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 2018

Commission File Number 1-06262

BP p.l.c.

(Translation of registrant’s name into English)

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

(Address of principal executive offices)

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




	Form 20-F x Form 40-F ¨

Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(1): ¨
Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(7): ¨

THIS REPORT ON FORM 6-K SHALL BE DEEMED TO BE INCORPORATED BY REFERENCE IN THE PROSPECTUS INCLUDED IN THE REGISTRATION STATEMENT ON FORM F-3 (FILE NOS. 333-226485, 333-226485-01 AND 333-226485-02) OF BP p.l.c., BP CAPITAL MARKETS p.l.c. AND BP CAPITAL MARKETS AMERICA INC.; 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 2018_(a)



		Page
1.	Management’s Discussion and Analysis of Financial Condition and Results of Operations for the period January-December 2018(b)	3-13, 29-35, 36-39

2.	Consolidated Financial Statements including Notes to Consolidated Financial Statements for the period January-December 2018	14-28

3.	Legal proceedings	36

4.	Cautionary statement	39

5.	Capitalization and Indebtedness	40

6.	Recent credit ratings update	41

7.	Signatures	41


(a)	In this Form 6-K, references to the full year 2018 and full year 2017 refer to full year periods ended 31 December 2018 and 31 December 2017 respectively. References to the fourth quarter 2018 and fourth quarter 2017 refer to the three-month periods ended 31 December 2018 and 31 December 2017 respectively.


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

Table of contents

Group results fourth quarter and full year 2018



Highlights	Building business momentum, growing earnings and returns

• More than double full-year earnings, near double returns


–	Profit for the fourth quarter and full year was $766 million and $9,383 million respectively, compared with $27 million and $3,389 million for the same periods in 2017. Underlying replacement cost profit for full year 2018 was $12.7 billion, more than double that reported for 2017. The fourth quarter result was $3.5 billion, driven by the strong operating performance across all business segments.


–	Return on average capital employed_(a) was 11.2% compared to 5.8% in 2017.


–	Operating cash flow for the full year 2018 was $22.9 billion including the impact of Gulf of Mexico oil spill payments. This compares with $18.9 billion for 2017_(b).


–	Gulf of Mexico oil spill payments in 2018 totalled $3.2 billion on a post-tax basis.


–	Total divestments and other proceeds in 2018 were $3.5 billion. BP intends to complete more than $10 billion divestments over the next two years, which includes plans announced following the BHP transaction.


–	Dividend of 10.25 cents a share announced for the fourth quarter, 2.5% higher than a year earlier.


•	Record Upstream reliability, record refining throughput


–	Operational reliability was very strong in 2018 for both main business segments.


–	For the year, BP-operated Upstream plant reliability was a record 96%, and Downstream delivered refining availability of 95% and record refining throughput.


–	Reported oil and gas production averaged 3.7 million barrels of oil equivalent a day for 2018. Upstream underlying production, which excludes Rosneft, was 8.2% higher than 2017.


•	Growing the business, advancing the energy transition


–	Six Upstream major projects started up in 2018, making a total of 19 brought online since 2016.


–	Reserves replacement ratio (RRR) for 2018, including Rosneft, is 100%_(c). Including acquisitions and disposals, RRR is 209%, primarily reflecting the BHP transaction.


–	Fuels marketing continued to grow, with over 25% more convenience partnership sites, as well as further retail expansion in Mexico.


–	BP set out its approach to advancing the energy transition in 2018, introducing its ‘reduce-improve-create’ framework and setting clear targets for operational greenhouse gas emissions, towards which it is already making significant progress.


–	BP acquired UK electric vehicle charging company Chargemaster and Lightsource BP saw important expansion internationally.


_(a)	The nearest equivalent GAAP measures of the numerator and denominator are profit for the period and average capital employed respectively (see below).


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


_(c)	On a combined basis of subsidiaries and equity-accounted entities.



Financial summary	Fourth		Fourth
Financial summary	quarter		quarter		Year		Year
$ million	2018		2017		2018		2017
Profit for the period_(a)	766		27		9,383		3,389
Inventory holding (gains) losses, before tax	2,574		(816	)	801		(853	)
Taxation charge (credit) on inventory holding gains and losses	(623	)	206		(198	)	225
RC profit (loss)	2,717		(583	)	9,986		2,761
Net (favourable) adverse impact of non-operating items and fair value accounting effects, before tax	668		2,559		3,380		3,730
Taxation charge (credit) on non-operating items and fair value accounting effects	92		131		(643	)	(325	)
Underlying RC profit	3,477		2,107		12,723		6,166
Profit per ordinary share (cents)	3.83		0.14		46.98		17.20
Profit per ADS (dollars)	0.23		0.01		2.82		1.03
RC profit per ordinary share (cents)	13.58		(2.94	)	50.00		14.02
RC profit per ADS (dollars)	0.81		(0.18	)	3.00		0.84
Underlying RC profit per ordinary share (cents)	17.38		10.64		63.70		31.31
Underlying RC profit per ADS (dollars)	1.04		0.64		3.82		1.88
Average capital employed ($ billion)					165.5		159.4


(a)	Profit attributable to BP shareholders.

RC profit (loss), underlying RC profit and return on average capital employed are non-GAAP measures. These measures and Upstream plant reliability, refining availability, major projects, inventory holding gains and losses, non-operating items, fair value accounting effects, underlying production and reserves replacement ratio are defined in the Glossary on page 36.

The commentary above and following should be read in conjunction with the cautionary statement on page 39.

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Group headlines

Results

BP’s profit for the fourth quarter and full year was $766 million and $9,383 million respectively, compared with $27 million and $3,389 million for the same periods in 2017.

For the full year, replacement cost (RC) profit* was $9,986 million, compared with $2,761 million in 2017. Underlying RC profit* was $12,723 million, compared with $6,166 million in 2017. Underlying RC profit is after adjusting RC profit for a net charge for non-operating items* of $2,805 million and net favourable fair value accounting effects* of $68 million (both on a post-tax basis).

For the fourth quarter, RC profit was $2,717 million, compared with a loss of $583 million in 2017. Underlying RC profit was $3,477 million compared with $2,107 million for the same period in 2017. Underlying RC profit is after adjusting RC profit for a net charge for non-operating items of $1,186 million and net favourable fair value accounting effects of $426 million (both on a post-tax basis).

See further information on pages 5, 30 and 31.

Depreciation, depletion and amortization

The charge for depreciation, depletion and amortization was $15.5 billion in 2018, compared with $15.6 billion in 2017. In 2019, we expect the charge to be in line with 2018.

Non-operating items

Non-operating items amounted to a post-tax charge of $1,186 million for the quarter and $2,805 million for the full year. The charge for the quarter includes the impact of the annual update of environmental provisions, changes to non-Gulf of Mexico oil spill related legal provisions, as well as further restructuring costs. The group restructuring programme originally announced in 2014 has now been completed. See further information on page 30.

Effective tax rate

The effective tax rate (ETR) on the profit for the fourth quarter and full year was 68% and 43% respectively, compared with 95% and 52% for the same periods in 2017.

The ETR on RC profit or loss* for the fourth quarter and full year was 45% and 42% respectively. The ETR for both periods in 2017 was significantly impacted by the effect of non-operating items and therefore was not a meaningful measure.

Adjusting for non-operating items and fair value accounting effects, the underlying ETR* for the fourth quarter and full year was 38% for both periods, compared with 27% and 38% for the same periods in 2017. The higher underlying ETR for the fourth quarter reflects the reassessment of the recognition of deferred tax assets, partly offset by changes in the geographical mix of profits. In the current environment the underlying ETR for 2019 is expected to be around 40%. ETR on RC profit or loss and underlying ETR are non-GAAP measures.

Dividend

BP today announced a quarterly dividend of 10.25 cents per ordinary share ($0.615 per ADS), which is expected to be paid on 29 March 2019. The corresponding amount in sterling will be announced on 18 March 2019. See page 27 for further information.

Share buybacks

BP repurchased 2 million ordinary shares at a cost of $16 million, including fees and stamp duty, during the fourth quarter of 2018. For the full year, BP repurchased 50 million ordinary shares at a cost of $355 million, including fees and stamp duty. We expect to continue our share buyback programme, and to fully offset the impact of scrip dilution since the third quarter of 2017 by the end of 2019.

Operating cash flow*

Operating cash flow was $6.8 billion in the fourth quarter and $22.9 billion in the full year including the impact of Gulf of Mexico oil spill payments of $0.3 billion and $3.2 billion respectively. These compare with $5.9 billion for the fourth quarter of 2017 and $18.9 billion for the full year of 2017.

Capital expenditure*

Total capital expenditure for the fourth quarter and full year was $12.9 billion and $25.1 billion respectively, compared with $4.8 billion and $17.8 billion for the same periods in 2017.

Organic capital expenditure* for the fourth quarter and full year was $4.4 billion and $15.1 billion respectively, compared with $4.6 billion and $16.5 billion for the same periods in 2017.

Inorganic capital expenditure* for the fourth quarter and full year was $8.5 billion and $9.9 billion respectively, including $6.7 billion relating to the BHP acquisition (see Note 3), compared with $0.2 billion and $1.3 billion for the same periods in 2017.

Organic capital expenditure and inorganic capital expenditure are non-GAAP measures. See page 29 for further information.

Divestment and other proceeds

Total divestment and other proceeds for the year were $3.5 billion, compared with $4.3 billion a year ago, and includes $0.6 billion loan repayment to BP relating to the refinancing of Trans Adriatic Pipeline AG in the fourth quarter. Divestment proceeds* were $2.4 billion for the fourth quarter and $2.9 billion for the full year, compared with $2.5 billion and $3.4 billion for the same periods in 2017.

Debt

Gross debt at 31 December 2018 was $65.8 billion compared with $63.2 billion a year ago. Gross debt ratio* at 31 December 2018 was 39.3%, compared with 38.6% a year ago.

Net debt* at 31 December 2018 was $44.1 billion, compared with $37.8 billion a year ago. Gearing* or net debt ratio* at 31 December 2018 was 30.3%, compared with 27.4% a year ago.

Net debt, net debt ratio and gearing are non-GAAP measures. See page 27 for more information.

Reserves replacement ratio*

The organic reserves replacement ratio on a combined basis of subsidiaries and equity-accounted entities was 100% for the year. Including acquisitions and divestments, such as the BHP transaction and investment in LLC Kharampurneftegaz in Russia, the total reserves replacement ratio was 209%.

* For items marked with an asterisk throughout this document, definitions are provided in the Glossary on page 36.

The commentary above contains forward-looking statements and should be read in conjunction with the cautionary statement on page 39.

