Edgar Filing: BP PLC

Document

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 6-K

Report of Foreign Private Issuer

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

the Securities Exchange Act of 1934

for the period ended 31 December 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 x Form 40-F ¨

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

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

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BP p.l.c. and subsidiaries

Form 6-K for the period ended 31 December 2017_(a)



		Page
1.	Management’s Discussion and Analysis of Financial Condition and Results of Operations for the period January-December 2017_(b)	3-14, 27-32, 34-36

2.	Consolidated Financial Statements including Notes to Consolidated Financial Statements for the period January-December 2017	14-26

3.	Legal proceedings	33

4.	Cautionary statement	37

5.	Computation of Ratio of Earnings to Fixed Charges	38

6.	Capitalization and Indebtedness	39

7.	Signatures	40


^(a)	In this Form 6-K, references to the full year 2017 and full year 2016 refer to full year periods ended 31 December 2017 and 31 December 2016 respectively. References to the fourth quarter 2017 and fourth quarter 2016 refer to the three-month periods ended 31 December 2017 and 31 December 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 fourth quarter and full year 2017



Full year Highlights


•	Profit for the full year and fourth quarter was $3.4 billion and $27 million respectively, compared with $115 million and $497 million for the same periods in 2016. Underlying replacement cost profit* was $6.2 billion for full year 2017 and $2.1 billion for the fourth quarter, compared with $2.6 billion and $400 million for full year and fourth quarter 2016 respectively.


•	Operating cash flow* for 2017 was $18.9 billion, after post-tax Gulf of Mexico oil spill expenditure of $5.2 billion, compared with $10.7 billion, after post-tax Gulf of Mexico oil spill expenditure of $6.9 billion in 2016.


•	Downstream earnings were very strong with underlying replacement cost profit of $7.0 billion, 24% higher than 2016 and replacement cost profit of $7.2 billion, 40% higher than 2016.


•	Operational reliability was high, with refining availability* and Upstream BP-operated plant reliability* both 95%.


•	Seven new major projects* delivered, boosting oil and gas production. Upstream production, excluding BP's share of Rosneft production, was 12% higher than 2016, the highest since 2010. Including Rosneft, production was 3.6 million barrels of oil equivalent a day, 10% higher than 2016. Oil and gas realizations were 25% higher.


•	Exploration delivered the most successful year for BP since 2004.


•	Dividend unchanged at 10 cents per share.


•	BP began share buybacks in the fourth quarter, spending $343 million, fully offsetting the dilution from scrip dividends issued in the third quarter.


•	Non-operating items in the fourth quarter, which are excluded from underlying profit*, included a $0.9 billion charge for US tax changes and a $1.7 billion post-tax charge relating to a further provision for claims associated with the oil spill.



Financial summary	Fourth		Fourth
Financial summary	quarter		quarter		Year		Year
$ million	2017		2016		2017		2016
Profit for the period_(a)	27		497		3,389		115
Inventory holding (gains) losses*, before tax	(816	)	(601	)	(853	)	(1,597	)
Taxation charge (credit) on inventory holding gains and losses	206		176		225		483
RC profit (loss)*	(583	)	72		2,761		(999	)
Net (favourable) adverse impact of non-operating items* and fair value
accounting effects*, before tax	2,559		481		3,730		6,746
Taxation charge (credit) on non-operating items and fair value accounting effects	131		(153	)	(325	)	(3,162	)
Underlying RC profit	2,107		400		6,166		2,585
Profit per ordinary share (cents)	0.14		2.62		17.20		0.61
Profit per ADS (dollars)	0.01		0.16		1.03		0.04
RC profit (loss) per ordinary share (cents)*	(2.94	)	0.38		14.02		(5.33	)
RC profit (loss) per ADS (dollars)	(0.18	)	0.02		0.84		(0.32	)
Underlying RC profit per ordinary share (cents)*	10.64		2.11		31.31		13.79
Underlying RC profit per ADS (dollars)	0.64		0.13		1.88		0.83


^(a)	Profit attributable to BP shareholders.

* See definitions in the Glossary on page 34. RC profit (loss), underlying RC profit and organic capital expenditure are non-GAAP measures.

The commentary above and following should be read in conjunction with the cautionary statement on page 37.

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Group headlines

Earnings

BP’s profit for the fourth quarter and full year was $27 million and $3,389 million respectively, compared with $497 million and $115 million for the same periods in 2016.

For the full year, replacement cost (RC) profit was $2,761 million, compared with a loss of $999 million in 2016. Underlying RC profit was $6,166 million, compared with $2,585 million in 2016. Underlying RC profit is after adjusting for a net charge for non-operating items of $3,309 million and net adverse fair value accounting effects of $96 million (both on a post-tax basis).

For the fourth quarter, RC loss was $583 million, compared with a profit of $72 million for the same period in 2016. Underlying RC profit was $2,107 million compared with $400 million for the same period in 2016. Underlying RC profit is after adjusting for a net charge for non-operating items of $2,515 million and net adverse fair value accounting effects of $175 million (both on a post-tax basis).

See further information on page 5.

Depreciation, depletion and amortization

The charge for depreciation, depletion and amortization was $15.6 billion in 2017, compared with $14.5 billion in 2016. In 2018, we expect the charge to be higher than 2017.

Non-operating items

Non-operating items amounted to a charge of $2,325 million pre-tax and $2,515 million post-tax for the quarter and a charge of $3,622 million pre-tax and $3,309 million post-tax for the full year. The post-tax non-operating charge for the fourth quarter includes a charge of $1.7 billion relating to business economic loss and other claims associated with the Gulf of Mexico oil spill (see Note 2 on page 19) and a $0.9 billion deferred tax charge following the change in the US tax rate. See further information on page 28.

Effective tax rate

The effective tax rate (ETR) on the profit or loss for the fourth quarter and full year was 95% and 52% respectively, compared with 12% and 107% for the same periods in 2016.

The ETR on RC profit or loss* for the fourth quarter and full year was significantly impacted by the effect of non-operating items and therefore it is not a meaningful measure.

The adjusted ETR* is calculated by eliminating the impact of non-operating items, which for the fourth quarter includes a one-off deferred tax charge in respect of the revaluation of deferred tax assets and liabilities following the reduction in the US federal corporate income tax rate from 35% to 21% enacted in December 2017; fair value accounting effects; and the impact of a reduction in the UK supplementary tax charge in the third quarter of 2016.

The adjusted ETR for the fourth quarter and full year was 27% and 38% respectively, compared with 10% and 23% for the same periods in 2016. The adjusted ETR for the fourth quarter 2017 reflects a benefit from the reassessment of the recognition of deferred tax assets. The adjusted ETR for the fourth quarter 2016 was impacted by a high proportion of equity-accounted income (which is reported net of tax in the income statement) within RC profit, and reflected a benefit from the reassessment of the recognition of deferred tax assets and other items, partly offset by charges for foreign exchange impacts.

The adjusted ETR for the full year is higher than last year predominantly due to changes in the geographical mix of profits notably the impact of the renewal of our interest in the Abu Dhabi onshore oil concession. In the current environment, and assuming no further reassessment of the

recognition of deferred tax assets, the adjusted ETR in 2018 is expected to be above 40%. ETR on RC profit or loss and adjusted ETR are non-GAAP measures.

Dividend

BP today announced a quarterly dividend of 10.00 cents per ordinary share ($0.600 per ADS), which is expected to be paid on 29 March 2018. The corresponding amount in sterling will be announced on 19 March 2018. See page 25 for further information.

Share buybacks

BP recommenced a share buyback programme in the fourth quarter to offset the dilution of the scrip issue and repurchased 51 million ordinary shares at a cost of $343 million, including fees and stamp duty, during the fourth quarter of 2017.

Operating cash flow*

Operating cash flow for the fourth quarter and full year was $5.9 billion and $18.9 billion respectively, after post-tax expenditure relating to the Gulf of Mexico oil spill of $0.3 billion and $5.2 billion. For the same periods in 2016 the equivalent amounts were $2.4 billion and $10.7 billion, after post-tax Gulf of Mexico oil spill expenditure of $2.0 billion and $6.9 billion.

Capital expenditure*

Total capital expenditure for the fourth quarter and full year was $4.8 billion and $17.8 billion respectively, compared with $4.9 billion and $17.5 billion for the same periods in 2016.

Organic capital expenditure* for the fourth quarter and full year was $4.6 billion and $16.5 billion respectively, compared with $4.5 billion and $16.7 billion for the same periods in 2016. In 2018, we expect organic capital expenditure to be in the range of $15-16 billion.

Inorganic capital expenditure* for the fourth quarter and full year was $0.2 billion and $1.3 billion respectively, compared with $0.4 billion and $0.8 billion for the same periods in 2016.

See page 27 for further information.

Divestment and other proceeds

Total divestment and other proceeds for the year were $4.3 billion including proceeds of $0.8 billion received in relation to the initial public offering of BP Midstream Partners LP’s common units. Divestment proceeds* were $2.5 billion for the fourth quarter and $3.4 billion for the full year, compared with $0.5 billion and $2.6 billion for the same periods in 2016. In 2018, divestments are expected to be in the range of $2-3 billion.

Debt

Gross debt at 31 December 2017 was $63.2 billion compared with $58.3 billion a year ago. The ratio of gross debt to gross debt plus equity at 31 December 2017 was 38.6%, compared with 37.6% a year ago.

Net debt* at 31 December 2017 was $37.8 billion, compared with $35.5 billion a year ago. The net debt ratio* at 31 December 2017 was 27.4%, compared with 26.8% a year ago. We continue to target a net debt ratio in the range of 20-30%. Net debt and the net debt ratio are non-GAAP measures. See page 25 for more information.

Reserves replacement ratio*

The reserves replacement ratio on a combined basis of subsidiaries and equity-accounted entities was estimated at 143%_(a)for the year.

_(a) Includes estimated reserves data for Rosneft. The reserves replacement ratio will be finalized and reported in BP Annual Report and Form 20-F 2017.

The commentary above and following should be read in conjunction with the cautionary statement on page 37.

