Blueprint

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 6-K

Report of Foreign Issuer

Pursuant to Rule 13a-16 or 15d-16 of

the Securities Exchange Act of 1934

for the period ended 31 October 2017

BP p.l.c.

(Translation of registrant's name into English)

1 ST JAMES'S SQUARE, LONDON, SW1Y 4PD, ENGLAND

(Address of principal executive offices)

Indicate by check mark whether the registrant files or will file annual

reports under cover Form 20-F or Form 40-F.

Form 20-F |X| Form 40-F

--------------- ----------------

Indicate by check mark whether the registrant by furnishing the information

contained in this Form is also thereby furnishing the information to the

Commission pursuant to Rule 12g3-2(b) under the Securities Exchange Act of

1934.

Yes No |X|

--------------- ----------------

FOR IMMEDIATE RELEASE

London 31 October 2017

BP p.l.c. Group results

Third quarter and nine months 2017

For a printer friendly copy of this announcement, please click on the link below to open a PDF version:

http://www.rns-pdf.londonstockexchange.com/rns/0280V_-2017-10-30.pdf

Top of page 1

Highlights	Year-to-date organic balance at $49 a barrel Share buybacks announced to offset scrip dilution Reported third quarter group oil and gas production up 14%
	● Underlying replacement cost (RC) profit* for the third quarter was $1.9 billion, compared with $684 million in previous quarter. ● Third-quarter operating cash flow, excluding Gulf of Mexico oil spill payments, was $6.6 billion. Including these payments, operating cash flow for the quarter was $6.0 billion. ● Underlying operating cash flow* in first nine months exceeded organic capital expenditure* plus full dividend* - equivalent to organic cash balance including full dividend at Brent oil price of $49 a barrel, or $42 a barrel including cash dividend only(a). ● Dividend unchanged at 10 cents per share. ● Recommencing share buyback programme in fourth quarter to offset ongoing dilutive effect of scrip dividends over time. ● Reported group oil and gas production in the third quarter averaged 3.6 million barrels of oil equivalent a day, 14% higher than in the third quarter of 2016. ● Three Upstream major projects* began production in the quarter. ● Downstream underlying quarterly earnings were the highest for five years, second-highest on a RC basis. ● Around $4.5 billion in disposal proceeds are expected for full year 2017, with $1.0 billion received in first nine months. Proceeds expected in the fourth quarter include those from the SECCO transaction ($1.4 billion) and the initial public offering of BP Midstream Partners LP's common units ($0.7 billion).

Financial summary

Third quarter 2017

See chart on PDF

	Third	Second	Third	Nine	Nine
	quarter	quarter	quarter	months	months
$ million	2017	2017	2016	2017	2016
Profit (loss) for the period(b)	1,769	144	1,620	3,362	(382)
Inventory holding (gains) losses*, net of tax	(390)	409	41	(18)	(689)
RC profit (loss)*	1,379	553	1,661	3,344	(1,071)
Net (favourable) adverse impact of
non-operating items* and fair value accounting
effects*, net of tax	486	131	(728)	715	3,256
Underlying RC profit	1,865	684	933	4,059	2,185
RC profit (loss) per ordinary share (cents)*	6.98	2.80	8.82	17.01	(5.74)
RC profit (loss) per ADS (dollars)	0.42	0.17	0.53	1.02	(0.34)
Underlying RC profit per ordinary share (cents)*	9.44	3.47	4.96	20.65	11.70
Underlying RC profit per ADS (dollars)	0.57	0.21	0.30	1.24	0.70

(a)	See organic balance/organic cash balance definition and further information in the Glossary on page 29.
(b)	Profit attributable to BP shareholders.

Bob Dudley - Group chief executive:

"We are steadily building a track record of delivering on our plans and growing across our businesses. This quarter, three new Upstream projects and the highest Downstream earnings in five years, underpinned by reliable operations and disciplined spending, have generated healthy earnings and cash flow. There is still room for further improvement and we will keep striving to increase sustainable free cash flow* and distributions to shareholders."

* See definitions in the Glossary on page 29. RC profit (loss), underlying RC profit, operating cash flow excluding Gulf of Mexico oil spill payments / Underlying operating cash flow and organic capital expenditure are non-GAAP measures.
The commentary above and following should be read in conjunction with the cautionary statement on page 32.

Top of page 2

BP p.l.c. Group results

Third quarter and nine months 2017

Group headlines

Earnings

BP's profit for the third quarter and nine months was $1,769 million and $3,362 million respectively, compared with a profit of $1,620 million and a loss of $382 million for the same periods in 2016.

The third-quarter replacement cost (RC) profit was $1,379 million, compared with $1,661 million for the same period in 2016. After adjusting for a net charge for non-operating items of $274 million and net adverse fair value accounting effects of $212 million (both on a post-tax basis), underlying RC profit for the third quarter was $1,865 million, compared with $933 million for the same period in 2016.

For the nine months, RC profit was $3,344 million, compared with a loss of $1,071 million a year ago. After adjusting for a net charge for non-operating items of $794 million and net favourable fair value accounting effects of $79 million (both on a post-tax basis), underlying RC profit for the nine months was $4,059 million, compared with $2,185 million for the same period in 2016.

See further information on page 3.

Non-operating items

Non-operating items amounted to a charge of $385 million pre-tax and $274 million post-tax for the quarter and a charge of $1,297 million pre-tax and $794 million post-tax for the nine months. See further information on page 25.

Effective tax rate

The effective tax rate (ETR) on RC profit or loss* for the third quarter and nine months was 43% for both periods, compared with -16% and 73% for the same periods in 2016. Adjusting for non-operating items and fair value accounting effects and the impact of the reduction in the rate of the UK North Sea supplementary charge in the third quarter 2016, the adjusted ETR* for the third quarter and nine months was 40% and 42% respectively, compared with 37% and 25% for the same periods in 2016.

The adjusted ETR for the third quarter and nine months is higher than a year ago mainly due to changes in the mix of profits, notably the impact of the renewal of our interest in the Abu Dhabi onshore oil concession. We continue to expect the full year adjusted ETR to be above 40%. Adjusted ETR is a non-GAAP measure. See further information on page 29.

Dividend

BP today announced a quarterly dividend of 10.00 cents per ordinary share ($0.600 per ADS), which is expected to be paid on 21 December 2017. The corresponding amount in sterling will be announced on 11 December 2017. See page 22 for further information.

Share buybacks

BP will recommence a share buyback programme in the fourth quarter, intended to offset the ongoing dilutive effect of scrip dividends over time. The programme will not necessarily match the dilution on a quarterly basis but will reflect the ongoing judgement of various factors including changes in the price environment, the underlying performance of the business, the outlook for the group's financial framework and other market factors which may vary from quarter to quarter.

Operating cash flow*

Excluding post-tax amounts related to the Gulf of Mexico oil spill, operating cash flow* for the third quarter and nine months was $6.6 billion and $17.9 billion respectively, compared with $4.8 billion and $13.1 billion for the same periods in 2016. Including amounts relating to the Gulf of Mexico oil spill, operating cash flow for the third quarter and nine months was $6.0 billion and $13.0 billion respectively, compared with $2.5 billion and $8.3 billion for the same periods in 2016.

Capital expenditure*

Organic capital expenditure* for the third quarter and nine months was $4.0 billion and $11.9 billion respectively, compared with $3.5 billion and $12.2 billion for the same periods in 2016.

Inorganic capital expenditure* for the third quarter and nine months was $0.5 billion and $1.1 billion respectively, compared with $0.05 billion, and $0.3 billion for the same periods in 2016.

Organic and inorganic capital expenditure are non-GAAP measures. See page 24 for further information.

Divestment proceeds*

Divestment proceeds were $0.2 billion for the third quarter and $1.0 billion for the nine months, compared with $0.6 billion and $2.2 billion for the same periods in 2016.

Net debt*

Net debt at 30 September 2017 was $39.8 billion, compared with $32.4 billion a year ago. The net debt ratio* at 30 September 2017 was 28.4%, compared with 25.9% a year ago. Net debt and the net debt ratio are non-GAAP measures. See page 23 for more information.

Brian Gilvary - Chief financial officer:

"We have made strong progress this year in adjusting to the lower oil price environment and have now brought our finances, including the full dividend, back into organic balance at an oil price just below $50 a barrel. Given the momentum we see across our businesses and our confidence in the outlook for the group's finances, we will be recommencing a share buyback programme this quarter. We intend to offset the ongoing dilution from the scrip dividend over time."

The commentary above should be read in conjunction with the cautionary statement on page 32.

Top of page 3

BP p.l.c. Group results

Third quarter and nine months 2017

Analysis of underlying RC profit before interest and tax

	Third	Second	Third	Nine	Nine
	quarter	quarter	quarter	months	months
$ million	2017	2017	2016	2017	2016
Underlying RC profit before interest and tax*
Upstream	1,562	710	(224)	3,642	(942)
Downstream	2,338	1,413	1,431	5,493	4,757
Rosneft	137	279	120	515	432
Other businesses and corporate	(398)	(366)	(260)	(1,204)	(814)
Consolidation adjustment - UPII*	(130)	135	17	(63)	(64)
Underlying RC profit before interest and tax	3,509	2,171	1,084	8,383	3,369
Finance costs and net finance expense relating to
pensions and other post-retirement benefits	(444)	(420)	(358)	(1,251)	(1,012)
Taxation on an underlying RC basis	(1,212)	(1,055)	164	(3,030)	(161)
Non-controlling interests	12	(12)	43	(43)	(11)
Underlying RC profit attributable to BP
shareholders	1,865	684	933	4,059	2,185

Reconciliations of underlying RC profit or loss to the nearest equivalent IFRS measure are provided on page 1 for the group and on pages 6-11 for the segments.

Analysis of RC profit (loss) before interest and tax and reconciliation to

profit (loss) for the period

	Third	Second	Third	Nine	Nine
	quarter	quarter	quarter	months	months
$ million	2017	2017	2016	2017	2016
RC profit (loss) before interest and tax*
Upstream	1,242	795	1,196	3,293	(118)
Downstream	2,175	1,567	978	5,448	4,263
Rosneft	137	279	120	515	432
Other businesses and corporate(a)	(460)	(721)	(441)	(1,612)	(7,040)
Consolidation adjustment - UPII	(130)	135	17	(63)	(64)
RC profit (loss) before interest and tax	2,964	2,055	1,870	7,581	(2,527)
Finance costs and net finance expense relating to
pensions and other post-retirement benefits	(566)	(541)	(481)	(1,620)	(1,381)
Taxation on a RC basis	(1,031)	(949)	229	(2,574)	2,848
Non-controlling interests	12	(12)	43	(43)	(11)
RC profit (loss) attributable to BP shareholders	1,379	553	1,661	3,344	(1,071)
Inventory holding gains (losses)	557	(586)	(60)	37	996
Taxation (charge) credit on inventory holding
gains and losses	(167)	177	19	(19)	(307)
Profit (loss) for the period attributable to
BP shareholders	1,769	144	1,620	3,362	(382)

(a)	Includes costs related to the Gulf of Mexico oil spill. See page 11 and also Note 2 from page 17 for further information on the accounting for the Gulf of Mexico oil spill.

