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 30 June 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)(7): ¨

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 30 June 2018_(a)



		Page
1.	Management’s Discussion and Analysis of Financial Condition and Results of Operations for the period January-June 2018_(b)	3-13, 33-38, 40-43

2.	Consolidated Financial Statements including Notes to Consolidated Financial Statements for the period January-June 2018	14-32

3.	Principal risks and uncertainties	39

4.	Legal proceedings	40

5.	Other matters	43

6.	Cautionary statement	43

7.	Computation of Ratio of Earnings to Fixed Charges	44

8.	Capitalization and Indebtedness	45

9.	Signatures	46


(a)	In this Form 6-K, references to the half year 2018 and half year 2017 refer to six-month periods ended 30 June 2018 and 30 June 2017 respectively. References to the second quarter 2018 and second quarter 2017 refer to the three-month periods ended 30 June 2018 and 30 June 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 second quarter and half year 2018



Highlights	Strong earnings, strategic momentum, increased dividend


•	Profit for the second quarter of 2018 was $2.8 billion, compared with $0.1 billion for the same period in 2017. Underlying replacement cost profit* for the second quarter of 2018 was $2.8 billion – four times that reported for the same period in 2017 – including significantly higher earnings from the Upstream and Rosneft.


•	Operating cash flow* was $6.3 billion in the second quarter and $10.0 billion in the first half including the impact of Gulf of Mexico oil spill payments of $0.7 billion and $2.4 billion respectively_(a).

• Dividend was increased 2.5% to 10.25 cents a share, the first rise since the third quarter of 2014.


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


•	Oil and gas production: reported production in the quarter was 3.6 million barrels of oil equivalent a day. Upstream production, excluding Rosneft, was 1.4% higher than a year earlier and up 9.6% when adjusted for portfolio changes and pricing effects, driven by rising output from new major projects* and strong plant reliability*.


•	Major projects: with start-ups in Azerbaijan, Russia and Egypt, three of the six new projects expected to start in 2018 are now online.


•	Strategic portfolio management: agreed to buy world-class US onshore oil and gas assets from BHP, a $10.5 billion acquisition that will transform BP’s US Lower 48 business. BP also agreed to increase its stake in the Clair oilfield in the UK while exiting the Greater Kuparuk Area in Alaska.


•	Downstream reported strong first half refining performance, with record levels of crude processed at Whiting refinery in US; further expansion in fuels marketing, with more than 1,200 convenience partnership sites now across our retail network.


•	Advancing the energy transition: acquisition of UK's largest electric vehicle charging company Chargemaster and investment in innovative battery technology firm StoreDot move forward BP’s approach to advanced mobility.

• Gulf of Mexico oil spill payments in the quarter were $0.7 billion on a post-tax basis.

• Gross debt reduced in the quarter by $1.8 billion to $60.4 billion. Net debt* reduced in the quarter by $0.7 billion to $39.3 billion.

• BP's share buyback programme continued with 29 million ordinary shares bought back in the first half at a cost of $200 million.


_(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	Second		Second		First		First
Financial summary	quarter		quarter		half		half
$ million	2018		2017		2018		2017
Sales and other operating revenues	75,439		56,511		143,611		112,374
Profit for the period_(a)	2,799		144		5,268		1,593
Inventory holding (gains) losses*, before tax	(1,310	)	586		(1,402	)	520
Taxation charge (credit) on inventory holding gains and losses	300		(177	)	312		(148	)
RC profit (loss)*	1,789		553		4,178		1,965
Net (favourable) adverse impact of non-operating items* and fair value accounting effects*, before tax	1,275		237		1,670		504
Taxation charge (credit) on non-operating items and fair value accounting effects	(242	)	(106	)	(440	)	(275	)
Underlying RC profit	2,822		684		5,408		2,194
Profit per ordinary share (cents)	14.03		0.73		26.42		8.12
Profit per ADS (dollars)	0.84		0.04		1.59		0.49
RC profit (loss) per ordinary share (cents)*	8.96		2.80		20.96		10.02
RC profit (loss) per ADS (dollars)	0.54		0.17		1.26		0.60
Underlying RC profit per ordinary share (cents)*	14.14		3.47		27.13		11.19
Underlying RC profit per ADS (dollars)	0.85		0.21		1.63		0.67


(a)	Profit attributable to BP shareholders.

* See definitions in the Glossary on page 40. RC profit (loss), underlying RC profit, net debt and organic capital expenditure are non-GAAP measures.

The commentary above and following should be read in conjunction with the cautionary statement on page 43.

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Group headlines

Results

BP’s profit for the second quarter and half year was $2,799 million and $5,268 million respectively, compared with $144 million and $1,593 million for the same periods in 2017.

For the half year, replacement cost (RC) profit* was $4,178 million, compared with $1,965 million in 2017. Underlying RC profit* was $5,408 million, compared with $2,194 million in 2017. Underlying RC profit is after adjusting RC profit for a net charge for non-operating items* of $970 million and net adverse fair value accounting effects* of $260 million (both on a post-tax basis).

For the second quarter, RC profit was $1,789 million, compared with a profit of $553 million in 2017. Underlying RC profit was $2,822 million compared with $684 million for the same period in 2017. Underlying RC profit is after adjusting RC profit for a net charge for non-operating items of $723 million and net adverse fair value accounting effects of $310 million (both on a post-tax basis).

See further information on pages 5, 34 and 35.

Non-operating items

Non-operating items amounted to a post-tax charge of $723 million for the quarter and $970 million for the half year. The charge for the quarter includes post-tax amounts relating to the Gulf of Mexico oil spill of $193 million for business economic loss claims and $126 million for other claims and litigation relating to the spill, as well as finance costs in respect of the unwinding of discounting effects relating to oil spill payables. See further information on page 34.

Effective tax rate

The effective tax rate (ETR) on the profit for the second quarter and half year was 42% and 39% respectively, compared with 83% and 46% for the same periods in 2017. The ETR on RC profit or loss* for the second quarter and half year was 49% and 42% respectively, compared with 63% and 43% for the same periods in 2017. Adjusting for non-operating items and fair value accounting effects, the underlying ETR* for the second quarter and half year was 42% and 40% respectively, compared with 60% and 45% for the same periods in 2017. The lower underlying ETR for the second quarter and half year mainly reflected lower exploration write-offs partly offset by deferred tax charges due to foreign exchange impacts. ETR on RC profit or loss and underlying ETR are non-GAAP measures.

Dividend

On 26 July 2018 BP announced a quarterly dividend of 10.25 cents per ordinary share ($0.615 per ADS), which is expected to be paid on 21 September 2018. The corresponding amount in sterling will be announced on 11 September 2018. See page 26 for further information.

Share buybacks

BP repurchased 11 million ordinary shares at a cost of $80 million, including fees and stamp duty, during the second quarter of 2018. For the half year, BP repurchased 29 million ordinary shares at a cost of $200 million, including fees and stamp duty.

Operating cash flow*

Operating cash flow was $6.3 billion in the second quarter and $10.0 billion in the first half including the impact of Gulf of Mexico oil spill payments of $0.7 billion and $2.4 billion respectively. These compare with $4.9 billion for the second quarter of 2017 and $7.0 billion for the first half of 2017.

Capital expenditure*

Total capital expenditure for the second quarter and half year was $3.8 billion and $7.8 billion respectively, compared with $4.5 billion and $8.6 billion for the same periods in 2017.

Organic capital expenditure* for the second quarter and half year was $3.5 billion and $7.0 billion respectively, compared with $4.3 billion and $7.9 billion for the same periods in 2017.

Inorganic capital expenditure* for the second quarter and half year was $0.4 billion and $0.8 billion respectively, compared with $0.1 billion and $0.7 billion for the same periods in 2017.

See page 33 for further information.

Divestment and other proceeds

Divestment proceeds* were $0.2 billion for the second quarter and $0.3 billion for the half year, compared with $0.5 billion and $0.7 billion for the same periods in 2017.

Debt

Gross debt at 30 June 2018 was $60.4 billion compared with $63.0 billion a year ago. Gross debt ratio* at 30 June 2018 was 37.2%, compared with 39.0% a year ago.

Net debt* at 30 June 2018 was $39.3 billion, compared with $39.8 billion a year ago. Gearing* or net debt ratio* at 30 June 2018 was 27.8%, compared with 28.8% a year ago.

We expect gearing to remain within the target band, of 20-30%, during the second half of 2018.

Net debt, net debt ratio and gearing are non-GAAP measures. See page 26 for more information.

The commentary above contains forward-looking statements and should be read in conjunction with the cautionary statement on page 43.

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Analysis of underlying RC profit* before interest and tax



	Second		Second		First		First
	quarter		quarter		half		half
$ million	2018		2017		2018		2017
Underlying RC profit before interest and tax
Upstream	3,508		710		6,665		2,080
Downstream	1,455		1,413		3,281		3,155
Rosneft	766		279		1,013		378
Other businesses and corporate	(477	)	(366	)	(869	)	(806	)
Consolidation adjustment – UPII*	151		135		(9	)	67
Underlying RC profit before interest and tax	5,403		2,171		10,081		4,874
Finance costs and net finance expense relating to pensions and other post-retirement benefits	(448	)	(420	)	(912	)	(807	)
Taxation on an underlying RC basis	(2,059	)	(1,055	)	(3,625	)	(1,818	)
Non-controlling interests	(74	)	(12	)	(136	)	(55	)
Underlying RC profit attributable to BP shareholders	2,822		684		5,408		2,194

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



	Second		Second		First		First
	quarter		quarter		half		half
$ million	2018		2017		2018		2017
RC profit (loss) before interest and tax
Upstream	3,514		795		6,688		2,051
Downstream	840		1,567		2,553		3,273
Rosneft	766		279		1,013		378
Other businesses and corporate_(a)	(1,025	)	(721	)	(1,596	)	(1,152	)
Consolidation adjustment – UPII	151		135		(9	)	67
RC profit (loss) before interest and tax	4,246		2,055		8,649		4,617
Finance costs and net finance expense relating to pensions and other post-retirement benefits	(566	)	(541	)	(1,150	)	(1,054	)
Taxation on a RC basis	(1,817	)	(949	)	(3,185	)	(1,543	)
Non-controlling interests	(74	)	(12	)	(136	)	(55	)
RC profit (loss) attributable to BP shareholders	1,789		553		4,178		1,965
Inventory holding gains (losses)*	1,310		(586	)	1,402		(520	)
Taxation (charge) credit on inventory holding gains and losses	(300	)	177		(312	)	148
Profit (loss) for the period attributable to BP shareholders	2,799		144		5,268		1,593


(a)	Includes costs related to the Gulf of Mexico oil spill. See page 13 and also Note 2 from page 21 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 second quarter was 2,465mboe/d, 1.4% higher than a year earlier. Underlying production* – adjusted for PSA* impacts and portfolio changes, including termination of BP’s interest in the offshore concession in Abu Dhabi – was 9.6% higher than a year ago due to production from the ramp-up of major projects* and continued strong plant reliability*. Unit production costs* for the second quarter improved by 3% compared with the same period in 2017.

Three Upstream major projects have now started up in 2018: the Shah Deniz 2 gas project in Azerbaijan and the Taas-Yuryakh oil expansion in Russia in the second quarter, following the Atoll project in Egypt in the first quarter. These projects were started up under budget and on or ahead of schedule. Another three major projects are expected to begin production during 2018. In addition, during the first half of the year, final investment decisions have been made on five projects in Oman, India, the North Sea and Angola.

BP has accessed new acreage in the Campos basin, offshore Brazil, as a result of the fourth Pre-Salt Production Sharing Contract Bid Round.

BP has agreed to buy a portfolio of US unconventional oil and gas assets from BHP. This major acquisition will upgrade and materially reposition BP’s US onshore oil and gas business. BP also agreed to increase its interest in the UK's Clair field, an advantaged oil asset with growth potential, while divesting its non-operating interest in the Greater Kuparuk Area in Alaska.

Downstream

In marketing, BP’s convenience partnership model is now rolled out to more than 1,200 sites across our network, more than 300 BP-branded retail sites are now open in Mexico and lubricants continues to deliver premium brand growth.

