Edgar Filing: BP PLC

Document

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 6-K

Report of Foreign Private Issuer

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

the Securities Exchange Act of 1934

for the period ended 31 March 2018

Commission File Number 1-06262

BP p.l.c.

(Translation of registrant’s name into English)

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

(Address of principal executive offices)

Indicate by check mark whether the registrant files or will file annual reports under cover of Form 20-F or Form 40-F:




	Form 20-F x Form 40-F ¨

Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(1): ¨
Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(1): ¨

THIS REPORT ON FORM 6-K SHALL BE DEEMED TO BE INCORPORATED BY REFERENCE IN THE PROSPECTUS INCLUDED IN THE REGISTRATION STATEMENT ON FORM F-3 (FILE NOS. 333-208478 AND 333-208478-01) OF BP CAPITAL MARKETS p.l.c. AND BP p.l.c.; THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-67206) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-79399) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-103924) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-123482) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-123483) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-131583) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-131584) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-132619) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-146868) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-146870) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-146873) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-173136) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-177423) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-179406) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-186462) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-186463) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-199015) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-200794) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-200795) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-207188) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-207189) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-210316) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-210318) OF BP p.l.c., AND TO BE A PART THEREOF FROM THE DATE ON WHICH THIS REPORT IS FURNISHED, TO THE EXTENT NOT SUPERSEDED BY DOCUMENTS OR REPORTS SUBSEQUENTLY FILED OR FURNISHED.

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BP p.l.c. and subsidiaries

Form 6-K for the period ended 31 March 2018_(a)



		Page
1.	Management’s Discussion and Analysis of Financial Condition and Results of Operations for the period January-March 2018_(b)	3-13, 26-31, 32-34

2.	Consolidated Financial Statements including Notes to Consolidated Financial Statements for the period January-March 2018	14-25

3.	Legal proceedings	32

4.	Cautionary statement	35

5.	Computation of Ratio of Earnings to Fixed Charges	36

6.	Capitalization and Indebtedness	37

7.	Signatures	38


^(a)	In this Form 6-K, references to the first quarter 2018 and first quarter 2017 refer to three-month periods ended 31 March 2018 and 31 March 2017 respectively.


^(b)	This discussion should be read in conjunction with the consolidated financial statements and related notes provided elsewhere in this Form 6-K and with the information, including the consolidated financial statements and related notes, in BP’s Annual Report on Form 20-F for the year ended 31 December 2017.

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Group results first quarter 2018



Highlights	Momentum continues into 2018 as BP delivers strong 1Q profit


•	Profit for the first quarter was $2,469 million, compared with $1,449 million for the same period in 2017, a rise of 70%. Underlying replacement cost profit* for the first quarter was $2,586 million, compared with $1,510 million for the same period in 2017, a rise of 71%.


•	Operating cash flow* in the quarter was $3,646 million including the impact of post-tax Gulf of Mexico oil spill payments of $1,714 million_(a). Operating cash flow was also negatively impacted by a $1,810 million increase in working capital driven by higher oil prices and seasonal inventory builds.


•	Upstream reported the strongest quarter since third quarter 2014 on both a replacement cost and underlying basis.


•	Reported oil and gas production was 3.7 million barrels of oil equivalent a day in the quarter, 6% higher than the first quarter of 2017. Upstream production, excluding Rosneft, was 9% higher, supported by continued ramp up of major projects. Upstream plant reliability was 96% for the quarter.


•	First Upstream major project of 2018, Atoll in Egypt, started production; to date in 2018, final investment decisions have been taken on four new projects – in Oman, India and two in the UK North Sea.


•	Continued Downstream earnings growth with strong refining availability in the US.


•	Gulf of Mexico oil spill payments in the quarter were $1.6 billion on a pre-tax basis, including $1.2 billion for the final payment relating to the 2012 Department of Justice settlement.


•	BP continued its share buyback programme in the quarter, buying 18 million shares for a cost of $120 million.


•	Dividend unchanged at 10 cents per share.


_(a)	Operating cash flow excluding Gulf of Mexico oil spill payments is a measure used by management and BP believes it is useful as it allows for meaningful comparisons between reporting periods. It is not however disclosed in this SEC filing because SEC regulations do not permit the inclusion of this non-GAAP metric.



Financial summary	First		First
Financial summary	quarter		quarter
$ million	2018		2017
Profit for the period_(a)	2,469		1,449
Inventory holding (gains) losses*, before tax	(92	)	(66	)
Taxation charge (credit) on inventory holding gains and losses	12		29
RC profit (loss)*	2,389		1,412
Net (favourable) adverse impact of non-operating items* and fair value
accounting effects*, before tax	395		267
Taxation charge (credit) on non-operating items and fair value accounting effects	(198	)	(169	)
Underlying RC profit	2,586		1,510
Profit per ordinary share (cents)	12.40		7.42
Profit per ADS (dollars)	0.74		0.45
RC profit (loss) per ordinary share (cents)*	11.99		7.23
RC profit (loss) per ADS (dollars)	0.72		0.43
Underlying RC profit per ordinary share (cents)*	12.98		7.74
Underlying RC profit per ADS (dollars)	0.78		0.46


^(a)	Profit attributable to BP shareholders.

* See definitions in the Glossary on page 32. RC profit (loss), underlying RC profit and organic capital expenditure are non-GAAP measures.

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 first quarter, BP’s profit was $2,469 million, compared with $1,449 million for the same period in 2017.

RC profit was $2,389 million for the first quarter, compared with $1,412 million a year ago.

Underlying replacement cost (RC) profit was $2,586 million for the first quarter, compared with $1,510 million in 2017, mainly due to higher profits in Upstream, partially offset by a higher tax charge. Underlying RC profit is after adjusting RC profit for a net charge for non-operating items of $247 million and net favourable fair value accounting effects of $50 million (both on a post-tax basis).

See further information on pages 5, 27 and 28.

Non-operating items

Non-operating items amounted to a charge of $456 million pre-tax and $247 million post-tax for the quarter. See further information on page 27.

Effective tax rate

The effective tax rate (ETR) on the profit for the first quarter was 35%, compared with 29% for the same period in 2017. The ETR on RC profit or loss* for the first quarter was 36%, compared with 29% for the same period in 2017. Adjusting for non-operating items and fair value accounting effects, the underlying ETR* for the first quarter was 37%, compared with 33% for the same period a year ago. The underlying ETR for the first quarter was higher than a year ago mainly due to the absence of favourable foreign exchange impacts. In the current environment the underlying ETR in 2018 is expected to be above 40%. ETR on RC profit or loss and underlying ETR are non-GAAP measures.

Dividend

BP today announced a quarterly dividend of 10.00 cents per ordinary share ($0.600 per ADS), which is expected to be paid on 22 June 2018. The corresponding amount in sterling will be announced on 11 June 2018. See page 24 for further information.

Share buybacks

BP repurchased 18 million ordinary shares at a cost of $120 million, including fees and stamp duty, during the first quarter of 2018.

Operating cash flow*

Operating cash flow in the quarter was $3,646 million including the impact of post-tax Gulf of Mexico oil spill payments of $1,714 million. Operating cash flow was also negatively impacted by a $1,810 million increase in working capital driven by higher oil prices and seasonal inventory builds. For the same period in 2017 operating cash flow was $2,114 million including the impact of post-tax Gulf of Mexico oil spill payments of $2,294 million.

Capital expenditure*

Total capital expenditure for the first quarter was $4.0 billion , compared with $4.1 billion for the same period in 2017.

Organic capital expenditure* for the first quarter was $3.5 billion, compared with $3.5 billion for the same period in 2017. We expect organic capital expenditure to be in the range of $15-16 billion for 2018.