Top of page 4

BP p.l.c. Group results

Third quarter and nine months 2017

Strategic progress		Financial framework
Upstream Three Upstream major projects, the Persephone project in Australia, the Juniper project in Trinidad, and the first phase of the Khazzan tight gas development in Oman, all started production in the third quarter. Six of the seven major projects BP expects to start production in 2017 are now online. The seventh, Zohr in Egypt, is on track to start up before the end of the year. The delivery of the major projects continues to underpin Upstream production growth. Over the first nine months of 2017, Upstream production - which excludes Rosneft - was 10% higher than in the same period in 2016. Upstream unit production costs* are also 16% lower than the prior year, benefiting from production growth and continued focus on cost discipline. In September, BP, together with our partners, extended the production-sharing agreement* (PSA) for the Azeri, Chirag and Deep Water Gunashli fields (ACG) in Azerbaijan by 25 years to the end of 2049. Downstream BP delivered double digit earnings growth from fuels marketing in the first nine months - premium fuel sales volumes have continued to grow and BP's convenience partnership model has been rolled out to more than 170 retail sites worldwide so far this year. In lubricants, BP renewed its global partnership and supply agreement with Volvo Car Group. In manufacturing, both refining and petrochemicals have grown earnings, with our US refineries processing record levels of advantaged crude.		Operating cash flow, excluding Gulf of Mexico payments, was $6.6 billion in the third quarter, and $17.9 billion for the first nine months of 2017. This compares with $13.1 billion for the first nine months of 2016. Organic capital expenditure of $4.0 billion in the third quarter brought the total for the first nine months to $11.9 billion. BP now expects total organic capital expenditure for 2017 will be around $16 billion, within the $15-17 billion range previously indicated. In the first nine months of 2017, operating cash flow excluding Gulf of Mexico payments exceeded organic capital expenditure and cash dividend payments to BP shareholders by $1.5 billion. Divestment proceeds, as per the cash flow statement, for the first nine months of 2017 were $1.0 billion. Significant proceeds are expected to be received in the fourth quarter, including those from the sale of BP's interest in the SECCO joint venture in China ($1.4 billion) and from the initial public offering of BP Midstream Partners LP's common units ($0.7 billion). Total proceeds in 2017 are expected to be around $4.5 billion. Gulf of Mexico oil spill payments were $0.6 billion in the third quarter, significantly lower than in the first two quarters of the year. Payments over the first nine months of 2017 were $4.9 billion; for the full year payments are now expected to be around $5.5 billion. BP continues to target a gearing range of 20-30%. At the end of the third quarter, gearing was 28.4%.
Operating metrics	Nine months 2017(vs. Nine months 2016)	Financial metrics	Nine months 2017(vs. Nine months 2016)
SafetyTier 1 process safety events*	12 (-1)	Underlying RC profit	$4.1bn (+$1.9bn)
SafetyReported recordable injury frequency*	0.21 (-4%)	Operating cash flow excluding Gulf of Mexico oil spill payments	$17.9bn (+$4.8bn)
Group production	3,557mboe/d (+10%)	Organic capital expenditure	$11.9bn (-$0.3bn)
Upstream production (excludes Rosneft segment)	2,427mboe/d (+10%)	Gulf of Mexico oil spill payments	$4.9bn (+$0.03bn)
Upstream unit production costs	$7.17/boe (-16%)	Divestment proceeds	$1.0bn (-$1.2bn)
BP-operated Upstream operating efficiency*(a)	80.4%	Net debt ratio (gearing)	28.4% (+2.5)
Refining availability*	95.0% (-0.4)	Dividend per ordinary share(b)	10.00 cents (-)

(a)	Reported on a one-quarter lagged basis and represents first half 2017 actuals only.
(b)	Represents dividend announced in the quarter (vs. prior year quarter).

The commentary above contains forward-looking statements and should be read in conjunction with the cautionary statement on page 32.

Top of page 5

BP p.l.c. Group results

Third quarter and nine months 2017

INTENTIONALLY BLANK

Top of page 6

BP p.l.c. Group results

Third quarter and nine months 2017

Upstream

	Third	Second	Third	Nine	Nine
	quarter	quarter	quarter	months	months
$ million	2017	2017	2016	2017	2016
Profit (loss) before interest and tax	1,255	796	1,183	3,301	(77)
Inventory holding (gains) losses*	(13)	(1)	13	(8)	(41)
RC profit (loss) before interest and tax	1,242	795	1,196	3,293	(118)
Net (favourable) adverse impact of
non-operating items* and fair value
accounting effects*	320	(85)	(1,420)	349	(824)
Underlying RC profit (loss) before interest
and tax*(a)	1,562	710	(224)	3,642	(942)

(a)	See page 7 for a reconciliation to segment RC profit before interest and tax by region.

Financial results

The replacement cost profit before interest and tax for the third quarter and nine months was $1,242 million and $3,293 million respectively, compared with a profit of $1,196 million and a loss of $118 million for the same periods in 2016. The third quarter and nine months included a net non-operating charge of $146 million and $527 million respectively, compared with a net non-operating gain of $1,465 million and $1,117 million for the same periods in 2016. Fair value accounting effects in the third quarter and nine months had an adverse impact of $174 million and a favourable impact of $178 million respectively, compared with an adverse impact of $45 million and $293 million in the same periods of 2016.

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 $1,562 million and $3,642 million respectively, compared with a loss of $224 million and a loss of $942 million for the same periods in 2016. The result for the third quarter mainly reflected higher liquids and gas realizations, higher production including the impact of the Abu Dhabi concession renewal and major project start-ups, and lower exploration write-offs, partly offset by higher depreciation, depletion and amortization. The result for the nine months reflected higher liquids and gas realizations, and higher production including the impact of the Abu Dhabi concession renewal and major project start-ups, partly offset by higher depreciation, depletion and amortization, and higher exploration write-offs.

Production

Production for the quarter was 2,462mboe/d, 16.3% higher than the third quarter of 2016. Underlying production* for the quarter increased by 10.9%, due to the ramp-up of major projects. For the nine months, production was 2,427mboe/d, 9.6% higher than in the same period of 2016. Nine months underlying production was 6.7% higher than the same period of 2016 due to major project start-ups.

Key events

On 7 August, BP announced that it has brought online a natural gas well (BP 100%) in the Mancos Shale, New Mexico in the US Lower 48, highlighting the potential of the field to be a significant new source of US natural gas supply.

On 14 August, BP Trinidad and Tobago announced first gas from the Juniper development in Trinidad. On the same day, BP confirmed that production has started from the Persephone project off the coast of Western Australia (Woodside operator, BP 16.67%).

On 11 September, BP announced an agreement with Bridas Corporation to form a new integrated energy company in Argentina, Pan American Energy Group (PAEG), by combining their interests in the oil and gas producer Pan American Energy with the refining and marketing company Axion Energy in a cash-free transaction. PAEG will be owned equally by BP and Bridas Corporation.

On 14 September, the joint development and production-sharing agreement* (PSA) for the Azeri, Chirag fields and the Deep Water Portion of the Gunashli field in the Azerbaijan sector of the Caspian Sea (ACG PSA) was extended by signing an amended and restated PSA between the State Oil Company of the Republic of Azerbaijan (SOCAR) and the contractor parties. The renewed PSA, expected to be ratified by the Azerbaijani parliament before year end, extends the PSA's term by 25 years to 2049 and includes an improved contractor parties' profit share at a fixed rate of 25%. Under the terms of the agreement, BP's interest changes from 35.78% to 30.37% from the agreement's effective date following ratification, with a bonus of $1.46 billion (BP net), payable to the government of Azerbaijan in equal instalments over 8 years.

On 25 September, BP, together with the Ministry of Oil & Gas of the Sultanate of Oman, announced that first gas had been achieved from the Khazzan gas field (BP operator 60%, Oman Oil Company 40%).

On 24 October, Aker BP ASA (Aker BP), in which BP holds a 30% ownership interest, announced an agreement to acquire Hess Norge AS. Upon completion of the transaction, Aker BP will become the sole owner of the Valhall and Hod fields. This transaction is subject to regulatory approvals.

On 27 October, BP won two licences in the third Pre-Salt Bid Round in Brazil, the Alto De Cabo Frio Central block (Petrobras operator 50%, BP 50%), and the Peroba block (Petrobras operator 40%, BP 40%, and China National Petroleum Corporation 20%).

Outlook

Looking ahead, we expect fourth-quarter reported production to be higher than the third quarter reflecting the continued ramp-up of major projects and recovery from seasonal turnaround and maintenance activities.

The commentary above contains forward-looking statements and should be read in conjunction with the cautionary statement on page 32.

Top of page 7

BP p.l.c. Group results

Third quarter and nine months 2017

Upstream (continued)

	Third	Second	Third	Nine	Nine
	quarter	quarter	quarter	months	months
$ million	2017	2017	2016	2017	2016
Underlying RC profit (loss) before interest and tax
US	264	179	(151)	609	(1,123)
Non-US	1,298	531	(73)	3,033	181
	1,562	710	(224)	3,642	(942)
Non-operating items(a)
US(b)	(97)	(34)	326	(143)	106
Non-US(c)(d)	(49)	13	1,139	(384)	1,011
	(146)	(21)	1,465	(527)	1,117
Fair value accounting effects
US	(100)	92	(15)	184	(105)
Non-US	(74)	14	(30)	(6)	(188)
	(174)	106	(45)	178	(293)
RC profit (loss) before interest and tax
US	67	237	160	650	(1,122)
Non-US	1,175	558	1,036	2,643	1,004
	1,242	795	1,196	3,293	(118)
Exploration expense
US(b)	190	25	22	255	182
Non-US(d)(e)	107	825	781	1,304	1,225
	297	850	803	1,559	1,407
Of which: Exploration expenditure written off(b)(d)(e)	217	753	687	1,231	1,108
Production (net of royalties)(f)
Liquids*(g) (mb/d)
US	408	418	353	425	386
Europe	123	122	112	120	119
Rest of World(g)	809	812	669	816	714
	1,341	1,352	1,134	1,360	1,219
Natural gas (mmcf/d)
US	1,703	1,576	1,679	1,625	1,649
Europe	217	274	262	251	263
Rest of World	4,581	4,410	3,753	4,311	3,867
	6,502	6,260	5,695	6,187	5,779
Total hydrocarbons*(g) (mboe/d)
US	702	689	643	705	670
Europe	161	169	157	163	164
Rest of World(g)	1,599	1,572	1,316	1,559	1,381
	2,462	2,431	2,116	2,427	2,215
Average realizations*(h)
Total liquids(g)(i) ($/bbl)	47.45	46.27	40.99	47.87	36.50
Natural gas ($/mcf)	2.89	3.19	2.77	3.18	2.76
Total hydrocarbons(g) ($/boe)	33.23	33.59	29.37	34.63	27.20

(a)	Third quarter and nine months 2016 principally relate to impairment reversals in Angola and the North Sea.
(b)	Third quarter and nine months 2017 include the write-off of $145 million in relation to the value ascribed to certain licences in the deepwater Gulf of Mexico as part of the accounting for the acquisition of upstream assets from Devon Energy in 2011. This has been classified within the 'other' category of non-operating items.
(c)	Nine months 2017 includes an impairment charge arising following the announcement on 3 April 2017 of the agreement to sell the Forties Pipeline System business to INEOS.
(d)	Third quarter and nine months 2016 include $601 million of exploration write-offs relating to a licence in Brazil, of which $334 million relates to the value ascribed to the licence when acquired from Devon Energy in 2011, and has been classified within the 'other' category of non-operating items.
(e)	Second quarter and nine months 2017 include the write-off of exploration well and lease costs in Angola. Nine months 2017 also includes the write-off of exploration well costs in Egypt.
(f)	Includes BP's share of production of equity-accounted entities in the Upstream segment.
(g)	A minor adjustment has been made to comparative periods in 2016. See page 28 for more information.
(h)	Realizations are based on sales by consolidated subsidiaries only - this excludes equity-accounted entities.
(i)	Includes condensate, natural gas liquids and bitumen.

Because of rounding, some totals may not agree exactly with the sum of their component parts.

Top of page 8

BP p.l.c. Group results

Third quarter and nine months 2017

Downstream

	Third	Second	Third	Nine	Nine
	quarter	quarter	quarter	months	months
$ million	2017	2017	2016	2017	2016
Profit (loss) before interest and tax	2,695	988	943	5,487	5,189
Inventory holding (gains) losses*	(520)	579	35	(39)	(926)
RC profit before interest and tax	2,175	1,567	978	5,448	4,263
Net (favourable) adverse impact of
non-operating items* and fair value
accounting effects*	163	(154)	453	45	494
Underlying RC profit before interest and tax*(a)	2,338	1,413	1,431	5,493	4,757

(a)	See page 9 for a reconciliation to segment RC profit before interest and tax by region and by business.

