts of prior month pricing of
barrels into our US refining system, partly mitigating the negative impacts
seen in the second quarter. For the nine months, compared with the same period
last year, the benefits of the stronger refining environment were partially
offset by a significantly weaker supply and trading contribution despite a
recovery in the third quarter.
During the quarter, we announced the agreement to sell the Carson refinery in
California and related assets in the region, including marketing and logistics
assets to Tesoro Corporation for $2.5 billion. Completion of the deal is
subject to regulatory and other approvals and is expected to occur before
mid-2013. In October, we also announced the agreement to sell our Texas City
refinery and a portion of its retail and logistics network in the south-east
US to Marathon Petroleum Corporation for an estimated $2.5 billion. Completion
of the deal is expected in early 2013, subject to regulatory and other
approvals. See Note 3 on page 29 for further details of these agreements.
Looking ahead to the fourth quarter, we expect refining margins to decline
from the unusually high levels seen in the third quarter. As indicated in our
second-quarter announcement, we will imminently commence a planned
transitional outage to replace the largest of three crude units at the Whiting
refinery, which temporarily reduces the refinery's crude capacity by more than
50%. This is part of our major project to enable the refinery to process
significantly more Canadian heavy crude. It is expected that the work will be
completed by mid-year 2013, in time for the start-up of the whole project in
the second half of 2013. In addition, we expect to carry out major turnarounds
at two of our refineries in the fourth quarter.
The lubricants business delivered an underlying replacement cost profit before
interest and tax of $311 million in the third quarter and $956 million in the
nine months, compared with $247 million and $987 million in the same periods
last year, reflecting continued robust performance despite a difficult
marketing environment.
The petrochemicals business delivered an underlying replacement cost loss
before interest and tax of $20 million in the third quarter and a profit of
$120 million in the nine months, compared with a profit of $235 million and
$1,024 million in the same periods last year. This reflected continued
weakness in margins globally resulting from recent capacity additions in Asia,
high feedstock prices for aromatics production and lower demand.
Looking ahead, we expect petrochemicals margins to remain depressed in the
fourth quarter.
In September, we announced that we had agreed to sell all of our purified
terephthalic acid interest in BP Chemicals (Malaysia) Sdn Bhd, to Reliance
Global Holdings Pte. Ltd. for $230 million and the sale was completed in
October 2012.
Top of page 9
Downstream
Third Second Third Nine Nine
quarter quarter quarter $ million months months
2011 2012 2012 Underlying RC profit before interest 2012 2011
and tax -
by region
927 450 1,723 US 2,462 1,782
739 679 1,281 Non-US 2,595 3,472
1,666 1,129 3,004 5,057 5,254
Non-operating items
(184) (2,433) (229) US (2,750) (439)
(43) (245) (86) Non-US (349) (23)
(227) (2,678) (315) (3,099) (462)
Fair value accounting effects(a)
18 (1) (388) US (432) 41
36 (186) 102 Non-US (3) 77
54 (187) (286) (435) 118
RC profit (loss) before interest and
tax
761 (1,984) 1,106 US (720) 1,384
732 248 1,297 Non-US 2,243 3,526
1,493 (1,736) 2,403 1,523 4,910
Underlying RC profit before interest
and tax -
by business(b)(c)
1,184 781 2,713 Fuels 3,981 3,243
247 320 311 Lubricants 956 987
235 28 (20) Petrochemicals 120 1,024
1,666 1,129 3,004 5,057 5,254
Non-operating items and fair value
accounting
effects(a)
(190) (2,863) (592) Fuels (3,523) (434)
16 (2) (8) Lubricants (10) 89
1 - (1) Petrochemicals (1) 1
(173) (2,865) (601) (3,534) (344)
RC profit (loss) before interest and
tax(b)(c)
994 (2,082) 2,121 Fuels 458 2,809
263 318 303 Lubricants 946 1,076
236 28 (21) Petrochemicals 119 1,025
1,493 (1,736) 2,403 1,523 4,910
12.51 15.84 19.50 BP Average refining marker margin 15.65 12.49
(RMM) ($/bbl)(d)
Refinery throughputs (mb/d)
1,371 1,295 1,403 US 1,306 1,252
776 706 791 Europe 757 764
283 281 318 Rest of World 292 302
2,430 2,282 2,512 2,355 2,318
95.3 94.5 95.0 Refining availability (%)(e) 94.8 94.7
Marketing sales volumes (mb/d)(f)
1,411 1,409 1,432 US 1,397 1,398
1,353 1,279 1,268 Europe 1,254 1,306
592 603 571 Rest of World 583 605
3,356 3,291 3,271 3,234 3,309
2,358 2,568 2,393 Trading/supply sales 2,447 2,448
5,714 5,859 5,664 Total refined product sales 5,681 5,757
Petrochemicals production (kte)
1,127 1,110 900 US 3,088 3,028
955 998 993 Europe(c) 3,002 2,990
1,504 1,750 1,686 Rest of World 5,253 5,268
3,586 3,858 3,579 11,343 11,286
(a) Fair value accounting effects represent the favourable (unfavourable)
impact relative to management's measure of performance. For Downstream,
these arise solely in the fuels business. Further information is provided
on page 21.