In manufacturing, BP’s Whiting refinery processed record levels of crude and our petrochemicals business announced two new PTA licensing agreements, demonstrating the strength of BP’s industry-leading technology.

Advancing the energy transition

BP has continued to progress its lower-carbon strategy as detailed in the Advancing the energy transition report published in April.

Two Upstream major projects that have started operation in 2018 so far – Shah Deniz 2 and Atoll – produce natural gas.

BP also significantly progressed its advanced mobility strategy with the purchase of Chargemaster, the UK’s largest electric vehicle charging network operator. Together with investments in StoreDot, a developer of ultra-fast charging battery technology, and mobile-charging company FreeWire, this supports BP’s aim to become the leading fuel provider for electric as well as conventional vehicles.

Financial framework

Operating cash flow* was $6.3 billion in the quarter and $10.0 billion in the first half, including Gulf of Mexico oil spill payments of $0.7 billion in the quarter and $2.4 billion in the first half. These compare with $4.9 billion for the second quarter of 2017 and $7.0 billion for the first half of 2017.

Organic capital expenditure* of $3.5 billion in the quarter brought the total for the first half of 2018 to $7.0 billion. BP expects 2018 organic capital expenditure to be around $15 billion.

Divestments and other proceeds totalled $0.3 billion for the half year. 2018 total proceeds are expected to be over $3 billion including proceeds from the sale of BP’s interests in the Greater Kuparuk Area in Alaska.

Gulf of Mexico oil spill payments on a post-tax basis totalled $2.4 billion in the first half of 2018. Payments for the full year are expected to be just over $3 billion on a post-tax basis.

Gearing* at the end of the quarter was 27.8%, within BP’s target band of 20-30%. We expect gearing to remain within the target band during the second half of 2018.



Operating metrics	First half 2018	Financial metrics	First half 2018
Operating metrics	(vs. First half 2017)	Financial metrics	(vs. First half 2017)
Tier 1 process safety events*	8	Underlying RC profit*ⁱ	$5.4bn
Tier 1 process safety events*	(-3)	Underlying RC profit*ⁱ	(+$3.2bn)
Reported recordable injury frequency*	0.22	Operating cash flow excluding Gulf of Mexico oil spill payments (post-tax)	_(b)
Reported recordable injury frequency*	(—)
Group production	3,662mboe/d	Organic capital expenditureⁱⁱ	$7.0bn
Group production	(+3.3%)	Organic capital expenditureⁱⁱ	(-$0.9bn)
Upstream production (excludes Rosneft segment)	2,535mboe/d	Gulf of Mexico oil spill payments (post-tax)_(c)	$2.4bn
Upstream production (excludes Rosneft segment)	(+5.2%)	Gulf of Mexico oil spill payments (post-tax)_(c)	(-$1.9bn)
Upstream unit production costs	$7.32/boe	Divestment proceeds*	$0.3bn
Upstream unit production costs	(+1.6%)	Divestment proceeds*	(-$0.4bn)
BP-operated Upstream plant reliability_(a)	95.8%	Net debt ratio* (gearing)ⁱⁱⁱ	27.8%
BP-operated Upstream plant reliability_(a)	(+0.7)	Net debt ratio* (gearing)ⁱⁱⁱ	(-1.0)
Refining availability*	94.1%	Dividend per ordinary share_(d)	10.25 cents
Refining availability*	(-0.7)	Dividend per ordinary share_(d)	(+2.5%)


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

(b)

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 half year, net cash provided by operating activities was $10.0 billion and post-tax Gulf of Mexico oil spill payments were $2.4 billion.

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(c)	Amounts shown are post-tax, first quarter 2018 amounts disclosed were pre-tax. Post-tax amounts are consistent with operating cash flow excluding Gulf of Mexico oil spill payments in the table above and the financial framework. The equivalent amount on a pre-tax basis was $2.7 billion, a reduction of $1.6 billion on the prior year.


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



Nearest GAAP equivalent measures
i	Profit for the period:	$5.3bn
ii	Capital expenditure*:	$7.8bn
iii	Gross debt ratio*:	37.2%

The commentary above contains forward-looking statements and should be read in conjunction with the cautionary statement on page 43.

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Upstream



	Second		Second		First		First
	quarter		quarter		half		half
$ million	2018		2017		2018		2017
Sales and other operating revenues_(a)	12,698		10,493		26,568		21,820
Profit before interest and tax	3,518		796		6,693		2,046
Inventory holding (gains) losses*	(4	)	(1	)	(5	)	5
RC profit before interest and tax	3,514		795		6,688		2,051
Net (favourable) adverse impact of non-operating items* and fair value accounting effects*	(6	)	(85	)	(23	)	29
Underlying RC profit (loss) before interest and tax*_(b)	3,508		710		6,665		2,080


(a)	Includes sales to other segments.


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

Financial results

Sales and other operating revenues for the second quarter and half year were $13 billion and $27 billion respectively, compared with $10 billion and $22 billion for the corresponding periods in 2017. For the second quarter and half year, revenues were higher due to higher realizations, higher sales volumes, and higher gas marketing and trading revenues.

The replacement cost profit before interest and tax for the second quarter and half year was $3,514 million and $6,688 million respectively, compared with $795 million and $2,051 million for the same periods in 2017. The second quarter and half year included a net non-operating gain of $27 million and a charge of $77 million respectively, compared with a net charge of $21 million and $381 million for the same periods in 2017. Fair value accounting effects in the second quarter and half year had an adverse impact of $21 million and a favourable impact of $100 million respectively, compared with a favourable impact of $106 million and $352 million in the same periods of 2017.

After adjusting for non-operating items and fair value accounting effects, the underlying replacement cost profit before interest and tax for the second quarter and half year was $3,508 million and $6,665 million respectively, compared with $710 million and $2,080 million for the same periods in 2017. The result for the second quarter and half year mainly reflected higher liquids and gas realizations, lower exploration write-offs, and higher production from the ramp-up of major projects*.

Production

Production for the quarter was 2,465mboe/d, 1.4% higher than the second quarter of 2017. Underlying production* for the quarter increased by 9.6%, due to the ramp-up of major projects.

For the half year, production was 2,535mboe/d, 5.2% higher than 2017. Underlying production for the half year was 11.7% higher than 2017 due to the ramp-up of major projects.

Key events

In the second quarter, the Rosneft-operated Taas-Yuryakh expansion project (BP 20%) completed commissioning of the main project facilities for the Srednebotuobinskoye oil and gas condensate field in Eastern Siberia, Russia. This is the second of six major projects expected to come onstream for BP this year. The project was delivered under budget and on schedule.

On 7 June, BP won the licence for the Dois Irmãos block located in the Campos basin, offshore Brazil, as a result of the fourth Pre-Salt Production Sharing Contract Bid Round (Petrobras operator 45%, BP 30%, and Equinor 25%).

On 2 July, BP and its partners in the Shah Deniz consortium (BP operator 28.8%) announced the start-up of the Shah Deniz 2 gas project in Azerbaijan, including its first commercial gas delivery to Turkey. Shah Deniz 2 is the starting point for the Southern Gas Corridor series of pipelines that will deliver gas from the Caspian Sea direct to European markets and the third of six major projects expected to come onstream for BP this year. The project started up under budget and on schedule.

On 3 July, BP announced that it has entered into an agreement to purchase from ConocoPhillips a 16.5% interest in the BP-operated Clair field, west of Shetland in the UK. As a result, BP’s interest in Clair will increase to 45.1%. Simultaneously BP has entered into agreements to sell to ConocoPhillips BP’s entire 39.2% interest in the Greater Kuparuk Area on the North Slope of Alaska as well as BP’s holding in the Kuparuk Transportation Company. The two transactions together are expected to be cash neutral. The transactions remain subject to regulatory approvals.

On 26 July, BP announced that BP America Production Company will acquire from BHP Billiton Petroleum (North America) Inc. 100% of the issued share capital of Petrohawk Energy Corporation for a total consideration of $10.5 billion subject to customary adjustments. These unconventional oil and gas assets comprise 470,000 net acres of licences, including a new position for BP in the liquids-rich Permian-Delaware basin, and two premium positions in the Eagle Ford and Haynesville basins. The assets have combined current production of 190,000 barrels of oil equivalent per day, about 45% of which is liquid hydrocarbons, as well as undeveloped resources. The transaction is anticipated to complete by the end of October subject to regulatory approvals.

This builds on the progress announced in our first-quarter results, which comprised the following: BP announced the start of gas production from the Atoll Phase One project in Egypt; BP confirmed that the governments of Mauritania and Senegal signed an Inter-Government Cooperation Agreement (ICA) which will enable the development of the BP-operated Tortue/Ahmeyim gas project; BP took final investment decisions on the two new North Sea developments, Alligin and Vorlich satellite fields; BP’s equity interest (14.67%) in the ADNOC Offshore concession in Abu Dhabi expired; BP announced that, together with its partner, the Oman Oil Company Exploration & Production, it has approved the development of Ghazeer, the second phase of the Khazzan gas field in Oman; 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; BP together with its partner Reliance Industries Limited, announced the sanction of the Satellite Cluster project off the east coast of India; BP and the State Oil Company

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Upstream (continued)

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.

Outlook

Looking ahead, we expect third-quarter reported production to be broadly flat with the second quarter with continued seasonal turnaround and maintenance activities.

The commentary above contains forward-looking statements and should be read in conjunction with the cautionary statement on page 43.



	Second		Second		First		First
	quarter		quarter		half		half
$ million	2018		2017		2018		2017
Underlying RC profit before interest and tax
US	742		179		1,268		345
Non-US	2,766		531		5,397		1,735
	3,508		710		6,665		2,080
Non-operating items
US	(29	)	(34	)	(174	)	(46	)
Non-US_(a)	56		13		97		(335	)
	27		(21	)	(77	)	(381	)
Fair value accounting effects
US	(143	)	92		(152	)	284
Non-US	122		14		252		68
	(21	)	106		100		352
RC profit before interest and tax
US	570		237		942		583
Non-US	2,944		558		5,746		1,468
	3,514		795		6,688		2,051
Exploration expense
US	77		25		386		65
Non-US_(b)	87		825		292		1,197
	164		850		678		1,262
Of which: Exploration expenditure written off_(b)	81		753		507		1,014
Production (net of royalties)_(c)
Liquids* (mb/d)
US	411		418		429		433
Europe	147		122		143		118
Rest of World	659		812		695		819
	1,217		1,352		1,267		1,371
Of which equity-accounted entities	112		202		144		208
Natural gas (mmcf/d)
US	1,744		1,576		1,767		1,585
Europe	202		274		209		269
Rest of World	5,297		4,410		5,376		4,173
	7,242		6,260		7,352		6,026
Of which equity-accounted entities	493		558		485		544
Total hydrocarbons* (mboe/d)
US	711		689		734		706
Europe	182		169		180		165
Rest of World	1,572		1,572		1,622		1,539
	2,465		2,431		2,535		2,410
Of which equity-accounted entities	197		298		227		301
Average realizations*_(d)
Total liquids_(e) ($/bbl)	67.24		46.27		64.21		48.09
Natural gas ($/mcf)	3.65		3.19		3.72		3.34
Total hydrocarbons($/boe)	43.37		33.59		42.36		35.37


(a)	First half 2017 relates primarily to an impairment charge related to the sale of the Forties Pipeline System business to INEOS.


(b)	Second quarter and first half 2017 predominantly relates to the write-off of exploration well and lease costs in Angola. First half 2017 also includes write-off of exploration wells in Egypt.


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


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


(e)	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



	Second		Second		First		First
	quarter		quarter		half		half
$ million	2018		2017		2018		2017
Sales and other operating revenues_(a)	69,174		52,195		130,580		102,275
Profit before interest and tax	2,036		988		3,818		2,792
Inventory holding (gains) losses*	(1,196	)	579		(1,265	)	481
RC profit before interest and tax	840		1,567		2,553		3,273
Net (favourable) adverse impact of non-operating items* and fair value accounting effects*	615		(154	)	728		(118	)
Underlying RC profit before interest and tax*_(b)	1,455		1,413		3,281		3,155


(a)	Includes sales to other segments.


(b)	See page 11 for a reconciliation to segment RC profit before interest and tax by region and by business.