Financial results

The replacement cost profit before interest and tax for the third quarter and nine months was $2,175 million and $5,448 million respectively, compared with $978 million and $4,263 million for the same periods in 2016.

The third quarter and nine months include a net non-operating charge of $55 million and a net non-operating gain of $7 million respectively, compared with a net non-operating charge of $196 million and a net non-operating gain of $53 million for the same periods in 2016. Fair value accounting effects had an adverse impact of $108 million in the third quarter and $52 million for the nine months, compared with an adverse impact of $257 million and $547 million for the same periods in 2016.

Replacement cost profit before interest and tax for fuels, lubricants and petrochemicals is set out on page 9.

Fuels business

The fuels business reported an underlying replacement cost profit before interest and tax of $1,788 million for the third quarter and $3,896 million for the nine months, compared with $983 million and $3,310 million for the same periods in 2016 driven by higher refining and fuels marketing results. The result for the quarter also reflects an improved contribution from supply and trading. The contribution was however lower for the nine months compared to last year.

The refining result for the quarter and nine months reflects continued strong operational performance, capturing higher industry refining margins which were partially offset by narrower North American heavy crude oil differentials. The result also benefited from increased commercial optimization and higher levels of advantaged feedstock processed in the US. The nine-months result also reflects the impact of a higher level of planned turnaround activity.

The fuels marketing result for both the quarter and nine months reflects continued profit growth supported by higher premium volume and the continued rollout of our convenience partnership sites.

On 30 October, we completed the initial public offering of common units in our subsidiary, BP Midstream Partners LP. As a result of the initial public offering, we received net proceeds of around $0.7 billion.

Lubricants business

The lubricants business reported an underlying replacement cost profit before interest and tax of $356 million for the third quarter and $1,104 million for the nine months, compared with $370 million and $1,166 million for the same periods in 2016. The result for the quarter and nine months reflects continued premium brand growth, more than offset by the impact of higher base oil prices due to temporary supply constraints and increasing crude oil prices.

Petrochemicals business

The petrochemicals business reported an underlying replacement cost profit before interest and tax of $194 million for the third quarter and $493 million for the nine months, compared with $78 million and $281 million for the same periods in 2016. The result for the quarter and nine months reflects an improved margin environment, stronger margin optimization and lower costs reflecting the continued benefits from our simplification and efficiency programmes.

In April, we announced our intention to divest our 50% shareholding in our Shanghai SECCO Petrochemical Company Limited joint venture in China. The transaction is expected to complete in the fourth quarter. As a result, the asset relating to our shareholding has been classified as held for sale in the group balance sheet at 30 September 2017.

Outlook

While industry refining margins have remained robust coming into the fourth quarter, we would expect a normal seasonal decline compared with the third quarter. In the fourth quarter, we also expect a higher level of turnaround activity.

The commentary above contains forward-looking statements and should be read in conjunction with the cautionary statement on page 32.

Top of page 9

BP p.l.c. Group results

Third quarter and nine months 2017

Downstream (continued)

	Third	Second	Third	Nine	Nine
	quarter	quarter	quarter	months	months
$ million	2017	2017	2016	2017	2016
Underlying RC profit before interest and tax -
by region
US	640	283	298	1,477	1,224
Non-US	1,698	1,130	1,133	4,016	3,533
	2,338	1,413	1,431	5,493	4,757
Non-operating items
US	(39)	28	(56)	(23)	74
Non-US	(16)	110	(140)	30	(21)
	(55)	138	(196)	7	53
Fair value accounting effects
US	20	10	(178)	(32)	(343)
Non-US	(128)	6	(79)	(20)	(204)
	(108)	16	(257)	(52)	(547)
RC profit before interest and tax
US	621	321	64	1,422	955
Non-US	1,554	1,246	914	4,026	3,308
	2,175	1,567	978	5,448	4,263
Underlying RC profit before interest and tax -
by business(a)(b)
Fuels	1,788	908	983	3,896	3,310
Lubricants	356	355	370	1,104	1,166
Petrochemicals	194	150	78	493	281
	2,338	1,413	1,431	5,493	4,757
Non-operating items and fair value
accounting effects(c)
Fuels	(154)	159	(455)	9	(493)
Lubricants	(3)	(2)	1	(8)	(3)
Petrochemicals	(6)	(3)	1	(46)	2
	(163)	154	(453)	(45)	(494)
RC profit before interest and tax(a)(b)
Fuels	1,634	1,067	528	3,905	2,817
Lubricants	353	353	371	1,096	1,163
Petrochemicals	188	147	79	447	283
	2,175	1,567	978	5,448	4,263

BP average refining marker margin (RMM)* ($/bbl)	16.3	13.8	11.6	14.0	12.0
Refinery throughputs (mb/d)
US	737	708	613	713	660
Europe	768	782	795	784	802
Rest of World	240	198	242	207	237
	1,745	1,688	1,650	1,704	1,699
Refining availability* (%)	95.3	94.5	95.4	95.0	95.4
Marketing sales of refined products (mb/d)
US	1,186	1,177	1,205	1,160	1,130
Europe	1,204	1,153	1,236	1,143	1,184
Rest of World	480	497	503	496	502
	2,870	2,827	2,944	2,799	2,816
Trading/supply sales of refined products	3,088	2,996	2,581	3,015	2,755
Total sales volumes of refined products	5,958	5,823	5,525	5,814	5,571
Petrochemicals production (kte)
US	617	672	564	1,787	2,018
Europe	1,285	1,365	898	3,903	2,799
Rest of World	2,025	2,001	1,987	6,099	5,863
	3,927	4,038	3,449	11,789	10,680

(a)	Segment-level overhead expenses are included in the fuels business result.
(b)	BP's share of income from petrochemicals at our Gelsenkirchen and Mülheim sites in Germany is reported in the fuels business.
(c)	For Downstream, fair value accounting effects arise solely in the fuels business.

Top of page 10

BP p.l.c. Group results

Third quarter and nine months 2017

Rosneft

	Third	Second	Third	Nine	Nine
	quarter	quarter	quarter	months	months
$ million	2017(a)	2017	2016	2017(a)	2016
Profit before interest and tax(b)	161	271	108	505	461
Inventory holding (gains) losses*	(24)	8	12	10	(29)
RC profit before interest and tax	137	279	120	515	432
Net charge (credit) for non-operating items*	-	-	-	-	-
Underlying RC profit before interest and tax*	137	279	120	515	432

Financial results

Replacement cost profit before interest and tax and underlying replacement cost profit before interest and tax for the third quarter and nine months was $137 million and $515 million respectively, compared with $120 million and $432 million for the same periods in 2016. There were no non-operating items in the third quarter and nine months of either year.

Compared with the same period in 2016, the result for the third quarter was primarily affected by higher oil prices and favourable duty lag effects partially offset by adverse foreign exchange effects. For the nine months, the result was primarily affected by higher oil prices partially offset by adverse foreign exchange effects.

In June 2017 Rosneft's annual general meeting adopted a resolution to pay dividends of 5.98 Russian roubles per ordinary share. In July BP received a dividend in relation to the 2016 annual results of $190 million, after the deduction of withholding tax.

BP's two nominees, Bob Dudley and Guillermo Quintero, were re-elected to Rosneft's board by the extraordinary general meeting (EGM) on 29 September. The EGM also adopted a resolution to pay interim dividends for the first half of 2017 of 3.83 Russian roubles per ordinary share. BP expects to receive a dividend of approximately $120 million after the deduction of withholding tax, subject to fluctuations in foreign exchange.

Key events

In August, Rosneft completed the acquisition of a 49.13% stake in Essar Oil Limited (EOL), an Indian downstream business, from the Essar group.

In October Rosneft completed the deal to acquire a 30% stake in a concession agreement to develop the Zohr field in Egypt from the Italian company Eni S.p.A.

	Third	Second	Third	Nine	Nine
	quarter	quarter	quarter	months	months
	2017(a)	2017	2016	2017(a)	2016
Production (net of royalties) (BP share)
Liquids* (mb/d)	903	902	820	906	813
Natural gas (mmcf/d)	1,263	1,302	1,221	1,300	1,256
Total hydrocarbons* (mboe/d)	1,120	1,126	1,030	1,130	1,030

(a)

The operational and financial information of the Rosneft segment for the third quarter and nine months of the year is based on preliminary operational and financial results of Rosneft for the nine months ended 30 September 2017. Actual results may differ from these amounts.

(b)

The Rosneft segment result includes equity-accounted earnings arising from BP's 19.75% shareholding in Rosneft as adjusted for the accounting required under IFRS relating to BP's purchase of its interest in Rosneft and the amortization of the deferred gain relating to the divestment of BP's interest in TNK-BP. These adjustments have increased the reported profit before interest and tax for the third quarter and nine months 2017, as shown in the table above, compared with the equivalent amount in Russian roubles that we expect Rosneft to report in its own financial statements under IFRS. BP's share of Rosneft's profit before interest and tax for each year-to-date period is calculated by translating the amounts reported in Russian roubles into US dollars using the average exchange rate for the year to date. BP's share of Rosneft's earnings after finance costs, taxation and non-controlling interests, as adjusted, is included in the BP group income statement within profit before interest and taxation.

Top of page 11

BP p.l.c. Group results

Third quarter and nine months 2017

Other businesses and corporate

	Third	Second	Third	Nine	Nine
	quarter	quarter	quarter	months	months
$ million	2017	2017	2016	2017	2016
Profit (loss) before interest and tax
Gulf of Mexico oil spill	(84)	(347)	(66)	(466)	(5,966)
Other	(376)	(374)	(375)	(1,146)	(1,074)
Profit (loss) before interest and tax	(460)	(721)	(441)	(1,612)	(7,040)
Inventory holding (gains) losses*	-	-	-	-	-
RC profit (loss) before interest and tax	(460)	(721)	(441)	(1,612)	(7,040)
Net charge (credit) for non-operating items*
Gulf of Mexico oil spill	84	347	66	466	5,966
Other	(22)	8	115	(58)	260
Net charge (credit) for non-operating items	62	355	181	408	6,226
Underlying RC profit (loss) before interest and
tax*	(398)	(366)	(260)	(1,204)	(814)
Underlying RC profit (loss) before interest and
tax
US	(145)	(104)	(107)	(446)	(326)
Non-US	(253)	(262)	(153)	(758)	(488)
	(398)	(366)	(260)	(1,204)	(814)
Non-operating items
US	(92)	(350)	(168)	(480)	(6,152)
Non-US	30	(5)	(13)	72	(74)
	(62)	(355)	(181)	(408)	(6,226)
RC profit (loss) before interest and tax
US	(237)	(454)	(275)	(926)	(6,478)
Non-US	(223)	(267)	(166)	(686)	(562)
	(460)	(721)	(441)	(1,612)	(7,040)

Other businesses and corporate comprises our alternative energy business, shipping, treasury, corporate activities including centralized functions, and the costs of the Gulf of Mexico oil spill.

Financial results

The replacement cost loss before interest and tax for the third quarter and nine months was $460 million and $1,612 million respectively, compared with $441 million and $7,040 million for the same periods in 2016.

The results included a net non-operating charge of $62 million for the third quarter and $408 million for the nine months, compared with a net non-operating charge of $181 million and $6,226 million for the same periods in 2016.

After adjusting for non-operating items, the underlying replacement cost loss before interest and tax for the third quarter and nine months was $398 million and $1,204 million respectively, compared with $260 million and $814 million for the same periods in 2016. The underlying charge for the nine months was impacted by weaker business results, and adverse foreign exchange effects which had a favourable effect in the same period in 2016.

Alternative energy - biofuels, wind

The net ethanol-equivalent production (which includes ethanol and sugar) for the third quarter and nine months was 362 million litres and 588 million litres respectively, compared with 352 million litres and 635 million litres for the same periods in 2016.

