Blueprint
 
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
 
Form 6-K
 
 
Report of Foreign Issuer
 
Pursuant to Rule 13a-16 or 15d-16 of
the Securities Exchange Act of 1934
 
for the period ended 31 July, 2018
 
 
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 Form 20-F or Form 40-F.
 
 
Form 20-F |X| Form 40-F
--------------- ----------------
 
 
 
Indicate by check mark whether the registrant by furnishing the information
contained in this Form is also thereby furnishing the information to the
Commission pursuant to Rule 12g3-2(b) under the Securities Exchange Act of
1934.
 
 
 
Yes No |X|
--------------- --------------
 
 
 
 
 
 
Exhibit 1.1
2Q18 Part 1 of 1 and 31 July 2018
 
 
Exhibit 1.1
 
 
 
FOR IMMEDIATE RELEASE
 
Top of page 1
 
London
 
31 July 2018
 
 
 
BP p.l.c. Group results
 
Second quarter and half year 2018(a)
 
 
 
 
 
For a printer friendly copy of this announcement, please click on the link below to open a PDF version:
 
http://www.rns-pdf.londonstockexchange.com/rns/2324W_1-2018-7-30.pdf 
 
 
 
 
Highlights
 
Strong earnings, strategic momentum, increased dividend
 
 
● 
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 excluding Gulf of Mexico oil spill payments* was $7.0 billion in the second quarter – which included a $1.3 billion working capital* release (after adjusting for inventory holding gains*) – and $12.4 billion in the first half, including a $0.4 billion working capital build.
●    
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.
●    
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. 
 
See chart on PDF
 
 
 
 
Bob Dudley - Group chief executive:
We continue to make steady progress against our strategy and plans, delivering another quarter of strong operational and financial performance. We brought two more major projects online, high-graded our portfolio through acquisitions such as BHP’s US onshore assets and invested in a low-carbon future with the creation of BP Chargemaster. Given this momentum and the strength of our financial frame, we are increasing our dividend for the first time in almost four years. This reflects not just our commitment to growing distributions to shareholders but our confidence in the future.
 
 
Financial summary
 
 
 
 
 
 
 
 
$ million
 
 
2Q18
 
1Q18
 
2Q17
 
 
1H18
 
1H17
 
Profit for the period(b)
 
 
2,799
 
 
2,469
 
 
144
 
 
 
5,268
 
 
1,593
 
 
Inventory holding (gains) losses, net of tax
 
 
(1,010
 
)
 
(80
 
)
 
409
 
 
 
(1,090
 
)
 
372
 
 
RC profit*
 
 
1,789
 
 
2,389
 
 
553
 
 
 
4,178
 
 
1,965
 
 
Net (favourable) adverse impact of non-operating items*and fair value accounting effects*, net of tax
 
 
1,033
 
 
197
 
 
131
 
 
 
1,230
 
 
229
 
 
Underlying RC profit
 
 
2,822
 
 
2,586
 
 
684
 
 
 
5,408
 
 
2,194
 
 
RC profit per ordinary share (cents)*
 
 
8.96
 
 
11.99
 
 
2.80
 
 
 
20.96
 
 
10.02
 
 
RC profit per ADS (dollars)
 
 
0.54
 
 
0.72
 
 
0.17
 
 
 
1.26
 
 
0.60
 
 
Underlying RC profit per ordinary share (cents)*
 
 
14.14
 
 
12.98
 
 
3.47
 
 
 
27.13
 
 
11.19
 
 
Underlying RC profit per ADS (dollars)
 
 
0.85
 
 
0.78
 
 
0.21
 
 
 
1.63
 
 
0.67
 
 
 
(a)
This results announcement also represents BP’s half-yearly financial report (see page 12).
(b)
Profit attributable to BP shareholders.
* See definitions in the Glossary on page 34. RC profit (loss), underlying RC profit, operating cash flow excluding Gulf of Mexico oil spill payments, working capital after adjusting for inventory holding gains, 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 38.
 
 
 
Top of page 2
Group headlines
 
Results
For the half year, underlying replacement cost (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). RC profit was $4,178 million for the half year, compared with $1,965 million a year ago.
 
For the second quarter, underlying RC profit was $2,822 million, compared with $684 million 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). RC profit was $1,789 million for the second quarter, compared with $553 million in 2017.
 
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.
See further information on pages 3, 29 and 30.
 
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 29.
 
Effective tax rate
The effective tax rate (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*
Excluding post-tax amounts related to the Gulf of Mexico oil spill, operating cash flow* for the second quarter was $7.0 billion, including a $1.3 billion working capital* release (after adjusting for inventory holding gains*) and $12.4 billion in the half year, including a $0.4 billion working capital build (after adjusting for inventory holding gains), compared with $6.9 billion and $11.3 billion for the same periods in 2017. Including amounts relating to the Gulf of Mexico oil spill, operating cash flow for the second quarter and half year was $6.3 billion and $10.0 billion respectively (after a negative working capital impact of $0.6 billion for the quarter and $4.0 billion for the half year), compared with $4.9 billion and $7.0 billion for the same periods in 2017. See also Glossary for further information on working capital.
 
Capital expenditure*
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 28 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.
 
Gearing*
Net debt* at 30 June 2018 was $39.3 billion, compared with $39.8 billion a year ago. Gearing 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 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 38.
 
 
 
 
Top of page 3
Analysis of underlying RC profit* before interest and tax
 
 
 
Second
 
First
 
Second
 
 
First
 
First
 
 
 
quarter
 
quarter
 
quarter
 
 
half
 
half
 
$ million
 
 
2018
 
2018
 
2017
 
 
2018
 
2017
 
Underlying RC profit before interest and tax
 
 
 
 
 
 
 
 
Upstream
 
 
3,508
 
 
3,157
 
 
710
 
 
 
6,665
 
 
2,080
 
 
Downstream
 
 
1,455
 
 
1,826
 
 
1,413
 
 
 
3,281
 
 
3,155
 
 
Rosneft
 
 
766
 
 
247
 
 
279
 
 
 
1,013
 
 
378
 
 
Other businesses and corporate
 
 
(477
 
)
 
(392
 
)
 
(366
 
)
 
 
(869
 
)
 
(806
 
)
 
Consolidation adjustment – UPII*
 
 
151
 
 
(160
 
)
 
135
 
 
 
(9
 
)
 
67
 
 
Underlying RC profit before interest and tax
 
 
5,403
 
 
4,678
 
 
2,171
 
 
 
10,081
 
 
4,874
 
 
Finance costs and net finance expense relating to pensions and other post-retirement benefits
 
 
(448
 
)
 
(464
 
)
 
(420
 
)
 
 
(912
 
)
 
(807
 
)
 
Taxation on an underlying RC basis
 
 
(2,059
 
)
 
(1,566
 
)
 
(1,055
 
)
 
 
(3,625
 
)
 
(1,818
 
)
 
Non-controlling interests
 
 
(74
 
)
 
(62
 
)
 
(12
 
)
 
 
(136
 
)
 
(55
 
)
 
Underlying RC profit attributable to BP shareholders
 
 
2,822
 
 
2,586
 
 
684
 
 
 
5,408
 
 
2,194
 
 
 
 
Reconciliations of underlying RC profit or loss to the nearest equivalent IFRS measure are provided on page 1 for the group and on pages 6-11 for the segments.
 
 
 
Analysis of RC profit (loss)* before interest and tax and reconciliation to profit (loss) for the period
 
 
 
Second
 
First
 
Second
 
 
First
 
First
 
 
 
quarter
 
quarter
 
quarter
 
 
half
 
half
 
$ million
 
 
2018
 
2018
 
2017
 
 
2018
 
2017
 
RC profit (loss) before interest and tax
 
 
 
 
 
 
 
 
Upstream
 
 
3,514
 
 
3,174
 
 
795
 
 
 
6,688
 
 
2,051
 
 
Downstream
 
 
840
 
 
1,713
 
 
1,567
 
 
 
2,553
 
 
3,273
 
 
Rosneft
 
 
766
 
 
247
 
 
279
 
 
 
1,013
 
 
378
 
 
Other businesses and corporate(a)
 
 
(1,025
 
)
 
(571
 
)
 
(721
 
)
 
 
(1,596
 
)
 
(1,152
 
)
 
Consolidation adjustment – UPII
 
 
151
 
 
(160
 
)
 
135
 
 
 
(9
 
)
 
67
 
 
RC profit (loss) before interest and tax
 
 
4,246
 
 
4,403
 
 
2,055
 
 
 
8,649
 
 
4,617
 
 
Finance costs and net finance expense relating to pensions and other post-retirement benefits
 
 
(566
 
)
 
(584
 
)
 
(541
 
)
 
 
(1,150
 
)
 
(1,054
 
)
 
Taxation on a RC basis
 
 
(1,817
 
)
 
(1,368
 
)
 
(949
 
)
 
 
(3,185
 
)
 
(1,543
 
)
 
Non-controlling interests
 
 
(74
 
)
 
(62
 
)
 
(12
 
)
 
 
(136
 
)
 
(55
 
)
 
RC profit (loss) attributable to BP shareholders
 
 
1,789
 
 
2,389
 
 
553
 
 
 
4,178
 
 
1,965
 
 
Inventory holding gains (losses)*
 
 
1,310
 
 
92
 
 
(586
 
)
 
 
1,402
 
 
(520
 
)
 
Taxation (charge) credit on inventory holding gains and losses
 
 
(300
 
)
 
(12
 
)
 
177
 
 
 
(312
 
)
 
148
 
 
Profit (loss) for the period attributable to BP shareholders
 
 
2,799
 
 
2,469
 
 
144
 
 
 
5,268
 
 
1,593
 
 
 
(a)
Includes costs related to the Gulf of Mexico oil spill. See page 11 and also Note 2 from page 21 for further information on the accounting for the Gulf of Mexico oil spill.
 
