3Q18 Part 1 of 1

RNS Number : 5929F

BP PLC

30 October 2018

FOR IMMEDIATE RELEASE
London 30 October 2018

BP p.l.c. Group results
Third quarter and nine months 2018

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Highlights

Strong earnings driven by high reliability and major project delivery

• Strong earnings and cash flow:

- Underlying replacement cost profit for the third quarter of 2018 was $3.8 billion, more than double a year earlier and the highest quarterly result in more than five years, including significant earnings growth from the Upstream and Rosneft.

- Operating cash flow excluding Gulf of Mexico oil spill payments for the quarter was $6.6 billion, including a $0.7 billion working capital build (after adjusting for inventory holding gains).

- Gulf of Mexico oil spill payments in the quarter were $0.5 billion on a post-tax basis.

- Dividend of 10.25 cents a share for the third quarter, 2.5% higher than a year earlier.

• Strong operating performance:

- Very good reliability, with the highest quarterly refining availability for 15 years and BP-operated Upstream plant reliability of 95%.

- Reported oil and gas production was 3.6 million barrels of oil equivalent a day. Upstream underlying production, which excludes Rosneft and is adjusted for portfolio changes and pricing effects, was 6.8% higher than a year earlier, driven by ramp-up of new projects. Rosneft production of 1.2 million barrels of oil equivalent a day was 2.8% higher than last year.

• Strategic delivery:

- The Thunder Horse Northwest expansion project in the Gulf of Mexico and the Western Flank B project in Australia began production in October, both ahead of schedule. They are BP's fourth and fifth Upstream major projects to start up in 2018.

- Further expansion in fuels marketing, with now around 1,300 convenience partnership sites worldwide and network growth in Mexico.

• BHP transaction:

- The acquisition from BHP is expected to complete on 31 October.

- Reflecting confidence in cash generation and continued capital discipline, and assuming oil prices remain firm in the recent trading range, BP now expects to fund the entire transaction from available cash, rather than using equity for the deferred consideration. In this case, proceeds from the associated $5-6 billion of divestments will be used to reduce net debt.

See chart on PDF

Bob Dudley - Group chief executive:

Our focus on safe and reliable operations and delivering our strategy is driving strong earnings and growing cash flow. Operations are running well across BP and we're bringing new, higher-margin barrels into production faster through efficient project execution. We have made very good progress with our acquisition from BHP and expect to complete the transaction tomorrow. This will transform our position in the US Lower 48 and we expect it to create significant value for BP. This progress all underpins our commitment to growing distributions for our shareholders.

Financial summary	Third		Second		Third		Nine		Nine
	quarter		quarter		quarter		months		months
$ million	2018		2018		2017		2018		2017
Profit for the period_(a)	3,349		2,799		1,769		8,617		3,362
Inventory holding (gains) losses, net of tax	(258	)	(1,010	)	(390	)	(1,348	)	(18	)
RC profit	3,091		1,789		1,379		7,269		3,344
Net (favourable) adverse impact of non-operating items and fair value accounting effects, net of tax	747		1,033		486		1,977		715
Underlying RC profit	3,838		2,822		1,865		9,246		4,059
RC profit per ordinary share (cents)	15.45		8.96		6.98		36.42		17.01
RC profit per ADS (dollars)	0.93		0.54		0.42		2.19		1.02
Underlying RC profit per ordinary share (cents)	19.18		14.14		9.44		46.32		20.65
Underlying RC profit per ADS (dollars)	1.15		0.85		0.57		2.78		1.24

(a) Profit attributable to BP shareholders.

RC profit (loss), underlying RC profit, operating cash flow excluding Gulf of Mexico oil spill payments and working capital are non-GAAP measures. These measures and Upstream plant reliability, refining availability, major projects, inventory holding gains and losses, non-operating items, fair value accounting effects and underlying production are defined in the Glossary on page 31.

The commentary above and following should be read in conjunction with the cautionary statement on page 35.

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Group headlines

Results

For the nine months, underlying replacement cost (RC) profit* was $9,246 million, compared with $4,059 million in 2017. Underlying RC profit is after adjusting RC profit* for a net charge for non-operating items* of $1,619 million and net adverse fair value accounting effects* of $358 million (both on a post-tax basis). RC profit was $7,269 million for the nine months, compared with $3,344 million a year ago.

For the third quarter, underlying RC profit was $3,838 million, compared with $1,865 million in 2017. Underlying RC profit is after adjusting RC profit for a net charge for non-operating items of $649 million and net adverse fair value accounting effects of $98 million (both on a post-tax basis). RC profit was $3,091 million for the third quarter, compared with $1,379 million in 2017.

BP's profit for the third quarter and nine months was $3,349 million and $8,617 million respectively, compared with $1,769 million and $3,362 million for the same periods in 2017.

See further information on pages 3, 27 and 28.

Non-operating items

Non-operating items amounted to a post-tax charge of $649 million for the quarter and $1,619 million for the nine months. The charge for the quarter includes post-tax amounts relating to the Gulf of Mexico oil spill of $54 million for business economic loss claims and $30 million for other claims and litigation relating to the spill, as well as finance costs in respect of the unwinding of discounting effects relating to oil spill payables. See further information on page 27.

Effective tax rate

The effective tax rate (ETR) on RC profit or loss* for the third quarter and nine months was 38% and 41% respectively, compared with 43% for both periods in 2017. Adjusting for non-operating items and fair value accounting effects, the underlying ETR* for the third quarter and nine months was 36% and 38% respectively, compared with 40% and 42% for the same periods in 2017. The lower underlying ETR for the third quarter reflected lower adjustments in respect of prior years and re-evaluation of deferred tax positions, partly offset by deferred tax charges due to foreign exchange impacts. The lower underlying ETR for the nine months reflected lower exploration write-offs, partly offset by deferred tax charges due to foreign exchange impacts. In the current environment we now expect the underlying ETR for 2018 to be lower than 40%. ETR on RC profit or loss and underlying ETR are non-GAAP measures.

Dividend

BP today announced a quarterly dividend of 10.25 cents per ordinary share ($0.615 per ADS), which is expected to be paid on 21 December 2018. The corresponding amount in sterling will be announced on 10 December 2018. See page 24 for further information.

Share buybacks

BP repurchased 19 million ordinary shares at a cost of $139 million, including fees and stamp duty, during the third quarter of 2018. For the nine months, BP repurchased 48 million ordinary shares at a cost of $339 million, including fees and stamp duty.

Operating cash flow*

Excluding post-tax amounts related to the Gulf of Mexico oil spill, operating cash flow* for the third quarter was $6.6 billion, including a $0.7 billion working capital* build (after adjusting for inventory holding gains*) and $19.0 billion in the nine months, including a $1.1 billion working capital build (after adjusting for inventory holding gains), compared with $6.6 billion and $17.9 billion for the same periods in 2017. Including amounts relating to the Gulf of Mexico oil spill, operating cash flow for the third quarter and nine months was $6.1 billion and $16.0 billion respectively (after a $1.6 billion working capital build for the quarter and $5.5 billion for the nine months), compared with $6.0 billion and $13.0 billion for the same periods in 2017. See also the Glossary on page 31 for further information on working capital.

Capital expenditure*

Organic capital expenditure* for the third quarter and nine months was $3.7 billion and $10.7 billion respectively, compared with $4.0 billion and $11.9 billion for the same periods in 2017.

Inorganic capital expenditure* for the third quarter and nine months was $0.7 billion and $1.5 billion respectively, compared with $0.5 billion and $1.1 billion for the same periods in 2017.

Organic capital expenditure and inorganic capital expenditure are non-GAAP measures. See page 26 for further information.

Divestment and other proceeds

Divestment proceeds* were $0.1 billion for the third quarter and $0.4 billion for the nine months, compared with $0.2 billion and $1.0 billion for the same periods in 2017.

Gearing*

Net debt* at 30 September 2018 was $39.2 billion, compared with $39.8 billion a year ago. Gearing at 30 September 2018 was 27.5%, compared with 28.4% a year ago.

We expect gearing to remain within the target band of 20-30% during the fourth quarter of 2018. As described above, assuming oil prices remain firm, we expect to fund the deferred consideration related to the BHP transaction with available cash rather than issuing equity. As a result, gearing may move temporarily above the top end of the band in early 2019, but is expected to move back down towards the middle of the band by the end of 2019, in line with the generation of free cash flow and receipt of disposal proceeds.

Net debt and gearing are non-GAAP measures. See page 24 for more information.

Brian Gilvary - Chief financial officer:

This quarter's underlying result was significantly higher than the second quarter in a very similar price environment. Since we announced the BHP transaction, oil prices have firmed to levels significantly above the acquisition assumptions. While oil prices remain at these levels, we expect to finance the transaction fully using cash. In this event, the $5-6 billion divestment programme linked to the transaction will be used to reduce debt. We will also continue our share buyback programme to offset dilution from the scrip dividend.

* For items marked with an asterisk throughout this document, definitions are provided in the Glossary on page 31.

The commentary above contains forward-looking statements and should be read in conjunction with the cautionary statement on page 35.

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Analysis of underlying RC profit* before interest and tax

	Third		Second		Third		Nine		Nine
	quarter		quarter		quarter		months		months
$ million	2018		2018		2017		2018		2017
Underlying RC profit before interest and tax
Upstream	3,999		3,508		1,562		10,664		3,642
Downstream	2,111		1,455		2,338		5,392		5,493
Rosneft	872		766		137		1,885		515
Other businesses and corporate	(345	)	(477	)	(398	)	(1,214	)	(1,204	)
Consolidation adjustment - UPII*	78		151		(130	)	69		(63	)
Underlying RC profit before interest and tax	6,715		5,403		3,509		16,796		8,383
Finance costs and net finance expense relating to pensions and other post-retirement benefits	(610	)	(448	)	(444	)	(1,522	)	(1,251	)
Taxation on an underlying RC basis	(2,213	)	(2,059	)	(1,212	)	(5,838	)	(3,030	)
Non-controlling interests	(54	)	(74	)	12		(190	)	(43	)
Underlying RC profit attributable to BP shareholders	3,838		2,822		1,865		9,246		4,059

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	2018		2018		2017		2018		2017
RC profit (loss) before interest and tax
Upstream	3,472		3,514		1,242		10,160		3,293
Downstream	2,249		840		2,175		4,802		5,448
Rosneft	808		766		137		1,821		515
Other businesses and corporate_(a)	(815	)	(1,025	)	(460	)	(2,411	)	(1,612	)
Consolidation adjustment - UPII	78		151		(130	)	69		(63	)
RC profit (loss) before interest and tax	5,792		4,246		2,964		14,441		7,581
Finance costs and net finance expense relating to pensions and other post-retirement benefits	(729	)	(566	)	(566	)	(1,879	)	(1,620	)
Taxation on a RC basis	(1,918	)	(1,817	)	(1,031	)	(5,103	)	(2,574	)
Non-controlling interests	(54	)	(74	)	12		(190	)	(43	)
RC profit (loss) attributable to BP shareholders	3,091		1,789		1,379		7,269		3,344
Inventory holding gains (losses)*	371		1,310		557		1,773		37
Taxation (charge) credit on inventory holding gains and losses	(113	)	(300	)	(167	)	(425	)	(19	)
Profit (loss) for the period attributable to BP shareholders	3,349		2,799		1,769		8,617		3,362

(a) Includes costs related to the Gulf of Mexico oil spill. See page 11 and also Note 2 from page 19 for further information on the accounting for the Gulf of Mexico oil spill.