Net wind generation capacity*(a) was 1,432MW at 30 September 2017 compared with 1,474MW at 30 September 2016. BP's net share of wind generation for the third quarter and nine months was 644GWh and 2,856GWh respectively, compared with 828GWh and 3,235GWh for the same periods in 2016.

(a)	Capacity figures for 2016 include 23MW in the Netherlands managed by our Downstream segment.

Top of page 12

BP p.l.c. Group results

Third quarter and nine months 2017

Financial statements

Group income statement

	Third	Second	Third	Nine	Nine
	quarter	quarter	quarter	months	months
$ million	2017	2017	2016	2017	2016

Sales and other operating revenues (Note 5)	60,018	56,511	47,047	172,392	132,001
Earnings from joint ventures - after interest
and tax	231	160	174	596	477
Earnings from associates - after interest and tax	282	371	209	804	731
Interest and other income	185	127	146	434	392
Gains on sale of businesses and fixed assets	92	197	467	334	884
Total revenues and other income	60,808	57,366	48,043	174,560	134,485
Purchases	44,612	42,713	34,981	128,462	94,336
Production and manufacturing expenses(a)	5,454	5,761	5,517	16,470	22,482
Production and similar taxes (Note 6)	278	189	212	773	484
Depreciation, depletion and amortization (Note 5)	3,904	3,793	3,496	11,539	10,863
Impairment and losses on sale of businesses and
fixed assets	108	51	(1,424)	612	(1,359)
Exploration expense	297	850	803	1,559	1,407
Distribution and administration expenses	2,634	2,540	2,648	7,527	7,803
Profit (loss) before interest and taxation	3,521	1,469	1,810	7,618	(1,531)
Finance costs(a)	511	487	433	1,458	1,241
Net finance expense relating to pensions and
other post-retirement benefits	55	54	48	162	140
Profit (loss) before taxation	2,955	928	1,329	5,998	(2,912)
Taxation(a)	1,198	772	(248)	2,593	(2,541)
Profit (loss) for the period	1,757	156	1,577	3,405	(371)
Attributable to
BP shareholders	1,769	144	1,620	3,362	(382)
Non-controlling interests	(12)	12	(43)	43	11
	1,757	156	1,577	3,405	(371)

Earnings per share (Note 7)
Profit (loss) for the period attributable to
BP shareholders
Per ordinary share (cents)
Basic	8.95	0.73	8.61	17.10	(2.05)
Diluted	8.90	0.72	8.56	17.00	(2.05)
Per ADS (dollars)
Basic	0.54	0.04	0.52	1.03	(0.12)
Diluted	0.53	0.04	0.51	1.02	(0.12)

(a)	See Note 2 for information on the impact of the Gulf of Mexico oil spill on these income statement line items.

Top of page 13

BP p.l.c. Group results

Third quarter and nine months 2017

Group statement of comprehensive income

	Third	Second	Third	Nine	Nine
	quarter	quarter	quarter	months	months
$ million	2017	2017	2016	2017	2016

Profit (loss) for the period	1,757	156	1,577	3,405	(371)
Other comprehensive income
Items that may be reclassified subsequently to
profit or loss
Currency translation differences	611	(103)	192	1,722	1,031
Exchange gains (losses) on translation of
foreign operations reclassified to gain or loss
on sale of businesses and fixed assets	13	4	-	18	6
Available-for-sale investments	-	1	1	3	1
Cash flow hedges marked to market	49	81	(84)	178	(435)
Cash flow hedges reclassified to the income
statement	20	31	71	93	110
Cash flow hedges reclassified to the
balance sheet	29	36	30	104	49
Share of items relating to equity-accounted
entities, net of tax	128	72	174	431	661
Income tax relating to items that may
be reclassified	(59)	4	(78)	(180)	(84)
	791	126	306	2,369	1,339
Items that will not be reclassified to profit or loss
Remeasurements of the net pension and other
post-retirement benefit liability or asset	1,002	318	(2,995)	2,047	(5,980)
Income tax relating to items that will not be
reclassified	(351)	(102)	510	(699)	1,504
	651	216	(2,485)	1,348	(4,476)
Other comprehensive income	1,442	342	(2,179)	3,717	(3,137)
Total comprehensive income	3,199	498	(602)	7,122	(3,508)
Attributable to
BP shareholders	3,206	472	(558)	7,041	(3,513)
Non-controlling interests	(7)	26	(44)	81	5
	3,199	498	(602)	7,122	(3,508)

Top of page 14

BP p.l.c. Group results

Third quarter and nine months 2017

Group statement of changes in equity

	BP
	shareholders'	Non-controlling	Total
$ million	equity	interests	equity

At 1 January 2017	95,286	1,557	96,843

Total comprehensive income	7,041	81	7,122
Dividends	(4,526)	(109)	(4,635)
Share-based payments, net of tax	514	-	514
Share of equity-accounted entities' change in equity, net of tax	206	-	206
Transactions involving non-controlling interests	-	88	88
At 30 September 2017	98,521	1,617	100,138

	BP
	shareholders'	Non-controlling	Total
$ million	equity	interests	equity

At 1 January 2016	97,216	1,171	98,387

Total comprehensive income	(3,513)	5	(3,508)
Dividends	(3,429)	(83)	(3,512)
Share-based payments, net of tax	622	-	622
Share of equity-accounted entities' change in equity, net of tax	49	-	49
Transactions involving non-controlling interests	431	328	759
At 30 September 2016	91,376	1,421	92,797

Top of page 15

BP p.l.c. Group results

Third quarter and nine months 2017

Group balance sheet

	30 September	31 December
$ million	2017	2016
Non-current assets
Property, plant and equipment	130,651	129,757
Goodwill	11,514	11,194
Intangible assets	18,586	18,183
Investments in joint ventures	6,703	8,609
Investments in associates	15,921	14,092
Other investments	1,051	1,033
Fixed assets	184,426	182,868
Loans	553	532
Trade and other receivables	1,461	1,474
Derivative financial instruments	4,470	4,359
Prepayments	1,094	945
Deferred tax assets	4,819	4,741
Defined benefit pension plan surpluses	2,297	584
	199,120	195,503
Current assets
Loans	267	259
Inventories	18,078	17,655
Trade and other receivables	21,833	20,675
Derivative financial instruments	2,248	3,016
Prepayments	1,441	1,486
Current tax receivable	746	1,194
Other investments	84	44
Cash and cash equivalents	25,780	23,484
	70,477	67,813
Assets classified as held for sale (Note 3)	1,892	-
	72,369	67,813
Total assets	271,489	263,316
Current liabilities
Trade and other payables	39,965	37,915
Derivative financial instruments	2,154	2,991
Accruals	4,797	5,136
Finance debt	8,891	6,634
Current tax payable	1,455	1,666
Provisions	2,304	4,012
	59,566	58,354
Non-current liabilities
Other payables	13,805	13,946
Derivative financial instruments	3,881	5,513
Accruals	501	469
Finance debt	56,893	51,666
Deferred tax liabilities	7,619	7,238
Provisions	20,078	20,412
Defined benefit pension plan and other post-retirement benefit plan deficits	9,008	8,875
	111,785	108,119
Total liabilities	171,351	166,473
Net assets	100,138	96,843
Equity
BP shareholders' equity	98,521	95,286
Non-controlling interests	1,617	1,557
Total equity	100,138	96,843

Top of page 16

BP p.l.c. Group results

Third quarter and nine months 2017

Condensed group cash flow statement

		Third	Second	Third	Nine	Nine
		quarter	quarter	quarter	months	months
$ million		2017	2017	2016	2017	2016
Operating activities
Profit (loss) before taxation		2,955	928	1,329	5,998	(2,912)
Adjustments to reconcile profit (loss) before taxation
taxation to net cash provided by operating
activities
Depreciation, depletion and amortization and
exploration expenditure written off		4,121	4,546	4,183	12,770	11,971
Impairment and (gain) loss on sale of businesses
and fixed assets		16	(146)	(1,891)	278	(2,243)
Earnings from equity-accounted entities,
less dividends received		(111)	(103)	259	(434)	(250)
Net charge for interest and other finance
expense, less net interest paid		163	84	204	499	485
Share-based payments		177	156	166	495	629
Net operating charge for pensions and other post-
retirement benefits, less contributions and
benefit payments for unfunded plans		(160)	54	(96)	(179)	(120)
Net charge for provisions, less payments		(144)	183	(184)	(138)	5,116
Movements in inventories and other current and
non-current assets and liabilities		305	3	(1,001)	(3,292)	(3,591)
Income taxes paid		(1,298)	(815)	(461)	(2,969)	(822)
Net cash provided by operating activities		6,024	4,890	2,508	13,028	8,263
Investing activities
Expenditure on property, plant and equipment,
intangible and other assets		(4,136)	(4,181)	(3,379)	(12,140)	(12,043)
Acquisitions, net of cash acquired		(146)	(123)	-	(311)	-
Investment in joint ventures		(5)	(10)	(1)	(35)	(13)
Investment in associates		(176)	(174)	(185)	(533)	(474)
Total cash capital expenditure		(4,463)	(4,488)	(3,565)	(13,019)	(12,530)
Proceeds from disposal of fixed assets		149	312	590	649	981
Proceeds from disposal of businesses, net of
cash disposed		92	140	(21)	305	1,181
Proceeds from loan repayments		308	19	9	341	61
Net cash used in investing activities		(3,914)	(4,017)	(2,987)	(11,724)	(10,307)
Financing activities
Proceeds from long-term financing		3,078	1,720	3,925	8,511	9,373
Repayments of long-term financing		(1,239)	(1,463)	(75)	(3,619)	(4,952)
Net increase (decrease) in short-term debt		123	(299)	(512)	139	(324)
Net increase (decrease) in non-controlling interests		-	51	323	81	761
Dividends paid	- BP shareholders	(1,676)	(1,546)	(1,161)	(4,526)	(3,429)
	- non-controlling interests	(32)	(62)	(31)	(109)	(83)
Net cash provided by (used in) financing activities		254	(1,599)	2,469	477	1,346
Currency translation differences relating to cash
and cash equivalents		146	202	13	515	(171)
Increase (decrease) in cash and cash equivalents		2,510	(524)	2,003	2,296	(869)
Cash and cash equivalents at beginning of period		23,270	23,794	23,517	23,484	26,389
Cash and cash equivalents at end of period		25,780	23,270	25,520	25,780	25,520

Top of page 17

BP p.l.c. Group results

Third quarter and nine months 2017

Notes

Note 1. Basis of preparation

The interim financial information included in this report has been prepared in accordance with IAS 34 'Interim Financial Reporting'.

The results for the interim periods are unaudited and, in the opinion of management, include all adjustments necessary for a fair presentation of the results for each period. All such adjustments are of a normal recurring nature. This report should be read in conjunction with the consolidated financial statements and related notes for the year ended 31 December 2016 included in BP Annual Report and Form 20-F 2016.

BP prepares its consolidated financial statements included within BP Annual Report and Form 20-F on the basis of International Financial Reporting Standards (IFRS) as issued by the International Accounting Standards Board (IASB), IFRS as adopted by the European Union (EU) and in accordance with the provisions of the UK Companies Act 2006. IFRS as adopted by the EU differs in certain respects from IFRS as issued by the IASB. The differences have no impact on the group's consolidated financial statements for the periods presented.

The financial information presented herein has been prepared in accordance with the accounting policies expected to be used in preparing BP Annual Report and Form 20-F 2017, which do not differ significantly from those used in BP Annual Report and Form 20-F 2016.

Note 2. Gulf of Mexico oil spill

(a) Overview

The information presented in this note should be read in conjunction with BP Annual Report and Form 20-F 2016 - Financial statements - Note 2 and Legal proceedings on page 261.