Financial results

Sales and other operating revenues for the second quarter and half year were $69 billion and $131 billion respectively, compared with $52 billion and $102 billion for the corresponding periods in 2017. The increase in the second quarter and half year was mainly due to higher oil prices.

The replacement cost profit before interest and tax for the second quarter and half year was $840 million and $2,553 million respectively, compared with $1,567 million and $3,273 million for the same periods in 2017.

The second quarter and half year include a net non-operating charge of $225 million and $278 million respectively, compared with a gain of $138 million and $62 million for the same periods in 2017. Fair value accounting effects had an adverse impact of $390 million in the second quarter and $450 million for the half year, compared with a favourable impact of $16 million and $56 million for the same periods in 2017.

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

Fuels

The fuels business reported an underlying replacement cost profit before interest and tax of $1,054 million for the second quarter and $2,452 million for the half year, compared with $908 million and $2,108 million for the same periods in 2017. The result for the quarter and half year reflects a higher refining performance but a weak supply and trading contribution with a small loss in the second quarter. The result also reflects continued strong fuels marketing performance despite the adverse lag impact of increasing crude oil prices.

The refining performance for the quarter and half year reflects the benefits from increased commercial optimization with record levels of crude processed at our Whiting refinery, stronger industry refining margins and higher North American heavy crude oil discounts which was partly offset by pipeline capacity apportionment impacts.

In fuels marketing our convenience partnership model is now in more than 1,200 sites across our network and in Mexico we now have more than 300 BP-branded retail sites operational.

This quarter, we continued to progress our advanced mobility agenda. In May, we invested $20 million in StoreDot, a leading developer of ultra-fast charging battery technology and in July, we completed the acquisition of Chargemaster, the operator of the UK’s largest electric vehicle charging network, for £130 million.

In the quarter we signed a memorandum of understanding with state-owned Brazilian oil company Petrobras to explore potential joint commercial agreements in Brazil. We also announced that we will not be continuing with the proposed acquisition of Woolworths’ retail fuel and convenience business in Australia.

Lubricants

The lubricants business reported an underlying replacement cost profit before interest and tax of $326 million for the second quarter and $657 million for the half year, compared with $355 million and $748 million for the same periods in 2017. The result for the quarter and half year reflects continued premium brand growth, more than offset by the adverse lag impact of increasing base oil prices.

During the first 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.

Petrochemicals

The petrochemicals business reported an underlying replacement cost profit before interest and tax of $75 million for the second quarter and $172 million for the half year, compared with $150 million and $299 million for the same periods in 2017. The result for the quarter and half year reflects an improved margin environment, increased margin optimization and lower costs. This was more than offset by a significantly higher level of turnaround activity and the impact from the divestment of our interest in the SECCO joint venture, which completed in the fourth quarter of last year.

Outlook

Looking to the third quarter, we expect lower industry refining margins. We also expect significantly higher levels of turnaround activity in the second half of the year, particularly at our Whiting refinery in the US.

The commentary above contains forward-looking statements and should be read in conjunction with the cautionary statement on page 43.

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Downstream (continued)



	Second		Second		First		First
	quarter		quarter		half		half
$ million	2018		2017		2018		2017
Underlying RC profit before interest and tax - by region
US	399		283		988		837
Non-US	1,056		1,130		2,293		2,318
	1,455		1,413		3,281		3,155
Non-operating items
US	(155	)	28		(172	)	16
Non-US	(70	)	110		(106	)	46
	(225	)	138		(278	)	62
Fair value accounting effects_(a)
US	(299	)	10		(420	)	(52	)
Non-US	(91	)	6		(30	)	108
	(390	)	16		(450	)	56
RC profit before interest and tax
US	(55	)	321		396		801
Non-US	895		1,246		2,157		2,472
	840		1,567		2,553		3,273
Underlying RC profit before interest and tax - by business_(b)(c)
Fuels	1,054		908		2,452		2,108
Lubricants	326		355		657		748
Petrochemicals	75		150		172		299
	1,455		1,413		3,281		3,155
Non-operating items and fair value accounting effects_(a)
Fuels	(584	)	159		(694	)	163
Lubricants	(26	)	(2	)	(29	)	(5	)
Petrochemicals	(5	)	(3	)	(5	)	(40	)
	(615	)	154		(728	)	118
RC profit before interest and tax_(b)(c)
Fuels	470		1,067		1,758		2,271
Lubricants	300		353		628		743
Petrochemicals	70		147		167		259
	840		1,567		2,553		3,273

BP average refining marker margin (RMM)* ($/bbl)	14.9		13.8		13.3		12.8

Refinery throughputs (mb/d)
US	666		708		690		702
Europe	786		782		792		791
Rest of World	228		198		238		189
	1,680		1,688		1,720		1,682
Refining availability* (%)	93.3		94.5		94.1		94.8

Marketing sales of refined products (mb/d)
US	1,161		1,177		1,129		1,146
Europe	1,135		1,153		1,090		1,111
Rest of World	477		497		479		505
	2,773		2,827		2,698		2,762
Trading/supply sales of refined products	3,247		2,996		3,215		2,978
Total sales volumes of refined products	6,020		5,823		5,913		5,740

Petrochemicals production (kte)
US	404		672		903		1,170
Europe	1,094		1,365		2,222		2,618
Rest of World	1,358		2,001		2,749		4,074
	2,856		4,038		5,874		7,862


(a)	For Downstream, fair value accounting effects arise solely in the fuels business. See page 35 for further information.


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


(c)	Results from petrochemicals at our Gelsenkirchen and Mülheim sites in Germany are reported in the fuels business.

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Rosneft



	Second		Second	First		First
	quarter		quarter	half		half
$ million	2018_(a)		2017	2018_(a)		2017
Profit before interest and tax_(b)	876		271	1,145		344
Inventory holding (gains) losses*	(110	)	8	(132	)	34
RC profit before interest and tax	766		279	1,013		378
Net charge (credit) for non-operating items*	—		—	—		—
Underlying RC profit before interest and tax*	766		279	1,013		378

Financial results

Replacement cost (RC) profit before interest and tax and underlying RC profit before interest and tax for the second quarter and half year was $766 million and $1,013 million respectively, compared with $279 million and $378 million for the same periods in 2017. There were no non-operating items in the second quarter and half year of either year.

Compared with the same periods in 2017, the results for the second quarter and half year were primarily affected by higher oil prices, favourable foreign exchange and duty lag effects, and certain one-off items.

BP’s two nominees, Bob Dudley and Guillermo Quintero, were re-elected to Rosneft’s board at the annual general meeting (AGM) on 21 June. At the AGM, shareholders also approved a resolution to pay a dividend of 6.65 roubles per ordinary share, which brings the total dividend for 2017 to 10.48 roubles per ordinary share, constituting 50% of the company’s IFRS net profit. BP expects to receive a dividend of 12.5 billion roubles, after the deduction of withholding tax, on 31 July 2018.

Key events

In December 2017 Rosneft and BP announced an agreement to develop subsoil resources within the Kharampurskoe and Festivalnoye licence areas in Yamalo-Nenets Autonomous Okrug in northern Russia. In the second quarter of 2018 BP acquired a 49% stake in LLC Kharampurneftegaz and it is expected that Rosneft will transfer the relevant subsoil use licences to LLC Kharampurneftegaz, subject to regulatory approvals, later in 2018. BP's interest is reported through the Upstream segment.



	Second	Second	First	First
	quarter	quarter	half	half
	2018_(a)	2017	2018_(a)	2017
Production (net of royalties) (BP share)
Liquids* (mb/d)	909	902	906	907
Natural gas (mmcf/d)	1,262	1,302	1,285	1,318
Total hydrocarbons* (mboe/d)	1,127	1,126	1,127	1,134


(a)	The operational and financial information of the Rosneft segment for the second quarter and half year is based on preliminary operational and financial results of Rosneft for the half year ended 30 June 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



	Second		Second		First		First
	quarter		quarter		half		half
$ million	2018		2017		2018		2017
Sales and other operating revenues_(a)	376		326		719		611
Profit (loss) before interest and tax
Gulf of Mexico oil spill - business economic loss claims	(249	)	(260	)	(249	)	(260	)
Gulf of Mexico oil spill - other	(184	)	(87	)	(270	)	(122	)
Other	(592	)	(374	)	(1,077	)	(770	)
Profit (loss) before interest and tax	(1,025	)	(721	)	(1,596	)	(1,152	)
Inventory holding (gains) losses*	—		—		—		—
RC profit (loss) before interest and tax	(1,025	)	(721	)	(1,596	)	(1,152	)
Net charge (credit) for non-operating items*
Gulf of Mexico oil spill - business economic loss claims	249		260		249		260
Gulf of Mexico oil spill - other	184		87		270		122
Other	115		8		208		(36	)
Net charge (credit) for non-operating items	548		355		727		346
Underlying RC profit (loss) before interest and tax*	(477	)	(366	)	(869	)	(806	)
Underlying RC profit (loss) before interest and tax
US	(123	)	(104	)	(270	)	(301	)
Non-US	(354	)	(262	)	(599	)	(505	)
	(477	)	(366	)	(869	)	(806	)
Non-operating items
US	(498	)	(350	)	(646	)	(388	)
Non-US	(50	)	(5	)	(81	)	42
	(548	)	(355	)	(727	)	(346	)
RC profit (loss) before interest and tax
US	(621	)	(454	)	(916	)	(689	)
Non-US	(404	)	(267	)	(680	)	(463	)
	(1,025	)	(721	)	(1,596	)	(1,152	)


(a)	Includes sales to other segments.

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 second quarter and half year was $1,025 million and $1,596 million respectively, compared with $721 million and $1,152 million for the same periods in 2017.

The results included a net non-operating charge of $548 million for the second quarter and $727 million for the half year, compared with a charge of $355 million and $346 million for the same periods in 2017. See Note 2 on page 21 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 second quarter and half year was $477 million and $869 million respectively, compared with $366 million and $806 million for the same periods in 2017. The underlying charge for the second quarter was impacted by adverse foreign exchange effects.

Alternative Energy

The net ethanol-equivalent production (which includes ethanol and sugar) for the second quarter and half year was 259 million litres and 267 million litres respectively, compared with 227 million litres for the same periods in 2017 (there was no production for the first quarter in 2017 due to the inter-harvest period).

Net wind generation capacity* was 1,432MW at 30 June 2018, compared with 1,432MW at 30 June 2017. BP’s net share of wind generation for the second quarter and half year was 984GWh and 2,201GWh respectively, compared with 1,053GWh and 2,212GWh for the same periods in 2017.

Lightsource BP, the solar development company 43% owned by BP, made progress on a number of solar development projects during the quarter, including completing a 60MW solar farm in India, being awarded mandates for projects in mid-Kansas in the US, and also completing the acquisition of a portfolio of development projects in Pennsylvania and Maryland, in the US. Lightsource BP, in partnership with Everstone Capital, was also awarded the mandate to manage the Global Growth Energy Fund in India, established and partly funded by the UK and Indian governments.