 
Top of page 4
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 excluding Gulf of Mexico oil spill payments* was $7.0 billion in the quarter and $12.4 billion in the first half. These compare with $6.9 billion for the second quarter of 2017 and $11.3 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*
 
 
$5.4bn
 
 
(-3)
 
 
 
(+$3.2bn)
 
Reported recordable injury frequency*
 
 
0.22
 
 
Operating cash flow excluding Gulf of Mexico oil spill payments (post-tax)
 
 
$12.4bn
 
 
(—)
 
 
 
(+$1.1bn)
 
Group production
 
 
3,662mboe/d
 
 
Organic capital expenditure
 
 
$7.0bn
 
 
(+3.3%)
 
 
 
(-$0.9bn)
 
Upstream production (excludes Rosneft segment)
 
 
2,535mboe/d
 
 
Gulf of Mexico oil spill payments (post-tax)(b)
 
 
$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)
 
 
27.8%
 
 
(+0.7)
 
 
 
(-1.0)
 
Refining availability*
 
 
94.1%
 
 
Dividend per ordinary share(c)
 
 
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)
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.
(c)
Represents dividend announced in the quarter (vs. prior year quarter).
 
 
 
The commentary above contains forward-looking statements and should be read in conjunction with the cautionary statement on page 38.
 
 
 
 
 
Top of page 5
 
 
 
This page is intentionally left blank
 
 
 
 
 
Top of page 6
 
 
Upstream
 
 
 
Second
 
First
 
Second
 
 
First
 
First
 
 
 
quarter
 
quarter
 
quarter
 
 
half
 
half
 
$ million
 
 
2018
 
2018
 
2017
 
 
2018
 
2017
 
Profit before interest and tax
 
 
3,518
 
 
3,175
 
 
796
 
 
 
6,693
 
 
2,046
 
 
Inventory holding (gains) losses*
 
 
(4
 
)
 
(1
 
)
 
(1
 
)
 
 
(5
 
)
 
5
 
 
RC profit before interest and tax
 
 
3,514
 
 
3,174
 
 
795
 
 
 
6,688
 
 
2,051
 
 
Net (favourable) adverse impact of non-operating items* and fair value accounting effects*
 
 
(6
 
)
 
(17
 
)
 
(85
 
)
 
 
(23
 
)
 
29
 
 
Underlying RC profit before interest and tax*(a)
 
 
3,508
 
 
3,157
 
 
710
 
 
 
6,665
 
 
2,080
 
 
 
(a)
See page 7 for a reconciliation to segment RC profit before interest and tax by region.
 
Financial results
The replacement cost profit before interest and tax for the 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, and 4.6 billion barrels of oil equivalent 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 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.
 
 
 
Top of page 7
Upstream (continued)
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 38.
 
 
 
 
 
 
Second
 
First
 
Second
 
 
First
 
First
 
 
 
quarter
 
quarter
 
quarter
 
 
half
 
half
 
$ million
 
 
2018
 
2018
 
2017
 
 
2018
 
2017
 
Underlying RC profit before interest and tax
 
 
 
 
 
 
 
 
US
 
 
742
 
 
526
 
 
179
 
 
 
1,268
 
 
345
 
 
Non-US
 
 
2,766
 
 
2,631
 
 
531
 
 
 
5,397
 
 
1,735
 
 
 
 
3,508
 
 
3,157
 
 
710
 
 
 
6,665
 
 
2,080
 
 
Non-operating items
 
 
 
 
 
 
 
 
US
 
 
(29
 
)
 
(145
 
)
 
(34
 
)
 
 
(174
 
)
 
(46
 
)
 
Non-US(a)
 
 
56
 
 
41
 
 
13
 
 
 
97
 
 
(335
 
)
 
 
 
27
 
 
(104
 
)
 
(21
 
)
 
 
(77
 
)
 
(381
 
)
 
Fair value accounting effects
 
 
 
 
 
 
 
 
US
 
 
(143
 
)
 
(9
 
)
 
92
 
 
 
(152
 
)
 
284
 
 
Non-US
 
 
122
 
 
130
 
 
14
 
 
 
252
 
 
68
 
 
 
 
(21
 
)
 
121
 
 
106
 
 
 
100
 
 
352
 
 
RC profit before interest and tax
 
 
 
 
 
 
 
 
US
 
 
570
 
 
372
 
 
237
 
 
 
942
 
 
583
 
 
Non-US
 
 
2,944
 
 
2,802
 
 
558
 
 
 
5,746
 
 
1,468
 
 
 
 
3,514
 
 
3,174
 
 
795
 
 
 
6,688
 
 
2,051
 
 
Exploration expense
 
 
 
 
 
 
 
 
US
 
 
77
 
 
309
 
 
25
 
 
 
386
 
 
65
 
 
Non-US(b)
 
 
87
 
 
205
 
 
825
 
 
 
292
 
 
1,197
 
 
 
 
164
 
 
514
 
 
850
 
 
 
678
 
 
1,262
 
 
Of which: Exploration expenditure written off(b)
 
 
81
 
 
426
 
 
753
 
 
 
507
 
 
1,014
 
 
Production (net of royalties)(c)
 
 
 
 
 
 
 
 
Liquids* (mb/d)
 
 
 
 
 
 
 
 
US
 
 
411
 
 
448
 
 
418
 
 
 
429
 
 
433
 
 
Europe
 
 
147
 
 
139
 
 
122
 
 
 
143
 
 
118
 
 
Rest of World
 
 
659
 
 
731
 
 
812
 
 
 
695
 
 
819
 
 
 
 
1,217
 
 
1,319
 
 
1,352
 
 
 
1,267
 
 
1,371
 
 
Natural gas (mmcf/d)
 
 
 
 
 
 
 
 
US
 
 
1,744
 
 
1,790
 
 
1,576
 
 
 
1,767
 
 
1,585
 
 
Europe
 
 
202
 
 
217
 
 
274
 
 
 
209
 
 
269
 
 
Rest of World
 
 
5,297
 
 
5,456
 
 
4,410
 
 
 
5,376
 
 
4,173
 
 
 
 
7,242
 
 
7,463
 
 
6,260
 
 
 
7,352
 
 
6,026
 
 
Total hydrocarbons* (mboe/d)
 
 
 
 
 
 
 
 
US
 
 
711
 
 
757
 
 
689
 
 
 
734
 
 
706
 
 
Europe
 
 
182
 
 
177
 
 
169
 
 
 
180
 
 
165
 
 
Rest of World
 
 
1,572
 
 
1,672
 
 
1,572
 
 
 
1,622
 
 
1,539
 
 
 
 
2,465
 
 
2,605
 
 
2,431
 
 
 
2,535
 
 
2,410
 
 
Average realizations*(d)
 
 
 
 
 
 
 
 
Total liquids(e) ($/bbl)
 
 
67.24
 
 
61.40
 
 
46.27
 
 
 
64.21
 
 
48.09
 
 
Natural gas ($/mcf)
 
 
3.65
 
 
3.78
 
 
3.19
 
 
 
3.72
 
 
3.34
 
 
Total hydrocarbons ($/boe)
 
 
43.37
 
 
41.39
 
 
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.
 
 
 
Top of page 8
Downstream
 
 
 
Second
 
First
 
Second
 
 
First
 
First
 
 
 
quarter
 
quarter
 
quarter
 
 
half
 
half
 
$ million
 
 
2018
 
2018
 
2017
 
 
2018
 
2017
 
Profit before interest and tax
 
 
2,036
 
 
1,782
 
 
988
 
 
 
3,818
 
 
2,792
 
 
Inventory holding (gains) losses*
 
 
(1,196
 
)
 
(69
 
)
 
579
 
 
 
(1,265
 
)
 
481
 
 
RC profit before interest and tax
 
 
840
 
 
1,713
 
 
1,567
 
 
 
2,553
 
 
3,273
 
 
Net (favourable) adverse impact of non-operating items* and fair value accounting effects*
 
 
615
 
 
113
 
 
(154
 
)
 
 
728
 
 
(118
 
)
 
Underlying RC profit before interest and tax*(a)
 
 
1,455
 
 
1,826
 
 
1,413
 
 
 
3,281
 
 
3,155
 
 
 
(a)
See page 9 for a reconciliation to segment RC profit before interest and tax by region and by business.
 
Financial results
The replacement cost profit before interest and tax for the 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 9.
 
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 38.
 
 
 
Top of page 9
Downstream (continued)
 
 
 
Second
 
First
 
Second
 
 
First
 
First
 
 
 
quarter
 
quarter
 
quarter
 
 
half
 
half
 
$ million
 
 
2018
 
2018
 
2017
 
 
2018
 
2017
 
Underlying RC profit before interest and tax - by region
 
 
 
 
 
 
 
 
US
 
 
399
 
 
589
 
 
283
 
 
 
988
 
 
837
 
 
Non-US
 
 
1,056
 
 
1,237
 
 
1,130
 
 
 
2,293
 
 
2,318
 
 
 
 
1,455
 
 
1,826
 
 
1,413
 
 
 
3,281
 
 
3,155
 
 
Non-operating items
 
 
 
 
 
 
 
 
US
 
 
(155
 
)
 
(17
 
)
 
28
 
 
 
(172
 
)
 
16
 
 
Non-US
 
 
(70
 
)
 
(36
 
)
 
110
 
 
 
(106
 
)
 
46
 
 
 
 
(225
 
)
 
(53
 
)
 
138
 
 
 
(278
 
)
 
62
 
 
Fair value accounting effects(a)
 
 
 
 
 
 
 
 
US
 
 
(299
 
)
 
(121
 
)
 
10
 
 
 
(420
 
)
 
(52
 
)
 
Non-US
 
 
(91
 
)
 
61
 
 
6
 
 
 
(30
 
)
 
108
 
 
 
 
(390
 
)
 
(60
 
)
 
16
 
 
 
(450
 
)
 
56
 
 
RC profit before interest and tax
 
 
 
 
 
 
 
 
US
 
 
(55
 
)
 
451
 
 
321
 
 
 