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Strategic progress

Upstream

Upstream production, which excludes Rosneft, was 2,460mboe/d for the third quarter, flat with last year. Adjusted for portfolio and PSA* impacts, underlying production* was 6.8% higher, driven by continued ramp-up of production from major projects*. Upstream unit production costs* were higher year-to-date due to increased wellwork* activity and the impact of higher prices on production entitlements.

Five Upstream major projects have been delivered to date in 2018. The Thunder Horse Northwest expansion in the Gulf of Mexico and Western Flank B in Australia started up in October, both ahead of schedule. Shah Deniz 2 in Azerbaijan, Taas-Yuryakh expansion in Russia, and Atoll in Egypt, started up during the first half of the year.

In September, BP accessed new acreage in the prolific Santos basin, offshore Brazil, by winning the licence for the Pau Brasil block. This represents BP's first operated position in the Santos basin.

The acquisition of the significant portfolio of onshore US oil and gas assets from BHP, announced in July, is expected to complete by end of October.

Downstream

In manufacturing, refining and petrochemicals operations have both been strong in the quarter. Refining availability was 96.3%, the highest in 15 years.

In marketing, BP's convenience partnership model has now been rolled out to around 1,300 sites across our network worldwide, and more than 370 BP-branded retail sites are now open in Mexico.

Advancing the energy transition

BP completed the acquisition of Chargemaster, the UK's largest electric vehicle charging company, in the quarter.

Air BP entered into an agreement with Neste to explore opportunities to increase the supply and availability of sustainable aviation fuel.

In the quarter Lightsource BP agreed to form a joint venture to fund, develop and operate solar projects in Egypt and also announced an expansion of its position in the US, acquiring a portfolio of solar projects in Pennsylvania.

Financial framework

Operating cash flow excluding Gulf of Mexico oil spill payments* was $6.6 billion in the quarter and $19.0 billion in the nine months. These compare with $6.6 billion for the third quarter of 2017 and $17.9 billion for the nine months of 2017.

Organic capital expenditure* of $3.7 billion in the quarter brought the total for the nine months of 2018 to $10.7 billion. BP expects 2018 organic capital expenditure to be around $15 billion.

Divestments and other proceeds totalled $0.4 billion for the nine months. 2018 total proceeds are expected to be over $3 billion.

Gulf of Mexico oil spill payments on a post-tax basis totalled $2.9 billion in the nine months of 2018. Payments for the full year are expected to be just over $3 billion on a post-tax basis.

Gearing* at the end of the quarter was 27.5%, within BP's target band of 20-30%. Gearing is expected to remain within the target band during the fourth quarter of 2018.

Operating metrics	Nine months 2018	Financial metrics	Nine months 2018
Operating metrics	(vs. Nine months 2017)	Financial metrics	(vs. Nine months 2017)
Tier 1 process safety events*	13	Underlying RC profit*	$9.2bn
Tier 1 process safety events*	(+1)	Underlying RC profit*	(+$5.2bn)
Reported recordable injury frequency*	0.21	Operating cash flow excluding Gulf of Mexico oil spill payments (post-tax)	$19.0bn
Reported recordable injury frequency*	(-4%)		(+$1.1bn)
Group production	3,645mboe/d	Organic capital expenditure	$10.7bn
Group production	(+2.5%)	Organic capital expenditure	(-$1.1bn)
Upstream production (excludes Rosneft segment)	2,510mboe/d	Gulf of Mexico oil spill payments (post-tax)	$2.9bn
Upstream production (excludes Rosneft segment)	(+3.4%)	Gulf of Mexico oil spill payments (post-tax)	(-$1.9bn)
Upstream unit production costs	$7.27/boe	Divestment proceeds*	$0.4bn
Upstream unit production costs	(+1.5%)	Divestment proceeds*	(-$0.5bn)
BP-operated Upstream plant reliability*_(a)	95.6%	Net debt ratio* (gearing)	27.5%
BP-operated Upstream plant reliability*_(a)	(+1.0)	Net debt ratio* (gearing)	(-0.9)
Refining availability*	94.8%	Dividend per ordinary share_(b)	10.25 cents
Refining availability*	(-0.2)	Dividend per ordinary share_(b)	(+2.5%)

(a) BP-operated Upstream operating efficiency* has been replaced with Upstream plant reliability as a group operating metric in the first quarter 2018. It is more comparable with the equivalent metric disclosed for the Downstream, which is 'Refining availability'.

(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 35.

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Upstream

	Third		Second		Third		Nine		Nine
	quarter		quarter		quarter		months		months
$ million	2018		2018		2017		2018		2017
Profit before interest and tax	3,473		3,518		1,255		10,166		3,301
Inventory holding (gains) losses*	(1	)	(4	)	(13	)	(6	)	(8	)
RC profit before interest and tax	3,472		3,514		1,242		10,160		3,293
Net (favourable) adverse impact of non-operating items* and fair value accounting effects*	527		(6	)	320		504		349
Underlying RC profit before interest and tax*_(a)	3,999		3,508		1,562		10,664		3,642

(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 $3,472 million and $10,160 million respectively, compared with $1,242 million and $3,293 million for the same periods in 2017. The third quarter and nine months included a net non-operating charge of $242 million and $319 million respectively, compared with a net charge of $146 million and $527 million for the same periods in 2017. Fair value accounting effects in the third quarter and nine months had an adverse impact of $285 million and $185 million respectively, compared with an adverse impact of $174 million and a favourable impact of $178 million in the same periods of 2017.

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 $3,999 million and $10,664 million respectively, compared with $1,562 million and $3,642 million for the same periods in 2017. The result for the third quarter mainly reflected higher liquids and gas realizations and higher production from the ramp-up of major projects*, partially offset by higher exploration write-offs. The result for the nine months mainly reflected higher liquids and gas realizations, higher production from the ramp-up of major projects and lower exploration write-offs.

Production

Production for the quarter was 2,460mboe/d, flat with the third quarter of 2017. Underlying production* for the quarter increased by 6.8%, due to the ramp-up of major projects.

For the nine months, production was 2,510mboe/d, 3.4% higher than 2017. Underlying production for the nine months was 10.0% higher than 2017 due to the ramp-up of major projects.

Key events

On 28 September, BP won the licence for the Pau Brasil block located in the Santos basin, offshore Brazil, in the fifth Pre-Salt Production Sharing Contract Bid Round (BP operator 50%, CNOOC 30% and Ecopetrol 20%). BP will now have an operated position in the Santos basin for the first time.

On 1 October, EnQuest notified BP of the exercise of its option to acquire the remaining 75% of BP's stake in the Magnus field and associated infrastructure. EnQuest acquired 25% of BP's interest in Magnus field and associated infrastructure on 1 December 2017.

On 8 October, BP, Eni, and Libya's National Oil Corporation (NOC) signed a letter of intent to resume exploration activities under a major exploration and production sharing agreement (EPSA) in Libya. On completion, Eni would become operator of the EPSA with a 42.5% interest. BP and the Libyan Investment Authority would hold the remaining 42.5% and 15% interest, respectively. Currently, BP is the operator of the EPSA with an 85% interest and the Libyan Investment Authority holds the remaining 15% interest.

On 18 October, BP announced the start-up of the Thunder Horse Northwest Expansion project in the deepwater Gulf of Mexico. This is the fourth major project to begin production this year. The project was delivered under budget and ahead of schedule (BP operator 75% and ExxonMobil 25%).

On 25 October, the Western Flank B project in Australia commenced gas production. This is the fifth major project to start up this year. The project was delivered under budget and ahead of schedule (Woodside operator, BP, BHP, Chevron, Shell, and Japan Australia LNG, each 16.67%).

Outlook

Looking ahead, we expect fourth-quarter reported production to be higher than the third quarter due to the acquisition of BHP assets in the US Lower 48.

The commentary above contains forward-looking statements and should be read in conjunction with the cautionary statement on page 35.

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Upstream (continued)

	Third		Second		Third		Nine		Nine
	quarter		quarter		quarter		months		months
$ million	2018		2018		2017		2018		2017
Underlying RC profit before interest and tax
US	1,025		742		264		2,293		609
Non-US	2,974		2,766		1,298		8,371		3,033
	3,999		3,508		1,562		10,664		3,642
Non-operating items
US_(a)	(149	)	(29	)	(97	)	(323	)	(143	)
Non-US_(b)	(93	)	56		(49	)	4		(384	)
	(242	)	27		(146	)	(319	)	(527	)
Fair value accounting effects
US	(10	)	(143	)	(100	)	(162	)	184
Non-US	(275	)	122		(74	)	(23	)	(6	)
	(285	)	(21	)	(174	)	(185	)	178
RC profit before interest and tax
US	866		570		67		1,808		650
Non-US	2,606		2,944		1,175		8,352		2,643
	3,472		3,514		1,242		10,160		3,293
Exploration expense
US_(a)	39		77		190		425		255
Non-US_(c)	271		87		107		563		1,304
	310		164		297		988		1,559
Of which: Exploration expenditure written off_(a)(c)	227		81		217		734		1,231
Production (net of royalties)_(d)
Liquids* (mb/d)
US	424		411		408		428		425
Europe	128		147		123		138		120
Rest of World	663		659		809		684		816
	1,216		1,217		1,341		1,250		1,360
Natural gas (mmcf/d)
US	1,805		1,744		1,703		1,780		1,625
Europe	212		202		217		210		251
Rest of World	5,201		5,297		4,581		5,317		4,311
	7,218		7,242		6,502		7,307		6,187
Total hydrocarbons* (mboe/d)
US	736		711		702		734		705
Europe	165		182		161		175		163
Rest of World	1,560		1,572		1,599		1,601		1,559
	2,460		2,465		2,462		2,510		2,427
Average realizations*_(e)
Total liquids_(f) ($/bbl)	69.68		67.24		47.45		66.11		47.87
Natural gas ($/mcf)	3.86		3.65		2.89		3.77		3.18
Total hydrocarbons ($/boe)	46.14		43.37		33.23		43.64		34.63

(a) 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.