(b) Segment-level overhead expenses are included in the fuels business
result.
(c) BP's share of income from petrochemicals at our Gelsenkirchen and Mülheim
sites in Germany is reported in the fuels business.
(d) The RMM is the average of regional indicator margins weighted for BP's
crude refining capacity in each region. They may not be representative of
the margins achieved by BP in any period because of BP's particular
refinery configurations and crude and product slate. The quarterly
regional marker margins can be found on bp.com and are updated weekly.
(e) Refining availability represents Solomon Associates' operational
availability, which is defined as the percentage of the year that a unit
is available for processing after subtracting the annualized time lost
due to turnaround activity and all planned mechanical, process and
regulatory maintenance downtime.
(f) Marketing sales do not include volumes relating to crude oil.
Top of page 10
TNK-BP(a)
Third Second Third Nine Nine
quarter quarter quarter months months
2011 2012 2012 2012 2011
$ million
1,558 852 1,818 Profit before interest and tax 4,151 4,503
(36) (27) (20) Finance costs (83) (105)
(486) (393) (310) Taxation (934) (970)
(108) (69) (141) Minority interest (334) (251)
928 363 1,347 Net income (BP share)(b) 2,800 3,177
11 89 (65) Inventory holding (gains) losses, net (2) (30)
of tax
939 452 1,282 Net income on a RC basis 2,798 3,147
- - 12 Net charge (credit) for non-operating 105 -
items(c), net of tax
939 452 1,294 Net income on an underlying RC 2,903 3,147
basis(d)
Cash flow
425 - - Dividends received 690 2,059
Production (net of royalties) (BP
share)
883 881 876 Crude oil (mb/d) 879 866
664 779 728 Natural gas (mmcf/d) 773 686
998 1,016 1,002 Total hydrocarbons (mboe/d)(e) 1,012 985
Balance sheet 30 September 31 December
2012 2011
Investments in associates 12,126 10,013
(a) All amounts shown relate to BP's 50% share in TNK-BP.
(b) TNK-BP is an associate accounted for using the equity method and therefore
BP's share of TNK-BP's earnings after interest and tax is included in the
group income statement within BP's profit before interest and tax.
(c) Disclosure of non-operating items for TNK-BP began in the first quarter of
2012.
(d) See footnote (a) on page 4 for information on underlying RC profit.
(e) Natural gas is converted to oil equivalent at 5.8 billion cubic feet = 1
million barrels.
The net income on a replacement cost basis from BP's investment in TNK-BP for
the third quarter and nine months was $1,282 million and $2,798 million
respectively, compared with $939 million and $3,147 million for the same
periods a year ago.
The third quarter included a net charge for non-operating items of $12
million, relating to environmental provisions partly offset by gains on
disposal. The net non-operating charge of $105 million for the nine months
also included an impairment charge relating to the Lisichansk refinery in the
Ukraine. Prior to 2012, non-operating items relating to BP's investment in
TNK-BP were not identified or disclosed.
After adjusting for non-operating items, the net income on an underlying
replacement cost basis from BP's investment in TNK-BP for the third quarter
and nine months was $1,294 million and $2,903 million respectively, compared
with $939 million and $3,147 million for the same periods in 2011. The primary
factors impacting the third-quarter result, compared with the same period last
year, were positive foreign exchange effects and the impact of the tax
reference price lag on Russian export duties in the rising price environment.