396
 
 
801
 
 
Non-US
 
 
895
 
 
1,262
 
 
1,246
 
 
 
2,157
 
 
2,472
 
 
 
 
840
 
 
1,713
 
 
1,567
 
 
 
2,553
 
 
3,273
 
 
Underlying RC profit before interest and tax - by business(b)(c)
 
 
 
 
 
 
 
 
Fuels
 
 
1,054
 
 
1,398
 
 
908
 
 
 
2,452
 
 
2,108
 
 
Lubricants
 
 
326
 
 
331
 
 
355
 
 
 
657
 
 
748
 
 
Petrochemicals
 
 
75
 
 
97
 
 
150
 
 
 
172
 
 
299
 
 
 
 
1,455
 
 
1,826
 
 
1,413
 
 
 
3,281
 
 
3,155
 
 
Non-operating items and fair value accounting effects(a)
 
 
 
 
 
 
 
 
Fuels
 
 
(584
 
)
 
(110
 
)
 
159
 
 
 
(694
 
)
 
163
 
 
Lubricants
 
 
(26
 
)
 
(3
 
)
 
(2
 
)
 
 
(29
 
)
 
(5
 
)
 
Petrochemicals
 
 
(5
 
)
 
—
 
 
(3
 
)
 
 
(5
 
)
 
(40
 
)
 
 
 
(615
 
)
 
(113
 
)
 
154
 
 
 
(728
 
)
 
118
 
 
RC profit before interest and tax(b)(c)
 
 
 
 
 
 
 
 
Fuels
 
 
470
 
 
1,288
 
 
1,067
 
 
 
1,758
 
 
2,271
 
 
Lubricants
 
 
300
 
 
328
 
 
353
 
 
 
628
 
 
743
 
 
Petrochemicals
 
 
70
 
 
97
 
 
147
 
 
 
167
 
 
259
 
 
 
 
840
 
 
1,713
 
 
1,567
 
 
 
2,553
 
 
3,273
 
 
 
 
 
 
 
 
 
 
BP average refining marker margin (RMM)* ($/bbl)
 
 
14.9
 
 
11.7
 
 
13.8
 
 
 
13.3
 
 
12.8
 
 
 
 
 
 
 
 
 
 
Refinery throughputs (mb/d)
 
 
 
 
 
 
 
 
US
 
 
666
 
 
715
 
 
708
 
 
 
690
 
 
702
 
 
Europe
 
 
786
 
 
797
 
 
782
 
 
 
792
 
 
791
 
 
Rest of World
 
 
228
 
 
249
 
 
198
 
 
 
238
 
 
189
 
 
 
 
1,680
 
 
1,761
 
 
1,688
 
 
 
1,720
 
 
1,682
 
 
Refining availability* (%)
 
 
93.3
 
 
94.8
 
 
94.5
 
 
 
94.1
 
 
94.8
 
 
 
 
 
 
 
 
 
 
Marketing sales of refined products (mb/d)
 
 
 
 
 
 
 
 
US
 
 
1,161
 
 
1,096
 
 
1,177
 
 
 
1,129
 
 
1,146
 
 
Europe
 
 
1,135
 
 
1,045
 
 
1,153
 
 
 
1,090
 
 
1,111
 
 
Rest of World
 
 
477
 
 
481
 
 
497
 
 
 
479
 
 
505
 
 
 
 
2,773
 
 
2,622
 
 
2,827
 
 
 
2,698
 
 
2,762
 
 
Trading/supply sales of refined products
 
 
3,247
 
 
3,181
 
 
2,996
 
 
 
3,215
 
 
2,978
 
 
Total sales volumes of refined products
 
 
6,020
 
 
5,803
 
 
5,823
 
 
 
5,913
 
 
5,740
 
 
 
 
 
 
 
 
 
 
Petrochemicals production (kte)
 
 
 
 
 
 
 
 
US
 
 
404
 
 
499
 
 
672
 
 
 
903
 
 
1,170
 
 
Europe
 
 
1,094
 
 
1,128
 
 
1,365
 
 
 
2,222
 
 
2,618
 
 
Rest of World
 
 
1,358
 
 
1,391
 
 
2,001
 
 
 
2,749
 
 
4,074
 
 
 
 
2,856
 
 
3,018
 
 
4,038
 
 
 
5,874
 
 
7,862
 
 
 
(a)
For Downstream, fair value accounting effects arise solely in the fuels business. See page 30 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.
 
 
Top of page 10
Rosneft
 
 
 
Second
 
First
 
Second
 
 
First
 
First
 
 
 
quarter
 
quarter
 
quarter
 
 
half
 
half
 
$ million
 
 
2018(a)
 
2018
 
2017
 
 
2018(a)
 
2017
 
Profit before interest and tax(b)
 
 
876
 
 
269
 
 
271
 
 
 
1,145
 
 
344
 
 
Inventory holding (gains) losses*
 
 
(110
 
)
 
(22
 
)
 
8
 
 
 
(132
 
)
 
34
 
 
RC profit before interest and tax
 
 
766
 
 
247
 
 
279
 
 
 
1,013
 
 
378
 
 
Net charge (credit) for non-operating items*
 
 
—
 
 
—
 
 
—
 
 
 
—
 
 
—
 
 
Underlying RC profit before interest and tax*
 
 
766
 
 
247
 
 
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
 
First
 
Second
 
 
First
 
First
 
 
 
quarter
 
quarter
 
quarter
 
 
half
 
half
 
 
 
2018(a)
 
2018
 
2017
 
 
2018(a)
 
2017
 
Production (net of royalties) (BP share)
 
 
 
 
 
 
 
 
Liquids* (mb/d)
 
 
909
 
 
902
 
 
902
 
 
 
906
 
 
907
 
 
Natural gas (mmcf/d)
 
 
1,262
 
 
1,307
 
 
1,302
 
 
 
1,285
 
 
1,318
 
 
Total hydrocarbons* (mboe/d)
 
 
1,127
 
 
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.
 
 
Top of page 11
Other businesses and corporate
 
 
 
Second
 
First
 
Second
 
 
First
 
First
 
 
 
quarter
 
quarter
 
quarter
 
 
half
 
half
 
$ million
 
 
2018
 
2018
 
2017
 
 
2018
 
2017
 
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
 
)
 
(86
 
)
 
(87
 
)
 
 
(270
 
)
 
(122
 
)
 
Other
 
 
(592
 
)
 
(485
 
)
 
(374
 
)
 
 
(1,077
 
)
 
(770
 
)
 
Profit (loss) before interest and tax
 
 
(1,025
 
)
 
(571
 
)
 
(721
 
)
 
 
(1,596
 
)
 
(1,152
 
)
 
Inventory holding (gains) losses*
 
 
—
 
 
—
 
 
—
 
 
 
—
 
 
—
 
 
RC profit (loss) before interest and tax
 
 
(1,025
 
)
 
(571
 
)
 
(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
 
 
86
 
 
87
 
 
 
270
 
 
122
 
 
Other
 
 
115
 
 
93
 
 
8
 
 
 
208
 
 
(36
 
)
 
Net charge (credit) for non-operating items
 
 
548
 
 
179
 
 
355
 
 
 
727
 
 
346
 
 
Underlying RC profit (loss) before interest and tax*
 
 
(477
 
)
 
(392
 
)
 
(366
 
)
 
 
(869
 
)
 
(806
 
)
 
Underlying RC profit (loss) before interest and tax
 
 
 
 
 
 
 
 
US
 
 
(123
 
)
 
(147
 
)
 
(104
 
)
 
 
(270
 
)
 
(301
 
)
 
Non-US
 
 
(354
 
)
 
(245
 
)
 
(262
 
)
 
 
(599
 
)
 
(505
 
)
 
 
 
(477
 
)
 
(392
 
)
 
(366
 
)
 
 
(869
 
)
 
(806
 
)
 
Non-operating items
 
 
 
 
 
 
 
 
US
 
 
(498
 
)
 
(148
 
)
 
(350
 
)
 
 
(646
 
)
 
(388
 
)
 
Non-US
 
 
(50
 
)
 
(31
 
)
 
(5
 
)
 
 
(81
 
)
 
42
 
 
 
 
(548
 
)
 
(179
 
)
 
(355
 
)
 
 
(727
 
)
 
(346
 
)
 
RC profit (loss) before interest and tax
 
 
 
 
 
 
 
 
US
 
 
(621
 
)
 
(295
 
)
 
(454
 
)
 
 
(916
 
)
 
(689
 
)
 
Non-US
 
 
(404
 
)
 
(276
 
)
 
(267
 
)
 
 
(680
 
)
 
(463
 
)
 
 
 
(1,025
 
)
 
(571
 
)
 
(721
 
)
 
 
(1,596
 
)
 
(1,152
 
)
 
 
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.
 
 
 
Top of page 12
Half-yearly financial report
 
This results announcement also represents BP’s half-yearly financial report for the purposes of the Disclosure Guidance and Transparency Rules made by the UK Financial Conduct Authority. In this context: (i) the condensed set of financial statements can be found on pages 14-27; (ii) pages 1-11, and 28-38 comprise the interim management report; and (iii) the directors’ responsibility statement and auditors’ independent review report can be found on pages 12-13.
 
 
 
 
 
Statement of directors’ responsibilities
 
The directors confirm that, to the best of their knowledge, the condensed set of financial statements on pages 14-27 has been prepared in accordance with IAS 34 ‘Interim Financial Reporting’, and that the interim management report on pages 1-11 and 28-38 includes a fair review of the information required by the Disclosure Guidance and Transparency Rules.
 
The directors of BP p.l.c. are listed on pages 60-65 of BP Annual Report and Form 20-F 2017, with the following exceptions. Paul Anderson retired at the 2018 Annual General Meeting on 21 May 2018, and Dame Alison Carnwath was elected at the 2018 Annual General Meeting. On 26 July Helge Lund and Pamela Daley were appointed to the board.
 