The group income statement includes a pre-tax charge for the third quarter of $84 million to reflect the latest estimate for claims and associated administration costs, and $122 million for finance costs relating to the unwinding of discounting effects. The equivalent amounts for the nine months were $466 million and $369 million respectively. The cumulative pre-tax income statement charge since the incident, in April 2010, amounts to $63,420 million.

The amounts set out below reflect the impacts on the financial statements of the Gulf of Mexico oil spill for the periods presented. The income statement, balance sheet and cash flow statement impacts are included within the relevant line items in those statements as set out below.

	Third	Second	Third	Nine	Nine
	quarter	quarter	quarter	months	months
$ million	2017	2017	2016	2017	2016
Income statement
Production and manufacturing expenses	84	347	66	466	5,966
Profit (loss) before interest and taxation	(84)	(347)	(66)	(466)	(5,966)
Finance costs	122	121	123	369	369
Profit (loss) before taxation	(206)	(468)	(189)	(835)	(6,335)
Taxation	71	154	53	273	2,837
Profit (loss) for the period	(135)	(314)	(136)	(562)	(3,498)

Top of page 18

BP p.l.c. Group results

Third quarter and nine months 2017

Note 2. Gulf of Mexico oil spill (continued)

	30 September	31 December
$ million	2017	2016
Balance sheet
Current assets
Trade and other receivables	214	194
Current liabilities
Trade and other payables	(2,069)	(3,056)
Provisions	(726)	(2,330)
Net current assets (liabilities)	(2,581)	(5,192)
Non-current assets
Deferred tax assets	2,821	2,973
Non-current liabilities
Other payables	(12,197)	(13,522)
Provisions	-	(112)
Deferred tax liabilities	5,544	5,119
Net non-current assets (liabilities)	(3,832)	(5,542)
Net assets (liabilities)	(6,413)	(10,734)

	Third	Second	Third	Nine	Nine
	quarter	quarter	quarter	months	months
$ million	2017	2017	2016	2017	2016
Cash flow statement - Operating activities
Profit (loss) before taxation	(206)	(468)	(189)	(835)	(6,335)
Adjustments to reconcile profit (loss) before
taxation to net cash provided by
operating activities
Net charge for interest and other finance
expense, less net interest paid	122	121	123	369	369
Net charge for provisions, less payments	68	298	(494)	361	4,729
Movements in inventories and other current
and non-current assets and liabilities	(548)	(1,976)	(1,766)	(4,778)	(3,825)
Pre-tax cash flows	(564)	(2,025)	(2,326)	(4,883)	(5,062)

Cash outflows in 2016 and 2017 include payments made under the 2012 agreement with the US government to resolve all federal criminal claims arising from the incident and the 2016 consent decree and settlement agreement with the United States and the five Gulf coast states. Net cash from operating activities relating to the Gulf of Mexico oil spill, on a post-tax basis, amounted to an outflow of $564 million and $4,883 million in the third quarter and nine months of 2017 respectively. For the same periods in 2016, the amount was an outflow of $2,326 million and $4,849 million respectively.

Top of page 19

BP p.l.c. Group results

Third quarter and nine months 2017

Note 2. Gulf of Mexico oil spill (continued)

(b) Provisions and other payables

Provisions

Movements in the remaining provision, which relates to litigation and claims, are shown in the table below.

$ million
At 1 July 2017		955
Net increase in provision		75
Reclassified to other payables		(19)
Utilization		(285)
At 30 September 2017		726

Movements in the remaining provision during the nine months are shown in the table below.

$ million
At 1 January 2017		2,442
Net increase in provision		437
Reclassified to other payables		(709)
Utilization		(1,444)
At 30 September 2017		726

The provision includes amounts for the future cost of resolving claims by individuals and businesses for damage to real or personal property, lost profits or impairment of earning capacity and loss of subsistence use of natural resources.

PSC settlement

The provision for the cost associated with the 2012 Plaintiffs' Steering Committee (PSC) settlement reflects the latest estimate for claims, including business economic loss claims and associated administration costs. However, the amounts ultimately payable may differ from the amount provided and the timing of payments is uncertain.

The settlement programme's determination of business economic loss claims is now expected to be substantially complete by the end of 2017. Nevertheless a significant number of claims determined by the settlement programme have been and continue to be appealed by BP and/or the claimants. Depending upon the resolution of these claims under appeal, the amounts payable may differ from those currently provided.

There is additional uncertainty in relation to the impact of the May 2017 Fifth Circuit opinion (on the policy addressing the matching of revenue with expenses in relation to business economic loss claims) including on those business economic loss claims that have not yet been determined and those that are under appeal within the settlement programme. This includes uncertainty in relation to the impact of recently filed appeals of the district court's orders instructing the settlement programme on how to implement the Fifth Circuit's opinion. See Legal proceedings on page 32 for further details on the Fifth Circuit opinion and appeal of the district court's orders.

Amounts to resolve remaining claims under the PSC settlement are expected to be substantially paid by the end of 2018. The timing of payments is uncertain, and in particular, will be impacted by how long it takes to resolve claims that have been appealed and may be appealed in the future.

Other payables

Other payables include amounts payable under the 2012 agreement with the US government to resolve all federal criminal claims arising from the incident, amounts payable under the consent decree and settlement agreement with the United States and the five Gulf coast states for natural resource damages, state claims and Clean Water Act penalties, BP's remaining commitment to fund the Gulf of Mexico Research Initiative, and amounts payable for certain economic loss and property damage claims.

Further information on provisions, other payables, and contingent liabilities is provided in BP Annual Report and Form

20-F 2016 - Financial statements - Note 2.

Top of page 20

BP p.l.c. Group results

Third quarter and nine months 2017

Note 3. Non-current assets held for sale and events after the reporting period

In September, BP announced that it had agreed with Bridas Corporation (Bridas) to form a new integrated energy company by combining their interests in the oil and gas producer Pan American Energy (PAE) and the refiner and marketer Axion Energy (Axion) in a cash-free transaction. PAE is currently owned 60% by BP and 40% by Bridas. The new company, Pan American Energy Group, will be owned equally by BP and Bridas. The transaction, which is subject to certain pre-closing conditions being fulfilled, is expected to complete in the first quarter 2018. As a result, one sixth of BP's investment in PAE has been classified as held for sale in the group balance sheet at 30 September 2017.

In April, BP announced its intention to divest its 50% shareholding in the Shanghai SECCO Petrochemical Company Limited joint venture in China. During the quarter a number of steps in the regulatory process, and certain conditions precedent, were completed and the investment has been classified as held for sale in the group balance sheet at 30 September 2017. We expect to complete the transaction and receive estimated proceeds of $1.4 billion in the fourth quarter.

Note 4. Analysis of replacement cost profit (loss) before interest and tax and

reconciliation to profit (loss) before taxation

	Third	Second	Third	Nine	Nine
	quarter	quarter	quarter	months	months
$ million	2017	2017	2016	2017	2016
Upstream	1,242	795	1,196	3,293	(118)
Downstream	2,175	1,567	978	5,448	4,263
Rosneft	137	279	120	515	432
Other businesses and corporate(a)	(460)	(721)	(441)	(1,612)	(7,040)
	3,094	1,920	1,853	7,644	(2,463)
Consolidation adjustment - UPII*	(130)	135	17	(63)	(64)
RC profit (loss) before interest and tax*	2,964	2,055	1,870	7,581	(2,527)
Inventory holding gains (losses)*
Upstream	13	1	(13)	8	41
Downstream	520	(579)	(35)	39	926
Rosneft (net of tax)	24	(8)	(12)	(10)	29
Profit (loss) before interest and tax	3,521	1,469	1,810	7,618	(1,531)
Finance costs	511	487	433	1,458	1,241
Net finance expense relating to pensions and
other post-retirement benefits	55	54	48	162	140
Profit (loss) before taxation	2,955	928	1,329	5,998	(2,912)

RC profit (loss) before interest and tax*
US	428	302	(15)	1,243	(6,665)
Non-US	2,536	1,753	1,885	6,338	4,138
	2,964	2,055	1,870	7,581	(2,527)

(a)	Includes costs related to the Gulf of Mexico oil spill. See Note 2 for further information.

Top of page 21

BP p.l.c. Group results

Third quarter and nine months 2017

Note 5. Segmental analysis

Sales and other operating revenues	Third	Second	Third	Nine	Nine
	quarter	quarter	quarter	months	months
$ million	2017	2017	2016	2017	2016
By segment
Upstream	10,969	10,493	8,452	32,789	24,059
Downstream	54,881	52,195	43,488	157,156	120,849
Other businesses and corporate	378	326	425	989	1,243
	66,228	63,014	52,365	190,934	146,151

Less: sales and other operating revenues
between segments
Upstream	5,312	6,161	4,952	17,250	12,886
Downstream	765	208	175	887	768
Other businesses and corporate	133	134	191	405	496
	6,210	6,503	5,318	18,542	14,150

Third party sales and other operating revenues
Upstream	5,657	4,332	3,500	15,539	11,173
Downstream	54,116	51,987	43,313	156,269	120,081
Other businesses and corporate	245	192	234	584	747
Total sales and other operating revenues	60,018	56,511	47,047	172,392	132,001

By geographical area
US	21,853	21,577	18,853	64,582	50,130
Non-US	44,212	41,103	31,762	125,335	91,390
	66,065	62,680	50,615	189,917	141,520
Less: sales and other operating revenues
between areas	6,047	6,169	3,568	17,525	9,519
	60,018	56,511	47,047	172,392	132,001

Depreciation, depletion and amortization	Third	Second	Third	Nine	Nine
	quarter	quarter	quarter	months	months
$ million	2017	2017	2016	2017	2016
Upstream
US	1,154	1,133	1,027	3,524	3,180
Non-US	2,154	2,090	1,879	6,298	5,976
	3,308	3,223	2,906	9,822	9,156
Downstream
US	222	219	217	657	637
Non-US	287	274	275	840	821
	509	493	492	1,497	1,458
Other businesses and corporate
US	17	16	16	49	51
Non-US	70	61	82	171	198
	87	77	98	220	249
	3,904	3,793	3,496	11,539	10,863

Note 6. Production and similar taxes

	Third	Second	Third	Nine	Nine
	quarter	quarter	quarter	months	months
$ million	2017	2017	2016	2017	2016
US	(69)	41	32	8	117
Non-US	347	148	180	765	367
	278	189	212	773	484

Top of page 22

BP p.l.c. Group results

Third quarter and nine months 2017

Note 7. Earnings per share and shares in issue

Basic earnings per ordinary share (EpS) amounts are calculated by dividing the profit for the period attributable to ordinary shareholders by the weighted average number of ordinary shares outstanding during the period.

The calculation of EpS is performed separately for each discrete quarterly period, and for the year-to-date period. As a result, the sum of the discrete quarterly EpS amounts in any particular year-to-date period may not be equal to the EpS amount for the year-to-date period.

For the diluted EpS calculation the weighted average number of shares outstanding during the period is adjusted for the number of shares that are potentially issuable in connection with employee share-based payment plans using the treasury stock method.

	Third	Second	Third	Nine	Nine
	quarter	quarter	quarter	months	months
$ million	2017	2017	2016	2017	2016
Results for the period
Profit (loss) for the period attributable to
BP shareholders	1,769	144	1,620	3,362	(382)
Less: preference dividend	-	1	-	1	1
Profit (loss) attributable to BP ordinary
shareholders	1,769	143	1,620	3,361	(383)

Number of shares (thousand)(a)(b)
Basic weighted average number of
shares outstanding	19,756,117	19,686,613	18,824,739	19,654,608	18,660,397
ADS equivalent	3,292,686	3,281,102	3,137,456	3,275,768	3,110,066

Weighted average number of shares
outstanding used to calculate
diluted earnings per share	19,866,745	19,783,548	18,920,920	19,771,579	18,660,397
ADS equivalent	3,311,124	3,297,258	3,153,486	3,295,263	3,110,066

Shares in issue at period-end	19,797,657	19,738,566	18,912,989	19,797,657	18,912,989
ADS equivalent	3,299,609	3,289,761	3,152,164	3,299,609	3,152,164

(a)	Excludes treasury shares and includes certain shares that will be issued in the future under employee share-based payment plans.
(b)	If the inclusion of potentially issuable shares would decrease loss per share, the potentially issuable shares are excluded from the weighted average number of shares outstanding used to calculate diluted earnings per share.