For the nine months, the reduction was driven by the negative impact of export
duty lag and lower realizations, partially offset by positive foreign exchange
effects.
Total hydrocarbon production for the third quarter was 1,002mboe/d, slightly
higher than the same period in 2011, and 1,012mboe/d for the nine months, 3%
higher than a year ago. After adjusting for the effect of the acquisition of
BP's upstream interests in Vietnam and Venezuela, production for the third
quarter was slightly lower than the same period in 2011, and for the nine
months was 1% higher than a year ago, with the ramp-up of recent new
developments offsetting a decline in mature fields.
On 20 August, TNK-BP announced that it sold OJSC Novosibirskneftegaz and OJSC
Severnoeneftegaz as part of its strategy to optimize the asset portfolio and
reduce costs.
Top of page 11
TNK-BP
Agreement in principle with Rosneft
On 22 October 2012, BP announced that it had signed heads of terms for a
proposed transaction to sell its 50% share in TNK-BP to Rosneft. The proposed
transaction consists of two tranches:
(i) BP would sell its 50% shareholding in TNK-BP to Rosneft for cash
consideration of $17.1 billion and Rosneft shares representing a 12.84% stake
in Rosneft; and
(ii) BP intends to use $4.8 billion of the cash consideration to acquire
a further 5.66% stake in Rosneft from the Russian government. BP would acquire
the Rosneft shares from the Russian government at a price of $8 per share
(representing a premium of 12% to the Rosneft share closing price on the bid
date, 18 October 2012).
Signing of the definitive agreements is conditional on the Russian government
agreeing to the sale of the 5.66% stake in Rosneft and it is intended that the
TNK-BP sale and this further investment in Rosneft would complete on the same
day. Therefore, on completion of the proposed transaction, BP would acquire a
total 18.5% stake in Rosneft and net $12.3 billion in cash. This would result
in BP holding 19.75% of Rosneft stock, when aggregated with BP's 1.25% current
holding in Rosneft. At this level of ownership, BP expects to be able to
account for its share of Rosneft's earnings, production and reserves on an
equity basis. In addition, BP expects to have two seats on Rosneft's
nine-person main board.
In accordance with the heads of terms, BP and Rosneft have an exclusivity
period of 90 days to negotiate fully termed sale and purchase agreements.
After signing definitive agreements, completion would be subject to certain
customary closing conditions, including governmental, regulatory and
anti-trust approvals, and is currently anticipated to occur during the first
half of 2013. In addition, BP will agree not to dispose of any of the Rosneft
shares acquired in the transaction for at least 360 days following the
completion of the transaction.
Following this agreement, BP's investment in TNK-BP meets the criteria to be
classified as an asset held for sale. Consequently, BP will cease equity
accounting for its share of TNK-BP's earnings from the date of the
announcement. BP will continue to report its share of TNK-BP's production and
reserves until the transaction closes.
Top of page 12
Other businesses and corporate
Third Second Third Nine Nine
quarter quarter quarter months months
2011 2012 2012 2012 2011
$ million
(330) (522) (1,097) Profit (loss) before interest and (2,291) (1,391)
tax
- - - Inventory holding (gains) losses - (15)
(330) (522) (1,097) RC profit (loss) before interest and (2,291) (1,406)
tax
(76) (18) 523 Net charge (credit) for 741 368
non-operating items
Underlying RC profit (loss) before
interest
(406) (540) (574) and tax(a) (1,550) (1,038)
By region
Underlying RC profit (loss) before
interest
and tax(a)
(182) (185) (218) US (568) (527)
(224) (355) (356) Non-US (982) (511)
(406) (540) (574) (1,550) (1,038)
Non-operating items
(112) (92) (494) US (728) (123)
188 110 (29) Non-US (13) (245)
76 18 (523) (741) (368)
RC profit (loss) before interest and
tax
(294) (277) (712) US (1,296) (650)
(36) (245) (385) Non-US (995) (756)
(330) (522) (1,097) (2,291) (1,406)
(a) See footnote (a) on page 4 for information on underlying RC profit or
loss.
Other businesses and corporate comprises the Alternative Energy business,
Shipping, Treasury (which includes interest income on the group's cash and
cash equivalents), and corporate activities worldwide.
