2Q15 Part 1 of 1

RNS Number : 2299U
BP PLC
28 July 2015
 



BP p.l.c.

Group results

Second quarter and half year 2015(a)

 

Top of page 1

FOR IMMEDIATE RELEASE                                         London 28 July 2015

 







$ million


2015

2014

3,369

2,602


Profit (loss) for the period(b)


6,897

(187)

(499)


Inventory holding (gains) losses*, net of tax


(240)

3,182

2,103


Replacement cost profit (loss)*


6,657




Net (favourable) unfavourable impact






  of non-operating items* and fair value



453

474


  accounting effects*, net of tax


203

3,635

2,577


Underlying replacement cost profit*


6,860




Replacement cost profit (loss)



17.25

11.54


    per ordinary share (cents)


36.05

1.03

0.69


    per ADS (dollars)


2.16




Underlying replacement cost profit



19.71

14.14


    per ordinary share (cents)


37.15

1.18

0.85


    per ADS (dollars)


2.23

 

·   BP's second-quarter replacement cost (RC) loss was $6,266 million, compared with a profit of $3,182 million a year ago. After adjusting for a net charge for non-operating items of $7,486 million, mainly relating to the recently announced agreements in principle to settle federal, state and the vast majority of local government claims arising from the 2010 Deepwater Horizon accident, and net unfavourable fair value accounting effects of $93 million (both on a post-tax basis), underlying RC profit for the second quarter was $1,313 million, compared with $3,635 million for the same period in 2014. For the half year, RC loss was $4,163 million, compared with a profit of $6,657 million a year ago. After adjusting for a net charge for non-operating items of $7,899 million and net unfavourable fair value accounting effects of $154 million (both on a post-tax basis), underlying RC profit for the half year was $3,890 million, compared with $6,860 million for the same period in 2014. Non-operating items include a restructuring charge of $272 million for the quarter and $487 million for the half year. Restructuring charges are now expected to be around $1.5 billion by the end of 2015 relative to the $1 billion we announced back in December. RC profit or loss for the group, underlying RC profit or loss and fair value accounting effects are non-GAAP measures and further information is provided on pages 3 and 30.

 

·   On 2 July 2015, BP announced that it has reached agreements in principle to settle all outstanding federal and state claims and claims made by more than 400 local government entities arising from the 2010 Deepwater Horizon oil spill. BP has accepted releases received from the vast majority of local government entities and the District Court has ordered BP to commence processing payments under the releases.

 

·   The group income statement for the second quarter reflects a pre-tax charge of $9.8 billion related to the agreements in principle. All amounts relating to the Gulf of Mexico oil spill have been treated as non-operating items, with a net pre-tax charge of $10,755 million for the second quarter and $11,087 million for the half year ($7,154 million and $7,374 million respectively on a post-tax basis). For further information on the Gulf of Mexico oil spill and its consequences see page 10 and Note 2 on page 18. See also Principal risks and uncertainties on page 34 and Legal proceedings on page 35.

 

·   Including the impact of the Gulf of Mexico oil spill, net cash provided by operating activities for the second quarter and half year was $6.3 billion and $8.1 billion respectively, compared with $7.9 billion and $16.1 billion for the same periods in 2014. Excluding amounts related to the Gulf of Mexico oil spill, net cash provided by operating activities for the second quarter and half year was $6.4 billion and $8.9 billion respectively, compared with $7.6 billion and $16.5 billion for the same periods in 2014.

 

·   Net debt* at 30 June 2015 was $24.8 billion, compared with $24.4 billion a year ago. The net debt ratio* at 30 June 2015 was 18.8%, compared with 15.5% a year ago. Net debt and the net debt ratio are non-GAAP measures. See page 26 for more information.

 

·   Total capital expenditure on an accruals basis for the second quarter was $4.7 billion, of which organic capital expenditure* was $4.5 billion, compared with $5.6 billion for the same period in 2014, almost all of which was organic. For the half year, total capital expenditure on an accruals basis was $9.1 billion, of which organic capital expenditure was $8.9 billion, compared with $11.7 billion for the same period in 2014, of which organic capital expenditure was $11.0 billion. For full year 2015, we now expect organic capital expenditure to be below $20 billion.

 

·   BP today announced a quarterly dividend of 10.00 cents per ordinary share ($0.600 per ADS), which is expected to be paid on 18 September 2015. The corresponding amount in sterling will be announced on 8 September 2015. See page 25 for further information.

 

*

 

For items marked with an asterisk throughout this document, definitions are provided in the Glossary on page 32.

 

(a)

This results announcement also represents BP's half-yearly financial report (see page 11).

 

(b)

Profit attributable to BP shareholders.

 

 

The commentaries above and following should be read in conjunction with the cautionary statement on page 38.

 

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Group headlines (continued)

 

·   In October 2013, BP announced plans to divest a further $10 billion of assets before the end of 2015, having completed its earlier divestment programme of $38 billion. Transactions to date have reached around $7.4 billion. Disposal proceeds were $0.5 billion for the second quarter and $2.3 billion for the half year. The half-year amount includes proceeds from our Toledo refinery partner, Husky Energy, in place of capital commitments relating to the original divestment transaction that have not been subsequently sanctioned.

 

·   The effective tax rate (ETR) on RC profit or loss for the second quarter and half year was 33% and 47% compared with 34% and 32% for the same periods in 2014. Excluding the one-off deferred tax adjustment in the first quarter 2015 as a result of the reduction in the UK North Sea supplementary charge, the ETR for the half year was 35%. Adjusting for non-operating items, fair value accounting effects and the first-quarter 2015 one-off deferred tax adjustment, the underlying ETR in the second quarter and half year was 35% and 28% respectively, compared with 33% for the same periods in 2014. The underlying ETR for the half year is lower than a year ago mainly due to changes in the mix of our profits and certain one-off items, partly offset by foreign exchange effects from a stronger US dollar.

 

·   Finance costs and net finance expense relating to pensions and other post-retirement benefits were a charge of $364 million for the second quarter, compared with $356 million for the same period in 2014. For the half year, the respective amounts were $722 million and $723 million.

 

 

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Analysis of RC profit (loss) before interest and tax

and reconciliation to profit (loss) for the period

 







$ million


2015

2014





RC profit (loss) before interest and tax*




4,049

372

228


    Upstream


600

8,708

933

2,083

1,628


    Downstream


3,711

1,727

1,024

183

510


    Rosneft


693

1,542

(434)

(308)

(455)


    Other businesses and corporate


(763)

(931)

(251)

(323)

(10,747)


    Gulf of Mexico oil spill response(a)


(11,070)

(280)

(76)

(129)

(39)


    Consolidation adjustment - UPII*


(168)

14

5,245

1,878

(8,875)


RC profit (loss) before interest and tax


(6,997)

10,780





Finance costs and net finance expense relating to




(356)

(358)

(364)


  pensions and other post-retirement benefits


(722)

(723)

(1,643)

632

3,013


Taxation on a RC basis


3,645

(3,245)

(64)

(49)

(40)


Non-controlling interests


(89)

(155)

3,182

2,103

(6,266)


RC profit (loss) attributable to BP shareholders


(4,163)

6,657

258

756

627


Inventory holding gains (losses)


1,383

360





Taxation (charge) credit on inventory holding gains




(71)

(257)

(184)


  and losses


(441)

(120)





Profit (loss) for the period attributable to




3,369

2,602

(5,823)


  BP shareholders


(3,221)

6,897

 

(a)

See Note 2 on page 18 for further information on the accounting for the Gulf of Mexico oil spill response.

 

 

Analysis of underlying RC profit before interest and tax

 



First

First




half

half


$ million


2015

2014





Underlying RC profit before interest and tax*




4,655

604

494


    Upstream


1,098

9,056

733

2,158

1,867


    Downstream


4,025

1,744

1,024

183

510


    Rosneft


693

1,295

(438)

(290)

(401)


    Other businesses and corporate


(691)

(927)

(76)

(129)

(39)


    Consolidation adjustment - UPII


(168)

14

5,898

2,526

2,431


Underlying RC profit before interest and tax


4,957

11,182





Finance costs and net finance expense relating to




(347)

(349)

(356)


  pensions and other post-retirement benefits


(705)

(704)

(1,852)

449

(722)


Taxation on an underlying RC basis


(273)

(3,463)

(64)

(49)

(40)


Non-controlling interests


(89)

(155)

3,635

2,577

1,313


Underlying RC profit attributable to BP shareholders


3,890

6,860

 

Reconciliations of underlying RC profit or loss to the nearest equivalent IFRS measure are provided on page 1 for the group and on pages 4-9 for the segments.

 

 

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Upstream

 



First

First




half

half


$ million


2015

2014

4,048

390


Profit before interest and tax


8,701

1

(18)


Inventory holding (gains) losses*


7

4,049

372


RC profit before interest and tax


8,708




Net (favourable) unfavourable impact of






  non-operating items* and fair



606

232


  value accounting effects*


348

4,655

604


Underlying RC profit before interest and tax*(a)


9,056

 

(a)

See page 5 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 $228 million and $600 million respectively, compared with $4,049 million and $8,708 million for the same periods in 2014. The second quarter and half year included a net non-operating charge of $236 million and $478 million respectively, compared with a net non-operating charge of $516 million and $240 million for the same periods a year ago. Fair value accounting effects in the second quarter and half year had unfavourable impacts of $30 million and $20 million respectively, compared with unfavourable impacts of $90 million and $108 million in the same periods of 2014.

 

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 $494 million and $1,098 million respectively, compared with $4,655 million and $9,056 million for the same periods in 2014. The result for the second quarter reflected significantly lower liquids and gas realizations and higher exploration write-offs, partly offset by lower costs including the benefits from simplification and efficiency activities. In Libya, we recorded exploration write-offs and other costs totalling $598 million in the quarter. The result for the first half reflected significantly lower liquids and gas realizations, and lower gas marketing and trading results, partly offset by increased production and lower costs. Costs were lower reflecting benefits from simplification and efficiency activities and lower exploration write-offs, partly offset by rig cancellation costs.

 

Production

 

Production for the quarter was 2,112mboe/d, 0.3% higher than the second quarter of 2014. Underlying production* for the quarter decreased by 1.7%, mainly due to increased seasonal turnaround activity partly offset by the ramp-up of major projects which started up in 2014. For the first half, production was 2,209mboe/d, 4.3% higher than in the same period of 2014. First-half underlying production was 1.0% higher than in 2014.