(b) Nine months 2017 relates primarily to an impairment charge related to the sale of the Forties Pipeline System business to INEOS.

(c) Nine months 2017 predominantly relates to 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.

(d) Includes BP's share of production of equity-accounted entities in the Upstream segment.

(e) Realizations are based on sales by consolidated subsidiaries only - this excludes equity-accounted entities.

(f) Includes condensate, natural gas liquids and bitumen.

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

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Downstream

	Third		Second		Third		Nine		Nine
	quarter		quarter		quarter		months		months
$ million	2018		2018		2017		2018		2017
Profit before interest and tax	2,592		2,036		2,695		6,410		5,487
Inventory holding (gains) losses*	(343	)	(1,196	)	(520	)	(1,608	)	(39	)
RC profit before interest and tax	2,249		840		2,175		4,802		5,448
Net (favourable) adverse impact of non-operating items* and fair value accounting effects*	(138	)	615		163		590		45
Underlying RC profit before interest and tax*_(a)	2,111		1,455		2,338		5,392		5,493

(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 $2,249 million and $4,802 million respectively, compared with $2,175 million and $5,448 million for the same periods in 2017.

The third quarter and nine months include a net non-operating charge of $37 million and $315 million respectively, compared with a charge of $55 million and a gain of $7 million for the same periods in 2017. Fair value accounting effects had a favourable impact of $175 million in the third quarter and an adverse impact of $275 million for the nine months, compared with an adverse impact of $108 million and $52 million for the same periods in 2017.

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

Fuels

The fuels business reported an underlying replacement cost profit before interest and tax of $1,566 million for the third quarter and $4,018 million for the nine months, compared with $1,788 million and $3,896 million for the same periods in 2017.

The refining result for the quarter reflects strong operational performance and higher North American heavy crude oil discounts net of pipeline capacity apportionment impacts. These factors were more than offset by lower industry refining margins and a higher level of turnaround activity in the US. The stronger refining result for the nine months reflects the benefits of increased commercial optimization and higher net North American heavy crude oil discounts.

In fuels marketing the rollout of our convenience partnership model continued across the network and retail volumes grew.

For the quarter the contribution from supply and trading was similar to last year and higher than the second quarter. The result for the nine months was, however, impacted by a lower contribution from supply and trading in the first half of the year.

Lubricants

The lubricants business reported an underlying replacement cost profit before interest and tax of $324 million for the third quarter and $981 million for the nine months, compared with $356 million and $1,104 million for the same periods in 2017. The result for the quarter and nine months reflects continued premium volume growth, more than offset by the adverse lag impact of increasing base oil prices, as well as adverse foreign exchange rate movements in the quarter.

Petrochemicals

The petrochemicals business reported an underlying replacement cost profit before interest and tax of $221 million for the third quarter and $393 million for the nine months, compared with $194 million and $493 million for the same periods in 2017. The result for the quarter and nine months reflects an improved margin environment, increased margin optimization and continued strong cost management. These factors were partially offset by the impact from the divestment of our interest in the SECCO joint venture, which completed in the fourth quarter of last year. The result for the nine months was also impacted by a significantly higher level of turnaround activity in the first half of the year.

Outlook

Looking to the fourth quarter, we expect lower industry refining margins. We also expect higher levels of turnaround driven by activity at our Whiting refinery in the US.

The commentary above contains forward-looking statements and should be read in conjunction with the cautionary statement on page 35.

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Downstream (continued)

	Third		Second		Third		Nine		Nine
	quarter		quarter		quarter		months		months
$ million	2018		2018		2017		2018		2017
Underlying RC profit before interest and tax - by region
US	835		399		640		1,823		1,477
Non-US	1,276		1,056		1,698		3,569		4,016
	2,111		1,455		2,338		5,392		5,493
Non-operating items
US	(14	)	(155	)	(39	)	(186	)	(23	)
Non-US	(23	)	(70	)	(16	)	(129	)	30
	(37	)	(225	)	(55	)	(315	)	7
Fair value accounting effects_(a)
US	81		(299	)	20		(339	)	(32	)
Non-US	94		(91	)	(128	)	64		(20	)
	175		(390	)	(108	)	(275	)	(52	)
RC profit before interest and tax
US	902		(55	)	621		1,298		1,422
Non-US	1,347		895		1,554		3,504		4,026
	2,249		840		2,175		4,802		5,448
Underlying RC profit before interest and tax - by business_(b)(c)
Fuels	1,566		1,054		1,788		4,018		3,896
Lubricants	324		326		356		981		1,104
Petrochemicals	221		75		194		393		493
	2,111		1,455		2,338		5,392		5,493
Non-operating items and fair value accounting effects_(a)
Fuels	140		(584	)	(154	)	(554	)	9
Lubricants	-		(26	)	(3	)	(29	)	(8	)
Petrochemicals	(2	)	(5	)	(6	)	(7	)	(46	)
	138		(615	)	(163	)	(590	)	(45	)
RC profit before interest and tax_(b)(c)
Fuels	1,706		470		1,634		3,464		3,905
Lubricants	324		300		353		952		1,096
Petrochemicals	219		70		188		386		447
	2,249		840		2,175		4,802		5,448

BP average refining marker margin (RMM)* ($/bbl)	14.7		14.9		16.3		13.8		14.0

Refinery throughputs (mb/d)
US	740		666		737		707		713
Europe	805		786		768		796		784
Rest of World	248		228		240		242		207
	1,793		1,680		1,745		1,745		1,704
Refining availability* (%)	96.3		93.3		95.3		94.8		95.0

Marketing sales of refined products (mb/d)
US	1,169		1,161		1,186		1,142		1,160
Europe	1,166		1,135		1,204		1,116		1,143
Rest of World	497		477		480		485		496
	2,832		2,773		2,870		2,743		2,799
Trading/supply sales of refined products	3,147		3,247		3,088		3,192		3,015
Total sales volumes of refined products	5,979		6,020		5,958		5,935		5,814

Petrochemicals production (kte)
US	660		404		617		1,563		1,787
Europe	1,209		1,094		1,285		3,431		3,903
Rest of World	1,146		1,358		2,025		3,896		6,099
	3,015		2,856		3,927		8,890		11,789

(a) For Downstream, fair value accounting effects arise solely in the fuels business. See page 28 for further information.

(b) Segment-level overhead expenses are included in the fuels business result.

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Rosneft

	Third		Second		Third		Nine		Nine
	quarter		quarter		quarter		months		months
$ million	2018_(a)		2018		2017		2018_(a)		2017
Profit before interest and tax_(b)	835		876		161		1,980		505
Inventory holding (gains) losses*	(27	)	(110	)	(24	)	(159	)	10
RC profit before interest and tax	808		766		137		1,821		515
Net charge (credit) for non-operating items*	64		-		-		64		-
Underlying RC profit before interest and tax*	872		766		137		1,885		515

Financial results

Replacement cost (RC) profit before interest and tax for the third quarter and nine months was $808 million and $1,821 million respectively, compared with $137 million and $515 million for the same periods in 2017.

After adjusting for a non-operating item, the underlying RC profit before interest and tax for the third quarter and nine months was $872 million and $1,885 million respectively. There were no non-operating items in the third quarter and nine months of 2017.

Compared with the same periods in 2017, the results for the third quarter and nine months were primarily affected by higher oil prices, significant foreign exchange impacts and certain one-off items.

Following the approval at the annual general meeting in June of a resolution to pay a final dividend for 2017 of 6.65 roubles per ordinary share, BP received a payment of $200 million, after the deduction of withholding tax, on 31 July.

The extraordinary general meeting held on 28 September adopted a resolution to pay interim dividends of 14.58 Russian roubles per ordinary share which constitute 50% of Rosneft's IFRS net profit for the first half of 2018. BP expects to receive a dividend of approximately $410 million after the deduction of withholding tax, subject to fluctuations in foreign exchange, in the fourth quarter.

	Third	Second	Third	Nine	Nine
	quarter	quarter	quarter	months	months
	2018_(a)	2018	2017	2018_(a)	2017
Production (net of royalties) (BP share)
Liquids* (mb/d)	933	909	903	915	906
Natural gas (mmcf/d)	1,260	1,262	1,263	1,276	1,300
Total hydrocarbons* (mboe/d)	1,151	1,127	1,120	1,135	1,130

(a) The operational and financial information of the Rosneft segment for the third quarter and nine months is based on preliminary operational and financial results of Rosneft for the nine months ended 30 September 2018. 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 increase the reported profit before interest and tax, as shown in the table above, compared with the equivalent amount in Russian roubles in Rosneft's IFRS financial statements. In particular, in third quarter 2018 these adjustments resulted in BP reporting a lower amount relating to impairment charges of downstream goodwill than the equivalent amounts expected to be reported by Rosneft. 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.

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Other businesses and corporate

	Third		Second		Third		Nine		Nine
	quarter		quarter		quarter		months		months
$ million	2018		2018		2017		2018		2017
Profit (loss) before interest and tax
Gulf of Mexico oil spill - business economic loss claims	(69	)	(249	)	-		(318	)	(260	)
Gulf of Mexico oil spill - other	(59	)	(184	)	(84	)	(329	)	(206	)
Other	(687	)	(592	)	(376	)	(1,764	)	(1,146	)
Profit (loss) before interest and tax	(815	)	(1,025	)	(460	)	(2,411	)	(1,612	)
Inventory holding (gains) losses*	-		-		-		-		-
RC profit (loss) before interest and tax	(815	)	(1,025	)	(460	)	(2,411	)	(1,612	)
Net charge (credit) for non-operating items*
Gulf of Mexico oil spill - business economic loss claims	69		249		-		318		260
Gulf of Mexico oil spill - other	59		184		84		329		206
Other	342		115		(22	)	550		(58	)
Net charge (credit) for non-operating items	470		548		62		1,197		408
Underlying RC profit (loss) before interest and tax*	(345	)	(477	)	(398	)	(1,214	)	(1,204	)
Underlying RC profit (loss) before interest and tax
US	(166	)	(123	)	(145	)	(436	)	(446	)
Non-US	(179	)	(354	)	(253	)	(778	)	(758	)
	(345	)	(477	)	(398	)	(1,214	)	(1,204	)
Non-operating items
US	(438	)	(498	)	(92	)	(1,084	)	(480	)
Non-US	(32	)	(50	)	30		(113	)	72
	(470	)	(548	)	(62	)	(1,197	)	(408	)
RC profit (loss) before interest and tax
US	(604	)	(621	)	(237	)	(1,520	)	(926	)
Non-US	(211	)	(404	)	(223	)	(891	)	(686	)
	(815	)	(1,025	)	(460	)	(2,411	)	(1,612	)

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 $815 million and $2,411 million respectively, compared with $460 million and $1,612 million for the same periods in 2017.

