Summarized Group Income Statement

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BP p.l.c.
Group Results
Third Quarter 2006



London 24 October 2006

FOR IMMEDIATE RELEASE



Third
Second
Third




Quarter
Quarter
Quarter

Nine Months
2005
2006
2006
$ million
2006
2005
%
6,463
7,266
6,231
Profit for the period*
19,120
18,656

(2,053) (1,148)
744
Inventory holding (gains) losses
(762)
(3,774)






4,410
6,118
6,975
Replacement cost profit
18,358
14,882
23






11.86
16.59
18.76

per ordinary share (pence)
50.01
38.08

21.04
30.28
35.08

per ordinary share (cents)
91.02
70.07
30
1.26
1.82
2.10

per ADS (dollars)
5.46
4.20




BP’s third quarter replacement cost profit was $6,975 million, compared with $4,410 million a year ago, an
increase of 58%. For the nine months, replacement cost profit was $18,358 million compared with $14,882
million, up 23%.



The third quarter result included a net non-operating gain of $1,225 million compared with a net non-
operating charge of $921 million in the third quarter of 2005. This includes significant gains on upstream
asset disposals. For the nine months, the net non-operating gain was $1,214 million compared with a net
non-operating charge of $1,201 million for the nine months of 2005.



Compared with a year ago, the third quarter trading environment reflected higher oil realizations and higher
retail margins but lower refining margins and lower gas realizations.



Net cash provided by operating activities for the quarter and nine months was $5.1 billion and $23.2 billion
compared with $6.4 billion and $22.5 billion a year ago.



The ratio of net debt to net debt plus equity was 16%.



The quarterly dividend, to be paid in December, is 9.825 cents per share ($0.5895 per ADS) compared with
8.925 cents per share a year ago. For the nine months, the dividend showed an increase of 10%. In
sterling terms, the quarterly dividend is 5.241 pence per share, compared with 5.061 pence per share a
year ago; for the nine months the increase was 8%. During the nine months, the company repurchased
1,024 million of its own shares at a cost of $12 billion.

BP Group Chief Executive, Lord Browne, said:

“The trading environment reflected higher oil realizations and retail margins but lower refining margins
and gas realizations compared to a year ago. The third quarter result benefited from significant
disposal gains and IFRS accounting effects. Results are being impacted by higher tax charges. The
share buyback programme is continuing, with $3.5 billion of share repurchases during the quarter”.


* Profit attributable to BP shareholders.


1


Summary Quarterly Results



Exploration and Production’s third quarter result benefited from higher liquid realizations offset by lower gas
realizations. In addition, it included higher production taxes and higher costs, reflecting the impacts of sector
specific inflation, revenue investment and production growth. Furthermore, the result includes significant net
gains on the sale of assets. BP’s share of the TNK-BP result benefited from a gain of $892 million on the sale of
its interest in the Urdmurtneft assets.

Compared with a year ago, the Refining and Marketing result, excluding Texas City, reflects strong operating
performance. The lower result reflects lower refining margins, reduced supply optimization benefits and the
impact of higher levels of refining turnaround activity. Retail margins improved strongly compared with a year
ago. The result includes a significant gain related to IFRS fair value accounting effects.

In Gas, Power and Renewables, the lower third quarter result includes a charge for non-operating items
compared with a gain in the same period last year. A significant reduction in the contribution from gas and power
marketing and trading was partly offset by better operational performance in the natural gas liquids business and
a lower charge related to IFRS fair value accounting.

Finance costs and Other finance expense was $117 million for the quarter compared with $181 million in the third
quarter of 2005. Increases in market interest rates were more than offset by higher capitalized interest and a
higher return on pension assets due to the increased market value of the pension asset base.

The consolidation adjustment, which removes the margin on sales between segments in respect of inventory at
the period end, was a credit of $440 million in the third quarter. This primarily reflects changes in the amount of
BP equity production held in Refining and Marketing segment inventories.

The effective tax rate on replacement cost profit of continuing operations was 40% versus 34% a year earlier,
reflecting the retroactive impact of the increase in the North Sea tax rate, enacted in July 2006. The effect of this
change on the Group’s effective tax rate is partly mitigated by a sharp decline in prices around the end of the
quarter.