Note 8. Dividends

Dividends payable

BP today announced an interim dividend of 10.00 cents per ordinary share which is expected to be paid on 21 December 2017 to shareholders and American Depositary Share (ADS) holders on the register on 10 November 2017. The corresponding amount in sterling is due to be announced on 11 December 2017, calculated based on the average of the market exchange rates for the four dealing days commencing on 5 December 2017. Holders of ADSs are expected to receive $0.600 per ADS (less applicable fees). 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.

	Third	Second	Third	Nine	Nine
	quarter	quarter	quarter	months	months
	2017	2017	2016	2017	2016
Dividends paid per ordinary share
cents	10.000	10.000	10.000	30.000	30.000
pence	7.621	7.756	7.558	23.536	21.487
Dividends paid per ADS (cents)	60.00	60.00	60.00	180.00	180.00
Scrip dividends
Number of shares issued (millions)	51.3	70.1	130.0	236.5	418.8
Value of shares issued ($ million)	298	420	714	1,360	2,148

Top of page 23

BP p.l.c. Group results

Third quarter and nine months 2017

Note 9. Net Debt*

Net debt ratio *	Third	Second	Third	Nine	Nine
	quarter	quarter	quarter	months	months
$ million	2017	2017	2016	2017	2016
Gross debt	65,784	63,004	58,997	65,784	58,997
Fair value (asset) liability of hedges related
to finance debt(a)	(227)	60	(1,113)	(227)	(1,113)
	65,557	63,064	57,884	65,557	57,884
Less: cash and cash equivalents	25,780	23,270	25,520	25,780	25,520
Net debt	39,777	39,794	32,364	39,777	32,364
Equity	100,138	98,461	92,797	100,138	92,797
Net debt ratio	28.4%	28.8%	25.9%	28.4%	25.9%

Analysis of changes in net debt	Third	Second	Third	Nine	Nine
	quarter	quarter	quarter	months	months
$ million	2017	2017	2016	2017	2016
Opening balance
Finance debt	63,004	61,832	55,727	58,300	53,168
Fair value (asset) liability of hedges related to
finance debt(a)	60	597	(1,279)	697	379
Less: cash and cash equivalents	23,270	23,794	23,517	23,484	26,389
Opening net debt	39,794	38,635	30,931	35,513	27,158
Closing balance
Finance debt	65,784	63,004	58,997	65,784	58,997
Fair value (asset) liability of hedges related to
finance debt(a)	(227)	60	(1,113)	(227)	(1,113)
Less: cash and cash equivalents	25,780	23,270	25,520	25,780	25,520
Closing net debt	39,777	39,794	32,364	39,777	32,364
Decrease (increase) in net debt	17	(1,159)	(1,433)	(4,264)	(5,206)
Movement in cash and cash equivalents
(excluding exchange adjustments)	2,364	(726)	1,990	1,781	(698)
Net cash outflow (inflow) from financing
(excluding share capital and dividends)	(1,962)	42	(3,338)	(5,031)	(4,097)
Other movements	(186)	(13)	29	(265)	424
Movement in net debt before exchange effects	216	(697)	(1,319)	(3,515)	(4,371)
Exchange adjustments	(199)	(462)	(114)	(749)	(835)
Decrease (increase) in net debt	17	(1,159)	(1,433)	(4,264)	(5,206)

(a)

Derivative financial instruments entered into for the purpose of managing interest rate and foreign currency exchange risk associated with net debt with a fair value liability position of $883 million (second quarter 2017 liability of $1,167 million and third quarter 2016 liability of $1,323 million) are not included in the calculation of net debt shown above as hedge accounting is not applied for these instruments.

Note 10. Inventory valuation

A provision of $501 million was held at 30 September 2017 ($635 million at 30 June 2017 and $509 million at 30 September 2016) to write inventories down to their net realizable value. The net movement credited to the income statement during the third quarter 2017 was $131 million (second quarter 2017 was a charge of $132 million and third quarter 2016 was a credit of $178 million).

Note 11. Statutory accounts

The financial information shown in this publication, which was approved by the Board of Directors on 30 October 2017, is unaudited and does not constitute statutory financial statements. Audited financial information will be published in BP Annual Report and Form 20-F 2017. BP Annual Report and Form 20-F 2016 has been filed with the Registrar of Companies in England and Wales. The report of the auditor on those accounts was unqualified and did not contain a statement under section 498(2) or section 498(3) of the UK Companies Act 2006.

Top of page 24

BP p.l.c. Group results

Third quarter and nine months 2017

Additional information

Capital expenditure*

	Third	Second	Third	Nine	Nine
	quarter	quarter	quarter	months	months
$ million	2017	2017	2016	2017	2016
Capital expenditure on a cash basis
Organic capital expenditure*	3,993	4,348	3,519	11,879	12,202
Inorganic capital expenditure*(a)	470	140	46	1,140	328
	4,463	4,488	3,565	13,019	12,530

	Third	Second	Third	Nine	Nine
	quarter	quarter	quarter	months	months
$ million	2017	2017	2016	2017	2016
Organic capital expenditure by segment
Upstream
US	827	805	618	2,273	2,813
Non-US	2,601	3,005	2,433	7,945	8,011
	3,428	3,810	3,051	10,218	10,824
Downstream
US	159	149	159	460	471
Non-US	356	316	272	992	798
	515	465	431	1,452	1,269
Other businesses and corporate
US	10	3	3	34	7
Non-US	40	70	34	175	102
	50	73	37	209	109
	3,993	4,348	3,519	11,879	12,202
Organic capital expenditure by geographical area
US	996	957	780	2,767	3,291
Non-US	2,997	3,391	2,739	9,112	8,911
	3,993	4,348	3,519	11,879	12,202

(a)	Third quarter and nine months 2017 include amounts paid to acquire interests in Mauritania and Senegal and other items. Nine months 2017 also includes amounts paid to purchase an interest in the Zohr gas field in Egypt and in exploration blocks in Senegal.

Top of page 25

BP p.l.c. Group results

Third quarter and nine months 2017

Non-operating items*

	Third	Second	Third	Nine	Nine
	quarter	quarter	quarter	months	months
$ million	2017	2017	2016	2017	2016
Upstream
Impairment and gain (loss) on sale of businesses
and fixed assets(a)	18	(18)	1,908	(382)	1,912
Environmental and other provisions	-	-	(8)	-	(8)
Restructuring, integration and rationalization costs	(3)	(19)	(36)	(20)	(302)
Fair value gain (loss) on embedded derivatives	1	5	8	31	49
Other(b)	(162)	11	(407)	(156)	(534)
	(146)	(21)	1,465	(527)	1,117
Downstream
Impairment and gain (loss) on sale of businesses
and fixed assets	(35)	156	(11)	110	333
Environmental and other provisions	-	-	(72)	-	(75)
Restructuring, integration and rationalization costs	(19)	(18)	(108)	(102)	(197)
Fair value gain (loss) on embedded derivatives	-	-	-	-	-
Other	(1)	-	(5)	(1)	(8)
	(55)	138	(196)	7	53
Rosneft
Impairment and gain (loss) on sale of businesses
and fixed assets	-	-	-	-	-
Environmental and other provisions	-	-	-	-	-
Restructuring, integration and rationalization costs	-	-	-	-	-
Fair value gain (loss) on embedded derivatives	-	-	-	-	-
Other	-	-	-	-	-
	-	-	-	-	-
Other businesses and corporate
Impairment and gain (loss) on sale of businesses
and fixed assets	1	8	(6)	(6)	(2)
Environmental and other provisions	-	(3)	(99)	(3)	(134)
Restructuring, integration and rationalization costs	(6)	(23)	(10)	(37)	(69)
Fair value gain (loss) on embedded derivatives	-	-	-	-	-
Gulf of Mexico oil spill(c)	(84)	(347)	(66)	(466)	(5,966)
Other	27	10	-	104	(55)
	(62)	(355)	(181)	(408)	(6,226)
Total before interest and taxation	(263)	(238)	1,088	(928)	(5,056)
Finance costs(c)	(122)	(121)	(123)	(369)	(369)
Total before taxation	(385)	(359)	965	(1,297)	(5,425)
Taxation credit (charge)	111	144	(16)	503	2,777
Total after taxation for period	(274)	(215)	949	(794)	(2,648)

(a)	Nine months 2017 relates primarily to an impairment charge arising following the announcement on 3 April 2017 of the agreement to sell the Forties Pipeline System business to INEOS.
(b)	Third quarter and nine months 2017 include the write-off of $145 million in relation to the value ascribed to certain licences in the deepwater Gulf of Mexico as part of the accounting for the acquisition of upstream assets from Devon Energy in 2011.
(c)	See Note 2 for further details regarding costs relating to the Gulf of Mexico oil spill.

Top of page 26

BP p.l.c. Group results

Third quarter and nine months 2017

Non-GAAP information on fair value accounting effects

	Third	Second	Third	Nine	Nine
	quarter	quarter	quarter	months	months
$ million	2017	2017	2016	2017	2016
Favourable (adverse) impact relative to
management's measure of performance
Upstream	(174)	106	(45)	178	(293)
Downstream	(108)	16	(257)	(52)	(547)
	(282)	122	(302)	126	(840)
Taxation credit (charge)	70	(38)	81	(47)	232
	(212)	84	(221)	79	(608)

BP uses derivative instruments to manage the economic exposure relating to inventories above normal operating requirements of crude oil, natural gas and petroleum products. Under IFRS, these inventories are recorded at historical cost. The related derivative instruments, however, are required to be recorded at fair value with gains and losses recognized in the income statement. This is because hedge accounting is either not permitted or not followed, principally due to the impracticality of effectiveness-testing requirements. Therefore, measurement differences in relation to recognition of gains and losses occur. Gains and losses on these inventories are not recognized until the commodity is sold in a subsequent accounting period. Gains and losses on the related derivative commodity contracts are recognized in the income statement, from the time the derivative commodity contract is entered into, on a fair value basis using forward prices consistent with the contract maturity.

BP enters into physical commodity contracts to meet certain business requirements, such as the purchase of crude for a refinery or the sale of BP's gas production. Under IFRS these physical contracts are treated as derivatives and are required to be fair valued when they are managed as part of a larger portfolio of similar transactions. In addition, derivative instruments are used to manage the price risk associated with certain future natural gas sales. Gains and losses arising are recognized in the income statement from the time the derivative commodity contract is entered into.

IFRS require that inventory held for trading is recorded at its fair value using period-end spot prices, whereas any related derivative commodity instruments are required to be recorded at values based on forward prices consistent with the contract maturity. Depending on market conditions, these forward prices can be either higher or lower than spot prices, resulting in measurement differences.

BP enters into contracts for pipelines and storage capacity, oil and gas processing and liquefied natural gas (LNG) that, under IFRS, are recorded on an accruals basis. These contracts are risk-managed using a variety of derivative instruments that are fair valued under IFRS. This results in measurement differences in relation to recognition of gains and losses.

The way that BP manages the economic exposures described above, and measures performance internally, differs from the way these activities are measured under IFRS. BP calculates this difference for consolidated entities by comparing the IFRS result with management's internal measure of performance. Under management's internal measure of performance the inventory and capacity contracts in question are valued based on fair value using relevant forward prices prevailing at the end of the period. The fair values of certain derivative instruments used to risk manage certain LNG and oil and gas contracts and gas sales contracts, are deferred to match with the underlying exposure and the commodity contracts for business requirements are accounted for on an accruals basis. We believe that disclosing management's estimate of this difference provides useful information for investors because it enables investors to see the economic effect of these activities as a whole. The impacts of fair value accounting effects, relative to management's internal measure of performance, are shown in the table above. A reconciliation to GAAP information is set out below.