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Analysis of underlying RC profit* before interest and tax



	Fourth		Fourth
	quarter		quarter		Year		Year
$ million	2018		2017		2018		2017
Underlying RC profit before interest and tax
Upstream	3,886		2,223		14,550		5,865
Downstream	2,169		1,474		7,561		6,967
Rosneft	431		321		2,316		836
Other businesses and corporate	(344	)	(394	)	(1,558	)	(1,598	)
Consolidation adjustment – UPII*	142		(149	)	211		(212	)
Underlying RC profit before interest and tax	6,284		3,475		23,080		11,858
Finance costs and net finance expense relating to pensions and other post-retirement benefits	(654	)	(550	)	(2,176	)	(1,801	)
Taxation on an underlying RC basis	(2,148	)	(782	)	(7,986	)	(3,812	)
Non-controlling interests	(5	)	(36	)	(195	)	(79	)
Underlying RC profit attributable to BP shareholders	3,477		2,107		12,723		6,166

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 for the period



	Fourth		Fourth
	quarter		quarter		Year		Year
$ million	2018		2017		2018		2017
RC profit before interest and tax
Upstream	4,168		1,928		14,328		5,221
Downstream	2,138		1,773		6,940		7,221
Rosneft	400		321		2,221		836
Other businesses and corporate_(a)	(1,110	)	(2,833	)	(3,521	)	(4,445	)
Consolidation adjustment – UPII	142		(149	)	211		(212	)
RC profit before interest and tax	5,738		1,040		20,179		8,621
Finance costs and net finance expense relating to pensions and other post-retirement benefits	(776	)	(674	)	(2,655	)	(2,294	)
Taxation on a RC basis	(2,240	)	(913	)	(7,343	)	(3,487	)
Non-controlling interests	(5	)	(36	)	(195	)	(79	)
RC profit (loss) attributable to BP shareholders	2,717		(583	)	9,986		2,761
Inventory holding gains (losses)*	(2,574	)	816		(801	)	853
Taxation (charge) credit on inventory holding gains and losses	623		(206	)	198		(225	)
Profit for the period attributable to BP shareholders	766		27		9,383		3,389


(a)	Includes costs related to the Gulf of Mexico oil spill. See page 13 and also Note 2 on page 21 for further information on the accounting for the Gulf of Mexico oil spill.

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Strategic progress

Upstream

2018 Upstream production, which excludes Rosneft, was 3% higher than in 2017, the highest since 2010. Adjusted for portfolio changes and PSA* impacts, underlying production* was 8.2% higher than 2017 due to major project* ramp-ups and improved plant reliability*. Upstream production for the fourth quarter was 2,627mboe/d, 1.8% higher than a year earlier. Upstream unit production costs* for 2018 were higher than 2017 due to increased wellwork* activity and the impact of higher prices on production entitlements.

The Clair Ridge project, west of Shetland in the North Sea, was the sixth Upstream major project to come onstream in 2018, following earlier start-ups in Egypt, Russia, Azerbaijan, the Gulf of Mexico and Australia. BP has brought 19 new major projects online over 2016-2018.

Sanction for the first phase of the Greater Tortue Ahmeyim LNG development offshore Mauritania and Senegal and the Cassia Compression and Matapal gas projects in Trinidad were announced in the quarter. In January, BP announced approval of the Atlantis Phase 3 development in the Gulf of Mexico.

Downstream

Strong Downstream performance in 2018, with record earnings in a fourth quarter.

2018 manufacturing performance was strong with Solomon availability* for the year of 95% and record refining throughput on a current portfolio basis.

There was continued growth in marketing, with our convenience partnership model now rolled out to around 1,400 sites across the network, an increase of more than 25% in the year, and BP’s retail network in Mexico reaching 440 sites by year end.

In the quarter, BP and SOCAR announced an agreement to explore the creation of a joint venture to build and operate a new world-scale petrochemicals complex in Turkey.

Advancing the energy transition

Solar development company Lightsource BP (BP 43%) has doubled its global footprint over the past year, with a presence now in 10 countries. Most recently it announced it would enter Brazil. During the fourth quarter, Lightsource BP was awarded power purchase agreements (PPAs) in Australia and in the US. In the UK, it announced an agreement to power AB InBev’s manufacturing plants through an innovative 100MW PPA.

BP made a series of investments in electric vehicle technology and infrastructure during the year that significantly progress its advanced mobility agenda. This included the purchase of Chargemaster, operator of the UK’s largest vehicle charging network, as well as venturing investment into battery company StoreDot.

Financial framework

Operating cash flow* was $22.9 billion for the full year of 2018, including Gulf of Mexico oil spill payments of $3.2 billion for the full year. This compares with $18.9 billion for the full year of 2017.

Organic capital expenditure* for the full year of 2018 was $15.1 billion in the range of $15-16 billion previously indicated. BP expects 2019 organic capital expenditure to be in the range of $15-17 billion.

Divestments and other proceeds totalled $3.5 billion for the full year. BP intends to complete more than $10 billion divestments over the next two years, which includes plans announced following the BHP transaction.

Gulf of Mexico oil spill payments on a post-tax basis totalled $3.2 billion in the full year of 2018. Payments for 2019 are expected to be around $2 billion on a post-tax basis.

Gearing* at the end of the quarter was 30.3%. At current oil prices, and in line with growing free cash flow* supported by divestment proceeds, we expect gearing to move towards the middle of our targeted range of 20-30% in 2020.



Operating metrics	Year 2018	Financial metrics	Year 2018
Operating metrics	(vs. Year 2017)	Financial metrics	(vs. Year 2017)
Tier 1 process safety events*	16	Underlying RC profit*ⁱ	$12.7bn
Tier 1 process safety events*	(-2)	Underlying RC profit*ⁱ	(+$6.6bn)
Reported recordable injury frequency*	0.20	Operating cash flow excluding Gulf of Mexico oil spill payments (post-tax)	_(b)
Reported recordable injury frequency*	(-9%)
Group production	3,683mboe/d	Organic capital expenditureⁱⁱ	$15.1bn
Group production	(+2.4%)	Organic capital expenditureⁱⁱ	(-$1.4bn)
Upstream production (excludes Rosneft segment)	2,539mboe/d	Gulf of Mexico oil spill payments (post-tax)	$3.2bn
Upstream production (excludes Rosneft segment)	(+3.0%)	Gulf of Mexico oil spill payments (post-tax)	(-$1.9bn)
Upstream unit production costs	$7.15/boe	Divestment proceeds*	$2.9bn
Upstream unit production costs	(+0.6%)	Divestment proceeds*	(-$0.6bn)
BP-operated Upstream plant reliability_(a)	95.7%	Net debt ratio* (gearing)ⁱⁱⁱ	30.3%
BP-operated Upstream plant reliability_(a)	(+1.0)	Net debt ratio* (gearing)ⁱⁱⁱ	(+2.9)
Refining availability*	94.9%	Dividend per ordinary share_(c)	10.25 cents
Refining availability*	(-0.4)	Dividend per ordinary share_(c)	(+2.5%)
		Return on average capital employed*_(d)^iv	11.2%
		Return on average capital employed*_(d)^iv	(+5.4)


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

(b)

SEC regulations do not permit inclusion of this non-GAAP metric in this SEC filing. Operating cash flow excluding Gulf of Mexico oil spill payments is calculated by excluding post-tax payments relating to the Gulf of Mexico oil spill from net cash provided by operating activities, as reported in the condensed group cash flow statement. For the full year, net cash provided by operating activities was $22.9 billion and post-tax Gulf of Mexico oil spill payments were $3.2 billion.


(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.

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Nearest GAAP equivalent measures
i	Profit for the period:	$9.4bn
ii	Capital expenditure*:	$25.1bn
iii	Gross debt ratio*:	39.3%
iv	Numerator: Profit attributable to BP shareholders	$9.4bn
	Denominator: Average capital employed	$165.5bn

The commentary above contains forward-looking statements and should be read in conjunction with the cautionary statement on page 39.

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Upstream



	Fourth		Fourth
	quarter		quarter	Year	Year
$ million	2018		2017	2018	2017
Profit before interest and tax	4,156		1,928	14,322	5,229
Inventory holding (gains) losses*	12		—	6	(8	)
RC profit before interest and tax	4,168		1,928	14,328	5,221
Net (favourable) adverse impact of non-operating items* and fair value accounting effects*	(282	)	295	222	644
Underlying RC profit before interest and tax*_(a)	3,886		2,223	14,550	5,865


(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 $4,168 million and $14,328 million respectively, compared with $1,928 million and $5,221 million for the same periods in 2017. The fourth quarter and full year included a net non-operating gain of $136 million and a net charge of $183 million respectively, compared with a net charge of $144 million and $671 million for the same periods in 2017. Fair value accounting effects in the fourth quarter and full year had a favourable impact of $146 million and an adverse impact of $39 million respectively, compared with an adverse impact of $151 million and a favourable impact of $27 million in the same periods of 2017.

After adjusting for non-operating items and fair value accounting effects, the underlying replacement cost profit before interest and tax for the fourth quarter and full year was $3,886 million and $14,550 million respectively, compared with $2,223 million and $5,865 million for the same periods in 2017. The result for the fourth quarter mainly reflected higher liquids and gas realizations, strong gas marketing and trading results and higher production including BHP assets acquired by BPX Energy (previously known as the US Lower 48 business). The result for the full year mainly reflected higher liquids and gas realizations, higher production and lower exploration write-offs.

Production

Production for the quarter was 2,627mboe/d, 1.8% higher than 2017. Underlying production* for the quarter increased by 3.4%, due to major project ramp-ups.

For the full year, production was 2,539mboe/d, 3.0% higher than 2017. Underlying production for the full year was 8.2% higher than 2017 due to major project ramp-ups and improved plant reliability.

Key events

On 31 October, BP completed the acquisition of BHP’s US unconventional oil and gas assets.

On 23 November, BP announced the start-up of the Clair Ridge project. This was the sixth major project to start up in 2018 (BP operator 45.1%, Shell 28%, Chevron 19.4% and ConocoPhillips 7.5%).

On 14 December, BP announced the sanction for two new gas developments offshore Trinidad, Cassia Compression and Matapal.

On 17 December, Sonangol and BP signed an agreement to progress to final investment decision the development of the Platina field in deepwater Block 18, offshore Angola. Sonangol also agreed to extend the production licence for the BP-operated Greater Plutonio project on Block 18 to 2032, subject to government approval, and for Sonangol to assume an equity interest in the block (BP operator 50% and Sonangol Sinopec International Limited 50%).

On 21 December, BP announced final investment decision, subject to regulatory approvals, for Phase 1 of the Greater Tortue Ahmeyim LNG development in Mauritania and Senegal (BP operator 62% in Mauritania and 60% in Senegal).

On 8 January, BP announced sanction of Atlantis Phase 3 development (BP operator 56% and BHP 44%) in US Gulf of Mexico. In addition, two oil discoveries were also announced: Manuel (BP operator 50% and Shell 50%) and Nearly Headless Nick (LLOG operator 26.84%, BP 20.25% and other partners) in the Gulf of Mexico.

On 14 January, BP and Eni signed a heads of agreement with the Ministry of Oil and Gas of the Sultanate of Oman to work jointly towards the award of a new exploration and production-sharing agreement (EPSA) for Block 77 in central Oman (Eni operator 50% and BP 50%).