Inorganic capital expenditure* for the first quarter was $0.4 billion, compared with $0.5 billion for the same period in 2017.

See page 26 for further information.

Divestment and other proceeds

Divestment proceeds* were $0.2 billion for the first quarter, compared with $0.3 billion for the same period in 2017.

Debt

Gross debt at 31 March 2018 was $62.2 billion compared with $61.8 billion a year ago. Gross debt ratio* at 31 March 2018 was 37.8%, compared with 38.4% a year ago.

Net debt* at 31 March 2018 was $40.0 billion, compared with $38.6 billion a year ago. Gearing* or net debt ratio* at 31 March 2018 was 28.1%, compared with 27.4% at the end of 2017 and 28.0% a year ago. Gearing was higher, following increases in working capital and higher Gulf of Mexico oil spill payments in the quarter. We continue to target gearing in the range of 20-30%. Net debt, net debt ratio and gearing are non-GAAP measures. See page 25 for more information.

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



	First		First
	quarter		quarter
$ million	2018		2017
Underlying RC profit before interest and tax*
Upstream	3,157		1,370
Downstream	1,826		1,742
Rosneft	247		99
Other businesses and corporate	(392	)	(440	)
Consolidation adjustment – UPII*	(160	)	(68	)
Underlying RC profit before interest and tax	4,678		2,703
Finance costs and net finance expense relating to pensions and other
post-retirement benefits	(464	)	(387	)
Taxation on an underlying RC basis	(1,566	)	(763	)
Non-controlling interests	(62	)	(43	)
Underlying RC profit attributable to BP shareholders	2,586		1,510

Reconciliations of underlying RC profit or loss to the nearest equivalent IFRS measure are provided on page 3 for the group and on pages 8-13 for the segments.

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



	First		First
	quarter		quarter
$ million	2018		2017
RC profit (loss) before interest and tax*
Upstream	3,174		1,256
Downstream	1,713		1,706
Rosneft	247		99
Other businesses and corporate_(a)	(571	)	(431	)
Consolidation adjustment – UPII	(160	)	(68	)
RC profit (loss) before interest and tax	4,403		2,562
Finance costs and net finance expense relating to pensions and other
post-retirement benefits	(584	)	(513	)
Taxation on a RC basis	(1,368	)	(594	)
Non-controlling interests	(62	)	(43	)
RC profit (loss) attributable to BP shareholders	2,389		1,412
Inventory holding gains (losses)	92		66
Taxation (charge) credit on inventory holding gains and losses	(12	)	(29	)
Profit for the period attributable to BP shareholders	2,469		1,449


^(a)	Includes costs related to the Gulf of Mexico oil spill. See page 13 and also Note 2 from page 20 for further information on the accounting for the Gulf of Mexico oil spill.

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Strategic progress

Upstream

Upstream production, excluding Rosneft, for the quarter was 2,605mboe/d, a rise of 9.1% on a year earlier, driven by the continued ramp up of production from major projects*. Upstream plant reliability* was 96%, the best quarterly performance on record. Upstream unit production costs* were higher due to increased wellwork* activity in the quarter, but are expected to show continued year-on-year improvement driven by strong operational performance.

The Atoll Phase One project, offshore Egypt, began gas production in the quarter, ahead of schedule and under budget. The project is the first of six Upstream major projects* expected to begin production during 2018.

Since the start of the year, BP has taken final investment decisions on four new projects: Ghazeer, the second phase of the Khazzan development in Oman; KG D6 Satellites, the second project in the integrated KG D6 development offshore India; and the Alligin and Vorlich fields in the UK North Sea.

BP has accessed new acreage in both the US and Mexican regions of the Gulf of Mexico, in the Campos basin offshore Brazil, in Sao Tome & Principe, in Newfoundland, Canada, in Madagascar and in Azerbaijan.

Downstream

Strong performance in fuels marketing; premium fuels volumes were 5% higher than last year and we continued the rollout of BP’s convenience partnership model across our network. The rapid development of BP’s retail presence in Mexico continued with the 200th retail site now open following market entry a year ago.

In manufacturing, BP’s US refineries processed higher levels of advantaged crude than a year ago and BP’s PTA plant in Zhuhai, China set a new production record.

Advancing the energy transition

BP published a new report detailing BP’s lower carbon activities and commitments and setting out targets including maintaining BP’s net operational greenhouse gas emissions at or below 2015 levels out to 2025.

Financial framework

Operating cash flow* in the quarter was $3,646 million including the impact of post-tax Gulf of Mexico oil spill payments of $1,714 million. Operating cash flow was also negatively impacted by a $1,810 million increase in working capital driven by higher oil prices and seasonal inventory builds.

Organic capital expenditure* was $3.5 billion in the first quarter and is expected to total $15-16 billion in 2018.

Divestments and other proceeds totalled $0.2 billion in the quarter. Total proceeds of $2-3 billion are expected in 2018.

Gulf of Mexico oil spill payments of $1.6 billion were made in the quarter, including the final charge under the 2012 Department of Justice criminal settlement. Payments are expected to be just over $3 billion in 2018, weighted to the first half of the year.

Gearing* at the end of the quarter was 28.1%, within BP’s target band of 20-30%. With anticipated weighting of both Gulf of Mexico oil spill payments and divestment proceeds through the year, gearing is expected to trend down through the rest of the year.



Operating metrics	1Q 2018	Financial metrics	1Q 2018
Operating metrics	(vs. 1Q 2017)	Financial metrics	(vs. 1Q 2017)
Tier 1 process safety events*	5	Underlying RC profitⁱ	$2.6bn
Tier 1 process safety events*	(-1)	Underlying RC profitⁱ	(+$1.1bn)
Reported recordable injury frequency*	0.21	Operating cash flow excluding Gulf of Mexico oil spill payments (post-tax)	_(b)
Reported recordable injury frequency*	(-8%)
Group production	3,732mboe/d	Organic capital expenditureⁱⁱ	$3.5bn
Group production	(+5.7%)	Organic capital expenditureⁱⁱ	—
Upstream production (excludes Rosneft segment)	2,605mboe/d	Gulf of Mexico oil spill payments (pre-tax)_(c)	$1.6bn
Upstream production (excludes Rosneft segment)	(+9.1%)	Gulf of Mexico oil spill payments (pre-tax)_(c)	(-$0.7bn)
Upstream unit production costs	$7.69/boe	Divestment proceeds	$0.2bn
Upstream unit production costs	(+6.5%)	Divestment proceeds	(-$0.1bn)
BP-operated Upstream plant reliability_(a)	95.9%	Net debt ratio* (gearing)ⁱⁱⁱ	28.1%
BP-operated Upstream plant reliability_(a)	(+1.0)	Net debt ratio* (gearing)ⁱⁱⁱ	(+0.1)
Refining availability*	94.8%	Dividend per ordinary share_(d)	10.00 cents
Refining availability*	(-0.4)	Dividend per ordinary share_(d)	—


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

^(b)

SEC regulations do not permit inclusion of this non-GAAP metric in this SEC filing. Operating cash flow excluding Gulf of Mexico oil spill payments is calculated by excluding post-tax payments relating to the Gulf of Mexico oil spill from net cash provided by operating activities, as reported in the condensed group cash flow statement. For the first quarter net cash provided by operating activities was $3.6 billion and post-tax Gulf of Mexico oil spill payments were $1.7 billion.


^(c)	Amounts shown are pre-tax, 2017 amounts disclosed were post-tax. Pre-tax amounts give a better indication of the cash outflows arising in the period to settle outstanding liabilities. The equivalent amount on a post-tax basis was $1.7 billion, a reduction of $0.6 billion on the prior year.