The replacement cost loss before interest and tax for the third quarter and
nine months was $1,097 million and $2,291 million respectively, compared with
$330 million and $1,406 million for the same periods last year.
The third-quarter result included a net non-operating charge of $523 million,
primarily asset impairments and environmental provisions, compared with a net
non-operating gain of $76 million a year ago. For the nine months the net
non-operating charge was $741 million, compared with a net charge of
$368 million a year ago.
After adjusting for non-operating items, the underlying replacement cost loss
before interest and tax for the third quarter and nine months was $574 million
and $1,550 million respectively, compared with $406 million and $1,038 million
for the same periods last year. The third quarter was impacted by increased
corporate costs, while the movement for the nine months was primarily due to
foreign exchange effects, increased corporate costs and the sale of our
aluminium business in 2011.
In Alternative Energy, net wind generation capacity(b) at the end of the third
quarter was 1,274MW (1,988MW gross), compared with 774MW (1,362MW gross) at
the end of the same period a year ago. BP's net share of wind generation from
our 13 US wind farms for the third quarter was 628GWh (964GWh gross), compared
with 420GWh (763GWh gross) in the same period a year ago. For the nine months,
BP's net share was 2,572GWh (4,061GWh gross), compared with 1,669GWh (2,997GWh
gross) a year ago.
In our biofuels business, BP's net share of ethanol-equivalent(c) production
for the third quarter was 206 million litres (BP interest 100%) compared with
183 million litres (228 million litres gross) in the same period a year
ago(d). For the nine months, BP's net share of ethanol-equivalent production
was 304 million litres (BP interest 100%) compared with 278 million litres
(353 million litres gross) a year ago.
(b) Net wind generation capacity is the sum of the rated capacities of the
assets/turbines that have entered into commercial operation, including
BP's share of equity-accounted entities. The gross data is the equivalent
capacity on a gross-JV basis, which includes 100% of the capacity of
equity-accounted entities where BP has partial ownership. Capacity figures
include 32MW in the Netherlands managed by our Downstream segment.
(c) Ethanol-equivalent production includes ethanol and sugar.
(d) BP acquired the remaining 50% of Tropical Bioenergia on 22 November 2011.
Top of page 13
Cautionary statement
Cautionary statement regarding forward-looking statements: The discussion in
this results announcement contains forward-looking statements, particularly
those regarding BP's expectations for delivering more than 50% growth in net
cash provided by operating activities by 2014; the expected level of 2012
full-year organic capital expenditure; the expected quarterly dividend
payment; the expected terms of and timing of the execution of definitive
agreements in respect of BP's proposed transaction with Rosneft concerning the
sale of BP's stake in TNK-BP to Rosneft and the related acquisition by BP of
shares in Rosneft (the Rosneft transaction); the expected timing of completion
of the Rosneft transaction; the expected level of BP's holding of Rosneft
stock following completion of the Rosneft transaction; expectations regarding
the accounting treatment of BP's expected share of Rosneft's earnings and the
reporting of production and reserves; prospects for BP's level of
representation on Rosneft's board of directors; BP's intentions to retain
Rosneft shares received in the Rosneft transaction for at least 360 days
following the completion of the transaction; BP's intentions to continue to
patrol and maintain certain shoreline segments impacted by the Gulf of Mexico
oil spill; the expected timing of the fairness hearing in connection with the
final approval of the settlement agreements with the Plaintiffs' Steering
Committee (PSC); the source of funding for BP's $1-billion commitment to early
restoration projects, and the prospects for these early restoration projects;
the expected quantum of funds remaining in the $20-billion Trust fund in
subsequent periods; the expected level of reported production in the fourth
quarter of 2012, and the expected level of full-year reported production in
2012; the expected level of full-year production (as adjusted for divestments
and the impact of entitlement effects in BP's PSAs) in 2012; the timing of and
prospects for the completion of planned and announced divestments, including
the disposals of the Carson refinery and the Texas City refinery; the expected
level of refining margins in the fourth quarter of 2012; the expected level of
refinery turnarounds in the fourth quarter of 2012; the timing of and
prospects for upgrades to the Whiting refinery; the expected level of
petrochemicals margins in the fourth quarter of 2012 and the prospects for and
expected timing of certain investigations, claims, hearings, settlements and
litigation outcomes. By their nature, forward-looking statements involve risk
and uncertainty because they relate to events and depend on circumstances that
will or may occur in the future. Actual results may differ from those
expressed in such statements, depending on a variety of factors including the
timing of bringing new fields onstream; the timing of divestments; future
levels of industry product supply; demand and pricing; OPEC quota
restrictions; PSA effects; operational problems; general economic conditions;
political stability and economic growth in relevant areas of the world;
changes in laws and governmental regulations; regulatory or legal actions
including the types of enforcement action pursued and the nature of remedies
sought; the impact on our reputation following the Gulf of Mexico oil spill;
exchange rate fluctuations; development and use of new technology; the success
or otherwise of partnering; the actions of competitors, trading partners,
creditors, rating agencies and others; natural disasters and adverse weather
conditions; changes in public expectations and other changes to business
conditions; wars and acts of terrorism or sabotage; and other factors
discussed under "Principal risks and uncertainties" in our Form 6-K for the
period ended 30 June 2012 and under "Risk factors" in our Annual Report and
Form 20-F 2011 as filed with the US Securities and Exchange Commission.