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Analysis of underlying RC profit before interest and tax



	Fourth		Fourth
	quarter		quarter		Year		Year
$ million	2017		2016		2017		2016
Underlying RC profit before interest and tax*
Upstream	2,223		400		5,865		(542	)
Downstream	1,474		877		6,967		5,634
Rosneft	321		135		836		567
Other businesses and corporate	(394	)	(424	)	(1,598	)	(1,238	)
Consolidation adjustment – UPII*	(149	)	(132	)	(212	)	(196	)
Underlying RC profit before interest and tax	3,475		856		11,858		4,225
Finance costs and net finance expense relating to pensions and other
post-retirement benefits	(550	)	(359	)	(1,801	)	(1,371	)
Taxation on an underlying RC basis	(782	)	(51	)	(3,812	)	(212	)
Non-controlling interests	(36	)	(46	)	(79	)	(57	)
Underlying RC profit attributable to BP shareholders	2,107		400		6,166		2,585

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



	Fourth		Fourth
	quarter		quarter		Year		Year
$ million	2017		2016		2017		2016
RC profit (loss) before interest and tax*
Upstream	1,928		692		5,221		574
Downstream	1,773		899		7,221		5,162
Rosneft	321		158		836		590
Other businesses and corporate_(a)	(2,833	)	(1,117	)	(4,445	)	(8,157	)
Consolidation adjustment – UPII	(149	)	(132	)	(212	)	(196	)
RC profit (loss) before interest and tax	1,040		500		8,621		(2,027	)
Finance costs and net finance expense relating to pensions and other
post-retirement benefits	(674	)	(484	)	(2,294	)	(1,865	)
Taxation on a RC basis	(913	)	102		(3,487	)	2,950
Non-controlling interests	(36	)	(46	)	(79	)	(57	)
RC profit (loss) attributable to BP shareholders	(583	)	72		2,761		(999	)
Inventory holding gains (losses)	816		601		853		1,597
Taxation (charge) credit on inventory holding gains and losses	(206	)	(176	)	(225	)	(483	)
Profit for the period attributable to BP shareholders	27		497		3,389		115


^(a)	Includes costs related to the Gulf of Mexico oil spill. See page 13 and also Note 2 from page 19 for further information on the accounting for the Gulf of Mexico oil spill.

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Strategic progress

Upstream

2017 oil and gas production, excluding Rosneft, was 12% higher than in 2016, the highest since 2010. Upstream unit production costs* were 16% lower, benefiting from production growth and continued cost discipline.

Zohr in Egypt completed BP’s programme of seven major project* start-ups in 2017. Together with 2016 start-ups, the projects contribute more than 500mboe/d new net production capacity and are expected to deliver operating cash margins* around 35% greater than Upstream’s assets in 2015.

In the quarter BP accessed significant new exploration acreage in the Santos basin of Brazil and in Côte d’Ivoire with Kosmos Energy. BP announced six exploration discoveries in 2017 - the cumulative discovery of resources was BP’s largest since 2004.

Downstream

Fuels marketing earnings increased by more than 10% in 2017. Premium fuel volumes grew by 6% and BP’s convenience partnership model increased to 1,100 sites worldwide. More than 120 BP retail sites in Mexico were operational at year end. In lubricants, BP delivered premium brand growth and increased earnings from growth markets.

In manufacturing, both refining and petrochemicals grew earnings with record levels of advantaged feedstock processed in refining.

Advancing the energy transition

BP acquired a 43% interest in Lightsource, Europe’s largest solar development company, supporting its rapid expansion worldwide. Other progress included BP enhancing its biofuels business in Brazil through an ethanol storage joint venture, forming a partnership with Aria Energy to expand its renewable gas portfolio in the US and, in January, BP Ventures investing in the electric vehicle fast-charging company Freewire.

Financial framework

Operating cash flow* for full year 2017, after post-tax expenditure relating to the Gulf of Mexico oil spill of $5.2 billion, was $18.9 billion. This compares with $10.7 billion, after post-tax Gulf of Mexico oil spill expenditure of $6.9 billion, for full year 2016.

Organic capital expenditure* for 2017 was $16.5 billion, in the range of $15-17 billion previously indicated. BP expects 2018 organic capital expenditure to be in the range of $15-16 billion.

Total divestment and other proceeds for the year were $4.3 billion including $0.8 billion received in relation to the initial public offering of BP Midstream Partners LP’s common units. Divestment proceeds* were $3.4 billion for the full year, including the proceeds received in the fourth quarter for the sale of BP’s interest in the SECCO joint venture in China. In 2018, divestments are expected to be in the range of $2-3 billion.

Gulf of Mexico oil spill payments were $0.3 billion in the fourth quarter, bringing the total for 2017 to $5.2 billion. Cash outflows in 2018 are expected to be approximately $3 billion, weighted to the first half of the year.

Gearing* was 27.4% at the end of 2017. BP continues to target a gearing range of 20-30%.

Safety

The 3-year average for both Tier 1 process safety events* and reported recordable injury frequency* remains on an improving trend. Safety remains a core value and our number one priority. We are committed to continuous improvement to drive enhanced performance.



Operating metrics	Year 2017	Financial metrics	Year 2017
Operating metrics	(vs. Year 2016)	Financial metrics	(vs. Year 2016)
Tier 1 process safety events	18	Underlying RC profitⁱ	$6.2bn
Tier 1 process safety events	(+2)	Underlying RC profitⁱ	(+$3.6bn)
Reported recordable injury frequency	0.22	Operating cash flow excluding Gulf of Mexico oil spill payments	_(b)
Reported recordable injury frequency	(+3%)
Group production	3,595mboe/d	Organic capital expenditureⁱⁱ	$16.5bn
Group production	(+10%)	Organic capital expenditureⁱⁱ	(-$0.2bn)
Upstream production (excludes Rosneft segment)	2,466mboe/d	Gulf of Mexico oil spill payments	$5.2bn
Upstream production (excludes Rosneft segment)	(+12%)	Gulf of Mexico oil spill payments	(-$1.7bn)
Upstream unit production costs	$7.11/boe	Divestment proceeds	$3.4bn
Upstream unit production costs	(-16%)	Divestment proceeds	(+$0.8bn)
BP-operated Upstream operating efficiency*	80.5%	Net debt ratio (gearing)ⁱⁱⁱ	27.4%
BP-operated Upstream operating efficiency*		Net debt ratio (gearing)ⁱⁱⁱ	(+0.6)
BP-operated Upstream plant reliability* _(a)	94.7%	Dividend per ordinary share_(c)	10.00 cents
BP-operated Upstream plant reliability* _(a)	(-0.6)	Dividend per ordinary share_(c)	—
Refining availability*	95.3%	Return on average capital employed*_(d)^iv	5.8%
Refining availability*	—	Return on average capital employed*_(d)^iv	(+3.0)


^(a)	BP-operated Upstream plant reliability has been included as an operating metric this quarter. It is more comparable with the equivalent metric disclosed for the Downstream, which is ‘Refining availability’. BP-operated Upstream plant reliability was 94.9% for the first quarter 2017, 95.2% for the six months ended 30 June 2017 and 94.5% for the nine months ended 30 September 2017.

^(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 full year, net cash provided by operating activities was $18.9 billion and post-tax Gulf of Mexico oil spill expenditure was $5.2 billion.

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


^(d)	Return on average capital employed is included as this is a full year report.



Nearest GAAP equivalent measures
i	Profit for the period:	$3.4bn
ii	Capital expenditure*:	$17.8bn
iii	Gross debt ratio:	38.6%
iv	Numerator: Profit attributable to BP shareholders	$3.4bn
	Denominator: Average capital employed	$159.4bn

The commentary above contains forward-looking statements and should be read in conjunction with the cautionary statement on page 37.

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Upstream



	Fourth	Fourth
	quarter	quarter		Year		Year
$ million	2017	2016		2017		2016
Profit before interest and tax	1,928	711		5,229		634
Inventory holding (gains) losses*	—	(19	)	(8	)	(60	)
RC profit before interest and tax	1,928	692		5,221		574
Net (favourable) adverse impact of non-operating items* and fair value accounting effects*	295	(292	)	644		(1,116	)
Underlying RC profit (loss) before interest and tax*_(a)	2,223	400		5,865		(542	)


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

Financial results

The replacement cost profit before interest and tax for the fourth quarter and full year was $1,928 million and $5,221 million respectively, compared with $692 million and $574 million for the same periods in 2016. The fourth quarter and full year included a net non-operating charge of $144 million and $671 million respectively, compared with a net non-operating gain of $636 million and $1,753 million for the same periods in 2016. Fair value accounting effects in the fourth quarter and full year had an adverse impact of $151 million and a favourable impact of $27 million respectively, compared with an adverse impact of $344 million and $637 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 fourth quarter and full year was $2,223 million and $5,865 million respectively, compared with a profit of $400 million and a loss of $542 million for the same periods in 2016. The result for the fourth quarter mainly reflected higher liquids realizations and higher production including the impact of the Abu Dhabi onshore concession renewal and major project* start-ups. The result for the full year reflected higher liquids realizations, and higher production including the impact of the Abu Dhabi onshore concession renewal and major project start-ups, partly offset by higher depreciation, depletion and amortization, and higher exploration write-offs.

Production

Production for the quarter was 2,581mboe/d, 18.1% higher than the fourth quarter of 2016. Fourth quarter production reflects the fifth consecutive quarter of growth as well as the highest production since first quarter 2011. Underlying production* for the quarter increased by 11.1%, due to the ramp-up of major projects. For the full year, production was 2,466mboe/d, 11.7% higher than 2016. Underlying production for the full year was 7.9% higher than 2016 due to major project start-ups. The seven major project start-ups for 2017, together with the 2016 start-ups, contribute more than 500mboe/d of new net production capacity.

Key events

On 21 November, BP agreed to sell a package of its interests in the Bruce assets in the North Sea to Serica Energy plc, subject to regulatory approvals. The Bruce assets comprise the Bruce, Keith and Rhum fields, platforms and associated subsea infrastructure.

On 18 December, BP completed the formation of Pan American Energy Group (PAEG) (BP 50%, Bridas Corporation 50%), which is a combination of Pan American Energy and Axion Energy.

On 20 December, BP confirmed that production started from the Zohr gas field, offshore Egypt (ENI operator 60%, Rosneft 30%, BP 10%), BP’s seventh major project to start in 2017.

Also on 20 December, BP and Statoil signed an extension agreement for the In Amenas production-sharing contract* with Algerian state-owned energy company Sonatrach, which has been submitted to the Algerian authorities for ratification.

On 21 December, BP and Kosmos Energy (KE) were awarded five blocks offshore Côte d’Ivoire, under agreements with the government of Côte d’Ivoire and state oil company Société Nationale d'Operations Pétrolières de la Côte d'Ivoire (PETROCI) (BP 45%, KE 45%, PETROCI 10%).

In December Rosneft announced an agreement to develop resources within the Kharampurskoe and Festivalnoye licence areas in Yamalo-Nenets Autonomous Okrug in northern Russia jointly with BP. Rosneft will hold a majority stake of 51% and BP will hold a 49% stake. Completion of the deal is subject to regulatory approvals.

On 31 January, BP announced the oil discovery Capercaillie (BP 100%) and the oil discovery Achmelvich (BP 52.6%, Shell 28%, and Chevron 19.4%) in the UK North Sea, both operated by BP. These two discoveries bring the total exploration discoveries in 2017 to six, and our most successful exploration campaign in the UK North Sea since 2008.