Outlook

We expect full-year 2019 underlying production to be higher than 2018 due to 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 2019 reported production to be flat with fourth-quarter 2018 with divestments of assets in the North Sea and Alaska and turnaround and maintenance activities mainly in the high margin Gulf of Mexico region, offset by major project start-ups and the benefit of the BHP assets acquired by BPX Energy.

The commentary above contains forward-looking statements and should be read in conjunction with the cautionary statement on page 39.

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Upstream (continued)



	Fourth		Fourth
	quarter		quarter		Year		Year
$ million	2018		2017		2018		2017
Underlying RC profit before interest and tax
US	1,400		629		3,693		1,238
Non-US	2,486		1,594		10,857		4,627
	3,886		2,223		14,550		5,865
Non-operating items
US_(a)(b)	(267	)	(187	)	(590	)	(330	)
Non-US_(c)	403		43		407		(341	)
	136		(144	)	(183	)	(671	)
Fair value accounting effects
US	127		8		(35	)	192
Non-US	19		(159	)	(4	)	(165	)
	146		(151	)	(39	)	27
RC profit before interest and tax
US	1,260		450		3,068		1,100
Non-US	2,908		1,478		11,260		4,121
	4,168		1,928		14,328		5,221
Exploration expense
US_(b)	84		27		509		282
Non-US_(d)	373		494		936		1,798
	457		521		1,445		2,080
Of which: Exploration expenditure written off_(b)(d)	351		372		1,085		1,603
Production (net of royalties)_(e)
Liquids* (mb/d)
US	495		430		445		426
Europe	154		117		142		119
Rest of World	673		796		681		811
	1,321		1,344		1,268		1,356
Of which equity-accounted entities	121		209		129		207
Natural gas (mmcf/d)
US	2,255		1,759		1,900		1,659
Europe	215		186		211		235
Rest of World	5,104		5,231		5,263		4,543
	7,574		7,176		7,374		6,436
Of which equity-accounted entities	454		534		474		547
Total hydrocarbons* (mboe/d)
US	884		734		772		712
Europe	191		150		179		160
Rest of World	1,553		1,698		1,589		1,594
	2,627		2,581		2,539		2,466
Of which equity-accounted entities	200		301		211		302
Average realizations*_(f)
Total liquids_(g) ($/bbl)	61.80		56.16		64.98		49.92
Natural gas ($/mcf)	4.33		3.23		3.92		3.19
Total hydrocarbons($/boe)	42.98		37.48		43.47		35.38


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


(b)	Full year 2018 and full year 2017 include the write-off of $124 million and $145 million respectively in relation to the value ascribed to certain licences in the deepwater Gulf of Mexico as part of the accounting for the acquisition of upstream assets from Devon Energy in 2011. This has been classified within the ‘other’ category of non-operating items.

(c)

Fourth quarter and full year 2018 include an impairment reversal for assets in the North Sea and Angola. 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.


(d)	Full year 2017 predominantly relates to the write-off of exploration well and lease costs in Angola. Full year 2017 also includes the write-off of exploration well costs 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	2018		2017		2018	2017
Profit (loss) before interest and tax	(332	)	2,492		6,078	7,979
Inventory holding (gains) losses*	2,470		(719	)	862	(758	)
RC profit before interest and tax	2,138		1,773		6,940	7,221
Net (favourable) adverse impact of non-operating items* and fair value accounting effects*	31		(299	)	621	(254	)
Underlying RC profit before interest and tax*_(a)	2,169		1,474		7,561	6,967


(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 $2,138 million and $6,940 million respectively, compared with $1,773 million and $7,221 million for the same periods in 2017.

The fourth quarter and full year include a net non-operating charge of $401 million and $716 million respectively, compared with a gain of $382 million and $389 million for the same periods in 2017. Fair value accounting effects had a favourable impact of $370 million in the fourth quarter and $95 million for the full year, compared with an adverse impact of $83 million and $135 million for the same periods in 2017.

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

Fuels

The fuels business reported an underlying replacement cost profit before interest and tax of $1,624 million for the fourth quarter and $5,642 million for the full year, compared with $976 million and $4,872 million for the same periods in 2017.

Strong fuels marketing earnings growth for the quarter and full year reflects the benefits from our strategic improvement programmes, enabling improved margin capture and supply chain optimization. Our convenience partnership model is now in around 1,400 sites across our network, with more than 460 sites in Germany with our REWE to Go offer. We also continue to grow in Mexico, with 440 BP-branded retail sites at year end, and in the quarter we opened our first retail sites in Indonesia.

The higher refining result for the full year reflects increased commercial optimization and strong operations, which in North America allowed us to capture the benefits from higher North American heavy crude oil discounts, net of pipeline capacity apportionment impacts. These factors were partially offset by lower industry refining margins and a higher level of turnaround activity.

In addition, the contribution from supply and trading for the full year was lower than last year, although the result for the quarter was slightly higher than in the previous year.

Lubricants

The lubricants business reported an underlying replacement cost profit before interest and tax of $311 million for the fourth quarter and $1,292 million for the full year, compared with $375 million and $1,479 million for the same periods in 2017. The result for the quarter and full year reflects continued premium brand growth, more than offset by the adverse lag impact of increasing base oil prices, as well as adverse foreign exchange rate movements. Volumes in the fourth quarter were lower due to a planned systems implementation.

Petrochemicals

The petrochemicals business reported an underlying replacement cost profit before interest and tax of $234 million for the fourth quarter and $627 million for the full year, compared with $123 million and $616 million for the same periods in 2017. The result for the quarter and full year reflects an improved margin environment, increased margin optimization and continued strong cost management. The result for the full year was higher than last year despite the divestment of our interest in the SECCO joint venture in 2017 and a higher level of turnaround activity in 2018.

In the quarter we signed a heads of agreement with SOCAR Turkey to evaluate the creation of a joint venture to build and operate the largest integrated PTA, PX and aromatics complex in the western hemisphere.

Outlook

Looking to the first quarter of 2019, we expect significantly lower industry refining margins and narrower North American heavy crude oil discounts.

The commentary above contains forward-looking statements and should be read in conjunction with the cautionary statement on page 39.

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Downstream (continued)



	Fourth		Fourth
	quarter		quarter		Year		Year
$ million	2018		2017		2018		2017
Underlying RC profit before interest and tax - by region
US	995		501		2,818		1,978
Non-US	1,174		973		4,743		4,989
	2,169		1,474		7,561		6,967
Non-operating items
US	(109	)	(25	)	(295	)	(48	)
Non-US_(a)	(292	)	407		(421	)	437
	(401	)	382		(716	)	389
Fair value accounting effects_(b)
US	184		3		(155	)	(29	)
Non-US	186		(86	)	250		(106	)
	370		(83	)	95		(135	)
RC profit before interest and tax
US	1,070		479		2,368		1,901
Non-US	1,068		1,294		4,572		5,320
	2,138		1,773		6,940		7,221
Underlying RC profit before interest and tax - by business_(c)(d)
Fuels	1,624		976		5,642		4,872
Lubricants	311		375		1,292		1,479
Petrochemicals	234		123		627		616
	2,169		1,474		7,561		6,967
Non-operating items and fair value accounting effects_(b)
Fuels	173		(202	)	(381	)	(193	)
Lubricants	(198	)	(14	)	(227	)	(22	)
Petrochemicals	(6	)	515		(13	)	469
	(31	)	299		(621	)	254
RC profit before interest and tax_(c)(d)
Fuels	1,797		774		5,261		4,679
Lubricants	113		361		1,065		1,457
Petrochemicals	228		638		614		1,085
	2,138		1,773		6,940		7,221

BP average refining marker margin (RMM)* ($/bbl)	11.0		14.4		13.1		14.1

Refinery throughputs (mb/d)
US	691		714		703		713
Europe	735		741		781		773
Rest of World	240		243		241		216
	1,666		1,698		1,725		1,702
Refining availability* (%)	95.2		96.1		94.9		95.3

Marketing sales of refined products (mb/d)
US	1,138		1,127		1,141		1,151
Europe	1,053		1,132		1,100		1,140
Rest of World	526		542		495		508
	2,717		2,801		2,736		2,799
Trading/supply sales of refined products	3,199		3,549		3,194		3,149
Total sales volumes of refined products	5,916		6,350		5,930		5,948

Petrochemicals production (kte)
US	672		641		2,235		2,428
Europe	1,037		1,559		4,468		5,462
Rest of World	1,259		1,306		5,154		7,405
	2,968		3,506		11,857		15,295


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


(b)	For Downstream, fair value accounting effects arise solely in the fuels business. See page 31 for further information.


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


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

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Rosneft



	Fourth	Fourth
	quarter	quarter		Year		Year
$ million	2018_(a)	2017		2018_(a)		2017
Profit before interest and tax_(b)(c)	308	418		2,288		923
Inventory holding (gains) losses*	92	(97	)	(67	)	(87	)
RC profit before interest and tax	400	321		2,221		836
Net charge (credit) for non-operating items*	31	—		95		—
Underlying RC profit before interest and tax*	431	321		2,316		836

Financial results

Replacement cost (RC) profit before interest and tax for the fourth quarter and full year was $400 million and $2,221 million respectively, compared with $321 million and $836 million for the same periods in 2017.

After adjusting for non-operating items, the underlying RC profit before interest and tax for the fourth quarter and full year was $431 million and $2,316 million respectively. There were no non-operating items in the fourth quarter or full year of 2017.

Compared with the same periods in 2017, the results for the fourth quarter and full year were primarily affected by higher oil prices and favourable foreign exchange, partially offset by adverse duty lag effects.

In September the extraordinary general meeting adopted a resolution to pay interim dividends for the first half of 2018 of 14.58 Russian roubles per ordinary share. In October BP received a dividend of $420 million, after the deduction of withholding tax.

Key events

In September Rosneft and BP agreed to jointly explore two additional oil and gas licence areas located in the Sakha (Yakutia) republic of the Russian Federation. In December the first closing of the deal was completed with LLC Yermakneftegaz, a 51:49 joint venture between Rosneft and BP, acquiring a subsidiary company from Rosneft. The transfer of licences to the subsidiary, subject to external approvals, is expected in 2019.

In December the re-issue was completed of the Kharampurskoe and Festivalnoe subsoil-use licences to LLC Kharampurneftegaz, in which Rosneft and BP own 51% and 49% interests respectively.

BP’s interests in LLC Yermakneftegaz and LLC Kharampurneftegaz are reported through the Upstream segment.



	Fourth	Fourth
	quarter	quarter	Year	Year
	2018_(a)	2017	2018_(a)	2017
Production (net of royalties) (BP share)
Liquids* (mb/d)	946	899	923	904
Natural gas (mmcf/d)	1,312	1,333	1,285	1,308
Total hydrocarbons* (mboe/d)	1,173	1,129	1,144	1,129


(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 2018. Actual results may differ from these amounts.

(b)

The Rosneft segment result includes equity-accounted earnings arising from BP’s 19.75% shareholding in Rosneft as adjusted for the accounting required under IFRS relating to BP’s purchase of its interest in Rosneft and the amortization of the deferred gain relating to the divestment of BP’s interest in TNK-BP. These adjustments increase the segment's reported profit before interest and tax, as shown in the table above, compared with the amounts reported in Rosneft’s IFRS financial statements.