 

Key events

 

In April, BP confirmed the start of oil production from the Kizomba Satellites Phase-2 development in Block 15, offshore Angola. This deepwater project is operated by ExxonMobil.

 

In April, BP signed agreements to become a shareholder in the Trans Anatolian Natural Gas Pipeline (TANAP), and will hold a 12% equity share in the project. TANAP is a central part of the Southern Corridor pipeline system that will transport gas from the Shah Deniz field in Azerbaijan to markets in Turkey, Greece, Bulgaria and Italy.

 

BP signed agreements to purchase a 20% participatory interest in Taas-Yuryakh Neftegazodobycha, a Rosneft subsidiary which will further develop the Srednebotuobinskoye oil and gas condensate field in East Siberia. Related to this, Rosneft and BP will jointly undertake the exploration of an Area of Mutual Interest in the region. Rosneft and BP have also agreed to jointly explore two additional Areas of Mutual Interest in the West Siberian and Yenisey-Khatanga basins covering a combined area of approximately 260,000km2.

 

Greater Plutonio Phase 3 successfully started up production, BP's second major project start-up in Angola this year.

 

In Australia, front-end engineering and design has commenced on the Browse floating LNG development.

 

Following Atoll in the first quarter, we made a further gas discovery at the Nooros prospect, located in the Abu Madi West concession in the Nile Delta in Egypt, operated by our partner ENI. BP holds a 25% interest.

 

This builds on the progress we announced with our first-quarter results, which comprised the following: the gas discovery in the North Damietta Offshore Concession in the East Nile Delta in Egypt at the Atoll-1 Deepwater exploration well; the final agreements for two West Nile Delta projects Taurus/Libra and Giza/Fayoum/Raven with an estimated investment of around $12 billion by BP and its partner; the start of production at the Sunrise Phase 1 in-situ oil sands project in Alberta, Canada; and the sale of BP's equity in the Central Area Transmission System (CATS) business in the UK North Sea to Antin Infrastructure Partners.

 

Outlook

 

Looking ahead, we expect third-quarter 2015 reported production to be broadly flat with the second quarter, primarily reflecting the continuation of seasonal maintenance activity consistent with the second-quarter activity levels.

 

The commentary above contains forward-looking statements and should be read in conjunction with the cautionary statement on page 38.

 

 

 

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Upstream

 




$ million





Underlying RC profit (loss) before interest and tax



1,419

(545)


US


2,150

3,236

1,149


Non-US


6,906

4,655

604




9,056




Non-operating items



(72)

(68)


US


(131)

(444)

(174)


Non-US


(109)

(516)

(242)




(240)




Fair value accounting effects



(31)

(3)


US


(80)

(59)

13


Non-US


(28)

(90)

10




(108)




RC profit (loss) before interest and tax



1,316

(616)


US


1,939

2,733

988


Non-US


6,769

4,049

372




8,708




Exploration expense



68

78


US(a)


727

321

94


Non-US(b)


610

389

172




1,337




Production (net of royalties)(c)






Liquids* (mb/d)



429

392


US


413

92

112


Europe


99

562

754


Rest of World


572

1,083

1,258




1,084




Natural gas (mmcf/d)




1,525

1,517


US


1,502

166

264


Europe


182

4,244

4,307


Rest of World


4,317

5,936

6,088




6,001




Total hydrocarbons* (mboe/d)



692

653


US


672

121

158


Europe


130

1,293

1,496


Rest of World


1,316

2,106

2,307




2,118




Average realizations(d)



96.90

46.79


Total liquids ($/bbl)


97.03

5.67

4.44


Natural gas ($/mcf)


5.94

64.90

37.00


Total hydrocarbons ($/boe)


65.53

 

(a)

First half 2014 includes a $521-million write-off relating to the Utica shale acreage in Ohio, following the decision not to proceed with development plans.

(b)

Second quarter and first half 2015 include a $432-million write-off in Libya. BP has declared force majeure in Libya and there is significant uncertainty on when drilling operations might be able to proceed.

(c)

Includes BP's share of production of equity-accounted entities in the Upstream segment.

(d)

Based on sales by consolidated subsidiaries only - this excludes equity-accounted entities.

 

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

 

 

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Downstream

 







$ million


1,166

2,783


Profit before interest and tax


2,037

(233)

(700)


Inventory holding (gains) losses*


(310)

933

2,083


RC profit before interest and tax


1,727




Net (favourable) unfavourable impact of







  non-operating items* and fair




(200)

75


  value accounting effects*


17

733

2,158


Underlying RC profit before interest and tax*(a)


1,744

 

(a)

See page 7 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 $1,628 million and $3,711 million respectively, compared with $933 million and $1,727 million for the same periods in 2014. 

 

The 2015 results include a net non-operating charge of $122 million for the second quarter and $85 million for the half year mainly reflecting restructuring charges, compared with a net non-operating gain of $50 million and a net non-operating charge of $228 million for the same periods in 2014 (see pages 7 and 29 for further information on non-operating items). Fair value accounting effects had unfavourable impacts of $117 million for the second quarter and $229 million for the half year, compared with favourable impacts of $150 million and $211 million in the same periods of 2014. 

 

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 $1,867 million and $4,025 million respectively, compared with $733 million and $1,744 million for the same periods in 2014.

 

Replacement cost profit before interest and tax for the fuels, lubricants and petrochemicals businesses is set out on page 7.

 

Fuels business

 

The fuels business reported an underlying replacement cost profit before interest and tax of $1,394 million for the second quarter and $3,190 million for the half year, compared with $516 million and $1,216 million for the same periods in 2014. The results for the quarter and half year were driven by improved refining environment and production mix, partially offset by weaker North American crude oil differentials. The quarter and half year also benefited from a higher oil supply and trading contribution, returning to average levels in the second quarter, as well as lower costs, including the benefits from our simplification and efficiency programmes.

 

During the quarter we completed the cessation of refining operations at our Bulwer Island facility and we announced, with our partner, Rosneft, a planned reorganization of our German refining joint operations. In the first quarter we announced the sale of our bitumen business in Australia and completed the sale of our interest in UTA, a European fuel cards business.

 

Lubricants business

 

The lubricants business reported an underlying replacement cost profit before interest and tax of $397 million in the second quarter and $742 million in the half year, compared with $315 million and $622 million in the same periods last year. The strong quarterly and half-year performance reflects continued momentum in growth markets, premium brand performance and benefits from our simplification and efficiency programmes leading to lower costs. These benefits were partially offset by adverse foreign exchange effects.

 

Petrochemicals business

 

The petrochemicals business reported an underlying replacement cost profit before interest and tax of $76 million in the second quarter and $93 million in the half year, compared with losses of $98 million and $94 million in the same periods last year. The improved results reflect stronger operational performance, improved margins and the benefits of our simplification and efficiency programmes.

 

Our new advanced technology purified terephthalic acid (PTA) plant in Zhuhai, China which will add over one million tonnes of PTA capacity per year, is now fully commissioned and operational.

 

Outlook

 

Looking forward to the third quarter, we expect reduced refining margins and lower levels of turnaround activity. 

 

 

 

The commentary above contains forward-looking statements and should be read in conjunction with the cautionary statement on page 38.

 

 

Top of page 7

Downstream

 







$ million





Underlying RC profit before interest and tax - 






  by region



331

661


US


743

402

1,497


Non-US


1,001

733

2,158




1,744




Non-operating items



180

(4)


US


179

(130)

41


Non-US


(407)

50

37




(228)




Fair value accounting effects



206

(127)


US


297

(56)

15


Non-US


(86)

150

(112)




211




RC profit before interest and tax



717

530


US


1,219

216

1,553


Non-US


508

933

2,083




1,727




Underlying RC profit (loss) before interest






  and tax - by business(a)(b)



516

1,796


Fuels


1,216

315

345


Lubricants


622

(98)

17


Petrochemicals


(94)

733

2,158




1,744




Non-operating items and fair value accounting






  effects(c)



15

(60)


Fuels


(202)

186

(14)


Lubricants


186

(1)

(1)


Petrochemicals


(1)

200

(75)




(17)




RC profit (loss) before interest and tax(a)(b)



531

1,736


Fuels


1,014

501

331


Lubricants


808

(99)

16


Petrochemicals


(95)

933

2,083




1,727







15.4

15.2


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


14.4




Refinery throughputs (mb/d)



645

623


US


630

757

805


Europe


777

250

324


Rest of World


279

1,652

1,752




1,686

95.3

94.3


Refining availability* (%)


95.1




Marketing sales of refined products (mb/d)



1,183

1,098


US


1,152

1,154

1,174


Europe


1,146

515

607


Rest of World


530

2,852

2,879




2,828

2,468

2,544


Trading/supply sales of refined products


2,442

5,320

5,423


Total sales volumes of refined products


5,270




Petrochemicals production (kte)



969

905


US


2,040

895

972


Europe


1,867

1,501

1,663


Rest of World


2,923

3,365

3,540




6,830

 

(a)

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

(b)

BP's share of income from petrochemicals at our Gelsenkirchen and Mülheim sites in Germany is reported in the fuels business.

(c)

For Downstream, fair value accounting effects arise solely in the fuels business.

 

 

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Rosneft

 






2015(a)


$ million


2015(a)

1,050

221


Profit before interest and tax(b)


1,599

(26)

(38)


Inventory holding (gains) losses*


(57)

1,024

183


RC profit before interest and tax


1,542

-

-


Net charge (credit) for non-operating items*


(247)

1,024

183


Underlying RC profit before interest and tax*


1,295

 

Replacement cost profit before interest and tax for the second quarter and half year was $510 million and $693 million respectively, compared with $1,024 million and $1,542 million for the same periods in 2014.

 

There were no non-operating items in the second quarter 2015, half year 2015, or second quarter 2014, and there was a non-operating gain of $247 million in the first half of 2014.

 

After adjusting for non-operating items, the underlying replacement cost profit for the second quarter and half year was $510 million and $693 million respectively, compared with $1,024 million and $1,295 million for the same periods in 2014. Compared with the same period last year, the result for the second quarter was primarily affected by lower oil prices. For the half year, the result was primarily affected by lower oil prices partly offset by favourable foreign exchange effects.