The results included a net non-operating charge of $470 million for the third quarter and $1,197 million for the nine months, compared with a charge of $62 million and $408 million for the same periods in 2017. See Note 2 on page 19 for more information on the Gulf of Mexico oil spill.

After adjusting for non-operating items, the underlying replacement cost loss before interest and tax for the third quarter and nine months was $345 million and $1,214 million respectively, compared with $398 million and $1,204 million for the same periods in 2017.

Alternative Energy

The net ethanol-equivalent production (which includes ethanol and sugar) for the third quarter and nine months was 354 million litres and 621 million litres respectively, compared with 362 million litres and 588 million litres for the same periods in 2017.

Net wind generation capacity* was 1,431MW at 30 September 2018, compared with 1,432MW at 30 September 2017. BP's net share of wind generation for the third quarter and nine months was 687GWh and 2,888GWh respectively, compared with 644GWh and 2,856GWh for the same periods in 2017.

In July, Lightsource BP, the solar development company (BP 43%), formed a joint venture with Hassan Allam Holding in Egypt. The joint venture will fund, develop and operate solar projects locally, offering commercial and residential customers in Egypt world-class solutions in solar energy and energy storage. Lightsource BP is also evaluating new opportunities in a number of other countries, including Brazil and Australia.

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Financial statements

Group income statement

	Third	Second		Third		Nine	Nine
	quarter	quarter		quarter		months	months
$ million	2018	2018		2017		2018	2017

Sales and other operating revenues (Note 6)	79,468	75,439		60,018		223,079	172,392
Earnings from joint ventures - after interest and tax	148	220		231		661	596
Earnings from associates - after interest and tax	990	1,027		282		2,431	804
Interest and other income	154	165		185		478	434
Gains on sale of businesses and fixed assets	43	56		92		204	334
Total revenues and other income	80,803	76,907		60,808		226,853	174,560
Purchases	60,923	58,424		44,441		170,859	127,971
Production and manufacturing expenses_(a)	5,879	5,515		5,454		16,832	16,470
Production and similar taxes (Note 8)	451	531		449		1,350	1,264
Depreciation, depletion and amortization (Note 7)	3,728	3,811		3,904		11,470	11,539
Impairment and losses on sale of businesses and fixed assets	548	(23	)	108		616	612
Exploration expense	310	164		297		988	1,559
Distribution and administration expenses	2,801	2,929		2,634		8,524	7,527
Profit (loss) before interest and taxation	6,163	5,556		3,521		16,214	7,618
Finance costs_(a)	698	535		511		1,786	1,458
Net finance expense relating to pensions and other post-retirement benefits	31	31		55		93	162
Profit (loss) before taxation	5,434	4,990		2,955		14,335	5,998
Taxation_(a)	2,031	2,117		1,198		5,528	2,593
Profit (loss) for the period	3,403	2,873		1,757		8,807	3,405
Attributable to
BP shareholders	3,349	2,799		1,769		8,617	3,362
Non-controlling interests	54	74		(12	)	190	43
	3,403	2,873		1,757		8,807	3,405

Earnings per share (Note 9)
Profit (loss) for the period attributable to BP shareholders
Per ordinary share (cents)
Basic	16.74	14.03		8.95		43.17	17.10
Diluted	16.65	13.96		8.90		42.91	17.00
Per ADS (dollars)
Basic	1.00	0.84		0.54		2.59	1.03
Diluted	1.00	0.84		0.53		2.57	1.02

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

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Condensed group statement of comprehensive income

	Third		Second		Third		Nine		Nine
	quarter		quarter		quarter		months		months
$ million	2018		2018		2017		2018		2017

Profit (loss) for the period	3,403		2,873		1,757		8,807		3,405
Other comprehensive income
Items that may be reclassified subsequently to profit or loss
Currency translation differences	(753	)	(2,612	)	611		(2,834	)	1,722
Exchange (gains) losses on translation of foreign operations reclassified to gain or loss on sale of businesses and fixed assets	-		-		13		-		18
Available-for-sale investments	-		-		-		-		3
Cash flow hedges and costs of hedging	65		(107	)	98		(124	)	375
Share of items relating to equity-accounted entities, net of tax	95		(33	)	128		217		431
Income tax relating to items that may be reclassified	9		52		(59	)	(29	)	(180	)
	(584	)	(2,700	)	791		(2,770	)	2,369
Items that will not be reclassified to profit or loss
Remeasurements of the net pension and other post-retirement benefit liability or asset	389		1,714		1,002		2,968		2,047
Cash flow hedges that will subsequently be transferred to the balance sheet	(7	)	(35	)	-		(29	)	-
Income tax relating to items that will not be reclassified	(119	)	(557	)	(351	)	(941	)	(699	)
	263		1,122		651		1,998		1,348
Other comprehensive income	(321	)	(1,578	)	1,442		(772	)	3,717
Total comprehensive income	3,082		1,295		3,199		8,035		7,122
Attributable to
BP shareholders	3,040		1,268		3,206		7,888		7,041
Non-controlling interests	42		27		(7	)	147		81
	3,082		1,295		3,199		8,035		7,122

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Condensed group statement of changes in equity

	BP shareholders'		Non-controlling		Total
$ million	equity		interests		equity
At 31 December 2017	98,491		1,913		100,404
Adjustment on adoption of IFRS 9, net of tax_(a)	(180	)	-		(180	)
At 1 January 2018	98,311		1,913		100,224

Total comprehensive income	7,888		147		8,035
Dividends	(4,965	)	(129	)	(5,094	)
Cash flow hedges transferred to the balance sheet, net of tax	17		-		17
Repurchase of ordinary share capital	(339	)	-		(339	)
Share-based payments, net of tax	582		-		582
Share of equity-accounted entities' changes in equity, net of tax	(6	)	-		(6	)
Transactions involving non-controlling interests, net of tax	-		1		1
At 30 September 2018	101,488		1,932		103,420

	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' changes in equity, net of tax	206		-		206
Transactions involving non-controlling interests, net of tax	-		88		88
At 30 September 2017	98,521		1,617		100,138

(a) See Note 1 for further information.

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Group balance sheet

	30 September	31 December
$ million	2018	2017
Non-current assets
Property, plant and equipment	122,661	129,471
Goodwill	11,423	11,551
Intangible assets	17,703	18,355
Investments in joint ventures	8,272	7,994
Investments in associates	17,929	16,991
Other investments	1,353	1,245
Fixed assets	179,341	185,607
Loans	470	646
Trade and other receivables	1,467	1,434
Derivative financial instruments	4,579	4,110
Prepayments	1,143	1,112
Deferred tax assets	3,672	4,469
Defined benefit pension plan surpluses	6,618	4,169
	197,290	201,547
Current assets
Loans	292	190
Inventories	21,894	19,011
Trade and other receivables	27,401	24,849
Derivative financial instruments	3,751	3,032
Prepayments	1,833	1,414
Current tax receivable	900	761
Other investments	100	125
Cash and cash equivalents	26,192	25,586
	82,363	74,968
Assets classified as held for sale (Note 3)	3,289	-
	85,652	74,968
Total assets	282,942	276,515
Current liabilities
Trade and other payables	47,125	44,209
Derivative financial instruments	4,177	2,808
Accruals	4,521	4,960
Finance debt	9,175	7,739
Current tax payable	2,272	1,686
Provisions	2,320	3,324
	69,590	64,726
Liabilities directly associated with assets classified as held for sale (Note 3)	337	-
	69,927	64,726
Non-current liabilities
Other payables	13,438	13,889
Derivative financial instruments	5,531	3,761
Accruals	588	505
Finance debt	54,960	55,491
Deferred tax liabilities	8,920	7,982
Provisions	17,764	20,620
Defined benefit pension plan and other post-retirement benefit plan deficits	8,394	9,137
	109,595	111,385
Total liabilities	179,522	176,111
Net assets	103,420	100,404
Equity
BP shareholders' equity	101,488	98,491
Non-controlling interests	1,932	1,913
Total equity	103,420	100,404

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Condensed group cash flow statement

	Third		Second		Third		Nine		Nine
	quarter		quarter		quarter		months		months
$ million	2018		2018		2017		2018		2017
Operating activities
Profit (loss) before taxation	5,434		4,990		2,955		14,335		5,998
Adjustments to reconcile profit (loss) before taxation to net cash provided by operating activities
Depreciation, depletion and amortization and exploration expenditure written off	3,955		3,892		4,121		12,204		12,770
Impairment and (gain) loss on sale of businesses and fixed assets	505		(79	)	16		412		278
Earnings from equity-accounted entities, less dividends received	(664	)	(988	)	(111	)	(2,188	)	(434	)
Net charge for interest and other finance expense, less net interest paid	114		191		163		385		499
Share-based payments	160		167		177		564		495
Net operating charge for pensions and other post-retirement benefits, less contributions and benefit payments for unfunded plans	(62	)	(62	)	(160	)	(326	)	(179	)
Net charge for provisions, less payments	145		80		(144	)	369		(138	)
Movements in inventories and other current and non-current assets and liabilities	(1,573	)	(570	)	305		(5,541	)	(3,292	)
Income taxes paid	(1,922	)	(1,315	)	(1,298	)	(4,170	)	(2,969	)
Net cash provided by operating activities	6,092		6,306		6,024		16,044		13,028
Investing activities
Expenditure on property, plant and equipment, intangible and other assets	(3,675	)	(3,484	)	(4,136	)	(10,745	)	(12,140	)
Acquisitions, net of cash acquired	(606	)	(1	)	(146	)	(607	)	(311	)
Investment in joint ventures	(35	)	(18	)	(5	)	(92	)	(35	)
Investment in associates	(88	)	(322	)	(176	)	(748	)	(533	)
Total cash capital expenditure	(4,404	)	(3,825	)	(4,463	)	(12,192	)	(13,019	)
Proceeds from disposal of fixed assets	90		105		149		280		649
Proceeds from disposal of businesses, net of cash disposed	26		45		92		153		305
Proceeds from loan repayments	14		24		308		47		341
Net cash used in investing activities	(4,274	)	(3,651	)	(3,914	)	(11,712	)	(11,724	)
Financing activities
Net issue (repurchase) of shares	(139	)	(90	)	-		(339	)	-
Proceeds from long-term financing	5,888		910		3,078		6,920		8,511
Repayments of long-term financing	(2,521	)	(1,726	)	(1,239	)	(5,404	)	(3,619	)
Net increase (decrease) in short-term debt	485		292		123		428		139
Net increase (decrease) in non-controlling interests	1		-		-		-		81
Dividends paid - BP shareholders	(1,410	)	(1,727	)	(1,676	)	(4,966	)	(4,526	)
- non-controlling interests	(59	)	(57	)	(32	)	(129	)	(109	)
Net cash provided by (used in) financing activities	2,245		(2,398	)	254		(3,490	)	477
Currency translation differences relating to cash and cash equivalents	(56	)	(314	)	146		(225	)	515
Increase (decrease) in cash and cash equivalents	4,007		(57	)	2,510		617		2,296
Cash and cash equivalents at beginning of period	22,185		22,242		23,270		25,575		23,484
Cash and cash equivalents at end of period	26,192		22,185		25,780		26,192		25,780

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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 2017 included in BP Annual Report and Form 20-F 2017.