^(d)	Represents dividend announced in the quarter (vs. prior year quarter).

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Nearest GAAP equivalent measures
i	Profit for the period:	$2.5bn
ii	Capital expenditure*:	$4.0bn
iii	Gross debt ratio*:	37.8%

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



	First		First
	quarter		quarter
$ million	2018		2017
Profit before interest and tax	3,175		1,250
Inventory holding (gains) losses*	(1	)	6
RC profit before interest and tax	3,174		1,256
Net (favourable) adverse impact of non-operating items* and fair value accounting effects*	(17	)	114
Underlying RC profit (loss) before interest and tax*_(a)	3,157		1,370


^(a)	See page 9 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 first quarter was $3,174 million, compared with $1,256 million for the same period in 2017. The first quarter included a net non-operating charge of $104 million, compared with a net charge of $360 million for the same period in 2017. Fair value accounting effects in the first quarter had a favourable impact of $121 million, compared with a favourable impact of $246 million in the same period of 2017.

After adjusting for non-operating items and fair value accounting effects, the underlying replacement cost profit before interest and tax for the first quarter was $3,157 million, compared with $1,370 million for the same period in 2017. The result for the first quarter mainly reflected higher liquids and gas realizations, higher production due to the ramp-up of major projects* and higher gas marketing and trading results.

Production

Production for the quarter was 2,605mboe/d, 9.1% higher than the first quarter of 2017. Underlying production* for the quarter increased by 13.8%, due to the ramp-up of major projects. The first-quarter reported production reflects the sixth consecutive quarter of growth as well as the highest production since the fourth quarter of 2010.

Key events

On 12 February, BP announced the start of gas production from the Atoll Phase One project (BP 100%), offshore Egypt. Atoll is BP’s first major project to start in 2018.

Also on 12 February, BP confirmed that the governments of Mauritania and Senegal signed an Inter-Government Cooperation Agreement which will enable the development of the BP-operated Tortue/Ahmeyim gas project to continue to move towards a final investment decision.

In February, BP took final investment decisions on the two new North Sea developments, Alligin (BP operator 50%, Shell 50%) and Vorlich satellite fields (BP operator 66%, Ithaca Energy 34%).

In March, BP’s equity interest (14.67%) in the ADNOC Offshore concession in Abu Dhabi expired.

On 9 April, BP announced that, together with its partner the Oman Oil Company Exploration & Production, it has approved the development of Ghazeer (BP operator 60%, Oman Oil Company Exploration & Production 40%), the second phase of the Khazzan gas field in Oman.

On 12 April, BP and state-owned Brazilian oil company Petrobras announced the signing of a memorandum of understanding to form a strategic alliance to jointly explore potential business opportunities both in Brazil and beyond.

On 19 April, BP together with its partner Reliance Industries Limited, announced the sanction of the Satellite Cluster project, the second phase in the development of new deepwater gas fields in Block KG D6 (Reliance Industries Limited operator 60%, BP 30%, and NIKO 10%) off the east coast of India.

On 26 April, BP and the State Oil Company of the Azerbaijan Republic (SOCAR) signed a new production-sharing agreement* for the joint exploration and development of Block D230 in the North Absheron basin in the Azerbaijan sector of the Caspian Sea. The agreement is expected to be ratified by the Azerbaijani parliament before the summer recess.

Outlook

Looking ahead, we expect second-quarter reported production to be lower than the first quarter reflecting the expiration of the Abu Dhabi offshore concession and seasonal turnaround and maintenance activities.

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)



	First		First
	quarter		quarter
$ million	2018		2017
Underlying RC profit before interest and tax
US	526		166
Non-US	2,631		1,204
	3,157		1,370
Non-operating items
US	(145	)	(12	)
Non-US_(a)	41		(348	)
	(104	)	(360	)
Fair value accounting effects
US	(9	)	192
Non-US	130		54
	121		246
RC profit before interest and tax
US	372		346
Non-US	2,802		910
	3,174		1,256
Exploration expense
US	309		40
Non-US	205		372
	514		412
Of which: Exploration expenditure written off	426		261
Production (net of royalties)_(b)
Liquids* (mb/d)
US	448		448
Europe	139		115
Rest of World	731		827
	1,319		1,389
Of which equity-accounted entities	175		213
Natural gas (mmcf/d)
US	1,790		1,594
Europe	217		263
Rest of World	5,456		3,934
	7,463		5,791
Of which equity-accounted entities	478		530
Total hydrocarbons* (mboe/d)
US	757		723
Europe	177		160
Rest of World	1,672		1,505
	2,605		2,388
Of which equity-accounted entities	258		305
Average realizations*_(c)
Total liquids_(d) ($/bbl)	61.40		49.87
Natural gas ($/mcf)	3.78		3.50
Total hydrocarbons($/boe)	41.39		37.19


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


^(b)	Includes BP’s share of production of equity-accounted entities in the Upstream segment.


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


^(d)	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



	First		First
	quarter		quarter
$ million	2018		2017
Profit before interest and tax	1,782		1,804
Inventory holding (gains) losses*	(69	)	(98	)
RC profit before interest and tax	1,713		1,706
Net (favourable) adverse impact of non-operating items*
and fair value accounting effects*	113		36
Underlying RC profit before interest and tax*_(a)	1,826		1,742


^(a)	See page 11 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 first quarter was $1,713 million, compared with $1,706 million for the same period in 2017.

The first quarter includes a net non-operating charge of $53 million, compared with a charge of $76 million for the same period in 2017. Fair value accounting effects had an adverse impact of $60 million in the first quarter, compared with a favourable impact of $40 million for the same period in 2017.

After adjusting for non-operating items and fair value accounting effects, the underlying replacement cost profit before interest and tax for the first quarter was $1,826 million, compared with $1,742 million for the same period in 2017.

Replacement cost profit before interest and tax for the fuels, lubricants and petrochemicals businesses is set out on page 11.

Fuels

The fuels business reported an underlying replacement cost profit before interest and tax of $1,398 million for the first quarter, compared with $1,200 million for the same period in 2017 driven by a higher refining result, partly offset by a lower supply and trading contribution compared with the strong delivery last year. The supply and trading contribution was, however, higher than the fourth quarter.

The refining result for the quarter reflects the benefit from higher North American heavy crude oil discounts, partially offset by pipeline capacity apportionment impacts. The result also benefited from increased commercial optimization, a higher level of advantaged feedstock processed in the US and a lower level of turnaround activity.

The fuels marketing result for the quarter reflects continued strong performance supported by premium fuel volume growth and the continued rollout of our convenience partnership model across our network.

In April, we signed a memorandum of understanding with state-owned Brazilian oil company Petrobras to explore potential joint commercial agreements in Brazil.

Lubricants

The lubricants business reported an underlying replacement cost profit before interest and tax of $331 million for the first quarter, compared with $393 million for the same period in 2017. The result for the quarter reflects continued premium brand growth, more than offset by the adverse lag impact of increasing base oil prices.

During the quarter we significantly strengthened our relationship with Renault through the continuation of our Renault Formula 1 sponsorship with Renault Sport Racing, and we are exploring new opportunities to work globally with the Renault-Nissan-Mitsubishi Alliance. This includes collaborating in a number of areas including fuel and lubricants supply and the joint development of advanced mobility solutions and new technologies.

Petrochemicals

The petrochemicals business reported an underlying replacement cost profit before interest and tax of $97 million for the first quarter, compared with $149 million for the same period in 2017. The result for the quarter reflects an improved margin environment and stronger margin optimization offset by a higher level of turnaround activity. The result was also impacted by the divestment of our interest in the SECCO joint venture, which completed in the fourth quarter of last year.

