BP PLC — Foreign Filer Report 2017

Aug 1, 2017

6-K 1 d432490d6k.htm FORM 6-K Form 6-K

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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 2017

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 ☒ 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 2017 (a)

| 1. | Management’s Discussion and Analysis of Financial Condition and Results of Operations
for the period January-June 2017 (b) | 3-15, 30-35, 37-39 |
| --- | --- | --- |
| 2. | Consolidated Financial Statements including Notes to Consolidated Financial Statements for
the period January-June 2017 | 14-29 |
| 3. | Principal risks and uncertainties | 36 |
| 4. | Legal proceedings | 40 |
| 5. | Cautionary statement | 40 |
| 6. | Computation of Ratio of Earnings to Fixed Charges | 41 |
| 7. | Capitalization and Indebtedness | 42 |
| 8. | Recent credit ratings update | 43 |
| 9. | Signatures | 44 |

(a) In this Form 6-K, references to the first half 2017 and first half 2016 refer to six-month periods ended 30 June 2017 and 30 June 2016 respectively. References to the second quarter 2017 and second quarter 2016 refer to the three-month periods ended 30 June 2017 and 30 June 2016 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 2016.

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Group results second quarter and half year 2017 (a)

| Highlights |
| --- |
| • Profit for the second quarter was $0.1 billion,
underlying replacement cost (RC) profit for the second quarter was $0.7 billion. • Second-quarter operating cash flow was $4.9 billion after
post-tax Gulf of Mexico oil spill expenditure of $2.0 billion. • Dividend unchanged at 10 cents per share. • Second-quarter Upstream production was 10% higher than in the same
period in 2016; first-half production was 6% higher. • Upstream major projects on track; two new projects sanctioned in quarter; significant gas discoveries in Senegal and Trinidad announced; $753 million exploration write-off, predominantly in
Angola. • In Downstream, first-half fuels marketing earnings around 20% higher
than in the first half of 2016. |

	Second — quarter	quarter		half		half
$ million	2017	2016		2017		2016
Sales and other operating revenues	56,511		46,442		112,374		84,954
Profit (loss) for the period (a)	144		(1,419	)	1,593		(2,002	)
Inventory holding (gains) losses*, before tax	586		(1,188	)	520		(1,056	)
Taxation charge (credit) on inventory holding gains and losses	(177	)	360		(148	)	326
RC profit (loss)*	553		(2,247	)	1,965		(2,732	)
Net (favourable) unfavourable impact of non-operating items and fair value accounting effects, before
tax	237		5,518		504		6,928
Taxation charge (credit) on non-operating items and fair value accounting effects	(106	)	(2,551	)	(275	)	(2,944	)
Underlying RC profit	684		720		2,194		1,252
Profit (loss) per ordinary share (cents)	0.73		(7.60	)	8.12		(10.78	)
Profit (loss) per ADS (dollars)	0.04		(0.46	)	0.49		(0.65	)
RC profit (loss) per ordinary share (cents)*	2.80		(12.03	)	10.02		(14.71	)
RC profit (loss) per ADS (dollars)	0.17		(0.72	)	0.60		(0.88	)
Underlying RC profit per ordinary share (cents)*	3.47		3.85		11.19		6.73
Underlying RC profit per ADS (dollars)	0.21		0.23		0.67		0.40

(a) Profit attributable to BP shareholders.

Bob Dudley – Group chief executive: “We continue to position BP for the new oil price environment, with a continued tight focus on costs, efficiency and discipline in capital spending. We delivered strong operational performance in the first half of 2017 and have considerable strategic momentum coming into the rest of the year and 2018, with rising production from our new Upstream projects and marketing growth in the Downstream.” Brian Gilvary – Chief financial officer: “Cash flow was strong in the first half – organic cash flow exceeded organic capital expenditure and dividends paid. While net debt* rose primarily due to Gulf of Mexico payments, we expect this will improve over the second half as these payments decline and divestment proceeds come in towards the end of the year.”

• See definitions in the Glossary on page 37. RC profit (loss), underlying RC profit, cash flow excluding Gulf of Mexico oil spill payments, organic capital expenditure and net debt are non-GAAP measures.

The commentary above and following should be read in conjunction with the cautionary statement on page 40.

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Group headlines

Earnings

BP’s profit for the second quarter and half year was $144 million and $1,593 million respectively, compared with a loss of $1,419 million and a loss of $2,002 million for the same periods in 2016.

The second-quarter replacement cost (RC) profit was $553 million, compared with a loss of $2,247 million for the same period in 2016. After adjusting for a net charge for non-operating items of $215 million and net favourable fair value accounting effects of $84 million (both on a post-tax basis), underlying RC profit for the second quarter was $684 million, compared with $720 million for the same period in 2016.

For the half year, RC profit was $1,965 million, compared with a loss of $2,732 million a year ago. After adjusting for a net charge for non-operating items of $520 million and net favourable fair value accounting effects of $291 million (both on a post-tax basis), underlying RC profit for the half year was $2,194 million, compared with $1,252 million for the same period in 2016.

See further information on page 5.

Non-operating items

Non-operating items amounted to a charge of $359 million pre-tax and $215 million post-tax for the quarter and a charge of $912 million pre-tax and $520 million post-tax for the half year.

The Gulf of Mexico oil spill charge before interest and tax for the second quarter was $347 million to reflect the latest estimate for claims, including business economic loss claims, and associated administration costs. In addition, the half year also reflects an impairment charge in the first quarter due to the divestment of certain Upstream assets.

Effective tax rate

The effective tax rate (ETR) on the profit or loss for the second quarter and half year was 83% and 46% respectively, compared with 59% and 54% for the same periods in 2016. The ETR on RC profit or loss for the second quarter and half year was 63% and 43% respectively, compared with 51% and 49% for the same periods in 2016. Adjusting for non-operating items and fair value accounting effects, the adjusted ETR for the second quarter and half year was 60% and 45% respectively, compared with 21% and 20% for the same periods in 2016.

The adjusted ETR for the second quarter and half year is higher than a year ago mainly due to the exploration write-offs and changes in the mix of profits, notably the impact of the renewal of our interest in the Abu Dhabi onshore oil concession. We now expect the full year adjusted ETR to be above 40%.

Dividend

BP today announced a quarterly dividend of 10.00 cents per ordinary share ($0.600 per ADS), which is expected to be paid on 22 September 2017. The corresponding amount in sterling will be announced on 12 September 2017. See page 23 for further information.

Operating cash flow*

Operating cash flow for the second quarter and half year was $4.9 billion and $7.0 billion respectively, after post-tax expenditure relating to the Gulf of Mexico oil spill of $2.0 billion and $4.3 billion. For the same periods in 2016 the equivalent amounts were $3.9 billion and $5.8 billion, after post-tax Gulf of Mexico oil spill expenditure of $1.4 billion and $2.5 billion.

Capital expenditure*

Total capital expenditure for the second quarter and half year was $4.5 billion and $8.6 billion respectively, compared with $4.5 billion and $9.0 billion for the same periods in 2016.

Organic capital expenditure* for the second quarter and half year was $4.3 billion and $7.9 billion respectively, compared with $4.2 billion and $8.7 billion for the same periods in 2016.

Inorganic capital expenditure* for the second quarter and half year was $0.1 billion and $0.7 billion respectively, compared with $0.3 billion for both periods in 2016.

Organic and inorganic capital expenditure are non-GAAP measures. See page 30 for further information.

Divestment proceeds*

Divestment proceeds were $0.5 billion for the second quarter and $0.7 billion for the half year, compared with $0.4 billion and $1.6 billion for the same periods in 2016.

Debt

Gross debt at 30 June 2017 was $63.0 billion compared with $55.7 billion a year ago. The ratio of gross debt to gross debt plus equity at 30 June 2017 was 39.0%, compared with 37.2% a year ago.

Net debt at 30 June 2017 was $39.8 billion, compared with $30.9 billion a year ago. The net debt ratio at 30 June 2017 was 28.8%, compared with 24.7% a year ago. Net debt and the net debt ratio are non-GAAP measures. See page 24 for more information.

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Analysis of underlying RC profit before interest and tax

	Second — quarter	quarter		half		half
$ million	2017	2016		2017		2016
Underlying RC profit before interest and tax*
Upstream	710		29		2,080		(718	)
Downstream	1,413		1,513		3,155		3,326
Rosneft	279		246		378		312
Other businesses and corporate	(366	)	(376	)	(806	)	(554	)
Consolidation adjustment - UPII*	135		(121	)	67		(81	)
Underlying RC profit before interest and tax	2,171		1,291		4,874		2,285
Finance costs and net finance expense relating to pensions and other post-retirement benefits	(420	)	(337	)	(807	)	(654	)
Taxation on an underlying RC basis	(1,055	)	(205	)	(1,818	)	(325	)
Non-controlling interests	(12	)	(29	)	(55	)	(54	)
Underlying RC profit attributable to BP shareholders	684		720		2,194		1,252

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 — quarter	quarter		half		half
$ million	2017	2016		2017		2016
RC profit (loss) before interest and tax*
Upstream	795		(109	)	2,051		(1,314	)
Downstream	1,567		1,405		3,273		3,285
Rosneft	279		246		378		312
Other businesses and corporate (a)	(721	)	(5,525	)	(1,152	)	(6,599	)
Consolidation adjustment - UPII	135		(121	)	67		(81	)
RC profit (loss) before interest and tax	2,055		(4,104	)	4,617		(4,397	)
Finance costs and net finance expense relating to pensions and other post-retirement benefits	(541	)	(460	)	(1,054	)	(900	)
Taxation on a RC basis	(949	)	2,346		(1,543	)	2,619
Non-controlling interests	(12	)	(29	)	(55	)	(54	)
RC profit (loss) attributable to BP shareholders	553		(2,247	)	1,965		(2,732	)
Inventory holding gains (losses)	(586	)	1,188		(520	)	1,056
Taxation (charge) credit on inventory holding gains and losses	177		(360	)	148		(326	)
Profit (loss) for the period attributable to BP shareholders	144		(1,419	)	1,593		(2,002	)

(a) Includes costs related to the Gulf of Mexico oil spill. See page 13 and also Note 2 from page 18 for further information on the accounting for the Gulf of Mexico oil spill.