Capital expenditure was $4.8 billion for the quarter, including $1 billion in respect of our investment in Rosneft.
Disposal proceeds were $2.8 billion.

Net debt at the end of the quarter was $16.8 billion. The ratio of net debt to net debt plus equity was 16%.

During the third quarter, the company repurchased 299 million of its own shares, at a cost of $3.5 billion. Of
these, 48 million shares were purchased for cancellation and the remainder are held in treasury. Additionally,
shares to the value of $1.25 billion were issued to Alfa Group and Access Renova (AAR) being the last instalment
of the deferred consideration for our investment in TNK-BP.

The commentaries above and following are based on replacement cost profit.

The financial information for 2005 has been restated to reflect the following, all with effect from 1 January 2006:
(a) the transfer of three equity-accounted entities from Other businesses and corporate to Refining and Marketing
following the sale of Innovene; (b) the transfer of certain mid-stream assets and activities from Refining and
Marketing and Exploration and Production to Gas, Power and Renewables; (c) the transfer of Hydrogen for
Transport activities from Gas, Power and Renewables to Refining and Marketing; and (d) the change in the basis
of accounting for over-the-counter forward sale and purchase contracts for oil, natural gas, NGLs and power. See
Note 2 for further details.

2



Non-operating Items





Third
$ million
Quarter
2006




Exploration and Production


2,466
Refining and Marketing


(431)
Gas, Power and Renewables


(85)
Other businesses and corporate


78


2,028

Taxation

(803)
Continuing Operations


1,225
Innovene Operations



Taxation



Total for all operations


1,225


3


Reconciliation of Replacement Cost Profit to Profit for the Period


Third
Second
Third


Quarter
Quarter
Quarter
Nine Months
2005
2006
2006 $ million
2006
2005
6,534
7,826
9,935 Exploration and Production
24,584
18,919
1,875
1,856
1,503 Refining and Marketing
4,971
4,559
347
453
152 Gas, Power and Renewables
906
948
(501) (193) (261) Other businesses and corporate
(671)
(828)


Consolidation adjustments


(285) (277) 440
Unrealized profit in inventory
155
(442)
Net profit on transactions between continuing
144


and Innovene operations(a)

399
8,114
9,665
11,769 RC profit before interest and tax
29,945
23,555





(181) (107) (117) Finance costs and other finance expense
(367)
(546)
(2,674) (3,441) (4,614) Taxation
(10,984)
(7,444)
(68) (77) (63) Minority interest
(211)
(198)
RC profit from continuing operations
5,191
6,040
6,975 attributable to BP shareholders(b)
18,383
15,367





Inventory holding gains (losses) for
1,938
1,148
(744) continuing operations
762
3,547
Profit for the period from continuing
operations attributable to

7,129
7,188
6,231 BP shareholders
19,145
18,914
Profit (loss) for the period from Innovene
(666)
78
– operations(c)
(25)
(258)
Profit for the period attributable to
6,463
7,266
6,231 BP shareholders
19,120
18,656





RC profit from continuing operations attributable
5,191
6,040
6,975 to BP shareholders
18,383
15,367
(781)
78
RC profit (loss) from Innovene operations
(25)
(485)
4,410
6,118
6,975 Replacement cost profit
18,358
14,882


(a)
In the circumstances of discontinued operations, Accounting Standards require that the profits earned by the discontinued
operations, in this case the Innovene operations, on sales to the continuing operations be eliminated on consolidation from
the discontinued operations, and attributed to the continuing operations and vice versa. This adjustment has two offsetting
elements: the net margin on crude refined by Innovene as substantially all crude for their refineries was supplied by BP and
most of the refined products manufactured were taken by BP; and the margin on sales of feedstock from BP’s US refineries
to Innovene’s manufacturing plants. The profits attributable to individual segments were not affected by this adjustment.
Neither does this representation indicate the profits earned by continuing or Innovene operations, as if they were stand-
alone entities, for past periods or likely to be earned in future periods.


