6-K 1 a30062018bp6kq2.htm 6-K Document


UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549


Form 6-K

Report of Foreign Private Issuer

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

for the period ended 30 June 2018
Commission File Number 1-06262

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

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

Indicate by check mark whether the registrant files or will file annual reports under cover of Form 20-F or Form 40-F:
 
 
 
 
Form 20-F x  Form 40-F ¨  
 
 
 
 
Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(1): ¨
Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(7): ¨

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


1


BP p.l.c. and subsidiaries
Form 6-K for the period ended 30 June 2018(a) 

(a)
In this Form 6-K, references to the half year 2018 and half year 2017 refer to six-month periods ended 30 June 2018 and 30 June 2017 respectively. References to the second quarter 2018 and second quarter 2017 refer to the three-month periods ended 30 June 2018 and 30 June 2017 respectively.
(b)
This discussion should be read in conjunction with the consolidated financial statements and related notes provided elsewhere in this Form 6-K and with the information, including the consolidated financial statements and related notes, in BP’s Annual Report on Form 20-F for the year ended 31 December 2017.


2


Group results second quarter and half year 2018

Highlights
Strong earnings, strategic momentum, increased dividend
Profit for the second quarter of 2018 was $2.8 billion, compared with $0.1 billion for the same period in 2017. Underlying replacement cost profit* for the second quarter of 2018 was $2.8 billion – four times that reported for the same period in 2017 – including significantly higher earnings from the Upstream and Rosneft.
Operating cash flow* was $6.3 billion in the second quarter and $10.0 billion in the first half including the impact of Gulf of Mexico oil spill payments of $0.7 billion and $2.4 billion respectively(a).
    Dividend was increased 2.5% to 10.25 cents a share, the first rise since the third quarter of 2014.
Upstream reported the strongest quarter since the third quarter of 2014 on both a replacement cost and underlying basis.
Oil and gas production: reported production in the quarter was 3.6 million barrels of oil equivalent a day. Upstream production, excluding Rosneft, was 1.4% higher than a year earlier and up 9.6% when adjusted for portfolio changes and pricing effects, driven by rising output from new major projects* and strong plant reliability*.
Major projects: with start-ups in Azerbaijan, Russia and Egypt, three of the six new projects expected to start in 2018 are now online.
Strategic portfolio management: agreed to buy world-class US onshore oil and gas assets from BHP, a $10.5 billion acquisition that will transform BP’s US Lower 48 business. BP also agreed to increase its stake in the Clair oilfield in the UK while exiting the Greater Kuparuk Area in Alaska.
Downstream reported strong first half refining performance, with record levels of crude processed at Whiting refinery in US; further expansion in fuels marketing, with more than 1,200 convenience partnership sites now across our retail network.
Advancing the energy transition: acquisition of UK's largest electric vehicle charging company Chargemaster and investment in innovative battery technology firm StoreDot move forward BP’s approach to advanced mobility.
    Gulf of Mexico oil spill payments in the quarter were $0.7 billion on a post-tax basis.
    Gross debt reduced in the quarter by $1.8 billion to $60.4 billion. Net debt* reduced in the quarter by $0.7 billion to $39.3 billion.
    BP's share buyback programme continued with 29 million ordinary shares bought back in the first half at a cost of $200 million.

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

Second

 
First

First

 
quarter

quarter

 
half

half

$ million
 
2018

2017

 
2018

2017

Sales and other operating revenues
 
75,439

56,511

 
143,611

112,374

Profit for the period(a)
 
2,799

144

 
5,268

1,593

Inventory holding (gains) losses*, before tax
 
(1,310
)
586

 
(1,402
)
520

Taxation charge (credit) on inventory holding gains and losses
 
300

(177
)
 
312

(148
)
RC profit (loss)*
 
1,789

553

 
4,178

1,965

Net (favourable) adverse impact of non-operating items* and fair value accounting effects*, before tax
 
1,275

237

 
1,670

504

Taxation charge (credit) on non-operating items and fair value accounting effects
 
(242
)
(106
)
 
(440
)
(275
)
Underlying RC profit
 
2,822

684

 
5,408

2,194

Profit per ordinary share (cents)
 
14.03

0.73

 
26.42

8.12

Profit per ADS (dollars)
 
0.84

0.04

 
1.59

0.49

RC profit (loss) per ordinary share (cents)*
 
8.96

2.80

 
20.96

10.02

RC profit (loss) per ADS (dollars)
 
0.54

0.17

 
1.26

0.60

Underlying RC profit per ordinary share (cents)*
 
14.14

3.47

 
27.13

11.19

Underlying RC profit per ADS (dollars)
 
0.85

0.21

 
1.63

0.67

(a)
Profit attributable to BP shareholders.

* See definitions in the Glossary on page 40. RC profit (loss), underlying RC profit, net debt and organic capital expenditure are non-GAAP measures.
The commentary above and following should be read in conjunction with the cautionary statement on page 43.

3


Group headlines
Results
BP’s profit for the second quarter and half year was $2,799 million and $5,268 million respectively, compared with $144 million and $1,593 million for the same periods in 2017.
For the half year, replacement cost (RC) profit* was $4,178 million, compared with $1,965 million in 2017. Underlying RC profit* was $5,408 million, compared with $2,194 million in 2017. Underlying RC profit is after adjusting RC profit for a net charge for non-operating items* of $970 million and net adverse fair value accounting effects* of $260 million (both on a post-tax basis).
For the second quarter, RC profit was $1,789 million, compared with a profit of $553 million in 2017. Underlying RC profit was $2,822 million compared with $684 million for the same period in 2017. Underlying RC profit is after adjusting RC profit for a net charge for non-operating items of $723 million and net adverse fair value accounting effects of $310 million (both on a post-tax basis).
See further information on pages 5, 34 and 35.
Non-operating items
Non-operating items amounted to a post-tax charge of $723 million for the quarter and $970 million for the half year. The charge for the quarter includes post-tax amounts relating to the Gulf of Mexico oil spill of $193 million for business economic loss claims and $126 million for other claims and litigation relating to the spill, as well as finance costs in respect of the unwinding of discounting effects relating to oil spill payables. See further information on page 34.
Effective tax rate
The effective tax rate (ETR) on the profit for the second quarter and half year was 42% and 39% respectively, compared with 83% and 46% for the same periods in 2017. The ETR on RC profit or loss* for the second quarter and half year was 49% and 42% respectively, compared with 63% and 43% for the same periods in 2017. Adjusting for non-operating items and fair value accounting effects, the underlying ETR* for the second quarter and half year was 42% and 40% respectively, compared with 60% and 45% for the same periods in 2017. The lower underlying ETR for the second quarter and half year mainly reflected lower exploration write-offs partly offset by deferred tax charges due to foreign exchange impacts. ETR on RC profit or loss and underlying ETR are non-GAAP measures.
Dividend
On 26 July 2018 BP announced a quarterly dividend of 10.25 cents per ordinary share ($0.615 per ADS), which is expected to be paid on 21 September 2018. The corresponding amount in sterling will be announced on 11 September 2018. See page 26 for further information.
Share buybacks
BP repurchased 11 million ordinary shares at a cost of $80 million, including fees and stamp duty, during the second quarter of 2018. For the half year, BP repurchased 29 million ordinary shares at a cost of $200 million, including fees and stamp duty.
 

Operating cash flow*
Operating cash flow was $6.3 billion in the second quarter and $10.0 billion in the first half including the impact of Gulf of Mexico oil spill payments of $0.7 billion and $2.4 billion respectively. These compare with $4.9 billion for the second quarter of 2017 and $7.0 billion for the first half of 2017.
Capital expenditure*
Total capital expenditure for the second quarter and half year was $3.8 billion and $7.8 billion respectively, compared with $4.5 billion and $8.6 billion for the same periods in 2017.
Organic capital expenditure* for the second quarter and half year was $3.5 billion and $7.0 billion respectively, compared with $4.3 billion and $7.9 billion for the same periods in 2017.
Inorganic capital expenditure* for the second quarter and half year was $0.4 billion and $0.8 billion respectively, compared with $0.1 billion and $0.7 billion for the same periods in 2017.
See page 33 for further information.
Divestment and other proceeds
Divestment proceeds* were $0.2 billion for the second quarter and $0.3 billion for the half year, compared with $0.5 billion and $0.7 billion for the same periods in 2017.
Debt
Gross debt at 30 June 2018 was $60.4 billion compared with $63.0 billion a year ago. Gross debt ratio* at 30 June 2018 was 37.2%, compared with 39.0% a year ago.
Net debt* at 30 June 2018 was $39.3 billion, compared with $39.8 billion a year ago. Gearing* or net debt ratio* at 30 June 2018 was 27.8%, compared with 28.8% a year ago.
We expect gearing to remain within the target band, of 20-30%, during the second half of 2018.
Net debt, net debt ratio and gearing are non-GAAP measures. See page 26 for more information.

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

4


Analysis of underlying RC profit* before interest and tax
 
 
Second

Second

 
First

First

 
 
quarter

quarter

 
half

half

$ million
 
2018

2017

 
2018

2017

Underlying RC profit before interest and tax
 
 
 
 
 
 
Upstream
 
3,508

710

 
6,665

2,080

Downstream
 
1,455

1,413

 
3,281

3,155

Rosneft
 
766

279

 
1,013

378

Other businesses and corporate
 
(477
)
(366
)
 
(869
)
(806
)
Consolidation adjustment – UPII*
 
151

135

 
(9
)
67

Underlying RC profit before interest and tax
 
5,403

2,171

 
10,081

4,874

Finance costs and net finance expense relating to pensions and other post-retirement benefits
 
(448
)
(420
)
 
(912
)
(807
)
Taxation on an underlying RC basis
 
(2,059
)
(1,055
)
 
(3,625
)
(1,818
)
Non-controlling interests
 
(74
)
(12
)
 
(136
)
(55
)
Underlying RC profit attributable to BP shareholders
 
2,822

684

 
5,408

2,194

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

Second

 
First

First

 
 
quarter

quarter

 
half

half

$ million
 
2018

2017

 
2018

2017

RC profit (loss) before interest and tax
 
 
 
 
 
 
Upstream
 
3,514

795

 
6,688

2,051

Downstream
 
840

1,567

 
2,553

3,273

Rosneft
 
766

279

 
1,013

378

Other businesses and corporate(a)
 
(1,025
)
(721
)
 
(1,596
)
(1,152
)
Consolidation adjustment – UPII
 
151

135

 
(9
)
67

RC profit (loss) before interest and tax
 
4,246

2,055

 
8,649

4,617

Finance costs and net finance expense relating to pensions and other post-retirement benefits
 
(566
)
(541
)
 
(1,150
)
(1,054
)
Taxation on a RC basis
 
(1,817
)
(949
)
 
(3,185
)
(1,543
)
Non-controlling interests
 
(74
)
(12
)
 
(136
)
(55
)
RC profit (loss) attributable to BP shareholders
 
1,789

553

 
4,178

1,965

Inventory holding gains (losses)*
 
1,310

(586
)
 
1,402

(520
)
Taxation (charge) credit on inventory holding gains and losses
 
(300
)
177

 
(312
)
148

Profit (loss) for the period attributable to BP shareholders
 
2,799

144

 
5,268

1,593

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




5


Strategic progress
Upstream
Upstream production, excluding Rosneft, for the second quarter was 2,465mboe/d, 1.4% higher than a year earlier. Underlying production* – adjusted for PSA* impacts and portfolio changes, including termination of BP’s interest in the offshore concession in Abu Dhabi – was 9.6% higher than a year ago due to production from the ramp-up of major projects* and continued strong plant reliability*. Unit production costs* for the second quarter improved by 3% compared with the same period in 2017.
Three Upstream major projects have now started up in 2018: the Shah Deniz 2 gas project in Azerbaijan and the Taas-Yuryakh oil expansion in Russia in the second quarter, following the Atoll project in Egypt in the first quarter. These projects were started up under budget and on or ahead of schedule. Another three major projects are expected to begin production during 2018. In addition, during the first half of the year, final investment decisions have been made on five projects in Oman, India, the North Sea and Angola.
BP has accessed new acreage in the Campos basin, offshore Brazil, as a result of the fourth Pre-Salt Production Sharing Contract Bid Round.
BP has agreed to buy a portfolio of US unconventional oil and gas assets from BHP. This major acquisition will upgrade and materially reposition BP’s US onshore oil and gas business. BP also agreed to increase its interest in the UK's Clair field, an advantaged oil asset with growth potential, while divesting its non-operating interest in the Greater Kuparuk Area in Alaska.
Downstream
In marketing, BP’s convenience partnership model is now rolled out to more than 1,200 sites across our network, more than 300 BP-branded retail sites are now open in Mexico and lubricants continues to deliver premium brand growth.
In manufacturing, BP’s Whiting refinery processed record levels of crude and our petrochemicals business announced two new PTA licensing agreements, demonstrating the strength of BP’s industry-leading technology.
 

Advancing the energy transition
BP has continued to progress its lower-carbon strategy as detailed in the Advancing the energy transition report published in April.
Two Upstream major projects that have started operation in 2018 so far – Shah Deniz 2 and Atoll – produce natural gas.
BP also significantly progressed its advanced mobility strategy with the purchase of Chargemaster, the UK’s largest electric vehicle charging network operator. Together with investments in StoreDot, a developer of ultra-fast charging battery technology, and mobile-charging company FreeWire, this supports BP’s aim to become the leading fuel provider for electric as well as conventional vehicles.
Financial framework
Operating cash flow* was $6.3 billion in the quarter and $10.0 billion in the first half, including Gulf of Mexico oil spill payments of $0.7 billion in the quarter and $2.4 billion in the first half. These compare with $4.9 billion for the second quarter of 2017 and $7.0 billion for the first half of 2017.
Organic capital expenditure* of $3.5 billion in the quarter brought the total for the first half of 2018 to $7.0 billion. BP expects 2018 organic capital expenditure to be around $15 billion.

Divestments and other proceeds totalled $0.3 billion for the half year. 2018 total proceeds are expected to be over $3 billion including proceeds from the sale of BP’s interests in the Greater Kuparuk Area in Alaska.
Gulf of Mexico oil spill payments on a post-tax basis totalled $2.4 billion in the first half of 2018. Payments for the full year are expected to be just over $3 billion on a post-tax basis.

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


Operating metrics
 
First half 2018
 
Financial metrics
 
First half 2018
 
(vs. First half 2017)
 
 
(vs. First half 2017)
Tier 1 process safety events*
 
8
 
Underlying RC profit*i
 
$5.4bn
 
(-3)
 
 
(+$3.2bn)
Reported recordable injury frequency*
 
0.22
 
Operating cash flow excluding Gulf of Mexico oil spill payments (post-tax)
 
(b) 
 
(—)
 
 
 
Group production
 
3,662mboe/d
 
Organic capital expenditureii
 
$7.0bn
 
(+3.3%)
 
 
(-$0.9bn)
Upstream production (excludes Rosneft segment)
 
2,535mboe/d
 
Gulf of Mexico oil spill payments (post-tax)(c)
 
$2.4bn
 
(+5.2%)
 
 
(-$1.9bn)
Upstream unit production costs
 
$7.32/boe
 
Divestment proceeds*
 
$0.3bn
 
(+1.6%)
 
 
(-$0.4bn)
BP-operated Upstream plant reliability(a)
 
95.8%
 
Net debt ratio* (gearing)iii
 
27.8%
 
(+0.7)
 
 
(-1.0)
Refining availability*
 
94.1%
 
Dividend per ordinary share(d)
 
10.25 cents
 
(-0.7)
 
 
(+2.5%)
(a)
BP-operated Upstream operating efficiency* has been replaced with Upstream plant reliability as a group operating metric in the first quarter 2018. It is more comparable with the equivalent metric disclosed for the Downstream, which is ‘Refining availability’.
(b)
SEC regulations do not permit inclusion of this non-GAAP metric in this SEC filing. Operating cash flow excluding Gulf of Mexico oil spill payments is calculated by excluding post-tax payments relating to the Gulf of Mexico oil spill from net cash provided by operating activities, as reported in the condensed group cash flow statement. For the half year, net cash provided by operating activities was $10.0 billion and post-tax Gulf of Mexico oil spill payments were $2.4 billion.

