UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549


Form 6-K

Report of Foreign Private Issuer

Pursuant to Rule 13a-16 or 15d-16 of
the Securities Exchange Act of 1934

for the period ended 31 December 2017
Commission File Number 1-06262

BP p.l.c.
(Translation of registrant’s name into English)

1 ST JAMES’S SQUARE, LONDON, SW1Y 4PD, ENGLAND
(Address of principal executive offices)

Indicate by check mark whether the registrant files or will file annual reports under cover of Form 20-F or Form 40-F:
 
 
 
 
Form 20-F x  Form 40-F ¨  
 
 
 
 
Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(1): ¨
Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(1): ¨

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


1

Table of contents

BP p.l.c. and subsidiaries
Form 6-K for the period ended 31 December 2017(a) 

 
 
 
Page
1.
 
3-14, 27-32, 34-36
 
 
 
 
2.
 
14-26
 
 
 
 
3.
 
33
 
 
 
 
4.
 
37
 
 
 
 
5.
 
38
 
 
 
 
6.
 
39
 
 
 
 
7.
 
40
(a) 
In this Form 6-K, references to the full year 2017 and full year 2016 refer to full year periods ended 31 December 2017 and 31 December 2016 respectively. References to the fourth quarter 2017 and fourth quarter 2016 refer to the three-month periods ended 31 December 2017 and 31 December 2016 respectively.
(b) 
This discussion should be read in conjunction with the consolidated financial statements and related notes provided elsewhere in this Form 6-K and with the information, including the consolidated financial statements and related notes, in BP’s Annual Report on Form 20-F for the year ended 31 December 2016.


2

Table of contents

Group results fourth quarter and full year 2017

Full year
Highlights
 
Profit for the full year and fourth quarter was $3.4 billion and $27 million respectively, compared with $115 million and $497 million for the same periods in 2016. Underlying replacement cost profit* was $6.2 billion for full year 2017 and $2.1 billion for the fourth quarter, compared with $2.6 billion and $400 million for full year and fourth quarter 2016 respectively.
Operating cash flow* for 2017 was $18.9 billion, after post-tax Gulf of Mexico oil spill expenditure of $5.2 billion, compared with $10.7 billion, after post-tax Gulf of Mexico oil spill expenditure of $6.9 billion in 2016.
Downstream earnings were very strong with underlying replacement cost profit of $7.0 billion, 24% higher than 2016 and replacement cost profit of $7.2 billion, 40% higher than 2016.
Operational reliability was high, with refining availability* and Upstream BP-operated plant reliability* both 95%.
Seven new major projects* delivered, boosting oil and gas production. Upstream production, excluding BP's share of Rosneft production, was 12% higher than 2016, the highest since 2010. Including Rosneft, production was 3.6 million barrels of oil equivalent a day, 10% higher than 2016. Oil and gas realizations were 25% higher.
Exploration delivered the most successful year for BP since 2004.
Dividend unchanged at 10 cents per share.
BP began share buybacks in the fourth quarter, spending $343 million, fully offsetting the dilution from scrip dividends issued in the third quarter.
Non-operating items in the fourth quarter, which are excluded from underlying profit*, included a $0.9 billion charge for US tax changes and a $1.7 billion post-tax charge relating to a further provision for claims associated with the oil spill.

 
Financial summary
 
Fourth

Fourth

 




 
quarter

quarter

 
Year

Year

$ million
 
2017

2016

 
2017

2016

Profit for the period(a)
 
27

497

 
3,389

115

Inventory holding (gains) losses*, before tax
 
(816
)
(601
)
 
(853
)
(1,597
)
Taxation charge (credit) on inventory holding gains and losses
 
206

176

 
225

483

RC profit (loss)*
 
(583
)
72

 
2,761

(999
)
Net (favourable) adverse impact of non-operating items* and fair value
 
 
 
 
 
 
  accounting effects*, before tax
 
2,559

481

 
3,730

6,746

Taxation charge (credit) on non-operating items and fair value accounting effects
 
131

(153
)
 
(325
)
(3,162
)
Underlying RC profit
 
2,107

400

 
6,166

2,585

Profit per ordinary share (cents)
 
0.14

2.62

 
17.20

0.61

Profit per ADS (dollars)
 
0.01

0.16

 
1.03

0.04

RC profit (loss) per ordinary share (cents)*
 
(2.94
)
0.38

 
14.02

(5.33
)
RC profit (loss) per ADS (dollars)
 
(0.18
)
0.02

 
0.84

(0.32
)
Underlying RC profit per ordinary share (cents)*
 
10.64

2.11

 
31.31

13.79

Underlying RC profit per ADS (dollars)
 
0.64

0.13

 
1.88

0.83

(a) 
Profit attributable to BP shareholders.

* See definitions in the Glossary on page 34. RC profit (loss), underlying RC profit and organic capital expenditure are non-GAAP measures.
The commentary above and following should be read in conjunction with the cautionary statement on page 37.

3

Table of contents

Group headlines
Earnings
BP’s profit for the fourth quarter and full year was $27 million and $3,389 million respectively, compared with $497 million and $115 million for the same periods in 2016.
For the full year, replacement cost (RC) profit was $2,761 million, compared with a loss of $999 million in 2016. Underlying RC profit was $6,166 million, compared with $2,585 million in 2016. Underlying RC profit is after adjusting for a net charge for non-operating items of $3,309 million and net adverse fair value accounting effects of $96 million (both on a post-tax basis).
For the fourth quarter, RC loss was $583 million, compared with a profit of $72 million for the same period in 2016. Underlying RC profit was $2,107 million compared with $400 million for the same period in 2016. Underlying RC profit is after adjusting for a net charge for non-operating items of $2,515 million and net adverse fair value accounting effects of $175 million (both on a post-tax basis).
See further information on page 5.
Depreciation, depletion and amortization
The charge for depreciation, depletion and amortization was $15.6 billion in 2017, compared with $14.5 billion in 2016. In 2018, we expect the charge to be higher than 2017.
Non-operating items
Non-operating items amounted to a charge of $2,325 million pre-tax and $2,515 million post-tax for the quarter and a charge of $3,622 million pre-tax and $3,309 million post-tax for the full year. The post-tax non-operating charge for the fourth quarter includes a charge of $1.7 billion relating to business economic loss and other claims associated with the Gulf of Mexico oil spill (see Note 2 on page 19) and a $0.9 billion deferred tax charge following the change in the US tax rate. See further information on page 28.
Effective tax rate
The effective tax rate (ETR) on the profit or loss for the fourth quarter and full year was 95% and 52% respectively, compared with 12% and 107% for the same periods in 2016.
The ETR on RC profit or loss* for the fourth quarter and full year was significantly impacted by the effect of non-operating items and therefore it is not a meaningful measure.
The adjusted ETR* is calculated by eliminating the impact of non-operating items, which for the fourth quarter includes a one-off deferred tax charge in respect of the revaluation of deferred tax assets and liabilities following the reduction in the US federal corporate income tax rate from 35% to 21% enacted in December 2017; fair value accounting effects; and the impact of a reduction in the UK supplementary tax charge in the third quarter of 2016.
The adjusted ETR for the fourth quarter and full year was 27% and 38% respectively, compared with 10% and 23% for the same periods in 2016. The adjusted ETR for the fourth quarter 2017 reflects a benefit from the reassessment of the recognition of deferred tax assets. The adjusted ETR for the fourth quarter 2016 was impacted by a high proportion of equity-accounted income (which is reported net of tax in the income statement) within RC profit, and reflected a benefit from the reassessment of the recognition of deferred tax assets and other items, partly offset by charges for foreign exchange impacts.
The adjusted ETR for the full year is higher than last year predominantly due to changes in the geographical mix of profits notably the impact of the renewal of our interest in the Abu Dhabi onshore oil concession. In the current environment, and assuming no further reassessment of the
 
recognition of deferred tax assets, the adjusted ETR in 2018 is expected to be above 40%. ETR on RC profit or loss and adjusted ETR are non-GAAP measures.
Dividend
BP today announced a quarterly dividend of 10.00 cents per ordinary share ($0.600 per ADS), which is expected to be paid on 29 March 2018. The corresponding amount in sterling will be announced on 19 March 2018. See page 25 for further information.
Share buybacks
BP recommenced a share buyback programme in the fourth quarter to offset the dilution of the scrip issue and repurchased 51 million ordinary shares at a cost of $343 million, including fees and stamp duty, during the fourth quarter of 2017.
Operating cash flow*
Operating cash flow for the fourth quarter and full year was $5.9 billion and $18.9 billion respectively, after post-tax expenditure relating to the Gulf of Mexico oil spill of $0.3 billion and $5.2 billion. For the same periods in 2016 the equivalent amounts were $2.4 billion and $10.7 billion, after post-tax Gulf of Mexico oil spill expenditure of $2.0 billion and $6.9 billion.
Capital expenditure*
Total capital expenditure for the fourth quarter and full year was $4.8 billion and $17.8 billion respectively, compared with $4.9 billion and $17.5 billion for the same periods in 2016.
Organic capital expenditure* for the fourth quarter and full year was $4.6 billion and $16.5 billion respectively, compared with $4.5 billion and $16.7 billion for the same periods in 2016. In 2018, we expect organic capital expenditure to be in the range of $15-16 billion.
Inorganic capital expenditure* for the fourth quarter and full year was $0.2 billion and $1.3 billion respectively, compared with $0.4 billion and $0.8 billion for the same periods in 2016.
See page 27 for further information.
Divestment and other proceeds
Total divestment and other proceeds for the year were $4.3 billion including proceeds of $0.8 billion received in relation to the initial public offering of BP Midstream Partners LP’s common units. Divestment proceeds* were $2.5 billion for the fourth quarter and $3.4 billion for the full year, compared with $0.5 billion and $2.6 billion for the same periods in 2016. In 2018, divestments are expected to be in the range of $2-3 billion.
Debt
Gross debt at 31 December 2017 was $63.2 billion compared with $58.3 billion a year ago. The ratio of gross debt to gross debt plus equity at 31 December 2017 was 38.6%, compared with 37.6% a year ago.
Net debt* at 31 December 2017 was $37.8 billion, compared with $35.5 billion a year ago. The net debt ratio* at 31 December 2017 was 27.4%, compared with 26.8% a year ago. We continue to target a net debt ratio in the range of 20-30%. Net debt and the net debt ratio are non-GAAP measures. See page 25 for more information.
Reserves replacement ratio*
The reserves replacement ratio on a combined basis of subsidiaries and equity-accounted entities was estimated at 143%(a) for the year.
(a) Includes estimated reserves data for Rosneft. The reserves replacement ratio will be finalized and reported in BP Annual Report and Form 20-F 2017.
The commentary above and following should be read in conjunction with the cautionary statement on page 37.

4

Table of contents

Analysis of underlying RC profit before interest and tax
 
 
Fourth

Fourth

 




 
 
quarter

quarter

 
Year

Year

$ million
 
2017

2016

 
2017

2016

Underlying RC profit before interest and tax*
 
 
 
 
 
 
Upstream
 
2,223

400

 
5,865

(542
)
Downstream
 
1,474

877

 
6,967

5,634

Rosneft
 
321

135

 
836

567

Other businesses and corporate
 
(394
)
(424
)
 
(1,598
)
(1,238
)
Consolidation adjustment – UPII*
 
(149
)
(132
)
 
(212
)
(196
)
Underlying RC profit before interest and tax
 
3,475

856

 
11,858

4,225

Finance costs and net finance expense relating to pensions and other
 
 
 
 
 
 
  post-retirement benefits
 
(550
)
(359
)
 
(1,801
)
(1,371
)
Taxation on an underlying RC basis
 
(782
)
(51
)
 
(3,812
)
(212
)
Non-controlling interests
 
(36
)
(46
)
 
(79
)
(57
)
Underlying RC profit attributable to BP shareholders
 
2,107

400

 
6,166

2,585


Reconciliations of underlying RC profit or loss to the nearest equivalent IFRS measure are provided on page 3 for the group and on pages 8-13 for the segments.
 