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Strategic progress Upstream Upstream operating performance was strong in the first half, underpinned by 6% production growth and an 18% reduction in unit production costs. BP’s major projects programme is on track to deliver 800,000boe/d of new production by 2020. Three projects have already come online in 2017, Persephone in Australia and Juniper in Trinidad are in final commissioning, and Khazzan Phase 1 in Oman and Zohr in Egypt are expected online before year end. In the second quarter, BP sanctioned development of two new major gas projects: ‘R-Series’ in India and Angelin in Trinidad. BP announced four gas discoveries in the first half. One in Egypt and two in Trinidad may support future developments and the major Yakaar discovery offshore Senegal marked a further step in building BP’s new business in Mauritania and Senegal. BP decided to exit some exploration assets in Angola, leading to higher exploration write-offs in the second quarter. Downstream BP’s fuels marketing business continues to make good strategic progress; first-half earnings were around 20% higher than in the first half of 2016. Premium fuel volumes continue to grow and around 90 new convenience partnership sites have been added so far this year. In lubricants, BP signed an agreement to be the exclusive premium brand sold by Kroger, the largest supermarket chain in the US. In refining, BP increased the level of advantaged feedstock processed in the US and, in petrochemicals, BP’s industry-leading PTA technology is now operational at all its key PTA sites. Financial framework Operating cash flow in the first half of 2017, after post-tax expenditure relating to the Gulf of Mexico oil spill of $4.3 billion, was $7.0 billion, with $4.9 billion in the second quarter, after post-tax expenditure relating to the Gulf of Mexico oil spill of $2.0 billion. This compares with $5.8 billion for the first half of 2016, after post-tax Gulf of Mexico oil spill expenditure of $2.5 billion. Organic capital expenditure of $4.3 billion in the second quarter brought the total for the first half of 2017 to $7.9 billion. BP continues to intend to keep annual organic capital expenditure in the range $15-17 billion. In the first half of 2017, operating cash flow, excluding Gulf of Mexico payments, exceeded organic capital expenditure and cash dividend payments. BP expects divestments of $4.5-5.5 billion in 2017, with proceeds weighted to the second half of the year. Divestment proceeds for the first half of 2017 were $0.7 billion. Gulf of Mexico oil spill payments were $2.0 billion in the second quarter and $4.3 billion in the first half of 2017. Payments are expected to be considerably lower in the second half, and the 2017 full-year estimate is unchanged at $4.5-5.5 billion. The additional charge in the second quarter is not expected to have any significant effect on forecast cash flows in the second half of 2017. BP continues to target a gearing range of 20-30%. At the end of the second quarter, gearing was 28.8%.

Operating metrics	First half 2017 (vs. First half 2016)	Financial metrics	First half 2017 (vs. First half 2016)
Safety Tier 1 process safety events*	11 (+2)	Underlying RC profit i	$2.2bn (+$0.9bn)
Safety Reported recordable injury frequency*	0.22 (-3%)	Operating cash flow excluding Gulf of Mexico oil spill payments	(b)
Group production	3,544mboe/d (+8%)	Organic capital expenditure ii	$7.9bn (-$0.8bn)
Upstream production excluding Rosneft segment	2,410mboe/d (+6%)	Gulf of Mexico oil spill payments	$4.3bn (+$1.8bn)
Upstream unit production costs*	$7.20/boe (-18%)	Divestment proceeds	$0.7bn (-$0.9bn)
BP-operated Upstream operating efficiency* (a)	81.4%	Net debt ratio (gearing) iii	28.8% (+4.1)
Refining availability*	94.8% (-0.5)	Dividend per ordinary share	10.00 cents (–)

(a) Reported on a one-quarter lagged basis and represents 1Q 2017 actuals only. (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 expenditure relating to the Gulf of Mexico oil spill from net cash provided by operating activities, as reported in the condensed group cash flow statement. For the first half, net cash provided by operating activities was $7.0 billion and post-tax Gulf of Mexico oil spill expenditure was $4.3 billion.

| Nearest GAAP equivalent
measures — i | Profit for the period: | $1.6bn |
| --- | --- | --- |
| ii | Capital expenditure*: | $8.6bn |
| iii | Gross debt ratio: | 39.0% |

The commentary above contains forward-looking statements and should be read in conjunction with the cautionary statement on page 40.

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INTENTIONALLY BLANK

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Upstream

	Second — quarter	quarter		half	half
$ million	2017	2016		2017	2016
Sales and other operating revenues (a)	10,493		8,176		21,820	15,607
Profit (loss) before interest and tax	796		(24	)	2,046	(1,260	)
Inventory holding (gains) losses*	(1	)	(85	)	5	(54	)
RC profit (loss) before interest and tax	795		(109	)	2,051	(1,314	)
Net (favourable) unfavourable impact of non-operating items and fair value accounting effects	(85	)	138		29	596
Underlying RC profit (loss) before interest and
tax* (b)	710		29		2,080	(718	)

(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 $10 billion and $22 billion respectively, compared with $8 billion and $16 billion for the corresponding periods in 2016. For the second quarter and half year, revenues were higher mainly due to higher realizations, increased production, and higher gas marketing and trading revenues.

The replacement cost profit before interest and tax for the second quarter and half year was $795 million and $2,051 million respectively, compared with a loss of $109 million and $1,314 million for the same periods in 2016. The second quarter and half year included a net non-operating charge of $21 million and $381 million respectively, compared with a net non-operating gain of $7 million and a charge of $348 million for the same periods in 2016. Fair value accounting effects in the second quarter and half year had a favourable impact of $106 million and $352 million respectively, compared with an unfavourable impact of $145 million and $248 million in the same periods of 2016.

After adjusting for non-operating items and fair value accounting effects, the underlying replacement cost profit before interest and tax for the second quarter and half year was $710 million and $2,080 million respectively, compared with a profit of $29 million and a loss of $718 million for the same periods in 2016. The result for the second quarter and half year mainly reflected higher liquids and gas realizations, and higher production including the impact of the Abu Dhabi concession renewal and major project start-ups, partly offset by higher exploration write-offs largely in Angola and higher depreciation, depletion and amortization.

Production

Production for the quarter was 2,431mboe/d, 9.9% higher than the second quarter of 2016. Underlying production* for the quarter increased by 7.0%, due to the ramp-up of major projects. For the first half, production was 2,410mboe/d, 6.4% higher than in the same period of 2016. First-half underlying production was 5% higher than the same period of 2016 due to major project start-ups.

Key events

On 8 May, BP along with joint venture partner Kosmos Energy announced the Yakaar gas discovery located at Cayar Offshore Profond block offshore Senegal (BP 60% (following completion on 3 July of the acquisition by BP of Timis Corp’s working interest), Kosmos 30%, and Petrosen 10%).

On 10 May, BP announced the start of gas production from the first two fields, Taurus and Libra, of the West Nile Delta development in Egypt (BP operator 82.75 % and DEA Deutsche Erdoel AG 17.25%).

On 22 May, BP announced first oil from the redeveloped Schiehallion Area, following completion of the Quad 204 project in the west of Shetland region, offshore UK (BP operator 36%, Shell 54%, and Siccar Point Energy 10%).

On 2 June, BP Trinidad and Tobago LLC (bpTT) announced the sanction for the development of its Angelin offshore gas project. On the same day, bpTT also announced that it has made two significant gas discoveries with the Savannah and Macadamia exploration wells.

On 15 June, BP and Reliance Industries Limited (RIL) announced the development of the R-Series project in Block KG D6 off the east coast of India (RIL operator 60%, BP 30%, and NIKO 10%).

This builds on the progress announced in our first-quarter results, which comprised the following: BP’s previously announced transaction with Kosmos Energy in Senegal was approved by the Senegal Minister of Energy and of Development of Renewable Energies; BP completed the purchase of a 10% interest from Eni (operator, 90%) in the Shorouk concession offshore Egypt; BP announced its third gas discovery in the North Damietta Offshore Concession (BP 100%) in the East Nile Delta, Egypt; BP announced that it had agreed to sell its Forties Pipeline System (FPS) business and other associated interests and facilities to INEOS; and bpTT announced the start-up of the Trinidad onshore compression project.

Outlook

Looking ahead, we expect third-quarter reported production to be broadly flat with the second quarter with the continued ramp-up of major projects offset by seasonal turnaround and maintenance activities.

The commentary above contains forward-looking statements and should be read in conjunction with the cautionary statement on page 40.

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Upstream (continued)

	Second — quarter	quarter		half		half
$ million	2017	2016		2017		2016
Underlying RC profit (loss) before interest and tax
US	179		(305	)	345		(972	)
Non-US	531		334		1,735		254
	710		29		2,080		(718	)
Non-operating items
US	(34	)	(57	)	(46	)	(220	)
Non-US (a)	13		64		(335	)	(128	)
	(21	)	7		(381	)	(348	)
Fair value accounting effects
US	92		(57	)	284		(90	)
Non-US	14		(88	)	68		(158	)
	106		(145	)	352		(248	)
RC profit (loss) before interest and tax
US	237		(419	)	583		(1,282	)
Non-US	558		310		1,468		(32	)
	795		(109	)	2,051		(1,314	)
Exploration expense
US	25		48		65		160
Non-US (b)	825		302		1,197		444
	850		350		1,262		604
Of which: Exploration expenditure written
off (b)	753		260		1,014		421
Production (net of
royalties) (c)
Liquids * (d) (mb/d)
US	418		401		433		402
Europe	122		117		118		122
Rest of World (d)	812		706		819		737
	1,352		1,224		1,371		1,261
Of which equity-accounted entities	202		176		208		173
Natural gas (mmcf/d)
US	1,576		1,666		1,585		1,634
Europe	274		238		269		263
Rest of World	4,410		3,829		4,173		3,924
	6,260		5,733		6,026		5,822
Of which equity-accounted entities	558		497		544		482
Total hydrocarbons * (d) (mboe/d)
US	689		688		706		684
Europe	169		158		165		168
Rest of World (d)	1,572		1,366		1,539		1,413
	2,431		2,212		2,410		2,265
Of which equity-accounted entities	298		262		301		256
Average
realizations* (e)
Total liquids(d)(f) ($/bbl)	46.27		39.68		48.09		34.44
Natural gas ($/mcf)	3.19		2.66		3.34		2.75
Total hydrocarbons(d) ($/boe)	33.59		28.66		35.37		26.16

(a) First half 2017 relates primarily to an impairment charge arising following the announcement on 3 April 2017 of the agreement to sell the Forties Pipeline System business to INEOS.

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

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

(d) A minor adjustment has been made to comparative periods in 2016. See page 35 for more information.

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

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

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

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Downstream

	Second — quarter	quarter		half		half
$ million	2017	2016		2017		2016
Sales and other operating revenues (a)	52,195		42,809		102,275		77,361
Profit (loss) before interest and tax	988		2,463		2,792		4,246
Inventory holding (gains) losses*	579		(1,058	)	481		(961	)
RC profit before interest and tax	1,567		1,405		3,273		3,285
Net (favourable) unfavourable impact of non-operating items and fair value accounting effects	(154	)	108		(118	)	41
Underlying RC profit before interest and
tax* (b)	1,413		1,513		3,155		3,326

(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 $52 billion and $102 billion respectively, compared with $43 billion and $77 billion for the corresponding periods in 2016. The increase in the second quarter and half year was mainly due to higher oil prices and sales volumes.