6


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



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


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

7


Upstream
 
 
Second

Second

 
First

First

 
 
quarter

quarter

 
half

half

$ million
 
2018

2017

 
2018

2017

Sales and other operating revenues(a)
 
12,698

10,493

 
26,568

21,820

Profit before interest and tax
 
3,518

796

 
6,693

2,046

Inventory holding (gains) losses*
 
(4
)
(1
)
 
(5
)
5

RC profit before interest and tax
 
3,514

795

 
6,688

2,051

Net (favourable) adverse impact of non-operating items* and fair value accounting effects*
 
(6
)
(85
)
 
(23
)
29

Underlying RC profit (loss) before interest and tax*(b)
 
3,508

710

 
6,665

2,080

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

Financial results
Sales and other operating revenues for the second quarter and half year were $13 billion and $27 billion respectively, compared with $10 billion and $22 billion for the corresponding periods in 2017. For the second quarter and half year, revenues were higher due to higher realizations, higher sales volumes, and higher gas marketing and trading revenues.
The replacement cost profit before interest and tax for the second quarter and half year was $3,514 million and $6,688 million respectively, compared with $795 million and $2,051 million for the same periods in 2017. The second quarter and half year included a net non-operating gain of $27 million and a charge of $77 million respectively, compared with a net charge of $21 million and $381 million for the same periods in 2017. Fair value accounting effects in the second quarter and half year had an adverse impact of $21 million and a favourable impact of $100 million respectively, compared with a favourable impact of $106 million and $352 million in the same periods of 2017.
After adjusting for non-operating items and fair value accounting effects, the underlying replacement cost profit before interest and tax for the second quarter and half year was $3,508 million and $6,665 million respectively, compared with $710 million and $2,080 million for the same periods in 2017. The result for the second quarter and half year mainly reflected higher liquids and gas realizations, lower exploration write-offs, and higher production from the ramp-up of major projects*.
Production
Production for the quarter was 2,465mboe/d, 1.4% higher than the second quarter of 2017. Underlying production* for the quarter increased by 9.6%, due to the ramp-up of major projects.
For the half year, production was 2,535mboe/d, 5.2% higher than 2017. Underlying production for the half year was 11.7% higher than 2017 due to the ramp-up of major projects.
Key events
In the second quarter, the Rosneft-operated Taas-Yuryakh expansion project (BP 20%) completed commissioning of the main project facilities for the Srednebotuobinskoye oil and gas condensate field in Eastern Siberia, Russia. This is the second of six major projects expected to come onstream for BP this year. The project was delivered under budget and on schedule.
On 7 June, BP won the licence for the Dois Irmãos block located in the Campos basin, offshore Brazil, as a result of the fourth Pre-Salt Production Sharing Contract Bid Round (Petrobras operator 45%, BP 30%, and Equinor 25%).
On 2 July, BP and its partners in the Shah Deniz consortium (BP operator 28.8%) announced the start-up of the Shah Deniz 2 gas project in Azerbaijan, including its first commercial gas delivery to Turkey. Shah Deniz 2 is the starting point for the Southern Gas Corridor series of pipelines that will deliver gas from the Caspian Sea direct to European markets and the third of six major projects expected to come onstream for BP this year. The project started up under budget and on schedule.
On 3 July, BP announced that it has entered into an agreement to purchase from ConocoPhillips a 16.5% interest in the BP-operated Clair field, west of Shetland in the UK. As a result, BP’s interest in Clair will increase to 45.1%. Simultaneously BP has entered into agreements to sell to ConocoPhillips BP’s entire 39.2% interest in the Greater Kuparuk Area on the North Slope of Alaska as well as BP’s holding in the Kuparuk Transportation Company. The two transactions together are expected to be cash neutral. The transactions remain subject to regulatory approvals.
On 26 July, BP announced that BP America Production Company will acquire from BHP Billiton Petroleum (North America) Inc. 100% of the issued share capital of Petrohawk Energy Corporation for a total consideration of $10.5 billion subject to customary adjustments. These unconventional oil and gas assets comprise 470,000 net acres of licences, including a new position for BP in the liquids-rich Permian-Delaware basin, and two premium positions in the Eagle Ford and Haynesville basins. The assets have combined current production of 190,000 barrels of oil equivalent per day, about 45% of which is liquid hydrocarbons, as well as undeveloped resources. The transaction is anticipated to complete by the end of October subject to regulatory approvals.
This builds on the progress announced in our first-quarter results, which comprised the following: BP announced the start of gas production from the Atoll Phase One project in Egypt; BP confirmed that the governments of Mauritania and Senegal signed an Inter-Government Cooperation Agreement (ICA) which will enable the development of the BP-operated Tortue/Ahmeyim gas project; BP took final investment decisions on the two new North Sea developments, Alligin and Vorlich satellite fields; BP’s equity interest (14.67%) in the ADNOC Offshore concession in Abu Dhabi expired; BP announced that, together with its partner, the Oman Oil Company Exploration & Production, it has approved the development of Ghazeer, the second phase of the Khazzan gas field in Oman; BP and state-owned Brazilian oil company Petrobras announced the signing of a memorandum of understanding to form a strategic alliance to jointly explore potential business opportunities both in Brazil and beyond; BP together with its partner Reliance Industries Limited, announced the sanction of the Satellite Cluster project off the east coast of India; BP and the State Oil Company

8


Upstream (continued)
of the Azerbaijan Republic (SOCAR) signed a new production-sharing agreement* for the joint exploration and development of Block D230 in the North Absheron basin in the Azerbaijan sector of the Caspian Sea.
Outlook
Looking ahead, we expect third-quarter reported production to be broadly flat with the second quarter with continued seasonal turnaround and maintenance activities.
The commentary above contains forward-looking statements and should be read in conjunction with the cautionary statement on page 43.

 
 
Second

Second

 
First

First

 
 
quarter

quarter

 
half

half

$ million
 
2018

2017

 
2018

2017

Underlying RC profit before interest and tax
 
 
 
 
 
 
US
 
742

179

 
1,268

345

Non-US
 
2,766

531

 
5,397

1,735

 
 
3,508

710

 
6,665

2,080

Non-operating items
 
 
 
 
 
 
US
 
(29
)
(34
)
 
(174
)
(46
)
Non-US(a)
 
56

13

 
97

(335
)
 
 
27

(21
)
 
(77
)
(381
)
Fair value accounting effects
 
 
 
 
 
 
US
 
(143
)
92

 
(152
)
284

Non-US
 
122

14

 
252

68

 
 
(21
)
106

 
100

352

RC profit before interest and tax
 
 
 
 
 
 
US
 
570

237

 
942

583

Non-US
 
2,944

558

 
5,746

1,468

 
 
3,514

795

 
6,688

2,051

Exploration expense
 
 
 
 
 
 
US
 
77

25

 
386

65

Non-US(b)
 
87

825

 
292

1,197

 
 
164

850

 
678

1,262

Of which: Exploration expenditure written off(b)
 
81

753

 
507

1,014

Production (net of royalties)(c)
 
 
 
 
 
 
Liquids* (mb/d)
 
 
 
 
 
 
US
 
411

418

 
429

433

Europe
 
147

122

 
143

118

Rest of World
 
659

812

 
695

819

 
 
1,217

1,352

 
1,267

1,371

Of which equity-accounted entities
 
112

202

 
144

208

Natural gas (mmcf/d)
 
 
 
 
 
 
US
 
1,744

1,576

 
1,767

1,585

Europe
 
202

274

 
209

269

Rest of World
 
5,297

4,410

 
5,376

4,173

 
 
7,242

6,260

 
7,352

6,026

Of which equity-accounted entities
 
493

558

 
485

544

Total hydrocarbons* (mboe/d)
 
 
 
 
 
 
US
 
711

689

 
734

706

Europe
 
182

169

 
180

165

Rest of World
 
1,572

1,572

 
1,622

1,539

 
 
2,465

2,431

 
2,535

2,410

Of which equity-accounted entities
 
197

298

 
227

301

Average realizations*(d)
 
 
 
 
 
 
Total liquids(e) ($/bbl)
 
67.24

46.27

 
64.21

48.09

Natural gas ($/mcf)
 
3.65

3.19

 
3.72

3.34

Total hydrocarbons ($/boe)
 
43.37

33.59

 
42.36

35.37

(a)
First half 2017 relates primarily to an impairment charge related to the sale of the Forties Pipeline System business to INEOS.
(b)
Second quarter and first half 2017 predominantly relates to the write-off of exploration well and lease costs in Angola. First half 2017 also includes write-off of exploration wells in Egypt.
(c)
Includes BP’s share of production of equity-accounted entities in the Upstream segment.
(d)
Realizations are based on sales by consolidated subsidiaries only – this excludes equity-accounted entities.
(e)
Includes condensate, natural gas liquids and bitumen.

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

9


Downstream
 
 
Second

Second

 
First

First

 
 
quarter

quarter

 
half

half

$ million
 
2018

2017

 
2018

2017

Sales and other operating revenues(a)
 
69,174

52,195

 
130,580

102,275

Profit before interest and tax
 
2,036

988

 
3,818

2,792

Inventory holding (gains) losses*
 
(1,196
)
579

 
(1,265
)
481

RC profit before interest and tax
 
840

1,567

 
2,553

3,273

Net (favourable) adverse impact of non-operating items* and fair value accounting effects*
 
615

(154
)
 
728

(118
)
Underlying RC profit before interest and tax*(b)
 
1,455

1,413

 
3,281

3,155

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

Financial results
Sales and other operating revenues for the second quarter and half year were $69 billion and $131 billion respectively, compared with $52 billion and $102 billion for the corresponding periods in 2017. The increase in the second quarter and half year was mainly due to higher oil prices.
The replacement cost profit before interest and tax for the second quarter and half year was $840 million and $2,553 million respectively, compared with $1,567 million and $3,273 million for the same periods in 2017.
The second quarter and half year include a net non-operating charge of $225 million and $278 million respectively, compared with a gain of $138 million and $62 million for the same periods in 2017. Fair value accounting effects had an adverse impact of $390 million in the second quarter and $450 million for the half year, compared with a favourable impact of $16 million and $56 million for the same periods in 2017.
After adjusting for non-operating items and fair value accounting effects, the underlying replacement cost profit before interest and tax for the second quarter and half year was $1,455 million and $3,281 million respectively, compared with $1,413 million and $3,155 million for the same periods in 2017.
Replacement cost profit before interest and tax for the fuels, lubricants and petrochemicals businesses is set out on page 11.
Fuels
The fuels business reported an underlying replacement cost profit before interest and tax of $1,054 million for the second quarter and $2,452 million for the half year, compared with $908 million and $2,108 million for the same periods in 2017. The result for the quarter and half year reflects a higher refining performance but a weak supply and trading contribution with a small loss in the second quarter. The result also reflects continued strong fuels marketing performance despite the adverse lag impact of increasing crude oil prices.
The refining performance for the quarter and half year reflects the benefits from increased commercial optimization with record levels of crude processed at our Whiting refinery, stronger industry refining margins and higher North American heavy crude oil discounts which was partly offset by pipeline capacity apportionment impacts.
In fuels marketing our convenience partnership model is now in more than 1,200 sites across our network and in Mexico we now have more than 300 BP-branded retail sites operational.
This quarter, we continued to progress our advanced mobility agenda. In May, we invested $20 million in StoreDot, a leading developer of ultra-fast charging battery technology and in July, we completed the acquisition of Chargemaster, the operator of the UK’s largest electric vehicle charging network, for £130 million.
In the quarter we signed a memorandum of understanding with state-owned Brazilian oil company Petrobras to explore potential joint commercial agreements in Brazil. We also announced that we will not be continuing with the proposed acquisition of Woolworths’ retail fuel and convenience business in Australia.
Lubricants
The lubricants business reported an underlying replacement cost profit before interest and tax of $326 million for the second quarter and $657 million for the half year, compared with $355 million and $748 million for the same periods in 2017. The result for the quarter and half year reflects continued premium brand growth, more than offset by the adverse lag impact of increasing base oil prices.
During the first quarter we significantly strengthened our relationship with Renault through the continuation of our Renault Formula 1 sponsorship with Renault Sport Racing, and we are exploring new opportunities to work globally with the Renault-Nissan-Mitsubishi Alliance.
Petrochemicals
The petrochemicals business reported an underlying replacement cost profit before interest and tax of $75 million for the second quarter and $172 million for the half year, compared with $150 million and $299 million for the same periods in 2017. The result for the quarter and half year reflects an improved margin environment, increased margin optimization and lower costs. This was more than offset by a significantly higher level of turnaround activity and the impact from the divestment of our interest in the SECCO joint venture, which completed in the fourth quarter of last year.
Outlook
Looking to the third quarter, we expect lower industry refining margins. We also expect significantly higher levels of turnaround activity in the second half of the year, particularly at our Whiting refinery in the US.
The commentary above contains forward-looking statements and should be read in conjunction with the cautionary statement on page 43.

10


Downstream (continued)
 
 
Second

Second

 
First

First

 
 
quarter

quarter

 
half

half

$ million
 
2018

2017

 
2018

2017

Underlying RC profit before interest and tax - by region
 
 
 
 
 
 
US
 
399

283

 
988

837

Non-US
 
1,056

1,130

 
2,293

2,318

 
 
1,455

1,413

 
3,281

3,155

Non-operating items
 
 
 
 
 
 
US
 
(155
)
28

 
(172
)
16

Non-US
 
(70
)
110

 
(106
)
46

 
 
(225
)
138

 
(278
)
62

Fair value accounting effects(a)
 
 
 
 
 
 
US
 
(299
)
10

 
(420
)
(52
)
Non-US
 
(91
)
6

 
(30
)
108

 
 
(390
)
16

 
(450
)
56

RC profit before interest and tax
 
 
 
 
 
 
US
 
(55
)
321

 
396

801

Non-US
 
895

1,246

 
2,157

2,472

 
 
840

1,567

 
2,553

3,273

Underlying RC profit before interest and tax - by business(b)(c)
 
 
 
 
 
 
Fuels
 
1,054

908

 
2,452

2,108

Lubricants
 
326

355

 
657

748

Petrochemicals
 
75

150

 
172

299

 
 
1,455

1,413

 
3,281

3,155

Non-operating items and fair value accounting effects(a)
 
 
 
 
 
 
Fuels
 
(584
)
159

 
(694
)
163

Lubricants
 
(26
)
(2
)
 
(29
)
(5
)
Petrochemicals
 
(5
)
(3
)
 
(5
)
(40
)
 
 
(615
)
154

 
(728
)
118

RC profit before interest and tax(b)(c)
 
 
 
 
 
 
Fuels
 
470

1,067

 
1,758

2,271

Lubricants
 
300

353

 
628

743

Petrochemicals
 
70

147

 
167

259

 
 
840

1,567

 
2,553

3,273

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

13.8

 
13.3

12.8

 
 
 
 
 
 
 
Refinery throughputs (mb/d)
 
 
 
 
 
 
US
 
666

708

 
690

702

Europe
 
786

782

 
792

791

Rest of World
 
228

198

 
238

189

 
 
1,680

1,688

 
1,720

1,682

Refining availability* (%)
 
93.3

94.5

 
94.1

94.8

 
 
 
 
 
 
 
Marketing sales of refined products (mb/d)
 
 
 
 
 
 
US
 
1,161

1,177

 
1,129

1,146

Europe
 
1,135

1,153

 
1,090

1,111

Rest of World
 
477

497

 
479

505

 
 
2,773

2,827

 
2,698

2,762

Trading/supply sales of refined products
 
3,247

2,996

 
3,215

2,978

Total sales volumes of refined products
 
6,020

5,823

 
5,913

5,740

 
 
 
 
 
 
 
Petrochemicals production (kte)
 
 
 
 
 
 
US
 
404

672

 
903

1,170

Europe
 
1,094

1,365

 
2,222

2,618

Rest of World
 
1,358

2,001

 
2,749

4,074

 
 
2,856

4,038

 
5,874

7,862

(a)
For Downstream, fair value accounting effects arise solely in the fuels business. See page 35 for further information.
(b)
Segment-level overhead expenses are included in the fuels business result.
(c)
Results from petrochemicals at our Gelsenkirchen and Mülheim sites in Germany are reported in the fuels business.