 

See also Group statement of comprehensive income - Share of items relating to equity-accounted entities, net of tax, and footnote (a), on page 14 for other foreign exchange effects.

 

A second BP representative, Guillermo Quintero, president of BP Energy do Brasil Ltda, was elected to Rosneft's board of directors at Rosneft's Annual General Meeting of Shareholders (AGM) on 17 June 2015. 

 

Rosneft's AGM also approved the distribution of a dividend of 8.21 roubles per share. We received our share of this dividend in July 2015, which amounted to $271 million after the deduction of withholding tax.

 






2015(a)




2015(a)




Production (net of royalties) (BP share)


820

816


Liquids* (mb/d)


825

1,036

1,225


Natural gas (mmcf/d)


1,030

999

1,027


Total hydrocarbons* (mboe/d)


1,002

 

(a)

The operational and financial information of the Rosneft segment for the second quarter and first half is based on preliminary operational and financial results of Rosneft for the six months ended 30 June 2015. 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 disposal of BP's interest in TNK-BP. These adjustments have increased the reported profit for the second quarter and first half 2015, as shown in the table above, compared with the equivalent amount in Russian roubles that we expect Rosneft to report in its own financial statements under IFRS. BP's share of Rosneft's profit before interest and tax for each year-to-date period is calculated by translating the amounts reported in Russian roubles into US dollars using the average exchange rate for the year to date. BP's share of Rosneft's earnings after finance costs, taxation and non-controlling interests, as adjusted, is included in the BP group income statement within profit before interest and taxation.

 

 

Top of page 9

Other businesses and corporate

 







$ million


(434)

(308)


Profit (loss) before interest and tax


(931)

-

-


Inventory holding (gains) losses*


-

(434)

(308)


RC profit (loss) before interest and tax


(931)

(4)

18


Net charge (credit) for non-operating items*


4

(438)

(290)


Underlying RC profit (loss) before interest and tax*


(927)




Underlying RC profit (loss) before interest and tax



(226)

(62)


US


(325)

(212)

(228)


Non-US


(602)

(438)

(290)




(927)




Non-operating items



4

(1)


US


3

-

(17)


Non-US


(7)

4

(18)




(4)




RC profit (loss) before interest and tax



(222)

(63)


US


(322)

(212)

(245)


Non-US


(609)

(434)

(308)




(931)

 

Other businesses and corporate comprises biofuels and wind businesses, shipping, treasury (which includes interest income on the group's cash and cash equivalents), and corporate activities including centralized functions.

 

Financial results

 

The replacement cost loss before interest and tax for the second quarter and half year was $455 million and $763 million respectively, compared with $434 million and $931 million for the same periods in 2014.

 

The second-quarter result included a net non-operating charge of $54 million, compared with a net non-operating gain of $4 million a year ago. For the half year, the net non-operating charge was $72 million, compared with a net non-operating charge of $4 million a year ago.

 

After adjusting for non-operating items, the underlying replacement cost loss before interest and tax for the second quarter and half year was $401 million and $691 million respectively, compared with $438 million and $927 million for the same periods in 2014. The 2015 results reflected improved business performance and lower corporate and functional costs, partly offset by adverse foreign exchange impacts.

 

Biofuels

 

The net ethanol-equivalent production (which includes ethanol and sugar) for the second quarter was 247 million litres, compared with 113 million litres for the same period in 2014, as there was no production in the second quarter of 2014 at one of our mills in Brazil due to an expansion project.

 

Wind

 

Net wind generation capacity*(a) was 1,588MW at 30 June 2015, compared with 1,590MW at 30 June 2014. BP's net share of wind generation for the second quarter and half year was 1,150GWh and 2,277GWh respectively, compared with 1,248GWh and  2,540GWh for the same periods in 2014.

 

(a)

Capacity figures include 32MW in the Netherlands managed by our Downstream segment.

 

 

Top of page 10

Gulf of Mexico oil spill

 

We announced on 2 July 2015 that BP Exploration & Production Inc. has reached agreements in principle with the US federal government and five Gulf states to settle all outstanding federal and state claims arising from the Deepwater Horizon oil spill. The agreement with the Gulf states also provides for the settlement of claims made by more than 400 local government entities. The agreements in principle are subject to execution of definitive agreements, including a Consent Decree with the United States and Gulf states with respect to the Clean Water Act and natural resource damage claims. The definitive agreements will only become effective if there is final court approval of the Consent Decree. We expect that the definitive agreement with the Gulf states will be executed and that the court will approve the Consent Decree. BP advised the Court that it is satisfied with and has accepted releases received from the vast majority of local government entities. Accordingly, on 27 July, the District Court ordered BP to commence processing payments required under the releases and that such payments be made within 30 days of the Court's order. The agreements in principle do not cover claims relating to the 2012 class action settlements with the Plaintiffs' Steering Committee, including business economic loss claims; private claims from other litigants not included within the class action settlements; or private securities litigation in MDL 2185.

 

For further details see Note 2 on page 18 and Legal proceedings on page 35.

 

Financial update

 

The replacement cost loss before interest and tax for the second quarter and half year was $10,747 million and $11,070 million respectively, compared with $251 million and $280 million for the same periods last year. The second-quarter loss reflects a $9.8 billion charge associated with the government settlements mentioned above, additional claims administration costs and business economic loss claims under the Plaintiffs' Steering Committee settlement, and adjustments to other provisions, as well as the ongoing costs of the Gulf Coast Restoration Organization. The cumulative pre-tax charge recognized to date amounts to $54.6 billion.

 

The cumulative income statement charge does not include amounts for obligations that BP currently considers are not possible to measure reliably. The total amounts that will ultimately be paid by BP in relation to the incident will be dependent on many factors, as discussed under Provisions and contingent liabilities in Note 2 on page 20. These could have a material impact on our consolidated financial position, results and cash flows.

 

 

Top of page 11

Half-yearly financial report

 

This results announcement also represents BP's half-yearly financial report for the purposes of the Disclosure 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 13-27; (ii) pages 1-10, and 28-38 comprise the interim management report; and (iii) the directors' responsibility statement and auditors' independent review report can be found on pages 11-12.

 

 

Statement of directors' responsibilities

 

The directors confirm that, to the best of their knowledge, the condensed set of financial statements on pages 13-27 has been prepared in accordance with IAS 34 'Interim Financial Reporting', and that the interim management report on pages 1-10 and 28-38 includes a fair review of the information required by the Disclosure and Transparency Rules.

 

The directors of BP p.l.c. are listed on pages 52-55 of BP Annual Report and Form 20-F 2014, with the exception of George David who retired at the 2015 Annual General Meeting and Paula Rosput Reynolds and Sir John Sawers who joined the board on 14 May 2015.

 

By order of the board

 

Bob Dudley

Brian Gilvary

Group Chief Executive

Chief Financial Officer

27 July 2015

27 July 2015

 

 

Top of page 12

Independent review report to BP p.l.c.

 

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 2015 which comprises the group income statement, group statement of comprehensive income, group statement of changes in equity, group balance sheet, condensed group cash flow statement, and Notes 1 to 10. 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 guidance contained in 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 Auditing Practices Board for use in the United Kingdom (ISRE 2410). To the fullest extent permitted by law, we do not accept or assume responsibility to anyone other than the company, for our 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 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 (IFRS) as issued by the International Accounting Standards Board (IASB) and IFRS as adopted by the European Union (EU). 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 EU.

 

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 ISRE 2410. A review of interim financial information consists of making enquiries, 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 Ireland) 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 2015 is not prepared, in all material respects, in accordance with International Accounting Standard 34 as issued by the IASB and as adopted by the EU and the Disclosure and Transparency Rules of the United Kingdom's Financial Conduct Authority.

 

 

Ernst & Young LLP

London

27 July 2015

 

The maintenance and integrity of the BP p.l.c. website are the responsibility of the directors; the review work carried out by the auditors does not involve consideration of these matters and, accordingly, the 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 13

Financial statements

 

Group income statement

 




$ million




93,957

54,196


Sales and other operating revenues (Note 4)


185,667

155

104


Earnings from joint ventures - after interest and tax


270

1,228

362


Earnings from associates - after interest and tax


2,011

157

120


Interest and other income


488

330

138


Gains on sale of businesses and fixed assets


379

95,827

54,920


Total revenues and other income


188,815

74,536

37,936


Purchases


146,004

6,980

7,000


Production and manufacturing expenses


13,811

816

362


Production and similar taxes (Note 5)


1,802

3,751

3,836


Depreciation, depletion and amortization


7,341




Impairment and losses on sale of businesses and



774

197


  fixed assets


1,200

389

172


Exploration expense


1,337

3,078

2,783


Distribution and administration expenses


6,180

5,503

2,634


Profit (loss) before interest and taxation


11,140

277

281


Finance costs


564




Net finance expense relating to pensions and other



79

77


  post-retirement benefits


159

5,147

2,276


Profit (loss) before taxation


10,417

1,714

(375)


Taxation


3,365

3,433

2,651


Profit (loss) for the period


7,052




Attributable to



3,369

2,602


  BP shareholders


6,897

64

49


  Non-controlling interests


155

3,433

2,651




7,052










Earnings per share (Note 6)






Profit (loss) for the period attributable to  BP  shareholders






  Per ordinary share (cents)



18.26

14.28


    Basic


37.35

18.15

14.21


    Diluted


37.11




  Per ADS (dollars)



1.10

0.86


    Basic


2.24

1.09

0.85


    Diluted


2.23

 

 

Top of page 14

Financial statements (continued)

 

Group statement of comprehensive income

 







$ million





3,433

2,651


Profit (loss) for the period


7,052




Other comprehensive income






Items that may be reclassified subsequently to profit






  or loss



1,005

(1,612)


  Currency translation differences


92




  Exchange gains (losses) on translation of foreign






    operations reclassified to gain or loss on sale of



-

-


    business and fixed assets


-

2

-


  Available-for-sale investments marked to market


(1)




  Available-for-sale investments reclassified to the



1

-


    income statement


1

77

(212)


  Cash flow hedges marked to market


100




  Cash flow hedges reclassified to the



(49)

74


    income statement


(69)

(2)

5


  Cash flow hedges reclassified to the balance sheet


(3)





  Share of items relating to equity-accounted entities,




51

(80)


    net of tax(a)


(22)

9

124


  Income tax relating to items that may be reclassified


9

1,094

(1,701)




107





Items that will not be reclassified to profit or loss







  Remeasurements of the net pension and other post-



222

(568)


    retirement benefit liability or asset


(714)




  Share of items relating to equity-accounted entities,



-

-


    net of tax


5




  Income tax relating to items that will not



(73)

158


    be reclassified


221

149

(410)




(488)

1,243

(2,111)


Other comprehensive income


(381)

4,676

540


Total comprehensive income


6,671




Attributable to



4,606

513


  BP shareholders


6,509

70

27


  Non-controlling interests


162

4,676

540




6,671

 

(a)

Includes the effects of hedge accounting adopted by Rosneft from 1 October 2014 in relation to a portion of future export revenue denominated in US dollars. For further information see BP Annual Report and Form 20-F 2014 - Financial statements - Note 15.