Analysis of RC profit (loss) before interest and tax and reconciliation to profit (loss) for the period
 
 
Fourth

Fourth

 




 
 
quarter

quarter

 
Year

Year

$ million
 
2017

2016

 
2017

2016

RC profit (loss) before interest and tax*
 
 
 
 
 
 
Upstream
 
1,928

692

 
5,221

574

Downstream
 
1,773

899

 
7,221

5,162

Rosneft
 
321

158

 
836

590

  Other businesses and corporate(a)
 
(2,833
)
(1,117
)
 
(4,445
)
(8,157
)
Consolidation adjustment – UPII
 
(149
)
(132
)
 
(212
)
(196
)
RC profit (loss) before interest and tax
 
1,040

500

 
8,621

(2,027
)
Finance costs and net finance expense relating to pensions and other
 
 
 
 
 
 
post-retirement benefits
 
(674
)
(484
)
 
(2,294
)
(1,865
)
Taxation on a RC basis
 
(913
)
102

 
(3,487
)
2,950

Non-controlling interests
 
(36
)
(46
)
 
(79
)
(57
)
RC profit (loss) attributable to BP shareholders
 
(583
)
72

 
2,761

(999
)
Inventory holding gains (losses)
 
816

601

 
853

1,597

Taxation (charge) credit on inventory holding gains and losses
 
(206
)
(176
)
 
(225
)
(483
)
Profit for the period attributable to BP shareholders
 
27

497

 
3,389

115

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




5

Table of contents

Strategic progress

Upstream
2017 oil and gas production, excluding Rosneft, was 12% higher than in 2016, the highest since 2010. Upstream unit production costs* were 16% lower, benefiting from production growth and continued cost discipline.
Zohr in Egypt completed BP’s programme of seven major project* start-ups in 2017. Together with 2016 start-ups, the projects contribute more than 500mboe/d new net production capacity and are expected to deliver operating cash margins* around 35% greater than Upstream’s assets in 2015.
In the quarter BP accessed significant new exploration acreage in the Santos basin of Brazil and in Côte d’Ivoire with Kosmos Energy. BP announced six exploration discoveries in 2017 - the cumulative discovery of resources was BP’s largest since 2004.
Downstream
Fuels marketing earnings increased by more than 10% in 2017. Premium fuel volumes grew by 6% and BP’s convenience partnership model increased to 1,100 sites worldwide. More than 120 BP retail sites in Mexico were operational at year end. In lubricants, BP delivered premium brand growth and increased earnings from growth markets.
In manufacturing, both refining and petrochemicals grew earnings with record levels of advantaged feedstock processed in refining.
Advancing the energy transition
BP acquired a 43% interest in Lightsource, Europe’s largest solar development company, supporting its rapid expansion worldwide. Other progress included BP enhancing its biofuels business in Brazil through an ethanol storage joint venture, forming a partnership with Aria Energy to expand its renewable gas portfolio in the US and, in January, BP Ventures investing in the electric vehicle fast-charging company Freewire.
 
Financial framework

Operating cash flow* for full year 2017, after post-tax expenditure relating to the Gulf of Mexico oil spill of $5.2 billion, was $18.9 billion. This compares with $10.7 billion, after post-tax Gulf of Mexico oil spill expenditure of $6.9 billion, for full year 2016.
Organic capital expenditure* for 2017 was $16.5 billion, in the range of $15-17 billion previously indicated. BP expects 2018 organic capital expenditure to be in the range of $15-16 billion.

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

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

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

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

Operating
metrics
 
 Year 2017
 
Financial
metrics
 
 Year 2017
 
(vs. Year 2016)
 
 
(vs. Year 2016)
Tier 1 process safety events
 
18
 
Underlying RC profiti
 
$6.2bn
 
(+2)
 
 
(+$3.6bn)
Reported recordable injury frequency
 
0.22
 
Operating cash flow excluding Gulf of Mexico oil spill payments
 
(b) 
 
(+3%)
 
 
 
Group production
 
3,595mboe/d
 
Organic capital expenditureii
 
$16.5bn
 
(+10%)
 
 
(-$0.2bn)
Upstream production (excludes Rosneft segment)
 
2,466mboe/d
 
Gulf of Mexico oil spill payments
 
$5.2bn
 
(+12%)
 
 
(-$1.7bn)
Upstream unit production costs
 
$7.11/boe
 
Divestment proceeds
 
$3.4bn
 
(-16%)
 
 
(+$0.8bn)
BP-operated Upstream operating efficiency*
 
80.5%
 
Net debt ratio (gearing)iii
 
27.4%
 
 
 
 
(+0.6)
BP-operated Upstream plant reliability* (a)
 
94.7%
 
Dividend per ordinary share(c)
 
10.00 cents
 
(-0.6)
 
 
Refining availability*
 
95.3%
 
Return on average capital employed*(d)iv
 
5.8%
 
 
 
(+3.0)
(a) 
BP-operated Upstream plant reliability has been included as an operating metric this quarter. It is more comparable with the equivalent metric disclosed for the Downstream, which is ‘Refining availability’. BP-operated Upstream plant reliability was 94.9% for the first quarter 2017, 95.2% for the six months ended 30 June 2017 and 94.5% for the nine months ended 30 September 2017.
(b) 
SEC regulations do not permit inclusion of this non-GAAP metric in this SEC filing. Operating cash flow excluding Gulf of Mexico oil spill payments is calculated by excluding post-tax expenditure relating to the Gulf of Mexico oil spill from net cash provided by operating activities, as reported in the condensed group cash flow statement. For the full year, net cash provided by operating activities was $18.9 billion and post-tax Gulf of Mexico oil spill expenditure was $5.2 billion.

6

Table of contents

(c) 
Represents dividend announced in the quarter (vs. prior year quarter).
(d) 
Return on average capital employed is included as this is a full year report.


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


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

7

Table of contents

Upstream
 
 
Fourth

Fourth

 




 
 
quarter

quarter

 
Year

Year

$ million
 
2017

2016

 
2017

2016

Profit before interest and tax
 
1,928

711

 
5,229

634

Inventory holding (gains) losses*
 

(19
)
 
(8
)
(60
)
RC profit before interest and tax
 
1,928

692

 
5,221

574

Net (favourable) adverse impact of non-operating items* and fair value accounting effects*
 
295

(292
)
 
644

(1,116
)
Underlying RC profit (loss) before interest and tax*(a)
 
2,223

400

 
5,865

(542
)
(a) 
See page 9 for a reconciliation to segment RC profit before interest and tax by region.

Financial results
The replacement cost profit before interest and tax for the fourth quarter and full year was $1,928 million and $5,221 million respectively, compared with $692 million and $574 million for the same periods in 2016. The fourth quarter and full year included a net non-operating charge of $144 million and $671 million respectively, compared with a net non-operating gain of $636 million and $1,753 million for the same periods in 2016. Fair value accounting effects in the fourth quarter and full year had an adverse impact of $151 million and a favourable impact of $27 million respectively, compared with an adverse impact of $344 million and $637 million in the same periods of 2016.

After adjusting for non-operating items and fair value accounting effects, the underlying replacement cost profit before interest and tax for the fourth quarter and full year was $2,223 million and $5,865 million respectively, compared with a profit of $400 million and a loss of $542 million for the same periods in 2016. The result for the fourth quarter mainly reflected higher liquids realizations and higher production including the impact of the Abu Dhabi onshore concession renewal and major project* start-ups. The result for the full year reflected higher liquids realizations, and higher production including the impact of the Abu Dhabi onshore concession renewal and major project start-ups, partly offset by higher depreciation, depletion and amortization, and higher exploration write-offs.

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

Key events
On 21 November, BP agreed to sell a package of its interests in the Bruce assets in the North Sea to Serica Energy plc, subject to regulatory approvals. The Bruce assets comprise the Bruce, Keith and Rhum fields, platforms and associated subsea infrastructure.
On 18 December, BP completed the formation of Pan American Energy Group (PAEG) (BP 50%, Bridas Corporation 50%), which is a combination of Pan American Energy and Axion Energy.
On 20 December, BP confirmed that production started from the Zohr gas field, offshore Egypt (ENI operator 60%, Rosneft 30%, BP 10%), BP’s seventh major project to start in 2017.
Also on 20 December, BP and Statoil signed an extension agreement for the In Amenas production-sharing contract* with Algerian state-owned energy company Sonatrach, which has been submitted to the Algerian authorities for ratification.
On 21 December, BP and Kosmos Energy (KE) were awarded five blocks offshore Côte d’Ivoire, under agreements with the government of Côte d’Ivoire and state oil company Société Nationale d'Operations Pétrolières de la Côte d'Ivoire (PETROCI) (BP 45%, KE 45%, PETROCI 10%).
In December Rosneft announced an agreement to develop resources within the Kharampurskoe and Festivalnoye licence areas in Yamalo-Nenets Autonomous Okrug in northern Russia jointly with BP. Rosneft will hold a majority stake of 51% and BP will hold a 49% stake. Completion of the deal is subject to regulatory approvals.
On 31 January, BP announced the oil discovery Capercaillie (BP 100%) and the oil discovery Achmelvich (BP 52.6%, Shell 28%, and Chevron 19.4%) in the UK North Sea, both operated by BP. These two discoveries bring the total exploration discoveries in 2017 to six, and our most successful exploration campaign in the UK North Sea since 2008.
Outlook
We expect full-year 2018 underlying production to be higher than 2017 due to the ramp-up of major projects. The actual reported outcome will depend on the exact timing of project start-ups, acquisition and divestment activities, OPEC quotas and entitlement impacts in our production-sharing agreements*. We expect first-quarter 2018 reported production to be broadly flat with the fourth quarter 2017, reflecting continued growth from the 2017 major project start-ups, offset by the expiration of the Abu Dhabi offshore concession and divestment impacts.

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

8

Table of contents

Upstream (continued)
 
 
Fourth

Fourth

 




 
 
quarter

quarter

 
Year

Year

$ million
 
2017

2016

 
2017

2016

Underlying RC profit (loss) before interest and tax
 
 
 
 
 
 
US
 
629

(147
)
 
1,238

(1,270
)
Non-US
 
1,594

547

 
4,627

728

 
 
2,223

400

 
5,865

(542
)
Non-operating items
 
 
 
 
 
 
US(a)
 
(187
)
21

 
(330
)
127

Non-US(b)(c)
 
43

615

 
(341
)
1,626

 
 
(144
)
636

 
(671
)
1,753

Fair value accounting effects
 
 
 
 
 
 
US
 
8

(274
)
 
192

(379
)
Non-US
 
(159
)
(70
)
 
(165
)
(258
)
 
 
(151
)
(344
)
 
27

(637
)
RC profit (loss) before interest and tax
 
 
 
 
 
 
US
 
450

(400
)
 
1,100

(1,522
)
Non-US
 
1,478

1,092

 
4,121

2,096

 
 
1,928

692

 
5,221

574

Exploration expense
 
 
 
 
 
 
US
 
27

511

 
282

693

Non-US(c)(d)
 
494

(197
)
 
1,798

1,028

 
 
521

314

 
2,080

1,721

Of which: Exploration expenditure written off(c)(d)
 
372

166

 
1,603

1,274

Production (net of royalties)(e)
 
 
 
 
 
 
Liquids* (mb/d)
 
 
 
 
 
 
US
 
430

406

 
426

391

Europe
 
117

122

 
119

120

Rest of World
 
796

650

 
811

698

 
 
1,344

1,178

 
1,356

1,208

Of which equity-accounted entities
 
209

210

 
207

184

Natural gas (mmcf/d)
 
 
 
 
 
 
US
 
1,759

1,675

 
1,659

1,656

Europe
 
186

268

 
235

264

Rest of World
 
5,231

3,903

 
4,543

3,876

 
 
7,176

5,846

 
6,436

5,796

Of which equity-accounted entities
 
534

517

 
547

494

Total hydrocarbons* (mboe/d)
 
 
 
 
 
 
US
 
734

694

 
712

676

Europe
 
150

168

 
160

165

Rest of World
 
1,698

1,323

 
1,594

1,366

 
 
2,581

2,186

 
2,466

2,208

Of which equity-accounted entities
 
301

300

 
302

269

Average realizations*(f)
 
 
 
 
 
 
Total liquids(g) ($/bbl)
 
56.16

43.89

 
49.92

38.27

Natural gas ($/mcf)
 
3.23

3.08

 
3.19

2.84

Total hydrocarbons ($/boe)
 
37.48

31.40

 
35.38

28.24

(a) 
Fourth quarter and full year 2017 include an impairment charge relating to the US Lower 48 business, partially offset by gains associated with asset divestments.
(b) 
Fourth quarter and full year 2017 include BP's share of an impairment reversal recognized by the Angola LNG equity-accounted entity, partially offset by other items. In addition, full year 2017 includes an impairment charge arising following the announcement of the agreement to sell the Forties Pipeline System business to INEOS. Fourth quarter and full year 2016 principally relate to impairment reversals in India, Angola and the North Sea.
(c) 
See page 28 for more information on non-operating items.
(d) 
Full year 2017 includes the write-off of exploration well and lease costs in Angola and the write-off of exploration wells in Egypt.
(e) 
Includes BP’s share of production of equity-accounted entities in the Upstream segment.
(f) 
Realizations are based on sales by consolidated subsidiaries only – this excludes equity-accounted entities.
(g) 
Includes condensate, natural gas liquids and bitumen.