 
 
By order of the board
 
 
 
Bob Dudley
 
Brian Gilvary
 
Group Chief Executive
 
Chief Financial Officer
 
30 July 2018
 
30 July 2018
 
 
 
 
Top of page 13
Independent review report to BP p.l.c.
 
 
 
Introduction
 
 
We have been engaged by the company to review the condensed set of financial statements in the half-yearly financial report for the six months ended 30 June 2018 which comprises the group income statement, condensed group statement of comprehensive income, condensed group statement of changes in equity, group balance sheet, condensed group cash flow statement and related notes 1 to 12. We have read the other information contained in the half-yearly financial report and considered whether it contains any apparent misstatements or material inconsistencies with the information in the condensed set of financial statements.
 
This report is made solely to the company in accordance with International Standard on Review Engagements (UK and Ireland) 2410 'Review of Interim Financial Information Performed by the Independent Auditor of the Entity' issued by the Financial Reporting Council. Our work has been undertaken so that we might state to the company those matters we are required to state to it in an independent review report and for no other purpose. To the fullest extent permitted by law, we do not accept or assume responsibility to anyone other than the company, for our review work, for this report, or for the conclusions we have formed.
 
 
 
Directors’ responsibilities
 
 
The half-yearly financial report is the responsibility of, and has been approved by, the directors. The directors are responsible for preparing the half-yearly financial report in accordance with the Disclosure Guidance and Transparency Rules of the United Kingdom’s Financial Conduct Authority.
 
As disclosed in Note 1, the annual financial statements of the group are prepared in accordance with International Financial Reporting Standards (IFRSs) as issued by the International Accounting Standards Board (IASB) and IFRSs as adopted by the European Union. The condensed set of financial statements included in this half-yearly financial report has been prepared in accordance with International Accounting Standard 34, 'Interim Financial Reporting', as issued by the IASB and as adopted by the European Union.
 
 
 
Our responsibility
 
 
Our responsibility is to express to the company a conclusion on the condensed set of financial statements in the half-yearly financial report based on our review.
 
 
 
Scope of review
 
 
We conducted our review in accordance with International Standard on Review Engagements (UK and Ireland) 2410 'Review of Interim Financial Information Performed by the Independent Auditor of the Entity' issued by the Financial Reporting Council for use in the United Kingdom. A review of interim financial information consists of making inquiries, primarily of persons responsible for financial and accounting matters, and applying analytical and other review procedures. A review is substantially less in scope than an audit conducted in accordance with International Standards on Auditing (UK) and consequently does not enable us to obtain assurance that we would become aware of all significant matters that might be identified in an audit. Accordingly, we do not express an audit opinion.
 
 
 
Conclusion
 
 
Based on our review, nothing has come to our attention that causes us to believe that the condensed set of financial statements in the half-yearly financial report for the six months ended 30 June 2018 is not prepared, in all material respects, in accordance with International Accounting Standard 34 as issued by the IASB and as adopted by the European Union and the Disclosure Guidance and Transparency Rules of the United Kingdom’s Financial Conduct Authority.
 
 
 
Deloitte LLP
Statutory Auditor
London
United Kingdom
30 July 2018
 
 
 
The maintenance and integrity of the BP p.l.c. website are the responsibility of the directors; the review work carried out by the statutory auditors does not involve consideration of these matters and, accordingly, the statutory auditors accept no responsibility for any changes that may have occurred to the financial information since it was initially presented on the website.
 
Legislation in the United Kingdom governing the preparation and dissemination of financial statements may differ from legislation in other jurisdictions.
 
 
 
Top of page 14
Financial statements
 
Group income statement
 
 
 
Second
 
First
 
Second
 
 
First
 
First
 
 
 
quarter
 
quarter
 
quarter
 
 
half
 
half
 
$ million
 
 
2018
 
2018
 
2017
 
 
2018
 
2017
 
 
 
 
 
 
 
 
 
Sales and other operating revenues (Note 6)
 
 
75,439
 
 
68,172
 
 
56,511
 
 
 
143,611
 
 
112,374
 
 
Earnings from joint ventures – after interest and tax
 
 
220
 
 
293
 
 
160
 
 
 
513
 
 
365
 
 
Earnings from associates – after interest and tax
 
 
1,027
 
 
414
 
 
371
 
 
 
1,441
 
 
522
 
 
Interest and other income
 
 
165
 
 
159
 
 
127
 
 
 
324
 
 
249
 
 
Gains on sale of businesses and fixed assets
 
 
56
 
 
105
 
 
197
 
 
 
161
 
 
242
 
 
Total revenues and other income
 
 
76,907
 
 
69,143
 
 
57,366
 
 
 
146,050
 
 
113,752
 
 
Purchases
 
 
58,424
 
 
51,512
 
 
42,555
 
 
 
109,936
 
 
83,530
 
 
Production and manufacturing expenses(a)
 
 
5,515
 
 
5,438
 
 
5,761
 
 
 
10,953
 
 
11,016
 
 
Production and similar taxes (Note 8)
 
 
531
 
 
368
 
 
347
 
 
 
899
 
 
815
 
 
Depreciation, depletion and amortization (Note 7)
 
 
3,811
 
 
3,931
 
 
3,793
 
 
 
7,742
 
 
7,635
 
 
Impairment and losses on sale of businesses and fixed assets
 
 
(23
 
)
 
91
 
 
51
 
 
 
68
 
 
504
 
 
Exploration expense
 
 
164
 
 
514
 
 
850
 
 
 
678
 
 
1,262
 
 
Distribution and administration expenses
 
 
2,929
 
 
2,794
 
 
2,540
 
 
 
5,723
 
 
4,893
 
 
Profit (loss) before interest and taxation
 
 
5,556
 
 
4,495
 
 
1,469
 
 
 
10,051
 
 
4,097
 
 
Finance costs(a)
 
 
535
 
 
553
 
 
487
 
 
 
1,088
 
 
947
 
 
Net finance expense relating to pensions and other post-retirement benefits
 
 
31
 
 
31
 
 
54
 
 
 
62
 
 
107
 
 
Profit (loss) before taxation
 
 
4,990
 
 
3,911
 
 
928
 
 
 
8,901
 
 
3,043
 
 
Taxation(a)
 
 
2,117
 
 
1,380
 
 
772
 
 
 
3,497
 
 
1,395
 
 
Profit (loss) for the period
 
 
2,873
 
 
2,531
 
 
156
 
 
 
5,404
 
 
1,648
 
 
Attributable to
 
 
 
 
 
 
 
 
BP shareholders
 
 
2,799
 
 
2,469
 
 
144
 
 
 
5,268
 
 
1,593
 
 
Non-controlling interests
 
 
74
 
 
62
 
 
12
 
 
 
136
 
 
55
 
 
 
 
2,873
 
 
2,531
 
 
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
 
 
12.40
 
 
0.73
 
 
 
26.42
 
 
8.12
 
 
Diluted
 
 
13.96
 
 
12.33
 
 
0.72
 
 
 
26.27
 
 
8.08
 
 
Per ADS (dollars)
 
 
 
 
 
 
 
 
Basic
 
 
0.84
 
 
0.74
 
 
0.04
 
 
 
1.59
 
 
0.49
 
 
Diluted
 
 
0.84
 
 
0.74
 
 
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.
 
 
 
 
Top of page 15
 
Condensed group statement of comprehensive income
 
 
 
Second
 
First
 
Second
 
 
First
 
First
 
 
 
quarter
 
quarter
 
quarter
 
 
half
 
half
 
$ million
 
 
2018
 
2018
 
2017
 
 
2018
 
2017
 
 
 
 
 
 
 
 
 
Profit (loss) for the period
 
 
2,873
 
 
2,531
 
 
156
 
 
 
5,404
 
 
1,648
 
 
Other comprehensive income
 
 
 
 
 
 
 
 
Items that may be reclassified subsequently to profit or loss
 
 
 
 
 
 
 
 
Currency translation differences
 
 
(2,612
 
)
 
531
 
 
(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
 
)
 
(82
 
)
 
148
 
 
 
(189
 
)
 
277
 
 
Share of items relating to equity-accounted entities, net of tax
 
 
(33
 
)
 
155
 
 
72
 
 
 
122
 
 
303
 
 
Income tax relating to items that may be reclassified
 
 
52
 
 
(90
 
)
 
4
 
 
 
(38
 
)
 
(121
 
)
 
 
 
(2,700
 
)
 
514
 
 
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
 
 
865
 
 
318
 
 
 
2,579
 
 
1,045
 
 
Cash flow hedges that will subsequently be transferred to the balance sheet
 
 
(35
 
)
 
13
 
 
—
 
 
 
(22
 
)
 
—
 
 
Income tax relating to items that will not be reclassified
 
 
(557
 
)
 
(265
 
)
 
(102
 
)
 
 
(822
 
)
 
(348
 
)
 
 
 
1,122
 
 
613
 
 
216
 
 
 
1,735
 
 
697
 
 
Other comprehensive income
 
 
(1,578
 
)
 
1,127
 
 
342
 
 
 
(451
 
)
 
2,275
 
 
Total comprehensive income
 
 
1,295
 
 
3,658
 
 
498
 
 
 
4,953
 
 
3,923
 
 
Attributable to
 
 
 
 
 
 
 
 
BP shareholders
 
 
1,268
 
 
3,580
 
 
472
 
 
 
4,848
 
 
3,835
 
 
Non-controlling interests
 
 
27
 
 
78
 
 
26
 
 
 
105
 
 
88
 
 
 
 
1,295
 
 
3,658
 
 
498
 
 
 
4,953
 
 
3,923
 
 
 
 
Top of page 16
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.
 