 

 

Top of page 15

Financial statements (continued)

 

Group statement of changes in equity

 




$ million




At 1 January 2015







Total comprehensive income


Dividends


Share-based payments, net of tax


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


Transactions involving non-controlling interests


At 30 June 2015











$ million







At 1 January 2014


129,302

1,105

130,407






Total comprehensive income


6,509

162

6,671

Dividends


(2,999)

(153)

(3,152)

Repurchases of ordinary share capital


(1,527)

-

(1,527)

Share-based payments, net of tax


576

-

576

Transactions involving non-controlling interests


-

3

3

At 30 June 2014


131,861

1,117

132,978

 

 

Top of page 16

Financial statements (continued)

 

Group balance sheet

 


$ million


Non-current assets



Property, plant and equipment


130,692

Goodwill


11,868

Intangible assets


20,907

Investments in joint ventures


8,753

Investments in associates


10,403

Other investments


1,228

Fixed assets


183,851

Loans


659

Trade and other receivables


4,787

Derivative financial instruments


4,442

Prepayments


964

Deferred tax assets


2,309

Defined benefit pension plan surpluses


31



197,043

Current assets



Loans


333

Inventories


18,373

Trade and other receivables


31,038

Derivative financial instruments


5,165

Prepayments


1,424

Current tax receivable


837

Other investments


329

Cash and cash equivalents


29,763



87,262

Total assets


284,305

Current liabilities



Trade and other payables


40,118

Derivative financial instruments


3,689

Accruals


7,102

Finance debt


6,877

Current tax payable


2,011

Provisions


3,818



63,615

Non-current liabilities



Other payables


3,587

Derivative financial instruments


3,199

Accruals


861

Finance debt


45,977

Deferred tax liabilities


13,893

Provisions


29,080

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


11,451



108,048

Total liabilities


171,663

Net assets


112,642

Equity



BP shareholders' equity


111,441

Non-controlling interests


1,201



112,642

 

 

Top of page 17

Financial statements (continued)

 

Condensed group cash flow statement

 







$ million



Operating activities



5,147

2,276


Profit (loss) before taxation


10,417




Adjustments to reconcile profit (loss) before






  taxation to net cash provided by operating activities






  Depreciation, depletion and amortization and



3,953

3,928


    exploration expenditure written off


8,375




  Impairment and (gain) loss on sale of businesses



444

59


    and fixed assets


821




  Earnings from equity-accounted entities, less



(1,080)

(276)


    dividends received


(1,764)




  Net charge for interest and other finance expense,



(3)

129


    less net interest paid


167

178

(238)


  Share-based payments


284




  Net operating charge for pensions and other post-






    retirement benefits, less contributions and benefit



(105)

(57)


    payments for unfunded plans


(207)

56

388


  Net charge for provisions, less payments


(137)




  Movements in inventories and other current and



654

(3,858)


   non-current assets and liabilities


339

(1,367)

(493)


  Income taxes paid


(2,187)

7,877

1,858


Net cash provided by operating activities


16,108




Investing activities



(5,499)

(4,636)


Capital expenditure


(11,390)

-

-


Acquisitions, net of cash acquired


(10)

(3)

(69)


Investment in joint ventures


(36)

(47)

(87)


Investment in associates


(135)

227

653


Proceeds from disposal of fixed assets


1,205




Proceeds from disposal of businesses, net of



571

1,087


  cash disposed


597

53

3


Proceeds from loan repayments


70

(4,698)

(3,049)


Net cash used in investing activities


(9,699)




Financing activities



(447)

-


Net repurchase of shares


(2,173)

856

7,788


Proceeds from long-term financing


6,835

(1,720)

(2,307)


Repayments of long-term financing


(2,957)

(57)

725


Net increase (decrease) in short-term debt


20

(1,572)

(1,709)


Dividends paid

- BP shareholders


(2,999)

(140)

(12)


- non-controlling interests


(153)

(3,080)

4,485


Net cash provided by (used in) financing activities


(1,427)




Currency translation differences relating to cash and



49

(623)


  cash equivalents


4

148

2,671


Increase (decrease) in cash and cash equivalents


4,986

27,358

29,763


Cash and cash equivalents at beginning of period


22,520

27,506

32,434


Cash and cash equivalents at end of period


27,506

 

 

Top of page 18

Financial statements (continued)

 

Notes

 

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 2014 included in the BP Annual Report and Form 20-F 2014.

 

The directors have made an assessment of the group's ability to continue as a going concern and 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 2015, which do not differ significantly from those used in BP Annual Report and Form 20-F 2014.

 

 

2.       Gulf of Mexico oil spill

 

(a) Overview

 

As a consequence of the Gulf of Mexico oil spill, BP continues to incur various costs and has also recognized liabilities for future costs. The information presented in this note should be read in conjunction with BP Annual Report and Form 20-F 2014 - Financial statements - Note 2 and Legal proceedings on page 228 and on page 35 of this report.

 

The group income statement includes a pre-tax charge of $10,755 million for the second quarter and $11,087 million for the first half of 2015 in relation to the Gulf of Mexico oil spill. The second-quarter charge includes additional amounts provided for the Clean Water Act penalty, natural resource damages and state and local government claims following the 2 July 2015 agreements in principle to settle all federal and state claims and claims made by more than 400 local government entities arising from the oil spill (the Agreements in Principle). The second-quarter charge also reflects additional business economic loss claims and claims administration costs under the Plaintiffs' Steering Committee (PSC) settlement and the ongoing costs of the Gulf Coast Restoration Organization. The cumulative pre-tax income statement charge since the incident, in April 2010, amounts to $54,582 million.

 

The cumulative income statement charge does not include amounts for obligations that BP considers are not possible, at this time, to measure reliably. For further information, see Provisions and contingent liabilities below.

 

The Agreements in Principle signed on 2 July 2015 are subject to execution of definitive agreements including a Consent Decree with the United States and Gulf states with respect to the Clean Water Act penalty and natural resource damages and other claims, a settlement agreement with five Gulf states with respect to state claims for economic loss, property damage and other claims, and release agreements for economic loss, property damage and other claims with local government entities. The state and local government claims cover economic loss, property damage, business interruption, breach of contract, loss of royalties, lost tourism, lost revenue, lost taxes, operating or other costs, losses or damages arising under the Oil Pollution Act of 1990 and other legislation. The Consent Decree will be subject to public comment and final court approval. The Consent Decree and settlement agreement with the Gulf states are conditional upon each other and neither will become effective unless there is final court approval of the Consent Decree and local government entities execute releases to BP's satisfaction. We expect that the definitive agreement with the Gulf states will be executed and that the court will approve the Consent Decree. BP advised the Court that it is satisfied with and has accepted releases received from the vast majority of local government entities. Accordingly, on 27 July, the District Court ordered BP to commence processing payments required under the releases and that such payments be made within 30 days of the Court's order. As part of the Agreements in Principle, BP agreed to pay up to $1 billion to resolve claims made by local government entities. For more information on the Agreements in Principle see Legal proceedings on page 35.

 

The Agreements in Principle described above significantly reduce the uncertainties faced by BP following the Gulf of Mexico oil spill in 2010. There continues to be uncertainty regarding the outcome or resolution of current or future litigation and the extent and timing of costs and liabilities relating to the incident not covered by the Agreements in Principle. The total amounts that will ultimately be paid by BP in relation to the incident will be dependent on many factors, as discussed under Provisions and contingent liabilities below, including in relation to any new information or future developments. These uncertainties could have a material impact on our consolidated financial position, results and cash flows.

 

 

Top of page 19

Financial statements (continued)

 

Notes

 

2.       Gulf of Mexico oil spill (continued)

 

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.

 










$ million







Income statement




251

323


Production and manufacturing expenses


280


(251)

(323)


Profit (loss) before interest and taxation


(280)


9

9


Finance costs


19


(260)

(332)


Profit (loss) before taxation


(299)


44

112


Taxation


54


(216)

(220)


Profit (loss) for the period


(245)

 

 




$ million



Balance sheet




Current assets




  Trade and other receivables


1,154


Current liabilities




  Trade and other payables


(655)


  Accruals


-


  Provisions


(1,702)


Net current assets (liabilities)


(1,203)


Non-current assets




  Trade and other receivables


2,701


Non-current liabilities




  Other payables

(2,412)


  Accruals

(169)


  Provisions


(6,903)


  Deferred tax


1,723


Net non-current assets (liabilities)


(5,060)


Net assets (liabilities)


(6,263)

 

 










$ million







Cash flow statement - Operating activities




(260)

(332)


Profit (loss) before taxation


(299)





Adjustments to reconcile profit (loss) before







  taxation to net cash provided by







  operating activities







Net charge for interest and other finance




9

9


  expense, less net interest paid


19


116

227


Net charge for provisions, less payments


19





Movements in inventories and other current




(33)

(595)


  and non-current assets and liabilities


(611)


(168)

(691)


Pre-tax cash flows


(872)

 

Net cash from operating activities relating to the Gulf of Mexico oil spill, on a post-tax basis, amounted to an outflow of $106 million and outflow of $797 million in the second quarter and first half of 2015 respectively. For the same periods in 2014, the amounts were an inflow of $229 million and an outflow of $355 million respectively.

 

 

Top of page 20

Financial statements (continued)

 

Notes

 

2.       Gulf of Mexico oil spill (continued)

 

Trust fund

 

BP established the Deepwater Horizon Oil Spill Trust (the Trust), funded in the amount of $20 billion, to satisfy legitimate individual and business claims, state and local government claims resolved by BP, final judgments and settlements, state and local response costs, and natural resource damages and related costs. Fines and penalties are not covered by the trust fund.