Outlook

Looking to the second quarter, we expect seasonally higher industry refining margins but lower discounts for North American heavy crude oil. We also expect a significantly higher level of turnaround activity.

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)



	First		First
	quarter		quarter
$ million	2018		2017
Underlying RC profit before interest and tax - by region
US	589		554
Non-US	1,237		1,188
	1,826		1,742
Non-operating items
US	(17	)	(12	)
Non-US	(36	)	(64	)
	(53	)	(76	)
Fair value accounting effects
US	(121	)	(62	)
Non-US	61		102
	(60	)	40
RC profit before interest and tax
US	451		480
Non-US	1,262		1,226
	1,713		1,706

Underlying RC profit before interest and tax - by business_(a)(b)
Fuels	1,398		1,200
Lubricants	331		393
Petrochemicals	97		149
	1,826		1,742
Non-operating items and fair value accounting effects_(c)
Fuels	(110	)	4
Lubricants	(3	)	(3	)
Petrochemicals	—		(37	)
	(113	)	(36	)
RC profit before interest and tax_(a)(b)
Fuels	1,288		1,204
Lubricants	328		390
Petrochemicals	97		112
	1,713		1,706

BP average refining marker margin (RMM)* ($/bbl)	11.7		11.7
Refinery throughputs (mb/d)
US	715		694
Europe	797		801
Rest of World	249		181
	1,761		1,676
Refining availability* (%)	94.8		95.2

Marketing sales of refined products (mb/d)
US	1,096		1,116
Europe	1,045		1,069
Rest of World	481		512
	2,622		2,697
Trading/supply sales of refined products	3,181		2,959
Total sales volumes of refined products	5,803		5,656

Petrochemicals production (kte)
US	499		498
Europe	1,128		1,253
Rest of World	1,391		2,073
	3,018		3,824


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


^(b)	Results from petrochemicals at our Gelsenkirchen and Mülheim sites in Germany is reported in the fuels business.


^(c)	For Downstream, fair value accounting effects arise solely in the fuels business.

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Rosneft



	First		First
	quarter		quarter
$ million	2018_(a)		2017
Profit before interest and tax_(b)	269		73
Inventory holding (gains) losses*	(22	)	26
RC profit before interest and tax	247		99
Net charge (credit) for non-operating items*	—		—
Underlying RC profit before interest and tax*	247		99

Financial results

Replacement cost (RC) profit before interest and tax and underlying RC profit before interest and tax for the first quarter was $247 million, compared with $99 million for the same period in 2017. There were no non-operating items in the first quarter of either year.

Compared with the same period in 2017, the result primarily reflects higher oil prices and a favourable foreign exchange impact.

On 25 April 2018, Rosneft announced that the board of directors had recommended that the annual general meeting (AGM) adopts a resolution to pay dividends of 6.65 roubles per ordinary share, which would bring the total dividend for 2017 to 10.48 roubles per ordinary share, which constitutes 50% of the company’s IFRS net profit. In addition to the dividend received in October 2017 in relation to the results for the first half of 2017, BP expects to receive later this year a dividend of 12.5 billion roubles, after the deduction of withholding tax subject to approval at the AGM.



	First	First
	quarter	quarter
	2018_(a)	2017
Production (net of royalties) (BP share)
Liquids* (mb/d)	902	912
Natural gas (mmcf/d)	1,307	1,334
Total hydrocarbons* (mboe/d)	1,127	1,142


^(a)	The operational and financial information of the Rosneft segment for the first quarter is based on preliminary operational and financial results of Rosneft for the three months ended 31 March 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. 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



	First		First
	quarter		quarter
$ million	2018		2017
Profit (loss) before interest and tax
Gulf of Mexico oil spill	(86	)	(35	)
Other	(485	)	(396	)
Profit (loss) before interest and tax	(571	)	(431	)
Inventory holding (gains) losses*	—		—
RC profit (loss) before interest and tax	(571	)	(431	)
Net charge (credit) for non-operating items*
Gulf of Mexico oil spill	86		35
Other	93		(44	)
Net charge (credit) for non-operating items	179		(9	)
Underlying RC profit (loss) before interest and tax*	(392	)	(440	)
Underlying RC profit (loss) before interest and tax
US	(147	)	(197	)
Non-US	(245	)	(243	)
	(392	)	(440	)
Non-operating items
US	(148	)	(38	)
Non-US	(31	)	47
	(179	)	9
RC profit (loss) before interest and tax
US	(295	)	(235	)
Non-US	(276	)	(196	)
	(571	)	(431	)

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 first quarter was $571 million, compared with $431 million for the same period in 2017.

The result included a net non-operating charge of $179 million, compared with a net non-operating gain of $9 million for the same period in 2017. See Note 2 on page 20 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 first quarter was $392 million, compared with $440 million for the same period in 2017.

Alternative Energy

The net ethanol-equivalent production (which includes ethanol and sugar) for the first quarter was 7.6 million litres, as the harvest period started earlier in 2018. There was no production for the first quarter in 2017 due to the inter-harvest period.

Net wind generation capacity*_(a) was 1,432MW at 31 March 2018 compared with 1,454MW at 31 March 2017. BP’s net share of wind generation for the first quarter was 1,217GWh, compared with 1,159GWh for the same period in 2017.

BP has re-entered solar with a new partnership with Lightsource to combine our scale, relationships and expertise in major projects with Lightsource’s expertise in developing solar projects. BP acquired a 43% equity share in Lightsource for a total consideration of $200 million, payable over three years on 31 January 2018 and has two seats on the board. Lightsource has rebranded as Lightsource BP.


^(a)	Capacity figures for 2017 include 23MW in the Netherlands managed by our Downstream segment.

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Financial statements

Group income statement



	First	First
	quarter	quarter
$ million	2018	2017

Sales and other operating revenues (Note 4)	68,172	55,863
Earnings from joint ventures - after interest and tax	293	205
Earnings from associates - after interest and tax	414	151
Interest and other income	159	122
Gains on sale of businesses and fixed assets	105	45
Total revenues and other income	69,143	56,386
Purchases	51,512	40,975
Production and manufacturing expenses_(a)	5,438	5,255
Production and similar taxes (Note 6)	368	468
Depreciation, depletion and amortization (Note 5)	3,931	3,842
Impairment and losses on sale of businesses and fixed assets	91	453
Exploration expense	514	412
Distribution and administration expenses	2,794	2,353
Profit (loss) before interest and taxation	4,495	2,628
Finance costs_(a)	553	460
Net finance expense relating to pensions and other post retirement benefits	31	53
Profit (loss) before taxation	3,911	2,115
Taxation_(a)	1,380	623
Profit (loss) for the period	2,531	1,492
Attributable to
BP shareholders	2,469	1,449
Non-controlling interests	62	43
	2,531	1,492

Earnings per share (Note 7)
Profit (loss) for the period attributable to BP shareholders
Per ordinary share (cents)
Basic	12.40	7.42
Diluted	12.33	7.38
Per ADS (dollars)
Basic	0.74	0.45
Diluted	0.74	0.44


^(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



	First		First
	quarter		quarter
$ million	2018		2017

Profit (loss) for the period	2,531		1,492
Other comprehensive income
Items that may be reclassified subsequently to profit or loss
Currency translation differences	531		1,214
Exchange (gains) losses on translation of foreign operations reclassified to gain
or loss on sale of businesses and fixed assets	—		1
Available-for-sale investments	—		2
Cash flow hedges and costs of hedging	(82	)	129
Share of items relating to equity-accounted entities, net of tax	155		231
Income tax relating to items that may be reclassified	(90	)	(125	)
	514		1,452
Items that will not be reclassified to profit or loss
Remeasurements of the net pension and other post-retirement benefit liability or asset	865		727
Cash flow hedges that will subsequently be transferred to the balance sheet	13		—
Income tax relating to items that will not be reclassified	(265	)	(246	)
	613		481
Other comprehensive income	1,127		1,933
Total comprehensive income	3,658		3,425
Attributable to
BP shareholders	3,580		3,363
Non-controlling interests	78		62
	3,658		3,425