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

9

Table of contents

Downstream
 
 
Fourth

Fourth

 




 
 
quarter

quarter

 
Year

Year

$ million
 
2017

2016

 
2017

2016

Profit before interest and tax
 
2,492

1,457

 
7,979

6,646

Inventory holding (gains) losses*
 
(719
)
(558
)
 
(758
)
(1,484
)
RC profit before interest and tax
 
1,773

899

 
7,221

5,162

Net (favourable) adverse impact of non-operating items*
 
 
 
 
 
 
  and fair value accounting effects*
 
(299
)
(22
)
 
(254
)
472

Underlying RC profit before interest and tax*(a)
 
1,474

877

 
6,967

5,634

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

Financial results
The replacement cost profit before interest and tax for the fourth quarter and full year was $1,773 million and $7,221 million respectively, compared with $899 million and $5,162 million for the same periods in 2016.
The fourth quarter and full year include a net non-operating gain of $382 million and $389 million respectively, compared with a net non-operating charge of $77 million and $24 million for the same periods in 2016. Fair value accounting effects had an adverse impact of $83 million in the fourth quarter and $135 million for the full year, compared with a favourable impact of $99 million and an adverse impact of $448 million for the same periods in 2016.
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 $1,474 million and $6,967 million respectively, compared with $877 million and $5,634 million for the same periods in 2016.
Replacement cost profit before interest and tax for the fuels, lubricants and petrochemicals businesses is set out on page 11.
Fuels
The fuels business reported an underlying replacement cost profit before interest and tax of $976 million for the fourth quarter and $4,872 million for the full year, compared with $417 million and $3,727 million for the same periods in 2016. The result for the quarter and full year reflects stronger refining performance. In addition, the full-year improvement reflects growth in fuels marketing, partly offset by a weaker contribution from supply and trading.
The refining result for the quarter and full year reflects continued strong operational performance, capturing higher industry refining margins, efficiency benefits as well as increased commercial optimization including the benefits of higher levels of advantaged feedstock. The full year result was, however, impacted by a higher level of planned turnaround activity.
The fuels marketing result for the full year reflects continued profit growth supported by higher premium fuel volumes which grew by 6% and the continued rollout of our convenience partnership model to more than 220 sites, bringing the total number of convenience partnership sites to 1,100 across our retail network.
We continue to grow in Mexico, where, by the end of 2017 we had more than 120 operational sites after becoming the first international oil company to enter the deregulated fuel retail market earlier in the year.
In December, the Australian Competition and Consumer Commission announced that it intends to oppose our proposed acquisition of Woolworths’ fuel and convenience sites in Australia. We are currently considering our next steps.
On 1 February 2018, we entered into joint ventures with Shandong Dongming Petrochemical Group to develop a leading branded retail fuels and convenience business in Shandong, Henan and Hebei provinces in China.

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

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

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

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


10

Table of contents

Downstream (continued)
 
 
Fourth

Fourth

 




 
 
quarter

quarter

 
Year

Year

$ million
 
2017

2016

 
2017

2016

Underlying RC profit before interest and tax - by region
 
 
 
 
 
 
US
 
501

(371
)
 
1,978

853

Non-US
 
973

1,248

 
4,989

4,781

 
 
1,474

877

 
6,967

5,634

Non-operating items
 
 
 
 
 
 
US
 
(25
)
(122
)
 
(48
)
(48
)
Non-US(a)
 
407

45

 
437

24

 
 
382

(77
)
 
389

(24
)
Fair value accounting effects
 
 
 
 
 
 
US
 
3

22

 
(29
)
(321
)
Non-US
 
(86
)
77

 
(106
)
(127
)
 
 
(83
)
99

 
(135
)
(448
)
RC profit before interest and tax
 
 
 
 
 
 
US
 
479

(471
)
 
1,901

484

Non-US
 
1,294

1,370

 
5,320

4,678

 
 
1,773

899

 
7,221

5,162

 
 
 
 
 
 
 
Underlying RC profit before interest and tax - by business(b)(c)
 
 
 
 
 
 
Fuels
 
976

417

 
4,872

3,727

Lubricants
 
375

357

 
1,479

1,523

Petrochemicals
 
123

103

 
616

384

 
 
1,474

877

 
6,967

5,634

Non-operating items and fair value accounting effects(d)
 
 
 
 
 
 
Fuels
 
(202
)
103

 
(193
)
(390
)
Lubricants
 
(14
)
(81
)
 
(22
)
(84
)
Petrochemicals(a)
 
515


 
469

2

 
 
299

22

 
254

(472
)
RC profit before interest and tax(b)(c)
 
 
 
 
 
 
Fuels
 
774

520

 
4,679

3,337

Lubricants
 
361

276

 
1,457

1,439

Petrochemicals
 
638

103

 
1,085

386

 
 
1,773

899

 
7,221

5,162

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

11.4

 
14.1

11.8

Refinery throughputs (mb/d)
 
 
 
 
 
 
US
 
714

604

 
713

646

Europe
 
741

806

 
773

803

Rest of World
 
243

234

 
216

236

 
 
1,698

1,644

 
1,702

1,685

Refining availability* (%)
 
96.1

94.9

 
95.3

95.3

 
 
 
 
 
 
 
Marketing sales of refined products (mb/d)
 
 
 
 
 
 
US
 
1,127

1,146

 
1,151

1,134

Europe
 
1,132

1,166

 
1,140

1,179

Rest of World
 
542

540

 
508

512

 
 
2,801

2,852

 
2,799

2,825

Trading/supply sales of refined products
 
3,549

2,836

 
3,149

2,775

Total sales volumes of refined products
 
6,350

5,688

 
5,948

5,600

 
 
 
 
 
 
 
Petrochemicals production (kte)
 
 
 
 
 
 
US
 
641

546

 
2,428

2,564

Europe
 
1,559

930

 
5,462

3,729

Rest of World
 
1,306

2,071

 
7,405

7,934

 
 
3,506

3,547

 
15,295

14,227

(a) 
Fourth quarter and full year 2017 gain primarily reflects the disposal of our shareholding in the SECCO joint venture.
(b) 
Segment-level overhead expenses are included in the fuels business result.
(c) 
Results from petrochemicals at our Gelsenkirchen and Mülheim sites in Germany is reported in the fuels business.
(d) 
For Downstream, fair value accounting effects arise solely in the fuels business.


11

Table of contents

Rosneft
 
 
Fourth

Fourth

 




 
 
quarter

quarter

 
Year

Year

$ million
 
2017(a)

2016

 
2017(a)

2016

Profit before interest and tax(b)
 
418

182

 
923

643

Inventory holding (gains) losses*
 
(97
)
(24
)
 
(87
)
(53
)
RC profit before interest and tax
 
321

158

 
836

590

Net charge (credit) for non-operating items*
 

(23
)
 

(23
)
Underlying RC profit before interest and tax*
 
321

135

 
836

567


Financial results
Replacement cost profit before interest and tax for the fourth quarter and full year was $321 million and $836 million respectively, compared with $158 million and $590 million for the same periods in 2016.
There were no non-operating items in the fourth quarter and full year of 2017, compared with a non-operating gain of $23 million in the same periods of 2016.
After adjusting for non-operating items, the underlying replacement cost profit before interest and tax for the fourth quarter and full year was $321 million and $836 million respectively, compared with $135 million and $567 million for the same periods in 2016.
Compared with the same periods in 2016, the results primarily reflected higher oil prices. The results for the fourth quarter and the full year also benefited from a $163-million gain representing the BP share of a voluntary out-of-court settlement between Sistema, Sistema-Invest and the Rosneft subsidiary, Bashneft. These positive effects were partially offset by adverse foreign exchange effects.
In September 2017 the extraordinary general meeting adopted a resolution to pay interim dividends for the first half of 2017 of 3.83 Russian roubles per ordinary share. In October BP received a dividend of $124 million after the deduction of withholding tax.
Key events
In October Rosneft completed the acquisition of a 30% stake for $1.1 billion in a concession agreement to develop the Zohr field in Egypt from the Italian company Eni. Eni retains a 60% stake and BP holds the remaining 10%.
In December Rosneft announced an agreement to develop subsoil resources within the Kharampurskoe and Festivalnoye licence areas in Yamalo-Nenets Autonomous Okrug in northern Russia jointly with BP. Rosneft will hold a majority stake of 51% and BP will hold a 49% stake. Completion of the deal is subject to regulatory approvals.

 
 
Fourth

Fourth

 




 
 
quarter

quarter

 
Year

Year

 
 
2017(a)

2016

 
2017(a)

2016

Production (net of royalties) (BP share)
 
 
 
 
 
 
Liquids* (mb/d)
 
899

919

 
904

840

Natural gas (mmcf/d)
 
1,333

1,347

 
1,308

1,279

Total hydrocarbons* (mboe/d)
 
1,129

1,152

 
1,129

1,060

(a) 
The operational and financial information of the Rosneft segment for the fourth quarter and full year is based on preliminary operational and financial results of Rosneft for the full year ended 31 December 2017. Actual results may differ from these amounts.
(b) 
The Rosneft segment result includes equity-accounted earnings arising from BP’s 19.75% shareholding in Rosneft as adjusted for the accounting required under IFRS relating to BP’s purchase of its interest in Rosneft and the amortization of the deferred gain relating to the divestment of BP’s interest in TNK-BP. These adjustments have increased the reported profit before interest and tax for the fourth quarter and full year 2017, as shown in the table above, compared with the equivalent amount in Russian roubles that we expect Rosneft to report in its own financial statements under IFRS. BP’s share of Rosneft’s profit before interest and tax for each year-to-date period is calculated by translating the amounts reported in Russian roubles into US dollars using the average exchange rate for the year to date. BP's share of Rosneft’s earnings after finance costs, taxation and non-controlling interests, as adjusted, is included in the BP group income statement within profit before interest and taxation.


12

Table of contents

Other businesses and corporate
 
 
Fourth

Fourth

 




 
 
quarter

quarter

 
Year

Year

$ million
 
2017

2016

 
2017

2016

Profit (loss) before interest and tax
 
 
 
 
 
 
Gulf of Mexico oil spill
 
(2,221
)
(674
)
 
(2,687
)
(6,640
)
Other
 
(612
)
(443
)
 
(1,758
)
(1,517
)
Profit (loss) before interest and tax
 
(2,833
)
(1,117
)
 
(4,445
)
(8,157
)
Inventory holding (gains) losses*
 


 


RC profit (loss) before interest and tax
 
(2,833
)
(1,117
)
 
(4,445
)
(8,157
)
Net charge (credit) for non-operating items*
 
 
 
 
 
 
Gulf of Mexico oil spill
 
2,221

674

 
2,687

6,640

Other
 
218

19

 
160

279

Net charge (credit) for non-operating items
 
2,439

693

 
2,847

6,919

Underlying RC profit (loss) before interest and tax*
 
(394
)
(424
)
 
(1,598
)
(1,238
)
Underlying RC profit (loss) before interest and tax
 
 
 
 
 
 
US
 
(29
)
50

 
(475
)
(276
)
Non-US
 
(365
)
(474
)
 
(1,123
)
(962
)
 
 
(394
)
(424
)
 
(1,598
)
(1,238
)
Non-operating items
 
 
 
 
 
 
US
 
(2,381
)
(672
)
 
(2,861
)
(6,824
)
Non-US
 
(58
)
(21
)
 
14

(95
)
 
 
(2,439
)
(693
)
 
(2,847
)
(6,919
)
RC profit (loss) before interest and tax
 
 
 
 
 
 
US
 
(2,410
)
(622
)
 
(3,336
)
(7,100
)
Non-US
 
(423
)
(495
)
 
(1,109
)
(1,057
)
 
 
(2,833
)
(1,117
)
 
(4,445
)
(8,157
)

Other businesses and corporate comprises our alternative energy business, shipping, treasury, corporate activities including centralized functions, and the costs of the Gulf of Mexico oil spill.
Financial results
The replacement cost loss before interest and tax for the fourth quarter and full year was $2,833 million and $4,445 million respectively, compared with $1,117 million and $8,157 million for the same periods in 2016.
The results included a net non-operating charge of $2,439 million for the fourth quarter and $2,847 million for the full year, mainly relating to the Gulf of Mexico oil spill, compared with a net non-operating charge of $693 million and $6,919 million for the same periods in 2016. See Note 2 on page 19 for more information on the Gulf of Mexico oil spill.
After adjusting for non-operating items, the underlying replacement cost loss before interest and tax for the fourth quarter and full year was $394 million and $1,598 million respectively, compared with $424 million and $1,238 million for the same periods in 2016. The underlying charge for the full year was impacted by weaker business results, higher corporate costs and adverse foreign exchange effects which had a favourable effect in 2016.
Alternative energy
The net ethanol-equivalent production (which includes ethanol and sugar) for the fourth quarter and full year was 188 million litres and 776 million litres respectively, compared with 98 million litres and 733 million litres for the same periods in 2016.
Net wind generation capacity*(a) was 1,432MW at 31 December 2017 compared with 1,474MW at 31 December 2016. BP’s net share of wind generation for the fourth quarter and full year was 1,148GWh and 4,004GWh respectively, compared with 1,154GWh and 4,389GWh for the same periods in 2016.
(a) 
Capacity figures for 2016 include 23MW in the Netherlands managed by our Downstream segment.

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

Outlook
In 2018, Other businesses and corporate average quarterly charges, excluding non-operating items, are expected to be around $350 million although this will fluctuate from quarter to quarter.
The commentary above contains forward-looking statements and should be read in conjunction with the cautionary statement on page 37.