 

The funding of the Trust was completed in 2012. The obligation to fund the $20-billion trust fund, adjusted to take account of the time value of money, was recognized in full in 2010 and charged to the income statement. An asset has been recognized representing BP's right to receive reimbursement from the trust fund. This is the portion of the estimated future expenditure provided for that will be settled by payments from the trust fund. During 2014, cumulative charges to be paid by the Trust reached $20 billion. Subsequent additional costs, over and above those provided within the $20 billion, are expensed to the income statement as incurred.

 

At 30 June 2015, $2,841 million of the provisions and payables are eligible to be paid from the Trust. The reimbursement asset is recorded within other receivables on the balance sheet, of which $2,638 million is classified as current and $203 million as non-current. During the second quarter of 2015, $523 million of provisions and $19 million of payables were paid from the Trust.

 

At 30 June 2015, the aggregate cash balances in the Trust and the associated qualifying settlement funds amounted to $3.7 billion, including $0.8 billion remaining in the seafood compensation fund which has yet to be distributed and $0.4 billion held for natural resource damage early restoration projects. When the cash balances in the trust fund are exhausted, payments in respect of legitimate claims and other costs will be made directly by BP.

 

(b) Provisions and contingent liabilities

 

BP has recorded certain provisions and disclosed certain contingent liabilities as a consequence of the Gulf of Mexico oil spill. These are described below and in more detail in BP Annual Report and Form 20-F 2014 - Financial statements - Note 2.

 

Provisions

 

BP has recorded provisions relating to the Gulf of Mexico oil spill in relation to environmental expenditure, litigation and claims, and Clean Water Act penalties. Movements in each class of provision during the second quarter and first half are presented in the table below.

 









$ million 



At 1 April 2015



Net increase in provision



Reclassified to other payables



Utilization

- paid by BP



              

- paid by the trust fund



At 30 June 2015



Of which

- current



              

- non-current


 















$ million 



At 1 January 2015



Net increase in provision



Unwinding of discount



Reclassified to other payables



Utilization

- paid by BP




- paid by the trust fund



At 30 June 2015


 

 

Top of page 21

Financial statements (continued)

 

Notes

 

2.       Gulf of Mexico oil spill (continued)

 

Provisions recorded include $18.7 billion, plus interest and adjusted to take account of the time value of money, in relation to the Agreements in Principle. In addition, $0.4 billion has been provided in relation to natural resource damage assessment costs under the Agreements in Principle. After taking account of amounts previously provided for, the net increase in provisions as a result of the settlement amounted to $9.8 billion.

 

Environmental

The environmental provision includes amounts payable for natural resource damage costs under one of the Agreements in Principle referred to above. These amounts are payable in instalments over 16 years commencing one year after the court approves the Consent Decree; the majority of the unpaid balance of this natural resource damages settlement accrues interest at a fixed rate. The remaining amounts payable under the $1-billion early restoration framework agreement with natural resource trustees for the US and five Gulf states are also included in environmental provisions.

 

Litigation and claims

The litigation and claims provision includes amounts that can be estimated reliably for the future cost of settling 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 (Individual and Business Claims), and amounts agreed under the Agreements in Principle in relation to state claims and amounts in respect of local government claims. Claims administration costs and legal costs have also been provided for. Amounts that cannot be measured reliably and which have therefore not been provided for are described under Contingent liabilities below.

 

Litigation and claims - PSC settlement

BP has provided for its best estimate of the cost associated with the PSC settlement agreements with the exception of the cost of business economic loss claims, except where an eligibility notice has been issued and is not subject to appeal by BP within the claims facility. See BP Annual Report and Form 20-F 2014 - Financial statements - Note 2 and Legal proceedings on pages 228-237 and page 35 of this report for further details on the settlements with the PSC and related matters.

 

Management believes that no reliable estimate can currently be made of any business economic loss claims not yet processed or processed but not yet paid, except where an eligibility notice has been issued and is not subject to appeal by BP within the claims facility.

 

The submission deadline for business economic loss claims passed on 8 June 2015; no further claims may be submitted. A significant number of business economic loss claims have been received but have not yet been processed and it is not possible to quantify the total value of the claims.

 

A revised policy for the matching of revenue and expenses for business economic loss claims was introduced in May 2014 and, of the claims assessable under the new policy, the majority have not yet been determined at this time. Uncertainties regarding the proper application of the revised policy to particular claims and categories of claims continue to arise as the claims administrator has applied the revised policy. There have been no, or only a small number of, claim determinations made under some of the specialized frameworks that have been put in place for particular industries and so determinations to date may not be representative of the total population of claims. In addition, while detailed data on pre-determination claims is not available due to a court order to protect claimant confidentiality, aggregated pre-determination data has recently been provided. While this data does provide some insights, it is not at a sufficient level of detail to review claim demographics or identify potential populations for each category of claims.

 

There is limited data available to build up a track record of claims determinations under the policies and protocols that are now being applied following resolution of the matching and causation issues. We are unable to reliably estimate future trends of the number and proportion of claims that will be determined to be eligible, nor can we reliably estimate the value of such claims. A provision for such business economic loss claims will be established when these uncertainties are resolved and a reliable estimate can be made of the liability.

 

The current estimate for the total cost of those elements of the PSC settlement that BP considers can be reliably estimated, including amounts already paid, is $11.3 billion. The Deepwater Horizon Court Supervised Settlement Program (DHCSSP) has issued eligibility notices, many of which are disputed by BP, in respect of business economic loss claims of approximately $415 million which have not been provided for. The total cost of the PSC settlement is likely to be significantly higher than the amount recognized to date of $11.3 billion because the current estimate does not reflect business economic loss claims not yet processed or processed but not yet paid, except where an eligibility notice has been issued and is not subject to appeal by BP within the claims facility.

 

 

Top of page 22

Financial statements (continued)

 

Notes

 

2.       Gulf of Mexico oil spill (continued)

 

There continues to be a high level of uncertainty in relation to the amounts that ultimately will be paid in relation to current claims as described above and in Legal proceedings on page 35 and the outcomes of any further litigation including by parties excluded from, or parties who opted out of, the PSC settlement, as well as uncertainty arising from the PSC's appeal to the Fifth Circuit of the District Court's 31 March 2015 decision to deny its motion seeking to alter or amend the revised matching policy for business economic loss claims. There is also uncertainty as to the cost of administering the claims process under the DHCSSP and in relation to future legal costs. The timing of payment of provisions related to the PSC settlement is dependent upon ongoing claims facility activity and is therefore also uncertain.

 

Litigation and claims - other claims

The provision recognized for litigation and claims includes amounts agreed under the Agreements in Principle in relation to state claims and amounts in respect of local government claims. The amount provided in respect of state claims is payable over 18 years from the date the court approves the Consent Decree, of which $1 billion is due following the court approval of the Consent Decree. BP advised the Court that it is satisfied with and has accepted releases received from the vast majority of local government entities. Accordingly, on 27 July, the District Court ordered BP to commence processing payments required under the releases and that such payments be made within 30 days of the Court's order. As part of the Agreements in Principle, BP agreed to pay up to $1 billion to resolve claims made by local government entities.

 

See Legal proceedings on page 35 for further details.

 

Clean Water Act penalties

A provision has been recognized for penalties under Section 311 of the Clean Water Act, as agreed in the Agreements in Principle. The penalty is payable in instalments over 15 years, commencing one year after the court approves the Consent Decree and execution of the associated agreements. The unpaid balance of this penalty accrues interest at a fixed rate.

 

Provision movements and analysis of income statement charge

A net increase in provisions of $10,663 million and $10,958 million was recognized for the second quarter and half year respectively. The second-quarter net increase arises primarily due to increases in provisions of $9.8 billion in relation to the Agreements in Principle. The remainder of the income statement charge relates to net increases in the litigation and claims provision for business economic loss claims, associated claims administration costs and other items. The net increase for the first half also includes additional increases in business economic loss claim provisions arising in the first quarter. The following table shows an analysis of the income statement charge.

 







$ million 



Environmental costs


5,503

8,726


Spill response costs


-

14,304


Litigation and claims costs


4,814

31,594


Clean Water Act penalties - amount provided


700

4,210


Other costs charged directly to the income statement


53

1,310


Recoveries credited to the income statement


-

(5,681)


Charge (credit) related to the trust fund


-

(137)


Other costs of the trust fund


-

8


Loss before interest and taxation


11,070

54,334


Finance costs

- related to the trust funds


-

137



- not related to the trust funds


17

111


Loss before taxation


11,087

54,582

 

Further information on provisions is provided in BP Annual Report and Form 20-F 2014 - Financial statements - Note 2.

 

 

Top of page 23

 

Financial statements (continued)

 

Notes

 

2.       Gulf of Mexico oil spill (continued)

 

Contingent liabilities

 

BP currently considers that it is not possible to measure reliably other obligations arising from the incident, including:

 

·     Claims asserted in civil litigation, including any further litigation by parties excluded from, or parties who opted out of, the PSC settlement, including as set out in Legal proceedings on pages 228-237 of BP Annual Report and Form 20-F 2014 and page 35 of this report, except for claims covered by the Agreements in Principle.

 

·     The cost of business economic loss claims under the PSC settlement not yet processed or processed but not yet paid (except where an eligibility notice has been issued and is not subject to appeal by BP within the claims facility).

 

·     Any obligation that may arise from securities-related litigation.

 

·     Any obligation in relation to other potential private or non-US government litigation or claims (except for those items provided for as described above under Provisions).

 

It is not practicable to estimate the magnitude or possible timing of payment of these contingent liabilities.

 

As a result of the Agreements in Principle, contingent liabilities are no longer disclosed in relation to Clean Water Act penalties, natural resource damages and state claims and the vast majority of local claims. See additional information on the Agreements in Principle above and in Legal proceedings on page 35.

 

The magnitude and timing of all possible obligations in relation to the Gulf of Mexico oil spill continue to be subject to uncertainty.

 

See also BP Annual Report and Form 20-F 2014 - Financial statements - Note 2.