Outlook

We expect full-year 2018 underlying production to be higher than 2017 due to the ramp-up of major projects. The actual reported outcome will depend on the exact timing of project start-ups, acquisition and divestment activities, OPEC quotas and entitlement impacts in our production-sharing agreements*. We expect first-quarter 2018 reported production to be broadly flat with the fourth quarter 2017, reflecting continued growth from the 2017 major project start-ups, offset by the expiration of the Abu Dhabi offshore concession and divestment impacts.

The commentary above contains forward-looking statements and should be read in conjunction with the cautionary statement on page 37.

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Upstream (continued)



	Fourth		Fourth
	quarter		quarter		Year		Year
$ million	2017		2016		2017		2016
Underlying RC profit (loss) before interest and tax
US	629		(147	)	1,238		(1,270	)
Non-US	1,594		547		4,627		728
	2,223		400		5,865		(542	)
Non-operating items
US_(a)	(187	)	21		(330	)	127
Non-US_(b)(c)	43		615		(341	)	1,626
	(144	)	636		(671	)	1,753
Fair value accounting effects
US	8		(274	)	192		(379	)
Non-US	(159	)	(70	)	(165	)	(258	)
	(151	)	(344	)	27		(637	)
RC profit (loss) before interest and tax
US	450		(400	)	1,100		(1,522	)
Non-US	1,478		1,092		4,121		2,096
	1,928		692		5,221		574
Exploration expense
US	27		511		282		693
Non-US_(c)(d)	494		(197	)	1,798		1,028
	521		314		2,080		1,721
Of which: Exploration expenditure written off_(c)(d)	372		166		1,603		1,274
Production (net of royalties)_(e)
Liquids* (mb/d)
US	430		406		426		391
Europe	117		122		119		120
Rest of World	796		650		811		698
	1,344		1,178		1,356		1,208
Of which equity-accounted entities	209		210		207		184
Natural gas (mmcf/d)
US	1,759		1,675		1,659		1,656
Europe	186		268		235		264
Rest of World	5,231		3,903		4,543		3,876
	7,176		5,846		6,436		5,796
Of which equity-accounted entities	534		517		547		494
Total hydrocarbons* (mboe/d)
US	734		694		712		676
Europe	150		168		160		165
Rest of World	1,698		1,323		1,594		1,366
	2,581		2,186		2,466		2,208
Of which equity-accounted entities	301		300		302		269
Average realizations*_(f)
Total liquids_(g) ($/bbl)	56.16		43.89		49.92		38.27
Natural gas ($/mcf)	3.23		3.08		3.19		2.84
Total hydrocarbons($/boe)	37.48		31.40		35.38		28.24


^(a)	Fourth quarter and full year 2017 include an impairment charge relating to the US Lower 48 business, partially offset by gains associated with asset divestments.

^(b)

Fourth quarter and full year 2017 include BP's share of an impairment reversal recognized by the Angola LNG equity-accounted entity, partially offset by other items. In addition, full year 2017 includes an impairment charge arising following the announcement of the agreement to sell the Forties Pipeline System business to INEOS. Fourth quarter and full year 2016 principally relate to impairment reversals in India, Angola and the North Sea.


^(c)	See page 28 for more information on non-operating items.


^(d)	Full year 2017 includes the write-off of exploration well and lease costs in Angola and the write-off of exploration wells in Egypt.


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


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


^(g)	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



	Fourth		Fourth
	quarter		quarter		Year		Year
$ million	2017		2016		2017		2016
Profit before interest and tax	2,492		1,457		7,979		6,646
Inventory holding (gains) losses*	(719	)	(558	)	(758	)	(1,484	)
RC profit before interest and tax	1,773		899		7,221		5,162
Net (favourable) adverse impact of non-operating items*
and fair value accounting effects*	(299	)	(22	)	(254	)	472
Underlying RC profit before interest and tax*_(a)	1,474		877		6,967		5,634


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

Financial results

The replacement cost profit before interest and tax for the fourth quarter and full year was $1,773 million and $7,221 million respectively, compared with $899 million and $5,162 million for the same periods in 2016.

The fourth quarter and full year include a net non-operating gain of $382 million and $389 million respectively, compared with a net non-operating charge of $77 million and $24 million for the same periods in 2016. Fair value accounting effects had an adverse impact of $83 million in the fourth quarter and $135 million for the full year, compared with a favourable impact of $99 million and an adverse impact of $448 million for the same periods in 2016.

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

Fuels

The fuels business reported an underlying replacement cost profit before interest and tax of $976 million for the fourth quarter and $4,872 million for the full year, compared with $417 million and $3,727 million for the same periods in 2016. The result for the quarter and full year reflects stronger refining performance. In addition, the full-year improvement reflects growth in fuels marketing, partly offset by a weaker contribution from supply and trading.

The refining result for the quarter and full year reflects continued strong operational performance, capturing higher industry refining margins, efficiency benefits as well as increased commercial optimization including the benefits of higher levels of advantaged feedstock. The full year result was, however, impacted by a higher level of planned turnaround activity.

The fuels marketing result for the full year reflects continued profit growth supported by higher premium fuel volumes which grew by 6% and the continued rollout of our convenience partnership model to more than 220 sites, bringing the total number of convenience partnership sites to 1,100 across our retail network.

We continue to grow in Mexico, where, by the end of 2017 we had more than 120 operational sites after becoming the first international oil company to enter the deregulated fuel retail market earlier in the year.

In December, the Australian Competition and Consumer Commission announced that it intends to oppose our proposed acquisition of Woolworths’ fuel and convenience sites in Australia. We are currently considering our next steps.

On 1 February 2018, we entered into joint ventures with Shandong Dongming Petrochemical Group to develop a leading branded retail fuels and convenience business in Shandong, Henan and Hebei provinces in China.

Lubricants

The lubricants business reported an underlying replacement cost profit before interest and tax of $375 million for the fourth quarter and $1,479 million for the full year, compared with $357 million and $1,523 million for the same periods in 2016. The result for the quarter and full year reflects growth in premium brands and growth markets, offset by the adverse lag impact of increasing base oil prices.

Petrochemicals

The petrochemicals business reported an underlying replacement cost profit before interest and tax of $123 million for the fourth quarter and $616 million for the full year, compared with $103 million and $384 million for the same periods in 2016. The result for the quarter and full year reflects an improved margin environment, stronger margin optimization, the benefits from our efficiency programmes and a lower level of turnaround activity. The result was, however, impacted by the divestment of our interest in the SECCO joint venture, which completed in the fourth quarter and was classified as held for sale in the group balance sheet at 30 September 2017.

Outlook

Looking to the first quarter of 2018, we expect higher discounts for North American heavy crude oil but lower industry refining margins. In addition, we expect our turnaround activity to be lower in refining but significantly higher in petrochemicals.

The commentary above contains forward-looking statements and should be read in conjunction with the cautionary statement on page 37.

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Downstream (continued)



	Fourth		Fourth
	quarter		quarter		Year		Year
$ million	2017		2016		2017		2016
Underlying RC profit before interest and tax - by region
US	501		(371	)	1,978		853
Non-US	973		1,248		4,989		4,781
	1,474		877		6,967		5,634
Non-operating items
US	(25	)	(122	)	(48	)	(48	)
Non-US_(a)	407		45		437		24
	382		(77	)	389		(24	)
Fair value accounting effects
US	3		22		(29	)	(321	)
Non-US	(86	)	77		(106	)	(127	)
	(83	)	99		(135	)	(448	)
RC profit before interest and tax
US	479		(471	)	1,901		484
Non-US	1,294		1,370		5,320		4,678
	1,773		899		7,221		5,162

Underlying RC profit before interest and tax - by business_(b)(c)
Fuels	976		417		4,872		3,727
Lubricants	375		357		1,479		1,523
Petrochemicals	123		103		616		384
	1,474		877		6,967		5,634
Non-operating items and fair value accounting effects_(d)
Fuels	(202	)	103		(193	)	(390	)
Lubricants	(14	)	(81	)	(22	)	(84	)
Petrochemicals_(a)	515		—		469		2
	299		22		254		(472	)
RC profit before interest and tax_(b)(c)
Fuels	774		520		4,679		3,337
Lubricants	361		276		1,457		1,439
Petrochemicals	638		103		1,085		386
	1,773		899		7,221		5,162

BP average refining marker margin (RMM)* ($/bbl)	14.4		11.4		14.1		11.8
Refinery throughputs (mb/d)
US	714		604		713		646
Europe	741		806		773		803
Rest of World	243		234		216		236
	1,698		1,644		1,702		1,685
Refining availability* (%)	96.1		94.9		95.3		95.3

Marketing sales of refined products (mb/d)
US	1,127		1,146		1,151		1,134
Europe	1,132		1,166		1,140		1,179
Rest of World	542		540		508		512
	2,801		2,852		2,799		2,825
Trading/supply sales of refined products	3,549		2,836		3,149		2,775
Total sales volumes of refined products	6,350		5,688		5,948		5,600

Petrochemicals production (kte)
US	641		546		2,428		2,564
Europe	1,559		930		5,462		3,729
Rest of World	1,306		2,071		7,405		7,934
	3,506		3,547		15,295		14,227


^(a)	Fourth quarter and full year 2017 gain primarily reflects the disposal of our shareholding in the SECCO joint venture.


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


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


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

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Rosneft



	Fourth		Fourth
	quarter		quarter		Year		Year
$ million	2017_(a)		2016		2017_(a)		2016
Profit before interest and tax_(b)	418		182		923		643
Inventory holding (gains) losses*	(97	)	(24	)	(87	)	(53	)
RC profit before interest and tax	321		158		836		590
Net charge (credit) for non-operating items*	—		(23	)	—		(23	)
Underlying RC profit before interest and tax*	321		135		836		567

Financial results

Replacement cost profit before interest and tax for the fourth quarter and full year was $321 million and $836 million respectively, compared with $158 million and $590 million for the same periods in 2016.

There were no non-operating items in the fourth quarter and full year of 2017, compared with a non-operating gain of $23 million in the same periods of 2016.

After adjusting for non-operating items, the underlying replacement cost profit before interest and tax for the fourth quarter and full year was $321 million and $836 million respectively, compared with $135 million and $567 million for the same periods in 2016.

Compared with the same periods in 2016, the results primarily reflected higher oil prices. The results for the fourth quarter and the full year also benefited from a $163-million gain representing the BP share of a voluntary out-of-court settlement between Sistema, Sistema-Invest and the Rosneft subsidiary, Bashneft. These positive effects were partially offset by adverse foreign exchange effects.

In September 2017 the extraordinary general meeting adopted a resolution to pay interim dividends for the first half of 2017 of 3.83 Russian roubles per ordinary share. In October BP received a dividend of $124 million after the deduction of withholding tax.

Key events

In October Rosneft completed the acquisition of a 30% stake for $1.1 billion in a concession agreement to develop the Zohr field in Egypt from the Italian company Eni. Eni retains a 60% stake and BP holds the remaining 10%.