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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	3,580		78		3,658
Dividends	(1,828	)	(13	)	(1,841	)
Cash flow hedges transferred to the balance sheet, net of tax	1		—		1
Repurchase of ordinary share capital	(120	)	—		(120	)
Share-based payments, net of tax	244		—		244
Transactions involving non-controlling interests, net of tax	(1	)	—		(1	)
At 31 March 2018	100,187		1,978		102,165

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

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

Total comprehensive income	3,363		62		3,425
Dividends	(1,304	)	(15	)	(1,319	)
Share-based payments, net of tax	177		—		177
Share of equity-accounted entities' changes in equity, net of tax	118		—		118
Transactions involving non-controlling interests, net of tax	—		38		38
At 31 March 2017	97,640		1,642		99,282


^(a)	See Note 1 for further information.

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Group balance sheet



	31 March	31 December
$ million	2018	2017
Non-current assets
Property, plant and equipment	129,002	129,471
Goodwill	11,710	11,551
Intangible assets	18,003	18,355
Investments in joint ventures	8,278	7,994
Investments in associates	17,652	16,991
Other investments	1,298	1,245
Fixed assets	185,943	185,607
Loans	571	646
Trade and other receivables	1,479	1,434
Derivative financial instruments	4,626	4,110
Prepayments	1,162	1,112
Deferred tax assets	4,176	4,469
Defined benefit pension plan surpluses	5,134	4,169
	203,091	201,547
Current assets
Loans	267	190
Inventories	20,802	19,011
Trade and other receivables	23,450	24,849
Derivative financial instruments	3,191	3,032
Prepayments	1,202	1,414
Current tax receivable	928	761
Other investments	114	125
Cash and cash equivalents	22,242	25,586
	72,196	74,968
Total assets	275,287	276,515
Current liabilities
Trade and other payables	42,995	44,209
Derivative financial instruments	2,664	2,808
Accruals	3,799	4,960
Finance debt	9,028	7,739
Current tax payable	2,103	1,686
Provisions	3,218	3,324
	63,807	64,726
Non-current liabilities
Other payables	13,961	13,889
Derivative financial instruments	3,657	3,761
Accruals	592	505
Finance debt	53,161	55,491
Deferred tax liabilities	8,284	7,982
Provisions	20,603	20,620
Defined benefit pension plan and other post-retirement benefit plan deficits	9,057	9,137
	109,315	111,385
Total liabilities	173,122	176,111
Net assets	102,165	100,404
Equity
BP shareholders’ equity	100,187	98,491
Non-controlling interests	1,978	1,913
Total equity	102,165	100,404

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Condensed group cash flow statement



	First		First
	quarter		quarter
$ million	2018		2017
Operating activities
Profit (loss) before taxation	3,911		2,115
Adjustments to reconcile profit (loss) before taxation to net cash provided by operating activities
Depreciation, depletion and amortization and exploration expenditure written off	4,357		4,103
Impairment and (gain) loss on sale of businesses and fixed assets	(14	)	408
Earnings from equity-accounted entities, less dividends received	(536	)	(220	)
Net charge for interest and other finance expense, less net interest paid	80		252
Share-based payments	237		162
Net operating charge for pensions and other post-retirement benefits, less
contributions and benefit payments for unfunded plans	(202	)	(73	)
Net charge for provisions, less payments	144		(177	)
Movements in inventories and other current and non-current assets and liabilities	(3,398	)	(3,600	)
Income taxes paid	(933	)	(856	)
Net cash provided by operating activities	3,646		2,114
Investing activities
Expenditure on property, plant and equipment, intangible and other assets	(3,586	)	(3,823	)
Acquisitions, net of cash acquired	—		(42	)
Investment in joint ventures	(39	)	(20	)
Investment in associates	(338	)	(183	)
Total cash capital expenditure	(3,963	)	(4,068	)
Proceeds from disposal of fixed assets	85		188
Proceeds from disposal of businesses, net of cash disposed	82		73
Proceeds from loan repayments	9		14
Net cash used in investing activities	(3,787	)	(3,793	)
Financing activities
Net issue (repurchase) of shares	(110	)	—
Proceeds from long-term financing	122		3,713
Repayments of long-term financing	(1,157	)	(917	)
Net increase (decrease) in short-term debt	(349	)	315
Increase in non-controlling interests	(1	)	30
Dividends paid - BP shareholders	(1,829	)	(1,304	)
- non-controlling interests	(13	)	(15	)
Net cash provided by (used in) financing activities	(3,337	)	1,822
Currency translation differences relating to cash and cash equivalents	145		167
Increase (decrease) in cash and cash equivalents	(3,333	)	310
Cash and cash equivalents at beginning of period_(a)	25,575		23,484
Cash and cash equivalents at end of period	22,242		23,794


^(a)	See Note 1 for further information.

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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 has 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’

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 relates 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 have not been 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 9 (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 liability	(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	)

IFRS 15 ‘Revenue from Contracts with Customers’

BP has elected to apply the ‘modified retrospective’ approach to transition permitted by IFRS 15 under which comparative financial information is not restated. The standard did not have a material effect on the group's financial statements as at 1 January 2018 and so no transition adjustment has been made.

An analysis of revenue from contracts with customers by product is presented in Note 4. 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.

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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 pre-tax charge for the first quarter of $86 million which includes the latest estimate for claims and associated administration costs, and $120 million for finance costs relating to the unwinding of discounting effects relating to payables. The cumulative pre-tax income statement charge since the incident, in April 2010, amounts to $65,971 million.

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



	First		First
	quarter		quarter
$ million	2018		2017
Income statement
Production and manufacturing expenses	86		35
Profit (loss) before interest and taxation	(86	)	(35	)
Finance costs	120		126
Profit (loss) before taxation	(206	)	(161	)
Taxation	61		48
Profit (loss) for the period	(145	)	(113	)



	31 March		31 December
$ million	2018		2017
Balance sheet
Current assets
Trade and other receivables	244		252
Current tax receivable	263		—
Current liabilities
Trade and other payables	(894	)	(2,089	)
Provisions	(1,246	)	(1,439	)
Net current assets (liabilities)	(1,633	)	(3,276	)
Non-current assets
Deferred tax assets	1,813		2,067
Non-current liabilities
Other payables	(12,375	)	(12,253	)
Provisions	(985	)	(1,141	)
Deferred tax liabilities	3,780		3,634
Net non-current assets (liabilities)	(7,767	)	(7,693	)
Net assets (liabilities)	(9,400	)	(10,969	)

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Note 2. Gulf of Mexico oil spill (continued)



	First		First
	quarter		quarter
$ million	2018		2017
Cash flow statement - Operating activities
Profit (loss) before taxation	(206	)	(161	)
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	120		126
Net charge for provisions, less payments	54		(5	)
Movements in inventories and other current and non-current assets and liabilities	(1,588	)	(2,254	)
Pre-tax cash flows	(1,620	)	(2,294	)

Cash outflows in 2017 and 2018 shown above include payments made under the 2012 agreement with the US government to resolve all federal criminal claims arising from the incident. Included in the current quarter cash outflow is $1,209 million relating to the final payment under the 2012 Department of Justice plea agreement. Net cash from operating activities relating to the Gulf of Mexico oil spill, on a post-tax basis, amounted to an outflow of $1,714 million in the first quarter. For the same period in 2017, the amount was an outflow of $2,294 million.