11


Rosneft
 
 
Second

Second

 
First

First

 
 
quarter

quarter

 
half

half

$ million
 
2018(a)

2017

 
2018(a)

2017

Profit before interest and tax(b)
 
876

271

 
1,145

344

Inventory holding (gains) losses*
 
(110
)
8

 
(132
)
34

RC profit before interest and tax
 
766

279

 
1,013

378

Net charge (credit) for non-operating items*
 


 


Underlying RC profit before interest and tax*
 
766

279

 
1,013

378

Financial results
Replacement cost (RC) profit before interest and tax and underlying RC profit before interest and tax for the second quarter and half year was $766 million and $1,013 million respectively, compared with $279 million and $378 million for the same periods in 2017. There were no non-operating items in the second quarter and half year of either year.
Compared with the same periods in 2017, the results for the second quarter and half year were primarily affected by higher oil prices, favourable foreign exchange and duty lag effects, and certain one-off items.
BP’s two nominees, Bob Dudley and Guillermo Quintero, were re-elected to Rosneft’s board at the annual general meeting (AGM) on 21 June. At the AGM, shareholders also approved a resolution to pay a dividend of 6.65 roubles per ordinary share, which brings the total dividend for 2017 to 10.48 roubles per ordinary share, constituting 50% of the company’s IFRS net profit. BP expects to receive a dividend of 12.5 billion roubles, after the deduction of withholding tax, on 31 July 2018.

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

 
 
Second

Second

 
First

First

 
 
quarter

quarter

 
half

half

 
 
2018(a)

2017

 
2018(a)

2017

Production (net of royalties) (BP share)
 
 
 
 
 
 
Liquids* (mb/d)
 
909

902

 
906

907

Natural gas (mmcf/d)
 
1,262

1,302

 
1,285

1,318

Total hydrocarbons* (mboe/d)
 
1,127

1,126

 
1,127

1,134

(a)
The operational and financial information of the Rosneft segment for the second quarter and half year is based on preliminary operational and financial results of Rosneft for the half year ended 30 June 2018. Actual results may differ from these amounts.
(b)
The Rosneft segment result includes equity-accounted earnings arising from BP’s 19.75% shareholding in Rosneft as adjusted for the accounting required under IFRS relating to BP’s purchase of its interest in Rosneft and the amortization of the deferred gain relating to the divestment of BP’s interest in TNK-BP. These adjustments increase the reported profit before interest and tax, as shown in the table above, compared with the equivalent amount in Russian roubles in Rosneft’s IFRS financial statements. BP’s share of Rosneft’s profit before interest and tax for each year-to-date period is calculated by translating the amounts reported in Russian roubles into US dollars using the average exchange rate for the year to date. BP's share of Rosneft’s earnings after finance costs, taxation and non-controlling interests, as adjusted, is included in the BP group income statement within profit before interest and taxation.


12


Other businesses and corporate
 
 
Second

Second

 
First

First

 
 
quarter

quarter

 
half

half

$ million
 
2018

2017

 
2018

2017

Sales and other operating revenues(a)
 
376

326

 
719

611

Profit (loss) before interest and tax
 
 
 
 
 
 
Gulf of Mexico oil spill - business economic loss claims
 
(249
)
(260
)
 
(249
)
(260
)
Gulf of Mexico oil spill - other
 
(184
)
(87
)
 
(270
)
(122
)
Other
 
(592
)
(374
)
 
(1,077
)
(770
)
Profit (loss) before interest and tax
 
(1,025
)
(721
)
 
(1,596
)
(1,152
)
Inventory holding (gains) losses*
 


 


RC profit (loss) before interest and tax
 
(1,025
)
(721
)
 
(1,596
)
(1,152
)
Net charge (credit) for non-operating items*
 
 
 
 
 
 
Gulf of Mexico oil spill - business economic loss claims
 
249

260

 
249

260

Gulf of Mexico oil spill - other
 
184

87

 
270

122

Other
 
115

8

 
208

(36
)
Net charge (credit) for non-operating items
 
548

355

 
727

346

Underlying RC profit (loss) before interest and tax*
 
(477
)
(366
)
 
(869
)
(806
)
Underlying RC profit (loss) before interest and tax
 
 
 
 
 
 
US
 
(123
)
(104
)
 
(270
)
(301
)
Non-US
 
(354
)
(262
)
 
(599
)
(505
)
 
 
(477
)
(366
)
 
(869
)
(806
)
Non-operating items
 
 
 
 
 
 
US
 
(498
)
(350
)
 
(646
)
(388
)
Non-US
 
(50
)
(5
)
 
(81
)
42

 
 
(548
)
(355
)
 
(727
)
(346
)
RC profit (loss) before interest and tax
 
 
 
 
 
 
US
 
(621
)
(454
)
 
(916
)
(689
)
Non-US
 
(404
)
(267
)
 
(680
)
(463
)
 
 
(1,025
)
(721
)
 
(1,596
)
(1,152
)
(a)
Includes sales to other segments.

Other businesses and corporate comprises our alternative energy business, shipping, treasury, corporate activities including centralized functions, and the costs of the Gulf of Mexico oil spill.
Financial results
The replacement cost loss before interest and tax for the second quarter and half year was $1,025 million and $1,596 million respectively, compared with $721 million and $1,152 million for the same periods in 2017.
The results included a net non-operating charge of $548 million for the second quarter and $727 million for the half year, compared with a charge of $355 million and $346 million for the same periods in 2017. See Note 2 on page 21 for more information on the Gulf of Mexico oil spill.
After adjusting for non-operating items, the underlying replacement cost loss before interest and tax for the second quarter and half year was $477 million and $869 million respectively, compared with $366 million and $806 million for the same periods in 2017. The underlying charge for the second quarter was impacted by adverse foreign exchange effects.
Alternative Energy
The net ethanol-equivalent production (which includes ethanol and sugar) for the second quarter and half year was 259 million litres and 267 million litres respectively, compared with 227 million litres for the same periods in 2017 (there was no production for the first quarter in 2017 due to the inter-harvest period).
Net wind generation capacity* was 1,432MW at 30 June 2018, compared with 1,432MW at 30 June 2017. BP’s net share of wind generation for the second quarter and half year was 984GWh and 2,201GWh respectively, compared with 1,053GWh and 2,212GWh for the same periods in 2017.

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





13


Financial statements
Group income statement
 
 
Second

Second

 
First

First

 
 
quarter

quarter

 
half

half

$ million
 
2018

2017

 
2018

2017

 
 
 
 
 
 
 
Sales and other operating revenues (Note 6)
 
75,439

56,511

 
143,611

112,374

Earnings from joint ventures – after interest and tax
 
220

160

 
513

365

Earnings from associates – after interest and tax
 
1,027

371

 
1,441

522

Interest and other income
 
165

127

 
324

249

Gains on sale of businesses and fixed assets
 
56

197

 
161

242

Total revenues and other income
 
76,907

57,366

 
146,050

113,752

Purchases
 
58,424

42,555

 
109,936

83,530

Production and manufacturing expenses(a)
 
5,515

5,761

 
10,953

11,016

Production and similar taxes (Note 8)
 
531

347

 
899

815

Depreciation, depletion and amortization (Note 7)
 
3,811

3,793

 
7,742

7,635

Impairment and losses on sale of businesses and fixed assets
 
(23
)
51

 
68

504

Exploration expense
 
164

850

 
678

1,262

Distribution and administration expenses
 
2,929

2,540

 
5,723

4,893

Profit (loss) before interest and taxation
 
5,556

1,469

 
10,051

4,097

Finance costs(a)
 
535

487

 
1,088

947

Net finance expense relating to pensions and other post-retirement benefits
 
31

54

 
62

107

Profit (loss) before taxation
 
4,990

928

 
8,901

3,043

Taxation(a)
 
2,117

772

 
3,497

1,395

Profit (loss) for the period
 
2,873

156

 
5,404

1,648

Attributable to
 
 
 
 
 
 
BP shareholders
 
2,799

144

 
5,268

1,593

Non-controlling interests
 
74

12

 
136

55

 
 
2,873

156

 
5,404

1,648

 
 
 
 
 
 
 
Earnings per share (Note 9)
 
 
 
 
 
 
Profit (loss) for the period attributable to BP shareholders
 
 
 
 
 
 
Per ordinary share (cents)
 
 
 
 
 
 
Basic
 
14.03

0.73

 
26.42

8.12

Diluted
 
13.96

0.72

 
26.27

8.08

Per ADS (dollars)
 
 
 
 
 
 
Basic
 
0.84

0.04

 
1.59

0.49

Diluted
 
0.84

0.04

 
1.58

0.48

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


14


Condensed group statement of comprehensive income
 
 
Second

Second

 
First

First

 
 
quarter

quarter

 
half

half

$ million
 
2018

2017

 
2018

2017

 
 
 
 
 
 
 
Profit (loss) for the period
 
2,873

156

 
5,404

1,648

Other comprehensive income
 
 
 
 
 
 
Items that may be reclassified subsequently to profit or loss
 
 
 
 
 
 
Currency translation differences
 
(2,612
)
(103
)
 
(2,081
)
1,111

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

4

 

5

Available-for-sale investments
 

1

 

3

Cash flow hedges and costs of hedging
 
(107
)
148

 
(189
)
277

Share of items relating to equity-accounted entities, net of tax
 
(33
)
72

 
122

303

Income tax relating to items that may be reclassified
 
52

4

 
(38
)
(121
)
 
 
(2,700
)
126

 
(2,186
)
1,578

Items that will not be reclassified to profit or loss
 
 
 
 
 
 
Remeasurements of the net pension and other post-retirement benefit liability or asset
 
1,714

318

 
2,579

1,045

Cash flow hedges that will subsequently be transferred to the balance sheet
 
(35
)

 
(22
)

Income tax relating to items that will not be reclassified
 
(557
)
(102
)
 
(822
)
(348
)
 
 
1,122

216

 
1,735

697

Other comprehensive income
 
(1,578
)
342

 
(451
)
2,275

Total comprehensive income
 
1,295

498

 
4,953

3,923

Attributable to
 
 
 
 
 
 
BP shareholders
 
1,268

472

 
4,848

3,835

Non-controlling interests
 
27

26

 
105

88

 
 
1,295

498

 
4,953

3,923


15


Condensed group statement of changes in equity
 
 
BP shareholders’

Non-controlling

Total

$ million
 
equity

interests

equity

At 31 December 2017
 
98,491

1,913

100,404

Adjustment on adoption of IFRS 9, net of tax(a)
 
(180
)

(180
)
At 1 January 2018
 
98,311

1,913

100,224

 
 
 
 
 
Total comprehensive income
 
4,848

105

4,953

Dividends
 
(3,556
)
(70
)
(3,626
)
Cash flow hedges transferred to the balance sheet, net of tax
 
5


5

Repurchase of ordinary share capital
 
(200
)

(200
)
Share-based payments, net of tax
 
414


414

Transactions involving non-controlling interests, net of tax
 
(1
)
1


At 30 June 2018
 
99,821

1,949

101,770

 
 
 
 
 
 
 
BP shareholders’

Non-controlling

Total

$ million
 
equity

interests

equity

 
 
 
 
 
At 1 January 2017
 
95,286

1,557

96,843

 
 
 
 
 
Total comprehensive income
 
3,835

88

3,923

Dividends
 
(2,850
)
(77
)
(2,927
)
Share-based payments, net of tax
 
334


334

Share of equity-accounted entities' changes in equity, net of tax
 
198


198

Transactions involving non-controlling interests, net of tax
 

90

90

At 30 June 2017
 
96,803

1,658

98,461

(a)
See Note 1 for further information.


16


Group balance sheet
 
 
30 June

31 December

$ million
 
2018

2017

Non-current assets
 
 
 
Property, plant and equipment
 
124,390

129,471

Goodwill
 
11,319

11,551

Intangible assets
 
17,808

18,355

Investments in joint ventures
 
8,293

7,994

Investments in associates
 
17,835

16,991

Other investments
 
1,284

1,245

Fixed assets
 
180,929

185,607

Loans
 
505

646

Trade and other receivables
 
1,472

1,434

Derivative financial instruments
 
4,633

4,110

Prepayments
 
1,134

1,112

Deferred tax assets
 
3,908

4,469

Defined benefit pension plan surpluses
 
6,354

4,169

 
 
198,935

201,547

Current assets
 
 
 
Loans
 
298

190

Inventories
 
21,004

19,011

Trade and other receivables
 
25,130

24,849

Derivative financial instruments
 
3,614

3,032

Prepayments
 
1,277

1,414

Current tax receivable
 
783

761

Other investments
 
106

125

Cash and cash equivalents
 
22,185

25,586

 
 
74,397

74,968

Assets classified as held for sale (Note 3)
 
2,294


 
 
76,691

74,968

Total assets
 
275,626

276,515

Current liabilities
 
 
 
Trade and other payables
 
46,635

44,209

Derivative financial instruments
 
3,643

2,808

Accruals
 
3,741

4,960

Finance debt
 
10,625

7,739

Current tax payable
 
2,283

1,686

Provisions
 
2,313

3,324

 
 
69,240

64,726

Liabilities directly associated with assets classified as held for sale (Note 3)
 
291


 
 
69,531

64,726

Non-current liabilities
 
 
 
Other payables
 
13,696

13,889

Derivative financial instruments
 
5,126

3,761

Accruals
 
599

505

Finance debt
 
49,733

55,491

Deferred tax liabilities
 
8,828

7,982

Provisions
 
17,783

20,620

Defined benefit pension plan and other post-retirement benefit plan deficits
 
8,560

9,137

 
 
104,325

111,385

Total liabilities
 
173,856

176,111

Net assets
 
101,770

100,404

Equity
 
 
 
BP shareholders’ equity
 
99,821

98,491

Non-controlling interests
 
1,949

1,913

Total equity
 
101,770

100,404



17


Condensed group cash flow statement
 
 
Second

Second

 
First

First

 
 
quarter

quarter

 
half

half

$ million
 
2018

2017

 
2018

2017

Operating activities
 
 
 
 
 
 
Profit (loss) before taxation
 
4,990

928

 
8,901

3,043

Adjustments to reconcile profit (loss) before taxation to net cash provided by operating activities
 
 
 
 
 
 
Depreciation, depletion and amortization and exploration expenditure written off
 
3,892

4,546

 
8,249

8,649

Impairment and (gain) loss on sale of businesses and fixed assets
 
(79
)
(146
)
 
(93
)
262

Earnings from equity-accounted entities, less dividends received
 
(988
)
(103
)
 
(1,524
)
(323
)
Net charge for interest and other finance expense, less net interest paid
 
191

84

 
271

336

Share-based payments
 
167

156

 
404

318

Net operating charge for pensions and other post-retirement benefits, less contributions and benefit payments for unfunded plans
 
(62
)
54

 
(264
)
(19
)
Net charge for provisions, less payments
 
80

183

 
224

6

Movements in inventories and other current and non-current assets and liabilities
 
(570
)
3

 
(3,968
)
(3,597
)
Income taxes paid
 
(1,315
)
(815
)
 
(2,248
)
(1,671
)
Net cash provided by operating activities
 
6,306

4,890

 
9,952

7,004

Investing activities
 
 
 
 
 
 
Expenditure on property, plant and equipment, intangible and other assets
 
(3,484
)
(4,181
)
 
(7,070
)
(8,004
)
Acquisitions, net of cash acquired
 
(1
)
(123
)
 
(1
)
(165
)
Investment in joint ventures
 
(18
)
(10
)
 
(57
)
(30
)
Investment in associates
 
(322
)
(174
)
 
(660
)
(357
)
Total cash capital expenditure
 
(3,825
)
(4,488
)
 
