1Q13 Part 1 of 1

RNS Number : 5344D
BP PLC
30 April 2013
 

 



BP p.l.c.

Group results

First quarter 2013

 

 

Top of page 1

FOR IMMEDIATE RELEASE                                    London 30 April 2013                      


 


First

Fourth

First



quarter

quarter

quarter

$ million


2013

2012

2012

Profit for the period(a)


16,863

1,488

 5,767

Inventory holding (gains) losses, net of tax


(267)

 521

(986)

Replacement cost profit(b)


16,596

 2,009

 4,781

Net (favourable) unfavourable impact of non-operating items





  and fair value accounting effects, net of tax(c)


(12,381)

 1,843

(130)

Underlying replacement cost profit(b)


4,215

 3,852

 4,651

Replacement cost profit





    per ordinary share (cents)


86.67

 10.53

 25.19

    per ADS (dollars)


 5.20

 0.63

 1.51

Underlying replacement cost profit





    per ordinary share (cents)


 22.01

 20.19

 24.51

    per ADS (dollars)


 1.32

 1.21

 1.47

 

·   BP's first-quarter replacement cost (RC) profit was $16,596 million, compared with $4,781 million for the same period in 2012. After adjusting for a net gain from non-operating items of $12,424 million and net unfavourable fair value accounting effects of $43 million (both on a post-tax basis), underlying RC profit for the first quarter was $4,215 million, compared with $4,651 million for the same period in 2012. 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 2, 17 and 19.

 

·   Non-operating items for the first quarter on a pre-tax basis amounted to a net gain of $12,401 million, primarily relating to the gain on disposal of our interest in TNK-BP. All amounts relating to the Gulf of Mexico oil spill have been treated as non-operating items, with a minimal net impact on the results this quarter. For further information on the Gulf of Mexico oil spill and its consequences see page 11, Note 2 on pages 23 - 27 and Legal proceedings on pages 32 - 33.

 

·   Including the impact of the Gulf of Mexico oil spill, net cash provided by operating activities for the first quarter was $4.0 billion, compared with $3.4 billion in the same period of 2012. Excluding amounts related to the Gulf of Mexico oil spill, net cash provided by operating activities for the first quarter was $4.3 billion, compared with $4.6 billion a year ago.

 

·   Net debt at the end of the quarter was $17.7 billion, compared with $31.0 billion a year ago, with the decrease driven primarily by a net cash inflow of $11.8 billion from the sale of our interest in TNK-BP to Rosneft. The ratio of net debt to net debt plus equity at the end of the quarter was 11.9% compared with 20.6% a year ago. Net debt and the ratio of net debt to net debt plus equity are non-GAAP measures. See page 3 for more information.

 

·   The effective tax rate (ETR) on replacement cost profit for the first quarter was 14%, compared with 34% for the same period in 2012. The low rate for the first quarter 2013 reflects the fact that the gain on disposal of TNK-BP is expected to be exempt from UK corporation tax under the provisions of the substantial shareholdings exemption introduced for UK companies in 2002. Adjusting for non-operating items and fair value accounting effects, the underlying ETR in the first quarter of 2013 was 39% compared with 33% in the first quarter of 2012. The increase was mainly due to a reduction in equity-accounted earnings (which are reported net of tax) as a result of the TNK-BP disposal.

 

·   Total capital expenditure for the first quarter was $17.7 billion, of which organic capital expenditure(d) was $5.7 billion, with the remainder relating to our investment in Rosneft (see below for further information). Disposal proceeds received in cash were $18.3 billion for the quarter.

 

·   Finance costs and net finance expense relating to pensions and other post-retirement benefits were a charge of $404 million for the first quarter, compared with $405 million for the same period in 2012.

 

·   On 21 March, BP and Rosneft completed transactions for the sale and purchase of BP's 50% interest in TNK-BP for $16.7 billion in cash and 12.84% of Rosneft shares. BP used $4.9 billion of the cash consideration to acquire 5.66% of Rosneft shares from Rosneftegaz. Together with its existing 1.25% shareholding in the company, BP now holds a 19.75% stake in Rosneft, Russia's largest oil company. See pages 9 and 28 for more information.