(b)
Replacement cost profit reflects the current cost of supplies. The replacement cost profit for the period is arrived at by
excluding from profit inventory holding gains and losses. BP uses this measure to assist investors to assess BP’s
performance from period to period. Replacement cost profit is not a recognized GAAP measure. Operating cash flow is
calculated from the starting point of profit before taxation which includes inventory holding gains and losses. Operating
cash flow also reflects working capital movements including inventories, trade and other receivables and trade and other
payables. The carrying value of these working capital items will change for various reasons, including movements in oil,
gas and products prices.


(c)
See further detail in Note 3.





4


Per Share Amounts



Third
Second
Third


Quarter
Quarter
Quarter
Nine Months
2005
2006
2006
2006
2005


Results for the period ($m)


6,463
7,266
6,231 Profit*
19,120
18,656
4,410
6,118
6,975 Replacement cost profit
18,358
14,882





20,984,851 19,993,613 19,815,830 Shares in issue at period end (thousand)
19,815,830
20,984,851
3,497,475
3,332,269
3,302,638 – ADS equivalent (thousand)
3,302,638
3,497,475
Average number of shares outstanding
21,007,316 20,171,546 19,818,106 (thousand)
20,167,945
21,238,117
3,501,219
3,361,924
3,303,018 – ADS equivalent (thousand)
3,361,324
3,539,686







Per ordinary share (cents)


30.75
35.94
31.46 Profit for the period
94.80
87.84
21.04
30.28
35.08 RC profit for the period
91.02
70.07







Per
ADS (cents)


184.50
215.64
188.76 Profit for the period
568.80
527.04
126.24
181.68
210.48 RC profit for the period
546.12
420.42

* Profit attributable to BP shareholders.

5


Exploration and Production



Third
Second
Third


Quarter
Quarter
Quarter
Nine Months
2005
2006
2006 $ million
2006
2005
6,535
7,827
9,929 Profit before interest and tax(a)
24,572
18,928
(1) (1)
6 Inventory holding (gains) losses
12
(9)
Replacement cost profit before interest
6,534
7,826
9,935 and tax
24,584
18,919







Results
include:


Impairment and gain (loss) on sale of
(106) 330
1,962 businesses and fixed assets
2,301
831


(17) Environmental and other provisions
(17)

Restructuring, integration and


rationalization costs


Fair value gain (loss) on embedded
(53) 149
521 derivatives
275
(887)
12

Other

37
(147) 479
2,466 Total non-operating items
2,559
(19)





177
97
351 Exploration expense
637
476


Of which:


93
13
232 Exploration expenditure written off
359
224







Production (Net of royalties) (b)


2,313
2,355
2,250 Crude oil (mb/d)
2,323
2,385
159
176
172 Natural gas liquids (mb/d)
172
176
2,472
2,531
2,422 Total liquids (mb/d) (c)
2,495
2,561
7,841
8,624
8,086 Natural gas (mmcf/d)
8,471
8,412
3,824
4,018
3,816 Total hydrocarbons (mboe/d) (d)
3,954
4,011







Average
realizations(e)


56.83
65.96
67.22 Crude oil ($/bbl)
63.73
49.07
36.70
37.80
40.08 Natural gas liquids ($/bbl)
37.81
31.30
54.80
62.86
64.15 Total liquids ($/bbl)
60.91
47.22
4.75
4.44
4.49 Natural gas ($/mcf)
4.83
4.45
41.68
44.58
45.47 Total hydrocarbons ($/boe)
44.74
36.97







Average oil marker prices ($/bbl)


61.63
69.59
69.60 Brent
67.02
53.68
63.18
70.46
70.44 West Texas Intermediate
68.09
55.43
60.91
68.84
69.02 Alaska North Slope US West Coast
66.28
52.08







Average natural gas marker prices


8.53
6.80
6.58 Henry Hub gas price ($/mmbtu) (f)
7.45
7.19
29.26
34.55
33.72 UK Gas – National Balancing Point (p/therm)
46.28
32.42


(a)
Profit from continuing operations and includes profit after interest and tax of equity-accounted entities.
(b)
Includes BP’s share of production of equity-accounted entities.
(c)
Crude oil and natural gas liquids.
(d)
Natural gas is converted to oil equivalent at 5.8 billion cubic feet = 1 million barrels.
(e)
Based on sales of consolidated subsidiaries only - this excludes equity-accounted entities.
(f)
Henry Hub First of the Month Index.