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Financial statements

Group income statement



	Second		Second	First	First
	quarter		quarter	half	half
$ million	2018		2017	2018	2017

Sales and other operating revenues (Note 6)	75,439		56,511	143,611	112,374
Earnings from joint ventures – after interest and tax	220		160	513	365
Earnings from associates – after interest and tax	1,027		371	1,441	522
Interest and other income	165		127	324	249
Gains on sale of businesses and fixed assets	56		197	161	242
Total revenues and other income	76,907		57,366	146,050	113,752
Purchases	58,424		42,555	109,936	83,530
Production and manufacturing expenses_(a)	5,515		5,761	10,953	11,016
Production and similar taxes (Note 8)	531		347	899	815
Depreciation, depletion and amortization (Note 7)	3,811		3,793	7,742	7,635
Impairment and losses on sale of businesses and fixed assets	(23	)	51	68	504
Exploration expense	164		850	678	1,262
Distribution and administration expenses	2,929		2,540	5,723	4,893
Profit (loss) before interest and taxation	5,556		1,469	10,051	4,097
Finance costs_(a)	535		487	1,088	947
Net finance expense relating to pensions and other post-retirement benefits	31		54	62	107
Profit (loss) before taxation	4,990		928	8,901	3,043
Taxation_(a)	2,117		772	3,497	1,395
Profit (loss) for the period	2,873		156	5,404	1,648
Attributable to
BP shareholders	2,799		144	5,268	1,593
Non-controlling interests	74		12	136	55
	2,873		156	5,404	1,648

Earnings per share (Note 9)
Profit (loss) for the period attributable to BP shareholders
Per ordinary share (cents)
Basic	14.03		0.73	26.42	8.12
Diluted	13.96		0.72	26.27	8.08
Per ADS (dollars)
Basic	0.84		0.04	1.59	0.49
Diluted	0.84		0.04	1.58	0.48


(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



	Second		Second		First		First
	quarter		quarter		half		half
$ million	2018		2017		2018		2017

Profit (loss) for the period	2,873		156		5,404		1,648
Other comprehensive income
Items that may be reclassified subsequently to profit or loss
Currency translation differences	(2,612	)	(103	)	(2,081	)	1,111
Exchange (gains) losses on translation of foreign operations reclassified to gain or loss on sale of businesses and fixed assets	—		4		—		5
Available-for-sale investments	—		1		—		3
Cash flow hedges and costs of hedging	(107	)	148		(189	)	277
Share of items relating to equity-accounted entities, net of tax	(33	)	72		122		303
Income tax relating to items that may be reclassified	52		4		(38	)	(121	)
	(2,700	)	126		(2,186	)	1,578
Items that will not be reclassified to profit or loss
Remeasurements of the net pension and other post-retirement benefit liability or asset	1,714		318		2,579		1,045
Cash flow hedges that will subsequently be transferred to the balance sheet	(35	)	—		(22	)	—
Income tax relating to items that will not be reclassified	(557	)	(102	)	(822	)	(348	)
	1,122		216		1,735		697
Other comprehensive income	(1,578	)	342		(451	)	2,275
Total comprehensive income	1,295		498		4,953		3,923
Attributable to
BP shareholders	1,268		472		4,848		3,835
Non-controlling interests	27		26		105		88
	1,295		498		4,953		3,923

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Condensed group statement of changes in equity



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

Total comprehensive income	4,848		105		4,953
Dividends	(3,556	)	(70	)	(3,626	)
Cash flow hedges transferred to the balance sheet, net of tax	5		—		5
Repurchase of ordinary share capital	(200	)	—		(200	)
Share-based payments, net of tax	414		—		414
Transactions involving non-controlling interests, net of tax	(1	)	1		—
At 30 June 2018	99,821		1,949		101,770

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

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

Total comprehensive income	3,835		88		3,923
Dividends	(2,850	)	(77	)	(2,927	)
Share-based payments, net of tax	334		—		334
Share of equity-accounted entities' changes in equity, net of tax	198		—		198
Transactions involving non-controlling interests, net of tax	—		90		90
At 30 June 2017	96,803		1,658		98,461


(a)	See Note 1 for further information.

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Group balance sheet



	30 June	31 December
$ million	2018	2017
Non-current assets
Property, plant and equipment	124,390	129,471
Goodwill	11,319	11,551
Intangible assets	17,808	18,355
Investments in joint ventures	8,293	7,994
Investments in associates	17,835	16,991
Other investments	1,284	1,245
Fixed assets	180,929	185,607
Loans	505	646
Trade and other receivables	1,472	1,434
Derivative financial instruments	4,633	4,110
Prepayments	1,134	1,112
Deferred tax assets	3,908	4,469
Defined benefit pension plan surpluses	6,354	4,169
	198,935	201,547
Current assets
Loans	298	190
Inventories	21,004	19,011
Trade and other receivables	25,130	24,849
Derivative financial instruments	3,614	3,032
Prepayments	1,277	1,414
Current tax receivable	783	761
Other investments	106	125
Cash and cash equivalents	22,185	25,586
	74,397	74,968
Assets classified as held for sale (Note 3)	2,294	—
	76,691	74,968
Total assets	275,626	276,515
Current liabilities
Trade and other payables	46,635	44,209
Derivative financial instruments	3,643	2,808
Accruals	3,741	4,960
Finance debt	10,625	7,739
Current tax payable	2,283	1,686
Provisions	2,313	3,324
	69,240	64,726
Liabilities directly associated with assets classified as held for sale (Note 3)	291	—
	69,531	64,726
Non-current liabilities
Other payables	13,696	13,889
Derivative financial instruments	5,126	3,761
Accruals	599	505
Finance debt	49,733	55,491
Deferred tax liabilities	8,828	7,982
Provisions	17,783	20,620
Defined benefit pension plan and other post-retirement benefit plan deficits	8,560	9,137
	104,325	111,385
Total liabilities	173,856	176,111
Net assets	101,770	100,404
Equity
BP shareholders’ equity	99,821	98,491
Non-controlling interests	1,949	1,913
Total equity	101,770	100,404

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Condensed group cash flow statement



	Second		Second		First		First
	quarter		quarter		half		half
$ million	2018		2017		2018		2017
Operating activities
Profit (loss) before taxation	4,990		928		8,901		3,043
Adjustments to reconcile profit (loss) before taxation to net cash provided by operating activities
Depreciation, depletion and amortization and exploration expenditure written off	3,892		4,546		8,249		8,649
Impairment and (gain) loss on sale of businesses and fixed assets	(79	)	(146	)	(93	)	262
Earnings from equity-accounted entities, less dividends received	(988	)	(103	)	(1,524	)	(323	)
Net charge for interest and other finance expense, less net interest paid	191		84		271		336
Share-based payments	167		156		404		318
Net operating charge for pensions and other post-retirement benefits, less contributions and benefit payments for unfunded plans	(62	)	54		(264	)	(19	)
Net charge for provisions, less payments	80		183		224		6
Movements in inventories and other current and non-current assets and liabilities	(570	)	3		(3,968	)	(3,597	)
Income taxes paid	(1,315	)	(815	)	(2,248	)	(1,671	)
Net cash provided by operating activities	6,306		4,890		9,952		7,004
Investing activities
Expenditure on property, plant and equipment, intangible and other assets	(3,484	)	(4,181	)	(7,070	)	(8,004	)
Acquisitions, net of cash acquired	(1	)	(123	)	(1	)	(165	)
Investment in joint ventures	(18	)	(10	)	(57	)	(30	)
Investment in associates	(322	)	(174	)	(660	)	(357	)
Total cash capital expenditure	(3,825	)	(4,488	)	(7,788	)	(8,556	)
Proceeds from disposal of fixed assets	105		312		190		500
Proceeds from disposal of businesses, net of cash disposed	45		140		127		213
Proceeds from loan repayments	24		19		33		33
Net cash used in investing activities	(3,651	)	(4,017	)	(7,438	)	(7,810	)
Financing activities
Net issue (repurchase) of shares	(90	)	—		(200	)	—
Proceeds from long-term financing	910		1,720		1,032		5,433
Repayments of long-term financing	(1,726	)	(1,463	)	(2,883	)	(2,380	)
Net increase (decrease) in short-term debt	292		(299	)	(57	)	16
Net increase (decrease) in non-controlling interests	—		51		(1	)	81
Dividends paid - BP shareholders	(1,727	)	(1,546	)	(3,556	)	(2,850	)
- non-controlling interests	(57	)	(62	)	(70	)	(77	)
Net cash provided by (used in) financing activities	(2,398	)	(1,599	)	(5,735	)	223
Currency translation differences relating to cash and cash equivalents	(314	)	202		(169	)	369
Increase (decrease) in cash and cash equivalents	(57	)	(524	)	(3,390	)	(214	)
Cash and cash equivalents at beginning of period	22,242		23,794		25,575		23,484
Cash and cash equivalents at end of period	22,185		23,270		22,185		23,270

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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.

The directors consider it appropriate to adopt the going concern basis of accounting in preparing these interim financial statements.

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

The financial information presented herein has been prepared in accordance with the accounting policies expected to be used in preparing BP Annual Report and Form 20-F 2018, which are the same as those used in preparing BP Annual Report and Form 20-F 2017 with the exception of the implementation of IFRS 9 'Financial Instruments' and IFRS 15 'Revenue from Contracts with Customers' from 1 January 2018.

New International Financial Reporting Standards adopted

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

IFRS 9 ‘Financial Instruments’

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

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

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

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



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

Net assets	100,404		100,224		(180	)

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Note 1. Basis of preparation (continued)

IFRS 15 ‘Revenue from Contracts with Customers’

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

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

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

Change in significant estimate - decommissioning provision

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

The impact of the review was a reduction in the provision of $1.5 billion as at 30 June 2018, with a similar reduction in the carrying amount of property, plant and equipment. There was no significant impact on the income statement for the first half of 2018. The impact on the income statement for the second half of 2018 is estimated to be a decrease in depreciation, depletion and amortization of around $80 million and an increase in finance costs of around $120 million.

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

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Note 2. Gulf of Mexico oil spill

(a) Overview

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

The group income statement includes a post-tax charge for the second quarter of $193 million relating to business economic loss (BEL) claims and $126 million relating to other claims and litigation. The group income statement also includes finance costs relating to the unwinding of discounting effects relating to payables.

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



	Second		Second		First		First
	quarter		quarter		half		half
$ million	2018		2017		2018		2017
Income statement
Production and manufacturing expenses	433		347		519		382
Profit (loss) before interest and taxation	(433	)	(347	)	(519	)	(382	)
Finance costs	118		121		238		247
Profit (loss) before taxation	(551	)	(468	)	(757	)	(629	)
Taxation	106		154		167		202
Profit (loss) for the period	(445	)	(314	)	(590	)	(427	)

The cumulative pre-tax income statement charge since the incident, in April 2010, amounts to $66,522 million.



	30 June		31 December
$ million	2018		2017
Balance sheet
Current assets
Trade and other receivables	207		252
Current liabilities
Trade and other payables	(2,464	)	(2,089	)
Provisions	(253	)	(1,439	)
Net current assets (liabilities)	(2,510	)	(3,276	)
Non-current assets
Deferred tax assets	1,775		2,067
Non-current liabilities
Other payables	(12,047	)	(12,253	)
Provisions	(172	)	(1,141	)
Deferred tax liabilities	3,816		3,634
Net non-current assets (liabilities)	(6,628	)	(7,693	)
Net assets (liabilities)	(9,138	)	(10,969	)



	Second		Second		First		First
	quarter		quarter		half		half
$ million	2018		2017		2018		2017
Cash flow statement - Operating activities
Profit (loss) before taxation	(551	)	(468	)	(757	)	(629	)
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	118		121		238		247
Net charge for provisions, less payments	48		298		102		293
Movements in inventories and other current and non-current assets and liabilities	(693	)	(1,976	)	(2,281	)	(4,230	)
Pre-tax cash flows	(1,078	)	(2,025	)	(2,698	)	(4,319	)

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Note 2. Gulf of Mexico oil spill (continued)

Cash outflows in 2018 and 2017 include payments made under the 2012 agreement with the US government to resolve all federal criminal claims arising from the incident and the 2016 consent decree and settlement agreement with the United States and the five Gulf coast states. Included in the current quarter cash outflow are payments of $550 million relating to the 2016 consent decree and settlement agreement. Net cash from operating activities relating to the Gulf of Mexico oil spill, on a post-tax basis, amounted to an outflow of $707 million and $2,421 million in the second quarter and half year of 2018 respectively. For the same periods in 2017, the amount was an outflow of $2,025 million and $4,319 million respectively.

(b) Provisions and other payables

Provisions

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



$ million
At 1 April 2018	2,231
Net increase in provision	411
Reclassified to other payables	(1,816	)
Utilization	(401	)
At 30 June 2018	425

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



$ million
At 1 January 2018	2,580
Net increase in provision	476
Reclassified to other payables	(1,875	)
Utilization	(756	)
At 30 June 2018	425

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

PSC settlement

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

The settlement programme’s determination of BEL claims was substantially completed by the end of 2017 and remaining claims continued to be processed in the first half of 2018 with only a very small number of claims now remaining to be determined. Nevertheless, a significant number of BEL claims determined by the settlement programme have been and continue to be appealed by BP and/or the claimants. During the second quarter settlement agreements were reached with claimants for a significant proportion of the provision existing at the beginning of the quarter. Amounts payable under these settlement agreements have been reclassified from provisions to other payables. The remaining amount provided for includes the latest estimate of the amounts that are expected ultimately to be paid to resolve outstanding BEL claims. Claims under appeal will ultimately only be resolved once the full judicial appeals process has been concluded, including appeals to the Federal District Court and Fifth Circuit, as may be the case, or when settlements are reached with individual claimants. Depending upon the ultimate resolution of these claims, the amounts payable may differ from those currently provided.