 

 

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

 










$ million



4,049

372


Upstream


8,708


933

2,083


Downstream


1,727


1,024

183


Rosneft


1,542


(434)

(308)


Other businesses and corporate


(931)


5,572

2,330




11,046


(251)

(323)


Gulf of Mexico oil spill response


(280)


(76)

(129)


Consolidation adjustment - UPII*


14


5,245

1,878


RC profit (loss) before interest and tax


10,780





Inventory holding gains (losses)*




(1)

18


  Upstream


(7)


233

700


  Downstream


310


26

38


  Rosneft (net of tax)


57


5,503

2,634


Profit (loss) before interest and tax


11,140


277

281


Finance costs


564





Net finance expense relating to pensions




79

77


  and other post-retirement benefits


159


5,147

2,276


Profit (loss) before taxation


10,417















RC profit (loss) before interest and tax*





1,643

(497)


US


2,768


3,602

2,375


Non-US


8,012


5,245

1,878




10,780

 

 

Top of page 24

Financial statements (continued)

 

Notes

 

4.        Sales and other operating revenues

 










$ million







By segment



16,739

11,630


Upstream


33,745


86,871

48,125


Downstream


171,169


412

428


Other businesses and corporate


843


104,022

60,183




205,757












Less: sales and other operating revenues







  between segments




9,729

5,563


Upstream


18,946


152

176


Downstream


714


184

248


Other businesses and corporate


430


10,065

5,987




20,090












Third party sales and other operating revenues




7,010

6,067


Upstream


14,799


86,719

47,949


Downstream


170,455


228

180


Other businesses and corporate


413





Total third party sales and other operating




93,957

54,196


  revenues


185,667












By geographical area




35,507

18,841


US


70,332


67,303

38,688


Non-US


133,608


102,810

57,529




203,940





Less: sales and other operating revenues




8,853

3,333


  between areas


18,273


93,957

54,196




185,667

 

 

5.      Production and similar taxes

 










$ million



215

34


US


494


601

328


Non-US


1,308


816

362




1,802

 

 

6.        Earnings per share and shares in issue

 

Basic earnings per ordinary share (EpS) amounts are calculated by dividing the profit for the period attributable to ordinary shareholders by the weighted average number of ordinary shares outstanding during the period.

 

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.

 

 

Top of page 25

Financial statements (continued)

 

Notes

 

6.        Earnings per share and shares in issue (continued)

 

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.

 










$ million







Results for the period








Profit (loss) for the period attributable




3,369

2,602


  to BP shareholders


6,897


1

-


Less: preference dividend


1





Profit (loss) attributable to BP




3,368

2,602


  ordinary shareholders


6,896












Number of shares (thousand)(a)(b)







Basic weighted average number of




18,440,909

18,220,486


  shares outstanding


18,460,787


3,073,484

3,036,747


ADS equivalent


3,076,797












Weighted average number of shares







  outstanding used to calculate




18,556,789

18,309,730


  diluted earnings per share


18,580,165


3,092,798

3,051,621


ADS equivalent


3,096,694









18,435,266

18,249,422


Shares in issue at period-end


18,435,266


3,072,544

3,041,570


ADS equivalent


3,072,544

 

(a)

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

(b)

If the inclusion of potentially issuable shares would decrease loss per share, the potentially issuable shares are excluded from the weighted average number of shares outstanding used to calculate diluted earnings per share.

 

 

7.        Dividends

 

Dividends payable

 

BP today announced an interim dividend of 10.00 cents per ordinary share which is expected to be paid on 18 September 2015 to shareholders and American Depositary Share (ADS) holders on the register on 7 August 2015. The corresponding amount in sterling is due to be announced on 8 September 2015, calculated based on the average of the market exchange rates for the four dealing days commencing on 2 September 2015. Holders of ADSs are expected to receive $0.600 per ADS (less applicable fees). A scrip dividend alternative is available, allowing shareholders to elect to receive their dividend in the form of new ordinary shares and ADS holders in the form of new ADSs. Details of the second-quarter dividend and timetable are available at bp.com/dividends and details of the scrip dividend programme are available at bp.com/scrip.

 

Dividends paid

 

















Dividends paid per ordinary share



9.750

10.000


  cents


19.250


5.807

6.670


  pence


11.514


58.50

60.00


Dividends paid per ADS (cents)


115.50





Scrip dividends




26.5

15.7


Number of shares issued (millions)


66.7


225

109


Value of shares issued ($ million)


551

 

 

Top of page 26

Financial statements (continued)

 

Notes

 

8.       Net debt*

 

Net debt ratio*

 










$ million



52,906

57,731


Gross debt


52,906





Fair value (asset) liability of hedges related




(1,001)

(174)


  to finance debt(a)


(1,001)


51,905

57,557




51,905


27,506

32,434


Less: cash and cash equivalents


27,506


24,399

25,123


Net debt


24,399


132,978

111,509


Equity


132,978


15.5%

18.4%


Net debt ratio


15.5%

 

Analysis of changes in net debt

 










$ million







Opening balance



53,249

52,854


Finance debt


48,192





Fair value (asset) liability of hedges




(633)

(445)


  related to finance debt(a)


(477)


27,358

29,763


Less: cash and cash equivalents


22,520


25,258

22,646


Opening net debt


25,195





Closing balance




52,906

57,731


Finance debt


52,906





Fair value (asset) liability of hedges




(1,001)

(174)


  related to finance debt(a)


(1,001)


27,506

32,434


Less: cash and cash equivalents


27,506


24,399

25,123


Closing net debt


24,399


859

(2,477)


Decrease (increase) in net debt


796





Movement in cash and cash equivalents




99

3,294


  (excluding exchange adjustments)


4,982





Net cash outflow (inflow) from financing




921

(6,206)


  (excluding share capital and dividends)


(3,898)


(276)

11


Other movements


(394)





Movement in net debt before




744

(2,901)


  exchange effects


690


115

424


Exchange adjustments


106


859

(2,477)


Decrease (increase) in net debt


796

 

(a)

Derivative financial instruments entered into for the purpose of managing interest rate and foreign currency exchange risk associated with net debt with a fair value liability position of $1,357 million (first quarter 2015 liability of $1,650 million and second quarter 2014 asset of $1 million) are not included in the calculation of net debt shown above as hedge accounting was not applied for these instruments.

 

 

9.     Inventory valuation

 

A provision of $590 million was held at 30 June 2015 ($797 million at 31 March 2015 and $468 million at 30 June 2014) to write inventories down to their net realizable value. The net movement credited to the income statement during the second quarter 2015 was $210 million (first quarter 2015 was a credit of $2,024 million and second quarter 2014 was a charge of $59 million).

 

 

 

Top of page 27

Financial statements (continued)

 

Notes

 

10.    Statutory accounts

 

The financial information shown in this publication, which was approved by the Board of Directors on 27 July 2015, is unaudited and does not constitute statutory financial statements. BP Annual Report and Form 20-F 2014 has been filed with the Registrar of Companies in England and Wales. The report of the auditor on those accounts was unqualified and contained an emphasis of matter paragraph relating to significant uncertainty over provisions and contingencies related to the Gulf of Mexico oil spill. The report of the auditor on those accounts 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 and acquisitions

 







$ million






By segment







Upstream




1,435

1,135


US


3,133

3,351

2,896


Non-US(a)(b)


7,050

4,786

4,031




10,183




Downstream



232

145


US


438

378

199


Non-US


722

610

344




1,160




Other businesses and corporate



13

16


US


16

204

74


Non-US


339

217

90




355

5,613

4,465




11,698




By geographical area



1,680

1,296


US


3,587

3,933

3,169


Non-US(a)(b)


8,111

5,613

4,465




11,698




Included above:



10

28


Acquisitions and asset exchanges


246

-

-


Other inorganic capital expenditure(a)(b)


442

 

(a)

First half 2014 includes $442 million relating to the purchase of additional 3.3% equity in Shah Deniz, Azerbaijan and the South Caucasus Pipeline.

(b)

Second quarter and first half 2015 includes a $150-million deposit paid relating to the agreed purchase of a 20% participatory interest in Taas-Yuryakh Neftegazodobycha, a Rosneft subsidiary.

 

Capital expenditure shown in the table above is presented on an accruals basis.

 

 

Top of page 29

Additional information (continued)

 

Non-operating items*

 







$ million






Upstream






Impairment and gain (loss) on sale of businesses and



(527)

(113)


  fixed assets


(643)

-

11


Environmental and other provisions


-

-

(181)


Restructuring, integration and rationalization costs


-

32

41


Fair value gain (loss) on embedded derivatives


130

(21)

-


Other


273

(516)

(242)




(240)




Downstream






Impairment and gain (loss) on sale of businesses and



79

66


  fixed assets


(176)

-

-


Environmental and other provisions


-

(1)

(28)


Restructuring, integration and rationalization costs


(2)

-

-


Fair value gain (loss) on embedded derivatives


-

(28)

(1)


Other


(50)

50

37




(228)




Rosneft






Impairment and gain (loss) on sale of businesses and



-

-


  fixed assets


247

-

-


Environmental and other provisions


-

-

-


Restructuring, integration and rationalization costs


-

-

-


Fair value gain (loss) on embedded derivatives


-

-

-


Other


-

-

-




247




Other businesses and corporate






Impairment and gain (loss) on sale of businesses and



4

(12)


  fixed assets


(2)

-

-


Environmental and other provisions


-

-

(6)


Restructuring, integration and rationalization costs


(1)

-

-


Fair value gain (loss) on embedded derivatives


-

-

-


Other


(1)

4

(18)




(4)

(251)

(323)


Gulf of Mexico oil spill response


(280)

(713)

(546)


Total before interest and taxation


(505)

(9)

(9)


Finance costs(a)


(19)

(722)

(555)


Total before taxation


(524)

241

142


Taxation credit (charge)


267

(481)

(413)


Total after taxation for period


(257)

 

(a)

Finance costs relate to the Gulf of Mexico oil spill. See Note 2 for further details.