 
Top of page 17
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
 
 
 
 
Top of page 18
Condensed group cash flow statement
 
 
 
Second
 
First
 
Second
 
 
First
 
First
 
 
 
quarter
 
quarter
 
quarter
 
 
half
 
half
 
$ million
 
 
2018
 
2018
 
2017
 
 
2018
 
2017
 
Operating activities
 
 
 
 
 
 
 
 
Profit (loss) before taxation
 
 
4,990
 
 
3,911
 
 
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
 
 
4,357
 
 
4,546
 
 
 
8,249
 
 
8,649
 
 
Impairment and (gain) loss on sale of businesses and fixed assets
 
 
(79
 
)
 
(14
 
)
 
(146
 
)
 
 
(93
 
)
 
262
 
 
Earnings from equity-accounted entities, less dividends received
 
 
(988
 
)
 
(536
 
)
 
(103
 
)
 
 
(1,524
 
)
 
(323
 
)
 
Net charge for interest and other finance expense, less net interest paid
 
 
191
 
 
80
 
 
84
 
 
 
271
 
 
336
 
 
Share-based payments
 
 
167
 
 
237
 
 
156
 
 
 
404
 
 
318
 
 
Net operating charge for pensions and other post-retirement benefits, less contributions and benefit payments for unfunded plans
 
 
(62
 
)
 
(202
 
)
 
54
 
 
 
(264
 
)
 
(19
 
)
 
Net charge for provisions, less payments
 
 
80
 
 
144
 
 
183
 
 
 
224
 
 
6
 
 
Movements in inventories and other current and non-current assets and liabilities
 
 
(570
 
)
 
(3,398
 
)
 
3
 
 
 
(3,968
 
)
 
(3,597
 
)
 
Income taxes paid
 
 
(1,315
 
)
 
(933
 
)
 
(815
 
)
 
 
(2,248
 
)
 
(1,671
 
)
 
Net cash provided by operating activities
 
 
6,306
 
 
3,646
 
 
4,890
 
 
 
9,952
 
 
7,004
 
 
Investing activities
 
 
 
 
 
 
 
 
Expenditure on property, plant and equipment, intangible and other assets
 
 
(3,484
 
)
 
(3,586
 
)
 
(4,181
 
)
 
 
(7,070
 
)
 
(8,004
 
)
 
Acquisitions, net of cash acquired
 
 
(1
 
)
 
—
 
 
(123
 
)
 
 
(1
 
)
 
(165
 
)
 
Investment in joint ventures
 
 
(18
 
)
 
(39
 
)
 
(10
 
)
 
 
(57
 
)
 
(30
 
)
 
Investment in associates
 
 
(322
 
)
 
(338
 
)
 
(174
 
)
 
 
(660
 
)
 
(357
 
)
 
Total cash capital expenditure
 
 
(3,825
 
)
 
(3,963
 
)
 
(4,488
 
)
 
 
(7,788
 
)
 
(8,556
 
)
 
Proceeds from disposal of fixed assets
 
 
105
 
 
85
 
 
312
 
 
 
190
 
 
500
 
 
Proceeds from disposal of businesses, net of cash disposed
 
 
45
 
 
82
 
 
140
 
 
 
127
 
 
213
 
 
Proceeds from loan repayments
 
 
24
 
 
9
 
 
19
 
 
 
33
 
 
33
 
 
Net cash used in investing activities
 
 
(3,651
 
)
 
(3,787
 
)
 
(4,017
 
)
 
 
(7,438
 
)
 
(7,810
 
)
 
Financing activities
 
 
 
 
 
 
 
 
Net issue (repurchase) of shares
 
 
(90
 
)
 
(110
 
)
 
—
 
 
 
(200
 
)
 
—
 
 
Proceeds from long-term financing
 
 
910
 
 
122
 
 
1,720
 
 
 
1,032
 
 
5,433
 
 
Repayments of long-term financing
 
 
(1,726
 
)
 
(1,157
 
)
 
(1,463
 
)
 
 
(2,883
 
)
 
(2,380
 
)
 
Net increase (decrease) in short-term debt
 
 
292
 
 
(349
 
)
 
(299
 
)
 
 
(57
 
)
 
16
 
 
Net increase (decrease) in non-controlling interests
 
 
—
 
 
(1
 
)
 
51
 
 
 
(1
 
)
 
81
 
 
Dividends paid - BP shareholders
 
 
(1,727
 
)
 
(1,829
 
)
 
(1,546
 
)
 
 
(3,556
 
)
 
(2,850
 
)
 
 - non-controlling interests
 
 
(57
 
)
 
(13
 
)
 
(62
 
)
 
 
(70
 
)
 
(77
 
)
 
Net cash provided by (used in) financing activities
 
 
(2,398
 
)
 
(3,337
 
)
 
(1,599
 
)
 
 
(5,735
 
)
 
223
 
 
Currency translation differences relating to cash and cash equivalents
 
 
(314
 
)
 
145
 
 
202
 
 
 
(169
 
)
 
369
 
 
Increase (decrease) in cash and cash equivalents
 
 
(57
 
)
 
(3,333
 
)
 
(524
 
)
 
 
(3,390
 
)
 
(214
 
)
 
Cash and cash equivalents at beginning of period
 
 
22,242
 
 
25,575
 
 
23,794
 
 
 
25,575
 
 
23,484
 
 
Cash and cash equivalents at end of period
 
 
22,185
 
 
22,242
 
 
23,270
 
 
 
22,185
 
 
23,270
 
 
 
 
Top of page 19
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
 
)
 
 
 
 
 
Top of page 20
 
 
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.
 
 
 
 
Top of page 21
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
 
First
 
Second
 
 
First
 
First
 
 
 
quarter
 
quarter
 
quarter
 
 
half
 
half
 
$ million
 
 
2018
 
2018
 
2017
 
 
2018
 
2017
 
Income statement
 
 
 
 
 
 
 
 
Production and manufacturing expenses
 
 
433
 
 
86
 
 
347
 
 
 
519
 
 
382
 
 
Profit (loss) before interest and taxation
 
 
(433
 
)
 
(86
 
)
 
(347
 
)
 
 
(519
 
)
 
(382
 
)
 
Finance costs
 
 
118
 
 
120
 
 
121
 
 
 
238
 
 
247
 
 
Profit (loss) before taxation
 
 
(551
 
)
 
(206
 
)
 
(468
 
)
 
 
(757
 
)
 
(629
 
)
 
Taxation
 
 
106
 
 
61
 
 
154
 
 
 
167
 
 
202
 
 
Profit (loss) for the period
 
 
(445
 
)
 
(145
 
)
 
(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
 
First
 
Second
 
 
First
 
First
 
 
 
quarter
 
quarter
 
quarter
 
 
half
 
half
 
$ million
 
 
2018
 
2018
 
2017
 
 
2018
 
2017
 
Cash flow statement - Operating activities
 
 
 
 
 
 
 
 
Profit (loss) before taxation
 
 
(551
 
)
 
(206
 
)
 
(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
 
 
120
 
 
121
 
 
 
238
 
 
247
 
 
Net charge for provisions, less payments
 
 
48
 
 
54
 
 
298
 
 
 
102
 
 
293
 
 
Movements in inventories and other current and non-current assets and liabilities
 
 
(693
 
)
 
(1,588
 
)
 
(1,976
 
)
 
 
(2,281
 
)
 
(4,230
 
)
 
Pre-tax cash flows
 
 
(1,078
 
)
 
(1,620
 
)
 
(2,025
 
)
 
 
(2,698
 
)
 
(4,319
 
)
 
 
 
 
 
 
Top of page 22
 
 
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.
 
 
 
Top of page 23
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
 
First
 
Second
 
 
First
 
First
 
 
 
quarter
 
quarter
 
quarter
 
 
half
 
half
 
$ million
 
 
2018
 
2018
 
2017
 
 
2018
 
2017
 
Upstream
 
 
3,514
 
 
3,174
 
 
795
 
 
 
6,688
 
 
2,051
 
 
Downstream
 
 
840
 
 
1,713
 
 
1,567
 
 
 
2,553
 
 
3,273
 
 
Rosneft
 
 
766
 
 
247
 
 
279
 
 
 
1,013
 
 
378
 
 
Other businesses and corporate(a)
 
 
(1,025
 
)
 
(571
 
)
 
(721
 
)
 
 
(1,596
 
)
 
(1,152
 
)
 
 
 
4,095
 
 
4,563
 
 
1,920
 
 
 
8,658
 
 
4,550
 
 
Consolidation adjustment – UPII*
 
 
151
 
 
(160
 
)
 
135
 
 
 
(9
 
)
 
67
 
 
RC profit (loss) before interest and tax*
 
 
4,246
 
 
4,403
 
 
2,055
 
 
 
8,649
 
 
4,617
 
 
Inventory holding gains (losses)*
 
 
 
 
 
 
 
 
Upstream
 
 
4
 
 
1
 
 
1
 
 
 
5
 
 
(5
 
)
 
Downstream
 
 
1,196
 
 
69
 
 
(579
 
)
 
 
1,265
 
 
(481
 
)
 
Rosneft (net of tax)
 
 
110
 
 
22
 
 
(8
 
)
 
 
132
 
 
(34
 
)
 
Profit (loss) before interest and tax
 
 
5,556
 
 
4,495
 
 
1,469
 
 
 
10,051
 
 
4,097
 
 
Finance costs
 
 
535
 
 
553
 
 
487
 
 
 
1,088
 
 
947
 
 
Net finance expense relating to pensions and other post-retirement benefits
 
 
31
 
 
31
 
 
54
 
 
 
62
 
 
107
 
 
Profit (loss) before taxation
 
 
4,990
 
 
3,911
 
 
928
 
 
 
8,901
 
 
3,043
 
 
 
 
 
 
 
 
 
 
RC profit (loss) before interest and tax*
 
 
 
 
 
 
 
 
US
 
 
(20
 
)
 
359
 
 
302
 
 
 
339
 
 
815
 
 
Non-US
 
 
4,266
 
 
4,044
 
 
1,753
 
 
 
8,310
 
 
3,802
 
 
 
 
4,246
 
 
4,403
 
 
2,055
 
 
 
8,649
 
 
4,617
 
 
 
(a)
Includes costs related to the Gulf of Mexico oil spill. See Note 2 for further information.
 