(7,788
)
(8,556
)
Proceeds from disposal of fixed assets
 
105

312

 
190

500

Proceeds from disposal of businesses, net of cash disposed
 
45

140

 
127

213

Proceeds from loan repayments
 
24

19

 
33

33

Net cash used in investing activities
 
(3,651
)
(4,017
)
 
(7,438
)
(7,810
)
Financing activities
 
 
 
 
 
 
Net issue (repurchase) of shares
 
(90
)

 
(200
)

Proceeds from long-term financing
 
910

1,720

 
1,032

5,433

Repayments of long-term financing
 
(1,726
)
(1,463
)
 
(2,883
)
(2,380
)
Net increase (decrease) in short-term debt
 
292

(299
)
 
(57
)
16

Net increase (decrease) in non-controlling interests
 

51

 
(1
)
81

Dividends paid - BP shareholders
 
(1,727
)
(1,546
)
 
(3,556
)
(2,850
)
 - non-controlling interests
 
(57
)
(62
)
 
(70
)
(77
)
Net cash provided by (used in) financing activities
 
(2,398
)
(1,599
)
 
(5,735
)
223

Currency translation differences relating to cash and cash equivalents
 
(314
)
202

 
(169
)
369

Increase (decrease) in cash and cash equivalents
 
(57
)
(524
)
 
(3,390
)
(214
)
Cash and cash equivalents at beginning of period
 
22,242

23,794

 
25,575

23,484

Cash and cash equivalents at end of period
 
22,185

23,270

 
22,185

23,270


18


Notes
Note 1. Basis of preparation

The interim financial information included in this report has been prepared in accordance with IAS 34 'Interim Financial Reporting'.
The results for the interim periods are unaudited and, in the opinion of management, include all adjustments necessary for a fair presentation of the results for each period. All such adjustments are of a normal recurring nature. This report should be read in conjunction with the consolidated financial statements and related notes for the year ended 31 December 2017 included in BP Annual Report and Form 20-F 2017.
The directors consider it appropriate to adopt the going concern basis of accounting in preparing these interim financial statements.
BP prepares its consolidated financial statements included within BP Annual Report and Form 20-F on the basis of International Financial Reporting Standards (IFRS) as issued by the International Accounting Standards Board (IASB), IFRS as adopted by the European Union (EU) and in accordance with the provisions of the UK Companies Act 2006. IFRS as adopted by the EU differs in certain respects from IFRS as issued by the IASB. The differences have no impact on the group’s consolidated financial statements for the periods presented.
The financial information presented herein has been prepared in accordance with the accounting policies expected to be used in preparing BP Annual Report and Form 20-F 2018, which are the same as those used in preparing BP Annual Report and Form 20-F 2017 with the exception of the implementation of IFRS 9 'Financial Instruments' and IFRS 15 'Revenue from Contracts with Customers' from 1 January 2018.
New International Financial Reporting Standards adopted

BP adopted IFRS 9 ‘Financial Instruments’ and IFRS 15 ‘Revenue from Contracts with Customers’ with effect from 1 January 2018. Information on the implementation of new accounting standards is included in BP Annual Report and Form 20-F 2017 - Financial statements - Note 1 Significant accounting policies, judgements, estimates and assumptions - Impact of new International Financial Reporting Standards.
IFRS 9 ‘Financial Instruments’
IFRS 9 provides a single classification and measurement approach for financial assets that reflects the business model in which they are managed and their cash flow characteristics. The group’s financial assets are classified as measured at amortized cost, fair value through profit or loss, or fair value through other comprehensive income. Investments in equity instruments are classified as measured at fair value through profit or loss unless the group elects, on an instrument-by-instrument basis, on initial recognition to recognize fair value gains and losses in other comprehensive income. The adoption of IFRS 9 did not have a significant effect on the group’s accounting policies relating to financial liabilities.
Under IFRS 9, impairments of financial assets classified as measured at amortized cost are recognized on an expected loss basis which incorporates forward-looking information when assessing credit risk. Movements in the expected loss reserve are recognized in profit or loss.
Under IFRS 9, fair value movements on the time value and cross currency basis spreads of certain hedging instruments are initially recognized in equity to the extent that they relate to the hedged item. Previously these were recognized in the income statement. In addition where the gain or loss on cash flow hedging instruments initially reported in other comprehensive income is transferred to the initial carrying amount of a non-financial asset or liability this is no longer presented as a reclassification adjustment. Instead the transfer to the balance sheet is presented in the statement of changes in equity.
The overall impact on transition to IFRS 9, including the impact upon the group's share of equity-accounted entities, was a reduction of $180 million in net assets, net of tax. This adjustment mainly related to an increase in the credit reserve of financial assets in the scope of IFRS 9's impairment requirements. As permitted by IFRS 9 comparatives were not restated. For certain line items in the balance sheet the closing balance at 31 December 2017 and the opening balance at 1 January 2018 therefore differ (as summarized below). Cash and cash equivalents at the beginning of 2018 in the Condensed group cash flow statement and Note 11 (Net debt) are the 1 January 2018 amounts included in the table below.
 
 
 
 
Adjustment

 
 
31 December

1 January

on adoption

$ million
 
2017

2018

of IFRS 9

Non-current
 
 
 
 
Investments in equity-accounted entities
 
24,985

24,903

(82
)
Loans, trade and other receivables
 
2,080

2,069

(11
)
Deferred tax liabilities
 
(7,982
)
(7,946
)
36

Current
 
 
 
 
Loans, trade and other receivables
 
25,039

24,927

(112
)
Cash and cash equivalents
 
25,586

25,575

(11
)
 
 
 
 
 
Net assets
 
100,404

100,224

(180
)

19


Note 1. Basis of preparation (continued)
IFRS 15 ‘Revenue from Contracts with Customers’
Under IFRS 15, revenue from contracts with customers is recognized as or when the group satisfies a performance obligation by transferring a promised good or service to a customer. A good or service is transferred when the customer obtains control of that good or service. The transfer of control of oil, natural gas, natural gas liquids, LNG, petroleum and chemical products, and other items sold by the group usually coincides with title passing to the customer and the customer taking physical possession. The group principally satisfies its performance obligations at a point in time and the amounts of revenue recognized relating to performance obligations satisfied over time are not significant. The accounting for revenue under IFRS 15 does not, therefore, represent a substantive change from the group’s previous practice for recognizing revenue from sales to customers.
BP elected to apply the ‘modified retrospective’ approach to transition permitted by IFRS 15 under which comparative financial information is not restated. Certain changes in accounting arising from the implementation of IFRS 15 were identified but the standard did not have a material effect on the group's financial statements as at 1 January 2018 and so no transition adjustment was made.The implementation of the standard has also not had a material effect on the group’s results for the first half of 2018 compared to those that would have been reported under the group’s previous accounting policy for revenue.
An analysis of revenue from contracts with customers by product is presented in Note 6. Amounts presented for comparative periods in 2017 include revenues determined in accordance with the group's previous accounting policies relating to revenue. The total amounts presented do not, therefore, represent the revenue from contracts with customers that would have been reported for those periods had IFRS 15 been applied using a fully retrospective approach to transition but the differences are not significant.
Change in significant estimate - decommissioning provision

Decommissioning provision cost estimates are reviewed regularly and the latest review was undertaken in the second quarter. The timing and amount of estimated future expenditures has been re-assessed and discounted to determine the present value. As at 30 June 2018 the present value of the decommissioning provision has been determined by discounting the estimated cash flows expressed in expected future prices, i.e. taking account of expected inflation, at a nominal discount rate (2.5%). Prior to 30 June 2018, the group estimated future cash flows in real terms i.e. at current prices and discounted them using a real discount rate (0.5% as at 31 December 2017).
The impact of the review was a reduction in the provision of $1.5 billion as at 30 June 2018, with a similar reduction in the carrying amount of property, plant and equipment. There was no significant impact on the income statement for the first half of 2018. The impact on the income statement for the second half of 2018 is estimated to be a decrease in depreciation, depletion and amortization of around $80 million and an increase in finance costs of around $120 million.
For further information on the group’s accounting policy on significant estimates and judgements relating to provisions, see BP Annual Report and 20-F 2017 - Financial statements - Note 1 Significant accounting policies, estimates and assumptions.




20


Note 2. Gulf of Mexico oil spill

(a) Overview
The information presented in this note should be read in conjunction with Note 2 of the financial statements and pages 270-272 of Legal proceedings included in BP Annual Report and Form 20-F 2017.
The group income statement includes a post-tax charge for the second quarter of $193 million relating to business economic loss (BEL) claims and $126 million relating to other claims and litigation. The group income statement also includes finance costs relating to the unwinding of discounting effects relating to payables.
The amounts set out below reflect the impacts on the financial statements of the Gulf of Mexico oil spill for the periods presented. The income statement, balance sheet and cash flow statement impacts are included within the relevant line items in those statements as set out below.

 
 
Second

Second

 
First

First

 
 
quarter

quarter

 
half

half

$ million
 
2018

2017

 
2018

2017

Income statement
 
 
 
 
 
 
Production and manufacturing expenses
 
433

347

 
519

382

Profit (loss) before interest and taxation
 
(433
)
(347
)
 
(519
)
(382
)
Finance costs
 
118

121

 
238

247

Profit (loss) before taxation
 
(551
)
(468
)
 
(757
)
(629
)
Taxation
 
106

154

 
167

202

Profit (loss) for the period
 
(445
)
(314
)
 
(590
)
(427
)
The cumulative pre-tax income statement charge since the incident, in April 2010, amounts to $66,522 million.
 
 
30 June

31 December

$ million
 
2018

2017

Balance sheet
 
 
 
Current assets
 
 
 
Trade and other receivables
 
207

252

Current liabilities
 
 
 
Trade and other payables
 
(2,464
)
(2,089
)
Provisions
 
(253
)
(1,439
)
Net current assets (liabilities)
 
(2,510
)
(3,276
)
Non-current assets
 
 
 
Deferred tax assets
 
1,775

2,067

Non-current liabilities
 
 
 
Other payables
 
(12,047
)
(12,253
)
Provisions
 
(172
)
(1,141
)
Deferred tax liabilities
 
3,816

3,634

Net non-current assets (liabilities)
 
(6,628
)
(7,693
)
Net assets (liabilities)
 
(9,138
)
(10,969
)

 
 
Second

Second

 
First

First

 
 
quarter

quarter

 
half

half

$ million
 
2018

2017

 
2018

2017

Cash flow statement - Operating activities
 
 
 
 
 
 
Profit (loss) before taxation
 
(551
)
(468
)
 
(757
)
(629
)
Adjustments to reconcile profit (loss) before taxation to net cash provided by operating activities
 
 
 
 
 
 
Net charge for interest and other finance expense, less net interest paid
 
118

121

 
238

247

Net charge for provisions, less payments
 
48

298

 
102

293

Movements in inventories and other current and non-current assets and liabilities
 
(693
)
(1,976
)
 
(2,281
)
(4,230
)
Pre-tax cash flows
 
(1,078
)
(2,025
)
 
(2,698
)
(4,319
)


21


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

(b) Provisions and other payables
Provisions
Movements in the remaining provision, which relates to litigation and claims, are shown in the table below.
$ million 
 
 
At 1 April 2018
 
2,231

Net increase in provision
 
411

Reclassified to other payables
 
(1,816
)
Utilization
 
(401
)
At 30 June 2018
 
425

Movements in the remaining provision, which relates to litigation and claims, for the half year are shown in the table below.
$ million 
 
 
At 1 January 2018
 
2,580

Net increase in provision
 
476

Reclassified to other payables
 
(1,875
)
Utilization
 
(756
)
At 30 June 2018
 
425

The provision includes amounts for the future cost of resolving claims by individuals and businesses for damage to real or personal property, lost profits or impairment of earning capacity and loss of subsistence use of natural resources.
PSC settlement
Provisions and other payables include the latest estimate for the remaining costs associated with the 2012 Plaintiffs’ Steering Committee (PSC) settlement. These costs relate predominantly to business economic loss (BEL) claims and associated administration costs. The amounts ultimately payable may differ from the amount provided and the timing of payments is uncertain.
The settlement programme’s determination of BEL claims was substantially completed by the end of 2017 and remaining claims continued to be processed in the first half of 2018 with only a very small number of claims now remaining to be determined. Nevertheless, a significant number of BEL claims determined by the settlement programme have been and continue to be appealed by BP and/or the claimants. During the second quarter settlement agreements were reached with claimants for a significant proportion of the provision existing at the beginning of the quarter. Amounts payable under these settlement agreements have been reclassified from provisions to other payables. The remaining amount provided for includes the latest estimate of the amounts that are expected ultimately to be paid to resolve outstanding BEL claims. Claims under appeal will ultimately only be resolved once the full judicial appeals process has been concluded, including appeals to the Federal District Court and Fifth Circuit, as may be the case, or when settlements are reached with individual claimants. Depending upon the ultimate resolution of these claims, the amounts payable may differ from those currently provided.
Payments to resolve outstanding claims under the PSC settlement are expected to be made over a number of years. The timing of payments, however, is uncertain, and, in particular, will be impacted by how long it takes to resolve claims that have been appealed and may be appealed in the future.

Other payables
Other payables includes amounts reclassified from provisions during the period which are payable over a period of up to nine years.
Other payables also includes amounts payable under the consent decree and settlement agreement with the United States and the five Gulf coast states for natural resource damages, state claims and Clean Water Act penalties, BP’s remaining commitment to fund the Gulf of Mexico Research Initiative, and amounts payable for economic loss and property damage claims settled in earlier periods.
Further information on provisions, other payables, and contingent liabilities is provided in BP Annual Report and Form 20-F 2017 - Financial statements - Note 2.



22


Note 3. Non-current assets held for sale

On 3 July 2018 BP announced that it had entered into an agreement with ConocoPhillips through which the group will sell its entire 39.2% non-operated interest in the Greater Kuparuk Area on the North Slope of Alaska and its holding in the Kuparuk Transportation Company. BP simultaneously entered into an agreement to buy a further 16.5% interest in the BP-operated Clair field, a core asset of BP's North Sea business in the UK, from ConocoPhillips. As a result of the transaction, BP will hold a 45.1% interest in the Clair field. The two transactions together are expected to be cash neutral for BP.
The transactions, which will be subject to State of Alaska, US federal and UK regulatory approvals and other approvals, are anticipated to complete in 2018. Assets and associated liabilities relating to BP’s interests in Kuparuk in Alaska, which are reported in the Upstream segment, are classified as held for sale in the group balance sheet at 30 June 2018.