(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 January 2018	2,580
Increase in provision	65
Reclassified to other payables	(59	)
Utilization	(355	)
At 31 March 2018	2,231

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

PSC settlement

The provision reflects 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. 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. The 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 (including how such resolution may be impacted by the May 2017 Fifth Circuit opinion), the amounts payable may differ from those currently provided.

The settlement programme is expected to issue determinations with respect to remaining BEL claims in the first half of 2018. There is uncertainty around how these claims will ultimately be determined, including in relation to the impact of the May 2017 Fifth Circuit opinion on the determination of such claims.

Payments to resolve outstanding claims under the PSC settlement are now 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.

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Note 2. Gulf of Mexico oil spill (continued)

Other payables

Other payables include amounts payable under the consent decree and settlement agreement with the United States and the five Gulf coast states for natural resource damages, state claims and Clean Water Act penalties, BP’s remaining commitment to fund the Gulf of Mexico Research Initiative, and amounts payable for certain economic loss and property damage claims.

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

Note 3. Analysis of replacement cost profit (loss) before interest and tax and reconciliation to profit (loss) before taxation



	First		First
	quarter		quarter
$ million	2018		2017
Upstream	3,174		1,256
Downstream	1,713		1,706
Rosneft	247		99
Other businesses and corporate_(a)	(571	)	(431	)
	4,563		2,630
Consolidation adjustment - UPII*	(160	)	(68	)
RC profit (loss) before interest and tax*	4,403		2,562
Inventory holding gains (losses)*
Upstream	1		(6	)
Downstream	69		98
Rosneft (net of tax)	22		(26	)
Profit (loss) before interest and tax	4,495		2,628
Finance costs	553		460
Net finance expense relating to pensions and other post-retirement benefits	31		53
Profit (loss) before taxation	3,911		2,115

RC profit (loss) before interest and tax*
US	359		513
Non-US	4,044		2,049
	4,403		2,562


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

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Note 4. Sales and other operating revenues



	First	First
	quarter	quarter
$ million	2018	2017
By segment
Upstream	13,870	11,327
Downstream	61,406	50,080
Other businesses and corporate	343	285
	75,619	61,692

Less: sales and other operating revenues between segments
Upstream	6,733	5,777
Downstream	482	(86	)
Other businesses and corporate	232	138
	7,447	5,829

Third party sales and other operating revenues
Upstream	7,137	5,550
Downstream	60,924	50,166
Other businesses and corporate	111	147
Total sales and other operating revenues	68,172	55,863

By geographical area
US	23,613	21,152
Non-US	51,240	40,020
	74,853	61,172
Less: sales and other operating revenues between areas	6,681	5,309
	68,172	55,863

Sales and other operating revenues include the following in relation to revenues from contracts with customers:
Crude oil	14,917	10,996
Oil products	44,130	36,601
Natural gas, LNG and NGLs	5,159	3,838
Non-oil products and other revenues from contracts with customers	3,495	2,864
Revenues from contracts with customers_(a)	67,701	54,299


^(a)	See Note 1 for further information.

Note 5. Depreciation, depletion and amortization



	First	First
	quarter	quarter
$ million	2018	2017
Upstream
US	1,088	1,237
Non-US	2,272	2,054
	3,360	3,291
Downstream
US	219	216
Non-US	302	279
	521	495
Other businesses and corporate
US	16	16
Non-US	34	40
	50	56
Total group	3,931	3,842

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Note 6. Production and similar taxes



	First	First
	quarter	quarter
$ million	2018	2017
US	90	36
Non-US	278	432
	368	468

Note 7. 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 18 million ordinary shares for a total cost of $120 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.



	First	First
	quarter	quarter
$ million	2018	2017
Results for the period
Profit (loss) for the period attributable to BP shareholders	2,469	1,449
Less: preference dividend	—	—
Profit (loss) attributable to BP ordinary shareholders	2,469	1,449

Number of shares (thousand)_(a)
Basic weighted average number of shares outstanding	19,918,700	19,518,500
ADS equivalent	3,319,783	3,253,083

Weighted average number of shares outstanding used to calculate diluted earnings per share	20,030,656	19,621,566
ADS equivalent	3,338,442	3,270,261

Shares in issue at period-end	19,943,591	19,664,528
ADS equivalent	3,323,931	3,277,421


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

Note 8. Dividends

Dividends payable

BP today announced an interim dividend of 10.00 cents per ordinary share which is expected to be paid on 22 June 2018 to shareholders and American Depositary Share (ADS) holders on the register on 11 May 2018. The corresponding amount in sterling is due to be announced on 11 June 2018, calculated based on the average of the market exchange rates for the four dealing days commencing on 5 June 2018. Holders of ADSs are expected to receive $0.600 per ADS (less applicable fees). A scrip dividend alternative is available, allowing shareholders to elect to receive their dividend in the form of new ordinary shares and ADS holders in the form of new ADSs. Details of the first quarter dividend and timetable are available at bp.com/dividends and details of the scrip dividend programme are available at bp.com/scrip.



	First	First
	quarter	quarter
	2018	2017
Dividends paid per ordinary share
cents	10.000	10.000
pence	7.169	8.159
Dividends paid per ADS (cents)	60.00	60.00
Scrip dividends
Number of shares issued (millions)	23.4	115.1
Value of shares issued ($ million)	155	642

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Note 9. Net Debt*



Net debt ratio*	First	Fourth	First
	quarter	quarter	quarter
$ million	2018	2017	2017
Gross debt	62,189	63,230	61,832
Fair value (asset) liability of hedges related to finance debt_(a)	46	175	597
	62,235	63,405	62,429
Less: cash and cash equivalents	22,242	25,586	23,794
Net debt	39,993	37,819	38,635
Equity	102,165	100,404	99,282
Net debt ratio	28.1%	27.4%	28.0%



Analysis of changes in net debt	First		Fourth		First
	quarter		quarter		quarter
$ million	2018		2017		2017
Opening balance
Finance debt	63,230		65,784		58,300
Fair value (asset) liability of hedges related to finance debt_(a)	175		(227	)	697
Less: cash and cash equivalents_(b)	25,575		25,780		23,484
Opening net debt	37,830		39,777		35,513
Closing balance
Finance debt	62,189		63,230		61,832
Fair value (asset) liability of hedges related to finance debt_(a)	46		175		597
Less: cash and cash equivalents	22,242		25,586		23,794
Closing net debt	39,993		37,819		38,635
Decrease (increase) in net debt	(2,163	)	1,958		(3,122	)
Movement in cash and cash equivalents (excluding exchange adjustments)	(3,478	)	(223	)	143
Net cash outflow (inflow) from financing_(c)	1,384		2,511		(3,111	)
Other movements	(27	)	(299	)	(66	)
Movement in net debt before exchange effects	(2,121	)	1,989		(3,034	)
Exchange adjustments_(c)	(42	)	(31	)	(88	)
Decrease (increase) in net debt	(2,163	)	1,958		(3,122	)

^(a)

Derivative financial instruments entered into for the purpose of managing interest rate and foreign currency exchange risk associated with net debt with a fair value liability position of $457 million (fourth quarter 2017 liability of $634 million and first quarter 2017 liability of $1,746 million) are not included in the calculation of net debt shown above as hedge accounting is not applied for these instruments.


^(b)	See Note 1 for further information.