 
Top of page 24
Note 6. Sales and other operating revenues
 
 
 
Second
 
First
 
Second
 
 
First
 
First
 
 
 
quarter
 
quarter
 
quarter
 
 
half
 
half
 
$ million
 
 
2018
 
2018
 
2017
 
 
2018
 
2017
 
By segment
 
 
 
 
 
 
 
 
Upstream
 
 
12,698
 
 
13,870
 
 
10,493
 
 
 
26,568
 
 
21,820
 
 
Downstream
 
 
69,174
 
 
61,406
 
 
52,195
 
 
 
130,580
 
 
102,275
 
 
Other businesses and corporate
 
 
376
 
 
343
 
 
326
 
 
 
719
 
 
611
 
 
 
 
82,248
 
 
75,619
 
 
63,014
 
 
 
157,867
 
 
124,706
 
 
 
 
 
 
 
 
 
 
Less: sales and other operating revenues between segments
 
 
 
 
 
 
 
 
Upstream
 
 
5,795
 
 
6,733
 
 
6,161
 
 
 
12,528
 
 
11,938
 
 
Downstream
 
 
785
 
 
482
 
 
208
 
 
 
1,267
 
 
122
 
 
Other businesses and corporate
 
 
229
 
 
232
 
 
134
 
 
 
461
 
 
272
 
 
 
 
6,809
 
 
7,447
 
 
6,503
 
 
 
14,256
 
 
12,332
 
 
 
 
 
 
 
 
 
 
Third party sales and other operating revenues
 
 
 
 
 
 
 
 
Upstream
 
 
6,903
 
 
7,137
 
 
4,332
 
 
 
14,040
 
 
9,882
 
 
Downstream
 
 
68,389
 
 
60,924
 
 
51,987
 
 
 
129,313
 
 
102,153
 
 
Other businesses and corporate
 
 
147
 
 
111
 
 
192
 
 
 
258
 
 
339
 
 
Total sales and other operating revenues
 
 
75,439
 
 
68,172
 
 
56,511
 
 
 
143,611
 
 
112,374
 
 
 
 
 
 
 
 
 
 
By geographical area
 
 
 
 
 
 
 
 
US
 
 
26,676
 
 
23,613
 
 
21,577
 
 
 
50,289
 
 
42,729
 
 
Non-US
 
 
56,032
 
 
51,240
 
 
41,103
 
 
 
107,272
 
 
81,123
 
 
 
 
82,708
 
 
74,853
 
 
62,680
 
 
 
157,561
 
 
123,852
 
 
Less: sales and other operating revenues between areas
 
 
7,269
 
 
6,681
 
 
6,169
 
 
 
13,950
 
 
11,478
 
 
 
 
75,439
 
 
68,172
 
 
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
 
 
14,917
 
 
11,784
 
 
 
32,084
 
 
22,780
 
 
Oil products
 
 
51,440
 
 
44,130
 
 
37,079
 
 
 
95,570
 
 
73,680
 
 
Natural gas, LNG and NGLs
 
 
4,960
 
 
5,159
 
 
3,479
 
 
 
10,119
 
 
7,317
 
 
Non-oil products and other revenues from contracts with customers
 
 
3,081
 
 
3,495
 
 
2,872
 
 
 
6,576
 
 
5,736
 
 
Revenues from contracts with customers(a)
 
 
76,648
 
 
67,701
 
 
55,214
 
 
 
144,349
 
 
109,513
 
 
 
(a) 
See Note 1 for further information.
 
 
Note 7. Depreciation, depletion and amortization
 
 
 
Second
 
First
 
Second
 
 
First
 
First
 
 
 
quarter
 
quarter
 
quarter
 
 
half
 
half
 
$ million
 
 
2018
 
2018
 
2017
 
 
2018
 
2017
 
Upstream
 
 
 
 
 
 
 
 
US
 
 
999
 
 
1,088
 
 
1,133
 
 
 
2,087
 
 
2,370
 
 
Non-US
 
 
2,226
 
 
2,272
 
 
2,090
 
 
 
4,498
 
 
4,144
 
 
 
 
3,225
 
 
3,360
 
 
3,223
 
 
 
6,585
 
 
6,514
 
 
Downstream
 
 
 
 
 
 
 
 
US
 
 
221
 
 
219
 
 
219
 
 
 
440
 
 
435
 
 
Non-US
 
 
293
 
 
302
 
 
274
 
 
 
595
 
 
553
 
 
 
 
514
 
 
521
 
 
493
 
 
 
1,035
 
 
988
 
 
Other businesses and corporate
 
 
 
 
 
 
 
 
US
 
 
16
 
 
16
 
 
16
 
 
 
32
 
 
32
 
 
Non-US
 
 
56
 
 
34
 
 
61
 
 
 
90
 
 
101
 
 
 
 
72
 
 
50
 
 
77
 
 
 
122
 
 
133
 
 
Total group
 
 
3,811
 
 
3,931
 
 
3,793
 
 
 
7,742
 
 
7,635
 
 
 
 
Top of page 25
Note 8. Production and similar taxes
 
 
 
Second
 
First
 
Second
 
 
First
 
First
 
 
 
quarter
 
quarter
 
quarter
 
 
half
 
half
 
$ million
 
 
2018
 
2018
 
2017
 
 
2018
 
2017
 
US
 
 
89
 
 
90
 
 
41
 
 
 
179
 
 
77
 
 
Non-US
 
 
442
 
 
278
 
 
306
 
 
 
720
 
 
738
 
 
 
 
531
 
 
368
 
 
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
 
First
 
Second
 
 
First
 
First
 
 
 
quarter
 
quarter
 
quarter
 
 
half
 
half
 
$ million
 
 
2018
 
2018
 
2017
 
 
2018
 
2017
 
Results for the period
 
 
 
 
 
 
 
 
Profit (loss) for the period attributable to BP shareholders
 
 
2,799
 
 
2,469
 
 
144
 
 
 
5,268
 
 
1,593
 
 
Less: preference dividend
 
 
1
 
 
—
 
 
1
 
 
 
1
 
 
1
 
 
Profit (loss) attributable to BP ordinary shareholders
 
 
2,798
 
 
2,469
 
 
143
 
 
 
5,267
 
 
1,592
 
 
 
 
 
 
 
 
 
 
Number of shares (thousand)(a)
 
 
 
 
 
 
 
 
Basic weighted average number of shares outstanding
 
 
19,945,053
 
 
19,918,700
 
 
19,686,613
 
 
 
19,931,945
 
 
19,602,785
 
 
ADS equivalent
 
 
3,324,175
 
 
3,319,783
 
 
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
 
 
20,030,656
 
 
19,783,548
 
 
 
20,050,123
 
 
19,713,151
 
 
ADS equivalent
 
 
3,340,712
 
 
3,338,442
 
 
3,297,258
 
 
 
3,341,687
 
 
3,285,525
 
 
 
 
 
 
 
 
 
 
Shares in issue at period-end
 
 
19,973,943
 
 
19,943,591
 
 
19,738,566
 
 
 
19,973,943
 
 
19,738,566
 
 
ADS equivalent
 
 
3,328,991
 
 
3,323,931
 
 
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.
Top of page 26
 
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
 
First
 
Second
 
 
First
 
First
 
 
 
quarter
 
quarter
 
quarter
 
 
half
 
half
 
 
 
2018
 
2018
 
2017
 
 
2018
 
2017
 
Dividends paid per ordinary share
 
 
 
 
 
 
 
 
cents
 
 
10.000
 
 
10.000
 
 
10.000
 
 
 
20.000
 
 
20.000
 
 
pence
 
 
7.444
 
 
7.169
 
 
7.756
 
 
 
14.613
 
 
15.915
 
 
Dividends paid per ADS (cents)
 
 
60.00
 
 
60.00
 
 
60.00
 
 
 
120.00
 
 
120.00
 
 
Scrip dividends
 
 
 
 
 
 
 
 
Number of shares issued (millions)
 
 
34.5
 
 
23.4
 
 
70.1
 
 
 
57.9
 
 
185.2
 
 
Value of shares issued ($ million)
 
 
266
 
 
155
 
 
420
 
 
 
421
 
 
1,062
 
 
 
 
 
 
Note 11. Net Debt*
 
Net debt ratio*
 
 
Second
 
First
 
Second
 
 
First
 
First
 
 
 
quarter
 
quarter
 
quarter
 
 
half
 
half
 
$ million
 
 
2018
 
2018
 
2017
 
 
2018
 
2017
 
Gross debt
 
 
60,358
 
 
62,189
 
 
63,004
 
 
 
60,358
 
 
63,004
 
 
Fair value (asset) liability of hedges related to finance debt(a)
 
 
1,104
 
 
46
 
 
60
 
 
 
1,104
 
 
60
 
 
 
 
61,462
 
 
62,235
 
 
63,064
 
 
 
61,462
 
 
63,064
 
 
Less: cash and cash equivalents
 
 
22,185
 
 
22,242
 
 
23,270
 
 
 
22,185
 
 
23,270
 
 
Net debt
 
 
39,277
 
 
39,993
 
 
39,794
 
 
 
39,277
 
 
39,794
 
 
Equity
 
 
101,770
 
 
102,165
 
 
98,461
 
 
 
101,770
 
 
98,461
 
 
Net debt ratio
 
 
27.8
 
%
 
28.1
 
%
 
28.8
 
%
 
 
27.8
 
%
 
28.8
 
%
 
 
 
 
 
 
Top of page 27
 
Note 11. Net Debt* (continued)
 
Analysis of changes in net debt
 
 
Second
 
First
 
Second
 
 
First
 
First
 
 
 
quarter
 
quarter
 
quarter
 
 
half
 
half
 
$ million
 
 
2018
 
2018
 
2017
 
 
2018
 
2017
 
Opening balance
 
 
 
 
 
 
 
 
Finance debt(a)
 