Note 4. Event after the reporting period

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


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

Second

 
First

First

 
 
quarter

quarter

 
half

half

$ million
 
2018

2017

 
2018

2017

Upstream
 
3,514

795

 
6,688

2,051

Downstream
 
840

1,567

 
2,553

3,273

Rosneft
 
766

279

 
1,013

378

Other businesses and corporate(a)
 
(1,025
)
(721
)
 
(1,596
)
(1,152
)
 
 
4,095

1,920

 
8,658

4,550

Consolidation adjustment – UPII*
 
151

135

 
(9
)
67

RC profit (loss) before interest and tax*
 
4,246

2,055

 
8,649

4,617

Inventory holding gains (losses)*
 
 
 
 
 
 
Upstream
 
4

1

 
5

(5
)
Downstream
 
1,196

(579
)
 
1,265

(481
)
Rosneft (net of tax)
 
110

(8
)
 
132

(34
)
Profit (loss) before interest and tax
 
5,556

1,469

 
10,051

4,097

Finance costs
 
535

487

 
1,088

947

Net finance expense relating to pensions and other post-retirement benefits
 
31

54

 
62

107

Profit (loss) before taxation
 
4,990

928

 
8,901

3,043

 
 
 
 
 
 
 
RC profit (loss) before interest and tax*
 
 
 
 
 
 
US
 
(20
)
302

 
339

815

Non-US
 
4,266

1,753

 
8,310

3,802

 
 
4,246

2,055

 
8,649

4,617

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



23


Note 6. Sales and other operating revenues
 
 
Second

Second

 
First

First

 
 
quarter

quarter

 
half

half

$ million
 
2018

2017

 
2018

2017

By segment
 
 
 
 
 
 
Upstream
 
12,698

10,493

 
26,568

21,820

Downstream
 
69,174

52,195

 
130,580

102,275

Other businesses and corporate
 
376

326

 
719

611

 
 
82,248

63,014

 
157,867

124,706

 
 
 
 
 
 
 
Less: sales and other operating revenues between segments
 
 
 
 
 
 
Upstream
 
5,795

6,161

 
12,528

11,938

Downstream
 
785

208

 
1,267

122

Other businesses and corporate
 
229

134

 
461

272

 
 
6,809

6,503

 
14,256

12,332

 
 
 
 
 
 
 
Third party sales and other operating revenues
 
 
 
 
 
 
Upstream
 
6,903

4,332

 
14,040

9,882

Downstream
 
68,389

51,987

 
129,313

102,153

Other businesses and corporate
 
147

192

 
258

339

Total sales and other operating revenues
 
75,439

56,511

 
143,611

112,374

 
 
 
 
 
 
 
By geographical area
 
 
 
 
 
 
US
 
26,676

21,577

 
50,289

42,729

Non-US
 
56,032

41,103

 
107,272

81,123

 
 
82,708

62,680

 
157,561

123,852

Less: sales and other operating revenues between areas
 
7,269

6,169

 
13,950

11,478

 
 
75,439

56,511

 
143,611

112,374

 
 
 
 
 
 
 
Sales and other operating revenues include the following in relation to revenues from contracts with customers
 
 
 
 
 
 
Crude oil
 
17,167

11,784

 
32,084

22,780

Oil products
 
51,440

37,079

 
95,570

73,680

Natural gas, LNG and NGLs
 
4,960

3,479

 
10,119

7,317

Non-oil products and other revenues from contracts with customers
 
3,081

2,872

 
6,576

5,736

Revenues from contracts with customers(a)
 
76,648

55,214

 
144,349

109,513

(a)
See Note 1 for further information.


Note 7. Depreciation, depletion and amortization
 
 
Second

Second

 
First

First

 
 
quarter

quarter

 
half

half

$ million
 
2018

2017

 
2018

2017

Upstream
 
 
 
 
 
 
US
 
999

1,133

 
2,087

2,370

Non-US
 
2,226

2,090

 
4,498

4,144

 
 
3,225

3,223

 
6,585

6,514

Downstream
 
 
 
 
 
 
US
 
221

219

 
440

435

Non-US
 
293

274

 
595

553

 
 
514

493

 
1,035

988

Other businesses and corporate
 
 
 
 
 
 
US
 
16

16

 
32

32

Non-US
 
56

61

 
90

101

 
 
72

77

 
122

133

Total group
 
3,811

3,793

 
7,742

7,635



24


Note 8. Production and similar taxes
 
 
Second

Second

 
First

First

 
 
quarter

quarter

 
half

half

$ million
 
2018

2017

 
2018

2017

US
 
89

41

 
179

77

Non-US
 
442

306

 
720

738

 
 
531

347

 
899

815



Note 9. Earnings per share and shares in issue
Basic earnings per ordinary share (EpS) amounts are calculated by dividing the profit (loss) for the period attributable to ordinary shareholders by the weighted average number of ordinary shares outstanding during the period. During the quarter the company repurchased for cancellation 11 million ordinary shares for a total cost of $80 million, as part of the share buyback programme as announced on 31 October 2017. The number of shares in issue is reduced when shares are repurchased.
The calculation of EpS is performed separately for each discrete quarterly period, and for the year-to-date period. As a result, the sum of the discrete quarterly EpS amounts in any particular year-to-date period may not be equal to the EpS amount for the year-to-date period.
For the diluted EpS calculation the weighted average number of shares outstanding during the period is adjusted for the number of shares that are potentially issuable in connection with employee share-based payment plans using the treasury stock method.
 
 
Second

Second

 
First

First

 
 
quarter

quarter

 
half

half

$ million
 
2018

2017

 
2018

2017

Results for the period
 
 
 
 
 
 
Profit (loss) for the period attributable to BP shareholders
 
2,799

144

 
5,268

1,593

Less: preference dividend
 
1

1

 
1

1

Profit (loss) attributable to BP ordinary shareholders
 
2,798

143

 
5,267

1,592

 
 
 
 
 
 
 
Number of shares (thousand)(a)
 
 
 
 
 
 
Basic weighted average number of shares outstanding
 
19,945,053

19,686,613

 
19,931,945

19,602,785

ADS equivalent
 
3,324,175

3,281,102

 
3,321,990

3,267,130

 
 
 
 
 
 
 
Weighted average number of shares outstanding used to calculate diluted earnings per share
 
20,044,277

19,783,548

 
20,050,123

19,713,151

ADS equivalent
 
3,340,712

3,297,258

 
3,341,687

3,285,525

 
 
 
 
 
 
 
Shares in issue at period-end
 
19,973,943

19,738,566

 
19,973,943

19,738,566

ADS equivalent
 
3,328,991

3,289,761

 
3,328,991

3,289,761

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

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

25


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

Second

 
First

First

 
 
quarter

quarter

 
half

half

 
 
2018

2017

 
2018

2017

Dividends paid per ordinary share
 
 
 
 
 
 
cents
 
10.000

10.000

 
20.000

20.000

pence
 
7.444

7.756

 
14.613

15.915

Dividends paid per ADS (cents)
 
60.00

60.00

 
120.00

120.00

Scrip dividends
 
 
 
 
 
 
Number of shares issued (millions)
 
34.5

70.1

 
57.9

185.2

Value of shares issued ($ million)
 
266

420

 
421

1,062

Note 11. Net Debt*
Net debt ratio*
 
Second

Second

 
First

First

 
 
 
quarter

quarter

 
half

half

Year

$ million
 
2018

2017

 
2018

2017

2017

Gross debt
 
60,358

63,004

 
60,358

63,004

63,230

Fair value (asset) liability of hedges related to finance debt(a)
 
1,104

60

 
1,104

60

175

 
 
61,462

63,064

 
61,462

63,064

63,405

Less: cash and cash equivalents
 
22,185

23,270

 
22,185

23,270

25,586

Net debt
 
39,277

39,794

 
39,277

39,794

37,819

Equity
 
101,770

98,461

 
101,770

98,461

100,404

Net debt ratio
 
27.8%
28.8%
 
27.8%
28.8%
27.4%

Analysis of changes in net debt
 
Second

Second

 
First

First

 
 
 
quarter

quarter

 
half

half

Year

$ million
 
2018

2017

 
2018

2017

2017

Opening balance
 
 
 
 
 
 
 
Finance debt(a)
 
62,189

61,832

 
63,230

58,300

58,300

Fair value (asset) liability of hedges related to finance debt(b)
 
46

597

 
175

697

697

Less: cash and cash equivalents(c)
 
22,242

23,794

 
25,575

23,484

23,484

Opening net debt
 
39,993

38,635

 
37,830

35,513

35,513

Closing balance
 
 
 
 
 
 
 
Finance debt(a)
 
60,358

63,004

 
60,358

63,004

63,230

Fair value (asset) liability of hedges related to finance debt(b)
 
1,104

60

 
1,104

60

175

Less: cash and cash equivalents
 
22,185

23,270

 
22,185

23,270

25,586

Closing net debt
 
39,277

39,794

 
39,277

39,794

37,819

Decrease (increase) in net debt
 
716

(1,159
)
 
(1,447
)
(4,281
)
(2,306
)
Movement in cash and cash equivalents (excluding exchange adjustments)
 
257

(726
)
 
(3,221
)
(583
)
1,558

Net cash outflow (inflow) from financing
 
524

42

 
1,908

(3,069
)
(2,520
)
Other movements
 
(123
)
(13
)
 
(150
)
(79
)
(564
)
Movement in net debt before exchange effects
 
658

(697
)
 
(1,463
)
(3,731
)
(1,526
)
Exchange adjustments
 
58

(462
)
 
16

(550
)
(780
)
Decrease (increase) in net debt
 
716

(1,159
)
 
(1,447
)
(4,281
)
(2,306
)
(a)
The fair value of finance debt at 30 June 2018 was $61,619 million (31 December 2017 $65,165 million).
(b)
Derivative financial instruments entered into for the purpose of managing interest rate and foreign currency exchange risk associated with net debt with a fair value liability position of $774 million (full year 2017 liability of $634 million and second quarter 2017 liability of $1,167 million) are not included in the calculation of net debt shown above as hedge accounting is not applied for these instruments.
(c)
See Note 1 for further information.

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

26


Note 12. Statutory accounts

The financial information shown in this publication, which was approved by the Board of Directors on 30 July 2018, is unaudited and does not constitute statutory financial statements. Audited financial information will be published in BP Annual Report and Form 20-F 2018.

27


Note 13. Condensed consolidating information on certain US subsidiaries
BP p.l.c. fully and unconditionally guarantees the payment obligations of its 100%-owned subsidiary BP Exploration (Alaska) Inc. under the BP Prudhoe Bay Royalty Trust. The following financial information for BP p.l.c., BP Exploration (Alaska) Inc. and all other subsidiaries on a condensed consolidating basis is intended to provide investors with meaningful and comparable financial information about BP p.l.c. and its subsidiary issuers of registered securities and is provided pursuant to Rule 3-10 of Regulation S-X in lieu of the separate financial statements of each subsidiary issuer of public debt securities. Non-current assets for BP p.l.c. includes investments in subsidiaries recorded under the equity method for the purposes of the condensed consolidating financial information. Equity-accounted income of subsidiaries is the group’s share of profit related to such investments. The eliminations and reclassifications column includes the necessary amounts to eliminate the intercompany balances and transactions between BP p.l.c., BP Exploration (Alaska) Inc. and other subsidiaries. The financial information presented in the following tables for BP Exploration (Alaska) Inc. incorporates subsidiaries of BP Exploration (Alaska) Inc. using the equity method of accounting and excludes the BP group’s midstream operations in Alaska that are reported through different legal entities and that are included within the ‘other subsidiaries’ column in these tables. BP p.l.c. also fully and unconditionally guarantees securities issued by BP Capital Markets p.l.c. and BP Capital Markets America Inc. These companies are 100%-owned finance subsidiaries of BP p.l.c.
Income statement
First half 2018
 
Issuer

Guarantor

 
 
 
$ million
 
BP Exploration (Alaska) Inc.

BP p.l.c.

Other subsidiaries

Eliminations and reclassifications

BP group

Sales and other operating revenues
 
2,199


143,552

(2,140
)
143,611

Earnings from joint ventures - after interest and tax
 


513


513

Earnings from associates - after interest and tax
 


1,441


1,441

Equity-accounted income of subsidiaries - after interest and tax
 

6,028


(6,028
)

Interest and other income
 
18

112

893

(699
)
324

Gains on sale of businesses and fixed assets
 


161


161

Total revenues and other income
 
2,217

6,140

146,560

(8,867
)
146,050

Purchases
 
705


111,371

(2,140
)
109,936

Production and manufacturing expenses
 
481


10,472


10,953

Production and similar taxes
 
144


755


899

Depreciation, depletion and amortization
 
262


7,480


7,742

Impairment and losses on sale of businesses and fixed assets
 


68


68

Exploration expense
 


678


678

Distribution and administration expenses
 
10

344

5,402

(33
)
5,723

Profit (loss) before interest and taxation
 
615

5,796

10,334

(6,694
)
10,051

Finance costs
 
3

577

1,174

(666
)
1,088

Net finance (income) expense relating to pensions and other post-retirement benefits
 

(49
)
111


62

Profit (loss) before taxation
 
612

5,268

9,049

(6,028
)
8,901

Taxation
 
83


3,414


3,497

Profit (loss) for the year
 
529

5,268

5,635

(6,028
)
5,404

Attributable to
 
 
 
 
 
 
BP shareholders
 
529

5,268

5,499

(6,028
)
5,268

Non-controlling interests
 


136


136

 
 
529

5,268

5,635

(6,028
)
5,404


Statement of comprehensive income
First half 2018
 
Issuer

Guarantor

 
 
 
$ million
 
BP Exploration (Alaska) Inc.

BP p.l.c.

Other subsidiaries

Eliminations and reclassifications

BP group

Profit (loss) for the year
 
529

5,268

5,635

(6,028
)
5,404

Other comprehensive income
 

1,686

(2,137
)

(451
)
Equity-accounted other comprehensive income of subsidiaries
 

(2,106
)

2,106


Total comprehensive income
 
529

4,848

3,498

(3,922
)
4,953

Attributable to
 
 
 
 
 
 
  BP shareholders
 
529

4,848

3,393

(3,922
)
4,848

  Non-controlling interests
 


105


105

 
 
529

4,848

3,498

(3,922
)
4,953


28


Note 13. Condensed consolidating information on certain US subsidiaries (continued)
Income statement continued
First half 2017
 
Issuer

Guarantor

 
 
 
$ million
 
BP Exploration (Alaska) Inc.

BP p.l.c.

Other subsidiaries

Eliminations and reclassifications

BP group

Sales and other operating revenues
 
1,614


112,355

(1,595
)
112,374

Earnings from joint ventures - after interest and tax
 


365


365

Earnings from associates - after interest and tax
 


522


522

Equity-accounted income of subsidiaries - after interest and tax
 

2,055


(2,055
)

Interest and other income
 
1

134

613

(499
)
249

Gains on sale of businesses and fixed assets
 


242


242

Total revenues and other income
 
1,615

2,189

114,097

(4,149
)
113,752

Purchases
 
516


84,609

(1,595
)
83,530

Production and manufacturing expenses
 
580


10,436


11,016

Production and similar taxes
 
46


769


815

Depreciation, depletion and amortization
 
415


7,220


7,635

Impairment and losses on sale of businesses and fixed assets
 


504


504

Exploration expense
 


1,262


1,262

Distribution and administration expenses
 
11

254

4,678

(50
)
4,893

Profit (loss) before interest and taxation
 
47

1,935

4,619

(2,504
)
4,097

Finance costs
 
3

371

1,022

(449
)
947

Net finance (income) expense relating to pensions and other post-retirement benefits
 

(7
)
114


107

Profit (loss) before taxation
 
44

1,571

3,483

(2,055
)
3,043

Taxation
 
(13
)
(22
)
1,430


1,395

Profit (loss) for the year
 
57

1,593

2,053

(2,055
)
1,648

Attributable to
 
 
 
 
 
 
BP shareholders
 
57

1,593

1,998

(2,055
)
1,593

Non-controlling interests
 


55


55

 
 
57

1,593

2,053

(2,055
)
1,648

Statement of comprehensive income continued
First half 2017
 
Issuer

Guarantor

 
 
 
$ million
 
BP Exploration (Alaska) Inc.

BP p.l.c.

Other subsidiaries

Eliminations and reclassifications

BP group

Profit (loss) for the year
 
57

1,593

2,053

(2,055
)
1,648

Other comprehensive income
 

578

1,697


2,275

Equity-accounted other comprehensive income of subsidiaries
 

1,664


(1,664
)

Total comprehensive income
 
57

3,835

3,750

(3,719
)
3,923

Attributable to
 
 
 
 
 
 
BP shareholders
 
57

3,835

3,662

(3,719
)
3,835

Non-controlling interests
 


88


88

 
 
57

3,835

3,750

(3,719
)
3,923




29


Note 13. Condensed consolidating information on certain US subsidiaries (continued)
Balance sheet
At 30 June 2018
 
Issuer

Guarantor

 
 
 
$ million
 
BP Exploration (Alaska) Inc.

BP p.l.c.