(c)	BP’s adjusted share of Rosneft’s earnings after Rosneft's own finance costs, taxation and non-controlling interests is included in the BP group income statement within profit before interest and taxation. For each year-to-date period it is calculated by translating the amounts reported in Russian roubles into US dollars using the average exchange rate for the year to date.

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Other businesses and corporate



	Fourth		Fourth
	quarter		quarter		Year		Year
$ million	2018		2017		2018		2017
Profit (loss) before interest and tax
Gulf of Mexico oil spill - business economic loss claims	(26	)	(2,110	)	(344	)	(2,370	)
Gulf of Mexico oil spill - other	(41	)	(111	)	(370	)	(317	)
Other	(1,043	)	(612	)	(2,807	)	(1,758	)
Profit (loss) before interest and tax	(1,110	)	(2,833	)	(3,521	)	(4,445	)
Inventory holding (gains) losses*	—		—		—		—
RC profit (loss) before interest and tax	(1,110	)	(2,833	)	(3,521	)	(4,445	)
Net charge (credit) for non-operating items*
Gulf of Mexico oil spill - business economic loss claims	26		2,110		344		2,370
Gulf of Mexico oil spill - other	41		111		370		317
Other	699		218		1,249		160
Net charge (credit) for non-operating items	766		2,439		1,963		2,847
Underlying RC profit (loss) before interest and tax*	(344	)	(394	)	(1,558	)	(1,598	)
Underlying RC profit (loss) before interest and tax
US	(179	)	(29	)	(615	)	(475	)
Non-US	(165	)	(365	)	(943	)	(1,123	)
	(344	)	(394	)	(1,558	)	(1,598	)
Non-operating items
US	(654	)	(2,381	)	(1,738	)	(2,861	)
Non-US	(112	)	(58	)	(225	)	14
	(766	)	(2,439	)	(1,963	)	(2,847	)
RC profit (loss) before interest and tax
US	(833	)	(2,410	)	(2,353	)	(3,336	)
Non-US	(277	)	(423	)	(1,168	)	(1,109	)
	(1,110	)	(2,833	)	(3,521	)	(4,445	)

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 $1,110 million and $3,521 million respectively, compared with $2,833 million and $4,445 million for the same periods in 2017.

The results included a net non-operating charge of $766 million for the fourth quarter and $1,963 million for the full year, primarily relating to the costs for the Gulf of Mexico oil spill, environmental and other provisions, impairments and restructuring costs, compared with a charge of $2,439 million and $2,847 million for the same periods in 2017. See Note 2 on page 21 for more information on the Gulf of Mexico oil spill.

After adjusting for non-operating items, the underlying replacement cost loss before interest and tax for the fourth quarter and full year was $344 million and $1,558 million respectively, compared with $394 million and $1,598 million for the same periods in 2017.

Alternative Energy

The net ethanol-equivalent production (which includes ethanol and sugar) for the fourth quarter and full year was 144 million litres and 765 million litres respectively, compared with 188 million litres and 776 million litres for the same periods in 2017. In the fourth quarter formal approvals were received for the Opla ethanol logistics JV with Copersucar, which is now established and operating well.

Net wind generation capacity* was 1,001MW at 31 December 2018, compared with 1,432MW at 31 December 2017. BP’s net share of wind generation for the fourth quarter and full year was 933GWh and 3,821GWh respectively, compared with 1,148GWh and 4,004GWh for the same periods in 2017. In 2018 we divested three of our wind facilities in Texas. We intend to focus on optimizing and investing in upgrades to our remaining sites, enabling us to continue to grow a wind energy business that we believe is sustainable for the long term.

In December, BP’s strategic solar partnership with Lightsource BP (BP 43%) reached its first anniversary. In that time, Lightsource BP has doubled its global footprint, with a presence now in 10 countries. Most recently the company announced it would enter Brazil, leveraging BP’s relationships and existing operations to fund, develop and operate solar projects locally. Also during the fourth quarter, Lightsource BP was awarded a 105MW power purchase agreement (PPA) in New South Wales, Australia and PPAs totalling 25MW in California and New Mexico in the US. In the UK, Lightsource BP also announced that it will power AB InBev’s manufacturing plants through an innovative 100MW PPA.

Outlook

In 2019, Other businesses and corporate average quarterly charges, excluding non-operating items, are expected to be around $350 million although this will fluctuate quarter to quarter.

The commentary above contains forward-looking statements and should be read in conjunction with the cautionary statement on page 36.

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Financial statements

Group income statement



	Fourth	Fourth
	quarter	quarter	Year	Year
$ million	2018	2017	2018	2017

Sales and other operating revenues (Note 5)	75,677	67,816	298,756	240,208
Earnings from joint ventures – after interest and tax	236	581	897	1,177
Earnings from associates – after interest and tax	425	526	2,856	1,330
Interest and other income	295	223	773	657
Gains on sale of businesses and fixed assets	252	876	456	1,210
Total revenues and other income	76,885	70,022	303,738	244,582
Purchases	59,019	51,745	229,878	179,716
Production and manufacturing expenses_(a)	6,173	7,759	23,005	24,229
Production and similar taxes (Note 7)	186	511	1,536	1,775
Depreciation, depletion and amortization (Note 6)	3,987	4,045	15,457	15,584
Impairment and losses on sale of businesses and fixed assets	244	604	860	1,216
Exploration expense	457	521	1,445	2,080
Distribution and administration expenses	3,655	2,981	12,179	10,508
Profit (loss) before interest and taxation	3,164	1,856	19,378	9,474
Finance costs_(a)	742	616	2,528	2,074
Net finance expense relating to pensions and other post-retirement benefits	34	58	127	220
Profit (loss) before taxation	2,388	1,182	16,723	7,180
Taxation_(a)	1,617	1,119	7,145	3,712
Profit (loss) for the period	771	63	9,578	3,468
Attributable to
BP shareholders	766	27	9,383	3,389
Non-controlling interests	5	36	195	79
	771	63	9,578	3,468

Earnings per share (Note 8)
Profit (loss) for the period attributable to BP shareholders
Per ordinary share (cents)
Basic	3.83	0.14	46.98	17.20
Diluted	3.80	0.14	46.67	17.10
Per ADS (dollars)
Basic	0.23	0.01	2.82	1.03
Diluted	0.23	0.01	2.80	1.03


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

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Condensed group statement of comprehensive income



	Fourth		Fourth
	quarter		quarter		Year		Year
$ million	2018		2017		2018		2017

Profit (loss) for the period	771		63		9,578		3,468
Other comprehensive income
Items that may be reclassified subsequently to profit or loss
Currency translation differences	(937	)	264		(3,771	)	1,986
Exchange (gains) losses on translation of foreign operations reclassified to gain or loss on sale of businesses and fixed assets	—		(138	)	—		(120	)
Available-for-sale investments	—		11		—		14
Cash flow hedges and costs of hedging	(68	)	50		(192	)	425
Share of items relating to equity-accounted entities, net of tax	200		133		417		564
Income tax relating to items that may be reclassified	33		(16	)	4		(196	)
	(772	)	304		(3,542	)	2,673
Items that will not be reclassified to profit or loss
Remeasurements of the net pension and other post-retirement benefit liability or asset	(651	)	1,599		2,317		3,646
Cash flow hedges that will subsequently be transferred to the balance sheet	(8	)	—		(37	)	—
Income tax relating to items that will not be reclassified	223		(604	)	(718	)	(1,303	)
	(436	)	995		1,562		2,343
Other comprehensive income	(1,208	)	1,299		(1,980	)	5,016
Total comprehensive income	(437	)	1,362		7,598		8,484
Attributable to
BP shareholders	(444	)	1,312		7,444		8,353
Non-controlling interests	7		50		154		131
	(437	)	1,362		7,598		8,484

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Condensed group statement of changes in equity



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

Total comprehensive income	7,444		154		7,598
Dividends	(6,699	)	(170	)	(6,869	)
Cash flow hedges transferred to the balance sheet, net of tax	26		—		26
Repurchase of ordinary share capital	(355	)	—		(355	)
Share-based payments, net of tax	703		—		703
Share of equity-accounted entities’ changes in equity, net of tax	14		—		14
Transactions involving non-controlling interests, net of tax	—		207		207
At 31 December 2018	99,444		2,104		101,548

	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


(a)	See Note 1 for further information.

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Group balance sheet



	31 December	31 December
$ million	2018	2017
Non-current assets
Property, plant and equipment	135,261	129,471
Goodwill	12,204	11,551
Intangible assets	17,284	18,355
Investments in joint ventures	8,647	7,994
Investments in associates	17,673	16,991
Other investments	1,341	1,245
Fixed assets	192,410	185,607
Loans	637	646
Trade and other receivables	1,834	1,434
Derivative financial instruments	5,145	4,110
Prepayments	1,179	1,112
Deferred tax assets	3,706	4,469
Defined benefit pension plan surpluses	5,955	4,169
	210,866	201,547
Current assets
Loans	326	190
Inventories	17,988	19,011
Trade and other receivables	24,478	24,849
Derivative financial instruments	3,846	3,032
Prepayments	963	1,414
Current tax receivable	1,019	761
Other investments	222	125
Cash and cash equivalents	22,468	25,586
	71,310	74,968
Total assets	282,176	276,515
Current liabilities
Trade and other payables	46,265	44,209
Derivative financial instruments	3,308	2,808
Accruals	4,626	4,960
Finance debt	9,373	7,739
Current tax payable	2,101	1,686
Provisions	2,564	3,324
	68,237	64,726
Non-current liabilities
Other payables	13,830	13,889
Derivative financial instruments	5,625	3,761
Accruals	575	505
Finance debt	56,426	55,491
Deferred tax liabilities	9,812	7,982
Provisions	17,732	20,620
Defined benefit pension plan and other post-retirement benefit plan deficits	8,391	9,137
	112,391	111,385
Total liabilities	180,628	176,111
Net assets	101,548	100,404
Equity
BP shareholders’ equity	99,444	98,491
Non-controlling interests	2,104	1,913
Total equity	101,548	100,404

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Condensed group cash flow statement