 

 

Top of page 30

Additional information (continued)

 

Non-GAAP information on fair value accounting effects

 







$ million






Favourable (unfavourable) impact relative to






  management's measure of performance



(90)

10


Upstream


(108)

150

(112)


Downstream


211

60

(102)




103

(32)

41


Taxation credit (charge)


(49)

28

(61)




54

 

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

 

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

 

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

 







$ million






Upstream








Replacement cost profit before interest and tax




4,139

362


  adjusted for fair value accounting effects


8,816

(90)

10


Impact of fair value accounting effects


(108)

4,049

372


Replacement cost profit before interest and tax


8,708





Downstream








Replacement cost profit before interest and tax




783

2,195


  adjusted for fair value accounting effects


1,516

150

(112)


Impact of fair value accounting effects


211

933

2,083


Replacement cost profit before interest and tax


1,727




Total group






Profit (loss) before interest and tax adjusted for



5,443

2,736


  fair value accounting effects


11,037

60

(102)


Impact of fair value accounting effects


103

5,503

2,634


Profit (loss) before interest and tax


11,140

 

 

Top of page 31

Additional information (continued)

 

Realizations and marker prices

 













Average realizations(a)








Liquids* ($/bbl)




89.61

46.24


US


89.71

101.43

52.28


Europe


102.88

103.37

46.13


Rest of World


103.04

96.90

46.79


BP Average


97.03




Natural gas ($/mcf)



3.86

2.39


US


4.23

8.07

7.32


Europe


8.99

6.31

5.05


Rest of World


6.47

5.67

4.44


BP Average


5.94




Total hydrocarbons* ($/boe)



63.83

33.20


US


64.74

88.22

49.35


Europe


90.61

62.89

37.41


Rest of World


62.83

64.90

37.00


BP Average


65.53




Average oil marker prices ($/bbl)



109.67

53.94


Brent


108.93

103.05

48.49


West Texas Intermediate


100.90

82.66

36.69


Western Canadian Select


79.86

108.05

51.95


Alaska North Slope


106.91

100.70

49.15


Mars


100.76

107.30

52.59


Urals (NWE - cif)


106.76




Average natural gas marker prices



4.68

2.99


Henry Hub gas price ($/mmBtu)(b)


4.81

44.81

47.90


UK Gas - National Balancing Point (p/therm)


52.67

 

(a)

Based on sales of consolidated subsidiaries only - this excludes equity-accounted entities.

(b)

Henry Hub First of Month Index.

 

 

Exchange rates

 









1.68

1.51


$/£ average rate for the period


1.67

1.70

1.48


$/£ period-end rate


1.70







1.37

1.12


$/€ average rate for the period


1.37

1.36

1.08


$/€ period-end rate


1.36









34.96

63.03


Rouble/$ average rate for the period


35.02

33.73

57.79


Rouble/$ period-end rate


33.73

 

 

Top of page 32

Glossary

 

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

 

Fair value accounting effects are non-GAAP adjustments to our IFRS profit (loss) relating to certain physical inventories, pipelines and storage capacity. Management uses a fair-value basis to value these items which, under IFRS, are accounted for on an accruals basis with the exception of trading inventories, which are valued using spot prices. The adjustments have the effect of aligning the valuation basis of the physical positions with that of any associated derivative instruments, which are required to be fair valued under IFRS, in order to provide a more representative view of the ultimate economic value. Further information and a reconciliation to GAAP information is provided on page 30.

 

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

 

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 comprises crude oil, condensate and natural gas liquids.

 

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'.

 

Net wind generation capacity is the sum of the rated capacities of the assets/turbines that have entered into commercial operation, including BP's share of equity-accounted entities. The gross data is the equivalent capacity on a gross-JV basis, which includes 100% of the capacity of equity-accounted entities where BP has partial ownership.

 

Non-operating items are charges and credits included in the financial statements that BP discloses separately because it considers such disclosures to be meaningful and relevant to investors. They are items that management considers not to be part of underlying business operations and are disclosed in order to enable investors better to understand and evaluate the group's reported financial performance. Non-operating items within equity-accounted earnings are reported net of incremental income tax reported by the equity-accounted entity. An analysis of non-operating items by region is shown on pages 5, 7 and 9, and by segment and type is shown on page 29.

 

Organic capital expenditure excludes acquisitions, asset exchanges, and other inorganic capital expenditure. An analysis of capital expenditure by segment and region is shown on page 28.

 

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

 

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

 

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

 

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

 

 

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Glossary (continued)

 

Replacement cost (RC) profit or loss reflects the replacement cost of inventories sold in the period and is arrived at by excluding inventory holding gains and losses from profit or loss. RC profit or loss is the measure of profit or loss that is required to be disclosed for each operating segment under International Financial Reporting Standards (IFRS). RC profit or loss for the group is not a recognized GAAP measure. Management 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.

 

Underlying production is production after adjusting for 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 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 for the year attributable to BP shareholders. The nearest equivalent measure on an IFRS basis for segments is RC profit or loss before interest and taxation.

 

 

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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 2014 (pages 48-50) and are summarized below. Other than the developments referred to under the heading Gulf of Mexico oil spill, 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.

 

Gulf of Mexico oil spill

·      On 2 July 2015 BP Exploration & Production Inc. signed agreements in principle to settle all federal and state claims, and claims made by more than 400 local government entities, arising from the oil spill. These agreements are subject to the execution of definitive agreements and court approval of the Consent Decree relating to such settlement. For further details, including items not covered by the agreements in principle, see Legal proceedings (Agreements in principle) on page 35. There continues to be uncertainty regarding the extent and timing of the remaining costs and liabilities relating to the 2010 Gulf of Mexico oil spill not covered by the agreements in principle.  

 

Strategic and commercial risks

·      Prices and markets - our financial performance is subject to fluctuating prices of oil, gas, refined products, 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 - we are exposed to a range of political developments and consequent changes to the operating and regulatory environment.

·      Rosneft investment - our investment in Rosneft may be impacted by events in or relating to Russia.

·      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 - we may have limited control over the standards, operations and compliance of our partners, contractors and sub-contractors.

·      Digital infrastructure and cybersecurity - breach of our digital security or failure of our digital infrastructure could damage our operations and our reputation.

·      Climate change and carbon pricing - public policies could increase costs and reduce future revenue and strategic growth opportunities.

·      Competition - inability to remain efficient, innovate and retain an appropriately skilled workforce could negatively impact delivery of our strategy in a highly competitive market.

·      Crisis management and business continuity - potential disruption to our business and operations could occur if we do not address an incident effectively.

·      Insurance - our insurance strategy could expose the group to material uninsured losses.

 

Safety and operational risks

·      Process safety, personal safety, and environmental risks - we are exposed to a wide range of health, safety, security and environmental risks that could result in regulatory action, legal liability, 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 potentially impact our financial performance.

 

Compliance and control risks

·      US government settlements - our settlements with legal and regulatory bodies in the US announced in November 2012 in respect of certain charges related to the Gulf of Mexico oil spill may expose us to further penalties, liabilities and private litigation 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 exploration opportunities.

·      Ethical misconduct and non-compliance - ethical misconduct or breaches of applicable laws by our businesses or our employees could damage 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.

 

 

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Legal proceedings

 

The following discussion sets out the material developments in the group's material legal proceedings during the half year 2015. For a full discussion of the group's material legal proceedings, see pages 228-238 of BP Annual Report and Form 20-F 2014.

 

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

 

Agreements in principle

On 2 July 2015, BP announced that BP Exploration & Production Inc. (BPXP) has executed agreements in principle with the United States federal government and five Gulf Coast states to settle all federal and state claims arising from the Incident. The agreement with the states of Alabama, Florida, Louisiana, Mississippi and Texas also provides for the settlement of claims made by more than 400 local government entities.

 

The principal payments are as follows:

 

·      BPXP is to pay the United States a civil penalty of $5.5 billion under the Clean Water Act (CWA) - payable over 15 years.

·      BPXP will pay $7.1 billion to the United States and the five Gulf states over 15 years for natural resource damages (NRD). This is in addition to the $1 billion already committed for early restoration. BPXP will also set aside an additional amount of $232 million to be added to the NRD interest payment at the end of the payment period to cover any further natural resource damages that are unknown at the time of the agreement.

·      A total of $4.9 billion will be paid over 18 years to settle economic and other claims made by the five Gulf states.

·      Up to $1 billion will be paid to resolve claims made by local government entities.

 

NRD and CWA payments are scheduled to start 12 months after the agreements become final. Total payments for NRD, CWA and State claims will be made at a rate of around $1.1 billion a year for the majority of the payment period.

 

The agreements in principle are subject to execution of definitive agreements. These will comprise a Consent Decree with the United States and Gulf states with respect to the civil penalty and natural resource damages, a settlement agreement with the five Gulf states with respect to State and local claims for economic and property losses, and release agreements with local government entities.

 

The Consent Decree will be subject to public comment and final court approval. The Consent Decree and settlement agreement with the Gulf states are conditional upon each other and neither will become effective unless (1) there is final court approval of the Consent Decree and (2) local government entities execute releases to BP's satisfaction. BP advised the Court that it is satisfied with and has accepted releases received from the vast majority of local government entities. Accordingly, on 27 July, the District Court ordered BP to commence processing payments required under the releases and that such payments be made within 30 days of the Court's order. The agreements in principle do not cover the remaining costs of the 2012 class action settlements with the Plaintiffs' Steering Committee for economic and property damage and medical claims. They do not cover claims by individuals and businesses that opted out of the 2012 settlements and/or whose claims were excluded from them, including claims for recovery of losses allegedly resulting from the 2010 federal deepwater drilling moratoria and/or the related permitting processes. The agreements in principle also do not resolve private securities litigation pending in MDL 2185.

 

Interest will accrue at a fixed rate on the unpaid balance of the civil penalty and NRD payments, compounded annually and payable in years 15 (CWA) and 16 (NRD). To address possible natural resource damages unknown at the time of the settlement, beginning 10 years after the settlement, the federal government and the Gulf states may request accelerated payment of accrued but unpaid interest on the NRD payments.

 

Parent company guarantees for these payments will be provided by BP Corporation North America Inc. as the primary guarantor and BP p.l.c. as the secondary guarantor.

 

The federal government and the Gulf states may jointly elect to accelerate the civil penalty and NRD payments in the event of a change of control or insolvency of BP p.l.c.

 

In addition to these agreed settlement payments, BPXP has also agreed to pay $350 million to cover outstanding NRD assessment costs and $250 million to cover the full settlement of outstanding response costs, claims related to the False Claims Act and royalties owed for the Macondo well. These additional payments will be paid over nine years, beginning in 2015.