6


Exploration and Production



The replacement cost profit before interest and tax for the third quarter was $9,935 million, an increase of 52%
over the third quarter of 2005. This result benefited from higher liquid realizations offset by lower gas realizations.
In addition, it included higher production taxes and higher costs, reflecting the impacts of sector specific inflation,
revenue investment and production growth. Furthermore, BP’s share of the TNK-BP result benefited from a gain
of $892 million on the sale of its interest in the Urdmurtneft assets. Net non-operating gains for the third quarter
were $2,466 million, mainly arising from net gains on sale of assets of $1,985 million, primarily from the sale of a
pre-development asset in the Gulf of Mexico, and fair value gains of $521 million on embedded derivatives
relating to North Sea gas contracts. The corresponding quarter in 2005 contained a net non-operating charge of
$147 million.

After adjusting for the effect of disposals, production increased by 3% compared with the third quarter of 2005.
Actual production was broadly flat compared with the third quarter of 2005.

The replacement cost profit before interest and tax of $24,584 million for the first nine months represented an
increase of 30% over the same period of the previous year. This result benefited from higher oil and gas
realizations partially offset by lower volumes, higher production taxes and higher costs reflecting the impacts of
sector specific inflation, increased integrity spend and repairs, revenue investments and production growth. The
nine months result included net gains on sales of assets of $2,324 million and net fair value gains of $275 million
on embedded derivatives. The first nine months of 2005 contained a net non-operating charge of $19 million.

After adjusting for the effect of disposals, production for the first nine months was up around 1% compared with
the first nine months of 2005 as underlying production growth from major projects in the new profit centres and
TNK-BP offset decline in existing profit centres. Actual production was down 57 mboe/d from 2005.

In September, we determined that the oil transit lines in the Eastern Operating Area of Prudhoe Bay could be
returned to service for the purposes of in-line inspection. We have now returned to service all three flow stations
previously shut down, and current production from Prudhoe Bay is around 400,000 barrels of oil and natural gas
liquids per day (BP has a 26% interest in the Prudhoe Bay field). We are still committed to replacing the main oil
transit lines (16 miles) in both the Eastern and Western Operating Areas of Prudhoe Bay and expect to complete
this next year. The effect of reduced production at Prudhoe Bay on average third quarter production was
27 mboe/d.

Offshore commissioning work on the Thunder Horse platform is proceeding. Following a series of tests carried
out over the past few months, which revealed metallurgical failures in components of the subsea system, we plan
to retrieve and replace all the subsea components we believe could be at risk. This work will be done over the
course of the next year and we do not expect production from Thunder Horse to begin before the middle of 2008.
It is too early to estimate the additional costs involved in replacing the affected systems.

In our other major projects we continue to make good progress. In Azerbaijan, ACG and BTC continue to ramp
up. The Shah Deniz gas field and East Azeri are on track to start up in the fourth quarter. In Angola, the FPSO
for the Dalia field is now being moored.

During the quarter, we made a significant oil exploration discovery on the Kaskida prospect in approximately
5,900 feet of water in the Gulf of Mexico and in Angola, we announced the Titania discovery, our 11th discovery in
Block 31. In addition we have been awarded the Birbhum coal bed methane licence in India and have reached
agreement to acquire acreage in the UK Central North Sea which contains two discovered fields and further
exploration potential.

During the quarter, we completed the sale of our remaining Gulf of Mexico Shelf assets which have been subject
to pre-emption rights. In July, we completed the sale of our 28% interest in the Shenzi discovery in the Gulf of
Mexico to Repsol. To date we have received $3.8 billion of proceeds from our divestment activity in 2006. In
August, TNK-BP completed the sale of its interest in the Urdmurtneft assets to Sinopec and we announced the
sale of five onshore properties in South Louisiana.