The replacement cost profit before interest and tax for the second quarter and first half was $1,567 million and $3,273 million respectively, compared with $1,405 million and $3,285 million for the same periods in 2016.

The second quarter and half year include a net non-operating gain of $138 million and $62 million respectively, compared with a net non-operating charge of $37 million and a net non-operating gain of $249 million for the same periods in 2016. Fair value accounting effects had a favourable impact of $16 million in the second quarter and $56 million for the half year, compared with an unfavourable impact of $71 million and $290 million for the same periods in 2016.

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 $1,413 million and $3,155 million respectively, compared with $1,513 million and $3,326 million for the same periods in 2016.

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

Fuels business

The fuels business reported an underlying replacement cost profit before interest and tax of $908 million for the second quarter and $2,108 million for the half year, compared with $1,011 million and $2,327 million for the same periods in 2016, driven by higher fuels marketing and refining results which were more than offset by a significantly lower supply and trading contribution for both the quarter and half year.

The fuels marketing result for the quarter and half year reflects continued growth supported by the rollout of our convenience partnership sites and higher premium volumes. For the half year, the fuels marketing result was around 20% higher than the same period last year.

The refining result for the quarter and half year benefited from stronger refining commercial optimization, partially offset by a higher level of turnaround activity. The half year also benefited from improved industry refining margins which were partially offset by narrower North American heavy crude oil differentials.

In the second quarter, we signed a memorandum of understanding with Reliance Industries Limited to jointly explore options to develop differentiated retail and aviation fuels, mobility and advanced low carbon energy businesses in India.

On 18 July we announced that we are evaluating the formation and initial public offering of a master limited partnership to enhance shareholder value and to support BP’s strategy to grow its US midstream business.

Lubricants business

The lubricants business reported an underlying replacement cost profit before interest and tax of $355 million for the second quarter and $748 million for the half year, compared with $412 million and $796 million for the same periods in 2016.

During the quarter, we announced an agreement to be the exclusive premium lubricants brand sold by Kroger, the largest supermarket chain in the US.

Petrochemicals business

The petrochemicals business reported an underlying replacement cost profit before interest and tax of $150 million for the second quarter and $299 million for the half year, compared with $90 million and $203 million for the same periods in 2016. The result for the second quarter and half year reflects an improved margin environment as well as lower costs reflecting the continued benefit from our simplification and efficiency programmes.

On 27 April, we announced our intention to divest our 50% shareholding in our Shanghai SECCO Petrochemical Company Limited joint venture in China for a consideration of $1.7 billion. This transaction is subject to regulatory approvals.

Outlook

In the third quarter, we expect a similar level of industry refining margins and that North American heavy crude oil differentials will remain under pressure.

The commentary above contains forward-looking statements and should be read in conjunction with the cautionary statement on page 40.

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Downstream (continued)

	Second — quarter	quarter		half		half
$ million	2017	2016		2017		2016
Underlying RC profit before interest and tax - by region
US	283		386		837		926
Non-US	1,130		1,127		2,318		2,400
	1,413		1,513		3,155		3,326
Non-operating items
US	28		17		16		130
Non-US	110		(54	)	46		119
	138		(37	)	62		249
Fair value accounting effects
US	10		(78	)	(52	)	(165	)
Non-US	6		7		108		(125	)
	16		(71	)	56		(290	)
RC profit before interest and tax
US	321		325		801		891
Non-US	1,246		1,080		2,472		2,394
	1,567		1,405		3,273		3,285
Underlying RC profit before interest and tax - by business (a)(b)
Fuels	908		1,011		2,108		2,327
Lubricants	355		412		748		796
Petrochemicals	150		90		299		203
	1,413		1,513		3,155		3,326
Non-operating items and fair value accounting effects (c)
Fuels	159		(93	)	163		(38	)
Lubricants	(2	)	(3	)	(5	)	(4	)
Petrochemicals	(3	)	(12	)	(40	)	1
	154		(108	)	118		(41	)
RC profit before interest and tax (a)(b)
Fuels	1,067		918		2,271		2,289
Lubricants	353		409		743		792
Petrochemicals	147		78		259		204
	1,567		1,405		3,273		3,285
BP average refining marker margin (RMM)* ($/bbl)	13.8		13.8		12.8		12.2
Refinery throughputs (mb/d)
US	708		668		702		683
Europe	782		805		791		806
Rest of World	198		231		189		235
	1,688		1,704		1,682		1,724
Refining availability* (%)	94.5		95.7		94.8		95.3
Marketing sales of refined products (mb/d)
US	1,177		1,115		1,146		1,093
Europe	1,153		1,170		1,111		1,157
Rest of World	497		515		505		502
	2,827		2,800		2,762		2,752
Trading/supply sales of refined products	2,996		2,875		2,978		2,843
Total sales volumes of refined products	5,823		5,675		5,740		5,595
Petrochemicals production (kte)
US	672		558		1,170		1,454
Europe	1,365		909		2,618		1,901
Rest of World	2,001		1,967		4,074		3,876
	4,038		3,434		7,862		7,231

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

(b) BP’s share of income from petrochemicals at our Gelsenkirchen and Mülheim sites in Germany is reported in the fuels business.

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

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Rosneft

	Second — quarter	Second — quarter	half	half
$ million	2017 (a)	2016	2017 (a)	2016
Profit before interest and tax (b)	271	291		344	353
Inventory holding (gains) losses*	8	(45	)	34	(41	)
RC profit before interest and tax	279	246		378	312
Net charge (credit) for non-operating items*	—	—		—	—
Underlying RC profit before interest and tax*	279	246		378	312

Financial results

Replacement cost profit before interest and tax and underlying replacement cost profit before interest and tax for the second quarter and half year was $279 million and $378 million respectively, compared with $246 million and $312 million for the same periods in 2016. There were no non-operating items in the second quarter and half year of either year.

Compared with the same periods in 2016, the result for the second quarter was primarily affected by higher oil prices and adverse duty lag effects. For the half year, the result was primarily affected by higher oil prices, adverse foreign exchange and adverse duty lag effects.

BP’s two nominees, Bob Dudley and Guillermo Quintero, were re-elected to Rosneft’s board by the annual general meeting (AGM) on 22 June. The AGM also adopted a resolution to pay dividends of 5.98 roubles per ordinary share. In July BP received a dividend in relation to the 2016 annual results of $190 million, after the deduction of withholding tax.

Key events

In April Rosneft completed the acquisition of a 100% interest in the Kondaneft project that is developing four licence areas in the Khanty-Mansiysk Autonomous District in West Siberia. The acquisition price was approximately $700 million.

On 29 June Rosneft completed the transaction for the sale of a 20% interest in its Verkhnechonskneftegaz subsidiary to the Beijing Gas Group, for around $1.1 billion.

quarter	quarter	half	half
2017 (a)	2016	2017 (a)	2016
Production (net of royalties) (BP share)
Liquids* (mb/d)	902	812	907	810
Natural gas (mmcf/d)	1,302	1,266	1,318	1,274
Total hydrocarbons* (mboe/d)	1,126	1,030	1,134	1,029

(a) The operational and financial information of the Rosneft segment for the second quarter and first half of the year is based on preliminary operational and financial results of Rosneft for the six months ended 30 June 2017. Actual results may differ from these amounts.

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

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Other businesses and corporate

	Second — quarter	quarter		half		half
$ million	2017	2016		2017		2016
Sales and other operating revenues (a)	326		422		611		818
Profit (loss) before interest and tax
Gulf of Mexico oil spill	(347	)	(5,106	)	(382	)	(5,900	)
Other	(374	)	(419	)	(770	)	(699	)
Profit (loss) before interest and tax	(721	)	(5,525	)	(1,152	)	(6,599	)
Inventory holding (gains) losses*	—		—		—		—
RC profit (loss) before interest and tax	(721	)	(5,525	)	(1,152	)	(6,599	)
Net charge (credit) for non-operating items*
Gulf of Mexico oil spill	347		5,106		382		5,900
Other	8		43		(36	)	145
Net charge (credit) for non-operating items	355		5,149		346		6,045
Underlying RC profit (loss) before interest and tax*	(366	)	(376	)	(806	)	(554	)
Underlying RC profit (loss) before interest and tax
US	(104	)	(109	)	(301	)	(219	)
Non-US	(262	)	(267	)	(505	)	(335	)
	(366	)	(376	)	(806	)	(554	)
Non-operating items
US	(350	)	(5,136	)	(388	)	(5,984	)
Non-US	(5	)	(13	)	42		(61	)
	(355	)	(5,149	)	(346	)	(6,045	)
RC profit (loss) before interest and tax
US	(454	)	(5,245	)	(689	)	(6,203	)
Non-US	(267	)	(280	)	(463	)	(396	)
	(721	)	(5,525	)	(1,152	)	(6,599	)

(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 $721 million and $1,152 million respectively, compared with $5,525 million and $6,599 million for the same periods in 2016.

The results included a net non-operating charge of $355 million for the second quarter and $346 million for the half year, compared with a net non-operating charge of $5,149 million and $6,045 million for the same periods in 2016.

After adjusting for non-operating items, the underlying replacement cost loss before interest and tax for the second quarter and half year was $366 million and $806 million respectively, compared with $376 million and $554 million for the same periods in 2016. The underlying charge for the half year was impacted by adverse foreign exchange effects, which had a favourable effect in the same period in 2016.

Alternative energy – biofuels, wind

The net ethanol-equivalent production (which includes ethanol and sugar) for the second quarter was 227 million litres, compared with 283 million litres for the same period in 2016.

Net wind generation capacity* (a) was 1,432MW at 30 June 2017 compared with 1,477MW at 30 June 2016. BP’s net share of wind generation for the second quarter and half year was 1,053GWh and 2,212GWh respectively, compared with 1,060GWh and 2,407GWh for the same periods in 2016.