Other subsidiaries

Eliminations and reclassifications

BP group

Non-current assets
 
 
 
 
 
 
Property, plant and equipment
 
4,577


119,813


124,390

Goodwill
 


11,319


11,319

Intangible assets
 
588


17,220


17,808

Investments in joint ventures
 


8,293


8,293

Investments in associates
 

2

17,833


17,835

Other investments
 


1,284


1,284

Subsidiaries - equity-accounted basis
 

165,566


(165,566
)

Fixed assets
 
5,165

165,568

175,762

(165,566
)
180,929

Loans
 


34,393

(33,888
)
505

Trade and other receivables
 

2,433

1,472

(2,433
)
1,472

Derivative financial instruments
 


4,633


4,633

Prepayments
 


1,134


1,134

Deferred tax assets
 


3,908


3,908

Defined benefit pension plan surpluses
 

5,708

646


6,354

 
 
5,165

173,709

221,948

(201,887
)
198,935

Current assets
 
 
 
 
 
 
Loans
 


298


298

Inventories
 
354


20,650


21,004

Trade and other receivables
 
2,600

294

37,130

(14,894
)
25,130

Derivative financial instruments
 


3,614


3,614

Prepayments
 
49


1,228


1,277

Current tax receivable
 


783


783

Other investments
 


106


106

Cash and cash equivalents
 

15

22,170


22,185

 
 
3,003

309

85,979

(14,894
)
74,397

Assets classified as held for sale (Note 3)
 
2,138


156


2,294

 
 
5,141

309

86,135

(14,894
)
76,691

Total assets
 
10,306

174,018

308,083

(216,781
)
275,626

Current liabilities
 
 
 
 
 
 
Trade and other payables
 
544

12,117

48,868

(14,894
)
46,635

Derivative financial instruments
 


3,643


3,643

Accruals
 
77

59

3,605


3,741

Finance debt
 


10,625


10,625

Current tax payable
 
77

48

2,158


2,283

Provisions
 
1


2,312


2,313

 
 
699

12,224

71,211

(14,894
)
69,240

Liabilities directly associated with assets classified as held for sale (Note 3)
 
291




291

 
 
990

12,224

71,211

(14,894
)
69,531

Non-current liabilities
 
 
 
 
 
 
Other payables
 
1

33,888

16,128

(36,321
)
13,696

Derivative financial instruments
 


5,126


5,126

Accruals
 


599


599

Finance debt
 


49,733


49,733

Deferred tax liabilities
 
861

1,337

6,630


8,828

Provisions
 
733


17,050


17,783

Defined benefit pension plan and other post-retirement benefit plan deficits
 

198

8,362


8,560

 
 
1,595

35,423

103,628

(36,321
)
104,325

Total liabilities
 
2,585

47,647

174,839

(51,215
)
173,856

Net assets
 
7,721

126,371

133,244

(165,566
)
101,770

Equity
 
 
 
 
 
 
BP shareholders’ equity
 
7,721

126,371

131,295

(165,566
)
99,821

Non-controlling interests
 


1,949


1,949

 
 
7,721

126,371

133,244

(165,566
)
101,770


30


Note 13. Condensed consolidating information on certain US subsidiaries (continued)
Balance sheet continued
At 31 December 2017
 
Issuer

Guarantor

 
 
 
$ million
 
BP Exploration (Alaska) Inc.

BP p.l.c.

Other subsidiaries

Eliminations and reclassifications

BP group

Non-current assets
 
 
 
 
 
 
Property, plant and equipment
 
6,973


122,498


129,471

Goodwill
 


11,551


11,551

Intangible assets
 
585


17,770


18,355

Investments in joint ventures
 


7,994


7,994

Investments in associates
 

2

16,989


16,991

Other investments
 


1,245


1,245

Subsidiaries - equity-accounted basis
 

161,840


(161,840
)

Fixed assets
 
7,558

161,842

178,047

(161,840
)
185,607

Loans
 
1


34,701

(34,056
)
646

Trade and other receivables
 

2,623

1,434

(2,623
)
1,434

Derivative financial instruments
 


4,110


4,110

Prepayments
 


1,112


1,112

Deferred tax assets
 


4,469


4,469

Defined benefit pension plan surpluses
 

3,838

331


4,169

 
 
7,559

168,303

224,204

(198,519
)
201,547

Current assets
 
 
 
 
 
 
Loans
 


190


190

Inventories
 
274


18,737


19,011

Trade and other receivables
 
2,206

293

32,691

(10,341
)
24,849

Derivative financial instruments
 


3,032


3,032

Prepayments
 
2


1,412


1,414

Current tax receivable
 


761


761

Other investments
 


125


125

Cash and cash equivalents
 

10

25,576


25,586

 
 
2,482

303

82,524

(10,341
)
74,968

Total assets
 
10,041

168,606

306,728

(208,860
)
276,515

Current liabilities
 
 
 
 
 
 
Trade and other payables
 
673

7,843

46,034

(10,341
)
44,209

Derivative financial instruments
 


2,808


2,808

Accruals
 
115

60

4,785


4,960

Finance debt
 


7,739


7,739

Current tax payable
 


1,686


1,686

Provisions
 
1


3,323


3,324

 
 
789

7,903

66,375

(10,341
)
64,726

Non-current liabilities
 
 
 
 
 
 
Other payables
 

34,104

16,464

(36,679
)
13,889

Derivative financial instruments
 


3,761


3,761

Accruals
 


505


505

Finance debt
 


55,491


55,491

Deferred tax liabilities
 
838

1,337

5,807


7,982

Provisions
 
1,222


19,398


20,620

Defined benefit pension plan and other post-retirement benefit plan deficits
 

221

8,916


9,137

 
 
2,060

35,662

110,342

(36,679
)
111,385

Total liabilities
 
2,849

43,565

176,717

(47,020
)
176,111

Net assets
 
7,192

125,041

130,011

(161,840
)
100,404

Equity
 
 
 
 
 
 
BP shareholders’ equity
 
7,192

125,041

128,098

(161,840
)
98,491

Non-controlling interests
 


1,913


1,913

 
 
7,192

125,041

130,011

(161,840
)
100,404



31


Note 13. Condensed consolidating information on certain US subsidiaries (continued)
Cash flow statement
First half 2018
 
Issuer

Guarantor

 
 
$ million
 
BP Exploration (Alaska) Inc.

BP p.l.c.

Other subsidiaries

BP group

Net cash provided by operating activities
 
171

3,543

6,238

9,952

Net cash provided by (used in) investing activities
 
(171
)

(7,267
)
(7,438
)
Net cash provided by (used in) financing activities
 

(3,538
)
(2,197
)
(5,735
)
Currency translation differences relating to cash and cash equivalents
 


(169
)
(169
)
Increase (decrease) in cash and cash equivalents
 

5

(3,395
)
(3,390
)
Cash and cash equivalents at beginning of year(a)
 

10

25,565

25,575

Cash and cash equivalents at end of year
 

15

22,170

22,185

 
 
 
 
 
 
First half 2017
 
Issuer

Guarantor

 
 
$ million
 
BP Exploration (Alaska) Inc.

BP p.l.c.

Other subsidiaries

BP group

Net cash provided by operating activities
 
177

2,799

4,028

7,004

Net cash provided by (used in) investing activities
 
(177
)

(7,633
)
(7,810
)
Net cash provided by (used in) financing activities
 

(2,849
)
3,072

223

Currency translation differences relating to cash and cash equivalents
 


369

369

Increase (decrease) in cash and cash equivalents
 

(50
)
(164
)
(214
)
Cash and cash equivalents at beginning of year
 

50

23,434

23,484

Cash and cash equivalents at end of year
 


23,270

23,270

(a)
See Note 1 for further information.



32


Additional information
Capital expenditure*
 
 
Second

Second

 
First

First

 
 
quarter

quarter

 
half

half

$ million
 
2018

2017

 
2018

2017

Capital expenditure on a cash basis
 
 
 
 
 
 
Organic capital expenditure*
 
3,470

4,348

 
7,008

7,886

Inorganic capital expenditure*(a)
 
355

140

 
780

670

 
 
3,825

4,488

 
7,788

8,556


 
 
Second

Second

 
First

First

 
 
quarter

quarter

 
half

half

$ million
 
2018

2017

 
2018

2017

Organic capital expenditure by segment
 
 
 
 
 
 
Upstream
 
 
 
 
 
 
US
 
826

805

 
1,580

1,446

Non-US
 
1,941

3,005

 
4,053

5,344

 
 
2,767

3,810

 
5,633

6,790

Downstream
 
 
 
 
 
 
US
 
232

149

 
403

301

Non-US
 
382

316

 
829

636

 
 
614

465

 
1,232

937

Other businesses and corporate
 
 
 
 
 
 
US
 
7

3

 
14

24

Non-US
 
82

70

 
129

135

 
 
89

73

 
143

159

 
 
3,470

4,348

 
7,008

7,886

Organic capital expenditure by geographical area
 
 
 
 
 
 
US
 
1,065

957

 
1,997

1,771

Non-US
 
2,405

3,391

 
5,011

6,115

 
 
3,470

4,348

 
7,008

7,886

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




33


Non-operating items*
 
 
Second

Second

 
First

First

 
 
quarter

quarter

 
half

half

$ million
 
2018

2017

 
2018

2017

Upstream
 
 
 
 
 
 
Impairment and gain (loss) on sale of businesses and fixed assets(a)
 
81

(18
)
 
107

(400
)
Environmental and other provisions
 


 


Restructuring, integration and rationalization costs
 
(62
)
(19
)
 
(61
)
(17
)
Fair value gain (loss) on embedded derivatives
 
9

5

 
16

30

Other
 
(1
)
11

 
(139
)
6

 
 
27

(21
)
 
(77
)
(381
)
Downstream
 
 
 
 
 
 
Impairment and gain (loss) on sale of businesses and fixed assets
 
(1
)
156

 
(15
)
145

Environmental and other provisions
 


 


Restructuring, integration and rationalization costs
 
(74
)
(18
)
 
(110
)
(83
)
Fair value gain (loss) on embedded derivatives
 


 


Other
 
(150
)

 
(153
)

 
 
(225
)
138

 
(278
)
62

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


 


Environmental and other provisions
 


 


Restructuring, integration and rationalization costs
 


 


Fair value gain (loss) on embedded derivatives
 


 


Other
 


 


 
 


 


Other businesses and corporate
 
 
 
 
 
 
Impairment and gain (loss) on sale of businesses and fixed assets
 
(1
)
8

 
1

(7
)
Environmental and other provisions
 
1

(3
)
 
(20
)
(3
)
Restructuring, integration and rationalization costs
 
(30
)
(23
)
 
(45
)
(31
)
Fair value gain (loss) on embedded derivatives
 


 


Gulf of Mexico oil spill - business economic loss claims(b)
 
(249
)
(260
)
 
(249
)
(260
)
Gulf of Mexico oil spill - other(b)
 
(184
)
(87
)
 
(270
)
(122
)
Other
 
(85
)
10

 
(144
)
77

 
 
(548
)
(355
)
 
(727
)
(346
)
Total before interest and taxation
 
(746
)
(238
)
 
(1,082
)
(665
)
Finance costs(b)
 
(118
)
(121
)
 
(238
)
(247
)
Total before taxation
 
(864
)
(359
)
 
(1,320
)
(912
)
Taxation credit (charge) on non-operating items
 
141

144

 
229

392

Taxation - impact of US tax reform(c)
 


 
121


Total after taxation for period
 
(723
)
(215
)
 
(970
)
(520
)
(a)
First half 2017 includes an impairment charge arising following the announcement of the agreement to sell the Forties Pipeline System business to INEOS.
(b)
See Note 2 for further details regarding costs relating to the Gulf of Mexico oil spill.
(c)
Fourth quarter 2017 included the impact of US tax reform, which reduced the US federal corporate income tax rate from 35% to 21% effective from 1 January 2018. First half 2018 reflects a further impact following a clarification of the tax reform. The impact of the US tax reform has been treated as a non-operating item because it is not considered to be part of underlying business operations, has a material impact upon the reported result and is substantially impacted by Gulf of Mexico oil spill charges, which are also treated as non-operating items. Separate disclosure is considered meaningful and relevant to investors.

34


Non-GAAP information on fair value accounting effects
 
 
Second

Second

 
First

First

 
 
quarter

quarter

 
half

half

$ million
 
2018

2017

 
2018

2017

Favourable (adverse) impact relative to management’s measure of performance
 
 
 
 
 
 
Upstream
 
(21
)
106

 
100

352

Downstream
 
(390
)
16

 
(450
)
56

 
 
(411
)
122

 
(350
)
408

Taxation credit (charge)
 
101

(38
)
 
90

(117
)
 
 
(310
)
84

 
(260
)
291

BP uses derivative instruments to manage the economic exposure relating to inventories above normal operating requirements of crude oil, natural gas and petroleum products. Under IFRS, these inventories are recorded at historical cost. The related derivative instruments, however, are required to be recorded at fair value with gains and losses recognized in the income statement. This is because hedge accounting is either not permitted or not followed, principally due to the impracticality of effectiveness-testing requirements. Therefore, measurement differences in relation to recognition of gains and losses occur. Gains and losses on these inventories are not recognized until the commodity is sold in a subsequent accounting period. Gains and losses on the related derivative commodity contracts are recognized in the income statement, from the time the derivative commodity contract is entered into, on a fair value basis using forward prices consistent with the contract maturity.
BP enters into physical commodity contracts to meet certain business requirements, such as the purchase of crude for a refinery or the sale of BP’s gas production. Under IFRS these physical contracts are treated as derivatives and are required to be fair valued when they are managed as part of a larger portfolio of similar transactions. Gains and losses arising are recognized in the income statement from the time the derivative commodity contract is entered into.
IFRS require that inventory held for trading is recorded at its fair value using period-end spot prices, whereas any related derivative commodity instruments are required to be recorded at values based on forward prices consistent with the contract maturity. Depending on market conditions, these forward prices can be either higher or lower than spot prices, resulting in measurement differences.
BP enters into contracts for pipelines and other transportation, storage capacity, oil and gas processing and liquefied natural gas (LNG) that, under IFRS, are recorded on an accruals basis. These contracts are risk-managed using a variety of derivative instruments that are fair valued under IFRS. This results in measurement differences in relation to recognition of gains and losses.
The way that BP manages the economic exposures described above, and measures performance internally, differs from the way these activities are measured under IFRS. BP calculates this difference for consolidated entities by comparing the IFRS result with management’s internal measure of performance. Under management’s internal measure of performance the inventory, transportation and capacity contracts in question are valued based on fair value using relevant forward prices prevailing at the end of the period. The fair values of derivative instruments used to risk manage certain oil, gas and other contracts, are deferred to match with the underlying exposure and the commodity contracts for business requirements are accounted for on an accruals basis. We believe that disclosing management’s estimate of this difference provides useful information for investors because it enables investors to see the economic effect of these activities as a whole.
In addition, from the first quarter 2018 fair value accounting effects include changes in the fair value of the near-term portions of LNG contracts that fall within BP’s risk management framework. LNG contracts are not considered derivatives, because there is insufficient market liquidity, and they are therefore accrual accounted under IFRS. However, oil and natural gas derivative financial instruments (used to risk manage the near-term portions of the LNG contracts) are fair valued under IFRS. The fair value accounting effect reduces timing differences between recognition of the derivative financial instruments used to risk manage the LNG contracts and the recognition of the LNG contracts themselves, which therefore gives a better representation of performance in each period. Comparative information has not been restated on the basis that the effect was not material.
For the second quarter of 2018, Downstream fair value accounting effects arose mainly due to changes in the fair value of transportation contracts in the US, which are reflected in the underlying result to eliminate measurement differences in the reported IFRS result in relation to the recognition of gains and losses, as described above.