13

Table of contents

Financial statements
Group income statement
 
 
Fourth

Fourth

 




 
 
quarter

quarter

 
Year

Year

$ million
 
2017

2016

 
2017

2016

 
 
 
 
 
 
 
Sales and other operating revenues (Note 4)
 
67,816

51,007

 
240,208

183,008

Earnings from joint ventures - after interest and tax
 
581

489

 
1,177

966

Earnings from associates - after interest and tax
 
526

263

 
1,330

994

Interest and other income
 
223

114

 
657

506

Gains on sale of businesses and fixed assets
 
876

248

 
1,210

1,132

Total revenues and other income
 
70,022

52,121

 
244,582

186,606

Purchases(a)
 
51,745

37,883

 
179,716

132,219

Production and manufacturing expenses(b)
 
7,759

6,595

 
24,229

29,077

Production and similar taxes (Note 5)(a)
 
511

199

 
1,775

683

Depreciation, depletion and amortization (Note 4)
 
4,045

3,642

 
15,584

14,505

Impairment and losses on sale of businesses and fixed assets
 
604

(305
)
 
1,216

(1,664
)
Exploration expense
 
521

314

 
2,080

1,721

Distribution and administration expenses
 
2,981

2,692

 
10,508

10,495

Profit (loss) before interest and taxation
 
1,856

1,101

 
9,474

(430
)
Finance costs(b)
 
616

434

 
2,074

1,675

Net finance expense relating to pensions and other post retirement benefits
 
58

50

 
220

190

Profit (loss) before taxation
 
1,182

617

 
7,180

(2,295
)
Taxation(b)
 
1,119

74

 
3,712

(2,467
)
Profit (loss) for the period
 
63

543

 
3,468

172

Attributable to
 
 
 
 
 
 
  BP shareholders
 
27

497

 
3,389

115

  Non-controlling interests
 
36

46

 
79

57

 
 
63

543

 
3,468

172

 
 
 
 
 
 
 
Earnings per share (Note 6)
 
 
 
 
 
 
Profit (loss) for the period attributable to BP shareholders
 
 
 
 
 
 
  Per ordinary share (cents)
 
 
 
 
 
 
    Basic
 
0.14

2.62

 
17.20

0.61

    Diluted
 
0.14

2.60

 
17.10

0.60

  Per ADS (dollars)
 
 
 
 
 
 
    Basic
 
0.01

0.16

 
1.03

0.04

    Diluted
 
0.01

0.16

 
1.03

0.04

(a) 
Amounts reported in prior quarters of 2017 for Purchases and Production and similar taxes have been amended, with no effect on profit for the period. See Note 5 for further information.
(b) 
See Note 2 for information on the impact of the Gulf of Mexico oil spill on these income statement line items.


14

Table of contents

Group statement of comprehensive income
 
 
Fourth

Fourth

 




 
 
quarter

quarter

 
Year

Year

$ million
 
2017

2016

 
2017

2016

 
 
 
 
 
 
 
Profit (loss) for the period
 
63

543

 
3,468

172

Other comprehensive income
 
 
 
 
 
 
Items that may be reclassified subsequently to profit or loss
 
 
 
 
 
 
  Currency translation differences
 
264

(777
)
 
1,986

254

  Exchange (gains) losses on translation of foreign operations reclassified to gain
 
 
 
 
 
 
     or loss on sale of businesses and fixed assets
 
(138
)
24

 
(120
)
30

  Available-for-sale investments
 
11


 
14

1

  Cash flow hedges marked to market
 
19

(204
)
 
197

(639
)
  Cash flow hedges reclassified to the income statement
 
23

86

 
116

196

  Cash flow hedges reclassified to the balance sheet
 
8

32

 
112

81

  Share of items relating to equity-accounted entities, net of tax
 
133

172

 
564

833

  Income tax relating to items that may be reclassified
 
(81
)
97

 
(261
)
13

 
 
239

(570
)
 
2,608

769

Items that will not be reclassified to profit or loss
 
 
 
 
 
 
  Remeasurements of the net pension and other post-retirement
 
 
 
 
 
 
    benefit liability or asset
 
1,599

3,484

 
3,646

(2,496
)
  Income tax relating to items that will not be reclassified
 
(539
)
(765
)
 
(1,238
)
739

 
 
1,060

2,719

 
2,408

(1,757
)
Other comprehensive income
 
1,299

2,149

 
5,016

(988
)
Total comprehensive income
 
1,362

2,692

 
8,484

(816
)
Attributable to
 
 
 
 
 
 
  BP shareholders
 
1,312

2,667

 
8,353

(846
)
  Non-controlling interests
 
50

25

 
131

30

 
 
1,362

2,692

 
8,484

(816
)

15

Table of contents

Group statement of changes in equity
 
 
BP shareholders’

Non-controlling

Total

$ million
 
equity

interests

equity

 
 
 
 
 
At 1 January 2017
 
95,286

1,557

96,843

 
 
 
 
 
Total comprehensive income
 
8,353

131

8,484

Dividends
 
(6,153
)
(141
)
(6,294
)
Repurchase of ordinary share capital
 
(343
)

(343
)
Share-based payments, net of tax
 
687


687

Share of equity-accounted entities’ changes in equity, net of tax
 
215


215

Transactions involving non-controlling interests, net of tax
 
446

366

812

At 31 December 2017
 
98,491

1,913

100,404

 
 
 
 
 
 
 
BP shareholders’

Non-controlling

Total

$ million
 
equity

interests

equity

 
 
 
 
 
At 1 January 2016
 
97,216

1,171

98,387

 
 
 
 
 
Total comprehensive income
 
(846
)
30

(816
)
Dividends
 
(4,611
)
(107
)
(4,718
)
Share-based payments, net of tax
 
2,991


2,991

Share of equity-accounted entities' changes in equity, net of tax
 
106


106

Transactions involving non-controlling interests, net of tax
 
430

463

893

At 31 December 2016
 
95,286

1,557

96,843


16

Table of contents

Group balance sheet
 
 
31 December

31 December

$ million
 
2017

2016

Non-current assets
 
 
 
Property, plant and equipment
 
129,471

129,757

Goodwill
 
11,551

11,194

Intangible assets
 
18,355

18,183

Investments in joint ventures
 
7,994

8,609

Investments in associates
 
16,991

14,092

Other investments
 
1,245

1,033

Fixed assets
 
185,607

182,868

Loans
 
646

532

Trade and other receivables
 
1,434

1,474

Derivative financial instruments
 
4,110

4,359

Prepayments
 
1,112

945

Deferred tax assets
 
4,469

4,741

Defined benefit pension plan surpluses
 
4,169

584

 
 
201,547

195,503

Current assets
 
 
 
Loans
 
190

259

Inventories
 
19,011

17,655

Trade and other receivables
 
24,849

20,675

Derivative financial instruments
 
3,032

3,016

Prepayments
 
1,414

1,486

Current tax receivable
 
761

1,194

Other investments
 
125

44

Cash and cash equivalents
 
25,586

23,484

 
 
74,968

67,813

Total assets
 
276,515

263,316

Current liabilities
 
 
 
Trade and other payables
 
44,209

37,915

Derivative financial instruments
 
2,808

2,991

Accruals
 
4,960

5,136

Finance debt
 
7,739

6,634

Current tax payable
 
1,686

1,666

Provisions
 
3,324

4,012

 
 
64,726

58,354

Non-current liabilities
 
 
 
Other payables
 
13,889

13,946

Derivative financial instruments
 
3,761

5,513

Accruals
 
505

469

Finance debt
 
55,491

51,666

Deferred tax liabilities
 
7,982

7,238

Provisions
 
20,620

20,412

Defined benefit pension plan and other post-retirement benefit plan deficits
 
9,137

8,875

 
 
111,385

108,119

Total liabilities
 
176,111

166,473

Net assets
 
100,404

96,843

Equity
 
 
 
BP shareholders’ equity
 
98,491

95,286

Non-controlling interests
 
1,913

1,557

Total equity
 
100,404

96,843



17

Table of contents

Condensed group cash flow statement
 
 
Fourth

Fourth

 




 
 
quarter

quarter

 
Year

Year

$ million
 
2017

2016

 
2017

2016

Operating activities
 
 
 
 
 
 
Profit (loss) before taxation
 
1,182

617

 
7,180

(2,295
)
Adjustments to reconcile profit (loss) before taxation to net cash
 
 
 
 
 
 
  provided by operating activities
 
 
 
 
 
 
  Depreciation, depletion and amortization and exploration expenditure
 
 
 
 
 
 
    written off
 
4,417

3,808

 
17,187

15,779

  Impairment and (gain) loss on sale of businesses and fixed assets
 
(272
)
(553
)
 
6

(2,796
)
  Earnings from equity-accounted entities, less dividends received
 
(820
)
(605
)
 
(1,254
)
(855
)
  Net charge for interest and other finance expense, less net interest paid
 
294

310

 
793

795

  Share-based payments
 
166

150

 
661

779

  Net operating charge for pensions and other post-retirement benefits, less
 
 
 
 
 
 
    contributions and benefit payments for unfunded plans
 
(215
)
(347
)
 
(394
)
(467
)
  Net charge for provisions, less payments
 
2,244

(629
)
 
2,106

4,487

  Movements in inventories and other current and non-current assets and
 
 
 
 
 
 
    liabilities
 
(60
)
393

 
(3,352
)
(3,198
)
  Income taxes paid
 
(1,033
)
(716
)
 
(4,002
)
(1,538
)
Net cash provided by operating activities
 
5,903

2,428

 
18,931

10,691

Investing activities
 
 
 
 
 
 
Expenditure on property, plant and equipment, intangible and other assets
 
(4,422
)
(4,658
)
 
(16,562
)
(16,701
)
Acquisitions, net of cash acquired
 
(16
)
(1
)
 
(327
)
(1
)
Investment in joint ventures
 
(15
)
(37
)
 
(50
)
(50
)
Investment in associates
 
(368
)
(226
)
 
(901
)
(700
)
Total cash capital expenditure
 
(4,821
)
(4,922
)
 
(17,840
)
(17,452
)
Proceeds from disposal of fixed assets
 
2,287

391

 
2,936

1,372

Proceeds from disposal of businesses, net of cash disposed
 
173

78

 
478

1,259

Proceeds from loan repayments
 
8

7

 
349

68

Net cash used in investing activities
 
(2,353
)
(4,446
)
 
(14,077
)
(14,753
)
Financing activities
 
 
 
 
 
 
Net issue (repurchase) of shares
 
(343
)

 
(343
)

Proceeds from long-term financing
 
201

3,069

 
8,712

12,442

Repayments of long-term financing
 
(2,657
)
(1,733
)
 
(6,276
)
(6,685
)
Net increase (decrease) in short-term debt
 
(297
)
375

 
(158
)
51

Net increase (decrease) in non-controlling interests
 
982

126

 
1,063

887

Dividends paid - BP shareholders
 
(1,627
)
(1,182
)
 
(6,153
)
(4,611
)
 - non-controlling interests
 
(32
)
(24
)
 
(141
)
(107
)
Net cash provided by (used in) financing activities
 
(3,773
)
631

 
(3,296
)
1,977

Currency translation differences relating to cash and cash equivalents
 
29

(649
)
 
544

(820
)
Increase (decrease) in cash and cash equivalents
 
(194
)
(2,036
)
 
2,102

(2,905
)
Cash and cash equivalents at beginning of period
 
25,780

25,520

 
23,484

26,389

Cash and cash equivalents at end of period
 
25,586

23,484

 
25,586

23,484


18

Table of contents

Notes
Note 1. Basis of preparation

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

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

The financial information presented herein has been prepared in accordance with the accounting policies expected to be used in preparing BP Annual Report and Form 20-F 2017, which do not differ significantly from those used in BP Annual Report and Form 20-F 2016.
Note 2. Gulf of Mexico oil spill

(a) Overview
The information presented in this note should be read in conjunction with BP Annual Report and Form 20-F 2016 - Financial statements - Note 2 and Legal proceedings on page 261.
The group income statement includes a post-tax charge for the fourth quarter of $1,693 million due to an increase in the provision relating to business economic loss (BEL) and other claims associated with the Deepwater Horizon Court Supervised Settlement Program (DHCSSP). The increase in the provision is primarily a result of significantly higher average claims determinations issued by the DHCSSP in the fourth quarter and the continuing effect of the Fifth Circuit’s May 2017 opinion on the matching of revenues with expenses when evaluating BEL claims.
The group income statement for the fourth quarter also includes finance costs relating to the unwinding of discounting effects and a tax charge of $3,012 million in respect of the revaluation of US deferred tax assets related to the Gulf of Mexico oil spill following the reduction in the US federal corporate income tax rate from 35% to 21% enacted in December 2017.
The amounts set out below reflect the impacts on the financial statements of the Gulf of Mexico oil spill for the periods presented. The income statement, balance sheet and cash flow statement impacts are included within the relevant line items in those statements as set out below.
 
 
Fourth

Fourth

 




 
 
quarter

quarter

 
Year

Year

$ million
 
2017

2016

 
2017

2016

Income statement
 
 
 
 
 
 
Production and manufacturing expenses
 
2,221

674

 
2,687

6,640

Profit (loss) before interest and taxation
 
(2,221
)
(674
)
 
(2,687
)
(6,640
)
Finance costs
 
124

125

 
493

494

Profit (loss) before taxation
 
(2,345
)
(799
)
 
(3,180
)
(7,134
)
Taxation
 
(2,495
)
268

 
(2,222
)
3,105

Profit (loss) for the period
 
(4,840
)
(531
)
 
(5,402
)
(4,029
)
The cumulative pre-tax income statement charge since the incident, in April 2010, amounts to $65,765 million.