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

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Financial statements

Group income statement

	Second — quarter	Second — quarter	half	half
$ million	2017	2016	2017	2016
Sales and other operating revenues (Note 4)	56,511	46,442		112,374	84,954
Earnings from joint ventures - after interest and tax	160	274		365	303
Earnings from associates - after interest and tax	371	380		522	522
Interest and other income	127	101		249	246
Gains on sale of businesses and fixed assets	197	79		242	417
Total revenues and other income	57,366	47,276		113,752	86,442
Purchases	42,713	32,752		83,850	59,355
Production and manufacturing expenses (a)	5,761	10,446		11,016	16,965
Production and similar taxes (Note 5)	189	258		495	272
Depreciation, depletion and amortization (Note 4)	3,793	3,637		7,635	7,367
Impairment and losses on sale of businesses and fixed assets	51	52		504	65
Exploration expense	850	350		1,262	604
Distribution and administration expenses	2,540	2,697		4,893	5,155
Profit (loss) before interest and taxation	1,469	(2,916	)	4,097	(3,341	)
Finance costs (a)	487	414		947	808
Net finance expense relating to pensions and other post-retirement benefits	54	46		107	92
Profit (loss) before taxation	928	(3,376	)	3,043	(4,241	)
Taxation (a)	772	(1,986	)	1,395	(2,293	)
Profit (loss) for the period	156	(1,390	)	1,648	(1,948	)
Attributable to
BP shareholders	144	(1,419	)	1,593	(2,002	)
Non-controlling interests	12	29		55	54
	156	(1,390	)	1,648	(1,948	)
Earnings per share (Note 6)
Profit (loss) for the period attributable to
BP shareholders
Per ordinary share (cents)
Basic	0.73	(7.60	)	8.12	(10.78	)
Diluted	0.72	(7.60	)	8.08	(10.78	)
Per ADS (dollars)
Basic	0.04	(0.46	)	0.49	(0.65	)
Diluted	0.04	(0.46	)	0.48	(0.65	)

(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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Group statement of comprehensive income

	Second — quarter	quarter		half		half
$ million	2017	2016		2017		2016
Profit (loss) for the period	156		(1,390	)	1,648		(1,948	)
Other comprehensive income
Items that may be reclassified subsequently to profit or loss
Currency translation differences	(103	)	(35	)	1,111		839
Exchange gains (losses) on translation of foreign operations reclassified to gain or loss on sale of
businesses and fixed assets	4		—		5		6
Available-for-sale investments	1		—		3		—
Cash flow hedges marked to market	81		(289	)	129		(351	)
Cash flow hedges reclassified to the income statement	31		16		73		39
Cash flow hedges reclassified to the balance sheet	36		6		75		19
Share of items relating to equity-accounted entities, net of tax	72		197		303		487
Income tax relating to items that may be reclassified	4		80		(121	)	(6	)
	126		(25	)	1,578		1,033
Items that will not be reclassified to profit or loss
Remeasurements of the net pension and other post-retirement benefit liability or asset	318		(1,763	)	1,045		(2,985	)
Income tax relating to items that will not be reclassified	(102	)	592		(348	)	994
	216		(1,171	)	697		(1,991	)
Other comprehensive income	342		(1,196	)	2,275		(958	)
Total comprehensive income	498		(2,586	)	3,923		(2,906	)
Attributable to
BP shareholders	472		(2,604	)	3,835		(2,955	)
Non-controlling interests	26		18		88		49
	498		(2,586	)	3,923		(2,906	)

Group statement of changes in equity

$ million — At 1 January 2017	BP shareholders’ equity — 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’ change in equity, net of tax	198		—		198
Transactions involving non-controlling interests	—		90		90
At 30 June 2017	96,803		1,658		98,461
$ million	BP shareholders’ equity	Non-controlling interests		Total equity
At 1 January 2016	97,216		1,171		98,387
Total comprehensive income	(2,955	)	49		(2,906	)
Dividends	(2,268	)	(52	)	(2,320	)
Share-based payments, net of tax	447		—		447
Share of equity-accounted entities’ change in equity, net of tax	65		—		65
Transactions involving non-controlling interests	221		214		435
At 30 June 2016	92,726		1,382		94,108

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Group balance sheet

	30 June	31 December
$ million	2017	2016
Non-current assets
Property, plant and equipment	130,715	129,757
Goodwill	11,395	11,194
Intangible assets	17,399	18,183
Investments in joint ventures	8,550	8,609
Investments in associates	15,408	14,092
Other investments	1,048	1,033
Fixed assets	184,515	182,868
Loans	540	532
Trade and other receivables	1,425	1,474
Derivative financial instruments	4,446	4,359
Prepayments	1,076	945
Deferred tax assets	5,114	4,741
Defined benefit pension plan surpluses	1,281	584
	198,397	195,503
Current assets
Loans	268	259
Inventories	16,449	17,655
Trade and other receivables	20,350	20,675
Derivative financial instruments	2,218	3,016
Prepayments	1,222	1,486
Current tax receivable	864	1,194
Other investments	77	44
Cash and cash equivalents	23,270	23,484
	64,718	67,813
Total assets	263,115	263,316
Current liabilities
Trade and other payables	36,642	37,915
Derivative financial instruments	2,295	2,991
Accruals	4,221	5,136
Finance debt	7,385	6,634
Current tax payable	1,716	1,666
Provisions	2,583	4,012
	54,842	58,354
Non-current liabilities
Other payables	12,556	13,946
Derivative financial instruments	4,210	5,513
Accruals	489	469
Finance debt	55,619	51,666
Deferred tax liabilities	7,435	7,238
Provisions	20,501	20,412
Defined benefit pension plan and other post-retirement benefit plan deficits	9,002	8,875
	109,812	108,119
Total liabilities	164,654	166,473
Net assets	98,461	96,843
Equity
BP shareholders’ equity	96,803	95,286
Non-controlling interests	1,658	1,557
Total equity	98,461	96,843

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Condensed group cash flow statement

$ million
Operating activities
Profit (loss) before taxation	928		(3,376	)	3,043		(4,241	)
Adjustments to reconcile profit (loss) before taxation taxation to net cash provided by operating
activities
Depreciation, depletion and amortization and exploration expenditure written off	4,546		3,897		8,649		7,788
Impairment and (gain) loss on sale of businesses and fixed assets	(146	)	(27	)	262		(352	)
Earnings from equity-accounted entities, less dividends received	(103	)	(485	)	(323	)	(509	)
Net charge for interest and other finance expense, less net interest paid	84		113		336		281
Share-based payments	156		204		318		463
Net operating charge for pensions and other post-retirement benefits, less contributions and benefit
payments for unfunded plans	54		(56	)	(19	)	(24	)
Net charge for provisions, less payments	183		4,565		6		5,300
Movements in inventories and other current and non-current assets and liabilities	3		(863	)	(3,597	)	(2,590	)
Income taxes paid	(815)		(89)		(1,671)		(361)
Net cash provided by operating activities	4,890		3,883		7,004		5,755
Investing activities
Expenditure on property, plant and equipment, intangible and other assets	(4,181	)	(4,283	)	(8,004	)	(8,664	)
Acquisitions, net of cash acquired	(123	)	—		(165	)	—
Investment in joint ventures	(10	)	(8	)	(30	)	(12	)
Investment in associates	(174	)	(196	)	(357	)	(289	)
Total cash capital expenditure	(4,488	)	(4,487	)	(8,556	)	(8,965	)
Proceeds from disposal of fixed assets	312		153		500		391
Proceeds from disposal of businesses, net of cash disposed	140		291		213		1,202
Proceeds from loan repayments	19		6		33		52
Net cash used in investing activities	(4,017	)	(4,037	)	(7,810	)	(7,320	)
Financing activities
Proceeds from long-term financing	1,720		2,710		5,433		5,448
Repayments of long-term financing	(1,463	)	(1,318	)	(2,380	)	(4,877	)
Net increase (decrease) in short-term debt	(299	)	300		16		188
Net increase (decrease) in non-controlling interests	51		368		81		438
Dividends paid - BP shareholders	(1,546	)	(1,169	)	(2,850	)	(2,268	)
- non-controlling interests	(62	)	(43	)	(77	)	(52	)
Net cash provided by (used in) financing activities	(1,599	)	848		223		(1,123	)
Currency translation differences relating to cash and cash equivalents	202		(226	)	369		(184	)
Increase (decrease) in cash and cash equivalents	(524	)	468		(214	)	(2,872	)
Cash and cash equivalents at beginning of period	23,794		23,049		23,484		26,389
Cash and cash equivalents at end of period	23,270		23,517		23,270		23,517

17

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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 2016 included in BP Annual Report and Form 20-F 2016 .

The directors have made an assessment of the group’s ability to continue as a going concern and 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 2017 , which do not differ significantly from those used in BP Annual Report and Form 20-F 2016 .

Note 2. Gulf of Mexico oil spill

(a) Overview

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

The group income statement includes a pre-tax charge for the second quarter of $347 million to reflect the latest estimate for claims, including business economic loss claims, and associated administration costs, and $121 million for finance costs relating to the unwinding of discounting effects. The equivalent amounts for the half year were $382 million and $247 million respectively. The cumulative pre-tax income statement charge since the incident, in April 2010, amounts to $63,214 million.

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

	Second — quarter	quarter		half		half
$ million	2017	2016		2017		2016
Income statement
Production and manufacturing expenses	347		5,106		382		5,900
Profit (loss) before interest and taxation	(347	)	(5,106	)	(382	)	(5,900	)
Finance costs	121		123		247		246
Profit (loss) before taxation	(468	)	(5,229	)	(629	)	(6,146	)
Taxation	154		2,533		202		2,784
Profit (loss) for the period	(314	)	(2,696	)	(427	)	(3,362	)

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Note 2. Gulf of Mexico oil spill (continued)

$ million	30 June — 2017	2016
Balance sheet
Current assets
Trade and other receivables	172		194
Current liabilities
Trade and other payables	(2,202	)	(3,056	)
Provisions	(955	)	(2,330	)
Net current assets (liabilities)	(2,985	)	(5,192	)
Non-current assets
Deferred tax assets	3,001		2,973
Non-current liabilities
Other payables	(12,151	)	(13,522	)
Provisions	—		(112	)
Deferred tax liabilities	5,294		5,119
Net non-current assets (liabilities)	(3,856	)	(5,542	)
Net assets (liabilities)	(6,841	)	(10,734	)

	Second — quarter	quarter		half		half
$ million	2017	2016		2017		2016
Cash flow statement - Operating activities
Profit (loss) before taxation	(468	)	(5,229	)	(629	)	(6,146	)
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	121		123		247		246
Net charge for provisions, less payments	298		4,466		293		5,223
Movements in inventories and other current and non-current assets and liabilities	(1,976	)	(971	)	(4,230	)	(2,059	)
Pre-tax cash flows	(2,025	)	(1,611	)	(4,319	)	(2,736	)

Cash outflows in 2016 and 2017 include payments made under the 2012 agreement with the US government to resolve all federal criminal claims arising from the incident and the 2016 consent decree and settlement agreement with the United States and the five Gulf coast states. Included in the current quarter cash outflow are payments of $379 million and $490 million relating to Clean Water Act penalties and natural resource damages settlements respectively. Net cash from operating activities relating to the Gulf of Mexico oil spill, on a post-tax basis, amounted to an outflow of $2,025 million and $4,319 million in the second quarter and first half of 2017 respectively. For the same periods in 2016, the amount was an outflow of $1,398 million and $2,523 million respectively.