35


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

Second

 
First

First

 
 
quarter

quarter

 
half

half

$ million
 
2018

2017

 
2018

2017

Upstream
 
 
 
 
 
 
Replacement cost profit before interest and tax adjusted for fair value accounting effects
 
3,535

689

 
6,588

1,699

Impact of fair value accounting effects
 
(21
)
106

 
100

352

Replacement cost profit before interest and tax
 
3,514

795

 
6,688

2,051

Downstream
 
 
 
 
 
 
Replacement cost profit before interest and tax adjusted for fair value accounting effects
 
1,230

1,551

 
3,003

3,217

Impact of fair value accounting effects
 
(390
)
16

 
(450
)
56

Replacement cost profit before interest and tax
 
840

1,567

 
2,553

3,273

Total group
 
 
 
 
 
 
Profit (loss) before interest and tax adjusted for fair value accounting effects
 
5,967

1,347

 
10,401

3,689

Impact of fair value accounting effects
 
(411
)
122

 
(350
)
408

Profit (loss) before interest and tax
 
5,556

1,469

 
10,051

4,097

Readily marketable inventory* (RMI)
 
 
30 June

31 December

$ million
 
2018

2017

RMI at fair value*
 
6,058

5,661

Paid-up RMI*
 
2,744

2,688

Readily marketable inventory (RMI) is oil and oil products inventory held and price risk-managed by BP’s integrated supply and trading function (IST) which could be sold to generate funds if required. Paid-up RMI is RMI that BP has paid for.
We believe that disclosing the amounts of RMI and paid-up RMI is useful to investors as it enables them to better understand and evaluate the group’s inventories and liquidity position by enabling them to see the level of discretionary inventory held by IST and to see builds or releases of liquid trading inventory.
See the Glossary on page 40 for a more detailed definition of RMI. RMI, RMI at fair value, paid-up RMI and unpaid RMI are non-GAAP measures. A reconciliation of total inventory as reported on the group balance sheet to paid-up RMI is provided below.
 
 
30 June

31 December

$ million
 
2018

2017

Reconciliation of total inventory to paid-up RMI
 
 
 
Inventories as reported on the group balance sheet under IFRS
 
21,004

19,011

Less: (a) inventories which are not oil and oil products and (b) oil and oil product inventories which are not risk-managed by IST
 
(15,453
)
(13,929
)
 
 
5,551

5,082

Plus: difference between RMI at fair value and RMI on an IFRS basis
 
507

579

RMI at fair value
 
6,058

5,661

Less: unpaid RMI* at fair value
 
(3,314
)
(2,973
)
Paid-up RMI
 
2,744

2,688



36


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

 
 
Second

Second

 
First

First

 
 
quarter

quarter

 
half

half

Per ordinary share (cents)
 
2018

2017

 
2018

2017

Profit for the period
 
14.03

0.73

 
26.42

8.12

Inventory holding (gains) losses*, before tax
 
(6.57
)
2.97

 
(7.03
)
2.65

Taxation charge (credit) on inventory holding gains and losses
 
1.50

(0.90
)
 
1.57

(0.75
)
Replacement cost (RC) profit (loss)*
 
8.96

2.80

 
20.96

10.02

Net (favourable) adverse impact of non-operating items* and fair value accounting effects*, before tax
 
6.39

1.21

 
8.38

2.57

Taxation charge (credit) on non-operating items and fair value accounting effects
 
(1.21
)
(0.54
)
 
(2.21
)
(1.40
)
Underlying RC profit*
 
14.14

3.47

 
27.13

11.19


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

Taxation (charge) credit
 
 
 
 
 
 
 
 
Second

Second

 
First

First

 
 
quarter

quarter

 
half

half

$ million
 
2018

2017

 
2018

2017

Taxation on profit or loss
 
(2,117
)
(772
)
 
(3,497
)
(1,395
)
Taxation on inventory holding gains and losses
 
(300
)
177

 
(312
)
148

Taxation on a replacement cost (RC) profit or loss basis
 
(1,817
)
(949
)
 
(3,185
)
(1,543
)
Taxation on non-operating items and fair value accounting effects
 
242

106

 
440

275

Taxation on underlying replacement cost profit or loss
 
(2,059
)
(1,055
)
 
(3,625
)
(1,818
)

Effective tax rate
 
 
 
 
 
 
 
 
Second

Second

 
First

First

 
 
quarter

quarter

 
half

half

%
 
2018

2017

 
2018

2017

ETR on profit or loss
 
42

83

 
39

46

Adjusted for inventory holding gains or losses
 
7

(20
)
 
3

(3
)
ETR on RC profit or loss*
 
49

63

 
42

43

Adjusted for non-operating items and fair value accounting effects
 
(7
)
(3
)
 
(2
)
2

Underlying ETR*
 
42

60

 
40

45


37


Realizations* and marker prices
 
 
Second

Second

 
First

First

 
 
quarter

quarter

 
half

half

 
 
2018

2017

 
2018

2017

Average realizations(a)
 
 
 
 
 
 
Liquids* ($/bbl)
 
 
 
 
 
 
US
 
62.47

44.65

 
60.01

45.51

Europe
 
71.70

47.79

 
68.56

50.50

Rest of World
 
69.88

47.11

 
66.50

49.46

BP Average
 
67.24

46.27

 
64.21

48.09

Natural gas ($/mcf)
 
 
 
 
 
 
US
 
1.96

2.32

 
2.10

2.41

Europe
 
7.04

4.48

 
7.11

4.93

Rest of World
 
4.16

3.47

 
4.19

3.64

BP Average
 
3.65

3.19

 
3.72

3.34

Total hydrocarbons* ($/boe)
 
 
 
 
 
 
US
 
40.77

32.46

 
40.19

33.39

Europe
 
64.91

41.10

 
62.72

43.84

Rest of World
 
42.89

33.48

 
41.69

35.64

BP Average
 
43.37

33.59

 
42.36

35.37

Average oil marker prices ($/bbl)
 
 
 
 
 
 
Brent
 
74.39

49.64

 
70.58

51.71

West Texas Intermediate
 
68.02

48.11

 
65.52

49.89

Western Canadian Select
 
49.76

38.55

 
43.30

38.66

Alaska North Slope
 
73.93

50.61

 
70.64

52.20

Mars
 
69.47

46.92

 
66.04

48.24

Urals (NWE – cif)
 
72.21

48.48

 
68.71

50.22

Average natural gas marker prices
 
 
 
 
 
 
Henry Hub gas price(b) ($/mmBtu)
 
2.80

3.19

 
2.90

3.25

UK Gas – National Balancing Point (p/therm)
 
53.88

37.83

 
55.94

43.14

(a)
Based on sales of consolidated subsidiaries only - this excludes equity-accounted entities.
(b)
Henry Hub First of Month Index.
Exchange rates
 
 
Second

Second

 
First

First

 
 
quarter

quarter

 
half

half

 
 
2018

2017

 
2018

2017

$/£ average rate for the period
 
1.36

1.28

 
1.38

1.26

$/£ period-end rate
 
1.31

1.30

 
1.31

1.30

 
 
 
 
 
 
 
$/€ average rate for the period
 
1.19

1.10

 
1.21

1.08

$/€ period-end rate
 
1.16

1.14

 
1.16

1.14

 
 
 
 
 
 
 
Rouble/$ average rate for the period
 
62.13

57.24

 
59.47

57.98

Rouble/$ period-end rate
 
63.07

59.05

 
63.07

59.05



38


Principal risks and uncertainties
The principal risks and uncertainties affecting BP are described in the Risk factors section of BP Annual Report and Form 20-F 2017 (pages 57-58) and are summarized below. There are no material changes in those risk factors for the remaining six months of the financial year.
The risks summarized below, separately or in combination, could have a material adverse effect on the implementation of our strategy, our business, financial performance, results of operations, cash flows, liquidity, prospects, shareholder value and returns and reputation.

Strategic and commercial risks
Prices and markets - our financial performance is impacted by fluctuating prices of oil, gas and refined products, technological change, exchange rate fluctuations, and the general macroeconomic outlook.
Access, renewal and reserves progression - our inability to access, renew and progress upstream resources in a timely manner could adversely affect our long-term replacement of reserves.
Major project* delivery - failure to invest in the best opportunities or deliver major projects successfully could adversely affect our financial performance.
Geopolitical - exposure to a range of political developments and consequent changes to the operating and regulatory environment could cause business disruption.
Liquidity, financial capacity and financial, including credit, exposure - failure to work within our financial framework could impact our ability to operate and result in financial loss.
Joint arrangements and contractors - varying levels of control over the standards, operations and compliance of our partners, contractors and sub-contractors could result in legal liability and reputational damage.
Digital infrastructure and cyber security - breach of our digital security or failure of our digital infrastructure including loss or misuse of sensitive information could damage our operations, increase costs and damage our reputation.
Climate change and the transition to a lower carbon economy - policy, legal, regulatory, technology and market change related to the issue of climate change could increase costs, reduce demand for our products, reduce revenue and limit certain growth opportunities.
Competition - inability to remain efficient, maintain a high quality portfolio of assets, innovate and retain an appropriately skilled workforce could negatively impact delivery of our strategy in a highly competitive market.
Crisis management and business continuity - failure to address an incident effectively could potentially disrupt our business.
Insurance - our insurance strategy could expose the group to material uninsured losses.

Safety and operational risks
Process safety, personal safety, and environmental risks - exposure to a wide range of health, safety, security and environmental risks could result in regulatory action, legal liability, business interruption, increased costs, damage to our reputation and potentially denial of our licence to operate.
Drilling and production - challenging operational environments and other uncertainties can impact drilling and production activities.
Security - hostile acts against our staff and activities could cause harm to people and disrupt our operations.
Product quality - supplying customers with off-specification products could damage our reputation, lead to regulatory action and legal liability, and impact our financial performance.

Compliance and control risks
US government settlements - failure to comply with the terms of our settlement with the US Environmental Protection Agency related to the Gulf of Mexico oil spill may expose us to further penalties or liabilities or could result in suspension or debarment of certain BP entities.
Regulation - changes in the regulatory and legislative environment could increase the cost of compliance, affect our provisions and limit our access to new growth opportunities.
Ethical misconduct and non-compliance - ethical misconduct or breaches of applicable laws by our businesses or our employees could be damaging to our reputation, and could result in litigation, regulatory action and penalties.
Treasury and trading activities - ineffective oversight of treasury and trading activities could lead to business disruption, financial loss, regulatory intervention or damage to our reputation.
Reporting - failure to accurately report our data could lead to regulatory action, legal liability and reputational damage.


39


Legal proceedings
The following discussion sets out the material developments in the group’s material legal proceedings during the first half of 2018. For a full discussion of the group’s material legal proceedings, see pages 270-273 of BP Annual Report and Form 20-F 2017.
Scharfstein v. BP West Coast Products, LLC
A class action lawsuit was filed against BP West Coast Products, LLC in Oregon State Court under the Oregon Unlawful Trade Practices Act on behalf of customers who used a debit card at ARCO gasoline stations in Oregon during the period 1 January 2011 to 30 August 2013, alleging that ARCO sites in Oregon failed to provide sufficient notice of the 35 cents per transaction debit card fee. In January 2014, the jury rendered a verdict against BP West Coast Products, LLC and awarded statutory damages of $200 per class member. On 25 August 2015, the trial court determined the size of the class to be slightly in excess of two million members. On 31 May 2016 the trial court entered a judgment against BP West Coast Products, LLC for the amount of $417.3 million. On 31 May 2018 the Oregon Court of Appeals affirmed the trial court's ruling. BP intends to appeal to the Oregon Supreme Court.
 

Glossary
Non-GAAP measures are provided for investors because they are closely tracked by management to evaluate BP’s operating performance and to make financial, strategic and operating decisions. Non-GAAP measures are sometimes referred to as alternative performance measures.
Capital expenditure is total cash capital expenditure as stated in the condensed group cash flow statement.
Consolidation adjustment – UPII is unrealized profit in inventory arising on inter-segment transactions.
Divestment proceeds are disposal proceeds as per the condensed group cash flow statement.
Effective tax rate (ETR) on replacement cost (RC) profit or loss is a non-GAAP measure. The ETR on RC profit or loss is calculated by dividing taxation on a RC basis by RC profit or loss before tax. Information on RC profit or loss is provided below. BP believes it is helpful to disclose the ETR on RC profit or loss because this measure excludes the impact of price changes on the replacement of inventories and allows for more meaningful comparisons between reporting periods. The nearest equivalent measure on an IFRS basis is the ETR on profit or loss for the period. A reconciliation to GAAP information is provided on page 37.
Fair value accounting effects are non-GAAP adjustments to our IFRS profit (loss). They reflect the difference between the way BP manages the economic exposure and internally measures performance of certain activities and the way those activities are measured under IFRS. Further information on fair value accounting effects is provided on page 35 .
Gearing – See Net debt and net debt ratio definition.
Gross debt ratio is defined as the ratio of gross debt to the total of gross debt plus shareholders' equity.
Hydrocarbons – Liquids and natural gas. Natural gas is converted to oil equivalent at 5.8 billion cubic feet = 1 million barrels.
Inorganic capital expenditure is a subset of capital expenditure and is a non-GAAP measure. Inorganic capital expenditure comprises consideration in business combinations and certain other significant investments made by the group. It is reported on a cash basis. BP believes that this measure provides useful information as it allows investors to understand how BP’s management invests funds in projects which expand the group’s activities through acquisition. Further information and a reconciliation to GAAP information is provided on page 33.
Inventory holding gains and losses represent the difference between the cost of sales calculated using the replacement cost of inventory and the cost of sales calculated on the first-in first-out (FIFO) method after adjusting for any changes in provisions where the net realizable value of the inventory is lower than its cost. Under the FIFO method, which we use for IFRS reporting, the cost of inventory charged to the income statement is based on its historical cost of purchase or manufacture, rather than its replacement cost. In volatile energy markets, this can have a significant distorting effect on reported income. The amounts disclosed represent the difference between the charge to the income statement for inventory on a FIFO basis (after adjusting for any related movements in net realizable value provisions) and the charge that would have arisen based on the replacement cost of inventory. For this purpose, the replacement cost of inventory is calculated using data from each operation’s production and manufacturing system, either on a monthly basis, or separately for each transaction where the system allows this approach. The amounts disclosed are not separately reflected in the financial statements as a gain or loss. No adjustment is made in respect of the cost of inventories held as part of a trading position and certain other temporary inventory positions. See Replacement cost (RC) profit or loss definition below.
Liquids – Liquids for Upstream and Rosneft comprises crude oil, condensate and natural gas liquids. For Upstream, liquids also includes bitumen.
Major projects have a BP net investment of at least $250 million, or are considered to be of strategic importance to BP or of a high degree of complexity.
Net debt and net debt ratio are non-GAAP measures. Net debt is calculated as gross finance debt, as shown in the balance sheet, plus the fair value of associated derivative financial instruments that are used to hedge foreign currency exchange and interest rate risks relating to finance debt, for which hedge accounting is applied, less cash and cash equivalents. The net debt ratio is defined as the ratio of net debt to the total of net debt plus shareholders’ equity. All components of equity are included in the denominator of the calculation. BP believes these measures provide useful information to investors. Net debt enables investors to see the economic effect of gross debt, related hedges and cash and cash equivalents in total. The net debt ratio enables investors to see how significant net debt is relative to equity from shareholders. The derivatives are reported on the balance sheet within the headings ‘Derivative financial instruments’. The nearest equivalent GAAP measures on an IFRS basis are gross debt and gross debt ratio. A reconciliation of gross debt to net debt is provided on page 26.