	Fourth		Fourth
	quarter		quarter		Year		Year
$ million	2018		2017		2018		2017
Operating activities
Profit (loss) before taxation	2,388		1,182		16,723		7,180
Adjustments to reconcile profit (loss) before taxation to net cash provided by operating activities
Depreciation, depletion and amortization and exploration expenditure written off	4,338		4,417		16,542		17,187
Impairment and (gain) loss on sale of businesses and fixed assets	(8	)	(272	)	404		6
Earnings from equity-accounted entities, less dividends received	(30	)	(820	)	(2,218	)	(1,254	)
Net charge for interest and other finance expense, less net interest paid	222		294		607		793
Share-based payments	126		166		690		661
Net operating charge for pensions and other post-retirement benefits, less contributions and benefit payments for unfunded plans	(60	)	(215	)	(386	)	(394	)
Net charge for provisions, less payments	617		2,244		986		2,106
Movements in inventories and other current and non-current assets and liabilities	778		(60	)	(4,763	)	(3,352	)
Income taxes paid	(1,542	)	(1,033	)	(5,712	)	(4,002	)
Net cash provided by operating activities	6,829		5,903		22,873		18,931
Investing activities
Expenditure on property, plant and equipment, intangible and other assets	(5,962	)	(4,422	)	(16,707	)	(16,562	)
Acquisitions, net of cash acquired	(6,379	)	(16	)	(6,986	)	(327	)
Investment in joint ventures	(290	)	(15	)	(382	)	(50	)
Investment in associates	(265	)	(368	)	(1,013	)	(901	)
Total cash capital expenditure	(12,896	)	(4,821	)	(25,088	)	(17,840	)
Proceeds from disposal of fixed assets	660		2,287		940		2,936
Proceeds from disposal of businesses, net of cash disposed	1,758		173		1,911		478
Proceeds from loan repayments	619		8		666		349
Net cash used in investing activities	(9,859	)	(2,353	)	(21,571	)	(14,077	)
Financing activities
Net issue (repurchase) of shares	(16	)	(343	)	(355	)	(343	)
Proceeds from long-term financing	2,118		201		9,038		8,712
Repayments of long-term financing	(1,806	)	(2,657	)	(7,210	)	(6,276	)
Net increase (decrease) in short-term debt	889		(297	)	1,317		(158	)
Net increase (decrease) in non-controlling interests	—		982		—		1,063
Dividends paid - BP shareholders	(1,733	)	(1,627	)	(6,699	)	(6,153	)
- non-controlling interests	(41	)	(32	)	(170	)	(141	)
Net cash provided by (used in) financing activities	(589	)	(3,773	)	(4,079	)	(3,296	)
Currency translation differences relating to cash and cash equivalents	(105	)	29		(330	)	544
Increase (decrease) in cash and cash equivalents	(3,724	)	(194	)	(3,107	)	2,102
Cash and cash equivalents at beginning of period_(a)	26,192		25,780		25,575		23,484
Cash and cash equivalents at end of period	22,468		25,586		22,468		25,586


(a)	See Note 1 for further information.

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Notes

Note 1. Basis of preparation

The results for the interim periods and for the year ended 31 December 2018 are unaudited and, in the opinion of management, include all adjustments necessary for a fair presentation of the results for each period. All such adjustments are of a normal recurring nature. This report should be read in conjunction with the consolidated financial statements and related notes for the year ended 31 December 2017 included in BP Annual Report and Form 20-F 2017.

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

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

New International Financial Reporting Standards adopted

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

IFRS 9 ‘Financial Instruments’

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

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

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

The overall impact on transition to IFRS 9, including the impact upon the group's share of equity-accounted entities, was a reduction of $180 million in net assets, net of tax. This adjustment mainly related to an increase in the credit reserve of financial assets in the scope of IFRS 9's impairment requirements. As permitted by IFRS 9 comparatives were not restated. For certain line items in the balance sheet the closing balance at 31 December 2017 and the opening balance at 1 January 2018 therefore differ (as summarized below). Cash and cash equivalents at the beginning of 2018 in the Condensed group cash flow statement and Note 10 (Net debt) are the 1 January 2018 amounts included in the table below.



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

Net assets	100,404		100,224		(180	)

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Note 1. Basis of preparation (continued)

IFRS 15 ‘Revenue from Contracts with Customers’

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

BP elected to apply the ‘modified retrospective’ approach to transition permitted by IFRS 15 under which comparative financial information is not restated. Certain changes in accounting arising from the implementation of IFRS 15 were identified but the standard did not have a material effect on the group's financial statements as at 1 January 2018 and so no transition adjustment was made. The implementation of the standard has also not had a material effect on the group’s results for the year ended 31 December 2018 compared to those that would have been reported under the group’s previous accounting policy for revenue.

An analysis of revenue from contracts with customers by product is presented in Note 5. Amounts presented for comparative periods in 2017 include revenues determined in accordance with the group's previous accounting policies relating to revenue. The total amounts presented do not, therefore, represent the revenue from contracts with customers that would have been reported for those periods had IFRS 15 been applied using a fully retrospective approach to transition but the differences are not significant.

Change in significant estimate - decommissioning provision

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

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

The nominal discount rate applied to provisions was revised at 31 December 2018 to 3.0%. The impact of this rate increase was a further $1.3 billion reduction in the decommissioning provision, with a similar reduction in the carrying amount of property, plant and equipment.

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

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Note 2. Gulf of Mexico oil spill

(a) Overview

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

The group income statement includes a post-tax charge for the fourth quarter of $20 million relating to business economic loss (BEL) claims and $15 million relating to other claims and litigation. The group income statement also includes finance costs relating to the unwinding of discounting effects relating to payables.

The amounts set out below reflect the impacts on the consolidated 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	2018		2017		2018		2017
Income statement
Production and manufacturing expenses	67		2,221		714		2,687
Profit (loss) before interest and taxation	(67	)	(2,221	)	(714	)	(2,687	)
Finance costs	122		124		479		493
Profit (loss) before taxation	(189	)	(2,345	)	(1,193	)	(3,180	)
Taxation	(8	)	(2,495	)	174		(2,222	)
Profit (loss) for the period	(197	)	(4,840	)	(1,019	)	(5,402	)

The cumulative pre-tax income statement charge since the incident, in April 2010, amounts to $66,958 million.



	31 December		31 December
$ million	2018		2017
Balance sheet
Current assets
Trade and other receivables	214		252
Current liabilities
Trade and other payables	(2,279	)	(2,089	)
Provisions	(333	)	(1,439	)
Net current assets (liabilities)	(2,398	)	(3,276	)
Non-current assets
Deferred tax assets	1,563		2,067
Non-current liabilities
Other payables	(11,922	)	(12,253	)
Provisions	(12	)	(1,141	)
Deferred tax liabilities	3,999		3,634
Net non-current assets (liabilities)	(6,372	)	(7,693	)
Net assets (liabilities)	(8,770	)	(10,969	)



	Fourth		Fourth
	quarter		quarter		Year		Year
$ million	2018		2017		2018		2017
Cash flow statement - Operating activities
Profit (loss) before taxation	(189	)	(2,345	)	(1,193	)	(3,180	)
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	122		124		479		493
Net charge for provisions, less payments	32		2,181		240		2,542
Movements in inventories and other current and non-current assets and liabilities	(238	)	(413	)	(3,057	)	(5,191	)
Pre-tax cash flows	(273	)	(453	)	(3,531	)	(5,336	)

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Note 2. Gulf of Mexico oil spill (continued)

Cash outflows in 2018 and 2017 include payments made under the 2012 agreement with the US government to resolve all federal criminal claims arising from the incident and the 2016 consent decree and settlement agreement with the United States and the five Gulf coast states. Net cash from operating activities relating to the Gulf of Mexico oil spill, on a post-tax basis, amounted to an outflow of $272 million and $3,218 million in the fourth quarter and full year of 2018 respectively. For the same periods in 2017, the amount was an outflow of $284 million and $5,167 million respectively.

(b) Provisions and other payables

Provisions

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



$ million
At 1 October 2018	389
Net increase in provision	45
Reclassified to other payables	(60	)
Utilization	(29	)
At 31 December 2018	345

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



$ million
At 1 January 2018	2,580
Net increase in provision	629
Reclassified to other payables	(2,045	)
Utilization	(819	)
At 31 December 2018	345

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

PSC settlement

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

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

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

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

Other payables

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

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

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

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Note 3. Business combinations

BP undertook a number of business combinations in 2018. For the full year, total consideration paid in cash amounted to $7,100 million, offset by cash acquired of $114 million. For the fourth quarter, total consideration paid in cash amounted to $6,485 million, offset by cash acquired of $106 million.

The acquisition brings BP extensive oil and gas production and resources in the liquids-rich regions of the Permian and Eagle Ford basins in Texas and in the Haynesville gas basin in Texas and Louisiana.

The total consideration for the transaction, after customary closing adjustments and the effect of discounting deferred payments, is $10,302 million, which will all be paid in cash. As at 31 December 2018, $6,788 million of the consideration had been paid, including $525 million during the third quarter 2018 and $6,263 million during the fourth quarter 2018. The remaining discounted amount of $3,514 million is included within other payables on the group balance sheet and will be paid in four instalments, with the final instalment being paid in April 2019.

The transaction has been accounted for as a business combination using the acquisition method. The provisional fair values of the identifiable assets and liabilities acquired, as at the date of acquisition, are shown in the table below. No goodwill has been recognized on the acquisition.



$ million
Assets
Property, plant and equipment	10,845
Intangible assets	21
Inventories	27
Trade and other receivables	493
Cash	104
Liabilities
Trade and other payables	(659	)
Provisions	(323	)
Non-controlling interest	(206	)
Total consideration	10,302

The acquisition-date fair values of the assets and liabilities acquired are provisional. As we gain further understanding of the acquired properties and development options, these fair values may be adjusted.

An analysis of the cash flows relating to the acquisition included within the cash flow statement for the full year 2018 is provided below.



		Year
$ million		2018
Transaction costs of the acquisition (included in cash flows from operating activities)		62
Interest on deferred payments (included in cash flows from operating activities)		21
Cash consideration paid, net of cash acquired (included in cash flows from investing activities)		6,684
Total net cash outflow for the acquisition		6,767

From the date of acquisition to 31 December 2018, the acquired activities generated revenues of $472 million and profit before tax of $49 million. If the business combination had taken place on 1 January 2018, it is estimated that the acquired activities would have generated revenues of $2,798 million and profit before tax of $431 million.