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Note 2. Gulf of Mexico oil spill (continued)

(b) Provisions and other payables

Provisions

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

$ million — At 1 April 2017	1,350
Net increase in provision	337
Reclassified to other payables	(94	)
Utilization	(638	)
At 30 June 2017	955

Movements in the remaining provision during the first half are shown in the table below.

$ million — At 1 January 2017	2,442
Net increase in provision	362
Reclassified to other payables	(690	)
Utilization	(1,159	)
At 30 June 2017	955

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

PSC settlement

The provision for the cost associated with the 2012 Plaintiffs’ Steering Committee (PSC) settlement has been increased in the second quarter to reflect the latest estimate for claims, including business economic loss claims and associated administration costs. However, the amounts ultimately payable may differ from the amount provided and the timing of payments is uncertain.

A significant number of claims determined by the settlement programme have been and may be appealed by BP and/or the claimants. Depending upon the resolution of these claims, the amount payable may differ from what is currently provided for. There is additional uncertainty in relation to the impact of the recent Fifth Circuit decision (on the policy addressing the matching of revenue with expenses in relation to business economic loss claims), including on those business economic loss claims that have not yet been determined and those that are under appeal within the settlement programme (see Legal proceedings on page 40 for further details on the Fifth Circuit decision).

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

Other payables

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

Further information on provisions, other payables, and contingent liabilities is provided in BP Annual Report and Form 20-F 2016 - Financial statements - Note 2.

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

	Second — quarter	quarter		half		half
$ million	2017	2016		2017		2016
Upstream	795		(109	)	2,051		(1,314	)
Downstream	1,567		1,405		3,273		3,285
Rosneft	279		246		378		312
Other businesses and corporate (a)	(721	)	(5,525	)	(1,152	)	(6,599	)
	1,920		(3,983	)	4,550		(4,316	)
Consolidation adjustment - UPII*	135		(121	)	67		(81	)
RC profit (loss) before interest and tax*	2,055		(4,104	)	4,617		(4,397	)
Inventory holding gains (losses)*
Upstream	1		85		(5	)	54
Downstream	(579	)	1,058		(481	)	961
Rosneft (net of tax)	(8	)	45		(34	)	41
Profit (loss) before interest and tax	1,469		(2,916	)	4,097		(3,341	)
Finance costs	487		414		947		808
Net finance expense relating to pensions and other post-retirement benefits	54		46		107		92
Profit (loss) before taxation	928		(3,376	)	3,043		(4,241	)
RC profit (loss) before interest and tax
US	302		(5,394	)	815		(6,650	)
Non-US	1,753		1,290		3,802		2,253
	2,055		(4,104	)	4,617		(4,397	)

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

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Note 4. Segmental analysis

Sales and other operating revenues	Second	Second	First	First
	quarter	quarter	half	half
$ million	2017	2016	2017	2016
By segment
Upstream	10,493	8,176	21,820	15,607
Downstream	52,195	42,809	102,275	77,361
Other businesses and corporate	326	422	611	818
	63,014	51,407	124,706	93,786
Less: sales and other operating revenues between segments
Upstream	6,161	4,301	11,938	7,934
Downstream	208	475	122	593
Other businesses and corporate	134	189	272	305
	6,503	4,965	12,332	8,832
Third party sales and other operating revenues
Upstream	4,332	3,875	9,882	7,673
Downstream	51,987	42,334	102,153	76,768
Other businesses and corporate	192	233	339	513
Total sales and other operating revenues	56,511	46,442	112,374	84,954
By geographical area
US	21,577	17,701	42,729	31,277
Non-US	41,103	32,482	81,123	59,628
	62,680	50,183	123,852	90,905
Less: sales and other operating revenues between areas	6,169	3,741	11,478	5,951
	56,511	46,442	112,374	84,954
Depreciation, depletion and amortization	Second	Second	First	First
	quarter	quarter	half	half
$ million	2017	2016	2017	2016
Upstream
US	1,133	1,064	2,370	2,153
Non-US	2,090	1,993	4,144	4,097
	3,223	3,057	6,514	6,250
Downstream
US	219	210	435	420
Non-US	274	279	553	546
	493	489	988	966
Other businesses and corporate
US	16	20	32	35
Non-US	61	71	101	116
	77	91	133	151
Total group	3,793	3,637	7,635	7,367

Note 5. Production and similar taxes

	Second	Second	First	First
	quarter	quarter	half	half
$ million	2017	2016	2017	2016
US	41	67	77	85
Non-US	148	191	418	187
	189	258	495	272

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Note 6. Earnings per share and shares in issue

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

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

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

	Second — quarter	Second — quarter	half	half
$ million	2017	2016	2017	2016
Results for the period
Profit (loss) for the period attributable to BP shareholders	144	(1,419	)	1,593	(2,002	)
Less: preference dividend	1	1		1	1
Profit (loss) attributable to BP ordinary shareholders	143	(1,420	)	1,592	(2,003	)
Number of shares (thousand) (a)(b)
Basic weighted average number of shares outstanding	19,686,613	18,685,199		19,602,785	18,577,135
ADS equivalent	3,281,102	3,114,200		3,267,130	3,096,189
Weighted average number of shares outstanding used to calculate diluted earnings per share	19,783,548	18,685,199		19,713,151	18,577,135
ADS equivalent	3,297,258	3,114,200		3,285,525	3,096,189
Shares in issue at period-end	19,738,566	18,777,156		19,738,566	18,777,156
ADS equivalent	3,289,761	3,129,526		3,289,761	3,129,526

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

(b) If the inclusion of potentially issuable shares would decrease loss per share, the potentially issuable shares are excluded from the weighted average number of shares outstanding used to calculate diluted earnings per share.

Note 7. Dividends

Dividends payable

BP today announced an interim dividend of 10.00 cents per ordinary share which is expected to be paid on 22 September 2017 to shareholders and American Depositary Share (ADS) holders on the register on 11 August 2017. The corresponding amount in sterling is due to be announced on 12 September 2017, calculated based on the average of the market exchange rates for the four dealing days commencing on 6 September 2017. Holders of ADSs are expected to receive $0.600 per ADS (less applicable fees). A scrip dividend alternative is available, allowing shareholders to elect to receive their dividend in the form of new ordinary shares and ADS holders in the form of new ADSs. Details of the second quarter dividend and timetable are available at bp.com/dividends and details of the scrip dividend programme are available at bp.com/scrip .

quarter	quarter	half	half
2017	2016	2017	2016
Dividends paid per ordinary share
cents	10.000	10.000	20.000	20.000
pence	7.756	6.917	15.915	13.929
Dividends paid per ADS (cents)	60.00	60.00	120.00	120.00
Scrip dividends
Number of shares issued (millions)	70.1	134.4	185.2	288.8
Value of shares issued ($ million)	420	695	1,062	1,434

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Note 8. Net Debt*

Net debt ratio *	Second — quarter	quarter		half		half
$ million	2017	2016		2017		2016
Gross debt	63,004		55,727		63,004		55,727
Fair value (asset) liability of hedges related to finance
debt (a)	60		(1,279	)	60		(1,279	)
	63,064		54,448		63,064		54,448
Less: cash and cash equivalents	23,270		23,517		23,270		23,517
Net debt	39,794		30,931		39,794		30,931
Equity	98,461		94,108		98,461		94,108
Net debt ratio	28.8	%	24.7	%	28.8	%	24.7	%
Analysis of changes in net debt	Second	Second		First		First
	quarter	quarter		half		half
$ million	2017	2016		2017		2016
Opening balance
Finance debt	61,832		54,012		58,300		53,168
Fair value (asset) liability of hedges related to finance
debt (a)	597		(967	)	697		379
Less: cash and cash equivalents	23,794		23,049		23,484		26,389
Opening net debt	38,635		29,996		35,513		27,158
Closing balance
Finance debt	63,004		55,727		63,004		55,727
Fair value (asset) liability of hedges related to finance
debt (a)	60		(1,279	)	60		(1,279	)
Less: cash and cash equivalents	23,270		23,517		23,270		23,517
Closing net debt	39,794		30,931		39,794		30,931
Decrease (increase) in net debt	(1,159	)	(935	)	(4,281	)	(3,773	)
Movement in cash and cash equivalents (excluding exchange adjustments)	(726	)	694		(583	)	(2,688	)
Net cash outflow (inflow) from financing (excluding share capital and dividends)	42		(1,692	)	(3,069	)	(759	)
Other movements	(13	)	36		(79	)	395
Movement in net debt before exchange effects	(697	)	(962	)	(3,731	)	(3,052	)
Exchange adjustments	(462	)	27		(550	)	(721	)
Decrease (increase) in net debt	(1,159	)	(935	)	(4,281	)	(3,773	)

(a) Derivative financial instruments entered into for the purpose of managing interest rate and foreign currency exchange risk associated with net debt with a fair value liability position of $1,167 million (second quarter 2016 liability of $1,440 million) are not included in the calculation of net debt shown above as hedge accounting is not applied for these instruments.

Note 9. Inventory valuation

A provision of $635 million was held at 30 June 2017 ($689 million at 30 June 2016) to write inventories down to their net realizable value. The net movement charged to the income statement during the second quarter 2017 was $132 million (second quarter 2016 was a charge of $12 million).

Note 10. Statutory accounts

The financial information shown in this publication, which was approved by the Board of Directors on 31 July 2017, is unaudited and does not constitute statutory financial statements. Audited financial information will be published in BP Annual Report and Form 20-F 2017 .

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Note 11. 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.