 

·   On 22 March, BP announced its intention to carry out a share repurchase programme with a total value of up to $8 billion over 12-18 months. As at 26 April, BP had bought back 120 million shares for a total amount of $834 million, including fees and stamp duty.

·   BP today announced a quarterly dividend of 9 cents per ordinary share ($0.54 per ADS), which is expected to be paid on 21 June 2013. The corresponding amount in sterling will be announced on 10 June 2013. 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 scrip dividend programme are available at bp.com/scrip.

 

(a)

Profit attributable to BP shareholders.

(b)

See page 2 for definitions of RC profit and underlying RC profit.

(c)

See pages 18 and 19 respectively for further information on non-operating items and fair value accounting effects.

(d)

Organic capital expenditure excludes acquisitions, asset exchanges, and other inorganic capital expenditure. See page 16 for further information.

The commentaries above and following are based on RC profit and should be read in conjunction with the cautionary statement on page 34.

 

 

Top of page 2

Analysis of RC profit before interest and tax

 and reconciliation to profit for the period

 


First

Fourth

First

$ million


quarter

quarter

quarter

RC profit before interest and tax


2013

2012

2012

  Upstream


 5,562

 7,688

 6,983

  Downstream


 1,647

 1,329

 859

  TNK-BP(a)


 12,500

 575

 1,064

  Rosneft(b)


 85

-   

-   

  Other businesses and corporate


(467)

(505)

(671)

  Gulf of Mexico oil spill response(c)


(22)

(4,126)

 30

  Consolidation adjustment - UPII(d)


 427

(428)

(541)

RC profit before interest and tax


 19,732

 4,533

 7,724

Finance costs and net finance expense relating to





  pensions and other post-retirement benefits


(404)

(467)

(405)

Taxation on a RC basis


(2,653)

(1,995)

(2,477)

Non-controlling interests


(79)

(62)

(61)

RC profit attributable to BP shareholders


 16,596

 2,009

 4,781

Inventory holding gains (losses)


 406

(766)

 1,437

Taxation (charge) credit on inventory holding gains and losses


(139)

 245

(451)

Profit for the period attributable to BP shareholders


 16,863

 1,488

 5,767

 

(a)

BP ceased equity accounting for its share of TNK-BP's earnings from 22 October 2012. See page 8 for further information.

(b)

BP's investment in Rosneft is accounted under the equity method from 21 March 2013. See page 9 for further information.

(c)

See Note 2 on pages 23 - 27 for further information on the accounting for the Gulf of Mexico oil spill response.

(d)

The consolidation adjustment - unrealized profit in inventory (UPII) - for the first quarter of 2013 was impacted by lower levels of equity crude within inventory in Europe and the US at the end of the period.

 

Replacement cost (RC) profit or loss reflects the replacement cost of supplies 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 for each operating segment that is required to be disclosed under International Financial Reporting Standards (IFRS). RC profit or loss for the group is not a recognized GAAP measure. See page 17 for further information on RC profit or loss.

 

 

Analysis of underlying RC profit before interest and tax

 


First

Fourth

First

$ million


quarter

quarter

quarter

Underlying RC profit before interest and tax


2013

2012

2012

  Upstream


 5,702

 4,375

 6,294

  Downstream


 1,641

 1,394

 927

  TNK-BP


- 

 224

 1,157

  Rosneft


 85

-   

-   

  Other businesses and corporate


(461)

(448)

(435)

  Consolidation adjustment - UPII


 427

(428)

(541)

Underlying RC profit before interest and tax


 7,394

 5,117

 7,402

Finance costs and net finance expense relating to





  pensions and other post-retirement benefits


(394)

(461)

(399)

Taxation on an underlying RC basis


(2,706)

(742)

(2,291)

Non-controlling interests


(79)

(62)

(61)

Underlying RC profit attributable to BP shareholders


 4,215

 3,852

 4,651

 

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. On pages 18 and 19 respectively, we provide 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.

 

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 - 10 for the segments.

 

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.