Payments to resolve outstanding claims under the PSC settlement are expected to be made over a number of years. The timing of payments, however, is uncertain, and, in particular, will be impacted by how long it takes to resolve claims that have been appealed and may be appealed in the future.

Other payables

Other payables includes amounts reclassified from provisions during the period which are payable over a period of up to nine years.

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

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

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Note 3. Non-current assets held for sale

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

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

Note 4. Event after the reporting period

On 26 July 2018, BP announced that it has agreed to acquire a portfolio of US onshore unconventional oil and gas assets in the Permian and Eagle Ford basins in Texas and in the Haynesville gas basin in Texas and Louisiana, from BHP. Subject to regulatory approvals, the transaction is anticipated to complete by the end of October 2018 and is expected to be accounted for as a business combination. Subject to completion, the effective date of the transaction is 1 July 2018. Under the terms of the agreement, BP will acquire 100% of the issued share capital of Petrohawk Energy Corporation, the wholly-owned subsidiary of BHP which holds the assets, for a total consideration of $10.5 billion, subject to customary adjustments. On completion, $5.25 billion, as adjusted, will be paid in cash. $5.25 billion will be deferred and payable in cash in six equal instalments over six months from the date of completion. BP intends to finance the deferred consideration through equity issued over the duration of the instalments. Following completion of the acquisition, BP intends to make new divestments of $5-6 billion, predominantly from the Upstream segment. The proceeds are intended to fund a share buyback programme of up to $5-6 billion over time.

Note 5. Analysis of replacement cost profit (loss) before interest and tax and reconciliation to profit (loss) before taxation



	Second		Second		First		First
	quarter		quarter		half		half
$ million	2018		2017		2018		2017
Upstream	3,514		795		6,688		2,051
Downstream	840		1,567		2,553		3,273
Rosneft	766		279		1,013		378
Other businesses and corporate_(a)	(1,025	)	(721	)	(1,596	)	(1,152	)
	4,095		1,920		8,658		4,550
Consolidation adjustment – UPII*	151		135		(9	)	67
RC profit (loss) before interest and tax*	4,246		2,055		8,649		4,617
Inventory holding gains (losses)*
Upstream	4		1		5		(5	)
Downstream	1,196		(579	)	1,265		(481	)
Rosneft (net of tax)	110		(8	)	132		(34	)
Profit (loss) before interest and tax	5,556		1,469		10,051		4,097
Finance costs	535		487		1,088		947
Net finance expense relating to pensions and other post-retirement benefits	31		54		62		107
Profit (loss) before taxation	4,990		928		8,901		3,043

RC profit (loss) before interest and tax*
US	(20	)	302		339		815
Non-US	4,266		1,753		8,310		3,802
	4,246		2,055		8,649		4,617


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

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Note 6. Sales and other operating revenues



	Second	Second	First	First
	quarter	quarter	half	half
$ million	2018	2017	2018	2017
By segment
Upstream	12,698	10,493	26,568	21,820
Downstream	69,174	52,195	130,580	102,275
Other businesses and corporate	376	326	719	611
	82,248	63,014	157,867	124,706

Less: sales and other operating revenues between segments
Upstream	5,795	6,161	12,528	11,938
Downstream	785	208	1,267	122
Other businesses and corporate	229	134	461	272
	6,809	6,503	14,256	12,332

Third party sales and other operating revenues
Upstream	6,903	4,332	14,040	9,882
Downstream	68,389	51,987	129,313	102,153
Other businesses and corporate	147	192	258	339
Total sales and other operating revenues	75,439	56,511	143,611	112,374

By geographical area
US	26,676	21,577	50,289	42,729
Non-US	56,032	41,103	107,272	81,123
	82,708	62,680	157,561	123,852
Less: sales and other operating revenues between areas	7,269	6,169	13,950	11,478
	75,439	56,511	143,611	112,374

Sales and other operating revenues include the following in relation to revenues from contracts with customers
Crude oil	17,167	11,784	32,084	22,780
Oil products	51,440	37,079	95,570	73,680
Natural gas, LNG and NGLs	4,960	3,479	10,119	7,317
Non-oil products and other revenues from contracts with customers	3,081	2,872	6,576	5,736
Revenues from contracts with customers_(a)	76,648	55,214	144,349	109,513


(a)	See Note 1 for further information.

Note 7. Depreciation, depletion and amortization



	Second	Second	First	First
	quarter	quarter	half	half
$ million	2018	2017	2018	2017
Upstream
US	999	1,133	2,087	2,370
Non-US	2,226	2,090	4,498	4,144
	3,225	3,223	6,585	6,514
Downstream
US	221	219	440	435
Non-US	293	274	595	553
	514	493	1,035	988
Other businesses and corporate
US	16	16	32	32
Non-US	56	61	90	101
	72	77	122	133
Total group	3,811	3,793	7,742	7,635

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Note 8. Production and similar taxes



	Second	Second	First	First
	quarter	quarter	half	half
$ million	2018	2017	2018	2017
US	89	41	179	77
Non-US	442	306	720	738
	531	347	899	815

Note 9. Earnings per share and shares in issue

Basic earnings per ordinary share (EpS) amounts are calculated by dividing the profit (loss) for the period attributable to ordinary shareholders by the weighted average number of ordinary shares outstanding during the period. During the quarter the company repurchased for cancellation 11 million ordinary shares for a total cost of $80 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.



	Second	Second	First	First
	quarter	quarter	half	half
$ million	2018	2017	2018	2017
Results for the period
Profit (loss) for the period attributable to BP shareholders	2,799	144	5,268	1,593
Less: preference dividend	1	1	1	1
Profit (loss) attributable to BP ordinary shareholders	2,798	143	5,267	1,592

Number of shares (thousand)_(a)
Basic weighted average number of shares outstanding	19,945,053	19,686,613	19,931,945	19,602,785
ADS equivalent	3,324,175	3,281,102	3,321,990	3,267,130

Weighted average number of shares outstanding used to calculate diluted earnings per share	20,044,277	19,783,548	20,050,123	19,713,151
ADS equivalent	3,340,712	3,297,258	3,341,687	3,285,525

Shares in issue at period-end	19,973,943	19,738,566	19,973,943	19,738,566
ADS equivalent	3,328,991	3,289,761	3,328,991	3,289,761


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

Issued ordinary share capital as at 30 June 2018 comprised 19,982,540,709, ordinary shares (30 June 2017 19,751,491,901 ordinary shares). This includes shares held in trust to settle future employee share plan obligations and excludes 1,377,156,087 ordinary shares which have been bought back and are held in treasury by BP (30 June 2017 1,483,428,207 ordinary shares).

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Note 10. Dividends

Dividends payable

On 26 July 2018 BP announced an interim dividend of 10.25 cents per ordinary share which is expected to be paid on 21 September 2018 to ordinary shareholders and American Depositary Share (ADS) holders on the register on 10 August 2018. The corresponding amount in sterling is due to be announced on 11 September 2018, calculated based on the average of the market exchange rates for the four dealing days commencing on 5 September 2018. Holders of ADSs are expected to receive $0.615 per ADS (less applicable fees). A scrip dividend alternative is available, allowing shareholders to elect to receive their dividend in the form of new ordinary shares and ADS holders in the form of new ADSs. Details of the second quarter dividend and timetable are available at bp.com/dividends and details of the scrip dividend programme are available at bp.com/scrip.



	Second	Second	First	First
	quarter	quarter	half	half
	2018	2017	2018	2017
Dividends paid per ordinary share
cents	10.000	10.000	20.000	20.000
pence	7.444	7.756	14.613	15.915
Dividends paid per ADS (cents)	60.00	60.00	120.00	120.00
Scrip dividends
Number of shares issued (millions)	34.5	70.1	57.9	185.2
Value of shares issued ($ million)	266	420	421	1,062

Note 11. Net Debt*



Net debt ratio*	Second	Second	First	First
	quarter	quarter	half	half	Year
$ million	2018	2017	2018	2017	2017
Gross debt	60,358	63,004	60,358	63,004	63,230
Fair value (asset) liability of hedges related to finance debt_(a)	1,104	60	1,104	60	175
	61,462	63,064	61,462	63,064	63,405
Less: cash and cash equivalents	22,185	23,270	22,185	23,270	25,586
Net debt	39,277	39,794	39,277	39,794	37,819
Equity	101,770	98,461	101,770	98,461	100,404
Net debt ratio	27.8%	28.8%	27.8%	28.8%	27.4%



Analysis of changes in net debt	Second		Second		First		First
	quarter		quarter		half		half		Year
$ million	2018		2017		2018		2017		2017
Opening balance
Finance debt_(a)	62,189		61,832		63,230		58,300		58,300
Fair value (asset) liability of hedges related to finance debt_(b)	46		597		175		697		697
Less: cash and cash equivalents_(c)	22,242		23,794		25,575		23,484		23,484
Opening net debt	39,993		38,635		37,830		35,513		35,513
Closing balance
Finance debt_(a)	60,358		63,004		60,358		63,004		63,230
Fair value (asset) liability of hedges related to finance debt_(b)	1,104		60		1,104		60		175
Less: cash and cash equivalents	22,185		23,270		22,185		23,270		25,586
Closing net debt	39,277		39,794		39,277		39,794		37,819
Decrease (increase) in net debt	716		(1,159	)	(1,447	)	(4,281	)	(2,306	)
Movement in cash and cash equivalents (excluding exchange adjustments)	257		(726	)	(3,221	)	(583	)	1,558
Net cash outflow (inflow) from financing	524		42		1,908		(3,069	)	(2,520	)
Other movements	(123	)	(13	)	(150	)	(79	)	(564	)
Movement in net debt before exchange effects	658		(697	)	(1,463	)	(3,731	)	(1,526	)
Exchange adjustments	58		(462	)	16		(550	)	(780	)
Decrease (increase) in net debt	716		(1,159	)	(1,447	)	(4,281	)	(2,306	)


(a)	The fair value of finance debt at 30 June 2018 was $61,619 million (31 December 2017 $65,165 million).

(b)

Derivative financial instruments entered into for the purpose of managing interest rate and foreign currency exchange risk associated with net debt with a fair value liability position of $774 million (full year 2017 liability of $634 million and second quarter 2017 liability of $1,167 million) are not included in the calculation of net debt shown above as hedge accounting is not applied for these instruments.


(c)	See Note 1 for further information.

On 3 July 2018, in the ordinary course of business, the group issued bonds totalling $2.8 billion with maturity dates ranging from 6 to 10 years. The issuance has no effect on the group's net debt or net debt ratio.

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Note 12. Statutory accounts

The financial information shown in this publication, which was approved by the Board of Directors on 30 July 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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Note 13. Condensed consolidating information on certain US subsidiaries

BP p.l.c. fully and unconditionally guarantees the payment obligations of its 100%-owned subsidiary BP Exploration (Alaska) Inc. under the BP Prudhoe Bay Royalty Trust. The following financial information for BP p.l.c., BP Exploration (Alaska) Inc. and all other subsidiaries on a condensed consolidating basis is intended to provide investors with meaningful and comparable financial information about BP p.l.c. and its subsidiary issuers of registered securities and is provided pursuant to Rule 3-10 of Regulation S-X in lieu of the separate financial statements of each subsidiary issuer of public debt securities. Non-current assets for BP p.l.c. includes investments in subsidiaries recorded under the equity method for the purposes of the condensed consolidating financial information. Equity-accounted income of subsidiaries is the group’s share of profit related to such investments. The eliminations and reclassifications column includes the necessary amounts to eliminate the intercompany balances and transactions between BP p.l.c., BP Exploration (Alaska) Inc. and other subsidiaries. The financial information presented in the following tables for BP Exploration (Alaska) Inc. incorporates subsidiaries of BP Exploration (Alaska) Inc. using the equity method of accounting and excludes the BP group’s midstream operations in Alaska that are reported through different legal entities and that are included within the ‘other subsidiaries’ column in these tables. BP p.l.c. also fully and unconditionally guarantees securities issued by BP Capital Markets p.l.c. and BP Capital Markets America Inc. These companies are 100%-owned finance subsidiaries of BP p.l.c.