40


Glossary (continued)
We are unable to present reconciliations of forward-looking information for net debt ratio to gross debt ratio, because without unreasonable efforts, we are unable to forecast accurately certain adjusting items required to present a meaningful comparable GAAP forward-looking financial measure. These items include fair value asset (liability) of hedges related to finance debt and cash and cash equivalents, that are difficult to predict in advance in order to include in a GAAP estimate.
Net wind generation capacity is the sum of the rated capacities of the assets/turbines that have entered into commercial operation, including BP’s share of equity-accounted entities.
Non-operating items are charges and credits included in the financial statements that BP discloses separately because it considers such disclosures to be meaningful and relevant to investors. They are items that management considers not to be part of underlying business operations and are disclosed in order to enable investors better to understand and evaluate the group’s reported financial performance. Non-operating items within equity-accounted earnings are reported net of incremental income tax reported by the equity-accounted entity. An analysis of non-operating items by region is shown on pages 9, 11 and 13, and by segment and type is shown on page 34.
Operating cash flow is net cash provided by (used in) operating activities as stated in the condensed group cash flow statement. When used in the context of a segment rather than the group, the terms refer to the segment’s share thereof.
Operating cash flow excluding Gulf of Mexico oil spill payments is a non-GAAP measure. It is calculated by excluding post-tax operating cash flows relating to the Gulf of Mexico oil spill as reported in Note 2 from net cash provided by operating activities as reported in the condensed group cash flow statement. BP believes net cash provided by operating activities excluding amounts related to the Gulf of Mexico oil spill is a useful measure as it allows for more meaningful comparisons between reporting periods. The nearest equivalent measure on an IFRS basis is net cash provided by operating activities.
Organic capital expenditure is a subset of capital expenditure and is a non-GAAP measure. Organic capital expenditure comprises capital expenditure less inorganic capital expenditure. BP believes that this measure provides useful information as it allows investors to understand how BP’s management invests funds in developing and maintaining the group’s assets. An analysis of organic capital expenditure by segment and region, and a reconciliation to GAAP information is provided on page 33.
We are unable to present reconciliations of forward-looking information for organic capital expenditure to total cash capital expenditure, because without unreasonable efforts, we are unable to forecast accurately the adjusting item, inorganic capital expenditure, that is difficult to predict in advance in order to derive the nearest GAAP estimate.
Production-sharing agreement (PSA) is an arrangement through which an oil and gas company bears the risks and costs of exploration, development and production. In return, if exploration is successful, the oil company receives entitlement to variable physical volumes of hydrocarbons, representing recovery of the costs incurred and a stipulated share of the production remaining after such cost recovery.
Readily marketable inventory (RMI) is inventory held and price risk-managed by our integrated supply and trading function (IST) which could be sold to generate funds if required. It comprises oil and oil products for which liquid markets are available and excludes inventory which is required to meet operational requirements and other inventory which is not price risk-managed. RMI is reported at fair value. Inventory held by the Downstream fuels business for the purpose of sales and marketing, and all inventories relating to the lubricants and petrochemicals businesses, are not included in RMI.
Paid-up RMI excludes RMI which has not yet been paid for. For inventory that is held in storage, a first-in first-out (FIFO) approach is used to determine whether inventory has been paid for or not. Unpaid RMI is RMI which has not yet been paid for by BP. RMI, RMI at fair value, Paid-up RMI and Unpaid RMI are non-GAAP measures. Further information is provided on page 36.
Realizations are the result of dividing revenue generated from hydrocarbon sales, excluding revenue generated from purchases made for resale and royalty volumes, by revenue generating hydrocarbon production volumes. Revenue generating hydrocarbon production reflects the BP share of production as adjusted for any production which does not generate revenue. Adjustments may include losses due to shrinkage, amounts consumed during processing, and contractual or regulatory host committed volumes such as royalties.
Refining availability represents Solomon Associates’ operational availability, which is defined as the percentage of the year that a unit is available for processing after subtracting the annualized time lost due to turnaround activity and all planned mechanical, process and regulatory downtime.
The Refining marker margin (RMM) is the average of regional indicator margins weighted for BP’s crude refining capacity in each region. Each regional marker margin is based on product yields and a marker crude oil deemed appropriate for the region. The regional indicator margins may not be representative of the margins achieved by BP in any period because of BP’s particular refinery configurations and crude and product slate.
Replacement cost (RC) profit or loss reflects the replacement cost of inventories sold in the period and is arrived at by excluding inventory holding gains and losses from profit or loss. RC profit or loss for the group is not a recognized GAAP measure. BP believes this measure is useful to illustrate to investors the fact that crude oil and product prices can vary significantly from period to period and that the impact on our reported result under IFRS can be significant. Inventory holding gains and losses vary from period to period due to changes in prices as well as changes in underlying inventory levels. In order for investors to understand the operating performance of the group excluding the impact of price changes on the replacement of inventories, and to make comparisons of operating performance between reporting periods, BP’s management believes it is helpful to disclose this measure. The nearest equivalent measure on an IFRS basis is profit or loss attributable to BP shareholders. A reconciliation to GAAP information is provided on page 3. RC profit or loss before interest and tax is the measure of profit or loss that is required to be disclosed for each operating segment under IFRS.

41


Glossary (continued)
RC profit or loss per share is a non-GAAP measure. Earnings per share is defined in Note 9. RC profit or loss per share is calculated using the same denominator. The numerator used is RC profit or loss attributable to BP shareholders rather than profit or loss attributable to BP shareholders. BP believes it is helpful to disclose the RC profit or loss per share because this measure excludes the impact of price changes on the replacement of inventories and allows for more meaningful comparisons between reporting periods. The nearest equivalent measure on an IFRS basis is basic earnings per share based on profit or loss for the period attributable to BP shareholders. A reconciliation to GAAP information is provided on page 37.
Reported recordable injury frequency measures the number of reported work-related employee and contractor incidents that result in a fatality or injury per 200,000 hours worked. This represents reported incidents occurring within BP’s operational HSSE reporting boundary. That boundary includes BP’s own operated facilities and certain other locations or situations.
Tier 1 process safety events are losses of primary containment from a process of greatest consequence – causing harm to a member of the workforce, costly damage to equipment or exceeding defined quantities. This represents reported incidents occurring within BP’s operational HSSE reporting boundary. That boundary includes BP’s own operated facilities and certain other locations or situations.
Underlying effective tax rate (ETR) is a non-GAAP measure. The underlying ETR is calculated by dividing taxation on an underlying replacement cost (RC) basis by underlying RC profit or loss before tax. Taxation on an underlying RC basis is taxation on a RC basis for the period adjusted for taxation on non-operating items and fair value accounting effects. Information on underlying RC profit or loss is provided below. BP believes it is helpful to disclose the underlying ETR because this measure may help investors to understand and evaluate, in the same manner as management, the underlying trends in BP’s operational performance on a comparable basis, period on period. The nearest equivalent measure on an IFRS basis is the ETR on profit or loss for the period. A reconciliation to GAAP information is provided on page 37.
We are unable to present reconciliations of forward-looking information for underlying ETR to ETR on profit or loss for the period, because without unreasonable efforts, we are unable to forecast accurately certain adjusting items required to present a meaningful comparable GAAP forward-looking financial measure. These items include the taxation on inventory holding gains and losses, non-operating items and fair value accounting effects, that are difficult to predict in advance in order to include in a GAAP estimate.
Underlying production is production after adjusting for acquisitions and divestments and entitlement impacts in our production-sharing agreements.
Underlying RC profit or loss is RC profit or loss after adjusting for non-operating items and fair value accounting effects. Underlying RC profit or loss and adjustments for fair value accounting effects are not recognized GAAP measures. See pages 29 and 30 for additional information on the non-operating items and fair value accounting effects that are used to arrive at underlying RC profit or loss in order to enable a full understanding of the events and their financial impact. BP believes that underlying RC profit or loss is a useful measure for investors because it is a measure closely tracked by management to evaluate BP’s operating performance and to make financial, strategic and operating decisions and because it may help investors to understand and evaluate, in the same manner as management, the underlying trends in BP’s operational performance on a comparable basis, period on period, by adjusting for the effects of these non-operating items and fair value accounting effects. The nearest equivalent measure on an IFRS basis for the group is profit or loss attributable to BP shareholders. The nearest equivalent measure on an IFRS basis for segments is RC profit or loss before interest and taxation. A reconciliation to GAAP information is provided on page 3.
Underlying RC profit or loss per share is a non-GAAP measure. Earnings per share is defined in Note 9. Underlying RC profit or loss per share is calculated using the same denominator. The numerator used is underlying RC profit or loss attributable to BP shareholders rather than profit or loss attributable to BP shareholders. BP believes it is helpful to disclose the underlying RC profit or loss per share because this measure may help investors to understand and evaluate, in the same manner as management, the underlying trends in BP’s operational performance on a comparable basis, period on period. The nearest equivalent measure on an IFRS basis is basic earnings per share based on profit or loss for the period attributable to BP shareholders. A reconciliation to GAAP information is provided on page 37.
Upstream operating efficiency is calculated as production for BP-operated sites, excluding US Lower 48 and adjusted for certain items including entitlement impacts in our production-sharing agreements divided by installed production capacity for BP-operated sites, excluding US Lower 48. Installed production capacity is the agreed rate achievable (measured at the export end of the system) when the installed production system (reservoir, wells, plant and export) is fully optimized and operated at full rate with no planned or unplanned deferrals.
Upstream plant reliability (BP-operated) is calculated taking 100% less the ratio of total unplanned plant deferrals divided by installed production capacity. Unplanned plant deferrals are associated with the topside plant and where applicable the subsea equipment (excluding wells and reservoir). Unplanned plant deferrals include breakdowns, which does not include Gulf of Mexico weather related downtime.
Upstream unit production cost is calculated as production cost divided by units of production. Production cost does not include ad valorem and severance taxes. Units of production are barrels for liquids and thousands of cubic feet for gas. Amounts disclosed are for BP subsidiaries only and do not include BP’s share of equity-accounted entities.

42


Other matters
As previously disclosed, the North Sea Rhum field (Rhum) is owned under a 50:50 unincorporated joint arrangement between BP and Iranian Oil Company (U.K.) Limited (IOC). In 2015, the US and the EU implemented temporary, limited and reversible relief of certain sanctions related to Iran pursuant to a Joint Comprehensive Plan of Action (JCPOA). On 29 September 2017, BP obtained a specific OFAC License relating to the ongoing operation of the Rhum field, such license expiring on 30 September 2018.
On 21 November 2017, BP announced that it had agreed to sell certain of its assets in the North Sea, including its ownership stake, and the transfer of its role as operator, in the Rhum joint arrangement to Serica Energy plc (Serica), with the aim to complete the sale and transfer of operatorship in the third quarter of 2018 subject to regulatory and third party approvals.
In May 2018, the U.S. government announced its planned withdrawal from the JCPOA, and tasked OFAC with implementing the full re-imposition of both primary and secondary sanctions in respect of Iran by the end of a wind-down period, which, for Rhum, expires on 4 November 2018. BP and Serica are actively engaged in discussions with both UK and US governments with the aim that the Rhum field can continue to operate during this wind-down period and thereafter.
Cautionary statement
In order to utilize the ‘safe harbor’ provisions of the United States Private Securities Litigation Reform Act of 1995 (the ‘PSLRA’) and the general doctrine of cautionary statements, BP is providing the following cautionary statement: The discussion in this results announcement contains certain forecasts, projections and forward-looking statements - that is, statements related to future, not past events and circumstances - with respect to the financial condition, results of operations and businesses of BP and certain of the plans and objectives of BP with respect to these items. These statements may generally, but not always, be identified by the use of words such as ‘will’, ‘expects’, ‘is expected to’, ‘aims’, ‘should’, ‘may’, ‘objective’, ‘is likely to’, ‘intends’, ‘believes’, ‘anticipates’, ‘plans’, ‘we see’ or similar expressions. In particular, the following, among other statements, are all forward looking in nature: expectations regarding the expected quarterly dividend payment and timing of such payment; plans and expectations to become the leading fuel provider for electric and conventional vehicles; plans and expectations regarding the start-up of six Upstream major projects in 2018; expectations regarding 2018 organic capital expenditure; plans and expectations with respect to gearing; expectations regarding divestment transactions and 2018 divestment proceeds; expectations regarding Upstream third-quarter 2018 reported production and turnaround and maintenance activity; expectations regarding Downstream third-quarter 2018 refining margins and turnaround activity; expectations regarding second-half 2018 decommissioning provision impacts; expectations regarding the amount of Rosneft dividends payable to BP; expectations regarding BP’s stake in LLC Kharampurneftegaz, including the transfer of subsoil use licences; plans and expectations regarding the agreements relating to BP’s increase in its interest in the Clair field and divestment from its interest in the Greater Kuparuk Area and holding in the Kuparuk Transportation Company; plans and expectations regarding the Southern Gas Corridor series of pipelines and the development of the Tortue/Ahmeyim gas project; plans and expectations regarding BP’s acquisition of onshore-US unconventional oil and gas assets from BHP; plans and expectations regarding legal and trial proceedings; plans and expectations regarding the operation of and sale of BP’s interest in the Rhum field; and expectations with respect to the timing and amount of future payments relating to the Gulf of Mexico oil spill including payments for full-year 2018 and 2012 PSC settlement payments. By their nature, forward-looking statements involve risk and uncertainty because they relate to events and depend on circumstances that will or may occur in the future and are outside the control of BP. Actual results may differ materially from those expressed in such statements, depending on a variety of factors, including: the specific factors identified in the discussions accompanying such forward-looking statements; the receipt of relevant third party and/or regulatory approvals; the timing and level of maintenance and/or turnaround activity; the timing and volume of refinery additions and outages; the timing of bringing new fields onstream; the timing, quantum and nature of certain divestments; future levels of industry product supply, demand and pricing, including supply growth in North America; OPEC quota restrictions; PSA effects; operational and safety problems; potential lapses in product quality; economic and financial market conditions generally or in various countries and regions; political stability and economic growth in relevant areas of the world; changes in laws and governmental regulations; regulatory or legal actions including the types of enforcement action pursued and the nature of remedies sought or imposed; the actions of prosecutors, regulatory authorities and courts; delays in the processes for resolving claims; amounts ultimately payable and timing of payments relating to the Gulf of Mexico oil spill; exchange rate fluctuations; development and use of new technology; recruitment and retention of a skilled workforce; the success or otherwise of partnering; the actions of competitors, trading partners, contractors, subcontractors, creditors, rating agencies and others; our access to future credit resources; business disruption and crisis management; the impact on our reputation of ethical misconduct and non-compliance with regulatory obligations; trading losses; major uninsured losses; decisions by Rosneft’s management and board of directors; the actions of contractors; natural disasters and adverse weather conditions; changes in public expectations and other changes to business conditions; wars and acts of terrorism; cyber-attacks or sabotage; and other factors discussed elsewhere in this report and under “Risk factors” in BP Annual Report and Form 20-F 2017 as filed with the US Securities and Exchange Commission.


43


Computation of ratio of earnings to fixed charges

 
 
First

 
 
half

 
 
2018

$ million except ratio
 
 
 
 
 
Earnings available for fixed charges:
 
 
Pre-tax profit from continuing operations before adjustment for income or loss from joint ventures and associates
 
6,947

Fixed charges
 
1,510

Amortization of capitalized interest
 
94

Distributed income of joint ventures and associates
 
430

Interest capitalized
 
(213
)
Preference dividend requirements, gross of tax
 
(1
)
Non-controlling interest of subsidiaries’ income not incurring fixed charges
 
(24
)
Total earnings available for fixed charges
 
8,743

 
 
 
Fixed charges:
 
 
Interest expensed
 
787

Interest capitalized
 
213

Rental expense representative of interest
 
509

Preference dividend requirements, gross of tax
 
1

Total fixed charges
 
1,510

 
 
 
Ratio of earnings to fixed charges
 
5.79


44


The following table shows the unaudited consolidated capitalization and indebtedness of the BP group as of 30 June 2018 in
accordance with IFRS:
Capitalization and indebtedness

 
 
30 June

$ million
 
2018

Share capital and reserves
 
 
Capital shares (1-2)
 
5,361

Paid-in surplus (3)
 
13,773

Merger reserve (3)
 
27,206

Treasury shares
 
(15,890
)
Cash flow hedge reserve
 
(801
)
Costs of hedging reserve
 
(187
)
Foreign currency translation reserve
 
(7,259
)
Profit and loss account
 
77,618

BP shareholders' equity
 
99,821

 
 
 
Finance debt (4-6)
 
 
Due within one year
 
10,625

Due after more than one year
 
49,733

Total finance debt
 
60,358

Total capitalization (7)
 
160,179


1.
Issued share capital as of 30 June 2018 comprised 19,982,540,709 ordinary shares, par value US$0.25 per share, and 12,706,252 preference shares, par value £1 per share. This excludes 1,377,156,087 ordinary shares which have been bought back and are held in treasury by BP. These shares are not taken into consideration in relation to the payment of dividends and voting at shareholders’ meetings.

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

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

4.
Finance debt recorded in currencies other than US dollars has been translated into US dollars at the relevant exchange rates existing on 30 June 2018.

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

6.
At 30 June 2018, the parent company, BP p.l.c., had issued guarantees totalling $57,929 million relating to finance debt of subsidiaries. Thus 96% of the group’s finance debt had been guaranteed by BP p.l.c.

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

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

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


45


Signatures

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


BP p.l.c.
(Registrant)



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


46