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 2018, which are the same as those used in preparing BP Annual Report and Form 20-F 2017 with the exception of the implementation of IFRS 9 'Financial Instruments' and IFRS 15 'Revenue from Contracts with Customers' from 1 January 2018.

New International Financial Reporting Standards adopted

BP adopted IFRS 9 'Financial Instruments' and IFRS 15 'Revenue from Contracts with Customers' with effect from 1 January 2018. Information on the implementation of new accounting standards is included in BP Annual Report and Form 20-F 2017 - Financial statements - Note 1 Significant accounting policies, judgements, estimates and assumptions - Impact of new International Financial Reporting Standards.

IFRS 9 'Financial Instruments'

IFRS 9 provides a single classification and measurement approach for financial assets that reflects the business model in which they are managed and their cash flow characteristics. The group's financial assets are classified as measured at amortized cost, fair value through profit or loss, or fair value through other comprehensive income. Investments in equity instruments are classified as measured at fair value through profit or loss unless the group elects, on an instrument-by-instrument basis, on initial recognition to recognize fair value gains and losses in other comprehensive income. The adoption of IFRS 9 did not have a significant effect on the group's accounting policies relating to financial liabilities.

Under IFRS 9, impairments of financial assets classified as measured at amortized cost are recognized on an expected loss basis which incorporates forward-looking information when assessing credit risk. Movements in the expected loss reserve are recognized in profit or loss.

Under IFRS 9, fair value movements on the time value and cross currency basis spreads of certain hedging instruments are initially recognized in equity to the extent that they relate to the hedged item. Previously these were recognized in the income statement. In addition where the gain or loss on cash flow hedging instruments initially reported in other comprehensive income is transferred to the initial carrying amount of a non-financial asset or liability this is no longer presented as a reclassification adjustment. Instead the transfer to the balance sheet is presented in the statement of changes in equity.

The overall impact on transition to IFRS 9, including the impact upon the group's share of equity-accounted entities, was a reduction of $180 million in net assets, net of tax. This adjustment mainly related to an increase in the credit reserve of financial assets in the scope of IFRS 9's impairment requirements. As permitted by IFRS 9 comparatives were not restated. For certain line items in the balance sheet the closing balance at 31 December 2017 and the opening balance at 1 January 2018 therefore differ (as summarized below). Cash and cash equivalents at the beginning of 2018 in the Condensed group cash flow statement and Note 11 (Net debt) are the 1 January 2018 amounts included in the table below.

					Adjustment
	31 December		1 January		on adoption
$ million	2017		2018		of IFRS 9
Non-current
Investments in equity-accounted entities	24,985		24,903		(82	)
Loans, trade and other receivables	2,080		2,069		(11	)
Deferred tax liabilities	(7,982	)	(7,946	)	36
Current
Loans, trade and other receivables	25,039		24,927		(112	)
Cash and cash equivalents	25,586		25,575		(11	)

Net assets	100,404		100,224		(180	)

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Note 1. Basis of preparation (continued)

IFRS 15 'Revenue from Contracts with Customers'

Under IFRS 15, revenue from contracts with customers is recognized as or when the group satisfies a performance obligation by transferring a promised good or service to a customer. A good or service is transferred when the customer obtains control of that good or service. The transfer of control of oil, natural gas, natural gas liquids, LNG, petroleum and chemical products, and other items sold by the group usually coincides with title passing to the customer and the customer taking physical possession. The group principally satisfies its performance obligations at a point in time and the amounts of revenue recognized relating to performance obligations satisfied over time are not significant. The accounting for revenue under IFRS 15 does not, therefore, represent a substantive change from the group's previous practice for recognizing revenue from sales to customers.

BP elected to apply the 'modified retrospective' approach to transition permitted by IFRS 15 under which comparative financial information is not restated. Certain changes in accounting arising from the implementation of IFRS 15 were identified but the standard did not have a material effect on the group's financial statements as at 1 January 2018 and so no transition adjustment was made. The implementation of the standard has also not had a material effect on the group's results for the first nine months of 2018 compared to those that would have been reported under the group's previous accounting policy for revenue.

An analysis of revenue from contracts with customers by product is presented in Note 6. Amounts presented for comparative periods in 2017 include revenues determined in accordance with the group's previous accounting policies relating to revenue. The total amounts presented do not, therefore, represent the revenue from contracts with customers that would have been reported for those periods had IFRS 15 been applied using a fully retrospective approach to transition but the differences are not significant.

Change in significant estimate - decommissioning provision

Decommissioning provision cost estimates are reviewed regularly and the latest review was undertaken in the second quarter of 2018. The timing and amount of estimated future expenditures were re-assessed and discounted to determine the present value. From 30 June 2018 the present value of the decommissioning provision is determined by discounting the estimated cash flows expressed in expected future prices, i.e. taking account of expected inflation, at a nominal discount rate (2.5%). Prior to 30 June 2018, the group estimated future cash flows in real terms i.e. at current prices and discounted them using a real discount rate (0.5% as at 31 December 2017).

The impact of the review was a reduction in the provision of $1.5 billion as at 30 June 2018, with a similar reduction in the carrying amount of property, plant and equipment. There was no significant impact on the income statement for the first half of 2018. The impact on the income statement for the second half of 2018 is estimated to be a decrease in depreciation, depletion and amortization of around $80 million and an increase in finance costs of around $80 million.

For further information on the group's accounting policy on significant estimates and judgements relating to provisions, see BP Annual Report and 20-F 2017 - Financial statements - Note 1 Significant accounting policies, estimates and assumptions.

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Note 2. Gulf of Mexico oil spill

(a) Overview

The information presented in this note should be read in conjunction with Note 2 of the financial statements and pages 270-272 of Legal proceedings included in BP Annual Report and Form 20-F 2017.

The group income statement includes a post-tax charge for the third quarter of $54 million relating to business economic loss (BEL) claims and $30 million relating to other claims and litigation. The group income statement also includes finance costs relating to the unwinding of discounting effects relating to payables.

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	2018		2018		2017		2018		2017
Income statement
Production and manufacturing expenses	128		433		84		647		466
Profit (loss) before interest and taxation	(128	)	(433	)	(84	)	(647	)	(466	)
Finance costs	119		118		122		357		369
Profit (loss) before taxation	(247	)	(551	)	(206	)	(1,004	)	(835	)
Taxation	15		106		71		182		273
Profit (loss) for the period	(232	)	(445	)	(135	)	(822	)	(562	)

The cumulative pre-tax income statement charge since the incident, in April 2010, amounts to $66,769 million.

	30 September		31 December
$ million	2018		2017
Balance sheet
Current assets
Trade and other receivables	207		252
Current liabilities
Trade and other payables	(2,396	)	(2,089	)
Provisions	(360	)	(1,439	)
Net current assets (liabilities)	(2,549	)	(3,276	)
Non-current assets
Deferred tax assets	1,605		2,067
Non-current liabilities
Other payables	(11,838	)	(12,253	)
Provisions	(29	)	(1,141	)
Deferred tax liabilities	3,966		3,634
Net non-current assets (liabilities)	(6,296	)	(7,693	)
Net assets (liabilities)	(8,845	)	(10,969	)

	Third		Second		Third		Nine		Nine
	quarter		quarter		quarter		months		months
$ million	2018		2018		2017		2018		2017
Cash flow statement - Operating activities
Profit (loss) before taxation	(247	)	(551	)	(206	)	(1,004	)	(835	)
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	119		118		122		357		369
Net charge for provisions, less payments	106		48		68		208		361
Movements in inventories and other current and non-current assets and liabilities	(538	)	(693	)	(548	)	(2,819	)	(4,778	)
Pre-tax cash flows	(560	)	(1,078	)	(564	)	(3,258	)	(4,883	)

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Note 2. Gulf of Mexico oil spill (continued)

Cash outflows in 2018 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 $525 million and $2,946 million in the third quarter and nine months of 2018 respectively. For the same periods in 2017, the amount was an outflow of $564 million and $4,883 million respectively.

(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 2018	425
Net increase in provision	108
Reclassified to other payables	(110	)
Utilization	(34	)
At 30 September 2018	389

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

$ million
At 1 January 2018	2,580
Net increase in provision	584
Reclassified to other payables	(1,985	)
Utilization	(790	)
At 30 September 2018	389

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

Provisions and other payables include the latest estimate for the remaining costs associated with the 2012 Plaintiffs' Steering Committee (PSC) settlement. These costs relate predominantly to business economic loss (BEL) claims and associated administration costs. The amounts ultimately payable may differ from the amount provided and the timing of payments is uncertain.

The settlement programme's determination of BEL claims was substantially completed by the end of 2017 and remaining claims continued to be processed in the first nine months of 2018 with only a very small number of claims now remaining to be determined. Nevertheless, a significant number of BEL claims determined by the settlement programme have been and continue to be appealed by BP and/or the claimants.

As settlement agreements have been reached with claimants amounts payable have been reclassified from provisions to other payables. The remaining amount provided for includes the latest estimate of the amounts that are expected ultimately to be paid to resolve outstanding BEL claims. Claims under appeal will ultimately only be resolved once the full judicial appeals process has been concluded, including appeals to the Federal District Court and Fifth Circuit, as may be the case, or when settlements are reached with individual claimants. Depending upon the ultimate resolution of these claims, the amounts payable may differ from those currently provided.

Payments to resolve outstanding claims under the PSC settlement are expected to be made over a number of years. The timing of payments, however, 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 includes 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, and BP's remaining commitment to fund the Gulf of Mexico Research Initiative.

Other payables also includes amounts payable for settled economic loss and property damage claims which are payable over a period of up to nine years.

Further information on provisions, other payables, and contingent liabilities is provided in BP Annual Report and Form 20-F 2017 - Financial statements - Note 2.