In December Rosneft announced an agreement to develop subsoil resources within the Kharampurskoe and Festivalnoye licence areas in Yamalo-Nenets Autonomous Okrug in northern Russia jointly with BP. Rosneft will hold a majority stake of 51% and BP will hold a 49% stake. Completion of the deal is subject to regulatory approvals.



	Fourth	Fourth
	quarter	quarter	Year	Year
	2017_(a)	2016	2017_(a)	2016
Production (net of royalties) (BP share)
Liquids* (mb/d)	899	919	904	840
Natural gas (mmcf/d)	1,333	1,347	1,308	1,279
Total hydrocarbons* (mboe/d)	1,129	1,152	1,129	1,060


^(a)	The operational and financial information of the Rosneft segment for the fourth quarter and full year is based on preliminary operational and financial results of Rosneft for the full year ended 31 December 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 fourth quarter and full year 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



	Fourth		Fourth
	quarter		quarter		Year		Year
$ million	2017		2016		2017		2016
Profit (loss) before interest and tax
Gulf of Mexico oil spill	(2,221	)	(674	)	(2,687	)	(6,640	)
Other	(612	)	(443	)	(1,758	)	(1,517	)
Profit (loss) before interest and tax	(2,833	)	(1,117	)	(4,445	)	(8,157	)
Inventory holding (gains) losses*	—		—		—		—
RC profit (loss) before interest and tax	(2,833	)	(1,117	)	(4,445	)	(8,157	)
Net charge (credit) for non-operating items*
Gulf of Mexico oil spill	2,221		674		2,687		6,640
Other	218		19		160		279
Net charge (credit) for non-operating items	2,439		693		2,847		6,919
Underlying RC profit (loss) before interest and tax*	(394	)	(424	)	(1,598	)	(1,238	)
Underlying RC profit (loss) before interest and tax
US	(29	)	50		(475	)	(276	)
Non-US	(365	)	(474	)	(1,123	)	(962	)
	(394	)	(424	)	(1,598	)	(1,238	)
Non-operating items
US	(2,381	)	(672	)	(2,861	)	(6,824	)
Non-US	(58	)	(21	)	14		(95	)
	(2,439	)	(693	)	(2,847	)	(6,919	)
RC profit (loss) before interest and tax
US	(2,410	)	(622	)	(3,336	)	(7,100	)
Non-US	(423	)	(495	)	(1,109	)	(1,057	)
	(2,833	)	(1,117	)	(4,445	)	(8,157	)

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 fourth quarter and full year was $2,833 million and $4,445 million respectively, compared with $1,117 million and $8,157 million for the same periods in 2016.

The results included a net non-operating charge of $2,439 million for the fourth quarter and $2,847 million for the full year, mainly relating to the Gulf of Mexico oil spill, compared with a net non-operating charge of $693 million and $6,919 million for the same periods in 2016. See Note 2 on page 19 for more information on the Gulf of Mexico oil spill.

After adjusting for non-operating items, the underlying replacement cost loss before interest and tax for the fourth quarter and full year was $394 million and $1,598 million respectively, compared with $424 million and $1,238 million for the same periods in 2016. The underlying charge for the full year was impacted by weaker business results, higher corporate costs and adverse foreign exchange effects which had a favourable effect in 2016.

Alternative energy

The net ethanol-equivalent production (which includes ethanol and sugar) for the fourth quarter and full year was 188 million litres and 776 million litres respectively, compared with 98 million litres and 733 million litres for the same periods in 2016.

Net wind generation capacity*_(a) was 1,432MW at 31 December 2017 compared with 1,474MW at 31 December 2016. BP’s net share of wind generation for the fourth quarter and full year was 1,148GWh and 4,004GWh respectively, compared with 1,154GWh and 4,389GWh for the same periods in 2016.


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

BP formed a strategic partnership with Lightsource, Europe's largest developer of large-scale solar projects, with the aim of driving further growth of solar power development worldwide. Under the terms of the deal, which completed on 31 January 2018, BP acquired a 43% equity share in Lightsource for a total consideration of $200 million, payable over three years. The move will combine BP’s global scale, technology and trading capabilities with Lightsource’s expertise in solar development. The company will rebrand as Lightsource BP.

Outlook

In 2018, Other businesses and corporate average quarterly charges, excluding non-operating items, are expected to be around $350 million although this will fluctuate from quarter to quarter.

The commentary above contains forward-looking statements and should be read in conjunction with the cautionary statement on page 37.

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Financial statements

Group income statement



	Fourth	Fourth
	quarter	quarter		Year	Year
$ million	2017	2016		2017	2016

Sales and other operating revenues (Note 4)	67,816	51,007		240,208	183,008
Earnings from joint ventures - after interest and tax	581	489		1,177	966
Earnings from associates - after interest and tax	526	263		1,330	994
Interest and other income	223	114		657	506
Gains on sale of businesses and fixed assets	876	248		1,210	1,132
Total revenues and other income	70,022	52,121		244,582	186,606
Purchases_(a)	51,745	37,883		179,716	132,219
Production and manufacturing expenses_(b)	7,759	6,595		24,229	29,077
Production and similar taxes (Note 5)_(a)	511	199		1,775	683
Depreciation, depletion and amortization (Note 4)	4,045	3,642		15,584	14,505
Impairment and losses on sale of businesses and fixed assets	604	(305	)	1,216	(1,664	)
Exploration expense	521	314		2,080	1,721
Distribution and administration expenses	2,981	2,692		10,508	10,495
Profit (loss) before interest and taxation	1,856	1,101		9,474	(430	)
Finance costs_(b)	616	434		2,074	1,675
Net finance expense relating to pensions and other post retirement benefits	58	50		220	190
Profit (loss) before taxation	1,182	617		7,180	(2,295	)
Taxation_(b)	1,119	74		3,712	(2,467	)
Profit (loss) for the period	63	543		3,468	172
Attributable to
BP shareholders	27	497		3,389	115
Non-controlling interests	36	46		79	57
	63	543		3,468	172

Earnings per share (Note 6)
Profit (loss) for the period attributable to BP shareholders
Per ordinary share (cents)
Basic	0.14	2.62		17.20	0.61
Diluted	0.14	2.60		17.10	0.60
Per ADS (dollars)
Basic	0.01	0.16		1.03	0.04
Diluted	0.01	0.16		1.03	0.04


^(a)	Amounts reported in prior quarters of 2017 for Purchases and Production and similar taxes have been amended, with no effect on profit for the period. See Note 5 for further information.


^(b)	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



	Fourth		Fourth
	quarter		quarter		Year		Year
$ million	2017		2016		2017		2016

Profit (loss) for the period	63		543		3,468		172
Other comprehensive income
Items that may be reclassified subsequently to profit or loss
Currency translation differences	264		(777	)	1,986		254
Exchange (gains) losses on translation of foreign operations reclassified to gain
or loss on sale of businesses and fixed assets	(138	)	24		(120	)	30
Available-for-sale investments	11		—		14		1
Cash flow hedges marked to market	19		(204	)	197		(639	)
Cash flow hedges reclassified to the income statement	23		86		116		196
Cash flow hedges reclassified to the balance sheet	8		32		112		81
Share of items relating to equity-accounted entities, net of tax	133		172		564		833
Income tax relating to items that may be reclassified	(81	)	97		(261	)	13
	239		(570	)	2,608		769
Items that will not be reclassified to profit or loss
Remeasurements of the net pension and other post-retirement
benefit liability or asset	1,599		3,484		3,646		(2,496	)
Income tax relating to items that will not be reclassified	(539	)	(765	)	(1,238	)	739
	1,060		2,719		2,408		(1,757	)
Other comprehensive income	1,299		2,149		5,016		(988	)
Total comprehensive income	1,362		2,692		8,484		(816	)
Attributable to
BP shareholders	1,312		2,667		8,353		(846	)
Non-controlling interests	50		25		131		30
	1,362		2,692		8,484		(816	)

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Group statement of changes in equity



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

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

Total comprehensive income	8,353		131		8,484
Dividends	(6,153	)	(141	)	(6,294	)
Repurchase of ordinary share capital	(343	)	—		(343	)
Share-based payments, net of tax	687		—		687
Share of equity-accounted entities’ changes in equity, net of tax	215		—		215
Transactions involving non-controlling interests, net of tax	446		366		812
At 31 December 2017	98,491		1,913		100,404

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

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

Total comprehensive income	(846	)	30		(816	)
Dividends	(4,611	)	(107	)	(4,718	)
Share-based payments, net of tax	2,991		—		2,991
Share of equity-accounted entities' changes in equity, net of tax	106		—		106
Transactions involving non-controlling interests, net of tax	430		463		893
At 31 December 2016	95,286		1,557		96,843

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Group balance sheet



	31 December	31 December
$ million	2017	2016
Non-current assets
Property, plant and equipment	129,471	129,757
Goodwill	11,551	11,194
Intangible assets	18,355	18,183
Investments in joint ventures	7,994	8,609
Investments in associates	16,991	14,092
Other investments	1,245	1,033
Fixed assets	185,607	182,868
Loans	646	532
Trade and other receivables	1,434	1,474
Derivative financial instruments	4,110	4,359
Prepayments	1,112	945
Deferred tax assets	4,469	4,741
Defined benefit pension plan surpluses	4,169	584
	201,547	195,503
Current assets
Loans	190	259
Inventories	19,011	17,655
Trade and other receivables	24,849	20,675
Derivative financial instruments	3,032	3,016
Prepayments	1,414	1,486
Current tax receivable	761	1,194
Other investments	125	44
Cash and cash equivalents	25,586	23,484
	74,968	67,813
Total assets	276,515	263,316
Current liabilities
Trade and other payables	44,209	37,915
Derivative financial instruments	2,808	2,991
Accruals	4,960	5,136
Finance debt	7,739	6,634
Current tax payable	1,686	1,666
Provisions	3,324	4,012
	64,726	58,354
Non-current liabilities
Other payables	13,889	13,946
Derivative financial instruments	3,761	5,513
Accruals	505	469
Finance debt	55,491	51,666
Deferred tax liabilities	7,982	7,238
Provisions	20,620	20,412
Defined benefit pension plan and other post-retirement benefit plan deficits	9,137	8,875
	111,385	108,119
Total liabilities	176,111	166,473
Net assets	100,404	96,843
Equity
BP shareholders’ equity	98,491	95,286
Non-controlling interests	1,913	1,557
Total equity	100,404	96,843

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Condensed group cash flow statement