^(c)	An amendment has been made to reduce the amount presented for net financing cash outflow for the fourth quarter of 2017 by $242 million to eliminate cash flows related to non-hedge accounted derivatives. Exchange adjustments have been amended by the same amount with no overall change in net debt.

Note 10. Statutory accounts

The financial information shown in this publication, which was approved by the Board of Directors on 30 April 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.

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Additional information

Capital expenditure*



	First	First
	quarter	quarter
$ million	2018	2017
Capital expenditure on a cash basis
Organic capital expenditure*	3,538	3,538
Inorganic capital expenditure*_(a)	425	530
	3,963	4,068



	First	First
	quarter	quarter
$ million	2018	2017
Organic capital expenditure by segment
Upstream
US	754	641
Non-US	2,112	2,339
	2,866	2,980
Downstream
US	171	152
Non-US	447	320
	618	472
Other businesses and corporate
US	7	21
Non-US	47	65
	54	86
	3,538	3,538
Organic capital expenditure by geographical area
US	932	814
Non-US	2,606	2,724
	3,538	3,538


^(a)	First quarter 2018 includes amounts relating to the 25-year extension to our ACG production-sharing agreement in Azerbaijan. First quarter 2017 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*



	First		First
	quarter		quarter
$ million	2018		2017
Upstream
Impairment and gain (loss) on sale of businesses and fixed assets_(a)	26		(382	)
Environmental and other provisions	—		—
Restructuring, integration and rationalization costs	1		2
Fair value gain (loss) on embedded derivatives	7		25
Other	(138	)	(5	)
	(104	)	(360	)
Downstream
Impairment and gain (loss) on sale of businesses and fixed assets	(14	)	(11	)
Environmental and other provisions	—		—
Restructuring, integration and rationalization costs	(36	)	(65	)
Fair value gain (loss) on embedded derivatives	—		—
Other	(3	)	—
	(53	)	(76	)
Rosneft
Impairment and gain (loss) on sale of businesses and fixed assets	—		—
Environmental and other provisions	—		—
Restructuring, integration and rationalization costs	—		—
Fair value gain (loss) on embedded derivatives	—		—
Other	—		—
	—		—
Other businesses and corporate
Impairment and gain (loss) on sale of businesses and fixed assets	2		(15	)
Environmental and other provisions	(21	)	—
Restructuring, integration and rationalization costs	(15	)	(8	)
Fair value gain (loss) on embedded derivatives	—		—
Gulf of Mexico oil spill_(b)	(86	)	(35	)
Other	(59	)	67
	(179	)	9
Total before interest and taxation	(336	)	(427	)
Finance costs_(b)	(120	)	(126	)
Total before taxation	(456	)	(553	)
Taxation credit (charge) on non-operating items	88		248
Taxation - impact of US tax reform_(c)	121		—
Total after taxation for period	(247	)	(305	)


^(a)	First quarter 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. First quarter 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



	First		First
	quarter		quarter
$ million	2018		2017
Favourable (adverse) impact relative to management’s measure of performance
Upstream	121		246
Downstream	(60	)	40
	61		286
Taxation credit (charge)	(11	)	(79	)
	50		207

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

The way that BP manages the economic exposures described above, and measures performance internally, differs from the way these activities are measured under IFRS. BP calculates this difference for consolidated entities by comparing the IFRS result with management’s internal measure of performance. Under management’s internal measure of performance the inventory and capacity contracts in question are valued based on fair value using relevant forward prices prevailing at the end of the period. The fair values of 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.

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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.



	First		First
	quarter		quarter
$ million	2018		2016
Upstream
Replacement cost profit before interest and tax adjusted for
fair value accounting effects	3,053		1,010
Impact of fair value accounting effects	121		246
Replacement cost profit before interest and tax	3,174		1,256
Downstream
Replacement cost profit before interest and tax adjusted for
fair value accounting effects	1,773		1,666
Impact of fair value accounting effects	(60	)	40
Replacement cost profit before interest and tax	1,713		1,706
Total group
Profit (loss) before interest and tax adjusted for
fair value accounting effects	4,434		2,342
Impact of fair value accounting effects	61		286
Profit (loss) before interest and tax	4,495		2,628

Readily marketable inventory* (RMI)



	31 March	31 December
$ million	2018	2017
RMI at fair value*	7,353	5,661
Paid-up RMI*	3,623	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 32 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.



	31 March		31 December
$ million	2018		2017
Reconciliation of total inventory to paid-up RMI
Inventories as reported on the group balance sheet under IFRS	20,802		19,011
Less: (a) inventories which are not oil and oil products and (b) oil and oil
product inventories which are not risk-managed by IST	(14,020	)	(13,929	)
	6,782		5,082
Plus: difference between RMI at fair value and RMI on an IFRS basis	571		579
RMI at fair value	7,353		5,661
Less: unpaid RMI* at fair value	(3,730	)	(2,973	)
Paid-up RMI	3,623		2,688

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Reconciliation of basic earnings per ordinary share to replacement cost (RC) profit (loss) per share and to underlying replacement cost profit (loss) per share



	First		First
	quarter		quarter
Per ordinary share (cents)	2018		2017
Profit for the period	12.40		7.42
Inventory holding (gains) losses*, before tax	(0.47	)	(0.34	)
Taxation charge (credit) on inventory holding gains and losses	0.06		0.15
Replacement cost (RC) profit (loss)*	11.99		7.23
Net (favourable) adverse impact of non-operating items* and fair value accounting effects*, before tax	1.98		1.38
Taxation charge (credit) on non-operating items and fair value accounting effects	(0.99	)	(0.87	)
Underlying RC profit*	12.98		7.74

Reconciliation of effective tax rate (ETR) to ETR on RC profit or loss and underlying ETR



Taxation (charge) credit
	First		First
	quarter		quarter
$ million	2018		2017
Taxation on profit or loss	(1,380	)	(623	)
Taxation on inventory holding gains and losses	(12	)	(29	)
Taxation on a replacement cost (RC) profit or loss basis	(1,368	)	(594	)
Taxation on non-operating items and fair value accounting effects	198		169
Underlying taxation	(1,566	)	(763	)



Effective tax rate
	First	First
	quarter	quarter
%	2018	2017
ETR on profit or loss	35	29
Adjusted for inventory holding gains or losses	1	—
ETR on RC profit or loss*	36	29
Adjusted for non-operating items and fair value accounting effects	1	4
Underlying ETR*	37	33

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Realizations* and marker prices



	First	First
	quarter	quarter
	2018	2017
Average realizations_(a)
Liquids* ($/bbl)
US	57.77	46.34
Europe	65.81	53.28
Rest of World	63.30	51.79
BP Average	61.40	49.87
Natural gas ($/mcf)
US	2.25	2.50
Europe	7.18	5.40
Rest of World	4.22	3.85
BP Average	3.78	3.50
Total hydrocarbons* ($/boe)
US	39.65	34.29
Europe	60.78	46.69
Rest of World	40.54	37.93
BP Average	41.39	37.19
Average oil marker prices ($/bbl)
Brent	66.82	53.69
West Texas Intermediate	62.90	51.70
Western Canadian Select	36.84	38.77
Alaska North Slope	67.20	53.82
Mars	62.44	49.59
Urals (NWE - cif)	65.27	51.88
Average natural gas marker prices
Henry Hub gas price_(b)($/mmBtu)	3.01	3.32
UK Gas - National Balancing Point (p/therm)	57.97	48.19


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


^(b)	Henry Hub First of Month Index.

Exchange rates



	First	First
	quarter	quarter
	2018	2017
$/£ average rate for the period	1.39	1.24
$/£ period-end rate	1.41	1.25

$/€ average rate for the period	1.23	1.07
$/€ period-end rate	1.24	1.07

Rouble/$ average rate for the period	56.88	58.72
Rouble/$ period-end rate	57.72	56.01

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Legal proceedings

For a full discussion of the group’s material legal proceedings, see pages 270-273 of BP Annual Report and Form 20-F 2017.