Income statement



First half 2018	Issuer	Guarantor
$ million	BP Exploration (Alaska) Inc.	BP p.l.c.		Other subsidiaries	Eliminations and reclassifications		BP group
Sales and other operating revenues	2,199	—		143,552	(2,140	)	143,611
Earnings from joint ventures - after interest and tax	—	—		513	—		513
Earnings from associates - after interest and tax	—	—		1,441	—		1,441
Equity-accounted income of subsidiaries - after interest and tax	—	6,028		—	(6,028	)	—
Interest and other income	18	112		893	(699	)	324
Gains on sale of businesses and fixed assets	—	—		161	—		161
Total revenues and other income	2,217	6,140		146,560	(8,867	)	146,050
Purchases	705	—		111,371	(2,140	)	109,936
Production and manufacturing expenses	481	—		10,472	—		10,953
Production and similar taxes	144	—		755	—		899
Depreciation, depletion and amortization	262	—		7,480	—		7,742
Impairment and losses on sale of businesses and fixed assets	—	—		68	—		68
Exploration expense	—	—		678	—		678
Distribution and administration expenses	10	344		5,402	(33	)	5,723
Profit (loss) before interest and taxation	615	5,796		10,334	(6,694	)	10,051
Finance costs	3	577		1,174	(666	)	1,088
Net finance (income) expense relating to pensions and other post-retirement benefits	—	(49	)	111	—		62
Profit (loss) before taxation	612	5,268		9,049	(6,028	)	8,901
Taxation	83	—		3,414	—		3,497
Profit (loss) for the year	529	5,268		5,635	(6,028	)	5,404
Attributable to
BP shareholders	529	5,268		5,499	(6,028	)	5,268
Non-controlling interests	—	—		136	—		136
	529	5,268		5,635	(6,028	)	5,404

Statement of comprehensive income



First half 2018	Issuer	Guarantor
$ million	BP Exploration (Alaska) Inc.	BP p.l.c.		Other subsidiaries		Eliminations and reclassifications		BP group
Profit (loss) for the year	529	5,268		5,635		(6,028	)	5,404
Other comprehensive income	—	1,686		(2,137	)	—		(451	)
Equity-accounted other comprehensive income of subsidiaries	—	(2,106	)	—		2,106		—
Total comprehensive income	529	4,848		3,498		(3,922	)	4,953
Attributable to
BP shareholders	529	4,848		3,393		(3,922	)	4,848
Non-controlling interests	—	—		105		—		105
	529	4,848		3,498		(3,922	)	4,953

Table of contents

Note 13. Condensed consolidating information on certain US subsidiaries (continued)

Income statement continued



First half 2017	Issuer		Guarantor
$ million	BP Exploration (Alaska) Inc.		BP p.l.c.		Other subsidiaries	Eliminations and reclassifications		BP group
Sales and other operating revenues	1,614		—		112,355	(1,595	)	112,374
Earnings from joint ventures - after interest and tax	—		—		365	—		365
Earnings from associates - after interest and tax	—		—		522	—		522
Equity-accounted income of subsidiaries - after interest and tax	—		2,055		—	(2,055	)	—
Interest and other income	1		134		613	(499	)	249
Gains on sale of businesses and fixed assets	—		—		242	—		242
Total revenues and other income	1,615		2,189		114,097	(4,149	)	113,752
Purchases	516		—		84,609	(1,595	)	83,530
Production and manufacturing expenses	580		—		10,436	—		11,016
Production and similar taxes	46		—		769	—		815
Depreciation, depletion and amortization	415		—		7,220	—		7,635
Impairment and losses on sale of businesses and fixed assets	—		—		504	—		504
Exploration expense	—		—		1,262	—		1,262
Distribution and administration expenses	11		254		4,678	(50	)	4,893
Profit (loss) before interest and taxation	47		1,935		4,619	(2,504	)	4,097
Finance costs	3		371		1,022	(449	)	947
Net finance (income) expense relating to pensions and other post-retirement benefits	—		(7	)	114	—		107
Profit (loss) before taxation	44		1,571		3,483	(2,055	)	3,043
Taxation	(13	)	(22	)	1,430	—		1,395
Profit (loss) for the year	57		1,593		2,053	(2,055	)	1,648
Attributable to
BP shareholders	57		1,593		1,998	(2,055	)	1,593
Non-controlling interests	—		—		55	—		55
	57		1,593		2,053	(2,055	)	1,648

Statement of comprehensive income continued



First half 2017	Issuer	Guarantor
$ million	BP Exploration (Alaska) Inc.	BP p.l.c.	Other subsidiaries	Eliminations and reclassifications		BP group
Profit (loss) for the year	57	1,593	2,053	(2,055	)	1,648
Other comprehensive income	—	578	1,697	—		2,275
Equity-accounted other comprehensive income of subsidiaries	—	1,664	—	(1,664	)	—
Total comprehensive income	57	3,835	3,750	(3,719	)	3,923
Attributable to
BP shareholders	57	3,835	3,662	(3,719	)	3,835
Non-controlling interests	—	—	88	—		88
	57	3,835	3,750	(3,719	)	3,923

Table of contents

Note 13. Condensed consolidating information on certain US subsidiaries (continued)

Balance sheet



At 30 June 2018	Issuer	Guarantor
$ million	BP Exploration (Alaska) Inc.	BP p.l.c.	Other subsidiaries	Eliminations and reclassifications		BP group
Non-current assets
Property, plant and equipment	4,577	—	119,813	—		124,390
Goodwill	—	—	11,319	—		11,319
Intangible assets	588	—	17,220	—		17,808
Investments in joint ventures	—	—	8,293	—		8,293
Investments in associates	—	2	17,833	—		17,835
Other investments	—	—	1,284	—		1,284
Subsidiaries - equity-accounted basis	—	165,566	—	(165,566	)	—
Fixed assets	5,165	165,568	175,762	(165,566	)	180,929
Loans	—	—	34,393	(33,888	)	505
Trade and other receivables	—	2,433	1,472	(2,433	)	1,472
Derivative financial instruments	—	—	4,633	—		4,633
Prepayments	—	—	1,134	—		1,134
Deferred tax assets	—	—	3,908	—		3,908
Defined benefit pension plan surpluses	—	5,708	646	—		6,354
	5,165	173,709	221,948	(201,887	)	198,935
Current assets
Loans	—	—	298	—		298
Inventories	354	—	20,650	—		21,004
Trade and other receivables	2,600	294	37,130	(14,894	)	25,130
Derivative financial instruments	—	—	3,614	—		3,614
Prepayments	49	—	1,228	—		1,277
Current tax receivable	—	—	783	—		783
Other investments	—	—	106	—		106
Cash and cash equivalents	—	15	22,170	—		22,185
	3,003	309	85,979	(14,894	)	74,397
Assets classified as held for sale (Note 3)	2,138	—	156	—		2,294
	5,141	309	86,135	(14,894	)	76,691
Total assets	10,306	174,018	308,083	(216,781	)	275,626
Current liabilities
Trade and other payables	544	12,117	48,868	(14,894	)	46,635
Derivative financial instruments	—	—	3,643	—		3,643
Accruals	77	59	3,605	—		3,741
Finance debt	—	—	10,625	—		10,625
Current tax payable	77	48	2,158	—		2,283
Provisions	1	—	2,312	—		2,313
	699	12,224	71,211	(14,894	)	69,240
Liabilities directly associated with assets classified as held for sale (Note 3)	291	—	—	—		291
	990	12,224	71,211	(14,894	)	69,531
Non-current liabilities
Other payables	1	33,888	16,128	(36,321	)	13,696
Derivative financial instruments	—	—	5,126	—		5,126
Accruals	—	—	599	—		599
Finance debt	—	—	49,733	—		49,733
Deferred tax liabilities	861	1,337	6,630	—		8,828
Provisions	733	—	17,050	—		17,783
Defined benefit pension plan and other post-retirement benefit plan deficits	—	198	8,362	—		8,560
	1,595	35,423	103,628	(36,321	)	104,325
Total liabilities	2,585	47,647	174,839	(51,215	)	173,856
Net assets	7,721	126,371	133,244	(165,566	)	101,770
Equity
BP shareholders’ equity	7,721	126,371	131,295	(165,566	)	99,821
Non-controlling interests	—	—	1,949	—		1,949
	7,721	126,371	133,244	(165,566	)	101,770

Table of contents

Note 13. Condensed consolidating information on certain US subsidiaries (continued)

Balance sheet continued



At 31 December 2017	Issuer	Guarantor
$ million	BP Exploration (Alaska) Inc.	BP p.l.c.	Other subsidiaries	Eliminations and reclassifications		BP group
Non-current assets
Property, plant and equipment	6,973	—	122,498	—		129,471
Goodwill	—	—	11,551	—		11,551
Intangible assets	585	—	17,770	—		18,355
Investments in joint ventures	—	—	7,994	—		7,994
Investments in associates	—	2	16,989	—		16,991
Other investments	—	—	1,245	—		1,245
Subsidiaries - equity-accounted basis	—	161,840	—	(161,840	)	—
Fixed assets	7,558	161,842	178,047	(161,840	)	185,607
Loans	1	—	34,701	(34,056	)	646
Trade and other receivables	—	2,623	1,434	(2,623	)	1,434
Derivative financial instruments	—	—	4,110	—		4,110
Prepayments	—	—	1,112	—		1,112
Deferred tax assets	—	—	4,469	—		4,469
Defined benefit pension plan surpluses	—	3,838	331	—		4,169
	7,559	168,303	224,204	(198,519	)	201,547
Current assets
Loans	—	—	190	—		190
Inventories	274	—	18,737	—		19,011
Trade and other receivables	2,206	293	32,691	(10,341	)	24,849
Derivative financial instruments	—	—	3,032	—		3,032
Prepayments	2	—	1,412	—		1,414
Current tax receivable	—	—	761	—		761
Other investments	—	—	125	—		125
Cash and cash equivalents	—	10	25,576	—		25,586
	2,482	303	82,524	(10,341	)	74,968
Total assets	10,041	168,606	306,728	(208,860	)	276,515
Current liabilities
Trade and other payables	673	7,843	46,034	(10,341	)	44,209
Derivative financial instruments	—	—	2,808	—		2,808
Accruals	115	60	4,785	—		4,960
Finance debt	—	—	7,739	—		7,739
Current tax payable	—	—	1,686	—		1,686
Provisions	1	—	3,323	—		3,324
	789	7,903	66,375	(10,341	)	64,726
Non-current liabilities
Other payables	—	34,104	16,464	(36,679	)	13,889
Derivative financial instruments	—	—	3,761	—		3,761
Accruals	—	—	505	—		505
Finance debt	—	—	55,491	—		55,491
Deferred tax liabilities	838	1,337	5,807	—		7,982
Provisions	1,222	—	19,398	—		20,620
Defined benefit pension plan and other post-retirement benefit plan deficits	—	221	8,916	—		9,137
	2,060	35,662	110,342	(36,679	)	111,385
Total liabilities	2,849	43,565	176,717	(47,020	)	176,111
Net assets	7,192	125,041	130,011	(161,840	)	100,404
Equity
BP shareholders’ equity	7,192	125,041	128,098	(161,840	)	98,491
Non-controlling interests	—	—	1,913	—		1,913
	7,192	125,041	130,011	(161,840	)	100,404

Table of contents

Note 13. Condensed consolidating information on certain US subsidiaries (continued)

Cash flow statement



First half 2018	Issuer		Guarantor
$ million	BP Exploration (Alaska) Inc.		BP p.l.c.		Other subsidiaries		BP group
Net cash provided by operating activities	171		3,543		6,238		9,952
Net cash provided by (used in) investing activities	(171	)	—		(7,267	)	(7,438	)
Net cash provided by (used in) financing activities	—		(3,538	)	(2,197	)	(5,735	)
Currency translation differences relating to cash and cash equivalents	—		—		(169	)	(169	)
Increase (decrease) in cash and cash equivalents	—		5		(3,395	)	(3,390	)
Cash and cash equivalents at beginning of year_(a)	—		10		25,565		25,575
Cash and cash equivalents at end of year	—		15		22,170		22,185

First half 2017	Issuer		Guarantor
$ million	BP Exploration (Alaska) Inc.		BP p.l.c.		Other subsidiaries		BP group
Net cash provided by operating activities	177		2,799		4,028		7,004
Net cash provided by (used in) investing activities	(177	)	—		(7,633	)	(7,810	)
Net cash provided by (used in) financing activities	—		(2,849	)	3,072		223
Currency translation differences relating to cash and cash equivalents	—		—		369		369
Increase (decrease) in cash and cash equivalents	—		(50	)	(164	)	(214	)
Cash and cash equivalents at beginning of year	—		50		23,434		23,484
Cash and cash equivalents at end of year	—		—		23,270		23,270


(a)	See Note 1 for further information.