	Fourth		Fourth
	quarter		quarter		Year		Year
$ million	2017		2016		2017		2016
Operating activities
Profit (loss) before taxation	1,182		617		7,180		(2,295	)
Adjustments to reconcile profit (loss) before taxation to net cash
provided by operating activities
Depreciation, depletion and amortization and exploration expenditure
written off	4,417		3,808		17,187		15,779
Impairment and (gain) loss on sale of businesses and fixed assets	(272	)	(553	)	6		(2,796	)
Earnings from equity-accounted entities, less dividends received	(820	)	(605	)	(1,254	)	(855	)
Net charge for interest and other finance expense, less net interest paid	294		310		793		795
Share-based payments	166		150		661		779
Net operating charge for pensions and other post-retirement benefits, less
contributions and benefit payments for unfunded plans	(215	)	(347	)	(394	)	(467	)
Net charge for provisions, less payments	2,244		(629	)	2,106		4,487
Movements in inventories and other current and non-current assets and
liabilities	(60	)	393		(3,352	)	(3,198	)
Income taxes paid	(1,033	)	(716	)	(4,002	)	(1,538	)
Net cash provided by operating activities	5,903		2,428		18,931		10,691
Investing activities
Expenditure on property, plant and equipment, intangible and other assets	(4,422	)	(4,658	)	(16,562	)	(16,701	)
Acquisitions, net of cash acquired	(16	)	(1	)	(327	)	(1	)
Investment in joint ventures	(15	)	(37	)	(50	)	(50	)
Investment in associates	(368	)	(226	)	(901	)	(700	)
Total cash capital expenditure	(4,821	)	(4,922	)	(17,840	)	(17,452	)
Proceeds from disposal of fixed assets	2,287		391		2,936		1,372
Proceeds from disposal of businesses, net of cash disposed	173		78		478		1,259
Proceeds from loan repayments	8		7		349		68
Net cash used in investing activities	(2,353	)	(4,446	)	(14,077	)	(14,753	)
Financing activities
Net issue (repurchase) of shares	(343	)	—		(343	)	—
Proceeds from long-term financing	201		3,069		8,712		12,442
Repayments of long-term financing	(2,657	)	(1,733	)	(6,276	)	(6,685	)
Net increase (decrease) in short-term debt	(297	)	375		(158	)	51
Net increase (decrease) in non-controlling interests	982		126		1,063		887
Dividends paid - BP shareholders	(1,627	)	(1,182	)	(6,153	)	(4,611	)
- non-controlling interests	(32	)	(24	)	(141	)	(107	)
Net cash provided by (used in) financing activities	(3,773	)	631		(3,296	)	1,977
Currency translation differences relating to cash and cash equivalents	29		(649	)	544		(820	)
Increase (decrease) in cash and cash equivalents	(194	)	(2,036	)	2,102		(2,905	)
Cash and cash equivalents at beginning of period	25,780		25,520		23,484		26,389
Cash and cash equivalents at end of period	25,586		23,484		25,586		23,484

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Notes

Note 1. Basis of preparation

The results for the interim periods and for the year ended 31 December 2017 are unaudited and, in the opinion of management, include all adjustments necessary for a fair presentation of the results for each period. All such adjustments are of a normal recurring nature. This report should be read in conjunction with the consolidated financial statements and related notes for the year ended 31 December 2016 included in BP Annual Report and Form 20-F 2016.

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

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

Note 2. Gulf of Mexico oil spill

(a) Overview

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

The group income statement includes a post-tax charge for the fourth quarter of $1,693 million due to an increase in the provision relating to business economic loss (BEL) and other claims associated with the Deepwater Horizon Court Supervised Settlement Program (DHCSSP). The increase in the provision is primarily a result of significantly higher average claims determinations issued by the DHCSSP in the fourth quarter and the continuing effect of the Fifth Circuit’s May 2017 opinion on the matching of revenues with expenses when evaluating BEL claims.

The group income statement for the fourth quarter also includes finance costs relating to the unwinding of discounting effects and a tax charge of $3,012 million in respect of the revaluation of US deferred tax assets related to the Gulf of Mexico oil spill following the reduction in the US federal corporate income tax rate from 35% to 21% enacted in December 2017.

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.



	Fourth		Fourth
	quarter		quarter		Year		Year
$ million	2017		2016		2017		2016
Income statement
Production and manufacturing expenses	2,221		674		2,687		6,640
Profit (loss) before interest and taxation	(2,221	)	(674	)	(2,687	)	(6,640	)
Finance costs	124		125		493		494
Profit (loss) before taxation	(2,345	)	(799	)	(3,180	)	(7,134	)
Taxation	(2,495	)	268		(2,222	)	3,105
Profit (loss) for the period	(4,840	)	(531	)	(5,402	)	(4,029	)

The cumulative pre-tax income statement charge since the incident, in April 2010, amounts to $65,765 million.

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Note 2. Gulf of Mexico oil spill (continued)



	31 December		31 December
$ million	2017		2016
Balance sheet
Current assets
Trade and other receivables	252		194
Current liabilities
Trade and other payables	(2,089	)	(3,056	)
Provisions	(1,439	)	(2,330	)
Net current assets (liabilities)	(3,276	)	(5,192	)
Non-current assets
Deferred tax assets	2,067		2,973
Non-current liabilities
Other payables	(12,253	)	(13,522	)
Provisions	(1,141	)	(112	)
Deferred tax liabilities	3,634		5,119
Net non-current assets (liabilities)	(7,693	)	(5,542	)
Net assets (liabilities)	(10,969	)	(10,734	)



	Fourth		Fourth
	quarter		quarter		Year		Year
$ million	2017		2016		2017		2016
Cash flow statement - Operating activities
Profit (loss) before taxation	(2,345	)	(799	)	(3,180	)	(7,134	)
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	124		125		493		494
Net charge for provisions, less payments	2,181		(376	)	2,542		4,353
Movements in inventories and other current and non-current assets and liabilities	(413	)	(993	)	(5,191	)	(4,818	)
Pre-tax cash flows	(453	)	(2,043	)	(5,336	)	(7,105	)

Cash outflows in 2016 and 2017 include payments made under the 2012 agreement with the US government to resolve all federal criminal claims arising from the incident and the 2016 consent decree and settlement agreement with the United States and the five Gulf coast states. Net cash from operating activities relating to the Gulf of Mexico oil spill, on a post-tax basis, amounted to an outflow of $284 million and $5,167 million in the fourth quarter and full year of 2017 respectively. For the same periods in 2016, the amount was an outflow of $2,043 million and $6,892 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 October 2017	726
Increase in provision	2,210
Reclassified to other payables	(50	)
Utilization	(306	)
At 31 December 2017	2,580

Movements in the remaining provision for the full year are shown in the table below.



$ million
At 1 January 2017	2,442
Increase in provision	2,647
Reclassified to other payables	(759	)
Utilization	(1,750	)
At 31 December 2017	2,580

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

PSC settlement

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

The increase in the provision in the quarter is primarily a result of significantly higher average claims determinations issued by the Deepwater Horizon Court Supervised Settlement Program (settlement programme) during the fourth quarter and the continuing effect of the May 2017 Fifth Circuit opinion on the policy addressing the matching of revenue with expenses in relation to business economic loss claims. See Legal proceedings on page 33 for further details on the May 2017 Fifth Circuit opinion and related appeals.

The settlement programme’s determination of business economic loss claims was substantially completed by the end of 2017. Nevertheless, a significant number of business economic loss claims determined by the settlement programme have been and continue to be appealed by BP and/or the claimants, with the total value of claims under appeal or eligible for appeal approximately doubling during the fourth quarter. The provision at the end of the year reflects the latest estimate of the amounts that are expected ultimately to be paid to resolve these claims. Depending upon the resolution of these claims (including how such resolution may be impacted by the May 2017 Fifth Circuit opinion), the amounts payable may differ from those currently provided.

The settlement programme is expected to issue determinations with respect to the remaining business economic loss claims in the first half of 2018. Whilst BP has a better understanding of the total population of remaining claims, there is uncertainty around how these claims will ultimately be determined, including in relation to the impact of the May 2017 Fifth Circuit opinion on the determination of the business economic claims.

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

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



	Fourth		Fourth
	quarter		quarter		Year		Year
$ million	2017		2016		2017		2016
Upstream	1,928		692		5,221		574
Downstream	1,773		899		7,221		5,162
Rosneft	321		158		836		590
Other businesses and corporate_(a)	(2,833	)	(1,117	)	(4,445	)	(8,157	)
	1,189		632		8,833		(1,831	)
Consolidation adjustment - UPII*	(149	)	(132	)	(212	)	(196	)
RC profit (loss) before interest and tax*	1,040		500		8,621		(2,027	)
Inventory holding gains (losses)*
Upstream	—		19		8		60
Downstream	719		558		758		1,484
Rosneft (net of tax)	97		24		87		53
Profit (loss) before interest and tax	1,856		1,101		9,474		(430	)
Finance costs	616		434		2,074		1,675
Net finance expense relating to pensions and other
post-retirement benefits	58		50		220		190
Profit (loss) before taxation	1,182		617		7,180		(2,295	)

RC profit (loss) before interest and tax*
US	(1,509	)	(1,646	)	(266	)	(8,311	)
Non-US	2,549		2,146		8,887		6,284
	1,040		500		8,621		(2,027	)


^(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	Fourth	Fourth
	quarter	quarter	Year	Year
$ million	2017	2016	2017	2016
By segment
Upstream	12,651	9,129	45,440	33,188
Downstream	62,697	46,834	219,853	167,683
Other businesses and corporate	480	424	1,469	1,667
	75,828	56,387	266,762	202,538

Less: sales and other operating revenues between segments
Upstream	6,929	4,695	24,179	17,581
Downstream	913	523	1,800	1,291
Other businesses and corporate	170	162	575	658
	8,012	5,380	26,554	19,530

Third party sales and other operating revenues
Upstream	5,722	4,434	21,261	15,607
Downstream	61,784	46,311	218,053	166,392
Other businesses and corporate	310	262	894	1,009
Total sales and other operating revenues	67,816	51,007	240,208	183,008

By geographical area
US	24,127	18,642	88,709	68,772
Non-US	50,778	37,381	176,113	128,771
	74,905	56,023	264,822	197,543
Less: sales and other operating revenues between areas	7,089	5,016	24,614	14,535
	67,816	51,007	240,208	183,008



Depreciation, depletion and amortization	Fourth	Fourth
	quarter	quarter	Year	Year
$ million	2017	2016	2017	2016
Upstream
US	1,107	1,216	4,631	4,396
Non-US	2,339	1,859	8,637	7,835
	3,446	3,075	13,268	12,231
Downstream
US	218	219	875	856
Non-US	301	273	1,141	1,094
	519	492	2,016	1,950
Other businesses and corporate
US	16	20	65	71
Non-US	64	55	235	253
	80	75	300	324
Total group	4,045	3,642	15,584	14,505

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Note 5. Production and similar taxes



	Fourth	Fourth
	quarter	quarter	Year	Year
$ million	2017	2016	2017	2016
US	44	38	52	155
Non-US_(a)	467	161	1,723	528
	511	199	1,775	683

^(a)

Amounts reported in prior quarters of 2017 have been amended as certain charges are better presented as Production and similar taxes rather than the previous presentation which showed the amounts as royalties within the Purchases line; there is no impact upon 2016. Amended total Production and similar taxes are $468 million for the first quarter, $347 million for the second quarter and $449 million for the third quarter. The previously reported amounts were $306 million, $189 million and $278 million respectively. Amended non-US Production and similar taxes are $432 million for the first quarter, $306 million for the second quarter and $518 million for the third quarter. The previously reported amounts were $270 million, $148 million and $347 million respectively. Purchases have been amended by the same amounts and there is, therefore, no impact on reported profit.