Top of page 14
Group income statement
Third Second Third Nine Nine
quarter quarter quarter months months
2011 2012 2012 2012 2011
$ million
95,383 93,341 90,591 Sales and other operating revenues 277,972 282,076
(Note 4)
Earnings from jointly controlled
entities - after
300 88 235 interest and tax 613 1,093
1,108 545 1,548 Earnings from associates - after 3,353 3,772
interest and tax
151 176 137 Interest and other income 488 426
790 742 610 Gains on sale of businesses and 2,285 2,753
fixed assets
97,732 94,892 93,121 Total revenues and other income 284,711 290,120
73,825 75,522 68,148 Purchases 215,313 213,827
7,809 7,889 7,093 Production and manufacturing 21,703 20,517
expenses(a)
2,021 1,827 1,912 Production and similar taxes (Note 6,085 6,208
5)
2,647 2,877 3,200 Depreciation, depletion and 9,285 8,153
amortization
Impairment and losses on sale of
businesses
211 4,821 486 and fixed assets 5,447 1,653
100 616 290 Exploration expense 1,166 1,178
3,693 3,213 3,627 Distribution and administration 9,968 10,048
expenses
(298) (270) (72) Fair value (gain) loss on embedded (243) 98
derivatives
7,724 (1,603) 8,437 Profit (loss) before interest and 15,987 28,438
taxation
298 267 256 Finance costs(a) 806 920
Net finance income relating to
(64) (55) (58) pensions and other (166) (198)
post-retirement benefits
7,490 (1,815) 8,239 Profit (loss) before taxation 15,347 27,716
2,270 (475) 2,739 Taxation(a) 5,211 9,393
5,220 (1,340) 5,500 Profit (loss) for the period 10,136 18,323
Attributable to
5,043 (1,385) 5,434 BP shareholders 9,964 18,015
177 45 66 Minority interest 172 308
5,220 (1,340) 5,500 10,136 18,323
Earnings per share - cents (Note
6)
Profit (loss) for the period
attributable to
BP shareholders
26.62 (7.29) 28.54 Basic 52.40 95.39
26.28 (7.29) 28.39 Diluted 52.05 94.22
(a) See Note 2 on pages 23 - 28 for further details of the impact of the Gulf
of Mexico oil spill on the income statement line items.
Top of page 15
Group statement of comprehensive income
Third Second Third Nine Nine
quarter quarter quarter months months
2011 2012 2012 2012 2011
$ million
5,220 (1,340) 5,500 Profit (loss) for the 10,136 18,323
period
(1,483) (1,038) 747 Currency translation 295 (425)
differences
Exchange (gains)
losses on translation
of
foreign operations
transferred to gain or
loss
6 (12) 12 on sales of - 19
businesses and fixed
assets
Actuarial gain (loss)
relating to pensions
and
- (2,301) 192 other (689) -
post-retirement
benefits
(338) (109) 61 Available-for-sale 16 (167)
investments marked to
market
Available-for-sale
investments - recycled
2 - - to the income - (3)
statement
(125) (96) 48 Cash flow hedges 27 68
marked to market
(70) 28 29 Cash flow hedges - The story has
recycled to the income been
statement truncated,
[TRUNCATED]
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