19

Table of contents

Note 2. Gulf of Mexico oil spill (continued)
 
 
31 December

31 December

$ million
 
2017

2016

Balance sheet
 
 
 
Current assets
 
 
 
  Trade and other receivables
 
252

194

Current liabilities
 
 
 
  Trade and other payables
 
(2,089
)
(3,056
)
  Provisions
 
(1,439
)
(2,330
)
Net current assets (liabilities)
 
(3,276
)
(5,192
)
Non-current assets
 
 
 
  Deferred tax assets
 
2,067

2,973

Non-current liabilities
 
 
 
  Other payables
 
(12,253
)
(13,522
)
  Provisions
 
(1,141
)
(112
)
  Deferred tax liabilities
 
3,634

5,119

Net non-current assets (liabilities)
 
(7,693
)
(5,542
)
Net assets (liabilities)
 
(10,969
)
(10,734
)

 
 
Fourth

Fourth

 




 
 
quarter

quarter

 
Year

Year

$ million
 
2017

2016

 
2017

2016

Cash flow statement - Operating activities
 
 
 
 
 
 
Profit (loss) before taxation
 
(2,345
)
(799
)
 
(3,180
)
(7,134
)
Adjustments to reconcile profit (loss) before taxation to net cash provided by operating activities
 
 
 
 
 
 
Net charge for interest and other finance expense, less net interest paid
 
124

125

 
493

494

Net charge for provisions, less payments
 
2,181

(376
)
 
2,542

4,353

Movements in inventories and other current and non-current assets and liabilities
 
(413
)
(993
)
 
(5,191
)
(4,818
)
Pre-tax cash flows
 
(453
)
(2,043
)
 
(5,336
)
(7,105
)

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

20

Table of contents

Note 2. Gulf of Mexico oil spill (continued)

(b) Provisions and other payables

Provisions

Movements in the remaining provision, which relates to litigation and claims, are shown in the table below.
$ million 
 
 
At 1 October 2017
 
726

Increase in provision
 
2,210

Reclassified to other payables
 
(50
)
Utilization
 
(306
)
At 31 December 2017
 
2,580

Movements in the remaining provision for the full year are shown in the table below.
$ million 
 
 
At 1 January 2017
 
2,442

Increase in provision
 
2,647

Reclassified to other payables
 
(759
)
Utilization
 
(1,750
)
At 31 December 2017
 
2,580

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

PSC settlement
The provision for the cost associated with the 2012 Plaintiffs’ Steering Committee (PSC) settlement reflects the latest estimate for claims, including business economic loss claims and associated administration costs. However, the amounts ultimately payable may differ from the amount provided and the timing of payments is uncertain.
The increase in the provision in the quarter is primarily a result of significantly higher average claims determinations issued by the Deepwater Horizon Court Supervised Settlement Program (settlement programme) during the fourth quarter and the continuing effect of the May 2017 Fifth Circuit opinion on the policy addressing the matching of revenue with expenses in relation to business economic loss claims. See Legal proceedings on page 33 for further details on the May 2017 Fifth Circuit opinion and related appeals.
The settlement programme’s determination of business economic loss claims was substantially completed by the end of 2017. Nevertheless, a significant number of business economic loss claims determined by the settlement programme have been and continue to be appealed by BP and/or the claimants, with the total value of claims under appeal or eligible for appeal approximately doubling during the fourth quarter. The provision at the end of the year reflects the latest estimate of the amounts that are expected ultimately to be paid to resolve these claims. Depending upon the resolution of these claims (including how such resolution may be impacted by the May 2017 Fifth Circuit opinion), the amounts payable may differ from those currently provided.
The settlement programme is expected to issue determinations with respect to the remaining business economic loss claims in the first half of 2018. Whilst BP has a better understanding of the total population of remaining claims, there is uncertainty around how these claims will ultimately be determined, including in relation to the impact of the May 2017 Fifth Circuit opinion on the determination of the business economic claims.
Payments to resolve outstanding claims under the PSC settlement are now expected to be made over a number of years. The timing of payments, however, is uncertain, and, in particular, will be impacted by how long it takes to resolve claims that have been appealed and may be appealed in the future.

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

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


21

Table of contents

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

Fourth

 




 
 
quarter

quarter

 
Year

Year

$ million
 
2017

2016

 
2017

2016

Upstream
 
1,928

692

 
5,221

574

Downstream
 
1,773

899

 
7,221

5,162

Rosneft
 
321

158

 
836

590

Other businesses and corporate(a)
 
(2,833
)
(1,117
)
 
(4,445
)
(8,157
)
 
 
1,189

632

 
8,833

(1,831
)
Consolidation adjustment - UPII*
 
(149
)
(132
)
 
(212
)
(196
)
RC profit (loss) before interest and tax*
 
1,040

500

 
8,621

(2,027
)
Inventory holding gains (losses)*
 
 
 
 
 
 
  Upstream
 

19

 
8

60

  Downstream
 
719

558

 
758

1,484

  Rosneft (net of tax)
 
97

24

 
87

53

Profit (loss) before interest and tax
 
1,856

1,101

 
9,474

(430
)
Finance costs
 
616

434

 
2,074

1,675

Net finance expense relating to pensions and other
 
 
 
 
 
 
  post-retirement benefits
 
58

50

 
220

190

Profit (loss) before taxation
 
1,182

617

 
7,180

(2,295
)
 
 
 
 
 
 
 
RC profit (loss) before interest and tax*
 
 
 
 
 
 
US
 
(1,509
)
(1,646
)
 
(266
)
(8,311
)
Non-US
 
2,549

2,146

 
8,887

6,284

 
 
1,040

500

 
8,621

(2,027
)
(a) 
Includes costs related to the Gulf of Mexico oil spill. See Note 2 for further information.








22

Table of contents

Note 4. Segmental analysis
Sales and other operating revenues
 
Fourth

Fourth

 




 
 
quarter

quarter

 
Year

Year

$ million
 
2017

2016

 
2017

2016

By segment
 
 
 
 
 
 
Upstream
 
12,651

9,129

 
45,440

33,188

Downstream
 
62,697

46,834

 
219,853

167,683

Other businesses and corporate
 
480

424

 
1,469

1,667

 
 
75,828

56,387

 
266,762

202,538

 
 
 
 
 
 
 
Less: sales and other operating revenues between segments
 
 
 
 
 
 
Upstream
 
6,929

4,695

 
24,179

17,581

Downstream
 
913

523

 
1,800

1,291

Other businesses and corporate
 
170

162

 
575

658

 
 
8,012

5,380

 
26,554

19,530

 
 
 
 
 
 
 
Third party sales and other operating revenues
 
 
 
 
 
 
Upstream
 
5,722

4,434

 
21,261

15,607

Downstream
 
61,784

46,311

 
218,053

166,392

Other businesses and corporate
 
310

262

 
894

1,009

Total sales and other operating revenues
 
67,816

51,007

 
240,208

183,008

 
 
 
 
 
 
 
By geographical area
 
 
 
 
 
 
US
 
24,127

18,642

 
88,709

68,772

Non-US
 
50,778

37,381

 
176,113

128,771

 
 
74,905

56,023

 
264,822

197,543

Less: sales and other operating revenues between areas
 
7,089

5,016

 
24,614

14,535

 
 
67,816

51,007

 
240,208

183,008


Depreciation, depletion and amortization
 
Fourth

Fourth

 




 
 
quarter

quarter

 
Year

Year

$ million
 
2017

2016

 
2017

2016

Upstream
 
 
 
 
 
 
US
 
1,107

1,216

 
4,631

4,396

Non-US
 
2,339

1,859

 
8,637

7,835

 
 
3,446

3,075

 
13,268

12,231

Downstream
 
 
 
 
 
 
US
 
218

219

 
875

856

Non-US
 
301

273

 
1,141

1,094

 
 
519

492

 
2,016

1,950

Other businesses and corporate
 
 
 
 
 
 
US
 
16

20

 
65

71

Non-US
 
64

55

 
235

253

 
 
80

75

 
300

324

Total group
 
4,045

3,642

 
15,584

14,505



23

Table of contents

Note 5. Production and similar taxes
 
 
Fourth

Fourth

 




 
 
quarter

quarter

 
Year

Year

$ million
 
2017

2016

 
2017

2016

US
 
44

38

 
52

155

Non-US(a)
 
467

161

 
1,723

528

 
 
511

199

 
1,775

683

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

Note 6. Earnings per share and shares in issue

Basic earnings per ordinary share (EpS) amounts are calculated by dividing the profit (loss) for the period attributable to ordinary shareholders by the weighted average number of ordinary shares outstanding during the period. During the quarter the company repurchased 51 million ordinary shares for a total consideration of $343 million, including transaction costs of $2 million, as part of the share buyback programme as announced on 31 October 2017. The number of shares in issue is reduced when shares are repurchased.
The calculation of EpS is performed separately for each discrete quarterly period, and for the year-to-date period. As a result, the sum of the discrete quarterly EpS amounts in any particular year-to-date period may not be equal to the EpS amount for the year-to-date period.
For the diluted EpS calculation the weighted average number of shares outstanding during the period is adjusted for the number of shares that are potentially issuable in connection with employee share-based payment plans using the treasury stock method.
 
 
Fourth

Fourth

 




 
 
quarter

quarter

 
Year

Year

$ million
 
2017

2016

 
2017

2016

Results for the period
 
 
 
 
 
 
Profit (loss) for the period attributable to BP shareholders
 
27

497

 
3,389

115

Less: preference dividend
 


 
1

1

Profit (loss) attributable to BP ordinary shareholders
 
27

497

 
3,388

114

 
 
 
 
 
 
 
Number of shares (thousand)(a)
 
 
 
 
 
 
Basic weighted average number of shares outstanding
 
19,804,932

18,995,725

 
19,692,613

18,744,800

ADS equivalent
 
3,300,822

3,165,954

 
3,282,102

3,124,133

 
 
 
 
 
 
 
Weighted average number of shares outstanding used to
 
 
 
 
 
 
  calculate diluted earnings per share
 
19,929,655

19,107,599

 
19,816,442

18,855,319

ADS equivalent
 
3,321,609

3,184,599

 
3,302,740

3,142,553

 
 
 
 
 
 
 
Shares in issue at period-end
 
19,817,325

19,438,990

 
19,817,325

19,438,990

ADS equivalent
 
3,302,887

3,239,831

 
3,302,887

3,239,831

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

24

Table of contents

Note 7. Dividends

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

Fourth

 




 
 
quarter

quarter

 
Year

Year

 
 
2017

2016

 
2017

2016

Dividends paid per ordinary share
 
 
 
 
 
 
  cents
 
10.000

10.000

 
40.000

40.000

  pence
 
7.443

7.931

 
30.979

29.418

Dividends paid per ADS (cents)
 
60.00

60.00

 
240.00

240.00

Scrip dividends
 
 
 
 
 
 
Number of shares issued (millions)
 
53.3

129.2

 
289.8

548.0

Value of shares issued ($ million)
 
354

710

 
1,714

2,858

Note 8. Net Debt*
Net debt ratio*
 
Fourth

Fourth

 




 
 
quarter

quarter

 
Year

Year

$ million
 
2017

2016

 
2017

2016

Gross debt
 
63,230

58,300

 
63,230

58,300

Fair value (asset) liability of hedges related to finance debt(a)
 
175

697

 
175

697

 
 
63,405

58,997

 
63,405

58,997

Less: cash and cash equivalents
 
25,586

23,484

 
25,586

23,484

Net debt
 
37,819

35,513

 
37,819

35,513

Equity
 
100,404

96,843

 
100,404

96,843

Net debt ratio
 
27.4%
26.8%
 
27.4%
26.8%

Analysis of changes in net debt
 
Fourth

Fourth

 




 
 
quarter

quarter

 
Year

Year

$ million
 
2017

2016

 
2017

2016

Opening balance
 
 
 
 
 
 
Finance debt
 
65,784

58,997

 
58,300

53,168

Fair value (asset) liability of hedges related to finance debt(a)
 
(227
)
(1,113
)
 
697

379

Less: cash and cash equivalents
 
25,780

25,520

 
23,484

26,389

Opening net debt
 
39,777

32,364

 
35,513

27,158

Closing balance
 
 
 
 
 
 
Finance debt
 
63,230

58,300

 
63,230

58,300

Fair value (asset) liability of hedges related to finance debt(a)
 
175

697

 
175

697

Less: cash and cash equivalents
 
25,586

23,484

 
25,586

23,484

Closing net debt
 
37,819

35,513

 
37,819

35,513

Decrease (increase) in net debt
 
1,958

(3,149
)
 
(2,306
)
(8,355
)
Movement in cash and cash equivalents
 
 
 
 
 
 
  (excluding exchange adjustments)
 
(223
)
(1,387
)
 
1,558

(2,085
)
Net cash outflow (inflow) from financing(b)
 
2,753

(1,711
)
 
(2,278
)
(5,808
)
Other movements
 
(299
)
(146
)
 
(564
)
278

Movement in net debt before exchange effects
 
2,231

(3,244
)
 
(1,284
)
(7,615
)
Exchange adjustments
 
(273
)
95

 
(1,022
)
(740
)
Decrease (increase) in net debt
 
1,958

(3,149
)
 
(2,306
)
(8,355
)
(a) 
Derivative financial instruments entered into for the purpose of managing interest rate and foreign currency exchange risk associated with net debt with a fair value liability position of $634 million (fourth quarter 2016 liability of $1,962 million) are not included in the calculation of net debt shown above as hedge accounting is not applied for these instruments.
(b) 
Comprises proceeds and repayments of long-term financing and net (increase) decrease in short-term debt.

25

Table of contents

Note 9. Inventory valuation

A provision of $474 million was held at 31 December 2017 ($501 million at 31 December 2016) to write inventories down to their net realizable value. The net movement credited to the income statement during the fourth quarter 2017 was $24 million (fourth quarter 2016 was a charge of $13 million).
Note 10. Statutory accounts

The financial information shown in this publication, which was approved by the Board of Directors on 5 February 2018, is unaudited and does not constitute statutory financial statements. Audited financial information will be published in BP Annual Report and Form 20-F 2017.