	Third	Second	Third	Nine	Nine
	quarter	quarter	quarter	months	months
$ million	2017	2017	2016	2017	2016
Upstream
Replacement cost profit before interest and tax
adjusted for fair value accounting effects	1,416	689	1,241	3,115	175
Impact of fair value accounting effects	(174)	106	(45)	178	(293)
Replacement cost profit (loss) before
interest and tax	1,242	795	1,196	3,293	(118)
Downstream
Replacement cost profit before interest and tax
adjusted for fair value accounting effects	2,283	1,551	1,235	5,500	4,810
Impact of fair value accounting effects	(108)	16	(257)	(52)	(547)
Replacement cost profit before interest and tax	2,175	1,567	978	5,448	4,263
Total group
Profit (loss) before interest and tax adjusted for
fair value accounting effects	3,803	1,347	2,112	7,492	(691)
Impact of fair value accounting effects	(282)	122	(302)	126	(840)
Profit (loss) before interest and tax	3,521	1,469	1,810	7,618	(1,531)

Top of page 27

BP p.l.c. Group results

Third quarter and nine months 2017

Readily marketable inventory* (RMI)

	30 September	31 December
$ million	2017	2016
RMI at fair value	5,714	5,952
Paid-up RMI*	2,516	2,705

Readily marketable inventory (RMI) is oil and oil products inventory held and price risk-managed by BP's integrated supply and trading function (IST) which could be sold to generate funds if required. Paid-up RMI is RMI that BP has paid for.

We believe that disclosing the amounts of RMI and paid-up RMI is useful to investors as it enables them to better understand and evaluate the group's inventories and liquidity position by enabling them to see the level of discretionary inventory held by IST and to see builds or releases of liquid trading inventory.

See the Glossary on page 29 for a more detailed definition of RMI. RMI, RMI at fair value and paid-up RMI are non-GAAP measures. A reconciliation of total inventory as reported on the group balance sheet to paid-up RMI is provided below.

	30 September	31 December
$ million	2017	2016
Reconciliation of total inventory to paid-up RMI
Inventories as reported on the group balance sheet	18,078	17,655
Less: (a) inventories which are not oil and oil products and (b) oil and oil
product inventories which are not risk-managed by IST	(12,787)	(12,131)
RMI on an IFRS basis	5,291	5,524
Plus: difference between RMI at fair value and RMI on an IFRS basis	423	428
RMI at fair value	5,714	5,952
Less: unpaid RMI* at fair value	(3,198)	(3,247)
Paid-up RMI	2,516	2,705

Top of page 28

BP p.l.c. Group results

Third quarter and nine months 2017

Realizations* and marker prices

	Third	Second	Third	Nine	Nine
	quarter	quarter	quarter	months	months
	2017	2017	2016	2017	2016
Average realizations(a)
Liquids* ($/bbl)
US	43.58	44.65	39.16	44.87	34.20
Europe	50.02	47.79	42.87	50.32	39.18
Rest of World(b)	49.54	47.11	41.92	49.49	37.54
BP Average(b)	47.45	46.27	40.99	47.87	36.50
Natural gas ($/mcf)
US	2.34	2.32	2.19	2.39	1.77
Europe	5.10	4.48	3.94	4.98	4.28
Rest of World	3.03	3.47	2.98	3.42	3.14
BP Average	2.89	3.19	2.77	3.18	2.76
Total hydrocarbons* ($/boe)
US	31.30	32.46	27.71	32.68	24.15
Europe	45.26	41.10	37.10	44.33	35.19
Rest of World(b)	33.13	33.48	29.24	34.76	27.85
BP Average(b)	33.23	33.59	29.37	34.63	27.20
Average oil marker prices ($/bbl)
Brent	52.08	49.64	45.86	51.84	41.88
West Texas Intermediate	48.18	48.11	44.88	49.32	41.41
Western Canadian Select	38.16	38.55	31.60	38.49	29.26
Alaska North Slope	52.04	50.61	44.65	52.15	41.58
Mars	48.46	46.92	41.83	48.31	38.14
Urals (NWE - cif)	50.73	48.48	43.73	50.39	39.67
Average natural gas marker prices
Henry Hub gas price(c) ($/mmBtu)	2.99	3.19	2.81	3.17	2.28
UK Gas - National Balancing Point (p/therm)	41.59	37.83	31.00	42.61	30.93

(a)	Based on sales of consolidated subsidiaries only - this excludes equity-accounted entities.
(b)	Production volume recognition methodology for our Technical Service Contract arrangement in Iraq has been simplified to exclude the impact of oil price movements on lifting imbalances. A minor adjustment has been made to third quarter and nine months 2016. There is no impact on the financial results.
(c)	Henry Hub First of Month Index.

Exchange rates

	Third	Second	Third	Nine	Nine
	quarter	quarter	quarter	months	months
	2017	2017	2016	2017	2016
$/£ average rate for the period	1.31	1.28	1.31	1.28	1.39
$/£ period-end rate	1.34	1.30	1.30	1.34	1.30

$/€ average rate for the period	1.17	1.10	1.12	1.11	1.12
$/€ period-end rate	1.18	1.14	1.12	1.18	1.12

Rouble/$ average rate for the period	58.99	57.24	64.60	58.33	68.37
Rouble/$ period-end rate	57.94	59.05	63.14	57.94	63.14

Top of page 29

BP p.l.c. Group results

Third quarter and nine months 2017

Glossary

Non-GAAP measures are provided for investors because they are closely tracked by management to evaluate BP's operating performance and to make financial, strategic and operating decisions.

Adjusted effective tax rate (ETR) is a non-GAAP measure. The adjusted ETR is calculated by dividing taxation on an underlying RC basis by underlying RC profit or loss before tax. Taxation on an underlying RC basis is taxation on a RC basis for the period adjusted for taxation on non-operating items and fair value accounting effects. For the 2016 calculation, taxation on an underlying RC basis also reflects an adjustment to eliminate a $434-million credit that arises from the reduction in the rate of the North Sea supplementary charge in the third quarter of 2016. Information on underlying RC profit or loss is provided below. BP believes it is helpful to disclose the adjusted ETR because this measure 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. The nearest equivalent measure on an IFRS basis is the ETR on profit or loss for the period.

Capital expenditure is total cash capital expenditure as stated in the condensed group cash flow statement.

Consolidation adjustment - UPII is unrealized profit in inventory arising on inter-segment transactions.

Divestment proceeds are disposal proceeds as per the condensed group cash flow statement.

Effective tax rate (ETR) on replacement cost (RC) profit or loss is a non-GAAP measure. The ETR on RC profit or loss is calculated by dividing taxation on a RC basis by RC profit or loss before tax. Information on RC profit or loss is provided below. BP believes it is helpful to disclose the ETR on RC profit or loss because this measure excludes the impact of price changes on the replacement of inventories and allows for more meaningful comparisons between reporting periods. The nearest equivalent measure on an IFRS basis is the ETR on profit or loss for the period.

Fair value accounting effects are non-GAAP adjustments to our IFRS profit (loss) relating to certain physical inventories, pipelines and storage capacity. Management uses a fair-value basis to value these items which, under IFRS, are accounted for on an accruals basis with the exception of trading inventories, which are valued using spot prices. The adjustments have the effect of aligning the valuation basis of the physical positions with that of any associated derivative instruments, which are required to be fair valued under IFRS, in order to provide a more representative view of the ultimate economic value. Further information is provided on page 26.

Free cash flow is operating cash flow less net cash used in investing activities, as presented in the condensed group cash flow statement.

Full dividend is cash dividend plus cash equivalent value of scrip dividend. See page 22 for more information.

Gearing - See Net debt and net debt ratio definition.

Hydrocarbons - Liquids and natural gas. Natural gas is converted to oil equivalent at 5.8 billion cubic feet = 1 million barrels.

Inorganic capital expenditure is a subset of capital expenditure and is a non-GAAP measure. Inorganic capital expenditure comprises consideration in business combinations and certain other significant investments made by the group. It is reported on a cash basis. BP believes that this measure provides useful information as it allows investors to understand how BP's management invests funds in projects which expand the group's activities through acquisition. Further information and a reconciliation to GAAP information is provided on page 24.

Inventory holding gains and losses represent the difference between the cost of sales calculated using the replacement cost of inventory and the cost of sales calculated on the first-in first-out (FIFO) method after adjusting for any changes in provisions where the net realizable value of the inventory is lower than its cost. Under the FIFO method, which we use for IFRS reporting, the cost of inventory charged to the income statement is based on its historical cost of purchase or manufacture, rather than its replacement cost. In volatile energy markets, this can have a significant distorting effect on reported income. The amounts disclosed represent the difference between the charge to the income statement for inventory on a FIFO basis (after adjusting for any related movements in net realizable value provisions) and the charge that would have arisen based on the replacement cost of inventory. For this purpose, the replacement cost of inventory is calculated using data from each operation's production and manufacturing system, either on a monthly basis, or separately for each transaction where the system allows this approach. The amounts disclosed are not separately reflected in the financial statements as a gain or loss. No adjustment is made in respect of the cost of inventories held as part of a trading position and certain other temporary inventory positions. See Replacement cost (RC) profit or loss definition below.

Liquids - Liquids for Upstream and Rosneft comprises crude oil, condensate and natural gas liquids. For Upstream, liquids also includes bitumen.

Major projects have a BP net investment of at least $250 million, or are considered to be of strategic importance to BP or of a high degree of complexity.

Net debt and net debt ratio are non-GAAP measures. Net debt is calculated as gross finance debt, as shown in the balance sheet, plus the fair value of associated derivative financial instruments that are used to hedge foreign currency exchange and interest rate risks relating to finance debt, for which hedge accounting is applied, less cash and cash

Top of page 30

BP p.l.c. Group results

Third quarter and nine months 2017

Glossary (continued)

equivalents. The net debt ratio is defined as the ratio of net debt to the total of net debt plus shareholders' equity. All components of equity are included in the denominator of the calculation. BP believes these measures 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. The derivatives are reported on the balance sheet within the headings 'Derivative financial instruments'.

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.

Non-operating items are charges and credits included in the financial statements that BP discloses separately because it considers such disclosures to be meaningful and relevant to investors. They are items that management considers not to be part of underlying business operations and are disclosed in order to enable investors better to understand and evaluate the group's reported financial performance. Non-operating items within equity-accounted earnings are reported net of incremental income tax reported by the equity-accounted entity. An analysis of non-operating items by region is shown on pages 7, 9 and 11, and by segment and type is shown on page 25.

Operating cash flow is net cash provided by (used in) operating activities as stated in the condensed group cash flow statement. When used in the context of a segment rather than the group, the terms refer to the segment's share thereof.

Operating cash flow excluding amounts related to the Gulf of Mexico oil spill / Gulf of Mexico oil spill payments or Underlying operating cash flow is a non-GAAP measure calculated by excluding post-tax operating cash flows relating to the Gulf of Mexico oil spill as reported in Note 2 from Net cash provided by operating activities as reported in the condensed group cash flow statement. BP believes it is helpful to disclose net cash provided by operating activities excluding amounts related to the Gulf of Mexico oil spill because this measure allows for more meaningful comparisons between reporting periods. The nearest equivalent measure on an IFRS basis is Net cash provided by operating activities.

Organic capital expenditure is a subset of capital expenditure and is a non-GAAP measure. Organic capital expenditure comprises capital expenditure less inorganic capital expenditure. BP believes that this measure provides useful information as it allows investors to understand how BP's management invests funds in developing and maintaining the group's assets. An analysis of organic capital expenditure by segment and region, and a reconciliation to GAAP information is provided on page 24.