 

 

Top of page 3

Per share amounts

 


First

Fourth

First



quarter

quarter

quarter



2013

2012

2012

Per ordinary share (cents)





Profit for the period


 88.07

 7.80

 30.39

RC profit for the period


 86.67

 10.53

 25.19

Underlying RC profit for the period


 22.01

 20.19

 24.51

Per ADS (dollars)





Profit for the period


 5.28

 0.47

 1.82

RC profit for the period


 5.20

 0.63

 1.51

Underlying RC profit for the period


 1.32

 1.21

 1.47

 

The amounts shown above are calculated based on the basic weighted average number of shares outstanding. See Note 7 on page 30 for details of the calculation of earnings per share.

 

 

Net debt ratio - net debt: net debt + equity

 


First

Fourth

First



quarter

quarter

quarter



2013

2012

2012

$ million





Gross debt


 46,425

 48,800

 46,471

Less: fair value asset of hedges related to finance debt


 1,083

 1,700

 1,224



 45,342

 47,100

 45,247

Less: cash and cash equivalents


 27,679

 19,635

 14,267

Net debt


 17,663

 27,465

 30,980

Equity


 131,085

 119,752

 119,315 

Net debt ratio


11.9%

18.7%

20.6%

 

See Note 8 on page 31 for further details on finance debt.

 

Net debt and net debt ratio are non-GAAP measures. Net debt includes the fair value of associated derivative financial instruments that are used to hedge foreign exchange and interest rate risks relating to finance debt, for which hedge accounting is claimed. The derivatives are reported on the balance sheet within the headings 'Derivative financial instruments'. We believe that net debt and net debt ratio 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.

 

 

Dividends

 

Dividends payable

 

BP today announced a dividend of 9 cents per ordinary share expected to be paid in June. The corresponding amount in sterling will be announced on 10 June 2013, calculated based on the average of the market exchange rates for the four dealing days commencing on 4 June 2013. Holders of American Depositary Shares (ADSs) will receive $0.54 per ADS. The dividend is due to be paid on 21 June 2013 to shareholders and ADS holders on the register on 10 May 2013. 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 first-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

 


First

Fourth

First



quarter

quarter

quarter



2013

2012

2012

Dividends paid per ordinary share





    cents


 9.000

 9.000

 8.000

    pence


 6.001

 5.589

 5.096

Dividends paid per ADS (cents)


 54.00

 54.00

 48.00

Scrip dividends





Number of shares issued (millions)


 14.5

 72.7

 39.6

Value of shares issued ($ million)


 101

 498

 306

 

 

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Upstream

 


First

Fourth

First



quarter

quarter

quarter



2013

2012

2012

$ million





Profit before interest and tax


 5,560

 7,692

 6,899

Inventory holding (gains) losses


 2

(4)

 84

RC profit before interest and tax


 5,562

 7,688

 6,983

Net (favourable) unfavourable impact of non-operating items





  and fair value accounting effects


 140

(3,313)

(689)

Underlying RC profit before interest and tax(a)


 5,702

 4,375

 6,294

 

(a)

See page 2 for information on underlying RC profit and see page 5 for a reconciliation to segment RC profit before interest and tax by region.

 

The replacement cost profit before interest and tax for the first quarter was $5,562 million compared with $6,983 million for the same period in 2012. The first quarter included a net non-operating loss of $80 million, primarily relating to impairment charges, compared with a net gain of $822 million in the same period last year, which was mainly due to gains on disposals. In the first quarter, fair value accounting effects had an unfavourable impact of $60 million compared with an unfavourable impact of $133 million in the same period last year.

 

After adjusting for non-operating items and fair value accounting effects, the underlying replacement cost profit before interest and tax for the first quarter was $5,702 million, compared with $6,294 million in the same period last year. The result in the first quarter was impacted by lower production due to divestments and lower liquids realizations, partly offset by stronger gas marketing and trading activities.

 

Production for the quarter was 2,330mboe/d, 5% lower than the first quarter of 2012. After adjusting for the effects of divestments and entitlement impacts in our production-sharing agreements (PSAs), production increased by 1.6%. This primarily reflects major project delivery in Angola, the Gulf of Mexico, and the North Sea, and improved performance in Trinidad, partly offset by natural field decline across the portfolio.