26

Table of contents

Additional information
Capital expenditure*
 
 
Fourth

Fourth

 




 
 
quarter

quarter

 
Year

Year

$ million
 
2017

2016

 
2017

2016

Capital expenditure on a cash basis
 
 
 
 
 
 
Organic capital expenditure*
 
4,622

4,473

 
16,501

16,675

Inorganic capital expenditure*(a)
 
199

449

 
1,339

777

 
 
4,821

4,922

 
17,840

17,452


 
 
Fourth

Fourth

 




 
 
quarter

quarter

 
Year

Year

$ million
 
2017

2016

 
2017

2016

Organic capital expenditure by segment
 
 
 
 
 
 
Upstream
 
 
 
 
 
 
US
 
726

602

 
2,999

3,415

Non-US
 
2,819

2,918

 
10,764

10,929

 
 
3,545

3,520

 
13,763

14,344

Downstream
 
 
 
 
 
 
US
 
349

303

 
809

774

Non-US
 
598

530

 
1,590

1,328

 
 
947

833

 
2,399

2,102

Other businesses and corporate
 
 
 
 
 
 
US
 
30

25

 
64

32

Non-US
 
100

95

 
275

197

 
 
130

120

 
339

229

 
 
4,622

4,473

 
16,501

16,675

Organic capital expenditure by geographical area
 
 
 
 
 
 
US
 
1,105

930

 
3,872

4,221

Non-US
 
3,517

3,543

 
12,629

12,454

 
 
4,622

4,473

 
16,501

16,675

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

27

Table of contents

Non-operating items*
 
 
Fourth

Fourth

 




 
 
quarter

quarter

 
Year

Year

$ million
 
2017

2016

 
2017

2016

Upstream
 
 
 
 
 
 
Impairment and gain (loss) on sale of businesses and fixed assets(a)(b)
 
(181
)
479

 
(563
)
2,391

Environmental and other provisions
 
1


 
1

(8
)
Restructuring, integration and rationalization costs
 
(4
)
(71
)
 
(24
)
(373
)
Fair value gain (loss) on embedded derivatives
 
2

(17
)
 
33

32

Other(b)(c)
 
38

245

 
(118
)
(289
)
 
 
(144
)
636

 
(671
)
1,753

Downstream
 
 
 
 
 
 
Impairment and gain (loss) on sale of businesses and fixed assets(d)
 
469

72

 
579

405

Environmental and other provisions
 
(19
)
2

 
(19
)
(73
)
Restructuring, integration and rationalization costs
 
(69
)
(103
)
 
(171
)
(300
)
Fair value gain (loss) on embedded derivatives
 


 


Other
 
1

(48
)
 

(56
)
 
 
382

(77
)
 
389

(24
)
Rosneft
 
 
 
 
 
 
Impairment and gain (loss) on sale of businesses and fixed assets
 

62

 

62

Environmental and other provisions
 


 


Restructuring, integration and rationalization costs
 


 


Fair value gain (loss) on embedded derivatives
 


 


Other
 

(39
)
 

(39
)
 
 

23

 

23

Other businesses and corporate
 
 
 
 
 
 
Impairment and gain (loss) on sale of businesses and fixed assets
 
(16
)
2

 
(22
)

Environmental and other provisions
 
(153
)

 
(156
)
(134
)
Restructuring, integration and rationalization costs
 
(35
)
(21
)
 
(72
)
(90
)
Fair value gain (loss) on embedded derivatives
 


 


Gulf of Mexico oil spill(e)
 
(2,221
)
(674
)
 
(2,687
)
(6,640
)
Other
 
(14
)

 
90

(55
)
 
 
(2,439
)
(693
)
 
(2,847
)
(6,919
)
Total before interest and taxation
 
(2,201
)
(111
)
 
(3,129
)
(5,167
)
Finance costs(e)
 
(124
)
(125
)
 
(493
)
(494
)
Total before taxation
 
(2,325
)
(236
)
 
(3,622
)
(5,661
)
Taxation credit (charge) on non-operating items(f)
 
669

56

 
1,172

2,833

Taxation - impact of US tax reform(g)
 
(859
)

 
(859
)

Total after taxation for period
 
(2,515
)
(180
)
 
(3,309
)
(2,828
)
(a) 
Fourth quarter and full year 2017 include an impairment charge relating to the US Lower 48 business, partially offset by gains associated with asset divestments. In addition, full year 2017 includes an impairment charge arising following the announcement of the agreement to sell the Forties Pipeline System business to INEOS. Fourth quarter and full year 2016 principally relate to impairment reversals.
(b) 
Fourth quarter and full year 2016 include a $319-million exploration write-back relating to Block KG D6 in India. In addition, an impairment reversal of $234 million was also recorded in relation to this block.
(c) 
Fourth quarter and full year 2017 include BP’s share of an impairment reversal recognized by the Angola LNG equity-accounted entity, partially offset by other items. Full year 2017 includes the write-off of $145 million in relation to the value ascribed to certain licences in the deepwater Gulf of Mexico as part of the accounting for the acquisition of upstream assets from Devon Energy in 2011. Full year 2016 includes the write-off of $334 million in relation to the value ascribed to the licence in Brazil as part of the accounting for the acquisition of upstream assets from Devon Energy in 2011.
(d) 
Fourth quarter and full year 2017 gain primarily reflects the disposal of our shareholding in the SECCO joint venture.
(e) 
See Note 2 for further details regarding costs relating to the Gulf of Mexico oil spill.
(f) 
Fourth quarter and full year 2017 include the tax effect of the increase in the provision in the fourth quarter for business economic loss and other claims associated with the Deepwater Horizon Court Supervised Settlement Program (DHCSSP) at the new US tax rate.
(g) 
Fourth quarter and full year 2017 include the impact of US tax reform, which reduced the US federal corporate income tax rate from 35% to 21% effective from 1 January 2018. The impact disclosed has been calculated as the change in deferred tax balances at 31 December 2017, excluding the increase in the provision in the fourth quarter for business economic loss and other claims associated with the DHCSSP, which arises following the reduction in rate. The impact of the US tax reform has been treated as a non-operating item because it is not considered to be part of underlying business operations, has a material impact upon the reported result and is substantially impacted by Gulf of Mexico oil spill charges, which are also treated as non-operating items. Separate disclosure is considered meaningful and relevant to investors.


28

Table of contents

Non-GAAP information on fair value accounting effects
 
 
Fourth

Fourth

 




 
 
quarter

quarter

 
Year

Year

$ million
 
2017

2016

 
2017

2016

Favourable (adverse) impact relative to management’s measure of
 
 
 
 
 
 
  performance
 
 
 
 
 
 
Upstream
 
(151
)
(344
)
 
27

(637
)
Downstream
 
(83
)
99

 
(135
)
(448
)
 
 
(234
)
(245
)
 
(108
)
(1,085
)
Taxation credit (charge)
 
59

97

 
12

329

 
 
(175
)
(148
)
 
(96
)
(756
)
BP uses derivative instruments to manage the economic exposure relating to inventories above normal operating requirements of crude oil, natural gas and petroleum products. Under IFRS, these inventories are recorded at historical cost. The related derivative instruments, however, are required to be recorded at fair value with gains and losses recognized in the income statement. This is because hedge accounting is either not permitted or not followed, principally due to the impracticality of effectiveness-testing requirements. Therefore, measurement differences in relation to recognition of gains and losses occur. Gains and losses on these inventories are not recognized until the commodity is sold in a subsequent accounting period. Gains and losses on the related derivative commodity contracts are recognized in the income statement, from the time the derivative commodity contract is entered into, on a fair value basis using forward prices consistent with the contract maturity.
BP enters into physical commodity contracts to meet certain business requirements, such as the purchase of crude for a refinery or the sale of BP’s gas production. Under IFRS these physical contracts are treated as derivatives and are required to be fair valued when they are managed as part of a larger portfolio of similar transactions. In addition, derivative instruments are used to manage the price risk associated with certain future natural gas sales. Gains and losses arising are recognized in the income statement from the time the derivative commodity contract is entered into.
IFRS require that inventory held for trading is recorded at its fair value using period-end spot prices, whereas any related derivative commodity instruments are required to be recorded at values based on forward prices consistent with the contract maturity. Depending on market conditions, these forward prices can be either higher or lower than spot prices, resulting in measurement differences.
BP enters into contracts for pipelines and storage capacity, oil and gas processing and liquefied natural gas (LNG) that, under IFRS, are recorded on an accruals basis. These contracts are risk-managed using a variety of derivative instruments that are fair valued under IFRS. This results in measurement differences in relation to recognition of gains and losses.
The way that BP manages the economic exposures described above, and measures performance internally, differs from the way these activities are measured under IFRS. BP calculates this difference for consolidated entities by comparing the IFRS result with management’s internal measure of performance. Under management’s internal measure of performance the inventory and capacity contracts in question are valued based on fair value using relevant forward prices prevailing at the end of the period. The fair values of certain derivative instruments used to risk manage certain LNG and oil and gas contracts and gas sales contracts, are deferred to match with the underlying exposure and the commodity contracts for business requirements are accounted for on an accruals basis. We believe that disclosing management’s estimate of this difference provides useful information for investors because it enables investors to see the economic effect of these activities as a whole. The impacts of fair value accounting effects, relative to management’s internal measure of performance, are shown in the table above. A reconciliation to GAAP information is set out below.
 
 
Fourth

Fourth

 




 
 
quarter

quarter

 
Year

Year

$ million
 
2017

2016

 
2017

2016

Upstream
 
 
 
 
 
 
Replacement cost profit before interest and tax adjusted for fair value
 
 
 
 
 
 
  accounting effects
 
2,079

1,036

 
5,194

1,211

Impact of fair value accounting effects
 
(151
)
(344
)
 
27

(637
)
Replacement cost profit before interest and tax
 
1,928

692

 
5,221

574

Downstream
 
 
 
 
 
 
Replacement cost profit before interest and tax adjusted for fair value
 
 
 
 
 
 
  accounting effects
 
1,856

800

 
7,356

5,610

Impact of fair value accounting effects
 
(83
)
99

 
(135
)
(448
)
Replacement cost profit before interest and tax
 
1,773

899

 
7,221

5,162

Total group
 
 
 
 
 
 
Profit (loss) before interest and tax adjusted for fair value
 
 
 
 
 
 
  accounting effects
 
2,090

1,346

 
9,582

655

Impact of fair value accounting effects
 
(234
)
(245
)
 
(108
)
(1,085
)
Profit (loss) before interest and tax
 
1,856

1,101

 
9,474

(430
)

29

Table of contents

Readily marketable inventory* (RMI)
 
 
31 December

31 December

$ million
 
2017

2016

RMI at fair value*
 
5,661

5,952

Paid-up RMI*
 
2,688

2,705

Readily marketable inventory (RMI) is oil and oil products inventory held and price risk-managed by BP’s integrated supply and trading function (IST) which could be sold to generate funds if required. Paid-up RMI is RMI that BP has paid for.
We believe that disclosing the amounts of RMI and paid-up RMI is useful to investors as it enables them to better understand and evaluate the group’s inventories and liquidity position by enabling them to see the level of discretionary inventory held by IST and to see builds or releases of liquid trading inventory.
See the Glossary on page 34 for a more detailed definition of RMI. RMI, RMI at fair value, paid-up RMI and unpaid RMI are non-GAAP measures. A reconciliation of total inventory as reported on the group balance sheet to paid-up RMI is provided below.
 