Table of contents

Additional information

Capital expenditure*



	Second	Second	First	First
	quarter	quarter	half	half
$ million	2018	2017	2018	2017
Capital expenditure on a cash basis
Organic capital expenditure*	3,470	4,348	7,008	7,886
Inorganic capital expenditure*_(a)	355	140	780	670
	3,825	4,488	7,788	8,556



	Second	Second	First	First
	quarter	quarter	half	half
$ million	2018	2017	2018	2017
Organic capital expenditure by segment
Upstream
US	826	805	1,580	1,446
Non-US	1,941	3,005	4,053	5,344
	2,767	3,810	5,633	6,790
Downstream
US	232	149	403	301
Non-US	382	316	829	636
	614	465	1,232	937
Other businesses and corporate
US	7	3	14	24
Non-US	82	70	129	135
	89	73	143	159
	3,470	4,348	7,008	7,886
Organic capital expenditure by geographical area
US	1,065	957	1,997	1,771
Non-US	2,405	3,391	5,011	6,115
	3,470	4,348	7,008	7,886


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

Table of contents

Non-operating items*



	Second		Second		First		First
	quarter		quarter		half		half
$ million	2018		2017		2018		2017
Upstream
Impairment and gain (loss) on sale of businesses and fixed assets_(a)	81		(18	)	107		(400	)
Environmental and other provisions	—		—		—		—
Restructuring, integration and rationalization costs	(62	)	(19	)	(61	)	(17	)
Fair value gain (loss) on embedded derivatives	9		5		16		30
Other	(1	)	11		(139	)	6
	27		(21	)	(77	)	(381	)
Downstream
Impairment and gain (loss) on sale of businesses and fixed assets	(1	)	156		(15	)	145
Environmental and other provisions	—		—		—		—
Restructuring, integration and rationalization costs	(74	)	(18	)	(110	)	(83	)
Fair value gain (loss) on embedded derivatives	—		—		—		—
Other	(150	)	—		(153	)	—
	(225	)	138		(278	)	62
Rosneft
Impairment and gain (loss) on sale of businesses and fixed assets	—		—		—		—
Environmental and other provisions	—		—		—		—
Restructuring, integration and rationalization costs	—		—		—		—
Fair value gain (loss) on embedded derivatives	—		—		—		—
Other	—		—		—		—
	—		—		—		—
Other businesses and corporate
Impairment and gain (loss) on sale of businesses and fixed assets	(1	)	8		1		(7	)
Environmental and other provisions	1		(3	)	(20	)	(3	)
Restructuring, integration and rationalization costs	(30	)	(23	)	(45	)	(31	)
Fair value gain (loss) on embedded derivatives	—		—		—		—
Gulf of Mexico oil spill - business economic loss claims_(b)	(249	)	(260	)	(249	)	(260	)
Gulf of Mexico oil spill - other_(b)	(184	)	(87	)	(270	)	(122	)
Other	(85	)	10		(144	)	77
	(548	)	(355	)	(727	)	(346	)
Total before interest and taxation	(746	)	(238	)	(1,082	)	(665	)
Finance costs_(b)	(118	)	(121	)	(238	)	(247	)
Total before taxation	(864	)	(359	)	(1,320	)	(912	)
Taxation credit (charge) on non-operating items	141		144		229		392
Taxation - impact of US tax reform_(c)	—		—		121		—
Total after taxation for period	(723	)	(215	)	(970	)	(520	)


(a)	First half 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 half 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.

Table of contents

Non-GAAP information on fair value accounting effects



	Second		Second		First		First
	quarter		quarter		half		half
$ million	2018		2017		2018		2017
Favourable (adverse) impact relative to management’s measure of performance
Upstream	(21	)	106		100		352
Downstream	(390	)	16		(450	)	56
	(411	)	122		(350	)	408
Taxation credit (charge)	101		(38	)	90		(117	)
	(310	)	84		(260	)	291

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

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

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

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

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

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

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

Table of contents

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.



	Second		Second	First		First
	quarter		quarter	half		half
$ million	2018		2017	2018		2017
Upstream
Replacement cost profit before interest and tax adjusted for fair value accounting effects	3,535		689	6,588		1,699
Impact of fair value accounting effects	(21	)	106	100		352
Replacement cost profit before interest and tax	3,514		795	6,688		2,051
Downstream
Replacement cost profit before interest and tax adjusted for fair value accounting effects	1,230		1,551	3,003		3,217
Impact of fair value accounting effects	(390	)	16	(450	)	56
Replacement cost profit before interest and tax	840		1,567	2,553		3,273
Total group
Profit (loss) before interest and tax adjusted for fair value accounting effects	5,967		1,347	10,401		3,689
Impact of fair value accounting effects	(411	)	122	(350	)	408
Profit (loss) before interest and tax	5,556		1,469	10,051		4,097

Readily marketable inventory* (RMI)



	30 June	31 December
$ million	2018	2017
RMI at fair value*	6,058	5,661
Paid-up RMI*	2,744	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 40 for a more detailed definition of RMI. RMI, RMI at fair value, paid-up RMI and unpaid RMI are non-GAAP measures. A reconciliation of total inventory as reported on the group balance sheet to paid-up RMI is provided below.



	30 June		31 December
$ million	2018		2017
Reconciliation of total inventory to paid-up RMI
Inventories as reported on the group balance sheet under IFRS	21,004		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	(15,453	)	(13,929	)
	5,551		5,082
Plus: difference between RMI at fair value and RMI on an IFRS basis	507		579
RMI at fair value	6,058		5,661
Less: unpaid RMI* at fair value	(3,314	)	(2,973	)
Paid-up RMI	2,744		2,688

Table of contents

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



	Second		Second		First		First
	quarter		quarter		half		half
Per ordinary share (cents)	2018		2017		2018		2017
Profit for the period	14.03		0.73		26.42		8.12
Inventory holding (gains) losses*, before tax	(6.57	)	2.97		(7.03	)	2.65
Taxation charge (credit) on inventory holding gains and losses	1.50		(0.90	)	1.57		(0.75	)
Replacement cost (RC) profit (loss)*	8.96		2.80		20.96		10.02
Net (favourable) adverse impact of non-operating items* and fair value accounting effects*, before tax	6.39		1.21		8.38		2.57
Taxation charge (credit) on non-operating items and fair value accounting effects	(1.21	)	(0.54	)	(2.21	)	(1.40	)
Underlying RC profit*	14.14		3.47		27.13		11.19

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



Taxation (charge) credit
	Second		Second		First		First
	quarter		quarter		half		half
$ million	2018		2017		2018		2017
Taxation on profit or loss	(2,117	)	(772	)	(3,497	)	(1,395	)
Taxation on inventory holding gains and losses	(300	)	177		(312	)	148
Taxation on a replacement cost (RC) profit or loss basis	(1,817	)	(949	)	(3,185	)	(1,543	)
Taxation on non-operating items and fair value accounting effects	242		106		440		275
Taxation on underlying replacement cost profit or loss	(2,059	)	(1,055	)	(3,625	)	(1,818	)



Effective tax rate
	Second		Second		First		First
	quarter		quarter		half		half
%	2018		2017		2018		2017
ETR on profit or loss	42		83		39		46
Adjusted for inventory holding gains or losses	7		(20	)	3		(3	)
ETR on RC profit or loss*	49		63		42		43
Adjusted for non-operating items and fair value accounting effects	(7	)	(3	)	(2	)	2
Underlying ETR*	42		60		40		45

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Realizations* and marker prices



	Second	Second	First	First
	quarter	quarter	half	half
	2018	2017	2018	2017
Average realizations_(a)
Liquids* ($/bbl)
US	62.47	44.65	60.01	45.51
Europe	71.70	47.79	68.56	50.50
Rest of World	69.88	47.11	66.50	49.46
BP Average	67.24	46.27	64.21	48.09
Natural gas ($/mcf)
US	1.96	2.32	2.10	2.41
Europe	7.04	4.48	7.11	4.93
Rest of World	4.16	3.47	4.19	3.64
BP Average	3.65	3.19	3.72	3.34
Total hydrocarbons* ($/boe)
US	40.77	32.46	40.19	33.39
Europe	64.91	41.10	62.72	43.84
Rest of World	42.89	33.48	41.69	35.64
BP Average	43.37	33.59	42.36	35.37
Average oil marker prices ($/bbl)
Brent	74.39	49.64	70.58	51.71
West Texas Intermediate	68.02	48.11	65.52	49.89
Western Canadian Select	49.76	38.55	43.30	38.66
Alaska North Slope	73.93	50.61	70.64	52.20
Mars	69.47	46.92	66.04	48.24
Urals (NWE – cif)	72.21	48.48	68.71	50.22
Average natural gas marker prices
Henry Hub gas price_(b)($/mmBtu)	2.80	3.19	2.90	3.25
UK Gas – National Balancing Point (p/therm)	53.88	37.83	55.94	43.14


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


(b)	Henry Hub First of Month Index.

Exchange rates



	Second	Second	First	First
	quarter	quarter	half	half
	2018	2017	2018	2017
$/£ average rate for the period	1.36	1.28	1.38	1.26
$/£ period-end rate	1.31	1.30	1.31	1.30

$/€ average rate for the period	1.19	1.10	1.21	1.08
$/€ period-end rate	1.16	1.14	1.16	1.14

Rouble/$ average rate for the period	62.13	57.24	59.47	57.98
Rouble/$ period-end rate	63.07	59.05	63.07	59.05

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Principal risks and uncertainties

The principal risks and uncertainties affecting BP are described in the Risk factors section of BP Annual Report and Form 20-F 2017 (pages 57-58) and are summarized below. There are no material changes in those risk factors for the remaining six months of the financial year.

The risks summarized below, separately or in combination, could have a material adverse effect on the implementation of our strategy, our business, financial performance, results of operations, cash flows, liquidity, prospects, shareholder value and returns and reputation.

Strategic and commercial risks


•	Prices and markets - our financial performance is impacted by fluctuating prices of oil, gas and refined products, technological change, exchange rate fluctuations, and the general macroeconomic outlook.


•	Access, renewal and reserves progression - our inability to access, renew and progress upstream resources in a timely manner could adversely affect our long-term replacement of reserves.


•	Major project* delivery - failure to invest in the best opportunities or deliver major projects successfully could adversely affect our financial performance.


•	Geopolitical - exposure to a range of political developments and consequent changes to the operating and regulatory environment could cause business disruption.


•	Liquidity, financial capacity and financial, including credit, exposure - failure to work within our financial framework could impact our ability to operate and result in financial loss.


•	Joint arrangements and contractors - varying levels of control over the standards, operations and compliance of our partners, contractors and sub-contractors could result in legal liability and reputational damage.


•	Digital infrastructure and cyber security - breach of our digital security or failure of our digital infrastructure including loss or misuse of sensitive information could damage our operations, increase costs and damage our reputation.


•	Climate change and the transition to a lower carbon economy - policy, legal, regulatory, technology and market change related to the issue of climate change could increase costs, reduce demand for our products, reduce revenue and limit certain growth opportunities.


•	Competition - inability to remain efficient, maintain a high quality portfolio of assets, innovate and retain an appropriately skilled workforce could negatively impact delivery of our strategy in a highly competitive market.


•	Crisis management and business continuity - failure to address an incident effectively could potentially disrupt our business.