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Note 3. Non-current assets held for sale

On 3 July 2018 BP announced that it had entered into an agreement with ConocoPhillips through which the group will sell its entire 39.2% non-operated interest in the Greater Kuparuk Area on the North Slope of Alaska and its holding in the Kuparuk Transportation Company. BP simultaneously entered into an agreement to buy a further 16.5% interest in the BP-operated Clair field, a core asset of BP's North Sea business in the UK, from ConocoPhillips. As a result of the transaction, BP will hold a 45.1% interest in the Clair field. The two transactions together are expected to be cash neutral for BP.

The transactions, which will be subject to State of Alaska, US federal and UK regulatory approvals and other approvals, are anticipated to complete in 2018. Assets and associated liabilities relating to BP's interests in Kuparuk in Alaska, which are reported in the Upstream segment, are classified as held for sale in the group balance sheet at 30 September 2018.

In January 2017, BP announced it had agreed to sell 25% of its 100% interest in the Magnus oil field and some associated pipeline infrastructure in the UK northern North Sea and in the Sullom Voe Terminal (SVT) on Shetland to EnQuest. This transaction was completed on 1 December 2017. Under the terms of the agreement, EnQuest had an option, exercisable between 1 July 2018 and 15 January 2019, to purchase BP's remaining 75% interest in Magnus, a further 9% interest in SVT and the remainder of BP's interests in the associated pipelines.

On 1 October 2018, EnQuest notified BP of the exercise of its option to acquire the remaining 75% of BP's stake in the Magnus field and associated infrastructure. The assets relating to these interests, which are reported in the Upstream segment, have been classified as held for sale in the group balance sheet at 30 September 2018.

Note 4. Update on BP's acquisition of a portfolio of BHP assets

BP's acquisition of a portfolio of US onshore oil and gas assets from BHP is expected to complete on 31 October 2018. On completion, $5.25 billion, less a deposit paid of $525 million and subject to customary adjustments, will be paid in cash. $5.25 billion will be deferred and payable in cash in six equal instalments over six months from the date of completion, with the first of these payments being made in November. Assuming oil prices remain firm in the recent trading range, BP now expects to fund the deferred consideration element of $5.25 billion over the next six months using available cash, rather than through equity issue. Proceeds from the previously announced divestment programme of $5-6 billion linked to this transaction will now be used to reduce debt.

Note 5. 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	2018		2018		2017		2018		2017
Upstream	3,472		3,514		1,242		10,160		3,293
Downstream	2,249		840		2,175		4,802		5,448
Rosneft	808		766		137		1,821		515
Other businesses and corporate_(a)	(815	)	(1,025	)	(460	)	(2,411	)	(1,612	)
	5,714		4,095		3,094		14,372		7,644
Consolidation adjustment - UPII*	78		151		(130	)	69		(63	)
RC profit (loss) before interest and tax*	5,792		4,246		2,964		14,441		7,581
Inventory holding gains (losses)*
Upstream	1		4		13		6		8
Downstream	343		1,196		520		1,608		39
Rosneft (net of tax)	27		110		24		159		(10	)
Profit (loss) before interest and tax	6,163		5,556		3,521		16,214		7,618
Finance costs	698		535		511		1,786		1,458
Net finance expense relating to pensions and other post-retirement benefits	31		31		55		93		162
Profit (loss) before taxation	5,434		4,990		2,955		14,335		5,998

RC profit (loss) before interest and tax*
US	1,215		(20	)	428		1,554		1,243
Non-US	4,577		4,266		2,536		12,887		6,338
	5,792		4,246		2,964		14,441		7,581

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

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Note 6. Sales and other operating revenues

	Third	Second	Third	Nine	Nine
	quarter	quarter	quarter	months	months
$ million	2018	2018	2017	2018	2017
By segment
Upstream	14,781	12,698	10,969	41,349	32,789
Downstream	72,376	69,174	54,881	202,956	157,156
Other businesses and corporate	423	376	378	1,142	989
	87,580	82,248	66,228	245,447	190,934

Less: sales and other operating revenues between segments
Upstream	7,368	5,795	5,312	19,896	17,250
Downstream	539	785	765	1,806	887
Other businesses and corporate	205	229	133	666	405
	8,112	6,809	6,210	22,368	18,542

Third party sales and other operating revenues
Upstream	7,413	6,903	5,657	21,453	15,539
Downstream	71,837	68,389	54,116	201,150	156,269
Other businesses and corporate	218	147	245	476	584
Total sales and other operating revenues	79,468	75,439	60,018	223,079	172,392

By geographical area
US	27,580	26,676	21,853	77,869	64,582
Non-US	58,869	56,032	44,212	166,141	125,335
	86,449	82,708	66,065	244,010	189,917
Less: sales and other operating revenues between areas	6,981	7,269	6,047	20,931	17,525
	79,468	75,439	60,018	223,079	172,392

Sales and other operating revenues include the following in relation to revenues from contracts with customers
Crude oil	17,744	17,167	13,052	49,828	35,832
Oil products	52,049	51,440	40,149	147,619	113,829
Natural gas, LNG and NGLs	5,764	4,960	4,102	15,883	11,419
Non-oil products and other revenues from contracts with customers	3,574	3,081	3,029	10,150	8,765
Revenues from contracts with customers_(a)	79,131	76,648	60,332	223,480	169,845

(a) See Note 1 for further information.

Note 7. Depreciation, depletion and amortization

	Third	Second	Third	Nine	Nine
	quarter	quarter	quarter	months	months
$ million	2018	2018	2017	2018	2017
Upstream
US	987	999	1,154	3,074	3,524
Non-US	2,167	2,226	2,154	6,665	6,298
	3,154	3,225	3,308	9,739	9,822
Downstream
US	220	221	222	660	657
Non-US	284	293	287	879	840
	504	514	509	1,539	1,497
Other businesses and corporate
US	16	16	17	48	49
Non-US	54	56	70	144	171
	70	72	87	192	220
Total group	3,728	3,811	3,904	11,470	11,539

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Note 8. Production and similar taxes

	Third	Second	Third		Nine	Nine
	quarter	quarter	quarter		months	months
$ million	2018	2018	2017		2018	2017
US	91	89	(69	)	270	8
Non-US	360	442	518		1,080	1,256
	451	531	449		1,350	1,264

Note 9. Earnings per share and shares in issue

Basic earnings per ordinary share (EpS) amounts are calculated by dividing the profit (loss) for the period attributable to ordinary shareholders by the weighted average number of ordinary shares outstanding during the period. During the quarter the company repurchased for cancellation 19 million ordinary shares for a total cost of $139 million, including transaction costs of $1 million, as part of the share buyback programme as announced on 31 October 2017. The number of shares in issue is reduced when shares are repurchased.

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	2018	2018	2017	2018	2017
Results for the period
Profit (loss) for the period attributable to BP shareholders	3,349	2,799	1,769	8,617	3,362
Less: preference dividend	-	1	-	1	1
Profit (loss) attributable to BP ordinary shareholders	3,349	2,798	1,769	8,616	3,361

Number of shares (thousand)_(a)
Basic weighted average number of shares outstanding	20,006,872	19,945,053	19,756,117	19,957,265	19,654,608
ADS equivalent	3,334,478	3,324,175	3,292,686	3,326,210	3,275,768

Weighted average number of shares outstanding used to calculate diluted earnings per share	20,118,456	20,044,277	19,866,745	20,081,256	19,771,579
ADS equivalent	3,353,076	3,340,712	3,311,124	3,346,876	3,295,263

Shares in issue at period-end	20,050,414	19,973,943	19,797,657	20,050,414	19,797,657
ADS equivalent	3,341,735	3,328,991	3,299,609	3,341,735	3,299,609

(a) Excludes treasury shares and includes certain shares that will be issued in the future under employee share-based payment plans.

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Note 10. Dividends

Dividends payable

BP today announced an interim dividend of 10.25 cents per ordinary share which is expected to be paid on 21 December 2018 to ordinary shareholders and American Depositary Share (ADS) holders on the register on 9 November 2018. The corresponding amount in sterling is due to be announced on 10 December 2018, calculated based on the average of the market exchange rates for the four dealing days commencing on 4 December 2018. Holders of ADSs are expected to receive $0.615 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
	2018	2018	2017	2018	2017
Dividends paid per ordinary share
cents	10.250	10.000	10.000	30.250	30.000
pence	7.930	7.444	7.621	22.543	23.536
Dividends paid per ADS (cents)	61.50	60.00	60.00	181.50	180.00
Scrip dividends
Number of shares issued (millions)	89.9	34.5	51.3	147.8	236.5
Value of shares issued ($ million)	638	266	298	1,059	1,360

Note 11. Net Debt*

Net debt ratio*	Third		Second		Third		Nine		Nine
	quarter		quarter		quarter		months		months
$ million	2018		2018		2017		2018		2017
Gross debt	64,135		60,358		65,784		64,135		65,784
Fair value (asset) liability of hedges related to finance debt_(a)	1,234		1,104		(227	)	1,234		(227	)
	65,369		61,462		65,557		65,369		65,557
Less: cash and cash equivalents	26,192		22,185		25,780		26,192		25,780
Net debt	39,177		39,277		39,777		39,177		39,777
Equity	103,420		101,770		100,138		103,420		100,138
Net debt ratio	27.5	%	27.8	%	28.4	%	27.5	%	28.4	%

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Note 11. Net Debt* (continued)

Analysis of changes in net debt	Third		Second		Third		Nine		Nine
	quarter		quarter		quarter		months		months
$ million	2018		2018		2017		2018		2017
Opening balance
Finance debt_(a)	60,358		62,189		63,004		63,230		58,300
Fair value (asset) liability of hedges related to finance debt_(b)	1,104		46		60		175		697
Less: cash and cash equivalents_(c)	22,185		22,242		23,270		25,575		23,484
Opening net debt	39,277		39,993		39,794		37,830		35,513
Closing balance
Finance debt_(a)	64,135		60,358		65,784		64,135		65,784
Fair value (asset) liability of hedges related to finance debt_(b)	1,234		1,104		(227	)	1,234		(227	)
Less: cash and cash equivalents	26,192		22,185		25,780		26,192		25,780
Closing net debt	39,177		39,277		39,777		39,177		39,777
Decrease (increase) in net debt	100		716		17		(1,347	)	(4,264	)
Movement in cash and cash equivalents (excluding exchange adjustments)	4,063		257		2,364		842		1,781
Net cash outflow (inflow) from financing	(3,852	)	524		(1,962	)	(1,944	)	(5,031	)
Other movements	(24	)	(123	)	(186	)	(174	)	(265	)
Movement in net debt before exchange effects	187		658		216		(1,276	)	(3,515	)
Exchange adjustments	(87	)	58		(199	)	(71	)	(749	)
Decrease (increase) in net debt	100		716		17		(1,347	)	(4,264	)

(a) The fair value of finance debt at 30 September 2018 was $64,971 million (1 January 2018 $65,165 million).