	Issuer
	BP				Eliminations
Income statement	Exploration			Other	and		BP
$ million	(Alaska) Inc.	BP p.l.c.		subsidiaries	reclassifications		group
First half 2017
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		—		84,929	(1,595	)	83,850
Production and manufacturing expenses	580		—		10,436	—		11,016
Production and similar taxes	46		—		449	—		495
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 period	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

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Note 11. Condensed consolidating information on certain US subsidiaries (continued)

	Issuer
	BP					Eliminations
Statement of comprehensive income	Exploration			Other		and		BP
$ million	(Alaska) Inc.	BP p.l.c.		subsidiaries		reclassifications		group
First half 2017
Profit (loss) for the period	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
	Issuer	Guarantor
	BP					Eliminations
Income statement	Exploration			Other		and		BP
$ million	(Alaska) Inc.	BP p.l.c.		subsidiaries		reclassifications		group
First half 2016
Sales and other operating revenues	1,215		—		84,950		(1,211	)	84,954
Earnings from joint ventures - after interest and tax	—		—		303		—		303
Earnings from associates - after interest and tax	—		—		522		—		522
Equity-accounted income of subsidiaries - after interest and tax	—		(1,725	)	—		1,725		—
Interest and other income	40		142		348		(284	)	246
Gains on sale of businesses and fixed assets	—		—		417		—		417
Total revenues and other income	1,255		(1,583	)	86,540		230		86,442
Purchases	324		—		60,242		(1,211	)	59,355
Production and manufacturing expenses	659		—		16,306		—		16,965
Production and similar taxes	67		—		205		—		272
Depreciation, depletion and amortization	310		—		7,057		—		7,367
Impairment and losses on sale of businesses and fixed assets	—		—		65		—		65
Exploration expense	—		—		604		—		604
Distribution and administration expenses	(6	)	459		4,725		(23	)	5,155
Profit (loss) before interest and taxation	(99	)	(2,042	)	(2,664	)	1,464		(3,341	)
Finance costs	42		69		958		(261	)	808
Net finance (income) expense relating to pensions and other post-retirement benefits	—		(43	)	135		—		92
Profit (loss) before taxation	(141	)	(2,068	)	(3,757	)	1,725		(4,241	)
Taxation	(70	)	(66	)	(2,157	)	—		(2,293	)
Profit (loss) for the period	(71	)	(2,002	)	(1,600	)	1,725		(1,948	)
Attributable to
BP shareholders	(71	)	(2,002	)	(1,654	)	1,725		(2,002	)
Non-controlling interests	—		—		54		—		54
	(71	)	(2,002	)	(1,600	)	1,725		(1,948	)

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Note 11. Condensed consolidating information on certain US subsidiaries (continued)

	Issuer
	BP					Eliminations
Statement of comprehensive income	Exploration			Other		and		BP
$ million	(Alaska) Inc.	BP p.l.c.		subsidiaries		reclassifications		group
First half 2016
Profit (loss) for the period	(71	)	(2,002	)	(1,600	)	1,725		(1,948	)
Other comprehensive income	—		(1,102	)	144		—		(958	)
Equity-accounted other comprehensive income of subsidiaries	—		149		—		(149	)	—
Total comprehensive income	(71	)	(2,955	)	(1,456	)	1,576		(2,906	)
Attributable to
BP shareholders	(71	)	(2,955	)	(1,505	)	1,576		(2,955	)
Non-controlling interests	—		—		49		—		49
	(71	)	(2,955	)	(1,456	)	1,576		(2,906	)
	Issuer	Guarantor
	BP					Eliminations
Balance sheet	Exploration			Other		and		BP
$ million	(Alaska) Inc.	BP p.l.c.		subsidiaries		reclassifications		group
At 30 June 2017
Non-current assets
Property, plant and equipment	7,153		—		123,562		—		130,715
Goodwill	—		—		11,395		—		11,395
Intangible assets	583		—		16,816		—		17,399
Investments in joint ventures	—		—		8,550		—		8,550
Investments in associates	—		2		15,406		—		15,408
Other investments	—		—		1,048		—		1,048
Subsidiaries - equity-accounted basis	—		160,769		—		(160,769	)	—
Fixed assets	7,736		160,771		176,777		(160,769	)	184,515
Loans	—		—		34,655		(34,115	)	540
Trade and other receivables	—		—		1,425		—		1,425
Derivative financial instruments	—		—		4,446		—		4,446
Prepayments	—		—		1,076		—		1,076
Deferred tax assets	—		—		5,114		—		5,114
Defined benefit pension plan surpluses	—		1,174		107		—		1,281
	7,736		161,945		223,600		(194,884	)	198,397
Current assets
Loans	—		—		268		—		268
Inventories	284		—		16,165		—		16,449
Trade and other receivables	2,604		3,210		27,410		(12,874	)	20,350
Derivative financial instruments	—		—		2,218		—		2,218
Prepayments	65		—		1,157		—		1,222
Current tax receivable	—		—		864		—		864
Other investments	—		—		77		—		77
Cash and cash equivalents	—		—		23,270		—		23,270
	2,953		3,210		71,429		(12,874	)	64,718
Total assets	10,689		165,155		295,029		(207,758	)	263,115
Current liabilities
Trade and other payables	576		7,067		41,873		(12,874	)	36,642
Derivative financial instruments	—		—		2,295		—		2,295
Accruals	83		(40	)	4,178		—		4,221
Finance debt	—		—		7,385		—		7,385
Current tax payable	5		—		1,711		—		1,716
Provisions	1		—		2,582		—		2,583
	665		7,027		60,024		(12,874	)	54,842
Non-current liabilities
Other payables	1		34,115		12,555		(34,115	)	12,556
Derivative financial instruments	—		—		4,210		—		4,210
Accruals	—		29		460		—		489
Finance debt	—		—		55,619		—		55,619
Deferred tax liabilities	1,272		405		5,758		—		7,435
Provisions	1,403		—		19,098		—		20,501
Defined benefit pension plan and other post-retirement benefit plan deficits	—		235		8,767		—		9,002
	2,676		34,784		106,467		(34,115	)	109,812
Total liabilities	3,341		41,811		166,491		(46,989	)	164,654
Net assets	7,348		123,344		128,538		(160,769	)	98,461
Equity
BP shareholders’ equity	7,348		123,344		126,880		(160,769	)	96,803
Non-controlling interests	—		—		1,658		—		1,658
	7,348		123,344		128,538		(160,769	)	98,461

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Note 11. Condensed consolidating information on certain US subsidiaries (continued)

	Issuer	Guarantor
	BP			Eliminations
Balance sheet	Exploration		Other	and	BP
$ million	(Alaska) Inc.	BP p.l.c.	subsidiaries	reclassifications	group
At 31 December 2016
Non-current assets
Property, plant and equipment	7,405	—	122,352	—		129,757
Goodwill	—	—	11,194	—		11,194
Intangible assets	578	—	17,605	—		18,183
Investments in joint ventures	—	—	8,609	—		8,609
Investments in associates	—	2	14,090	—		14,092
Other investments	—	—	1,033	—		1,033
Subsidiaries - equity-accounted basis	—	156,864	—	(156,864	)	—
Fixed assets	7,983	156,866	174,883	(156,864	)	182,868
Loans	9	—	34,941	(34,418	)	532
Trade and other receivables	—	2,951	1,474	(2,951	)	1,474
Derivative financial instruments	—	—	4,359	—		4,359
Prepayments	—	—	945	—		945
Deferred tax assets	—	—	4,741	—		4,741
Defined benefit pension plan surpluses	—	528	56	—		584
	7,992	160,345	221,399	(194,233	)	195,503
Current assets
Loans	—	—	259	—		259
Inventories	249	—	17,406	—		17,655
Trade and other receivables	2,583	487	24,660	(7,055	)	20,675
Derivative financial instruments	—	—	3,016	—		3,016
Prepayments	7	—	1,479	—		1,486
Current tax receivable	—	—	1,194	—		1,194
Other investments	—	—	44	—		44
Cash and cash equivalents	—	50	23,434	—		23,484
	2,839	537	71,492	(7,055	)	67,813
Total assets	10,831	160,882	292,891	(201,288	)	263,316
Current liabilities
Trade and other payables	722	4,096	40,152	(7,055	)	37,915
Derivative financial instruments	—	—	2,991	—		2,991
Accruals	116	129	4,891	—		5,136
Finance debt	—	—	6,634	—		6,634
Current tax payable	11	—	1,655	—		1,666
Provisions	2	—	4,010	—		4,012
	851	4,225	60,333	(7,055	)	58,354
Non-current liabilities
Other payables	20	34,389	16,906	(37,369	)	13,946
Derivative financial instruments	—	—	5,513	—		5,513
Accruals	—	43	426	—		469
Finance debt	—	—	51,666	—		51,666
Deferred tax liabilities	1,279	179	5,780	—		7,238
Provisions	1,390	—	19,022	—		20,412
Defined benefit pension plan and other post-retirement benefit plan deficits	—	219	8,656	—		8,875
	2,689	34,830	107,969	(37,369	)	108,119
Total liabilities	3,540	39,055	168,302	(44,424	)	166,473
Net assets	7,291	121,827	124,589	(156,864	)	96,843
Equity
BP shareholders’ equity	7,291	121,827	123,032	(156,864	)	95,286
Non-controlling interests	—	—	1,557	—		1,557
	7,291	121,827	124,589	(156,864	)	96,843

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Note 11. Condensed consolidating information on certain US subsidiaries (continued)

	Issuer
	BP
Cash flow statement	Exploration			Other		BP
$ million	(Alaska) Inc.	BP p.l.c.		subsidiaries		group
First half 2017
Net cash provided by operating activities	177		2,799		4,028		7,004
Net cash 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 period	—		50		23,434		23,484
Cash and cash equivalents at end of period	—		—		23,270		23,270
	Issuer	Guarantor
	BP
Cash flow statement	Exploration			Other		BP
$ million	(Alaska) Inc.	BP p.l.c.		subsidiaries		group
First half 2016
Net cash provided by operating activities	453		2,268		3,034		5,755
Net cash used in investing activities	(453	)	—		(6,867	)	(7,320	)
Net cash provided by (used in) financing activities	—		(2,268	)	1,145		(1,123	)
Currency translation differences relating to cash and cash equivalents	—		—		(184	)	(184	)
Increase (decrease) in cash and cash equivalents	—		—		(2,872	)	(2,872	)
Cash and cash equivalents at beginning of period	—		—		26,389		26,389
Cash and cash equivalents at end of period	—		—		23,517		23,517

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Additional information

Capital expenditure*

	Second	Second	First	First
	quarter	quarter	half	half
$ million	2017	2016	2017	2016
Capital expenditure on a cash basis
Organic capital expenditure*	4,348	4,205	7,886	8,683
Inorganic capital expenditure* (a)	140	282	670	282
	4,488	4,487	8,556	8,965
	Second	Second	First	First
	quarter	quarter	half	half
$ million	2017	2016	2017	2016
Organic capital expenditure by segment
Upstream
US	805	948	1,446	2,195
Non-US	3,005	2,769	5,344	5,578
	3,810	3,717	6,790	7,773
Downstream
US	149	193	301	312
Non-US	316	257	636	526
	465	450	937	838
Other businesses and corporate
US	3	4	24	4
Non-US	70	34	135	68
	73	38	159	72
	4,348	4,205	7,886	8,683
Organic capital expenditure by geographical area
US	957	1,145	1,771	2,511
Non-US	3,391	3,060	6,115	6,172
	4,348	4,205	7,886	8,683

(a) First half 2017 includes amounts paid to purchase an interest in the Zohr gas field in Egypt and in exploration blocks in Senegal.