7


Refining and Marketing



Third
Second
Third


Quarter
Quarter
Quarter
Nine Months
2005
2006
2006 $ million
2006
2005
3,714
2,992
717 Profit before interest and tax (a)
5,747
7,999
(1,839) (1,136)
786 Inventory holding (gains) losses
(776)
(3,440)
Replacement cost profit before
1,875
1,856
1,503 interest and tax
4,971
4,559


Results
include:


Impairment and gain (loss) on sale of
(14) 112

2 businesses and fixed assets
678
34
(140) –
(33) Environmental and other provisions
(33)
(140)
Restructuring, integration and


rationalization costs


Fair value gain (loss) on embedded


derivatives



(576)
(400) Other
(976)
(733)
(154) (464) (431) Total non-operating items
(331)
(839)


Refinery
throughputs (mb/d)


202
162
200 UK
158
192
687
671
622 Rest of Europe
644
668
1,328
1,200
1,213 USA
1,130
1,360
296
256
252 Rest of World
268
300
2,513
2,289
2,287 Total throughput
2,200
2,520
92.6
86.4
82.2 Refining availability (%)(b)
83.2
93.6


Oil
sales
volumes
(mb/d)




Refined
products


369
354
370 UK
356
354
1,402
1,311
1,367 Rest of Europe
1,331
1,357
1,674
1,631
1,609 USA
1,613
1,660
599
579
578 Rest of World
575
608
4,044
3,875
3,924 Total marketing sales
3,875
3,979
2,010
1,682
1,911 Trading/supply sales
1,932
2,112
6,054
5,557
5,835 Total refined product sales
5,807
6,091
2,471
1,996
1,913 Crude oil
2,160
2,474
8,525
7,553
7,748 Total oil sales
7,967
8,565


Global Indicator Refining Margin ($/bbl) (c)


7.78
5.78
4.54 NWE
4.40
5.46
17.12
17.74
11.47 USGC
13.36
11.31
13.40
14.75
11.50 Midwest
10.38
8.28
17.57
21.27
12.30 USWC
14.93
15.02
6.52
6.83
3.58 Singapore
4.65
5.94
12.35
12.59
8.40 BP Average
9.09
8.93


Chemicals
production
(kte)


284
298
230 UK
831
918
771
741
776 Rest of Europe
2,359
2,312
890
816
883 USA
2,488
3,215
1,674
1,728
1,682 Rest of World
5,097
4,225
3,619
3,583
3,571 Total production
10,775
10,670

(a)
Profit from continuing operations and includes profit after interest and tax of equity-accounted entities.
(b)
Refining availability is defined as the ratio of units which are available for processing, regardless of whether they are
actually being used, to total capacity. Where there is planned maintenance, such capacity is not regarded as being
available. During the first nine months 2006, there was planned maintenance of a substantial part of the Texas City
refinery.
(c)
The Global Indicator Refining Margin (GIM) is the average of regional indicator margins weighted for BP’s crude refining
capacity in each region. Each regional indicator margin is based on a single representative crude with product yields
characteristic of the typical level of upgrading complexity. The regional indicator margins 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.

8


Refining and Marketing



The replacement cost profit before interest and tax for the third quarter was $1,503 million. This is compared to
$1,875 million for the same period last year. The nine months’ result was $4,971 million compared to
$4,559 million for the same period last year, up 9%.

The quarter’s result included a charge of $431 million for non-operating items. This includes a further provision of
$400 million as a result of the ongoing review of fatality and personal injury compensation claims associated with
the incident in March 2005 at the Texas City refinery. In addition, non-operating items include impairment
charges of $90 million, a charge of $33 million in respect of new, and revisions to existing, environmental and
other provisions and net disposal gains of $92 million. The non-operating charge for the corresponding quarter in
2005 was $154 million.

The third quarter’s result included a significant gain related to IFRS fair value accounting effects. The third
quarter of 2005 included a smaller gain.