 

Federal multi-district litigation proceeding in New Orleans (MDL 2179) and related matters

US Department of Justice (DoJ) Action - Liability under Section 311(b)(7)(A) of the Clean Water Act. As previously disclosed, in February 2012, the federal district court in New Orleans (the District Court) held that the subsurface discharge which occurred during the Incident was from the Macondo well, rather than from the Deepwater Horizon vessel, and that BPXP and Anadarko Petroleum Company (Anadarko), and not Transocean Ltd. (Transocean), were liable for civil penalties under the Clean Water Act as owners of the well. On 27 June 2015, the US Supreme Court denied BPXP's and Anadarko's petitions for certiorari seeking review of the US Court of Appeals for the Fifth Circuit (the Fifth Circuit)'s order denying a rehearing of BPXP's and Anadarko's appeal.

 

 

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Legal proceedings (continued)

 

Trial Phases. As previously disclosed, on 4 September 2014, the District Court issued its ruling for Phase 1 of the trial in MDL 2179. BPXP and BP America Production Company (BPAPC) and other parties filed notices of appeal of the Phase 1 ruling to the Fifth Circuit. On 16 July 2015 the United States, with the consent of the other parties, filed a motion to hold the Phase 1 appeal in abeyance while the parties work towards finalizing the settlements under the 2 July 2015 agreements in principle. This motion was granted by the Fifth Circuit on 22 July 2015.

 

On 15 January 2015, the District Court issued its ruling for Phase 2 of MDL 2179. The District Court found that 3.19 million barrels of oil were discharged into the Gulf of Mexico and are therefore subject to a Clean Water Act penalty and that BP was not grossly negligent in its source control efforts. On 28 May 2015, both BPXP and the United States voluntarily dismissed the appeals of the Phase 2 ruling that they had made to the Fifth Circuit (without prejudice to their rights to appeal after the decision in the penalty phase). Other parties have also appealed the Phase 2 ruling but at the parties' request the Fifth Circuit has ordered that the appeal be held in abeyance until resolution of the Phase 1 appeal.

 

Trial in the penalty phase of MDL 2179 (the Penalty Phase) concluded on 2 February 2015. The Penalty Phase involved consideration of the amount of CWA civil penalties owed to the United States. Post-trial briefing concluded on 24 April 2015.

 

As discussed above, on 2 July 2015, BP announced an agreement in principle with the United States to settle the United States' claims against BPXP for CWA penalties.

 

Plaintiffs' Steering Committee (PSC) Settlements - Deepwater Horizon Court Supervised Settlement Program (DHCSSP) and interpretation of the Economic and Property Damages (EPD) Settlement Agreement. On 24 December 2013, the District Court issued a ruling that, amongst other things, directed the claims administrator, in administering business economic loss claims, to match revenue with corresponding variable expenses. On 13 March 2014, the claims administrator issued a revised matching policy reflecting this order, which was approved by the District Court. The PSC filed a motion on 27 May 2014 seeking to alter or amend the revised policy. This motion was denied by the District Court on 31 March 2015 and, on 23 April 2015, the PSC appealed this decision to the Fifth Circuit.

 

On 6 March 2015, BP gave notice that it was not proceeding with the appeal against the decision of the District Court in November 2014 denying BP's motion seeking an order removing Patrick Juneau from his role as claims administrator and settlement trustee for the EPD settlement.

 

On 8 May 2015, the Fifth Circuit upheld three awards to non-profit entities issued under the EPD Settlement, each of which was premised on an official policy that typically treated grant monies and contributions to non-profit entities as revenue for purposes of the settlement agreement's calculations. BP argued that this policy was inconsistent with the language of the settlement agreement and would place the agreement in violation of United States law, but the Fifth Circuit upheld the policy and determined that the District Court did not otherwise abuse its discretion in denying review of the three awards.

 

The deadline for filing all claims under the EPD Settlement other than those that fall into the Seafood Compensation Program was 8 June 2015.

 

For information about BP's current estimate of the total cost of the PSC settlements, see Note 2 on page 18.

 

Medical Benefits Class Action Settlement (Medical Settlement). The deadline for submitting claims under the Medical Settlement Agreement (MSA) for Specified Physical Conditions (SPCs) and under the Periodic Medical Consultation Program (PMCP) was 12 February 2015. There was an increased volume of SPC and PMCP claims filings at and around the bar date. The total number of claims estimated by the MSA claims administrator is approximately 37,000. To date, approximately 2,000 SPC claims, totalling approximately $5 million, have been approved for compensation. In addition, approximately 11,200 claimants have been determined eligible for the PMCP. Given the District Court's decision to classify all physical conditions first diagnosed after 16 April 2012 as Later-Manifested Physical Conditions (LMPC), class members must pursue compensation for LMPCs by submitting a Notice of Intent to Sue (NOIS) under the Back-End Litigation Option (BELO). As of 9 July 2015, 19 compliant NOISs have been received by the MSA claims administrator, four of which have resulted in pending BELO lawsuits. On 27 April 2015, the District Court issued an order allowing for jury trials for certain medical settlement claims for BELO plaintiffs.

 

State and local civil claims, including under the Oil Pollution Act of 1990 (OPA 90) - State of Alabama Damages Case Proceedings. On 19 April 2013, the State of Alabama filed an action against BP alleging general maritime law claims of negligence, gross negligence, and wilful misconduct; claims under OPA 90 seeking damages for removal costs, natural resource damages, property damage, lost tax and other revenue and damages for providing increased public services during or after removal activities; and various state law claims. On 14 February 2014, BP moved to strike the State of Alabama's jury trial demand as to its claim for compensatory damages under OPA 90. On 30 March 2015, the District Court denied BP's motion and on 29 April 2015 the District Court denied BP's motion to certify the ruling for appeal to the Fifth Circuit. On 16 March 2015 the District Court issued an amended scheduling order for the State of Alabama's claims against BP and other parties under which the pre-trial matters will be concluded in April 2016. On 2 July 2015, however, the court suspended all discovery obligations and court-scheduled events in the Alabama action in view of the 2 July 2015 agreements in principle between BPXP and the United States and five Gulf states.

 

 

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Legal proceedings (continued)

 

Halliburton and Transocean Settlements. On 20 May 2015, BP and Transocean, and BP and Halliburton Energy Services Inc. (Halliburton), entered into confidential settlement agreements to resolve the final remaining disputes between these parties stemming from the Incident.

 

Under the agreement with Transocean, BPXP and BPAPC agreed to indemnify Transocean for compensatory damages (including natural resource damages), to pay Transocean $125 million in compensation for incurred legal fees, and discontinue attempts to recover as an additional insured under Transocean's liability policies. Transocean will indemnify BPXP and BPAPC for the personal and bodily injury claims of Transocean employees, as well as for claims relating to any future cleanup or removal of diesel or other pollutants stored on the Deepwater Horizon. Finally, BPXP and BPAPC, and Transocean will mutually release all claims between the companies.

 

BPXP's agreement with Halliburton resolves the remaining claims between the two companies and includes indemnities and the dismissal of all claims against each other.

 

Non-US government lawsuits. On 1 May 2015, the Fifth Circuit affirmed the District Court's 12 September 2013 judgment dismissing with prejudice the claims brought in September 2010 by three Mexican states bordering the Gulf of Mexico against several BP entities.

 

MDL 2185 and other securities-related litigation

Canadian Class Action. On 26 March 2015, the Supreme Court of Canada dismissed the plaintiff's appeal to the August 2014 decision by the Ontario Court of Appeal which held that claims made on behalf of Canadian residents who purchased BP ordinary shares and ADSs on exchanges outside of Canada should be litigated in those countries, and that only claims asserted on behalf of Canadian residents who purchased ADSs on the Toronto Stock Exchange could be litigated in Canada. On 27 March 2015, the plaintiff filed a complaint in Texas federal court asserting claims under Canadian law against BP on behalf of a class of Canadian residents who allegedly suffered losses because of their purchase of BP ADSs on the New York Stock Exchange. That action has been transferred to the judge presiding over MDL 2185, and on 16 June 2015, BP moved to dismiss the action.

 

Other legal proceedings

Scharfstein v. BP West Coast Products, LLC. A purported 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's Oregon sites failed to provide sufficient notice of the 35 cents per transaction debit card fee. After a jury trial and subsequent hearing, in 2014 the jury rendered a verdict against BP and determined that statutory damages of $200 per class member should be awarded. A post-trial claims process in late 2014 identified approximately 1.7 million class members, subject to final determination. BP intends to appeal. No provision has been made for damages arising out of this class action.

 

 

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Cautionary statement

 

Cautionary statement regarding forward-looking statements: The discussion in this results announcement contains certain forecasts, projections and forward-looking statements - that is, statements related to future, not past events - with respect to the financial condition, results of operation 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, among other statements, plans regarding the divestment of $10 billion in assets by the end of 2015; expectations regarding restructuring charges; the expected quarterly dividend payment and timing of such payment; expectations regarding organic capital expenditure for full year 2015; plans and expectations regarding future development and exploration in Siberia; plans regarding TANAP and BP's interest therein; plans and expectations regarding Upstream projects announced with BP's first-quarter results; expectations regarding drilling operations in Libya; expectations regarding the level of reported production for third quarter 2015; expectations regarding third quarter refining margins and level of turnaround activity; expectations regarding the new plant in Zhuhai, China; expectations regarding Rosneft reporting; expectations with respect to finalizing the definitive agreements, including the Consent Decree with the United States and the Gulf states, timing of and expectations regarding court approval, the timing of payments under the agreement and financial impact of the settlement on BP and certain statements regarding the legal and trial proceedings, court decisions, claims, penalties and civil actions by government entities and/or other entities or parties, the risks associated with such proceedings; are all forward looking in nature. 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; the timing and amount of future 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, including under "Principal risks and uncertainties", and under "Risk factors" in BP Annual Report and Form 20-F 2014 as filed with the US Securities and Exchange Commission.

 

Notice to investors: BP has received written comments from the US Securities and Exchange Commission regarding its Form 20-F for the fiscal year ended 31 December 2014 in a letter dated 22 May 2015.

 

Contacts

 

London

United States




Press Office

David Nicholas

Scott Dean


+44 (0)20 7496 4708

+1 630 420 4990




Investor Relations

Jessica Mitchell

Craig Marshall

bp.com/investors

+44 (0)20 7496 4962

+1 281 366 3123

 

 

 

 


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