 
31 December

31 December

$ million
 
2017

2016

Reconciliation of total inventory to paid-up RMI
 
 
 
Inventories as reported on the group balance sheet
 
19,011

17,655

Less: (a) inventories which are not oil and oil products and (b) oil and oil
 
 
 
  product inventories which are not risk-managed by IST
 
(13,929
)
(12,131
)
RMI on an IFRS basis
 
5,082

5,524

Plus: difference between RMI at fair value and RMI on an IFRS basis
 
579

428

RMI at fair value
 
5,661

5,952

Less: unpaid RMI* at fair value
 
(2,973
)
(3,247
)
Paid-up RMI
 
2,688

2,705


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

 
 
Fourth

Fourth

 




 
 
quarter

quarter

 
Year

Year

Per ordinary share (cents)
 
2017

2016

 
2017

2016

Profit for the period
 
0.14

2.62

 
17.20

0.61

Inventory holding (gains) losses*, before tax
 
(4.12
)
(3.17
)
 
(4.32
)
(8.52
)
Taxation charge (credit) on inventory holding gains and losses
 
1.04

0.93

 
1.14

2.58

Replacement cost (RC) profit (loss)*
 
(2.94
)
0.38

 
14.02

(5.33
)
Net (favourable) unfavourable impact of non-operating items* and fair value
 
 
 
 
 
 
  accounting effects*, before tax
 
12.92

2.54

 
18.94

35.99

Taxation charge (credit) on non-operating items and fair value accounting effects
 
0.66

(0.81
)
 
(1.65
)
(16.87
)
Underlying RC profit*
 
10.64

2.11

 
31.31

13.79



30

Table of contents

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

Taxation (charge) credit
 
 
 
 
 
 
 
 
Fourth

Fourth

 




 
 
quarter

quarter

 
Year

Year

$ million
 
2017

2016

 
2017

2016

Taxation on profit or loss
 
(1,119
)
(74
)
 
(3,712
)
2,467

Taxation on inventory holding gains and losses
 
(206
)
(176
)
 
(225
)
(483
)
Taxation on a replacement cost (RC) profit or loss basis
 
(913
)
102

 
(3,487
)
2,950

Taxation on non-operating items and fair value accounting effects
 
(131
)
153

 
325

3,162

Adjusted for the impact of the reduction in the rate of the UK North Sea
 
 
 
 
 
 
   supplementary charge
 


 

434

Adjusted taxation
 
(782
)
(51
)
 
(3,812
)
(646
)

Effective tax rate
 
 
 
 
 
 
 
 
Fourth

Fourth

 




 
 
quarter

quarter

 
Year

Year

%
 
2017

2016

 
2017

2016

ETR on profit or loss
 
95

12

 
52

107

Adjusted for inventory holding gains or losses
 
154

(650
)
 
3

(31
)
ETR on RC profit or loss*
 
249

(638
)
 
55

76

Adjusted for non-operating items and fair value accounting effects
 
(222
)
648

 
(17
)
(69
)
Adjusted for the impact of the reduction in the rate of the UK North Sea
 
 
 
 
 
 
   supplementary charge
 


 

16

Adjusted ETR*
 
27

10

 
38

23

Return on average capital employed (ROACE)
 
 
 
 
 
 
Year

Year

$ million
 
2017

2016

Profit for the year attributable to BP shareholders
 
3,389

115

Inventory holding (gains) losses, net of tax
 
(628
)
(1,114
)
Non-operating items and fair value accounting effects, after taxation
 
3,405

3,584

Underlying replacement cost (RC) profit
 
6,166

2,585

Interest expense, net of tax(a)
 
924

635

Non-controlling interests
 
79

57

Adjusted underlying RC profit
 
7,169

3,277

Total equity
 
100,404

96,843

Gross debt
 
63,230

58,300

Capital employed (2017 average $159,389 million)
 
163,634

155,143

Less: Goodwill
 
11,551

11,194

Cash and cash equivalents
 
25,586

23,484

 
 
126,497

120,465

Average capital employed (excluding goodwill and cash and cash equivalents)
 
123,481

117,002

ROACE
 
5.8
%
2.8
%
(a) 
Pre-tax finance costs for the year were $2,074 million (2016 $1,675 million) including interest expense of $1,421 million (2016 $977 million) and unwinding of the discount on provisions and other payables of $653 million (2016 $698 million). Interest expense included above is calculated on a post tax basis using a notional tax rate of 35%.


31

Table of contents

Realizations* and marker prices
 
 
Fourth

Fourth

 




 
 
quarter

quarter

 
Year

Year

 
 
2017

2016

 
2017

2016

Average realizations(a)
 
 
 
 
 
 
Liquids* ($/bbl)
 
 
 
 
 
 
US
 
51.50

41.93

 
46.55

36.25

Europe
 
57.92

45.66

 
52.13

40.53

Rest of World(b)
 
59.09

45.27

 
51.83

39.29

BP Average(b)
 
56.16

43.89

 
49.92

38.27

Natural gas ($/mcf)
 
 
 
 
 
 
US
 
2.28

2.29

 
2.36

1.90

Europe
 
5.56

4.81

 
5.09

4.40

Rest of World
 
3.51

3.35

 
3.45

3.19

BP Average
 
3.23

3.08

 
3.19

2.84

Total hydrocarbons* ($/boe)
 
 
 
 
 
 
US
 
35.75

30.32

 
33.47

25.76

Europe
 
52.17

40.48

 
46.09

36.31

Rest of World(b)
 
37.27

30.98

 
35.44

28.62

BP Average(b)
 
37.48

31.40

 
35.38

28.24

Average oil marker prices ($/bbl)
 
 
 
 
 
 
Brent
 
61.26

49.33

 
54.19

43.73

West Texas Intermediate
 
55.23

49.23

 
50.79

43.34

Western Canadian Select
 
38.74

35.44

 
38.55

30.78

Alaska North Slope
 
61.31

50.06

 
54.43

43.67

Mars
 
57.70

46.23

 
50.65

40.14

Urals (NWE - cif)
 
60.17

47.73

 
52.84

41.68

Average natural gas marker prices
 
 
 
 
 
 
Henry Hub gas price(c) ($/mmBtu)
 
2.93

2.98

 
3.11

2.46

UK Gas - National Balancing Point (p/therm)
 
51.94

45.76

 
44.95

34.63

(a) 
Based on sales of consolidated subsidiaries only - this excludes equity-accounted entities.
(b) 
Production volume recognition methodology for our Technical Service Contract arrangement in Iraq has been simplified to exclude the impact of oil price movements on lifting imbalances. A minor adjustment has been made to fourth quarter and full year 2016. There is no impact on the financial results.
(c) 
Henry Hub First of Month Index.
Exchange rates
 
 
Fourth

Fourth

 




 
 
quarter

quarter

 
Year

Year

 
 
2017

2016

 
2017

2016

$/£ average rate for the period
 
1.33

1.24

 
1.29

1.35

$/£ period-end rate
 
1.34

1.22

 
1.34

1.22

 
 
 
 
 
 
 
$/€ average rate for the period
 
1.18

1.08

 
1.13

1.11

$/€ period-end rate
 
1.19

1.05

 
1.19

1.05

 
 
 
 
 
 
 
Rouble/$ average rate for the period
 
58.46

63.12

 
58.36

67.06

Rouble/$ period-end rate
 
57.60

60.63

 
57.60

60.63



32

Table of contents

Legal proceedings

The following discussion sets out the material developments in the group’s material legal proceedings during the fourth quarter. For a full discussion of the group’s material legal proceedings, see pages 261-265 of BP Annual Report and Form 20-F 2016, and page 35 of BP p.l.c. Group results second quarter and half year 2017.
Matters relating to the Deepwater Horizon accident and oil spill (the Incident)
Plaintiffs’ Steering Committee (PSC) settlements - Economic and Property Damages Settlement Agreement The Economic and Property Damages Settlement established a court-supervised settlement programme (CSSP) to resolve certain economic and property damage claims arising from the Incident.
Following numerous court decisions, on 31 March 2015, the United States district court in New Orleans denied the PSC motion seeking to alter or amend a revised policy relating to business economic loss claims. Such policy required the matching of revenue with the expenses incurred by claimants to generate that revenue, even where the revenue and expenses were recorded at different times. The PSC appealed the district court decision and, on 22 May 2017, the Fifth Circuit issued an opinion upholding the policy in part and reversing the policy in part. The Fifth Circuit ordered that the portion of the policy upheld, which covers the substantial majority of the remaining business economic loss claims, be applied as the governing methodology for all applicable business economic loss claims. BP filed a petition for a rehearing which was denied on 21 June 2017. In May to July 2017, the district court issued a series of orders instructing the CSSP on how to implement the Fifth Circuit’s opinion. On 10 August 2017, the district court denied BP’s motion to clarify or reconsider these orders. BP appealed all of these orders and decisions on 8 September 2017; the appeals have been consolidated with four appeals filed by claimants in early to mid-September 2017 challenging the same set of orders and decisions, albeit raising different issues than are raised by BP’s appeal. These appeals are currently pending before the Fifth Circuit.
As a result of significantly higher average claims determinations issued by the CSSP in the period and the continuing effect of the May 2017 Fifth Circuit opinion, the provision for the costs associated with the 2012 PSC settlement was increased in the fourth quarter of 2017. The amounts ultimately payable may differ from the amount provided and the timing of payments is uncertain. See Note 2 on page 19 for further details.
Other civil complaints Following numerous court decisions, on 11 January 2018, the United States district court in New Orleans issued an order requiring all remaining private plaintiffs with economic loss or property damage claims outside of the CSSP to file by 11 April 2018 a verified sworn statement regarding the actual damages each such plaintiff seeks in its pending litigation and an explanation of how those alleged damages were causally related to the Incident.
Non-US government lawsuits On 3 December 2015 and 29 March 2016, Acciones Colectivas de Sinaloa filed two class actions (which have since been consolidated) in a Mexican Federal District Court on behalf of several Mexican states against BP Exploration & Production Inc., BP America Production Company (BPAPC), and other purported BP subsidiaries. In these class actions, plaintiffs seek an order requiring the BP defendants to repair the damage to the Gulf of Mexico, to pay penalties, and to compensate plaintiffs for damage to property, to health and for economic loss. BP was formally served with the action on 8 December 2017.
Other legal proceedings
California False Claims Act matters On 4 November 2014, the California Attorney General filed a notice in California state court that it was intervening in a previously-sealed California False Claims Act (CFCA) lawsuit filed by relator Christopher Schroen against BP, BP Energy Company, BP Corporation North America Inc., BP Products and BPAPC. On 7 January 2015, the California Attorney General filed a complaint in intervention alleging that BP violated the CFCA and the California Unfair Competition Law by falsely and fraudulently overcharging California state entities for natural gas and making similar allegations in addition to individual claims. In January 2018 the parties reached a settlement pursuant to which BP, while denying liability, agreed to pay $102 million to the state of California.


 


33

Table of contents

Glossary
Non-GAAP measures are provided for investors because they are closely tracked by management to evaluate BP’s operating performance and to make financial, strategic and operating decisions.
Adjusted effective tax rate (ETR) is a non-GAAP measure. The adjusted ETR is calculated by dividing taxation on an underlying RC basis by underlying RC profit or loss before tax. Taxation on an underlying RC basis is taxation on a RC basis for the period adjusted for taxation on non-operating items and fair value accounting effects. For the 2016 calculation, taxation on an underlying RC basis also reflects an adjustment to eliminate a $434-million credit that arises from the reduction in the rate of the North Sea supplementary charge in the third quarter of 2016. Information on underlying RC profit or loss is provided below. BP believes it is helpful to disclose the adjusted ETR because this measure may help investors to understand and evaluate, in the same manner as management, the underlying trends in BP’s operational performance on a comparable basis, period on period. The nearest equivalent measure on an IFRS basis is the ETR on profit or loss for the period. A reconciliation to GAAP information is provided on page 31.
We are unable to present reconciliations of forward-looking information for adjusted ETR to ETR on profit or loss for the period, because without unreasonable efforts, we are unable to forecast accurately certain adjusting items required to present a meaningful comparable GAAP forward-looking financial measure. These items include the taxation on inventory holding gains and losses, non-operating items and fair value accounting effects, that are difficult to predict in advance in order to include in a GAAP estimate.
BP-operated Upstream plant reliability is calculated taking 100% less the ratio of total unplanned plant deferrals divided by installed production capacity. Unplanned plant deferrals are associated with the topside plant and where applicable the subsea equipment (excluding wells and reservoir). Unplanned plant deferrals include breakdowns, which does not include weather related downtime.
Capital expenditure is total cash capital expenditure as stated in the condensed group cash flow statement.
Consolidation adjustment - UPII is unrealized profit in inventory arising on inter-segment transactions.
Divestment proceeds are disposal proceeds as per the condensed group cash flow statement.
Effective tax rate (ETR) on replacement cost (RC) profit or loss is a non-GAAP measure. The ETR on RC profit or loss is calculated by dividing taxation on a RC basis by RC profit or loss before tax. Information on RC profit or loss is provided below. BP believes it is helpful to disclose the ETR on RC profit or loss because this measure excludes the impact of price changes on the replacement of inventories and allows for more meaningful comparisons between reporting periods. The nearest equivalent measure on an IFRS basis is the ETR on profit or loss for the period. A reconciliation to GAAP information is provided on page 31.
Fair value accounting effects are non-GAAP adjustments to our IFRS profit (loss) relating to certain physical inventories, pipelines and storage capacity. Management uses a fair-value basis to value these items which, under IFRS, are accounted for on an accruals basis with the exception of trading inventories, which are valued using spot prices. The adjustments have the effect of aligning the valuation basis of the physical positions with that of any associated derivative instruments, which are required to be fair valued under IFRS, in order to provide a more representative view of the ultimate economic value. Further information is provided on page 29 .
Gearing - See Net debt and net debt ratio definition.
Hydrocarbons - Liquids and natural gas. Natural gas is converted to oil equivalent at 5.8 billion cubic feet = 1 million barrels.
Inorganic capital expenditure is a subset of capital expenditure and is a non-GAAP measure. Inorganic capital expenditure comprises consideration in business combinations and certain other significant investments made by the group. It is reported on a cash basis. BP believes that this measure provides useful information as it allows investors to understand how BP’s management invests funds in projects which expand the group’s activities through acquisition. Further information and a reconciliation to GAAP information is provided on page 27.
Inventory holding gains and losses represent the difference between the cost of sales calculated using the replacement cost of inventory and the cost of sales calculated on the first-in first-out (FIFO) method after adjusting for any changes in provisions where the net realizable value of the inventory is lower than its cost. Under the FIFO method, which we use for IFRS reporting, the cost of inventory charged to the income statement is based on its historical cost of purchase or manufacture, rather than its replacement cost. In volatile energy markets, this can have a significant distorting effect on reported income. The amounts disclosed represent the difference between the charge to the income statement for inventory on a FIFO basis (after adjusting for any related movements in net realizable value provisions) and the charge that would have arisen based on the replacement cost of inventory. For this purpose, the replacement cost of inventory is calculated using data from each operation’s production and manufacturing system, either on a monthly basis, or separately for each transaction where the system allows this approach. The amounts disclosed are not separately reflected in the financial statements as a gain or loss. No adjustment is made in respect of the cost of inventories held as part of a trading position and certain other temporary inventory positions. See Replacement cost (RC) profit or loss definition below.
Liquids - Liquids for Upstream and Rosneft comprises crude oil, condensate and natural gas liquids. For Upstream, liquids also includes bitumen.
Major projects have a BP net investment of at least $250 million, or are considered to be of strategic importance to BP or of a high degree of complexity.