The results for both the third quarter and the first nine months of 2006, excluding Texas City, reflect strong
operating performance. The reduction in the result in respect of Texas City, including the impact on associated
businesses, was some $320 million compared to the third quarter of 2005 and around $1,400 million compared
with the first nine months of 2005. These figures exclude the provisions for fatality and personal injury
compensation claims which are treated as non-operating items. The third quarter result also reflects the absence
of hurricane activity which negatively impacted the third quarter of 2005.

This quarter’s result reflects lower refining margins and reduced supply optimization benefits driven by lower
crude and product prices, particularly around the end of the quarter. The quarter’s result also included the impact
of higher levels of refining turnaround activity. Retail margins improved strongly compared with the third quarter
of 2005 due to the steady decline in wholesale product prices. The result for the first nine months reflects higher
marketing margins and supply optimization benefits compared with the first nine months of 2005.

Refinery throughputs for the quarter and nine months were 2,287 mb/d and 2,200 mb/d respectively, lower than in
the corresponding periods of 2005. This is primarily as a result of the phased start-up of production at our Texas
City refinery during 2006. The recommissioning of the Texas City refinery continues, with throughput for the
quarter averaging 247 mb/d. Refining availability for the quarter, excluding Texas City, was 96.3%, higher than in
the corresponding period last year. Marketing sales were 3,924 mb/d for the third quarter and 3,875 mb/d for the
first nine months of the year, compared with 4,044 mb/d and 3,979 mb/d for the corresponding periods in the
previous year.

During the quarter, BP announced that it has entered the final planning stage of a $3 billion investment in
Canadian heavy crude oil processing capability at its Whiting refinery located in northwest Indiana. The intention
is to reconfigure the Whiting refinery so most of its feedstock can be heavy Canadian crude oil. Reconfiguring the
refinery also has the potential to increase its production of motor fuels by around 15 percent, which is
approximately 1.7 million additional gallons of gasoline and diesel per day. Construction is tentatively scheduled
to begin in 2007 and be completed by 2011, pending regulatory approval.

9


Gas, Power and Renewables



Third
Second
Third


Quarter
Quarter
Quarter
Nine Months
2005
2006
2006 $ million
2006
2005
445
463
152 Profit before interest and tax (a)
853
1,046
(98)
(10)
– Inventory holding (gains) losses
53
(98)
Replacement cost profit before
347
453
152 interest and tax
906
948


Results
include:


Impairment and gain (loss) on sale of
(2) (1)
(65) businesses and fixed assets
(66)
81
6

Environmental and other provisions

6
Restructuring, integration and


rationalization costs


Fair value gain (loss) on embedded
91
107
(20) derivatives
32
200


Other


95
106
(85) Total non-operating items
(34)
287


(a)
Profit from continuing operations and includes profit after interest and tax of equity-accounted entities.

The replacement cost profit before interest and tax for the third quarter and nine months was $152 million and
$906 million respectively, compared with $347 million and $948 million a year ago. Included in the result for the
quarter was a charge for non-operating items of $85 million arising from fair value losses of $20 million on
embedded derivatives related to long-term gas contracts, a charge of $70 million for the impairment of a North
American NGL asset and a $5 million gain on disposal. The corresponding quarter of 2005 included a net non-
operating gain of $95 million, largely comprising fair value gains of $91 million on embedded derivatives.

The third quarter result was 56% lower than the same quarter of 2005. The decrease was primarily due to a non-
operating charge in the current quarter compared with a net non-operating gain in the same period last year. A
significant reduction in the contribution from gas and power marketing and trading was partly offset by better
operational performance in the natural gas liquids business and a lower charge related to IFRS fair value
accounting. Similarly, the nine month result was marginally lower than the same period in 2005, largely reflecting
a net charge for non-operating items compared with a gain in the same period last year and higher IFRS fair value
accounting charges, partly offset by higher contributions from the operating businesses.

In August, we purchased Greenlight Energy, Inc., a US-based developer of wind power generation projects. The
purchase will further accelerate the rapid growth of BP’s wind power business in North America. In Korea,
K-power Company Limited (BP 35%) completed construction of a 1,074MW, LNG-fired combined cycle power
plant near Kwangyang City, which has began full commercial operation.






10