Note 6. Earnings per share and shares in issue

Basic earnings per ordinary share (EpS) amounts are calculated by dividing the profit (loss) for the period attributable to ordinary shareholders by the weighted average number of ordinary shares outstanding during the period. During the quarter the company repurchased 51 million ordinary shares for a total consideration of $343 million, including transaction costs of $2 million, as part of the share buyback programme as announced on 31 October 2017. The number of shares in issue is reduced when shares are repurchased.

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

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



	Fourth	Fourth
	quarter	quarter	Year	Year
$ million	2017	2016	2017	2016
Results for the period
Profit (loss) for the period attributable to BP shareholders	27	497	3,389	115
Less: preference dividend	—	—	1	1
Profit (loss) attributable to BP ordinary shareholders	27	497	3,388	114

Number of shares (thousand)_(a)
Basic weighted average number of shares outstanding	19,804,932	18,995,725	19,692,613	18,744,800
ADS equivalent	3,300,822	3,165,954	3,282,102	3,124,133

Weighted average number of shares outstanding used to
calculate diluted earnings per share	19,929,655	19,107,599	19,816,442	18,855,319
ADS equivalent	3,321,609	3,184,599	3,302,740	3,142,553

Shares in issue at period-end	19,817,325	19,438,990	19,817,325	19,438,990
ADS equivalent	3,302,887	3,239,831	3,302,887	3,239,831


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

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Note 7. Dividends

Dividends payable

BP today announced an interim dividend of 10.00 cents per ordinary share which is expected to be paid on 29 March 2018 to shareholders and American Depositary Share (ADS) holders on the register on 16 February 2018. The corresponding amount in sterling is due to be announced on 19 March 2018, calculated based on the average of the market exchange rates for the four dealing days commencing on 13 March 2018. Holders of ADSs are expected to receive $0.600 per ADS (less applicable fees). A scrip dividend alternative is available, allowing shareholders to elect to receive their dividend in the form of new ordinary shares and ADS holders in the form of new ADSs. Details of the fourth quarter dividend and timetable are available at bp.com/dividends and details of the scrip dividend programme are available at bp.com/scrip.



	Fourth	Fourth
	quarter	quarter	Year	Year
	2017	2016	2017	2016
Dividends paid per ordinary share
cents	10.000	10.000	40.000	40.000
pence	7.443	7.931	30.979	29.418
Dividends paid per ADS (cents)	60.00	60.00	240.00	240.00
Scrip dividends
Number of shares issued (millions)	53.3	129.2	289.8	548.0
Value of shares issued ($ million)	354	710	1,714	2,858

Note 8. Net Debt*



Net debt ratio*	Fourth	Fourth
	quarter	quarter	Year	Year
$ million	2017	2016	2017	2016
Gross debt	63,230	58,300	63,230	58,300
Fair value (asset) liability of hedges related to finance debt_(a)	175	697	175	697
	63,405	58,997	63,405	58,997
Less: cash and cash equivalents	25,586	23,484	25,586	23,484
Net debt	37,819	35,513	37,819	35,513
Equity	100,404	96,843	100,404	96,843
Net debt ratio	27.4%	26.8%	27.4%	26.8%



Analysis of changes in net debt	Fourth		Fourth
	quarter		quarter		Year		Year
$ million	2017		2016		2017		2016
Opening balance
Finance debt	65,784		58,997		58,300		53,168
Fair value (asset) liability of hedges related to finance debt_(a)	(227	)	(1,113	)	697		379
Less: cash and cash equivalents	25,780		25,520		23,484		26,389
Opening net debt	39,777		32,364		35,513		27,158
Closing balance
Finance debt	63,230		58,300		63,230		58,300
Fair value (asset) liability of hedges related to finance debt_(a)	175		697		175		697
Less: cash and cash equivalents	25,586		23,484		25,586		23,484
Closing net debt	37,819		35,513		37,819		35,513
Decrease (increase) in net debt	1,958		(3,149	)	(2,306	)	(8,355	)
Movement in cash and cash equivalents
(excluding exchange adjustments)	(223	)	(1,387	)	1,558		(2,085	)
Net cash outflow (inflow) from financing_(b)	2,753		(1,711	)	(2,278	)	(5,808	)
Other movements	(299	)	(146	)	(564	)	278
Movement in net debt before exchange effects	2,231		(3,244	)	(1,284	)	(7,615	)
Exchange adjustments	(273	)	95		(1,022	)	(740	)
Decrease (increase) in net debt	1,958		(3,149	)	(2,306	)	(8,355	)


^(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 $634 million (fourth quarter 2016 liability of $1,962 million) are not included in the calculation of net debt shown above as hedge accounting is not applied for these instruments.


^(b)	Comprises proceeds and repayments of long-term financing and net (increase) decrease in short-term debt.

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Note 9. Inventory valuation

A provision of $474 million was held at 31 December 2017 ($501 million at 31 December 2016) to write inventories down to their net realizable value. The net movement credited to the income statement during the fourth quarter 2017 was $24 million (fourth quarter 2016 was a charge of $13 million).

Note 10. Statutory accounts

The financial information shown in this publication, which was approved by the Board of Directors on 5 February 2018, 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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Additional information

Capital expenditure*



	Fourth	Fourth
	quarter	quarter	Year	Year
$ million	2017	2016	2017	2016
Capital expenditure on a cash basis
Organic capital expenditure*	4,622	4,473	16,501	16,675
Inorganic capital expenditure*_(a)	199	449	1,339	777
	4,821	4,922	17,840	17,452



	Fourth	Fourth
	quarter	quarter	Year	Year
$ million	2017	2016	2017	2016
Organic capital expenditure by segment
Upstream
US	726	602	2,999	3,415
Non-US	2,819	2,918	10,764	10,929
	3,545	3,520	13,763	14,344
Downstream
US	349	303	809	774
Non-US	598	530	1,590	1,328
	947	833	2,399	2,102
Other businesses and corporate
US	30	25	64	32
Non-US	100	95	275	197
	130	120	339	229
	4,622	4,473	16,501	16,675
Organic capital expenditure by geographical area
US	1,105	930	3,872	4,221
Non-US	3,517	3,543	12,629	12,454
	4,622	4,473	16,501	16,675


^(a)	Full year 2017 includes amounts paid to acquire interests in Mauritania and Senegal and in the Zohr gas field in Egypt.

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Non-operating items*



	Fourth		Fourth
	quarter		quarter		Year		Year
$ million	2017		2016		2017		2016
Upstream
Impairment and gain (loss) on sale of businesses and fixed assets_(a)(b)	(181	)	479		(563	)	2,391
Environmental and other provisions	1		—		1		(8	)
Restructuring, integration and rationalization costs	(4	)	(71	)	(24	)	(373	)
Fair value gain (loss) on embedded derivatives	2		(17	)	33		32
Other_(b)(c)	38		245		(118	)	(289	)
	(144	)	636		(671	)	1,753
Downstream
Impairment and gain (loss) on sale of businesses and fixed assets_(d)	469		72		579		405
Environmental and other provisions	(19	)	2		(19	)	(73	)
Restructuring, integration and rationalization costs	(69	)	(103	)	(171	)	(300	)
Fair value gain (loss) on embedded derivatives	—		—		—		—
Other	1		(48	)	—		(56	)
	382		(77	)	389		(24	)
Rosneft
Impairment and gain (loss) on sale of businesses and fixed assets	—		62		—		62
Environmental and other provisions	—		—		—		—
Restructuring, integration and rationalization costs	—		—		—		—
Fair value gain (loss) on embedded derivatives	—		—		—		—
Other	—		(39	)	—		(39	)
	—		23		—		23
Other businesses and corporate
Impairment and gain (loss) on sale of businesses and fixed assets	(16	)	2		(22	)	—
Environmental and other provisions	(153	)	—		(156	)	(134	)
Restructuring, integration and rationalization costs	(35	)	(21	)	(72	)	(90	)
Fair value gain (loss) on embedded derivatives	—		—		—		—
Gulf of Mexico oil spill_(e)	(2,221	)	(674	)	(2,687	)	(6,640	)
Other	(14	)	—		90		(55	)
	(2,439	)	(693	)	(2,847	)	(6,919	)
Total before interest and taxation	(2,201	)	(111	)	(3,129	)	(5,167	)
Finance costs_(e)	(124	)	(125	)	(493	)	(494	)
Total before taxation	(2,325	)	(236	)	(3,622	)	(5,661	)
Taxation credit (charge) on non-operating items_(f)	669		56		1,172		2,833
Taxation - impact of US tax reform_(g)	(859	)	—		(859	)	—
Total after taxation for period	(2,515	)	(180	)	(3,309	)	(2,828	)

^(a)

Fourth quarter and full year 2017 include an impairment charge relating to the US Lower 48 business, partially offset by gains associated with asset divestments. In addition, full year 2017 includes an impairment charge arising following the announcement of the agreement to sell the Forties Pipeline System business to INEOS. Fourth quarter and full year 2016 principally relate to impairment reversals.


^(b)	Fourth quarter and full year 2016 include a $319-million exploration write-back relating to Block KG D6 in India. In addition, an impairment reversal of $234 million was also recorded in relation to this block.

^(c)

Fourth quarter and full year 2017 include BP’s share of an impairment reversal recognized by the Angola LNG equity-accounted entity, partially offset by other items. Full year 2017 includes the write-off of $145 million in relation to the value ascribed to certain licences in the deepwater Gulf of Mexico as part of the accounting for the acquisition of upstream assets from Devon Energy in 2011. Full year 2016 includes the write-off of $334 million in relation to the value ascribed to the licence in Brazil as part of the accounting for the acquisition of upstream assets from Devon Energy in 2011.


^(d)	Fourth quarter and full year 2017 gain primarily reflects the disposal of our shareholding in the SECCO joint venture.


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


^(f)	Fourth quarter and full year 2017 include the tax effect of the increase in the provision in the fourth quarter for business economic loss and other claims associated with the Deepwater Horizon Court Supervised Settlement Program (DHCSSP) at the new US tax rate.

^(g)

Fourth quarter and full year 2017 include the impact of US tax reform, which reduced the US federal corporate income tax rate from 35% to 21% effective from 1 January 2018. The impact disclosed has been calculated as the change in deferred tax balances at 31 December 2017, excluding the increase in the provision in the fourth quarter for business economic loss and other claims associated with the DHCSSP, which arises following the reduction in rate. The impact of the US tax reform has been treated as a non-operating item because it is not considered to be part of underlying business operations, has a material impact upon the reported result and is substantially impacted by Gulf of Mexico oil spill charges, which are also treated as non-operating items. Separate disclosure is considered meaningful and relevant to investors.