 

Looking ahead we expect second quarter 2013 reported production to be lower than the first quarter, similar to the reduction we saw between the same periods last year, primarily as a result of planned major turnaround activity concentrated on higher margin assets in the Gulf of Mexico and the North Sea, and the continuing impact of our divestment programme mainly in the North Sea. We also expect costs to be higher in the second quarter compared with the first quarter, mainly due to seasonal turnaround activity.

 

We continued to make strategic progress. In January we announced the successful start-up of oil production from new facilities at the Valhall field in the southern part of the Norwegian North Sea. Production from Valhall is expected to continue to grow into the second half of 2013.

 

In February, we reached an agreement with Maersk Drilling to develop conceptual engineering designs for new advanced technology offshore drilling rigs which are intended to unlock the next frontier of deepwater oil and gas resources. The agreement is part of BP's Project 20KTM, a multi-year initiative to develop next-generation systems and tools for deepwater exploration and production.

 

In March, we announced that we have completed a successful flow test of the Itaipu-1A well offshore Brazil. The drill stem test was the latest activity in the ongoing appraisal programme at the BP-operated Itaipu discovery, indicating that commercially viable flow rates can be achieved from this pre-salt carbonate reservoir. The Itaipu-1A well is located in the deepwater sector of the Campos Basin, 125km offshore Brazil.

 

Also in March, together with our co-venturers, we announced the decision to proceed with a two-year appraisal programme to evaluate a potential third phase of the giant Clair field, west of the Shetland Islands. The initial commitment involves the drilling of five appraisal wells. Drilling on the first well has commenced.

 

In April in Azerbaijan, the Shah Deniz consortium began evaluating offers received from Nabucco Gas Pipeline International and Trans Adriatic Pipeline for transportation of Shah Deniz Stage 2 gas to Europe. The final selection decision on the European pipeline is expected to be made later this year.

 

Also in April we decided we will not move forward with the current plan for the Mad Dog Phase 2 project in the deepwater Gulf of Mexico. The current development plan is no longer as attractive as previously modelled, due largely to market conditions and industry cost inflation. BP, in collaboration with co-owners Union Oil Company of California, a subsidiary of Chevron Corp., and BHP Billiton Petroleum, is now reviewing existing plans and other options in order to evaluate how to develop the project.

 

 

The commentary above contains forward-looking statements and should be read in conjunction with the cautionary statement on page 34.

 

 

Top of page 5

Upstream

 


First

Fourth

First

$ million


quarter

quarter

quarter

Underlying RC profit before interest and tax


2013

2012

2012

US


 998

 827

 1,658

Non-US


 4,704

 3,548

 4,636



 5,702

 4,375

 6,294

Non-operating items





US


(6)

 3,992

 947

Non-US


(74)

(646)

(125)



(80)

 3,346

 822

Fair value accounting effects(a)





US


(40)

(29)

(71)

Non-US


(20)

(4)

(62)



(60)

(33)

(133)

RC profit before interest and tax





US


 952

 4,790

 2,534

Non-US


 4,610

 2,898

 4,449



 5,562

 7,688

 6,983

Exploration expense





US


 80

 139

 62

Non-US


 242

 170

 198



 322

 309

 260

Production (net of royalties)(b)





Liquids (mb/d)(c)





US


 366

 402

 454

Europe


 115

 100

 123

Rest of World


 712

 670

 671



 1,193

 1,172

 1,248

Natural gas (mmcf/d)





US


 1,532

 1,593

 1,820

Europe


 329

 371

 500

Rest of World


 4,733

 4,521

 4,665



 6,593

 6,484

 6,985

Total hydrocarbons (mboe/d)(d)





US


 631

 676

 768

Europe


 171

 164

 209

Rest of World


 1,528

 1,449

 1,475



 2,330

 2,290

 2,452

Average realizations(e)





Total liquids ($/bbl)


 103.11

 100.00

 108.13

Natural gas ($/mcf)


 5.52

 5.03

 4.68

Total hydrocarbons ($/boe)


 65.11

 62.38

 64.02

 

(a)

These effects represent the favourable (unfavourable) impact relative to management's measure of performance. Further information on fair value accounting effects is provided on page 19.

(b)

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

(c)

Crude oil and natural gas liquids.

(d)

Natural gas is converted to oil equivalent at 5.8 billion cubic feet = 1 million barrels.