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Note 4. Analysis of replacement cost profit (loss) before interest and tax and reconciliation to profit (loss) before taxation



	Fourth		Fourth
	quarter		quarter		Year		Year
$ million	2018		2017		2018		2017
Upstream	4,168		1,928		14,328		5,221
Downstream	2,138		1,773		6,940		7,221
Rosneft	400		321		2,221		836
Other businesses and corporate_(a)	(1,110	)	(2,833	)	(3,521	)	(4,445	)
	5,596		1,189		19,968		8,833
Consolidation adjustment – UPII*	142		(149	)	211		(212	)
RC profit (loss) before interest and tax*	5,738		1,040		20,179		8,621
Inventory holding gains (losses)*
Upstream	(12	)	—		(6	)	8
Downstream	(2,470	)	719		(862	)	758
Rosneft (net of tax)	(92	)	97		67		87
Profit (loss) before interest and tax	3,164		1,856		19,378		9,474
Finance costs	742		616		2,528		2,074
Net finance expense relating to pensions and other post-retirement benefits	34		58		127		220
Profit (loss) before taxation	2,388		1,182		16,723		7,180

RC profit (loss) before interest and tax*
US	1,487		(1,509	)	3,041		(266	)
Non-US	4,251		2,549		17,138		8,887
	5,738		1,040		20,179		8,621


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

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Note 5. Sales and other operating revenues



	Fourth		Fourth
	quarter		quarter	Year	Year
$ million	2018		2017	2018	2017
By segment
Upstream	15,050		12,651	56,399	45,440
Downstream	67,733		62,697	270,689	219,853
Other businesses and corporate	536		480	1,678	1,469
	83,319		75,828	328,766	266,762

Less: sales and other operating revenues between segments
Upstream	8,669		6,929	28,565	24,179
Downstream	(1,232	)	913	574	1,800
Other businesses and corporate	205		170	871	575
	7,642		8,012	30,010	26,554

Third party sales and other operating revenues
Upstream	6,381		5,722	27,834	21,261
Downstream	68,965		61,784	270,115	218,053
Other businesses and corporate	331		310	807	894
Total sales and other operating revenues	75,677		67,816	298,756	240,208

By geographical area
US	26,890		24,127	104,759	88,709
Non-US	53,540		50,778	219,681	176,113
	80,430		74,905	324,440	264,822
Less: sales and other operating revenues between areas	4,753		7,089	25,684	24,614
	75,677		67,816	298,756	240,208

Sales and other operating revenues include the following in relation to revenues from contracts with customers
Crude oil	15,448		13,838	65,276	49,670
Oil products	47,847		45,992	195,466	159,821
Natural gas, LNG and NGLs	5,862		4,777	21,745	16,196
Non-oil products and other revenues from contracts with customers	3,618		3,773	13,768	12,538
Revenues from contracts with customers_(a)	72,775		68,380	296,255	238,225


(a)	See Note 1 for further information.

Note 6. Depreciation, depletion and amortization



	Fourth	Fourth
	quarter	quarter	Year	Year
$ million	2018	2017	2018	2017
Upstream
US	1,137	1,107	4,211	4,631
Non-US	2,242	2,339	8,907	8,637
	3,379	3,446	13,118	13,268
Downstream
US	240	218	900	875
Non-US	298	301	1,177	1,141
	538	519	2,077	2,016
Other businesses and corporate
US	11	16	59	65
Non-US	59	64	203	235
	70	80	262	300
Total group	3,987	4,045	15,457	15,584

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Note 7. Production and similar taxes



	Fourth	Fourth
	quarter	quarter	Year	Year
$ million	2018	2017	2018	2017
US	99	44	369	52
Non-US	87	467	1,167	1,723
	186	511	1,536	1,775

Note 8. Earnings per share and shares in issue

Basic earnings per ordinary share (EpS) amounts are calculated by dividing the profit (loss) for the period attributable to ordinary shareholders by the weighted average number of ordinary shares outstanding during the period. During the quarter the company repurchased for cancellation 2 million ordinary shares for a total cost of $16 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	2018	2017	2018	2017
Results for the period
Profit (loss) for the period attributable to BP shareholders	766	27	9,383	3,389
Less: preference dividend	—	—	1	1
Profit (loss) attributable to BP ordinary shareholders	766	27	9,382	3,388

Number of shares (thousand)_(a)
Basic weighted average number of shares outstanding	20,007,781	19,804,932	19,970,215	19,692,613
ADS equivalent	3,334,630	3,300,822	3,328,369	3,282,102

Weighted average number of shares outstanding used to calculate diluted earnings per share	20,133,087	19,929,655	20,102,493	19,816,442
ADS equivalent	3,355,514	3,321,609	3,350,415	3,302,740

Shares in issue at period-end	20,101,658	19,817,325	20,101,658	19,817,325
ADS equivalent	3,350,276	3,302,887	3,350,276	3,302,887


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

Issued ordinary share capital as at 31 December 2018 comprised 20,260,732,488 ordinary shares (31 December 2017 19,815,850,568 ordinary shares). This includes shares held in trust to settle future employee share plan obligations and excludes 1,264,731,539 ordinary shares which have been bought back and are held in treasury by BP (31 December 2017 1,472,342,503 ordinary shares).

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Note 9. Dividends

Dividends payable

BP today announced an interim dividend of 10.25 cents per ordinary share which is expected to be paid on 29 March 2019 to ordinary shareholders and American Depositary Share (ADS) holders on the register on 15 February 2019. The corresponding amount in sterling is due to be announced on 18 March 2019, calculated based on the average of the market exchange rates for the four dealing days commencing on 12 March 2019. Holders of ADSs are expected to receive $0.615 per ADS (less applicable fees). A scrip dividend alternative is available, allowing shareholders to elect to receive their dividend in the form of new ordinary shares and ADS holders in the form of new ADSs. Details of the 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
	2018	2017	2018	2017
Dividends paid per ordinary share
cents	10.250	10.000	40.500	40.000
pence	8.025	7.443	30.568	30.979
Dividends paid per ADS (cents)	61.50	60.00	243.00	240.00
Scrip dividends
Number of shares issued (millions)	47.5	53.3	195.3	289.8
Value of shares issued ($ million)	322	354	1,381	1,714

Note 10. Net Debt*



Net debt ratio*	Fourth	Fourth
	quarter	quarter	Year	Year
$ million	2018	2017	2018	2017
Gross debt	65,799	63,230	65,799	63,230
Fair value (asset) liability of hedges related to finance debt_(a)	813	175	813	175
	66,612	63,405	66,612	63,405
Less: cash and cash equivalents	22,468	25,586	22,468	25,586
Net debt	44,144	37,819	44,144	37,819
Equity	101,548	100,404	101,548	100,404
Net debt ratio	30.3%	27.4%	30.3%	27.4%



Analysis of changes in net debt	Fourth		Fourth
	quarter		quarter		Year		Year
$ million	2018		2017		2018		2017
Opening balance
Finance debt_(a)	64,135		65,784		63,230		58,300
Fair value (asset) liability of hedges related to finance debt_(b)	1,234		(227	)	175		697
Less: cash and cash equivalents_(c)	26,192		25,780		25,575		23,484
Opening net debt	39,177		39,777		37,830		35,513
Closing balance
Finance debt_(a)	65,799		63,230		65,799		63,230
Fair value (asset) liability of hedges related to finance debt_(b)	813		175		813		175
Less: cash and cash equivalents	22,468		25,586		22,468		25,586
Closing net debt	44,144		37,819		44,144		37,819
Decrease (increase) in net debt	(4,967	)	1,958		(6,314	)	(2,306	)
Movement in cash and cash equivalents (excluding exchange adjustments)	(3,619	)	(223	)	(2,777	)	1,558
Net cash outflow (inflow) from financing	(1,201	)	2,511		(3,145	)	(2,520	)
Other movements	(147	)	(299	)	(321	)	(564	)
Movement in net debt before exchange effects	(4,967	)	1,989		(6,243	)	(1,526	)
Exchange adjustments	—		(31	)	(71	)	(780	)
Decrease (increase) in net debt	(4,967	)	1,958		(6,314	)	(2,306	)


(a)	The fair value of finance debt at 31 December 2018 was $66,346 million (31 December 2017 $65,165 million).

(b)

Derivative financial instruments entered into for the purpose of managing interest rate and foreign currency exchange risk associated with net debt with a fair value liability position of $827 million (full year 2017 liability of $634 million and fourth quarter 2017 liability of $634 million) are not included in the calculation of net debt shown above as hedge accounting is not applied for these instruments.


(c)	See Note 1 for further information.


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

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Note 11. Inventory valuation

A provision of $604 million was held against hydrocarbon inventories at 31 December 2018 ($62 million at 31 December 2017) to write them down to their net realizable value. The net movement charged to the income statement during the fourth quarter 2018 was $562 million (fourth quarter 2017 was a credit of $46 million).

Note 12. Statutory accounts

The financial information shown in this publication, which was approved by the Board of Directors on 4 February 2019, is unaudited and does not constitute statutory financial statements. Audited financial information will be published in BP Annual Report and Form 20-F 2018.

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Additional information

Capital expenditure*



	Fourth	Fourth
	quarter	quarter	Year	Year
$ million	2018	2017	2018	2017
Capital expenditure on a cash basis
Organic capital expenditure*	4,402	4,622	15,140	16,501
Inorganic capital expenditure*_(a)	8,494	199	9,948	1,339
	12,896	4,821	25,088	17,840



	Fourth	Fourth
	quarter	quarter	Year	Year
$ million	2018	2017	2018	2017
Organic capital expenditure by segment
Upstream
US	1,048	726	3,482	2,999
Non-US	2,419	2,819	8,545	10,764
	3,467	3,545	12,027	13,763
Downstream
US	237	349	877	809
Non-US	562	598	1,904	1,590
	799	947	2,781	2,399
Other businesses and corporate
US	34	30	54	64
Non-US	102	100	278	275
	136	130	332	339
	4,402	4,622	15,140	16,501
Organic capital expenditure by geographical area
US	1,319	1,105	4,413	3,872
Non-US	3,083	3,517	10,727	12,629
	4,402	4,622	15,140	16,501

(a)

On 31 October 2018, BP acquired from BHP Billiton Petroleum (North America) Inc. 100% of the issued share capital of Petrohawk Energy Corporation, a wholly owned subsidiary of BHP that holds a portfolio of unconventional onshore US oil and gas assets. As at 31 December 2018, $6,788 million of the consideration had been paid, including $6,263 million during the fourth quarter 2018. These amounts are included, net of cash acquired of $104 million in the fourth quarter, in inorganic capital expenditure. See Note 3 for more information. Fourth quarter and full year 2018 include $1,739 million relating to the purchase of an additional 16.5% interest in the Clair field west of Shetland in the North Sea, as part of the agreements with ConocoPhillips in which ConocoPhillips simultaneously purchased BP's entire 39.2% interest in the Greater Kuparuk Area on the North Slope of Alaska. Full year 2018 also includes amounts relating to the 25-year extension to our ACG production-sharing agreement* in Azerbaijan. Full year 2017 includes amounts paid to acquire interests in Mauritania and Senegal and amounts paid to purchase an interest in the Zohr gas field in Egypt and in exploration blocks in Senegal.