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Non-GAAP information on fair value accounting effects



	Fourth		Fourth
	quarter		quarter		Year		Year
$ million	2017		2016		2017		2016
Favourable (adverse) impact relative to management’s measure of
performance
Upstream	(151	)	(344	)	27		(637	)
Downstream	(83	)	99		(135	)	(448	)
	(234	)	(245	)	(108	)	(1,085	)
Taxation credit (charge)	59		97		12		329
	(175	)	(148	)	(96	)	(756	)

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.



	Fourth		Fourth
	quarter		quarter		Year		Year
$ million	2017		2016		2017		2016
Upstream
Replacement cost profit before interest and tax adjusted for fair value
accounting effects	2,079		1,036		5,194		1,211
Impact of fair value accounting effects	(151	)	(344	)	27		(637	)
Replacement cost profit before interest and tax	1,928		692		5,221		574
Downstream
Replacement cost profit before interest and tax adjusted for fair value
accounting effects	1,856		800		7,356		5,610
Impact of fair value accounting effects	(83	)	99		(135	)	(448	)
Replacement cost profit before interest and tax	1,773		899		7,221		5,162
Total group
Profit (loss) before interest and tax adjusted for fair value
accounting effects	2,090		1,346		9,582		655
Impact of fair value accounting effects	(234	)	(245	)	(108	)	(1,085	)
Profit (loss) before interest and tax	1,856		1,101		9,474		(430	)

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Readily marketable inventory* (RMI)



	31 December	31 December
$ million	2017	2016
RMI at fair value*	5,661	5,952
Paid-up RMI*	2,688	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 34 for a more detailed definition of RMI. RMI, RMI at fair value, paid-up RMI and unpaid RMI are non-GAAP measures. A reconciliation of total inventory as reported on the group balance sheet to paid-up RMI is provided below.



	31 December		31 December
$ million	2017		2016
Reconciliation of total inventory to paid-up RMI
Inventories as reported on the group balance sheet	19,011		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	(13,929	)	(12,131	)
RMI on an IFRS basis	5,082		5,524
Plus: difference between RMI at fair value and RMI on an IFRS basis	579		428
RMI at fair value	5,661		5,952
Less: unpaid RMI* at fair value	(2,973	)	(3,247	)
Paid-up RMI	2,688		2,705

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



	Fourth		Fourth
	quarter		quarter		Year		Year
Per ordinary share (cents)	2017		2016		2017		2016
Profit for the period	0.14		2.62		17.20		0.61
Inventory holding (gains) losses*, before tax	(4.12	)	(3.17	)	(4.32	)	(8.52	)
Taxation charge (credit) on inventory holding gains and losses	1.04		0.93		1.14		2.58
Replacement cost (RC) profit (loss)*	(2.94	)	0.38		14.02		(5.33	)
Net (favourable) unfavourable impact of non-operating items* and fair value
accounting effects*, before tax	12.92		2.54		18.94		35.99
Taxation charge (credit) on non-operating items and fair value accounting effects	0.66		(0.81	)	(1.65	)	(16.87	)
Underlying RC profit*	10.64		2.11		31.31		13.79

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



Taxation (charge) credit
	Fourth		Fourth
	quarter		quarter		Year		Year
$ million	2017		2016		2017		2016
Taxation on profit or loss	(1,119	)	(74	)	(3,712	)	2,467
Taxation on inventory holding gains and losses	(206	)	(176	)	(225	)	(483	)
Taxation on a replacement cost (RC) profit or loss basis	(913	)	102		(3,487	)	2,950
Taxation on non-operating items and fair value accounting effects	(131	)	153		325		3,162
Adjusted for the impact of the reduction in the rate of the UK North Sea
supplementary charge	—		—		—		434
Adjusted taxation	(782	)	(51	)	(3,812	)	(646	)



Effective tax rate
	Fourth		Fourth
	quarter		quarter		Year		Year
%	2017		2016		2017		2016
ETR on profit or loss	95		12		52		107
Adjusted for inventory holding gains or losses	154		(650	)	3		(31	)
ETR on RC profit or loss*	249		(638	)	55		76
Adjusted for non-operating items and fair value accounting effects	(222	)	648		(17	)	(69	)
Adjusted for the impact of the reduction in the rate of the UK North Sea
supplementary charge	—		—		—		16
Adjusted ETR*	27		10		38		23

Return on average capital employed (ROACE)




	Year		Year
$ million	2017		2016
Profit for the year attributable to BP shareholders	3,389		115
Inventory holding (gains) losses, net of tax	(628	)	(1,114	)
Non-operating items and fair value accounting effects, after taxation	3,405		3,584
Underlying replacement cost (RC) profit	6,166		2,585
Interest expense, net of tax_(a)	924		635
Non-controlling interests	79		57
Adjusted underlying RC profit	7,169		3,277
Total equity	100,404		96,843
Gross debt	63,230		58,300
Capital employed (2017 average $159,389 million)	163,634		155,143
Less: Goodwill	11,551		11,194
Cash and cash equivalents	25,586		23,484
	126,497		120,465
Average capital employed (excluding goodwill and cash and cash equivalents)	123,481		117,002
ROACE	5.8	%	2.8	%


^(a)	Pre-tax finance costs for the year were $2,074 million (2016 $1,675 million) including interest expense of $1,421 million (2016 $977 million) and unwinding of the discount on provisions and other payables of $653 million (2016 $698 million). Interest expense included above is calculated on a post tax basis using a notional tax rate of 35%.

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Realizations* and marker prices



	Fourth	Fourth
	quarter	quarter	Year	Year
	2017	2016	2017	2016
Average realizations_(a)
Liquids* ($/bbl)
US	51.50	41.93	46.55	36.25
Europe	57.92	45.66	52.13	40.53
Rest of World_(b)	59.09	45.27	51.83	39.29
BP Average_(b)	56.16	43.89	49.92	38.27
Natural gas ($/mcf)
US	2.28	2.29	2.36	1.90
Europe	5.56	4.81	5.09	4.40
Rest of World	3.51	3.35	3.45	3.19
BP Average	3.23	3.08	3.19	2.84
Total hydrocarbons* ($/boe)
US	35.75	30.32	33.47	25.76
Europe	52.17	40.48	46.09	36.31
Rest of World_(b)	37.27	30.98	35.44	28.62
BP Average_(b)	37.48	31.40	35.38	28.24
Average oil marker prices ($/bbl)
Brent	61.26	49.33	54.19	43.73
West Texas Intermediate	55.23	49.23	50.79	43.34
Western Canadian Select	38.74	35.44	38.55	30.78
Alaska North Slope	61.31	50.06	54.43	43.67
Mars	57.70	46.23	50.65	40.14
Urals (NWE - cif)	60.17	47.73	52.84	41.68
Average natural gas marker prices
Henry Hub gas price_(c)($/mmBtu)	2.93	2.98	3.11	2.46
UK Gas - National Balancing Point (p/therm)	51.94	45.76	44.95	34.63


^(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 fourth quarter and full year 2016. There is no impact on the financial results.


^(c)	Henry Hub First of Month Index.

Exchange rates



	Fourth	Fourth
	quarter	quarter	Year	Year
	2017	2016	2017	2016
$/£ average rate for the period	1.33	1.24	1.29	1.35
$/£ period-end rate	1.34	1.22	1.34	1.22

$/€ average rate for the period	1.18	1.08	1.13	1.11
$/€ period-end rate	1.19	1.05	1.19	1.05

Rouble/$ average rate for the period	58.46	63.12	58.36	67.06
Rouble/$ period-end rate	57.60	60.63	57.60	60.63

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Legal proceedings

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

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

Plaintiffs’ Steering Committee (PSC) settlements - Economic and Property Damages Settlement Agreement The Economic and Property Damages Settlement established a court-supervised settlement programme (CSSP) 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. In May to July 2017, the district court issued a series of orders instructing the CSSP on how to implement the Fifth Circuit’s opinion. On 10 August 2017, the district court denied BP’s motion to clarify or reconsider these orders. BP appealed all of these orders and decisions on 8 September 2017; the appeals have been consolidated with four appeals filed by claimants in early to mid-September 2017 challenging the same set of orders and decisions, albeit raising different issues than are raised by BP’s appeal. These appeals are currently pending before the Fifth Circuit.

As a result of significantly higher average claims determinations issued by the CSSP in the period and the continuing effect of the May 2017 Fifth Circuit opinion, the provision for the costs associated with the 2012 PSC settlement was increased in the fourth quarter of 2017. The amounts ultimately payable may differ from the amount provided and the timing of payments is uncertain. See Note 2 on page 19 for further details.

Other civil complaints Following numerous court decisions, on 11 January 2018, the United States district court in New Orleans issued an order requiring all remaining private plaintiffs with economic loss or property damage claims outside of the CSSP to file by 11 April 2018 a verified sworn statement regarding the actual damages each such plaintiff seeks in its pending litigation and an explanation of how those alleged damages were causally related to the Incident.

Non-US government lawsuits On 3 December 2015 and 29 March 2016, Acciones Colectivas de Sinaloa filed two class actions (which have since been consolidated) in a Mexican Federal District Court on behalf of several Mexican states against BP Exploration & Production Inc., BP America Production Company (BPAPC), and other purported BP subsidiaries. In these class actions, plaintiffs seek an order requiring the BP defendants to repair the damage to the Gulf of Mexico, to pay penalties, and to compensate plaintiffs for damage to property, to health and for economic loss. BP was formally served with the action on 8 December 2017.

Other legal proceedings

California False Claims Act matters On 4 November 2014, the California Attorney General filed a notice in California state court that it was intervening in a previously-sealed California False Claims Act (CFCA) lawsuit filed by relator Christopher Schroen against BP, BP Energy Company, BP Corporation North America Inc., BP Products and BPAPC. On 7 January 2015, the California Attorney General filed a complaint in intervention alleging that BP violated the CFCA and the California Unfair Competition Law by falsely and fraudulently overcharging California state entities for natural gas and making similar allegations in addition to individual claims. In January 2018 the parties reached a settlement pursuant to which BP, while denying liability, agreed to pay $102 million to the state of California.

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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 by underlying RC profit or loss before tax. Taxation on an underlying RC basis is taxation on a RC basis for the period adjusted for taxation on non-operating items and fair value accounting effects. For the 2016 calculation, taxation on an underlying RC basis also reflects an adjustment to eliminate a $434-million credit that arises from the reduction in the rate of the North Sea supplementary charge in the third quarter of 2016. Information on underlying RC profit or loss is provided below. BP believes it is helpful to disclose the adjusted ETR because this measure may help investors to understand and evaluate, in the same manner as management, the underlying trends in BP’s operational performance on a comparable basis, period on period. The nearest equivalent measure on an IFRS basis is the ETR on profit or loss for the period. A reconciliation to GAAP information is provided on page 31.