(e)

Based on sales of 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

 


First

Fourth

First



quarter

quarter

quarter



2013

2012

2012

$ million





Profit before interest and tax


 2,055

 564

 2,354

Inventory holding (gains) losses


(408)

 765

(1,495)

RC profit before interest and tax


 1,647

 1,329

 859

Net (favourable) unfavourable impact of non-operating items





  and fair value accounting effects


(6)

 65

 68

Underlying RC profit before interest and tax(a)


 1,641

 1,394

 927

 

(a)

See page 2 for information on underlying RC profit and see page 7 for a reconciliation to segment RC profit before interest and tax by region and by business.

 

The replacement cost profit before interest and tax for the first quarter was $1,647 million, compared with $859 million for the same period in 2012.

 

The first-quarter result included a net non-operating gain of $19 million, compared with a net charge of $106 million a year ago (see pages 7 and 18 for further information on non-operating items). Fair value accounting effects had an unfavourable impact of $13 million for the first quarter, compared with a favourable impact of $38 million for the first quarter of 2012.

 

After adjusting for non-operating items and fair value accounting effects, the underlying replacement cost profit before interest and tax for the first quarter was $1,641 million, compared with $927 million a year ago.

 

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

 

The fuels business delivered an underlying replacement cost profit before interest and tax of $1,237 million for the first quarter, compared with $490 million for the same period in 2012, principally due to a significant improvement in the supply and trading contribution. In addition, the business delivered strong operations with Solomon availability at 95.1%, which allowed us to capture the more favourable refining environment, particularly in the US Midwest where heavy Canadian crude grades were significantly discounted to other grades for most of the quarter. These benefits were partly offset by the impact of the planned outage of the largest crude unit at our Whiting refinery as part of the Whiting refinery modernization project. The new crude unit remains on track for commissioning in the second quarter of 2013, enabling the start-up of the Whiting refinery modernization project in the second half of the year.

 

Late in the first quarter, heavy Canadian crude differentials narrowed significantly and to date in the second quarter have remained at these levels. In addition, compared with the fourth quarter of 2012, fuels demand was weak during the first quarter leading to lower volumes and unit margins.

 

On 1 February 2013 we completed the sale of our Texas City refinery and a portion of its retail and logistics network in the south-eastern US to Marathon Petroleum Corporation. This divestment was the principal factor contributing to the decline in refining throughputs in the quarter of over 200mb/d compared with the same quarter last year and the fourth quarter of 2012.

 

In March 2013, BP-Husky Refining LLC successfully started up a new naphtha reformer at the Toledo refinery, which is intended to improve the plant's efficiency and competitiveness.

 

We continue to expect the sale of the Carson refinery in California, and related marketing and logistics assets in the region, to complete by mid-2013, subject to regulatory approvals (see Note 4 on page 29 for further details).

 

The lubricants business delivered an underlying replacement cost profit before interest and tax of $345 million in the first quarter, compared with $325 million in the same period last year. This reflects continued robust performance supported by growth in the share of sales of our premium Castrol brands and strong profitability from growth markets.

 

The petrochemicals business delivered an underlying replacement cost profit before interest and tax of $59 million in the first quarter of 2013 compared with $112 million in the same period last year. This decrease was due to the continued difficult margin environment, which also led us to reduce our production particularly in Asia. Production volumes compared with the same quarter last year were also impacted by the sale of our petrochemicals plant in Malaysia in October 2012. To date in the second quarter petrochemicals margins have been lower relative to levels seen in the first quarter and we expect them to remain subdued during 2013.

 

 

The commentary above contains forward-looking statements and should be read in conjunction with the cautionary statement on page 34.