Glossary

Non-GAAP measures are provided for investors because they are closely tracked by management to evaluate BP’s operating performance and to make financial, strategic and operating decisions. 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. A reconciliation to GAAP information is provided on page 30.

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.

Gross debt ratio is defined as the ratio of gross debt to the total of gross debt plus shareholders' equity.

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.

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 25.

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.

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Glossary (continued)

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 9, 11 and 13, 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. Changes in working capital represent movements in inventories and other current and non-current assets and liabilities as reported in the condensed group cash flow statement.

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.

Replacement cost (RC) profit or loss reflects the replacement cost of inventories sold in the period and is arrived at by excluding inventory holding gains and losses from profit or loss. RC profit or loss is the measure of profit or loss that is required to be disclosed for each operating segment under IFRS. RC profit or loss for the group is not a recognized GAAP measure. BP believes this measure is useful to illustrate to investors the fact that crude oil and product prices can vary significantly from period to period and that the impact on our reported result under IFRS can be significant. Inventory holding gains and losses vary from period to period due to changes in prices as well as changes in underlying inventory levels. In order for investors to understand the operating performance of the group excluding the impact of price changes on the replacement of inventories, and to make comparisons of operating performance between reporting periods, BP’s management believes it is helpful to disclose this measure. The nearest equivalent measure on an IFRS basis is profit or loss attributable to BP shareholders. A reconciliation to GAAP information is provided on page 3.

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Glossary (continued)

RC profit or loss per share is a non-GAAP measure. Earnings per share is defined in Note 7. RC profit or loss per share is calculated using the same denominator. The numerator used is RC profit or loss attributable to BP shareholders rather than profit or loss attributable to BP shareholders. BP believes it is helpful to disclose the RC profit or loss per share because this measure excludes the impact of price changes on the replacement of inventories and allows for more meaningful comparisons between reporting periods. The nearest equivalent measure on an IFRS basis is basic earnings per share based on profit or loss for the period attributable to BP shareholders. A reconciliation to GAAP information is provided on page 30.

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

Underlying RC profit or loss is RC profit or loss after adjusting for non-operating items and fair value accounting effects. Underlying RC profit or loss and adjustments for fair value accounting effects are not recognized GAAP measures. See pages 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. Underlying profit on page 3 refers to first-quarter underlying RC profit for the group. A reconciliation to GAAP information is provided on page 3.

Underlying RC profit or loss per share is a non-GAAP measure. Earnings per share is defined in Note 7. Underlying RC profit or loss per share is calculated using the same denominator. The numerator used is underlying RC profit or loss attributable to BP shareholders rather than profit or loss attributable to BP shareholders. BP believes it is helpful to disclose the underlying RC profit or loss per share because this measure may help investors to understand and evaluate, in the same manner as management, the underlying trends in BP’s operational performance on a comparable basis, period on period. The nearest equivalent measure on an IFRS basis is basic earnings per share based on profit or loss for the period attributable to BP shareholders. A reconciliation to GAAP information is provided on page 30.

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.

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.

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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’), 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 quarterly dividend payment and timing of such payment; plans and expectations with respect to operational targets, capital discipline and cash flows; plans and expectations with respect to emissions and advancing the energy transition; plans and expectations regarding the start-up of six Upstream major projects in 2018; expectations regarding 2018 organic capital expenditure; plans and expectations with respect to gearing including to target gearing within a 20-30% band and for gearing to trend down; expectations regarding divestment transactions and the amount and timing of divestment proceeds; expectations regarding the underlying effective tax rate in 2018; expectations regarding second-quarter 2018 reported production; expectations regarding Downstream second-quarter 2018 refining margins, turnaround activity and discounts for North American heavy crude oil; expectations regarding the amount of Rosneft dividends payable to BP; plans and expectations regarding a final investment decision on the Tortue/Ahmeyim gas project; plans and expectations regarding the production-sharing agreement with SOCAR; plans and expectations regarding the partnership with the Renault-Nissan-Mitsubishi Alliance; expectations regarding the determination of business economic loss claims in respect of the 2012 PSC settlement; and expectations with respect to the timing and amount of future payments relating to the Gulf of Mexico oil spill including 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 and under “Risk factors” in BP Annual Report and Form 20-F 2017 as filed with the US Securities and Exchange Commission.

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Computation of ratio of earnings to fixed charges



	First
	quarter
	2018
$ million except ratio

Earnings available for fixed charges:
Pre-tax profit from continuing operations before adjustment for income or loss from joint ventures and associates	3,204
Fixed charges	746
Amortization of capitalized interest	49
Distributed income of joint ventures and associates	171
Interest capitalized	(90	)
Preference dividend requirements, gross of tax	(1	)
Non-controlling interest of subsidiaries’ income not incurring fixed charges	(13	)
Total earnings available for fixed charges	4,066

Fixed charges:
Interest expensed	386
Interest capitalized	90
Rental expense representative of interest	269
Preference dividend requirements, gross of tax	1
Total fixed charges	746

Ratio of earnings to fixed charges	5.45

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The following table shows the unaudited consolidated capitalization and indebtedness of the BP group as of 31 March 2018 in

accordance with IFRS:

Capitalization and indebtedness



	31 March
$ million	2018
Share capital and reserves
Capital shares (1-2)	5,355
Paid-in surplus (3)	13,779
Merger reserve (3)	27,206
Treasury shares	(15,964	)
Cash flow hedge reserve	(747	)
Costs of hedging reserve	(118	)
Foreign currency translation reserve	(4,718	)
Profit and loss account	75,394
BP shareholders' equity	100,187

Finance debt (4-6)
Due within one year	9,028
Due after more than one year	53,161
Total finance debt	62,189
Total capitalization (7)	162,376

Issued share capital as of 31 March 2018 comprised 19,952,919,228 ordinary shares, par value US$0.25 per share, and 12,706,252 preference shares, par value £1 per share. This excludes 1,382,765,252 ordinary shares which have been bought back and are held in treasury by BP. These shares are not taken into consideration in relation to the payment of dividends and voting at shareholders’ meetings.


2.	Capital shares represent the ordinary and preference shares of BP which have been issued and are fully paid.


3.	Paid-in surplus and merger reserve represent additional paid-in capital of BP which cannot normally be returned to shareholders.


4.	Finance debt recorded in currencies other than US dollars has been translated into US dollars at the relevant exchange rates existing on 31 March 2018.


5.	Finance debt presented in the table above consists of borrowings and obligations under finance leases. Other contractual obligations are not presented in the table above – see BP Annual Report and Form 20-F 2017 – Liquidity and capital resources for further information.


6.	At 31 March 2018, the parent company, BP p.l.c., had issued guarantees totalling $59,902 million relating to finance debt of subsidiaries. Thus 96% of the group’s finance debt had been guaranteed by BP p.l.c.

At 31 March 2018, $150 million of finance debt was secured by the pledging of assets. The remainder of finance debt was unsecured.


7.	At 31 March 2018 the group had issued third-party guarantees under which amounts outstanding, incremental to amounts recognized on the group balance sheet, were $313 million in respect of the borrowings of equity-accounted entities and $242 million in respect of the borrowings of other third parties.


8.	There has been no material change since 31 March 2018 in the consolidated capitalization and indebtedness of BP.

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Signatures

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

BP p.l.c.

(Registrant)



Dated:	1 May 2018	/s/ David J Jackson
		David J Jackson
		Company Secretary