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

BP-operated Upstream plant reliability is calculated taking 100% less the ratio of total unplanned plant deferrals divided by installed production capacity. Unplanned plant deferrals are associated with the topside plant and where applicable the subsea equipment (excluding wells and reservoir). Unplanned plant deferrals include breakdowns, which does not include weather related downtime.

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 31.

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 29 .

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 27.

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

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

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

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Glossary (continued)

Net debt and net debt ratio are non-GAAP measures. Net debt is calculated as gross finance debt, as shown in the balance sheet, plus the fair value of associated derivative financial instruments that are used to hedge foreign currency exchange and interest rate risks relating to finance debt, for which hedge accounting is applied, less cash and cash equivalents. The net debt ratio is defined as the ratio of net debt to the total of net debt plus shareholders’ equity. All components of equity are included in the denominator of the calculation. BP believes these measures provide useful information to investors. Net debt enables investors to see the economic effect of gross debt, related hedges and cash and cash equivalents in total. The net debt ratio enables investors to see how significant net debt is relative to equity from shareholders. The derivatives are reported on the balance sheet within the headings ‘Derivative financial instruments’. The nearest equivalent GAAP measures are gross debt and gross debt ratio. A reconciliation of gross debt to net debt is provided on page 25.

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

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 28.

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 / expenditure or Underlying operating cash flow is a non-GAAP measure calculated by excluding post-tax operating cash flows relating to the Gulf of Mexico oil spill as reported in Note 2 from Net cash provided by operating activities as reported in the condensed group cash flow statement. The nearest equivalent measure on an IFRS basis is Net cash provided by operating activities.

Operating cash margin is operating cash flow divided by the applicable number of barrels of oil equivalent produced, at $52/bbl flat oil prices. Expected operating cash margins are calculated over the period 2016-2025.

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 27.

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) / Production-sharing contract 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, RMI at fair value, Paid-up RMI and Unpaid RMI are non-GAAP measures. Further information is provided on page 30.

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

Refining availability represents Solomon Associates’ operational availability, which is defined as the percentage of the year that a unit is available for processing after subtracting the annualized time lost due to turnaround activity and all planned mechanical, process and regulatory downtime.

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

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Glossary (continued)

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

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 30.

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

Reserves replacement ratio is the extent to which production is replaced by proved reserves additions. This ratio is expressed in oil equivalent terms and includes changes resulting from revisions to previous estimates, improved recovery, and extensions and discoveries.

Return on average capital employed (ROACE) is a non-GAAP measure and is underlying replacement cost profit, after adding back non-controlling interest and interest expense net of notional tax at an assumed 35%, divided by average capital employed, excluding cash and cash equivalents and goodwill. Interest expense is finance cost excluding the unwinding of the discount on provisions and other payables, and for full year 2017 interest expense was $1,421 million before tax. BP believes it is helpful to disclose the ROACE because this measure gives an indication of the company’s capital efficiency. The nearest GAAP measures of the numerator and denominator are profit or loss for the period attributable to BP shareholders and average capital employed respectively. A reconciliation of the numerator and denominator is provided on page 31.

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 28 and 29 for additional information on the non-operating items and fair value accounting effects that are used to arrive at underlying RC profit or loss in order to enable a full understanding of the events and their financial impact. BP believes that underlying RC profit or loss is a useful measure for investors because it is a measure closely tracked by management to evaluate BP’s operating performance and to make financial, strategic and operating decisions and because it may help investors to understand and evaluate, in the same manner as management, the underlying trends in BP’s operational performance on a comparable basis, period on period, by adjusting for the effects of these non-operating items and fair value accounting effects. The nearest equivalent measure on an IFRS basis for the group is profit or loss attributable to BP shareholders. The nearest equivalent measure on an IFRS basis for segments is RC profit or loss before interest and taxation. Underlying profit in the highlights on page 3 refers to full year underlying RC profit for the group. A reconciliation to GAAP information is provided on page 3 .

Underlying RC profit or loss per share is a non-GAAP measure. Earnings per share is defined in Note 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 30.

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

Upstream 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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Cautionary statement

In order to utilize the ‘safe harbor’ provisions of the United States Private Securities Litigation Reform Act of 1995 (the ‘PSLRA’), BP is providing the following cautionary statement: The discussion in this results announcement contains certain forecasts, projections and forward-looking statements - that is, statements related to future, not past events - with respect to the financial condition, results of operations and businesses of BP and certain of the plans and objectives of BP with respect to these items. These statements may generally, but not always, be identified by the use of words such as ‘will’, ‘expects’, ‘is expected to’, ‘aims’, ‘should’, ‘may’, ‘objective’, ‘is likely to’, ‘intends’, ‘believes’, ‘anticipates’, ‘plans’, ‘we see’ or similar expressions. In particular, the following, among other statements, are all forward looking in nature: expectations regarding the expected quarterly dividend payment and timing of such payment; plans and expectations regarding cash flows and returns to 2021 and beyond; expectations regarding 2018 organic capital expenditure and depreciation, depletion and amortization charges; plans and expectations with respect to gearing including to target gearing within a 20-30% band; plans and expectations to target a net debt ratio of 20-30%; expectations regarding divestment transactions and the amount and timing of divestment proceeds; expectations regarding the adjusted effective tax rate in 2018; plans and expectations regarding the continuation of the share buyback programme; expectations regarding Upstream 2018 underlying production and first-quarter 2018 reported production; expectations regarding Downstream first-quarter 2018 refining margins, turnaround activity and discounts for North American heavy crude oil; expectations regarding Other businesses and corporate 2018 average quarterly charges; expectations with respect to cash margins of 2016 and 2017 Upstream project start-ups; plans and expectations regarding the joint development agreement with Rosneft with respect to subsoil resources within the Kharampurskoe and Festivalnoye licence areas; plans and expectations regarding the joint ventures with Shandong Dongming Petrochemical Group; plans and expectations regarding the strategic partnership with Lightsource; expectations regarding the determination of business economic loss claims in respect of the 2012 PSC settlement; and expectations with respect to the timing and amount of future payments relating to the Gulf of Mexico oil spill including 2012 PSC settlement payments. By their nature, forward-looking statements involve risk and uncertainty because they relate to events and depend on circumstances that will or may occur in the future and are outside the control of BP. Actual results may differ materially from those expressed in such statements, depending on a variety of factors, including: the specific factors identified in the discussions accompanying such forward-looking statements; the receipt of relevant third party and/or regulatory approvals; the timing and level of maintenance and/or turnaround activity; the timing and volume of refinery additions and outages; the timing of bringing new fields onstream; the timing, quantum and nature of certain divestments; future levels of industry product supply, demand and pricing, including supply growth in North America; OPEC quota restrictions; PSA effects; operational and safety problems; potential lapses in product quality; economic and financial market conditions generally or in various countries and regions; political stability and economic growth in relevant areas of the world; changes in laws and governmental regulations; regulatory or legal actions including the types of enforcement action pursued and the nature of remedies sought or imposed; the actions of prosecutors, regulatory authorities and courts; delays in the processes for resolving claims; amounts ultimately payable and timing of payments relating to the Gulf of Mexico oil spill; exchange rate fluctuations; development and use of new technology; recruitment and retention of a skilled workforce; the success or otherwise of partnering; the actions of competitors, trading partners, contractors, subcontractors, creditors, rating agencies and others; our access to future credit resources; business disruption and crisis management; the impact on our reputation of ethical misconduct and non-compliance with regulatory obligations; trading losses; major uninsured losses; decisions by Rosneft’s management and board of directors; the actions of contractors; natural disasters and adverse weather conditions; changes in public expectations and other changes to business conditions; wars and acts of terrorism; cyber-attacks or sabotage; and other factors discussed elsewhere in this report, under “Principal risks and uncertainties” in our Form 6-K for the period ended 30 June 2017 and under “Risk factors” in BP Annual Report and Form 20-F 2016 as filed with the US Securities and Exchange Commission.

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Computation of ratio of earnings to fixed charges




	Year
	2017
$ million except ratio

Earnings available for fixed charges:
Pre-tax profit from continuing operations before adjustment for income or loss from joint ventures and associates	4,673
Fixed charges	2,960
Amortization of capitalized interest	219
Distributed income of joint ventures and associates	1,253
Interest capitalized	(297	)
Preference dividend requirements, gross of tax	(3	)
Non-controlling interest of subsidiaries’ income not incurring fixed charges	(14	)
Total earnings available for fixed charges	8,791

Fixed charges:
Interest expensed	1,421
Interest capitalized	297
Rental expense representative of interest	1,239
Preference dividend requirements, gross of tax	3
Total fixed charges	2,960

Ratio of earnings to fixed charges	2.97

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The following table shows the unaudited consolidated capitalization and indebtedness of the BP group as of 31 December 2017 in

accordance with IFRS:

Capitalization and indebtedness



	31 December
$ million	2017
Share capital and reserves
Capital shares (1-2)	5,343
Paid-in surplus (3)	13,573
Merger reserve (3)	27,206
Treasury shares	(16,958	)
Available-for-sale investments	17
Cash flow hedge reserve	(760	)
Foreign currency translation reserve	(5,156	)
Profit and loss account	75,226
BP shareholders' equity	98,491

Finance debt (4-6)
Due within one year	7,739
Due after more than one year	55,491
Total finance debt	63,230
Total capitalization (7)	161,721

Issued share capital as of 31 December 2017 comprised 19,815,850,568 ordinary shares, par value US$0.25 per share, and 12,706,252 preference shares, par value £1 per share. This excludes 1,472,342,503 ordinary shares which have been bought back and are held in treasury by BP. These shares are not taken into consideration in relation to the payment of dividends and voting at shareholders’ meetings.


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


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

shareholders.


4.	Finance debt recorded in currencies other than US dollars has been translated into US dollars at the relevant exchange rates existing on 31 December 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 31 December 2017, the parent company, BP p.l.c., had issued guarantees totalling $60,665 million relating to finance debt of subsidiaries. Thus 96% of the group’s finance debt had been guaranteed by BP p.l.c.

At 31 December 2017, $151 million of finance debt was secured by the pledging of assets. The remainder of finance debt was unsecured.


7.	At 31 December 2017 the group had issued third-party guarantees under which amounts outstanding, incremental to amounts recognized on the group balance sheet, were $645 million in respect of the borrowings of equity-accounted entities and $350 million in respect of the borrowings of other third parties.


8.	There has been no material change since 31 December 2017 in the consolidated capitalization and indebtedness of BP.

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Signatures

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

BP p.l.c.

(Registrant)



Dated:	6 February 2018	/s/ David J Jackson
		David J Jackson
		Company Secretary