 
62,189
 
 
63,230
 
 
61,832
 
 
 
63,230
 
 
58,300
 
 
Fair value (asset) liability of hedges related to finance debt(b)
 
 
46
 
 
175
 
 
597
 
 
 
175
 
 
697
 
 
Less: cash and cash equivalents(c)
 
 
22,242
 
 
25,575
 
 
23,794
 
 
 
25,575
 
 
23,484
 
 
Opening net debt
 
 
39,993
 
 
37,830
 
 
38,635
 
 
 
37,830
 
 
35,513
 
 
Closing balance
 
 
 
 
 
 
 
 
Finance debt(a)
 
 
60,358
 
 
62,189
 
 
63,004
 
 
 
60,358
 
 
63,004
 
 
Fair value (asset) liability of hedges related to finance debt(b)
 
 
1,104
 
 
46
 
 
60
 
 
 
1,104
 
 
60
 
 
Less: cash and cash equivalents
 
 
22,185
 
 
22,242
 
 
23,270
 
 
 
22,185
 
 
23,270
 
 
Closing net debt
 
 
39,277
 
 
39,993
 
 
39,794
 
 
 
39,277
 
 
39,794
 
 
Decrease (increase) in net debt
 
 
716
 
 
(2,163
 
)
 
(1,159
 
)
 
 
(1,447
 
)
 
(4,281
 
)
 
Movement in cash and cash equivalents (excluding exchange adjustments)
 
 
257
 
 
(3,478
 
)
 
(726
 
)
 
 
(3,221
 
)
 
(583
 
)
 
Net cash outflow (inflow) from financing
 
 
524
 
 
1,384
 
 
42
 
 
 
1,908
 
 
(3,069
 
)
 
Other movements
 
 
(123
 
)
 
(27
 
)
 
(13
 
)
 
 
(150
 
)
 
(79
 
)
 
Movement in net debt before exchange effects
 
 
658
 
 
(2,121
 
)
 
(697
 
)
 
 
(1,463
 
)
 
(3,731
 
)
 
Exchange adjustments
 
 
58
 
 
(42
 
)
 
(462
 
)
 
 
16
 
 
(550
 
)
 
Decrease (increase) in net debt
 
 
716
 
 
(2,163
 
)
 
(1,159
 
)
 
 
(1,447
 
)
 
(4,281
 
)
 
 
(a)
The fair value of finance debt at 30 June 2018 was $61,619 million (1 January 2018 $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 (first quarter 2018 liability of $457 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.
 
 
 
 
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. BP Annual Report and Form 20-F 2017 has been filed with the Registrar of Companies in England and Wales. The report of the auditor on those accounts was unqualified and did not contain a statement under section 498(2) or section 498(3) of the UK Companies Act 2006.
 
 
 
Top of page 28
 
 
Additional information
 
 
 
 
Capital expenditure*
 
 
 
Second
 
First
 
Second
 
 
First
 
First
 
 
 
quarter
 
quarter
 
quarter
 
 
half
 
half
 
$ million
 
 
2018
 
2018
 
2017
 
 
2018
 
2017
 
Capital expenditure on a cash basis
 
 
 
 
 
 
 
 
Organic capital expenditure*
 
 
3,470
 
 
3,538
 
 
4,348
 
 
 
7,008
 
 
7,886
 
 
Inorganic capital expenditure*(a)
 
 
355
 
 
425
 
 
140
 
 
 
780
 
 
670
 
 
 
 
3,825
 
 
3,963
 
 
4,488
 
 
 
7,788
 
 
8,556
 
 
 
 
 
 
 
Second
 
First
 
Second
 
 
First
 
First
 
 
 
quarter
 
quarter
 
quarter
 
 
half
 
half
 
$ million
 
 
2018
 
2018
 
2017
 
 
2018
 
2017
 
Organic capital expenditure by segment
 
 
 
 
 
 
 
 
Upstream
 
 
 
 
 
 
 
 
US
 
 
826
 
 
754
 
 
805
 
 
 
1,580
 
 
1,446
 
 
Non-US
 
 
1,941
 
 
2,112
 
 
3,005
 
 
 
4,053
 
 
5,344
 
 
 
 
2,767
 
 
2,866
 
 
3,810
 
 
 
5,633
 
 
6,790
 
 
Downstream
 
 
 
 
 
 
 
 
US
 
 
232
 
 
171
 
 
149
 
 
 
403
 
 
301
 
 
Non-US
 
 
382
 
 
447
 
 
316
 
 
 
829
 
 
636
 
 
 
 
614
 
 
618
 
 
465
 
 
 
1,232
 
 
937
 
 
Other businesses and corporate
 
 
 
 
 
 
 
 
US
 
 
7
 
 
7
 
 
3
 
 
 
14
 
 
24
 
 
Non-US
 
 
82
 
 
47
 
 
70
 
 
 
129
 
 
135
 
 
 
 
89
 
 
54
 
 
73
 
 
 
143
 
 
159
 
 
 
 
3,470
 
 
3,538
 
 
4,348
 
 
 
7,008
 
 
7,886
 
 
Organic capital expenditure by geographical area
 
 
 
 
 
 
 
 
US
 
 
1,065
 
 
932
 
 
957
 
 
 
1,997
 
 
1,771
 
 
Non-US
 
 
2,405
 
 
2,606
 
 
3,391
 
 
 
5,011
 
 
6,115
 
 
 
 
3,470
 
 
3,538
 
 
4,348
 
 
 
7,008
 
 
7,886
 
 
 
(a)
First quarter 2018 includes amounts relating to the 25-year extension to our ACG production-sharing agreement* in Azerbaijan.
 
 
 
 
Top of page 29
 
Non-operating items*
 
 
 
Second
 
First
 
Second
 
 
First
 
First
 
 
 
quarter
 
quarter
 
quarter
 
 
half
 
half
 
$ million
 
 
2018
 
2018
 
2017
 
 
2018
 
2017
 
Upstream
 
 
 
 
 
 
 
 
Impairment and gain (loss) on sale of businesses and fixed assets(a)
 
 
81
 
 
26
 
 
(18
 
)
 
 
107
 
 
(400
 
)
 
Environmental and other provisions
 
 
—
 
 
—
 
 
—
 
 
 
—
 
 
—
 
 
Restructuring, integration and rationalization costs
 
 
(62
 
)
 
1
 
 
(19
 
)
 
 
(61
 
)
 
(17
 
)
 
Fair value gain (loss) on embedded derivatives
 
 
9
 
 
7
 
 
5
 
 
 
16
 
 
30
 
 
Other
 
 
(1
 
)
 
(138
 
)
 
11
 
 
 
(139
 
)
 
6
 
 
 
 
27
 
 
(104
 
)
 
(21
 
)
 
 
(77
 
)
 
(381
 
)
 
Downstream
 
 
 
 
 
 
 
 
Impairment and gain (loss) on sale of businesses and fixed assets
 
 
(1
 
)
 
(14
 
)
 
156
 
 
 
(15
 
)
 
145
 
 
Environmental and other provisions
 
 
—
 
 
—
 
 
—
 
 
 
—
 
 
—
 
 
Restructuring, integration and rationalization costs
 
 
(74
 
)
 
(36
 
)
 
(18
 
)
 
 
(110
 
)
 
(83
 
)
 
Fair value gain (loss) on embedded derivatives
 
 
—
 
 
—
 
 
—
 
 
 
—
 
 
—
 
 
Other
 
 
(150
 
)
 
(3
 
)
 
—
 
 
 
(153
 
)
 
—
 
 
 
 
(225
 
)
 
(53
 
)
 
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
 
)
 
2
 
 
8
 
 
 
1
 
 
(7
 
)
 
Environmental and other provisions
 
 
1
 
 
(21
 
)
 
(3
 
)
 
 
(20
 
)
 
(3
 
)
 
Restructuring, integration and rationalization costs
 
 
(30
 
)
 
(15
 
)
 
(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
 
)
 
(86
 
)
 
(87
 
)
 
 
(270
 
)
 
(122
 
)
 
Other
 
 
(85
 
)
 
(59
 
)
 
10
 
 
 
(144
 
)
 
77
 
 
 
 
(548
 
)
 
(179
 
)
 
(355
 
)
 
 
(727
 
)
 
(346
 
)
 
Total before interest and taxation
 
 
(746
 
)
 
(336
 
)
 
(238
 
)
 
 
(1,082
 
)
 
(665
 
)
 
Finance costs(b)
 
 
(118
 
)
 
(120
 
)
 
(121
 
)
 
 
(238
 
)
 
(247
 
)
 
Total before taxation
 
 
(864
 
)
 
(456
 
)
 
(359
 
)
 
 
(1,320
 
)
 
(912
 
)
 
Taxation credit (charge) on non-operating items
 
 
141
 
 
88
 
 
144
 
 
 
229
 
 
392
 
 
Taxation - impact of US tax reform(c)
 
 
—
 
 
121
 
 
—
 
 
 
121
 
 
—
 
 
Total after taxation for period
 
 
(723
 
)
 
(247
 
)
 
(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 quarter 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.
 
 
 
 
Top of page 30
 
Non-GAAP information on fair value accounting effects
 
 
 
Second
 
First
 
Second
 
 
First
 
First
 
 
 
quarter
 
quarter
 
quarter
 
 
half
 
half
 
$ million
 
 
2018
 
2018
 
2017
 
 
2018
 
2017
 
Favourable (adverse) impact relative to management’s measure of performance
 
 
 
 
 
 
 
 
Upstream
 
 
(21
 
)
 
121
 
 
106
 
 
 
100
 
 
352
 
 
Downstream
 
 
(390
 
)
 
(60
 
)
 
16
 
 
 
(450
 
)
 
56
 
 
 
 
(411
 
)
 
61
 
 
122
 
 
 
(350
 
)
 
408
 
 
Taxation credit (charge)
 
 
101
 
 
(11
 
)
 
(38
 
)
 
 
90
 
 
(117
 
)
 
 
 
(310
 
)
 
50
 
 
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.
 