•	Insurance - our insurance strategy could expose the group to material uninsured losses.

Safety and operational risks


•	Process safety, personal safety, and environmental risks - exposure to a wide range of health, safety, security and environmental risks could result in regulatory action, legal liability, business interruption, increased costs, damage to our reputation and potentially denial of our licence to operate.


•	Drilling and production - challenging operational environments and other uncertainties can impact drilling and production activities.


•	Security - hostile acts against our staff and activities could cause harm to people and disrupt our operations.


•	Product quality - supplying customers with off-specification products could damage our reputation, lead to regulatory action and legal liability, and impact our financial performance.

Compliance and control risks


•	US government settlements - failure to comply with the terms of our settlement with the US Environmental Protection Agency related to the Gulf of Mexico oil spill may expose us to further penalties or liabilities or could result in suspension or debarment of certain BP entities.


•	Regulation - changes in the regulatory and legislative environment could increase the cost of compliance, affect our provisions and limit our access to new growth opportunities.


•	Ethical misconduct and non-compliance - ethical misconduct or breaches of applicable laws by our businesses or our employees could be damaging to our reputation, and could result in litigation, regulatory action and penalties.


•	Treasury and trading activities - ineffective oversight of treasury and trading activities could lead to business disruption, financial loss, regulatory intervention or damage to our reputation.


•	Reporting - failure to accurately report our data could lead to regulatory action, legal liability and reputational damage.

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Legal proceedings

The following discussion sets out the material developments in the group’s material legal proceedings during the first half of 2018. For a full discussion of the group’s material legal proceedings, see pages 270-273 of BP Annual Report and Form 20-F 2017.

Scharfstein v. BP West Coast Products, LLC

A class action lawsuit was filed against BP West Coast Products, LLC in Oregon State Court under the Oregon Unlawful Trade Practices Act on behalf of customers who used a debit card at ARCO gasoline stations in Oregon during the period 1 January 2011 to 30 August 2013, alleging that ARCO sites in Oregon failed to provide sufficient notice of the 35 cents per transaction debit card fee. In January 2014, the jury rendered a verdict against BP West Coast Products, LLC and awarded statutory damages of $200 per class member. On 25 August 2015, the trial court determined the size of the class to be slightly in excess of two million members. On 31 May 2016 the trial court entered a judgment against BP West Coast Products, LLC for the amount of $417.3 million. On 31 May 2018 the Oregon Court of Appeals affirmed the trial court's ruling. BP intends to appeal to the Oregon Supreme Court.

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 37.

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 35 .

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 33.

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 26.

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Glossary (continued)

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

Net wind generation capacity is the sum of the rated capacities of the assets/turbines that have entered into commercial operation, including BP’s share of equity-accounted entities.

Non-operating items are charges and credits included in the financial statements that BP discloses separately because it considers such disclosures to be meaningful and relevant to investors. They are items that management considers not to be part of underlying business operations and are disclosed in order to enable investors better to understand and evaluate the group’s reported financial performance. Non-operating items within equity-accounted earnings are reported net of incremental income tax reported by the equity-accounted entity. An analysis of non-operating items by region is shown on pages 9, 11 and 13, and by segment and type is shown on page 34.

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

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

Organic capital expenditure is a subset of capital expenditure and is a non-GAAP measure. Organic capital expenditure comprises capital expenditure less inorganic capital expenditure. BP believes that this measure provides useful information as it allows investors to understand how BP’s management invests funds in developing and maintaining the group’s assets. An analysis of organic capital expenditure by segment and region, and a reconciliation to GAAP information is provided on page 33.

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 36.

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 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. RC profit or loss before interest and tax is the measure of profit or loss that is required to be disclosed for each operating segment under IFRS.

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Glossary (continued)

RC profit or loss per share is a non-GAAP measure. Earnings per share is defined in Note 9. RC profit or loss per share is calculated using the same denominator. The numerator used is RC profit or loss attributable to BP shareholders rather than profit or loss attributable to BP shareholders. BP believes it is helpful to disclose the RC profit or loss per share because this measure excludes the impact of price changes on the replacement of inventories and allows for more meaningful comparisons between reporting periods. The nearest equivalent measure on an IFRS basis is basic earnings per share based on profit or loss for the period attributable to BP shareholders. A reconciliation to GAAP information is provided on page 37.

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. A reconciliation to GAAP information is provided on page 37.

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

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

Underlying RC profit or loss is RC profit or loss after adjusting for non-operating items and fair value accounting effects. Underlying RC profit or loss and adjustments for fair value accounting effects are not recognized GAAP measures. See pages 29 and 30 for additional information on the non-operating items and fair value accounting effects that are used to arrive at underlying RC profit or loss in order to enable a full understanding of the events and their financial impact. BP believes that underlying RC profit or loss is a useful measure for investors because it is a measure closely tracked by management to evaluate BP’s operating performance and to make financial, strategic and operating decisions and because it may help investors to understand and evaluate, in the same manner as management, the underlying trends in BP’s operational performance on a comparable basis, period on period, by adjusting for the effects of these non-operating items and fair value accounting effects. The nearest equivalent measure on an IFRS basis for the group is profit or loss attributable to BP shareholders. The nearest equivalent measure on an IFRS basis for segments is RC profit or loss before interest and taxation. A reconciliation to GAAP information is provided on page 3.

Underlying RC profit or loss per share is a non-GAAP measure. Earnings per share is defined in Note 9. Underlying RC profit or loss per share is calculated using the same denominator. The numerator used is underlying RC profit or loss attributable to BP shareholders rather than profit or loss attributable to BP shareholders. BP believes it is helpful to disclose the underlying RC profit or loss per share because this measure may help investors to understand and evaluate, in the same manner as management, the underlying trends in BP’s operational performance on a comparable basis, period on period. The nearest equivalent measure on an IFRS basis is basic earnings per share based on profit or loss for the period attributable to BP shareholders. A reconciliation to GAAP information is provided on page 37.

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.

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Other matters

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

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

In May 2018, the U.S. government announced its planned withdrawal from the JCPOA, and tasked OFAC with implementing the full re-imposition of both primary and secondary sanctions in respect of Iran by the end of a wind-down period, which, for Rhum, expires on 4 November 2018. BP and Serica are actively engaged in discussions with both UK and US governments with the aim that the Rhum field can continue to operate during this wind-down period and thereafter.

Cautionary statement

In order to utilize the ‘safe harbor’ provisions of the United States Private Securities Litigation Reform Act of 1995 (the ‘PSLRA’) and the general doctrine of cautionary statements, BP is providing the following cautionary statement: The discussion in this results announcement contains certain forecasts, projections and forward-looking statements - that is, statements related to future, not past events and circumstances - with respect to the financial condition, results of operations and businesses of BP and certain of the plans and objectives of BP with respect to these items. These statements may generally, but not always, be identified by the use of words such as ‘will’, ‘expects’, ‘is expected to’, ‘aims’, ‘should’, ‘may’, ‘objective’, ‘is likely to’, ‘intends’, ‘believes’, ‘anticipates’, ‘plans’, ‘we see’ or similar expressions. In particular, the following, among other statements, are all forward looking in nature: expectations regarding the expected quarterly dividend payment and timing of such payment; plans and expectations to become the leading fuel provider for electric and conventional vehicles; 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; expectations regarding divestment transactions and 2018 divestment proceeds; expectations regarding Upstream third-quarter 2018 reported production and turnaround and maintenance activity; expectations regarding Downstream third-quarter 2018 refining margins and turnaround activity; expectations regarding second-half 2018 decommissioning provision impacts; expectations regarding the amount of Rosneft dividends payable to BP; expectations regarding BP’s stake in LLC Kharampurneftegaz, including the transfer of subsoil use licences; plans and expectations regarding the agreements relating to BP’s increase in its interest in the Clair field and divestment from its interest in the Greater Kuparuk Area and holding in the Kuparuk Transportation Company; plans and expectations regarding the Southern Gas Corridor series of pipelines and the development of the Tortue/Ahmeyim gas project; plans and expectations regarding BP’s acquisition of onshore-US unconventional oil and gas assets from BHP; plans and expectations regarding legal and trial proceedings; plans and expectations regarding the operation of and sale of BP’s interest in the Rhum field; and expectations with respect to the timing and amount of future payments relating to the Gulf of Mexico oil spill including payments for full-year 2018 and 2012 PSC settlement payments. By their nature, forward-looking statements involve risk and uncertainty because they relate to events and depend on circumstances that will or may occur in the future and are outside the control of BP. Actual results may differ materially from those expressed in such statements, depending on a variety of factors, including: the specific factors identified in the discussions accompanying such forward-looking statements; the receipt of relevant third party and/or regulatory approvals; the timing and level of maintenance and/or turnaround activity; the timing and volume of refinery additions and outages; the timing of bringing new fields onstream; the timing, quantum and nature of certain divestments; future levels of industry product supply, demand and pricing, including supply growth in North America; OPEC quota restrictions; PSA effects; operational and safety problems; potential lapses in product quality; economic and financial market conditions generally or in various countries and regions; political stability and economic growth in relevant areas of the world; changes in laws and governmental regulations; regulatory or legal actions including the types of enforcement action pursued and the nature of remedies sought or imposed; the actions of prosecutors, regulatory authorities and courts; delays in the processes for resolving claims; amounts ultimately payable and timing of payments relating to the Gulf of Mexico oil spill; exchange rate fluctuations; development and use of new technology; recruitment and retention of a skilled workforce; the success or otherwise of partnering; the actions of competitors, trading partners, contractors, subcontractors, creditors, rating agencies and others; our access to future credit resources; business disruption and crisis management; the impact on our reputation of ethical misconduct and non-compliance with regulatory obligations; trading losses; major uninsured losses; decisions by Rosneft’s management and board of directors; the actions of contractors; natural disasters and adverse weather conditions; changes in public expectations and other changes to business conditions; wars and acts of terrorism; cyber-attacks or sabotage; and other factors discussed elsewhere in this report 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
	half
	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	6,947
Fixed charges	1,510
Amortization of capitalized interest	94
Distributed income of joint ventures and associates	430
Interest capitalized	(213	)
Preference dividend requirements, gross of tax	(1	)
Non-controlling interest of subsidiaries’ income not incurring fixed charges	(24	)
Total earnings available for fixed charges	8,743

Fixed charges:
Interest expensed	787
Interest capitalized	213
Rental expense representative of interest	509
Preference dividend requirements, gross of tax	1
Total fixed charges	1,510

Ratio of earnings to fixed charges	5.79

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The following table shows the unaudited consolidated capitalization and indebtedness of the BP group as of 30 June 2018 in

accordance with IFRS:

Capitalization and indebtedness



	30 June
$ million	2018
Share capital and reserves
Capital shares (1-2)	5,361
Paid-in surplus (3)	13,773
Merger reserve (3)	27,206
Treasury shares	(15,890	)
Cash flow hedge reserve	(801	)
Costs of hedging reserve	(187	)
Foreign currency translation reserve	(7,259	)
Profit and loss account	77,618
BP shareholders' equity	99,821

Finance debt (4-6)
Due within one year	10,625
Due after more than one year	49,733
Total finance debt	60,358
Total capitalization (7)	160,179


1.	Issued share capital as of 30 June 2018 comprised 19,982,540,709 ordinary shares, par value US$0.25 per share, and 12,706,252 preference shares, par value £1 per share. This excludes 1,377,156,087 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 30 June 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 30 June 2018, the parent company, BP p.l.c., had issued guarantees totalling $57,929 million relating to finance debt of subsidiaries. Thus 96% of the group’s finance debt had been guaranteed by BP p.l.c.

At 30 June 2018, $148 million of finance debt was secured by the pledging of assets. The remainder of finance debt was unsecured.


7.	At 30 June 2018 the group had issued third-party guarantees under which amounts outstanding, incremental to amounts recognized on the group balance sheet, were $305 million in respect of the borrowings of equity-accounted entities and $509 million in respect of the borrowings of other third parties.


8.	On 3 July 2018, in the ordinary course of business, the group issued bonds totalling $2.8 billion with maturity dates ranging from 6 to 10 years.

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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:	31 July 2018	/s/ David J Jackson
		David J Jackson
		Company Secretary