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Non-operating items*



	Fourth		Fourth
	quarter		quarter		Year		Year
$ million	2018		2017		2018		2017
Upstream
Impairment and gain (loss) on sale of businesses and fixed assets_(a)	34		(181	)	(90	)	(563	)
Environmental and other provisions	(35	)	1		(35	)	1
Restructuring, integration and rationalization costs_(b)	(53	)	(4	)	(131	)	(24	)
Fair value gain (loss) on embedded derivatives	—		2		17		33
Other_(c)	190		38		56		(118	)
	136		(144	)	(183	)	(671	)
Downstream
Impairment and gain (loss) on sale of businesses and fixed assets_(d)	(20	)	469		(54	)	579
Environmental and other provisions	(83	)	(19	)	(83	)	(19	)
Restructuring, integration and rationalization costs_(b)	(279	)	(69	)	(405	)	(171	)
Fair value gain (loss) on embedded derivatives	—		—		—		—
Other	(19	)	1		(174	)	—
	(401	)	382		(716	)	389
Rosneft
Impairment and gain (loss) on sale of businesses and fixed assets	(31	)	—		(95	)	—
Environmental and other provisions	—		—		—		—
Restructuring, integration and rationalization costs	—		—		—		—
Fair value gain (loss) on embedded derivatives	—		—		—		—
Other	—		—		—		—
	(31	)	—		(95	)	—
Other businesses and corporate
Impairment and gain (loss) on sale of businesses and fixed assets	(6	)	(16	)	(260	)	(22	)
Environmental and other provisions_(e)	(575	)	(153	)	(640	)	(156	)
Restructuring, integration and rationalization costs_(b)	(112	)	(35	)	(190	)	(72	)
Fair value gain (loss) on embedded derivatives	—		—		—		—
Gulf of Mexico oil spill - business economic loss claims_(f)	(26	)	(2,110	)	(344	)	(2,370	)
Gulf of Mexico oil spill - other_(f)	(41	)	(111	)	(370	)	(317	)
Other	(6	)	(14	)	(159	)	90
	(766	)	(2,439	)	(1,963	)	(2,847	)
Total before interest and taxation	(1,062	)	(2,201	)	(2,957	)	(3,129	)
Finance costs_(f)	(122	)	(124	)	(479	)	(493	)
Total before taxation	(1,184	)	(2,325	)	(3,436	)	(3,622	)
Taxation credit (charge) on non-operating items_(g)	(2	)	669		510		1,172
Taxation - impact of US tax reform_(h)	—		(859	)	121		(859	)
Total after taxation for period	(1,186	)	(2,515	)	(2,805	)	(3,309	)

(a)

Fourth quarter and full year 2018 include an impairment reversal for assets in the North Sea and Angola. Fourth quarter and full year 2017 include an impairment charge relating to BPX Energy (previously known as 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.


(b)	The group's restructuring programme, originally announced in 2014, has now been completed.

(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 2018 and full year 2017 also include the write-off of $124 million and $145 million respectively 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.


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


(e)	Fourth quarter and full year 2018 primarily reflects charges due to the annual update of environmental provisions, including asbestos-related provisions for past operations, together with updates of non-Gulf of Mexico oil spill related legal provisions.


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


(g)	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 at the tax rate applicable from 1 January 2018.

(h)

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. Full year 2018 reflects a further impact following a clarification of the tax reform. The impact of the US tax reform has been treated as a non-operating item because it is not considered to be part of underlying business operations, has a material impact upon the reported result and is substantially impacted by Gulf of Mexico oil spill charges, which are also treated as non-operating items. Separate disclosure is considered meaningful and relevant to investors.

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Non-GAAP information on fair value accounting effects



	Fourth		Fourth
	quarter		quarter		Year		Year
$ million	2018		2017		2018		2017
Favourable (adverse) impact relative to management’s measure of performance
Upstream	146		(151	)	(39	)	27
Downstream	370		(83	)	95		(135	)
	516		(234	)	56		(108	)
Taxation credit (charge)	(90	)	59		12		12
	426		(175	)	68		(96	)

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

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

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

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

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

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

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

The impacts of fair value accounting effects, relative to management’s internal measure of performance, are shown in the table above. A reconciliation to GAAP information is set out below.



	Fourth	Fourth
	quarter	quarter		Year		Year
$ million	2018	2017		2018		2017
Upstream
Replacement cost profit (loss) before interest and tax adjusted for fair value accounting effects	4,022	2,079		14,367		5,194
Impact of fair value accounting effects	146	(151	)	(39	)	27
Replacement cost profit (loss) before interest and tax	4,168	1,928		14,328		5,221
Downstream
Replacement cost profit (loss) before interest and tax adjusted for fair value accounting effects	1,768	1,856		6,845		7,356
Impact of fair value accounting effects	370	(83	)	95		(135	)
Replacement cost profit (loss) before interest and tax	2,138	1,773		6,940		7,221
Total group
Profit (loss) before interest and tax adjusted for fair value accounting effects	2,648	2,090		19,322		9,582
Impact of fair value accounting effects	516	(234	)	56		(108	)
Profit (loss) before interest and tax	3,164	1,856		19,378		9,474

Readily marketable inventory* (RMI)



	31 December	31 December
$ million	2018	2017
RMI at fair value*	4,202	5,661
Paid-up RMI*	1,641	2,688

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

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

See the Glossary on page 36 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	2018		2017
Reconciliation of total inventory to paid-up RMI
Inventories as reported on the group balance sheet under IFRS	17,988		19,011
Less: (a) inventories that are not oil and oil products and (b) oil and oil product inventories that are not risk-managed by IST	(14,066	)	(13,929	)
	3,922		5,082
Plus: difference between RMI at fair value and RMI on an IFRS basis	280		579
RMI at fair value	4,202		5,661
Less: unpaid RMI* at fair value	(2,561	)	(2,973	)
Paid-up RMI	1,641		2,688

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



	Fourth		Fourth
	quarter		quarter		Year		Year
Per ordinary share (cents)	2018		2017		2018		2017
Profit for the period	3.83		0.14		46.98		17.20
Inventory holding (gains) losses*, before tax	12.86		(4.12	)	4.01		(4.32	)
Taxation charge (credit) on inventory holding gains and losses	(3.11	)	1.04		(0.99	)	1.14
Replacement cost (RC) profit (loss)*	13.58		(2.94	)	50.00		14.02
Net (favourable) adverse impact of non-operating items* and fair value accounting effects*, before tax	3.34		12.92		16.93		18.94
Taxation charge (credit) on non-operating items and fair value accounting effects	0.46		0.66		(3.23	)	(1.65	)
Underlying RC profit*	17.38		10.64		63.70		31.31

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



Taxation (charge) credit
	Fourth		Fourth
	quarter		quarter		Year		Year
$ million	2018		2017		2018		2017
Taxation on profit or loss	(1,617	)	(1,119	)	(7,145	)	(3,712	)
Taxation on inventory holding gains and losses	623		(206	)	198		(225	)
Taxation on a replacement cost (RC) profit or loss basis	(2,240	)	(913	)	(7,343	)	(3,487	)
Taxation on non-operating items and fair value accounting effects	(92	)	(131	)	643		325
Taxation on underlying replacement cost profit or loss	(2,148	)	(782	)	(7,986	)	(3,812	)



Effective tax rate
	Fourth		Fourth
	quarter		quarter		Year		Year
%	2018		2017		2018		2017
ETR on profit or loss	68		95		43		52
Adjusted for inventory holding gains or losses	(23	)	154		(1	)	3
ETR on RC profit or loss*	45		249		42		55
Adjusted for non-operating items and fair value accounting effects	(7	)	(222	)	(4	)	(17	)
Underlying ETR*	38		27		38		38

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Return on average capital employed (ROACE)




	Year		Year
$ million	2018		2017
Profit for the year attributable to BP shareholders	9,383		3,389
Inventory holding (gains) losses, net of tax	603		(628	)
Non-operating items and fair value accounting effects, after taxation	2,737		3,405
Underlying replacement cost (RC) profit	12,723		6,166
Interest expense, net of tax_(a)	1,583		924
Non-controlling interests	195		79
Adjusted underlying RC profit	14,501		7,169
Total equity	101,548		100,404
Gross debt	65,799		63,230
Capital employed (2018 average $165,491 million, 2017 average $159,389 million)	167,347		163,634
Less: Goodwill	12,204		11,551
Cash and cash equivalents	22,468		25,586
	132,675		126,497
Average capital employed (excluding goodwill and cash and cash equivalents)	129,586		123,481
ROACE	11.2	%	5.8	%


^(a)	Pre-tax finance costs for the year were $2,528 million (2017 $2,074 million) including interest expense of $1,779 million (2017 $1,421 million) and unwinding of the discount on provisions and other payables of $749 million (2017 $653 million). Interest expense included above is calculated on a post tax basis (for 2017 interest expense was net of notional tax at an assumed 35%).

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Realizations* and marker prices



	Fourth	Fourth
	quarter	quarter	Year	Year
	2018	2017	2018	2017
Average realizations_(a)
Liquids* ($/bbl)
US	61.61	51.50	61.72	46.55
Europe	65.07	57.92	69.20	52.13
Rest of World	61.42	59.09	66.68	51.83
BP Average	61.80	56.16	64.98	49.92
Natural gas ($/mcf)
US	3.10	2.28	2.43	2.36
Europe	8.80	5.56	7.71	5.09
Rest of World	4.77	3.51	4.37	3.45
BP Average	4.33	3.23	3.92	3.19
Total hydrocarbons* ($/boe)
US	42.50	35.75	41.59	33.47
Europe	61.98	52.17	64.11	46.09
Rest of World	41.64	37.27	42.65	35.44
BP Average	42.98	37.48	43.47	35.38
Average oil marker prices ($/bbl)
Brent	68.81	61.26	71.31	54.19
West Texas Intermediate	59.98	55.23	65.20	50.79
Western Canadian Select	25.31	38.74	38.27	38.55
Alaska North Slope	69.53	61.31	71.54	54.43
Mars	64.45	57.70	66.86	50.65
Urals (NWE – cif)	68.02	60.17	69.89	52.84
Average natural gas marker prices
Henry Hub gas price_(b)($/mmBtu)	3.65	2.93	3.09	3.11
UK Gas – National Balancing Point (p/therm)	65.13	51.94	60.38	44.95


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


(b)	Henry Hub First of Month Index.

Exchange rates



	Fourth	Fourth
	quarter	quarter	Year	Year
	2018	2017	2018	2017
$/£ average rate for the period	1.29	1.33	1.33	1.29
$/£ period-end rate	1.27	1.34	1.27	1.34

$/€ average rate for the period	1.14	1.18	1.18	1.13
$/€ period-end rate	1.14	1.19	1.14	1.19

Rouble/$ average rate for the period	66.48	58.46	62.73	58.36
Rouble/$ period-end rate	69.57	57.60	69.57	57.60

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Legal proceedings

The following discussion sets out the material developments in the group’s material legal proceedings during the recent period. For a full discussion of the group’s material legal proceedings, see pages 270-273 of BP Annual Report and Form 20-F 2017, and page 34 of BP p.l.c. Group results second quarter and half-year 2018.

Other legal proceedings

Scharfstein v. BP West Coast Products, LLC A class action lawsuit was filed against BP West Coast Products, LLC (BPWCP) in Oregon State Court under the Oregon Unlawful Trade Practices Act on behalf of customers who used a debit card at ARCO gasoline stations in Oregon during the period 1 January 2011 to 30 August 2013, alleging that ARCO sites in Oregon failed to provide sufficient notice of the 35 cents per transaction debit card fee. In January 2014, the jury rendered a verdict against BPWCP and awarded statutory damages of $200 per class member. On 25 August 2015, the trial court determined the size of the class to be slightly in excess of two million members. On 31 May 2016 the trial court entered a judgment against BPWCP for the amount of $417.3 million. On 31 May 2018 the Oregon Court of Appeals affirmed the trial court’s ruling. BP filed a Petition for Review to the Oregon Supreme Court. On 8 November 2018 the Oregon Supreme Court denied BP’s petition for review. BP intends to appeal to the United States Supreme Court.

Glossary

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

Capital expenditure is total cash capital expenditure as stated in the condensed group cash flow statement.