 
 
 
 
Top of page 31
 
 
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
 
First
 
Second
 
 
First
 
First
 
 
 
quarter
 
quarter
 
quarter
 
 
half
 
half
 
$ million
 
 
2018
 
2018
 
2017
 
 
2018
 
2017
 
Upstream
 
 
 
 
 
 
 
 
Replacement cost profit (loss) before interest and tax adjusted for fair value accounting effects
 
 
3,535
 
 
3,053
 
 
689
 
 
 
6,588
 
 
1,699
 
 
Impact of fair value accounting effects
 
 
(21
 
)
 
121
 
 
106
 
 
 
100
 
 
352
 
 
Replacement cost profit (loss) before interest and tax
 
 
3,514
 
 
3,174
 
 
795
 
 
 
6,688
 
 
2,051
 
 
Downstream
 
 
 
 
 
 
 
 
Replacement cost profit (loss) before interest and tax adjusted for fair value accounting effects
 
 
1,230
 
 
1,773
 
 
1,551
 
 
 
3,003
 
 
3,217
 
 
Impact of fair value accounting effects
 
 
(390
 
)
 
(60
 
)
 
16
 
 
 
(450
 
)
 
56
 
 
Replacement cost profit (loss) before interest and tax
 
 
840
 
 
1,713
 
 
1,567
 
 
 
2,553
 
 
3,273
 
 
Total group
 
 
 
 
 
 
 
 
Profit (loss) before interest and tax adjusted for fair value accounting effects
 
 
5,967
 
 
4,434
 
 
1,347
 
 
 
10,401
 
 
3,689
 
 
Impact of fair value accounting effects
 
 
(411
 
)
 
61
 
 
122
 
 
 
(350
 
)
 
408
 
 
Profit (loss) before interest and tax
 
 
5,556
 
 
4,495
 
 
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 34 for a more detailed definition of RMI. RMI, RMI at fair value, paid-up RMI and unpaid RMI are non-GAAP measures. A reconciliation of total inventory as reported on the group balance sheet to paid-up RMI is provided below.
 
 
 
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
 
 
 
 
 
Top of page 32
 
Working capital* reconciliation
 
 
 
Second
 
 
First
 
 
 
quarter
 
 
half
 
$ million
 
 
2018
 
 
2018
 
Movements in inventories and other current and non-current assets and liabilities as per condensed group cash flow statement
 
 
(570
 
)
 
 
(3,968
 
)
 
Adjustments to exclude movements in inventories and other current and non-current assets and liabilities for the Gulf of Mexico oil spill (Note 2)
 
 
693
 
 
 
2,281
 
 
Adjusted for Inventory holding gains (losses)* (Note 5)
 
 
 
 
 
Upstream
 
 
4
 
 
 
5
 
 
Downstream
 
 
1,196
 
 
 
1,265
 
 
Working capital release (build)
 
 
1,323
 
 
 
(417
 
)
 
 
 
 
 
Realizations* and marker prices
 
 
 
Second
 
First
 
Second
 
 
First
 
First
 
 
 
quarter
 
quarter
 
quarter
 
 
half
 
half
 
 
 
2018
 
2018
 
2017
 
 
2018
 
2017
 
Average realizations(a)
 
 
 
 
 
 
 
 
Liquids* ($/bbl)
 
 
 
 
 
 
 
 
US
 
 
62.47
 
 
57.77
 
 
44.65
 
 
 
60.01
 
 
45.51
 
 
Europe
 
 
71.70
 
 
65.81
 
 
47.79
 
 
 
68.56
 
 
50.50
 
 
Rest of World
 
 
69.88
 
 
63.30
 
 
47.11
 
 
 
66.50
 
 
49.46
 
 
BP Average
 
 
67.24
 
 
61.40
 
 
46.27
 
 
 
64.21
 
 
48.09
 
 
Natural gas ($/mcf)
 
 
 
 
 
 
 
 
US
 
 
1.96
 
 
2.25
 
 
2.32
 
 
 
2.10
 
 
2.41
 
 
Europe
 
 
7.04
 
 
7.18
 
 
4.48
 
 
 
7.11
 
 
4.93
 
 
Rest of World
 
 
4.16
 
 
4.22
 
 
3.47
 
 
 
4.19
 
 
3.64
 
 
BP Average
 
 
3.65
 
 
3.78
 
 
3.19
 
 
 
3.72
 
 
3.34
 
 
Total hydrocarbons* ($/boe)
 
 
 
 
 
 
 
 
US
 
 
40.77
 
 
39.65
 
 
32.46
 
 
 
40.19
 
 
33.39
 
 
Europe
 
 
64.91
 
 
60.78
 
 
41.10
 
 
 
62.72
 
 
43.84
 
 
Rest of World
 
 
42.89
 
 
40.54
 
 
33.48
 
 
 
41.69
 
 
35.64
 
 
BP Average
 
 
43.37
 
 
41.39
 
 
33.59
 
 
 
42.36
 
 
35.37
 
 
Average oil marker prices ($/bbl)
 
 
 
 
 
 
 
 
Brent
 
 
74.39
 
 
66.82
 
 
49.64
 
 
 
70.58
 
 
51.71
 
 
West Texas Intermediate
 
 
68.02
 
 
62.90
 
 
48.11
 
 
 
65.52
 
 
49.89
 
 
Western Canadian Select
 
 
49.76
 
 
36.84
 
 
38.55
 
 
 
43.30
 
 
38.66
 
 
Alaska North Slope
 
 
73.93
 
 
67.20
 
 
50.61
 
 
 
70.64
 
 
52.20
 
 
Mars
 
 
69.47
 
 
62.44
 
 
46.92
 
 
 
66.04
 
 
48.24
 
 
Urals (NWE – cif)
 
 
72.21
 
 
65.27
 
 
48.48
 
 
 
68.71
 
 
50.22
 
 
Average natural gas marker prices
 
 
 
 
 
 
 
 
Henry Hub gas price(b) ($/mmBtu)
 
 
2.80
 
 
3.01
 
 
3.19
 
 
 
2.90
 
 
3.25
 
 
UK Gas – National Balancing Point (p/therm)
 
 
53.88
 
 
57.97
 
 
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
 
First
 
Second
 
 
First
 
First
 
 
 
quarter
 
quarter
 
quarter
 
 
half
 
half
 
 
 
2018
 
2018
 
2017
 
 
2018
 
2017
 
$/£ average rate for the period
 
 
1.36
 
 
1.39
 
 
1.28
 
 
 
1.38
 
 
1.26
 
 
$/£ period-end rate
 
 
1.31
 
 
1.41
 
 
1.30
 
 
 
1.31
 
 
1.30
 
 
 
 
 
 
 
 
 
 
$/€ average rate for the period
 
 
1.19
 
 
1.23
 
 
1.10
 
 
 
1.21
 
 
1.08
 
 
$/€ period-end rate
 
 
1.16
 
 
1.24
 
 
1.14
 
 
 
1.16
 
 
1.14
 
 
 
 
 
 
 
 
 
 
Rouble/$ average rate for the period
 
 
62.13
 
 
56.88
 
 
57.24
 
 
 
59.47
 
 
57.98
 
 
Rouble/$ period-end rate
 
 
63.07
 
 
57.72
 
 
59.05
 
 
 
63.07
 
 
59.05
 
 
 
 
Top of page 33
 
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.
 
 
 
Top of page 34
 
 
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.
 
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 30.
 
Gearing – See Net debt and net debt ratio definition.
 
Hydrocarbons – Liquids and natural gas. Natural gas is converted to oil equivalent at 5.8 billion cubic feet = 1 million barrels.
 
Inorganic capital expenditure is a subset of capital expenditure and is a non-GAAP measure. Inorganic capital expenditure comprises consideration in business combinations and certain other significant investments made by the group. It is reported on a cash basis. BP believes that this measure provides useful information as it allows investors to understand how BP’s management invests funds in projects which expand the group’s activities through acquisition. Further information and a reconciliation to GAAP information is provided on page 28.
 
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.
 
 
 
Top of page 35
 
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 7, 9 and 11, and by segment and type is shown on page 29.
 
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 28.
 
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 31.
 
 
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. 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.
 
 
 
Top of page 36
 
 
 
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.
 
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.
 
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.
 
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.
 
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.
 
 
 
 
Top of page 37
 
 
 
 
Glossary (continued)
 
 
Working capital - Change in working capital is movements in inventories and other current and non-current assets and liabilities as reported in the condensed group cash flow statement. Change in working capital adjusted for inventory holding gains/losses is a non-GAAP measure. It is calculated by adjusting for inventory holding gains/losses reported in the period and this therefore represents what would have been reported as movements in inventories and other current and non-current assets and liabilities, if the starting point in determining net cash provided by operating activities had been replacement cost profit rather than profit for the period. The nearest equivalent measure on an IFRS basis for this is movements in inventories and other current and non-current assets and liabilities. In the context of describing operating cash flow excluding Gulf of Mexico oil spill payments, change in working capital also excludes movements in inventories and other current and non-current assets and liabilities relating to the Gulf of Mexico oil spill. See page 32 for further details.
 
BP utilizes various arrangements in order to manage its working capital including discounting of receivables and, in the supply and trading business, the active management of supplier payment terms, inventory and collateral.
 
 
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.
 
 
 
Top of page 38
 
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.
 
This document contains references to non-proved resources that the SEC's rules prohibit us from including in our filings with the SEC. U.S. investors are urged to consider closely the disclosures in our Form 20-F, SEC File No. 1-06262. This form is available on our website at www.bp.com. You can also obtain this form from the SEC by calling 1-800-SEC-0330 or by logging on to their website at www.sec.gov.
 
 
 
 
 
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BP p.l.c.’s LEI Code 213800LH1BZH3D16G760
 
 
 
 
 
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/ D. J. JACKSON
 
------------------------
 
D. J. JACKSON
 
Company Secretary