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Non-operating items*

$ million
Upstream
Impairment and gain (loss) on sale of businesses and fixed assets (a)	(18	)	—		(400	)	4
Environmental and other provisions	—		—		—		—
Restructuring, integration and rationalization costs	(19	)	(3	)	(17	)	(266	)
Fair value gain (loss) on embedded derivatives	5		28		30		41
Other	11		(18	)	6		(127	)
	(21	)	7		(381	)	(348	)
Downstream
Impairment and gain (loss) on sale of businesses and fixed assets	156		23		145		344
Environmental and other provisions	—		(3	)	—		(3	)
Restructuring, integration and rationalization costs	(18	)	(54	)	(83	)	(89	)
Fair value gain (loss) on embedded derivatives	—		—		—		—
Other	—		(3	)	—		(3	)
	138		(37	)	62		249
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	8		4		(7	)	4
Environmental and other provisions	(3	)	(35	)	(3	)	(35	)
Restructuring, integration and rationalization costs	(23	)	(11	)	(31	)	(59	)
Fair value gain (loss) on embedded derivatives	—		—		—		—
Gulf of Mexico oil spill (b)	(347	)	(5,106	)	(382	)	(5,900	)
Other	10		(1	)	77		(55	)
	(355	)	(5,149	)	(346	)	(6,045	)
Total before interest and taxation	(238	)	(5,179	)	(665	)	(6,144	)
Finance costs (b)	(121	)	(123	)	(247	)	(246	)
Total before taxation	(359	)	(5,302	)	(912	)	(6,390	)
Taxation credit (charge)	144		2,483		392		2,793
Total after taxation for period	(215	)	(2,819	)	(520	)	(3,597	)

(a) First half 2017 relates primarily to an impairment charge arising following the announcement on 3 April 2017 of the agreement to sell the Forties Pipeline System business to INEOS.

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

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Non-GAAP information on fair value accounting effects

	Second — quarter	quarter		half		half
$ million	2017	2016		2017		2016
Favourable (unfavourable) impact relative to management’s measure of
performance
Upstream	106		(145	)	352		(248	)
Downstream	16		(71	)	56		(290	)
	122		(216	)	408		(538	)
Taxation credit (charge)	(38	)	68		(117	)	151
	84		(148	)	291		(387	)

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

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

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

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

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

	Second — quarter	Second — quarter	half	half
$ million	2017	2016	2017	2016
Upstream
Replacement cost profit (loss) before interest and tax adjusted for fair value accounting effects	689	36		1,699	(1,066	)
Impact of fair value accounting effects	106	(145	)	352	(248	)
Replacement cost profit before interest and tax	795	(109	)	2,051	(1,314	)
Downstream
Replacement cost profit before interest and tax adjusted for fair value accounting effects	1,551	1,476		3,217	3,575
Impact of fair value accounting effects	16	(71	)	56	(290	)
Replacement cost profit before interest and tax	1,567	1,405		3,273	3,285
Total group
Profit (loss) before interest and tax adjusted for fair value accounting effects	1,347	(2,700	)	3,689	(2,803	)
Impact of fair value accounting effects	122	(216	)	408	(538	)
Profit (loss) before interest and tax	1,469	(2,916	)	4,097	(3,341	)

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Readily marketable inventory* (RMI)

$ million — RMI at fair value	4,387	5,952
Paid-up RMI*	2,470	2,705

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

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

See the Glossary on page 37 for a more detailed definition of RMI. RMI, RMI at fair value and paid-up RMI are non-GAAP measures. A reconciliation of total inventory as reported on the group balance sheet to paid-up RMI is provided below.

$ million
Reconciliation of total inventory to paid-up RMI
Inventories as reported on the group balance sheet	16,449		17,655
Less: (a) inventories which are not oil and oil products and (b) oil and oil product inventories which
are not risk-managed by IST	(12,310	)	(12,131	)
RMI on an IFRS basis	4,139		5,524
Plus: difference between RMI at fair value and RMI on an IFRS basis	248		428
RMI at fair value	4,387		5,952
Less: unpaid RMI* at fair value	(1,917	)	(3,247	)
Paid-up RMI	2,470		2,705

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

	Second — quarter	quarter		half		half
Per ordinary share (cents)	2017	2016		2017		2016
Profit (loss) for the period	0.73		(7.60	)	8.12		(10.78	)
Inventory holding (gains) losses*, before tax	2.97		(6.36	)	2.65		(5.68	)
Taxation charge (credit) on inventory holding gains and losses	(0.90	)	1.93		(0.75	)	1.75
RC profit (loss)*	2.80		(12.03	)	10.02		(14.71	)
Net (favourable) unfavourable impact of non-operating items*and fair
value accounting effects*, before tax	1.21		29.53		2.57		37.29
Taxation charge (credit) on non-operating items and fair value
accounting effects	(0.54	)	(13.65	)	(1.40	)	(15.85	)
Underlying RC profit*	3.47		3.85		11.19		6.73

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

Taxation (charge) credit

	Second — quarter	quarter		half		half
$ million	2017	2016		2017		2016
Taxation on profit or loss	(772	)	1,986		(1,395	)	2,293
Taxation on inventory holding gains and losses	177		(360	)	148		(326	)
Taxation on a RC profit or loss basis	(949	)	2,346		(1,543	)	2,619
Taxation on non-operating items and fair value accounting
effects	106		2,551		275		2,944
Adjusted taxation	(1,055	)	(205	)	(1,818	)	(325	)

Effective tax rate

	Second — quarter	quarter		half		half
%	2017	2016		2017		2016
ETR on profit or loss	83		59		46		54
Adjusted for inventory holding gains or losses	(20	)	(8	)	(3	)	(5	)
ETR on RC profit or loss*	63		51		43		49
Adjusted for non-operating items and fair value accounting
effects	(3	)	(30	)	2		(29	)
Adjusted ETR*	60		21		45		20

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Realizations* and marker prices

quarter	quarter	half	half
2017	2016	2017	2016
Average
realizations (a)
Liquids* ($/bbl)
US	44.65	34.89	45.51	31.82
Europe	47.79	43.62	50.50	37.46
Rest of World (b)	47.11	42.36	49.46	35.60
BP Average (b)	46.27	39.68	48.09	34.44
Natural gas ($/mcf)
US	2.32	1.53	2.41	1.55
Europe	4.48	4.64	4.93	4.46
Rest of World	3.47	3.10	3.64	3.21
BP Average	3.19	2.66	3.34	2.75
Total hydrocarbons* ($/boe)
US	32.46	24.00	33.39	22.38
Europe	41.10	39.25	43.84	34.28
Rest of World (b)	33.48	30.03	35.64	27.20
BP Average (b)	33.59	28.66	35.37	26.16
Average oil marker prices ($/bbl)
Brent	49.64	45.59	51.71	39.81
West Texas Intermediate	48.11	45.53	49.89	39.64
Western Canadian Select	38.55	33.78	38.66	28.09
Alaska North Slope	50.61	45.74	52.20	40.00
Mars	46.92	42.08	48.24	36.25
Urals (NWE – cif)	48.48	43.37	50.22	37.56
Average natural gas marker prices
Henry Hub gas price (c) ($/mmBtu)	3.19	1.95	3.25	2.02
UK Gas – National Balancing Point (p/therm)	37.83	31.37	43.14	30.90

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

(b) Production volume recognition methodology for our Technical Service Contract arrangement in Iraq has been simplified to exclude the impact of oil price movements on lifting imbalances. A minor adjustment has been made to second quarter and first half 2016. There is no impact on the financial results.

(c) Henry Hub First of Month Index.

Exchange rates

quarter	quarter	half	half
2017	2016	2017	2016
$/£ average rate for the period	1.28	1.43	1.26	1.43
$/£ period-end rate	1.30	1.34	1.30	1.34
$/ € average rate for the period	1.10	1.13	1.08	1.12
$/ € period-end rate	1.14	1.11	1.14	1.11
Rouble/$ average rate for the period	57.24	65.86	57.98	70.35
Rouble/$ period-end rate	59.05	63.64	59.05	63.64

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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 2016 (pages 49-50) 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 subject to fluctuating prices of oil, gas, 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 – we are exposed to a range of political developments and consequent changes to the operating and regulatory environment.

• 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 – we may have limited control over the standards, operations and compliance of our partners, contractors and sub-contractors.

• Digital infrastructure and cybersecurity – breach of our digital security or failure of our digital infrastructure could damage our operations and our reputation.

• Climate change and carbon pricing – public policies could increase costs and reduce future revenue and strategic growth opportunities.

• Competition – inability to remain efficient, innovate and retain an appropriately skilled workforce could negatively impact delivery of our strategy in a highly competitive market.

• Crisis management and business continuity – potential disruption to our business and operations could occur if we do not address an incident effectively.

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

Safety and operational risks

• Process safety, personal safety, and environmental risks – we are exposed to a wide range of health, safety, security and environmental risks that could result in regulatory action, legal liability, 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 potentially impact our financial performance.

Compliance and control risks

• US government settlements – failure to comply with the terms of our settlements with legal and regulatory bodies in the US announced in November 2012 in respect of certain charges 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 exploration 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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Glossary

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

Adjusted effective tax rate (ETR) is a non-GAAP measure. The adjusted ETR is calculated by dividing taxation on an underlying RC basis excluding the impact of the reduction in the rate of the UK North Sea supplementary charge in the third quarter 2016 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 adjusted ETR because this measure may help investors to understand and evaluate, in the same manner as management, the underlying trends in BP’s operational performance on a comparable basis, period on period. The nearest equivalent measure on an IFRS basis is the ETR on profit or loss for the period, a reconciliation to GAAP information is provided on page 34.

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 34.

Fair value accounting effects are non-GAAP adjustments to our IFRS profit (loss) relating to certain physical inventories, pipelines and storage capacity. Management uses a fair-value basis to value these items which, under IFRS, are accounted for on an accruals basis with the exception of trading inventories, which are valued using spot prices. The adjustments have the effect of aligning the valuation basis of the physical positions with that of any associated derivative instruments, which are required to be fair valued under IFRS, in order to provide a more representative view of the ultimate economic value. Further information is provided on page 32.

Gearing – See Net debt and net debt ratio definition.

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

Inorganic capital expenditure is a subset of capital expenditure and is a non-GAAP measure. Inorganic capital expenditure comprises consideration in business combinations and certain other significant investments made by the group. It is reported on a cash basis. BP believes that this measure provides useful information as it allows investors to understand how BP’s management invests funds in projects which expand the group’s activities through acquisition. Further information and a reconciliation to GAAP information is provided on page 30.