(b) 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 $723 million (second quarter 2018 liability of $774 million and third quarter 2017 liability of $883 million) are not included in the calculation of net debt shown above as hedge accounting is not applied for these instruments.

Note 12. Statutory accounts

The financial information shown in this publication, which was approved by the Board of Directors on 29 October 2018, is unaudited and does not constitute statutory financial statements. Audited financial information will be published in BP Annual Report and Form 20-F 2018. BP Annual Report and Form 20-F 2017 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.

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Additional information

Capital expenditure*

	Third	Second	Third	Nine	Nine
	quarter	quarter	quarter	months	months
$ million	2018	2018	2017	2018	2017
Capital expenditure on a cash basis
Organic capital expenditure*	3,730	3,470	3,993	10,738	11,879
Inorganic capital expenditure*_(a)	674	355	470	1,454	1,140
	4,404	3,825	4,463	12,192	13,019

	Third	Second	Third	Nine	Nine
	quarter	quarter	quarter	months	months
$ million	2018	2018	2017	2018	2017
Organic capital expenditure by segment
Upstream
US	854	826	827	2,434	2,273
Non-US	2,073	1,941	2,601	6,126	7,945
	2,927	2,767	3,428	8,560	10,218
Downstream
US	237	232	159	640	460
Non-US	513	382	356	1,342	992
	750	614	515	1,982	1,452
Other businesses and corporate
US	6	7	10	20	34
Non-US	47	82	40	176	175
	53	89	50	196	209
	3,730	3,470	3,993	10,738	11,879
Organic capital expenditure by geographical area
US	1,097	1,065	996	3,094	2,767
Non-US	2,633	2,405	2,997	7,644	9,112
	3,730	3,470	3,993	10,738	11,879

(a) Third quarter 2018 includes a $525-million deposit payment made under the agreement, announced in July, to acquire from BHP a portfolio of US onshore unconventional oil and gas assets in the Permian and Eagle Ford basins in Texas and in the Haynesville gas basin in Texas and Louisiana. The deposit payment has been included within Acquisitions, net of cash acquired in the condensed group cash flow statement. The transaction is expected to complete on 31 October 2018. Nine months 2018 also includes amounts relating to the 25-year extension to our ACG production-sharing agreement* in Azerbaijan. 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.

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Non-operating items*

	Third		Second		Third		Nine		Nine
	quarter		quarter		quarter		months		months
$ million	2018		2018		2017		2018		2017
Upstream
Impairment and gain (loss) on sale of businesses and fixed assets_(a)	(231	)	81		18		(124	)	(382	)
Environmental and other provisions	-		-		-		-		-
Restructuring, integration and rationalization costs	(17	)	(62	)	(3	)	(78	)	(20	)
Fair value gain (loss) on embedded derivatives	1		9		1		17		31
Other	5		(1	)	(162	)	(134	)	(156	)
	(242	)	27		(146	)	(319	)	(527	)
Downstream
Impairment and gain (loss) on sale of businesses and fixed assets	(19	)	(1	)	(35	)	(34	)	110
Environmental and other provisions	-		-		-		-		-
Restructuring, integration and rationalization costs	(16	)	(74	)	(19	)	(126	)	(102	)
Fair value gain (loss) on embedded derivatives	-		-		-		-		-
Other	(2	)	(150	)	(1	)	(155	)	(1	)
	(37	)	(225	)	(55	)	(315	)	7
Rosneft
Impairment and gain (loss) on sale of businesses and fixed assets	(64	)	-		-		(64	)	-
Environmental and other provisions	-		-		-		-		-
Restructuring, integration and rationalization costs	-		-		-		-		-
Fair value gain (loss) on embedded derivatives	-		-		-		-		-
Other	-		-		-		-		-
	(64	)	-		-		(64	)	-
Other businesses and corporate
Impairment and gain (loss) on sale of businesses and fixed assets	(255	)	(1	)	1		(254	)	(6	)
Environmental and other provisions	(45	)	1		-		(65	)	(3	)
Restructuring, integration and rationalization costs	(33	)	(30	)	(6	)	(78	)	(37	)
Fair value gain (loss) on embedded derivatives	-		-		-		-		-
Gulf of Mexico oil spill - business economic loss claims_(b)	(69	)	(249	)	-		(318	)	(260	)
Gulf of Mexico oil spill - other_(b)	(59	)	(184	)	(84	)	(329	)	(206	)
Other	(9	)	(85	)	27		(153	)	104
	(470	)	(548	)	(62	)	(1,197	)	(408	)
Total before interest and taxation	(813	)	(746	)	(263	)	(1,895	)	(928	)
Finance costs_(b)	(119	)	(118	)	(122	)	(357	)	(369	)
Total before taxation	(932	)	(864	)	(385	)	(2,252	)	(1,297	)
Taxation credit (charge) on non-operating items	283		141		111		512		503
Taxation - impact of US tax reform_(c)	-		-		-		121		-
Total after taxation for period	(649	)	(723	)	(274	)	(1,619	)	(794	)

(a) Nine months 2017 includes an impairment charge arising following the announcement of the agreement to sell the Forties Pipeline System business to INEOS.

(b) See Note 2 for further details regarding costs relating to the Gulf of Mexico oil spill.

(c) Fourth quarter 2017 included the impact of US tax reform, which reduced the US federal corporate income tax rate from 35% to 21% effective from 1 January 2018. Nine months 2018 reflects a further impact following a clarification of the tax reform. The impact of the US tax reform has been treated as a non-operating item because it is not considered to be part of underlying business operations, has a material impact upon the reported result and is substantially impacted by Gulf of Mexico oil spill charges, which are also treated as non-operating items. Separate disclosure is considered meaningful and relevant to investors.

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Non-GAAP information on fair value accounting effects

	Third		Second		Third		Nine		Nine
	quarter		quarter		quarter		months		months
$ million	2018		2018		2017		2018		2017
Favourable (adverse) impact relative to management's measure of performance
Upstream	(285	)	(21	)	(174	)	(185	)	178
Downstream	175		(390	)	(108	)	(275	)	(52	)
	(110	)	(411	)	(282	)	(460	)	126
Taxation credit (charge)	12		101		70		102		(47	)
	(98	)	(310	)	(212	)	(358	)	79

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. 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 other transportation, 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, transportation 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 derivative instruments used to risk manage certain oil, gas and other 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.

In addition, from the first quarter 2018 fair value accounting effects include changes in the fair value of the near-term portions of LNG contracts that fall within BP's risk management framework. LNG contracts are not considered derivatives, because there is insufficient market liquidity, and they are therefore accrual accounted under IFRS. However, oil and natural gas derivative financial instruments (used to risk manage the near-term portions of the LNG contracts) are fair valued under IFRS. The fair value accounting effect reduces timing differences between recognition of the derivative financial instruments used to risk manage the LNG contracts and the recognition of the LNG contracts themselves, which therefore gives a better representation of performance in each period. Comparative information has not been restated on the basis that the effect was not material.

For the second quarter of 2018, Downstream fair value accounting effects arose mainly due to changes in the fair value of transportation contracts in the US, which are reflected in the underlying result to eliminate measurement differences in the reported IFRS result in relation to the recognition of gains and losses, as described above.

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Non-GAAP information on fair value accounting effects (continued)

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	2018		2018		2017		2018		2017
Upstream
Replacement cost profit (loss) before interest and tax adjusted for fair value accounting effects	3,757		3,535		1,416		10,345		3,115
Impact of fair value accounting effects	(285	)	(21	)	(174	)	(185	)	178
Replacement cost profit (loss) before interest and tax	3,472		3,514		1,242		10,160		3,293
Downstream
Replacement cost profit (loss) before interest and tax adjusted for fair value accounting effects	2,074		1,230		2,283		5,077		5,500
Impact of fair value accounting effects	175		(390	)	(108	)	(275	)	(52	)
Replacement cost profit (loss) before interest and tax	2,249		840		2,175		4,802		5,448
Total group
Profit (loss) before interest and tax adjusted for fair value accounting effects	6,273		5,967		3,803		16,674		7,492
Impact of fair value accounting effects	(110	)	(411	)	(282	)	(460	)	126
Profit (loss) before interest and tax	6,163		5,556		3,521		16,214		7,618

Readily marketable inventory* (RMI)

	30 September	31 December
$ million	2018	2017
RMI at fair value*	5,447	5,661
Paid-up RMI*	2,004	2,688

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 31 for a more detailed definition of RMI. RMI, RMI at fair value, paid-up RMI and unpaid 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	2018		2017
Reconciliation of total inventory to paid-up RMI
Inventories as reported on the group balance sheet under IFRS	21,894		19,011
Less: (a) inventories that are not oil and oil products and (b) oil and oil product inventories that are not risk-managed by IST	(16,790	)	(13,929	)
	5,104		5,082
Plus: difference between RMI at fair value and RMI on an IFRS basis	343		579
RMI at fair value	5,447		5,661
Less: unpaid RMI* at fair value	(3,443	)	(2,973	)
Paid-up RMI	2,004		2,688

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Working capital* reconciliation

	Third		Nine
	quarter		months
$ million	2018		2018
Movements in inventories and other current and non-current assets and liabilities as per condensed group cash flow statement	(1,573	)	(5,541	)
Adjustments to exclude movements in inventories and other current and non-current assets and liabilities for the Gulf of Mexico oil spill (Note 2)	538		2,819
Adjusted for Inventory holding gains (losses)* (Note 5)
Upstream	1		6
Downstream	343		1,608
Working capital release (build)	(691	)	(1,108	)

Realizations* and marker prices

	Third	Second	Third	Nine	Nine
	quarter	quarter	quarter	months	months
	2018	2018	2017	2018	2017
Average realizations_(a)
Liquids* ($/bbl)
US	65.22	62.47	43.58	61.76	44.87
Europe	73.90	71.70	50.02	70.51	50.32
Rest of World	71.95	69.88	49.54	68.41	49.49
BP Average	69.68	67.24	47.45	66.11	47.87
Natural gas ($/mcf)
US	2.22	1.96	2.34	2.15	2.39
Europe	7.79	7.04	5.10	7.33	4.98
Rest of World	4.36	4.16	3.03	4.24	3.42
BP Average	3.86	3.65	2.89	3.77	3.18
Total hydrocarbons* ($/boe)
US	43.20	40.77	31.30	41.21	32.68
Europe	68.54	64.91	45.26	64.80	44.33
Rest of World	45.51	42.89	33.13	42.98	34.76
BP Average	46.14	43.37	33.23	43.64	34.63
Average oil marker prices ($/bbl)
Brent	75.16	74.39	52.08	72.13	51.84
West Texas Intermediate	69.63	68.02	48.18	66.90	49.32
Western Canadian Select	40.33	49.76	38.16	42.35	38.49
Alaska North Slope	75.26	73.93	52.04	72.19	52.15
Mars	70.79	69.47	48.46	67.63	48.31
Urals (NWE - cif)	73.98	72.21	50.73	70.50	50.39
Average natural gas marker prices
Henry Hub gas price_(b) ($/mmBtu)	2.91	2.80	2.99	2.90	3.17
UK Gas - National Balancing Point (p/therm)	64.46	53.88	41.59	58.83	42.61

(a) Based on sales of consolidated subsidiaries only - this excludes equity-accounted entities.