Organic balance and organic cash balance are non-GAAP terms that refer to the point BP's organic sources of cash equal organic uses of cash. Organic sources of cash is the sum of operating cash flow, excluding amounts related to the Gulf of Mexico oil spill, and proceeds of loan repayments. Organic uses of cash is organic capital expenditure plus dividends. BP believes that the organic balance point is useful for investors because it is closely tracked by management to evaluate BP's financial 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 nearest equivalent measure on an IFRS basis for organic sources of cash is net cash provided by operating activities and the nearest equivalent measures on an IFRS basis for organic uses of cash are total cash capital expenditure and dividends paid - BP shareholders.

Brent oil prices of $49/bbl and $42/bbl are indicative estimates of the oil price at which organic sources and uses of cash balance and are based on an internal rule of thumb for the post-tax impact on annual operating cash flow for every $1/bbl change in the Brent price. Such a rule of thumb is by its nature approximate and only provides a broad directional indicator of the impact of a change in the oil price on operating cash flows. The relationship between oil prices and cash flows is not necessarily linear across a wide range of oil prices. Significant differences between the estimates implied by the application of the rule of thumb and the actual cash flows may arise due to complex mechanisms for calculating government shares of Upstream revenues in some jurisdictions, depending on price levels, and other factors. Actual results may differ significantly from the estimates implied by the application of this rule of thumb.

Production-sharing agreement (PSA) is an arrangement through which an oil company bears the risks and costs of exploration, development and production. In return, if exploration is successful, the oil company receives entitlement to variable physical volumes of hydrocarbons, representing recovery of the costs incurred and a stipulated share of the production remaining after such cost recovery.

Readily marketable inventory (RMI) is inventory held and price risk-managed by our integrated supply and trading function (IST) which could be sold to generate funds if required. It comprises oil and oil products for which liquid markets are available and excludes inventory which is required to meet operational requirements and other inventory which is not price risk-managed. RMI is reported at fair value. Inventory held by the Downstream fuels business for the purpose of sales and marketing, and all inventories relating to the lubricants and petrochemicals businesses, are not included in RMI.

Paid-up RMI excludes RMI which has not yet been paid for. For inventory that is held in storage, a first-in first-out (FIFO) approach is used to determine whether inventory has been paid for or not. Unpaid RMI is RMI which has not yet been paid for by BP. RMI, Paid-up RMI and Unpaid RMI are non-GAAP measures. Further information is provided on page 27.

Realizations are the result of dividing revenue generated from hydrocarbon sales, excluding revenue generated from purchases made for resale and royalty volumes, by revenue generating hydrocarbon production volumes. Revenue generating hydrocarbon production reflects the BP share of production as adjusted for any production which does not generate revenue. Adjustments may include losses due to shrinkage, amounts consumed during processing, and contractual or regulatory host committed volumes such as royalties.

Top of page 31

BP p.l.c. Group results

Third quarter and nine months 2017

Glossary (continued)

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 downtime.

The Refining marker margin (RMM) is the average of regional indicator margins weighted for BP's crude refining capacity in each region. Each regional marker margin is based on product yields and a marker crude oil deemed appropriate for the region. 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.

Replacement cost (RC) profit or loss reflects the replacement cost of inventories sold in the period 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 that is required to be disclosed for each operating segment under IFRS. RC profit or loss for the group is not a recognized GAAP measure. BP believes this measure is useful to illustrate to investors the fact that crude oil and product prices can vary significantly from period to period and that the impact on our reported result under IFRS can be significant. Inventory holding gains and losses vary from period to period due to changes in prices as well as changes in underlying inventory levels. In order for investors to understand the operating performance of the group excluding the impact of price changes on the replacement of inventories, and to make comparisons of operating performance between reporting periods, BP's management believes it is helpful to disclose this measure. The nearest equivalent measure on an IFRS basis is profit or loss attributable to BP shareholders.

RC profit or loss per share is a non-GAAP measure. Earnings per share is defined in Note 7. RC profit or loss per share is calculated using the same denominator. The numerator used is RC profit or loss attributable to BP shareholders rather than profit or loss attributable to BP shareholders. BP believes it is helpful to disclose the RC profit or loss per share because this measure excludes the impact of price changes on the replacement of inventories and allows for more meaningful comparisons between reporting periods. The nearest equivalent measure on an IFRS basis is basic earnings per share based on profit or loss for the period attributable to BP shareholders.

Reported recordable injury frequency measures the number of reported work-related employee and contractor incidents that result in a fatality or injury per 200,000 hours worked. This represents reported incidents occurring within BP's operational HSSE reporting boundary. That boundary includes BP's own operated facilities and certain other locations or situations.

Tier 1 process safety events are losses of primary containment from a process of greatest consequence - causing harm to a member of the workforce, costly damage to equipment or exceeding defined quantities. This represents reported incidents occurring within BP's operational HSSE reporting boundary. That boundary includes BP's own operated facilities and certain other locations or situations.

Underlying production is production after adjusting for divestments and entitlement impacts in our production-sharing agreements. 2017 underlying production does not include the Abu Dhabi onshore concession renewal.

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 adjustments for fair value accounting effects are not recognized GAAP measures. See pages 25 and 26 for 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. The nearest equivalent measure on an IFRS basis for the group is profit or loss attributable to BP shareholders. The nearest equivalent measure on an IFRS basis for segments is RC profit or loss before interest and taxation.

Underlying RC profit or loss per share is a non-GAAP measure. Earnings per share is defined in Note 7. Underlying RC profit or loss per share is calculated using the same denominator. The numerator used is underlying RC profit or loss attributable to BP shareholders rather than profit or loss attributable to BP shareholders. BP believes it is helpful to disclose the underlying RC profit or loss per share because this measure 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. The nearest equivalent measure on an IFRS basis is basic earnings per share based on profit or loss for the period attributable to BP shareholders.

Upstream operating efficiency is calculated as production for BP operated sites, excluding US Lower 48 and adjusted for certain items including entitlement impacts in our production-sharing agreements divided by installed production capacity for BP operated sites, excluding US Lower 48. Installed production capacity is the agreed rate achievable (measured at the export end of the system) when the installed production system (reservoir, wells, plant and export) is fully optimized and operated at full rate with no planned or unplanned deferrals.

Upstream unit production cost is calculated as production cost divided by units of production. Production cost does not include ad valorem and severance taxes. Units of production are barrels for liquids and thousands of cubic feet for gas. Amounts disclosed are for BP subsidiaries only and do not include BP's share of equity-accounted entities.

Top of page 32

BP p.l.c. Group results

Third quarter and nine months 2017

Legal proceedings

The following discussion sets out the material developments in the group's material legal proceedings during the recent period. For a full discussion of the group's material legal proceedings, see pages 261-265 of BP Annual Report and Form 20-F 2016, and page 35 of BP p.l.c. Group results second quarter and half year 2017.

Matters relating to the Deepwater Horizon accident and oil spill (the Incident)

Plaintiffs' Steering Committee (PSC) settlements - Economic and Property Damages Settlement Agreement The Economic and Property Damages Settlement established a court-supervised settlement claims programme to resolve certain economic and property damage claims arising from the Incident.

Following numerous court decisions, on 31 March 2015, the United States district court in New Orleans denied the PSC motion seeking to alter or amend a revised policy relating to business economic loss claims. Such policy required the matching of revenue with the expenses incurred by claimants to generate that revenue, even where the revenue and expenses were recorded at different times. The PSC appealed the district court decision and, on 22 May 2017, the Fifth Circuit issued an opinion upholding the policy in part and reversing the policy in part. The Fifth Circuit ordered that the portion of the policy upheld, which covers the substantial majority of the remaining business economic loss claims, be applied as the governing methodology for all applicable business economic loss claims. BP filed a petition for a rehearing which was denied on 21 June 2017. On 25 May 2017, 13 June 2017, and 5 July 2017, the district court issued a series of orders instructing the court supervised settlement programme on how to implement the Fifth Circuit's opinion. On 10 August 2017, the district court denied BP's motion to clarify or reconsider these orders. BP appealed all of these orders and decisions on 8 September 2017; the appeals have been consolidated with four appeals filed by claimants in September 2017 challenging the same set of orders and decisions. These appeals are currently pending before the Fifth Circuit.

Cautionary statement

In order to utilize the 'safe harbor' provisions of the United States Private Securities Litigation Reform Act of 1995 (the 'PSLRA'), BP is providing the following cautionary statement: The discussion in this results announcement contains certain forecasts, projections and forward-looking statements - that is, statements related to future, not past events - with respect to the financial condition, results of operations and businesses of BP and certain of the plans and objectives of BP with respect to these items. These statements may generally, but not always, be identified by the use of words such as 'will', 'expects', 'is expected to', 'aims', 'should', 'may', 'objective', 'is likely to', 'intends', 'believes', 'anticipates', 'plans', 'we see' or similar expressions. In particular, the following, among other statements, are all forward looking in nature: plans for recommencing a share buyback programme; expectations regarding the expected quarterly dividend payment and timing of such payment; expectations regarding 2017 organic capital expenditure; plans and expectations to target gearing within a 20-30% band; expectations regarding divestment transactions and the amount and timing of divestment proceeds; expectations regarding the adjusted effective tax rate in 2017; plans and expectations regarding the formation of Pan American Energy Group; plans and expectations regarding the joint development and production-sharing agreement with the State Oil Company of the Republic of Azerbaijan; expectations regarding Aker BP ASA's agreement to acquire Hess Norge AS; expectations regarding BP's divestment of its shareholding in SECCO; expectations regarding Upstream fourth-quarter 2017 reported production; expectations regarding Downstream fourth-quarter 2017 refining margins and turnaround activity; plans and expectations with respect to the start-up and development of new Upstream projects; expectations regarding Rosneft interim dividends for 2017 and Rosneft operational and financial information for the third quarter of 2017; expectations regarding the determination of business economic loss claims in respect of the PSC settlement; expectations with respect to the timing and amount of future payments relating to the Gulf of Mexico oil spill; and expectations that claims arising under the 2012 PSC settlement will be substantially paid in 2018. 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 and are outside the control of BP. Actual results may differ materially from those expressed in such statements, depending on a variety of factors, including: the specific factors identified in the discussions accompanying such forward-looking statements; the receipt of relevant third party and/or regulatory approvals; the timing and level of maintenance and/or turnaround activity; the timing and volume of refinery additions and outages; the timing of bringing new fields onstream; the timing, quantum and nature of certain divestments; future levels of industry product supply, demand and pricing, including supply growth in North America; OPEC quota restrictions; PSA effects; operational and safety problems; potential lapses in product quality; economic and financial market conditions generally or in various countries and regions; 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 or imposed; the actions of prosecutors, regulatory authorities and courts; delays in the processes for resolving claims; exchange rate fluctuations; development and use of new technology; recruitment and retention of a skilled workforce; the success or otherwise of partnering; the actions of competitors, trading partners, contractors, subcontractors, creditors, rating agencies and others; our access to future credit resources; business disruption and crisis management; the impact on our reputation of ethical misconduct and non-compliance with regulatory obligations; trading losses; major uninsured losses; decisions by Rosneft's management and board of directors; the actions of contractors; natural disasters and adverse weather conditions; changes in public expectations and other changes to business conditions; wars and acts of terrorism; cyber-attacks or sabotage; and other factors discussed elsewhere in this report, under "Principal risks and uncertainties" in our Form 6-K for the period ended 30 June 2017 and under "Risk factors" in BP Annual Report and Form 20-F 2016 as filed with the US Securities and Exchange Commission.

Contacts
	London	Houston

Press Office	David Nicholas	Brett Clanton
	+44 (0)20 7496 4708	+1 281 366 8346

Investor Relations	Craig Marshall	Brian Sullivan
bp.com/investors	+44 (0)20 7496 5183	+1 281 892 3421
BP p.l.c.'s LEI Code 213800LH1BZH3D16G760

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

BP p.l.c.

(Registrant)

Dated: 31 October 2017

	BP p.l.c.
	(Registrant)


	/s/ D.J. JACKSON
	------------------------
	D.J. JACKSON
	Company Secretary