Consolidation adjustment – UPII is unrealized profit in inventory arising on inter-segment transactions.

Divestment proceeds are disposal proceeds as per the condensed group cash flow statement.

Effective tax rate (ETR) on replacement cost (RC) profit or loss is a non-GAAP measure. The ETR on RC profit or loss is calculated by dividing taxation on a RC basis by RC profit or loss before tax. Information on RC profit or loss is provided below. BP believes it is helpful to disclose the ETR on RC profit or loss because this measure excludes the impact of price changes on the replacement of inventories and allows for more meaningful comparisons between reporting periods. The nearest equivalent measure on an IFRS basis is the ETR on profit or loss for the period. A reconciliation to GAAP information is provided on page 33.

Fair value accounting effects are non-GAAP adjustments to our IFRS profit (loss). They reflect the difference between the way BP manages the economic exposure and internally measures performance of certain activities and the way those activities are measured under IFRS. Further information on fair value accounting effects is provided on page 31.

Free cash flow is operating cash flow less net cash used in investing activities, as presented in the condensed group cash flow statement.

Gearing – See Net debt and net debt ratio definition.

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

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

Inorganic capital expenditure is a subset of capital expenditure and is a non-GAAP measure. Inorganic capital expenditure comprises consideration in business combinations and certain other significant investments made by the group. It is reported on a cash basis. BP believes that this measure provides useful information as it allows investors to understand how BP’s management invests funds in projects which expand the group’s activities through acquisition. Further information and a reconciliation to GAAP information is provided on page 29.

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

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

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

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Glossary (continued)

Net debt and net debt ratio are non-GAAP measures. Net debt is calculated as gross finance debt, as shown in the balance sheet, plus the fair value of associated derivative financial instruments that are used to hedge foreign currency exchange and interest rate risks relating to finance debt, for which hedge accounting is applied, less cash and cash equivalents. The net debt ratio is defined as the ratio of net debt to the total of net debt plus shareholders’ equity. All components of equity are included in the denominator of the calculation. BP believes these measures provide useful information to investors. Net debt enables investors to see the economic effect of gross debt, related hedges and cash and cash equivalents in total. The net debt ratio enables investors to see how significant net debt is relative to equity from shareholders. The derivatives are reported on the balance sheet within the headings ‘Derivative financial instruments’. The nearest equivalent GAAP measures on an IFRS basis are gross debt and gross debt ratio. A reconciliation of gross debt to net debt is provided on page 27.

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

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

Non-operating items are charges and credits included in the financial statements that BP discloses separately because it considers such disclosures to be meaningful and relevant to investors. They are items that management considers not to be part of underlying business operations and are disclosed in order to enable investors better to understand and evaluate the group’s reported financial performance. Non-operating items within equity-accounted earnings are reported net of incremental income tax reported by the equity-accounted entity. An analysis of non-operating items by region is shown on pages 9, 11 and 13, and by segment and type is shown on page 30.

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

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

Organic capital expenditure is a subset of capital expenditure and is a non-GAAP measure. Organic capital expenditure comprises capital expenditure less inorganic capital expenditure. BP believes that this measure provides useful information as it allows investors to understand how BP’s management invests funds in developing and maintaining the group’s assets. An analysis of organic capital expenditure by segment and region, and a reconciliation to GAAP information is provided on page 29.

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

Production-sharing agreement (PSA) is an arrangement through which an oil and gas company bears the risks and costs of exploration, development and production. In return, if exploration is successful, the oil company receives entitlement to variable physical volumes of hydrocarbons, representing recovery of the costs incurred and a stipulated share of the production remaining after such cost recovery.

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

Paid-up RMI excludes RMI which has not yet been paid for. For inventory that is held in storage, a first-in first-out (FIFO) approach is used to determine whether inventory has been paid for or not. Unpaid RMI is RMI which has not yet been paid for by BP. RMI, RMI at fair value, Paid-up RMI and Unpaid RMI are non-GAAP measures. Further information is provided on page 32.

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

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

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

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Glossary (continued)

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

RC profit or loss per share is a non-GAAP measure. Earnings per share is defined in Note 8. 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 33.

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 the year’s production has been replaced by proved reserves added to our reserve base. The ratio is expressed in oil-equivalent terms and includes changes resulting from discoveries, improved recovery and extensions and revisions to previous estimates, but excludes changes resulting from acquisitions and disposals. The reserves replacement ratio will be reported in BP Annual Report and Form 20-F 2018.

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 tax (for 2017 interest expense was net of notional tax at an assumed 35%), divided by average capital employed, excluding cash and cash equivalents and goodwill. Interest expense is finance costs excluding the unwinding of the discount on provisions and other payables, and for full year 2018 interest expense was $1,779 million (2017 $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 34.

Solomon availability – See Refining availability definition.

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

Underlying effective tax rate (ETR) is a non-GAAP measure. The underlying ETR is calculated by dividing taxation on an underlying replacement cost (RC) basis by underlying RC profit or loss before tax. Taxation on an underlying RC basis is taxation on a RC basis for the period adjusted for taxation on non-operating items and fair value accounting effects. Information on underlying RC profit or loss is provided below. BP believes it is helpful to disclose the underlying ETR because this measure may help investors to understand and evaluate, in the same manner as management, the underlying trends in BP’s operational performance on a comparable basis, period on period. The nearest equivalent measure on an IFRS basis is the ETR on profit or loss for the period. A reconciliation to GAAP information is provided on page 33.

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

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

Underlying RC profit or loss is RC profit or loss after adjusting for non-operating items and fair value accounting effects. Underlying RC profit or loss and adjustments for fair value accounting effects are not recognized GAAP measures. See pages 30 and 31 for additional information on the non-operating items and fair value accounting effects that are used to arrive at underlying RC profit or loss in order to enable a full understanding of the events and their financial impact. BP believes that underlying RC profit or loss is a useful measure for investors because it is a measure closely tracked by management to evaluate BP’s operating performance and to make financial, strategic and operating decisions and because it may help investors to understand and evaluate, in the same manner as management, the underlying trends in BP’s operational performance on a comparable basis, period on period, by adjusting for the effects of these non-operating items and fair value accounting effects. The nearest equivalent measure on an IFRS basis for the group is profit or loss attributable to BP shareholders. The nearest equivalent measure on an IFRS basis for segments is RC profit or loss before interest and taxation. A reconciliation to GAAP information is provided on page 3.

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Glossary (continued)

Underlying RC profit or loss per share is a non-GAAP measure. Earnings per share is defined in Note 8. 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 33.

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

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

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

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

Cautionary statement

In order to utilize the ‘safe harbor’ provisions of the United States Private Securities Litigation Reform Act of 1995 (the ‘PSLRA’) and the general doctrine of cautionary statements, BP is providing the following cautionary statement: The discussion in this results announcement contains certain forecasts, projections and forward-looking statements - that is, statements related to future, not past events and circumstances - with respect to the financial condition, results of operations and businesses of BP and certain of the plans and objectives of BP with respect to these items. These statements may generally, but not always, be identified by the use of words such as ‘will’, ‘expects’, ‘is expected to’, ‘aims’, ‘should’, ‘may’, ‘objective’, ‘is likely to’, ‘intends’, ‘believes’, ‘anticipates’, ‘plans’, ‘we see’ or similar expressions. In particular, the following, among other statements, are all forward looking in nature: expectations regarding the expected quarterly dividend payment and timing of such payment; expectations regarding BP’s strategy and its impact on BP and its shareholders; plans and expectations regarding share buybacks, including to offset the impact of dilution from the scrip programme; expectations regarding the underlying effective tax rate in 2019; expectations for cash flow growth to underpin the balance sheet; expectations regarding 2019 organic capital expenditure and depreciation, depletion and amortization charges; plans and expectations with respect to gearing; plans and expectations to complete more than $10 billion divestments over the next two years; expectations regarding Upstream full-year 2019 underlying and reported production and first-quarter 2019 reported production; expectations regarding Downstream first-quarter 2019 refining margins, and narrower discounts for North American heavy crude oil; expectations regarding the transfer of licences to LLC Yermakneftegaz; plans and expectations regarding BP’s wind energy business; expectations regarding Other businesses and corporate 2019 average quarterly charges; plans and expectations regarding Lightsource BP, including to enter Brazil and to provide power to AB InBev’s manufacturing plants in the UK; plans and expectations regarding BP’s acquisition of onshore-US oil and gas assets from BHP, including expectations regarding the timing of purchase price payments; plans and expectations regarding legal and trial proceedings including to appeal the decision in the Scharfstein v. BP West Coast Products, LLC lawsuit; and expectations with respect to the timing and amount of future payments relating to the Gulf of Mexico oil spill including payments for full-year 2019 and 2012 PSC settlement payments. By their nature, forward-looking statements involve risk and uncertainty because they relate to events and depend on circumstances that will or may occur in the future and are outside the control of BP. Actual results may differ materially from those expressed in such statements, depending on a variety of factors, including: the specific factors identified in the discussions accompanying such forward-looking statements; the receipt of relevant third party and/or regulatory approvals; the timing and level of maintenance and/or turnaround activity; the timing and volume of refinery additions and outages; the timing of bringing new projects onstream; the timing, quantum and nature of certain acquisitions and 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 2018 and “Risk factors” in BP Annual Report and Form 20-F 2017 as filed with the US Securities and Exchange Commission.

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

accordance with IFRS:

Capitalization and indebtedness



	31 December
$ million	2018
Share capital and reserves
Capital shares (1-2)	5,398
Paid-in surplus (3)	13,748
Merger reserve (3)	27,206
Treasury shares	(15,767	)
Cash flow hedge reserve	(777	)
Costs of hedging reserve	(210	)
Foreign currency translation reserve	(8,901	)
Profit and loss account	78,747
BP shareholders' equity	99,444

Finance debt (4-6)
Due within one year	9,373
Due after more than one year	56,426
Total finance debt	65,799
Total capitalization (7)	165,243

Issued share capital as of 31 December 2018 comprised 20,260,732,488 ordinary shares, par value US$0.25 per share, and 12,706,252 preference shares, par value £1 per share. This excludes 1,264,731,539 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 2018.


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


6.	At 31 December 2018, the parent company, BP p.l.c., had issued guarantees totalling $63,035 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 2018, $148 million of finance debt was secured by the pledging of assets. The remainder of finance debt was unsecured.


7.	At 31 December 2018 the group had issued third-party guarantees under which amounts outstanding, incremental to amounts recognized on the group balance sheet, were $684 million in respect of the borrowings of equity-accounted entities and $423 million in respect of the borrowings of other third parties.


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

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Recent credit ratings update

On 8 October 2018, Moody’s changed the outlook from positive to stable on the A1 issuer rating of BP p.l.c. and the long-term debt ratings of its guaranteed subsidiaries and Prime-1 commercial paper ratings of BP Capital Markets p.l.c. and BP Corporation North America, Inc. Moody’s affirmed the current ratings.

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:	5 February 2019	/s/ JENS BERTELSEN
		JENS BERTELSEN
		Secretary