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

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

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

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Glossary (continued)

Net debt and net debt ratio are non-GAAP measures. Net debt is calculated as gross finance debt, as shown in the balance sheet, plus the fair value of associated derivative financial instruments that are used to hedge foreign currency exchange and interest rate risks relating to finance debt, for which hedge accounting is applied, less cash and cash equivalents. The net debt ratio is defined as the ratio of net debt to the total of net debt plus shareholders’ equity. All components of equity are included in the denominator of the calculation. BP believes these measures provide useful information to investors. Net debt enables investors to see the economic effect of gross debt, related hedges and cash and cash equivalents in total. The net debt ratio enables investors to see how significant net debt is relative to equity from shareholders. The derivatives are reported on the balance sheet within the headings ‘Derivative financial instruments’.

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 the 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. The gross data is the equivalent capacity on a gross-JV basis, which includes 100% of the capacity of equity-accounted entities where BP has partial ownership.

Non-operating items are charges and credits included in the financial statements that BP discloses separately because it considers such disclosures to be meaningful and relevant to investors. They are items that management considers not to be part of underlying business operations and are disclosed in order to enable investors better to understand and evaluate the group’s reported financial performance. Non-operating items within equity-accounted earnings are reported net of incremental income tax reported by the equity-accounted entity. An analysis of non-operating items by region is shown on pages 9, 11 and 13, and by segment and type is shown on page 31.

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 or Organic cash flow is a non-GAAP measure calculated by excluding post-tax operating cash flows relating to the Gulf of Mexico oil spill as reported in Note 2 from Net cash provided by operating activities as reported in the condensed group cash flow statement. 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 30.

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 company bears the risks and costs of exploration, development and production. In return, if exploration is successful, the oil company receives entitlement to variable physical volumes of hydrocarbons, representing recovery of the costs incurred and a stipulated share of the production remaining after such cost recovery.

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

Paid-up RMI excludes RMI which has not yet been paid for. For inventory that is held in storage, a first-in first-out (FIFO) approach is used to determine whether inventory has been paid for or not. Unpaid RMI is RMI which has not yet been paid for by BP. RMI, Paid-up RMI and Unpaid RMI are non-GAAP measures. Further information is provided on page 33.

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.

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Glossary (continued)

The Refining marker margin (RMM) is the average of regional indicator margins weighted for BP’s crude refining capacity in each region. Each regional marker margin is based on product yields and a marker crude oil deemed appropriate for the region. The regional indicator margins may not be representative of the margins achieved by BP in any period because of BP’s particular refinery configurations and crude and product slate.

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

RC profit or loss per share is a non-GAAP measure. Earnings per share is defined in Note 6. 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 34.

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

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

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

Underlying RC profit or loss is RC profit or loss after adjusting for non-operating items and fair value accounting effects. Underlying RC profit or loss and adjustments for fair value accounting effects are not recognized GAAP measures. See pages 31 and 32 for additional information on the non-operating items and fair value accounting effects that are used to arrive at underlying RC profit or loss in order to enable a full understanding of the events and their financial impact. BP believes that underlying RC profit or loss is a useful measure for investors because it is a measure closely tracked by management to evaluate BP’s operating performance and to make financial, strategic and operating decisions and because it may help investors to understand and evaluate, in the same manner as management, the underlying trends in BP’s operational performance on a comparable basis, period on period, by adjusting for the effects of these non-operating items and fair value accounting effects. The nearest equivalent measure on an IFRS basis for the group is profit or loss attributable to BP shareholders. The nearest equivalent measure on an IFRS basis for segments is RC profit or loss before interest and taxation.

Underlying RC profit or loss per share is a non-GAAP measure. Earnings per share is defined in Note 6. 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 34.

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

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

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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 2017. For a full discussion of the group’s material legal proceedings, see pages 261-265 of BP Annual Report and Form 20-F 2016 .

Deepwater Horizon accident and oil spill (the Incident)

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

Following numerous court decisions, on 31 March 2015, the United States district court in New Orleans denied the PSC motion seeking to alter or amend a revised policy relating to business economic loss claims. Such policy required the matching of revenue with the expenses incurred by claimants to generate that revenue, even where the revenue and expenses were recorded at different times. The PSC appealed the district court decision and, on 22 May 2017, the Fifth Circuit issued an opinion upholding the policy in part and reversing the policy in part. The Fifth Circuit ordered that the portion of the policy upheld, which covers the substantial majority of the remaining business economic loss claims, be applied as the governing methodology for all applicable business economic loss claims. BP filed a petition for a rehearing which was denied on 21 June 2017. On 5 July 2017, the district court issued an order instructing the court supervised settlement programme on how to implement the Fifth Circuit’s opinion. BP continues to evaluate the impact of the Fifth Circuit’s decision on undetermined business economic loss claims, and claims under appeal within the programme, and is considering its next steps in relation to this order. See Note 2 on page 18 for further information.

Cautionary statement

In order to utilize the ‘safe harbor’ provisions of the United States Private Securities Litigation Reform Act of 1995 (the ‘PSLRA’), BP is providing the following cautionary statement: The discussion in this results announcement contains certain forecasts, projections and forward-looking statements – that is, statements related to future, not past events – with respect to the financial condition, results of operations and businesses of BP and certain of the plans and objectives of BP with respect to these items. These statements may generally, but not always, be identified by the use of words such as ‘will’, ‘expects’, ‘is expected to’, ‘aims’, ‘should’, ‘may’, ‘objective’, ‘is likely to’, ‘intends’, ‘believes’, ‘anticipates’, ‘plans’, ‘we see’ or similar expressions. In particular, among other statements, expectations regarding the expected quarterly dividend payment and timing of such payment; expectations regarding 2017 net debt, organic capital expenditure and divestment proceeds; expectations regarding the adjusted effective tax rate in 2017; expectations regarding Upstream third-quarter 2017 reported production; expectations regarding Downstream third-quarter 2017 refining margins and North American heavy crude oil differentials; plans and expectations with respect to the start-up of new Upstream projects; expectations with respect to new Upstream production through 2020; expectations regarding Rosneft operational and financial information for the first half of 2017; expectations with respect to the timing and amount of payments relating to the Gulf of Mexico oil spill; and expectation that remaining claims under the 2012 PSC settlement will be substantially paid by the end of 2018; are all forward looking in nature. By their nature, forward-looking statements involve risk and uncertainty because they relate to events and depend on circumstances that will or may occur in the future and are outside the control of BP. Actual results may differ materially from those expressed in such statements, depending on a variety of factors, including: the specific factors identified in the discussions accompanying such forward-looking statements; the receipt of relevant third party and/or regulatory approvals; the timing and level of maintenance and/or turnaround activity; the timing and volume of refinery additions and outages; the timing of bringing new fields onstream; the timing, quantum and nature of certain divestments; future levels of industry product supply, demand and pricing, including supply growth in North America; OPEC quota restrictions; PSA effects; operational and safety problems; potential lapses in product quality; economic and financial market conditions generally or in various countries and regions; political stability and economic growth in relevant areas of the world; changes in laws and governmental regulations; regulatory or legal actions including the types of enforcement action pursued and the nature of remedies sought or imposed; the actions of prosecutors, regulatory authorities and courts; delays in the processes for resolving claims; exchange rate fluctuations; development and use of new technology; recruitment and retention of a skilled workforce; the success or otherwise of partnering; the actions of competitors, trading partners, contractors, subcontractors, creditors, rating agencies and others; our access to future credit resources; business disruption and crisis management; the impact on our reputation of ethical misconduct and non-compliance with regulatory obligations; trading losses; major uninsured losses; decisions by Rosneft’s management and board of directors; the actions of contractors; natural disasters and adverse weather conditions; changes in public expectations and other changes to business conditions; wars and acts of terrorism; cyber-attacks or sabotage; and other factors discussed elsewhere in this report and under “Risk factors” in BP Annual Report and Form 20-F 2016 as filed with the US Securities and Exchange Commission.

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Computation of ratio of earnings to fixed charges

	First
	half
$ million except ratio	2017
Earnings available for fixed charges:
Pre-tax profit from continuing operations before adjustment for
income or loss from joint ventures and associates	2,156
Fixed charges	1,403
Amortization of capitalized interest	108
Distributed income of joint ventures and associates	564
Interest capitalized	(147	)
Preference dividend requirements, gross of tax	(1	)
Non-controlling interest of subsidiaries’ income not incurring
fixed charges	(2	)
Total earnings available for fixed charges	4,081
Fixed charges:
Interest expensed	625
Interest capitalized	147
Rental expense representative of interest	630
Preference dividend requirements, gross of tax	1
Total fixed charges	1,403
Ratio of earnings to fixed charges	2.91

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The following table shows the unaudited consolidated capitalization and indebtedness of the BP group as of

30 June 2017 in accordance with IFRS:

Capitalization and indebtedness

$ million	30 June — 2017
Share capital and reserves
Capital shares (1-2)	5,330
Paid-in surplus (3)	13,586
Merger reserve (3)	27,206
Treasury shares	(17,149	)
Available-for-sale investments	6
Cash flow hedge reserve	(904	)
Foreign currency translation reserve	(5,857	)
Profit and loss account	74,585
BP shareholders’ equity	96,803
Finance debt (4-6)
Due within one year	7,385
Due after more than one year	55,619
Total finance debt	63,004
Total capitalization (7)	159,807

(1) Issued share capital as of 30 June 2017 comprised 19,751,491,901 ordinary shares, par value US$0.25 per share, and 12,706,252 preference shares, par value £1 per share. This excludes 1,483,428,207 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 2017.

(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 2016 – Liquidity and capital resources for further information.

(6) At 30 June 2017, the parent company, BP p.l.c., had issued guarantees totalling $60,212 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 2017, $142 million of finance debt was secured by the pledging of assets. The remainder of finance debt was unsecured.

(7) At 30 June 2017 the group had issued third-party guarantees under which amounts outstanding, incremental to amounts recognized on the group balance sheet, were $307 million in respect of the borrowings of equity-accounted entities and $324 million in respect of the borrowings of other third parties.

(8) There has been no material change since 30 June 2017 in the consolidated capitalization and indebtedness of BP.

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Recent credit ratings update

On 8 June 2017, Moody’s upgraded the rating of BP p.l.c. and the long-term debt ratings of its guaranteed subsidiaries from A2 to A1. Concurrently, Moody’s affirmed its Prime-1 commercial paper ratings of BP Capital Markets p.l.c. and BP Corporation North America, Inc. The outlook on all these ratings is positive.

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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:
DAVID J JACKSON
Company Secretary

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