(b) Henry Hub First of Month Index.

Exchange rates

	Third	Second	Third	Nine	Nine
	quarter	quarter	quarter	months	months
	2018	2018	2017	2018	2017
$/£ average rate for the period	1.30	1.36	1.31	1.35	1.28
$/£ period-end rate	1.31	1.31	1.34	1.31	1.34

$/€ average rate for the period	1.16	1.19	1.17	1.19	1.11
$/€ period-end rate	1.17	1.16	1.18	1.17	1.18

Rouble/$ average rate for the period	65.54	62.13	58.99	61.52	58.33
Rouble/$ period-end rate	65.76	63.07	57.94	65.76	57.94

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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 270-273 of BP Annual Report and Form 20-F 2017, and page 34 of BP p.l.c. Group results second quarter and half-year 2018.

Other legal proceedings

Prudhoe Bay leak On 12 May 2008, a BP p.l.c. shareholder filed a consolidated complaint alleging violations of federal securities law on behalf of a putative class of BP p.l.c. shareholders, based on alleged misrepresentations concerning the integrity of the Prudhoe Bay pipeline operated by BP Exploration (Alaska) Inc. before its shutdown on 6 August 2006 following oil leaks. On 7 December 2015, the complaint was dismissed with prejudice and plaintiffs appealed to the Ninth Circuit Court of Appeals. On 31 July 2018 the Ninth Circuit granted the parties' motion to dismiss the appeal, voluntarily ending the litigation.

Scharfstein v. BP West Coast Products, LLC A class action lawsuit was filed against BP West Coast Products, LLC in Oregon State Court under the Oregon Unlawful Trade Practices Act on behalf of customers who used a debit card at ARCO gasoline stations in Oregon during the period 1 January 2011 to 30 August 2013, alleging that ARCO sites in Oregon failed to provide sufficient notice of the 35 cents per transaction debit card fee. On 31 May 2016 the trial court entered a judgement against BP West Coast Products, LLC for the amount of $417.3 million. On 31 May 2018 the Oregon Court of Appeals affirmed the trials court's ruling. BP filed a Petition for Review to the Oregon Supreme Court on 16 August 2018 and awaits the court's decision.

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. Non-GAAP measures are sometimes referred to as alternative performance measures.

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). They reflect the difference between the way BP manages the economic exposure and internally measures performance of certain activities and the way those activities are measured under IFRS. Further information on fair value accounting effects is provided on page 28.

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 26.

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.

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Glossary (continued)

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 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'. The nearest equivalent GAAP measures on an IFRS basis are gross debt and gross debt ratio. A reconciliation of gross debt to net debt is provided on page 24.

We are unable to present reconciliations of forward-looking information for net debt ratio to gross debt ratio, because without unreasonable efforts, we are unable to forecast accurately certain adjusting items required to present a meaningful comparable GAAP forward-looking financial measure. These items include fair value asset (liability) of hedges related to finance debt and cash and cash equivalents, that are difficult to predict in advance in order to include in a GAAP estimate.

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.

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 27.

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 Gulf of Mexico oil spill payments is a non-GAAP measure. It is 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 net cash provided by operating activities excluding amounts related to the Gulf of Mexico oil spill is a useful measure as it 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 26.

We are unable to present reconciliations of forward-looking information for organic capital expenditure to total cash capital expenditure, because without unreasonable efforts, we are unable to forecast accurately the adjusting item, inorganic capital expenditure, that is difficult to predict in advance in order to derive the nearest GAAP estimate.

Production-sharing agreement (PSA) is an arrangement through which an oil and gas 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, RMI at fair value, Paid-up RMI and Unpaid RMI are non-GAAP measures. Further information is provided on page 29.

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.

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.

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Glossary (continued)

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 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. A reconciliation to GAAP information is provided on page 1. RC profit or loss before interest and tax is the measure of profit or loss that is required to be disclosed for each operating segment under IFRS.

RC profit or loss per share is a non-GAAP measure. Earnings per share is defined in Note 9. 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 effective tax rate (ETR) is a non-GAAP measure. The underlying ETR is calculated by dividing taxation on an underlying replacement cost (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. Information on underlying RC profit or loss is provided below. BP believes it is helpful to disclose the underlying 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.

We are unable to present reconciliations of forward-looking information for underlying ETR to ETR on profit or loss for the period, because without unreasonable efforts, we are unable to forecast accurately certain adjusting items required to present a meaningful comparable GAAP forward-looking financial measure. These items include the taxation on inventory holding gains and losses, non-operating items and fair value accounting effects, that are difficult to predict in advance in order to include in a GAAP estimate.

Underlying production is production after adjusting for acquisitions and divestments and entitlement impacts in our production-sharing agreements.

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 27 and 28 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. A reconciliation to GAAP information is provided on page 1.

Underlying RC profit or loss per share is a non-GAAP measure. Earnings per share is defined in Note 9. 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 plant reliability (BP-operated) is calculated taking 100% less the ratio of total unplanned plant deferrals divided by installed production capacity. Unplanned plant deferrals are associated with the topside plant and where applicable the subsea equipment (excluding wells and reservoir). Unplanned plant deferrals include breakdowns, which does not include Gulf of Mexico weather related downtime.

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Glossary (continued)

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.

Wellwork is activities undertaken on previously completed wells with the primary objective to restore or increase production.

Working capital - Change in working capital is movements in inventories and other current and non-current assets and liabilities as reported in the condensed group cash flow statement. Change in working capital adjusted for inventory holding gains/losses is a non-GAAP measure. It is calculated by adjusting for inventory holding gains/losses reported in the period and this therefore represents what would have been reported as movements in inventories and other current and non-current assets and liabilities, if the starting point in determining net cash provided by operating activities had been replacement cost profit rather than profit for the period. The nearest equivalent measure on an IFRS basis for this is movements in inventories and other current and non-current assets and liabilities. In the context of describing operating cash flow excluding Gulf of Mexico oil spill payments, change in working capital also excludes movements in inventories and other current and non-current assets and liabilities relating to the Gulf of Mexico oil spill. See page 30 for further details.

BP utilizes various arrangements in order to manage its working capital including discounting of receivables and, in the supply and trading business, the active management of supplier payment terms, inventory and collateral.

Other matters

As previously disclosed, the North Sea Rhum field (Rhum) is owned under a 50:50 unincorporated joint arrangement between BP and Iranian Oil Company (U.K.) Limited (IOC). In 2015, the US and the EU implemented temporary, limited and reversible relief of certain sanctions related to Iran pursuant to a Joint Comprehensive Plan of Action (JCPOA). On 29 September 2017, BP obtained a specific OFAC License relating to the ongoing operation of the Rhum field, such licence expiring on 30 September 2018.

On 21 November 2017, BP announced that it had agreed to sell certain of its assets in the North Sea, including its ownership stake, and the transfer of its role as operator, in the Rhum joint arrangement to Serica Energy plc (Serica), with the aim to complete the sale and transfer of operatorship in the third quarter of 2018 subject to regulatory and third party approvals.

In May 2018, the U.S. government announced its planned withdrawal from the JCPOA, and tasked OFAC with implementing the full re-imposition of both primary and secondary sanctions in respect of Iran by the end of a wind-down period, which, for Rhum, expires on 4 November 2018. On 9 October 2018 Serica announced that Serica and BP had received a conditional licence relating to the ongoing operation of the Rhum field from the U.S. Office of Foreign Assets Control (OFAC). The licence is valid until 31 October 2019 and is conditional upon arrangements being put in place by 4 November 2018 relating to the interest in the Rhum field held by IOC. Subject to the fulfilment of the conditions, the OFAC License will enable production from the Rhum field to continue and BP and Serica to proceed to complete the sale and transfer.

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Cautionary statement

In order to utilize the 'safe harbor' provisions of the United States Private Securities Litigation Reform Act of 1995 (the 'PSLRA') and the general doctrine of cautionary statements, 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 and circumstances - 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: expectations regarding the expected underlying ETR for 2018; expectations regarding the expected quarterly dividend payment and timing of such payment; plans and expectations to maintain a strong financial framework and capital discipline; expectations regarding 2018 organic capital expenditure; plans and expectations with respect to gearing; expectations regarding divestment transactions, 2018 divestment proceeds and use of divestment proceeds to reduce debt; expectations regarding Upstream fourth-quarter 2018 reported production; expectations regarding Downstream fourth-quarter 2018 refining margins and turnaround activity, including at the Whiting refinery; expectations regarding second-half 2018 decommissioning provision impacts; expectations regarding the amount of Rosneft dividends payable to BP; expectations regarding BP's operated position in the Santos basin in Brazil; plans and expectations regarding the Lightsource BP joint venture with Hassan Allam Holding; plans and expectations regarding the agreements relating to BP's increase in its interest in the Clair field and divestment of its interest in the Greater Kuparuk Area and holding in the Kuparuk Transportation Company; plans and expectations regarding BP's acquisition of onshore-US oil and gas assets from BHP, including expectations regarding the purchase price, timing of closing, financing of the transaction and longer-term value creation; plans and expectations regarding share buybacks, including to offset the impact of dilution from the scrip programme; plans and expectations regarding the operation of and sale of BP's interest in the Rhum field; and expectations with respect to the timing and amount of future payments relating to the Gulf of Mexico oil spill including payments for full-year 2018 and 2012 PSC settlement payments. 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; amounts ultimately payable and timing of payments relating to the Gulf of Mexico oil spill; 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 results announcement for the period ended 30 June 2018 and "Risk factors" in BP Annual Report and Form 20-F 2017 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 4962	+1 281 892 3421

BP p.l.c.'s LEI Code 213800LH1BZH3D16G760

This information is provided by RNS, the news service of the London Stock Exchange. RNS is approved by the Financial Conduct Authority to act as a Primary Information Provider in the United Kingdom. Terms and conditions relating to the use and distribution of this information may apply. For further information, please contact rns@lseg.com or visit www.rns.com.

END

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