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Glossary (continued)
Net debt and net debt ratio are non-GAAP measures. Net debt is calculated as gross finance debt, as shown in the balance sheet, plus the fair value of associated derivative financial instruments that are used to hedge foreign currency exchange and interest rate risks relating to finance debt, for which hedge accounting is applied, less cash and cash equivalents. The net debt ratio is defined as the ratio of net debt to the total of net debt plus shareholders’ equity. All components of equity are included in the denominator of the calculation. BP believes these measures provide useful information to investors. Net debt enables investors to see the economic effect of gross debt, related hedges and cash and cash equivalents in total. The net debt ratio enables investors to see how significant net debt is relative to equity from shareholders. The derivatives are reported on the balance sheet within the headings ‘Derivative financial instruments’. The nearest equivalent GAAP measures are gross debt and gross debt ratio. A reconciliation of gross debt to net debt is provided on page 25.
We are unable to present reconciliations of forward-looking information for net debt ratio to gross debt ratio, because without unreasonable efforts, we are unable to forecast accurately certain adjusting items required to present a meaningful comparable GAAP forward-looking financial measure. These items include fair value asset (liability) of hedges related to finance debt, and cash and cash equivalents, that are difficult to predict in advance in order to include in a GAAP estimate.
Net wind generation capacity is the sum of the rated capacities of the assets/turbines that have entered into commercial operation, including BP’s share of equity-accounted entities. The gross data is the equivalent capacity on a gross-JV basis, which includes 100% of the capacity of equity-accounted entities where BP has partial ownership.
Non-operating items are charges and credits included in the financial statements that BP discloses separately because it considers such disclosures to be meaningful and relevant to investors. They are items that management considers not to be part of underlying business operations and are disclosed in order to enable investors better to understand and evaluate the group’s reported financial performance. Non-operating items within equity-accounted earnings are reported net of incremental income tax reported by the equity-accounted entity. An analysis of non-operating items by region is shown on pages 9, 11 and 13, and by segment and type is shown on page 28.
Operating cash flow is net cash provided by (used in) operating activities as stated in the condensed group cash flow statement. When used in the context of a segment rather than the group, the terms refer to the segment’s share thereof.
Operating cash flow excluding Gulf of Mexico oil spill payments / expenditure or Underlying operating cash flow is a non-GAAP measure calculated by excluding post-tax operating cash flows relating to the Gulf of Mexico oil spill as reported in Note 2 from Net cash provided by operating activities as reported in the condensed group cash flow statement. The nearest equivalent measure on an IFRS basis is Net cash provided by operating activities.
Operating cash margin is operating cash flow divided by the applicable number of barrels of oil equivalent produced, at $52/bbl flat oil prices. Expected operating cash margins are calculated over the period 2016-2025.
Organic capital expenditure is a subset of capital expenditure and is a non-GAAP measure. Organic capital expenditure comprises capital expenditure less inorganic capital expenditure. BP believes that this measure provides useful information as it allows investors to understand how BP’s management invests funds in developing and maintaining the group’s assets. An analysis of organic capital expenditure by segment and region, and a reconciliation to GAAP information is provided on page 27.
We are unable to present reconciliations of forward-looking information for organic capital expenditure to total cash capital expenditure, because without unreasonable efforts, we are unable to forecast accurately the adjusting item, inorganic capital expenditure, that is difficult to predict in advance in order to derive the nearest GAAP estimate.
Production-sharing agreement (PSA) / Production-sharing contract is an arrangement through which an oil company bears the risks and costs of exploration, development and production. In return, if exploration is successful, the oil company receives entitlement to variable physical volumes of hydrocarbons, representing recovery of the costs incurred and a stipulated share of the production remaining after such cost recovery.
Readily marketable inventory (RMI) is inventory held and price risk-managed by our integrated supply and trading function (IST) which could be sold to generate funds if required. It comprises oil and oil products for which liquid markets are available and excludes inventory which is required to meet operational requirements and other inventory which is not price risk-managed. RMI is reported at fair value. Inventory held by the Downstream fuels business for the purpose of sales and marketing, and all inventories relating to the lubricants and petrochemicals businesses, are not included in RMI.
Paid-up RMI excludes RMI which has not yet been paid for. For inventory that is held in storage, a first-in first-out (FIFO) approach is used to determine whether inventory has been paid for or not. Unpaid RMI is RMI which has not yet been paid for by BP. RMI, RMI at fair value, Paid-up RMI and Unpaid RMI are non-GAAP measures. Further information is provided on page 30.
Realizations are the result of dividing revenue generated from hydrocarbon sales, excluding revenue generated from purchases made for resale and royalty volumes, by revenue generating hydrocarbon production volumes. Revenue generating hydrocarbon production reflects the BP share of production as adjusted for any production which does not generate revenue. Adjustments may include losses due to shrinkage, amounts consumed during processing, and contractual or regulatory host committed volumes such as royalties.
Refining availability represents Solomon Associates’ operational availability, which is defined as the percentage of the year that a unit is available for processing after subtracting the annualized time lost due to turnaround activity and all planned mechanical, process and regulatory downtime.
The Refining marker margin (RMM) is the average of regional indicator margins weighted for BP’s crude refining capacity in each region. Each regional marker margin is based on product yields and a marker crude oil deemed appropriate for the region. The regional indicator margins may not be representative of the margins achieved by BP in any period because of BP’s particular refinery configurations and crude and product slate.

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Glossary (continued)
Replacement cost (RC) profit or loss reflects the replacement cost of inventories sold in the period and is arrived at by excluding inventory holding gains and losses from profit or loss. RC profit or loss is the measure of profit or loss that is required to be disclosed for each operating segment under IFRS. RC profit or loss for the group is not a recognized GAAP measure. BP believes this measure is useful to illustrate to investors the fact that crude oil and product prices can vary significantly from period to period and that the impact on our reported result under IFRS can be significant. Inventory holding gains and losses vary from period to period due to changes in prices as well as changes in underlying inventory levels. In order for investors to understand the operating performance of the group excluding the impact of price changes on the replacement of inventories, and to make comparisons of operating performance between reporting periods, BP’s management believes it is helpful to disclose this measure. The nearest equivalent measure on an IFRS basis is profit or loss attributable to BP shareholders. A reconciliation to GAAP information is provided on page 3 .
RC profit or loss per share is a non-GAAP measure. Earnings per share is defined in Note 6. RC profit or loss per share is calculated using the same denominator. The numerator used is RC profit or loss attributable to BP shareholders rather than profit or loss attributable to BP shareholders. BP believes it is helpful to disclose the RC profit or loss per share because this measure excludes the impact of price changes on the replacement of inventories and allows for more meaningful comparisons between reporting periods. The nearest equivalent measure on an IFRS basis is basic earnings per share based on profit or loss for the period attributable to BP shareholders. A reconciliation to GAAP information is provided on page 30.
Reported recordable injury frequency measures the number of reported work-related employee and contractor incidents that result in a fatality or injury per 200,000 hours worked. This represents reported incidents occurring within BP’s operational HSSE reporting boundary. That boundary includes BP’s own operated facilities and certain other locations or situations.
Reserves replacement ratio is the extent to which production is replaced by proved reserves additions. This ratio is expressed in oil equivalent terms and includes changes resulting from revisions to previous estimates, improved recovery, and extensions and discoveries.
Return on average capital employed (ROACE) is a non-GAAP measure and is underlying replacement cost profit, after adding back non-controlling interest and interest expense net of notional tax at an assumed 35%, divided by average capital employed, excluding cash and cash equivalents and goodwill. Interest expense is finance cost excluding the unwinding of the discount on provisions and other payables, and for full year 2017 interest expense was $1,421 million before tax. BP believes it is helpful to disclose the ROACE because this measure gives an indication of the company’s capital efficiency. The nearest GAAP measures of the numerator and denominator are profit or loss for the period attributable to BP shareholders and average capital employed respectively. A reconciliation of the numerator and denominator is provided on page 31.
Tier 1 process safety events are losses of primary containment from a process of greatest consequence - causing harm to a member of the workforce, costly damage to equipment or exceeding defined quantities. This represents reported incidents occurring within BP’s operational HSSE reporting boundary. That boundary includes BP’s own operated facilities and certain other locations or situations.
Underlying production is production after adjusting for divestments and entitlement impacts in our production-sharing agreements. 2017 underlying production does not include the Abu Dhabi onshore concession renewal.
Underlying RC profit or loss is RC profit or loss after adjusting for non-operating items and fair value accounting effects. Underlying RC profit or loss and adjustments for fair value accounting effects are not recognized GAAP measures. See pages 28 and 29 for additional information on the non-operating items and fair value accounting effects that are used to arrive at underlying RC profit or loss in order to enable a full understanding of the events and their financial impact. BP believes that underlying RC profit or loss is a useful measure for investors because it is a measure closely tracked by management to evaluate BP’s operating performance and to make financial, strategic and operating decisions and because it may help investors to understand and evaluate, in the same manner as management, the underlying trends in BP’s operational performance on a comparable basis, period on period, by adjusting for the effects of these non-operating items and fair value accounting effects. The nearest equivalent measure on an IFRS basis for the group is profit or loss attributable to BP shareholders. The nearest equivalent measure on an IFRS basis for segments is RC profit or loss before interest and taxation. Underlying profit in the highlights on page 3 refers to full year underlying RC profit for the group. A reconciliation to GAAP information is provided on page 3 .
Underlying RC profit or loss per share is a non-GAAP measure. Earnings per share is defined in Note 6. Underlying RC profit or loss per share is calculated using the same denominator. The numerator used is underlying RC profit or loss attributable to BP shareholders rather than profit or loss attributable to BP shareholders. BP believes it is helpful to disclose the underlying RC profit or loss per share because this measure may help investors to understand and evaluate, in the same manner as management, the underlying trends in BP’s operational performance on a comparable basis, period on period. The nearest equivalent measure on an IFRS basis is basic earnings per share based on profit or loss for the period attributable to BP shareholders. A reconciliation to GAAP information is provided on page 30.
Upstream operating efficiency is calculated as production for BP-operated sites, excluding US Lower 48 and adjusted for certain items including entitlement impacts in our production-sharing agreements divided by installed production capacity for BP-operated sites, excluding US Lower 48. Installed production capacity is the agreed rate achievable (measured at the export end of the system) when the installed production system (reservoir, wells, plant and export) is fully optimized and operated at full rate with no planned or unplanned deferrals.
Upstream unit production cost is calculated as production cost divided by units of production. Production cost does not include ad valorem and severance taxes. Units of production are barrels for liquids and thousands of cubic feet for gas. Amounts disclosed are for BP subsidiaries only and do not include BP’s share of equity-accounted entities.

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




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Computation of ratio of earnings to fixed charges

 
 


 
 
Year

 
 
2017

$ million except ratio
 
 
 
 
 
Earnings available for fixed charges:
 
 
Pre-tax profit from continuing operations before adjustment for income or loss from joint ventures and associates
 
4,673

Fixed charges
 
2,960

Amortization of capitalized interest
 
219

Distributed income of joint ventures and associates
 
1,253

Interest capitalized
 
(297
)
Preference dividend requirements, gross of tax
 
(3
)
Non-controlling interest of subsidiaries’ income not incurring fixed charges
 
(14
)
Total earnings available for fixed charges
 
8,791

 
 
 
Fixed charges:
 
 
Interest expensed
 
1,421

Interest capitalized
 
297

Rental expense representative of interest
 
1,239

Preference dividend requirements, gross of tax
 
3

Total fixed charges
 
2,960

 
 
 
Ratio of earnings to fixed charges
 
2.97


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The following table shows the unaudited consolidated capitalization and indebtedness of the BP group as of 31 December 2017 in
accordance with IFRS:
Capitalization and indebtedness

 
 
31 December

$ million
 
2017

Share capital and reserves
 
 
Capital shares (1-2)
 
5,343

Paid-in surplus (3)
 
13,573

Merger reserve (3)
 
27,206

Treasury shares
 
(16,958
)
Available-for-sale investments
 
17

Cash flow hedge reserve
 
(760
)
Foreign currency translation reserve
 
(5,156
)
Profit and loss account
 
75,226

BP shareholders' equity
 
98,491

 
 
 
Finance debt (4-6)
 
 
Due within one year
 
7,739

Due after more than one year
 
55,491

Total finance debt
 
63,230

Total capitalization (7)
 
161,721


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

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

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

4.
Finance debt recorded in currencies other than US dollars has been translated into US dollars at the relevant exchange rates existing on 31 December 2017.

5.
Finance debt presented in the table above consists of borrowings and obligations under finance leases. Other contractual obligations are not presented in the table above – see BP Annual Report and Form 20-F 2016 – Liquidity and capital resources for further information.

6.
At 31 December 2017, the parent company, BP p.l.c., had issued guarantees totalling $60,665 million relating to finance debt of subsidiaries. Thus 96% of the group’s finance debt had been guaranteed by BP p.l.c.

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

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

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


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Signatures

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


BP p.l.c.
(Registrant)



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


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