 

 

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Downstream

 


First

Fourth

First

$ million


quarter

quarter

quarter

Underlying RC profit before interest and tax - by region


2013

2012

2012

US


 750

 583

 289

Non-US


 891

 811

 638



 1,641

 1,394

 927

Non-operating items





US


 28

(96)

(88)

Non-US


(9)

 23

(18)



 19

(73)

(106)

Fair value accounting effects(a)





US


(65)

(9)

(43)

Non-US


 52

 17

 81



(13)

 8

 38

RC profit before interest and tax





US


 713

 478

 158

Non-US


 934

 851

 701



 1,647

 1,329

 859

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





Fuels


 1,237

 1,019

 490

Lubricants


 345

 329

 325

Petrochemicals


 59

 46

 112



 1,641

 1,394

 927

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





Fuels


 11

(86)

(68)

Lubricants


(5)

 1

-   

Petrochemicals


- 

 20

-   



 6

(65)

(68)

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





Fuels


 1,248

 933

 422

Lubricants


 340

 330

 325

Petrochemicals


 59

 66

 112



 1,647

 1,329

 859






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


 17.4

 16.9

 14.6

Refinery throughputs (mb/d)





US


 937

 1,325

 1,218

Europe


 806

 732

 775

Rest of World


 322

 293

 277



 2,065

 2,350

 2,270

Refining availability (%)(e)


 95.1

 95.0

 94.9

Marketing sales of refined products (mb/d)





US


 1,402

 1,393

 1,349

Europe(f)


 1,158

 1,236

 1,192

Rest of World


 557

 599

 574



 3,117

 3,228

 3,115

Trading/supply sales of refined products


 2,308

 2,434

 2,380

Total sales volumes of refined products


 5,425

 5,662

 5,495

Petrochemicals production (kte)





US


 1,076

 959

 1,078

Europe(c)


 1,014

 925

 1,011

Rest of World


 1,417

 1,500

 1,817



 3,507

 3,384

 3,906

 

(a)

Fair value accounting effects represent the favourable (unfavourable) impact relative to management's measure of performance. For Downstream, these arise solely in the fuels business. Further information is provided on page 19.

(b)

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

(c)

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

(d)

The 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. In 2013 BP updated the RMM methodology; prior periods have been restated.

(e)

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 maintenance downtime.

(f)

A minor amendment has been made to the first quarter 2012.

 

 

Top of page 8

TNK-BP

 


First

Fourth

First



quarter

quarter

quarter



2013

2012

2012

$ million





Profit before interest and tax(a)


 12,500

 570

 1,090

Inventory holding (gains) losses


- 

 5

(26)

RC profit before interest and tax


 12,500

 575

 1,064

Net charge (credit) for non-operating items


(12,500)

(351)

 93

Underlying RC profit before interest and tax(b)


-   

 224

 1,157

 

(a)

The TNK-BP segment includes equity-accounted earnings from associates, in which all amounts shown relate to BP's 50% share in TNK-BP, as follows:

 

Profit before interest and tax


-   

 254

 1,481

Finance costs


-   

(1)

(36)

Taxation


-   

(45)

(231)

Non-controlling interests


-   

(22)

(124)

Net income (BP share)


-   

 186

 1,090

Inventory holding (gains) losses, net of tax


-   

 5

(26)

Net charge (credit) for non-operating items, net of tax


-   

 33

 93

Net income (BP share) on an underlying RC basis(b)


-   

 224

 1,157

 

(b)

See page 2 for information on underlying RC profit.

 


First

Fourth

First



quarter

quarter

quarter



2013

2012

2012

Production (net of royalties) (BP share)(c)





Crude oil (mb/d)


 758

 870

 879

Natural gas (mmcf/d)


 745

 818

 813

Total hydrocarbons (mboe/d)(d)


 886

 1,011

 1,019

 

(c)

BP continued to report its share of TNK-BP's production and reserves following the agreement to sell its 50% share to Rosneft until the sale completed on 21 March 2013.

(d)

Natural gas is converted to oil equivalent at 5.8 billion cubic feet = 1 million barrels.

 

On 21 March 2013, BP completed sale and purchase agreements with Rosneft and Rosneftegaz - the Russian state-owned parent company of Rosneft - for the sale of BP's 50% interest in TNK-BP to Rosneft, and for BP's further investment in Rosneft.

 

Replacement cost profit before interest and tax(e) for the first quarter was $12,500 million, compared with $1,064 million for the same period in 2012. The first-quarter result reflects the non-operating gain on disposal of BP's interest in TNK-BP. See Note 3 on page 28 for more information on the disposal of TNK-BP. First quarter 2012 included a non-operating impairment charge of $93 million.

 

No equity-accounted earnings are included in the TNK-BP segment result for the first quarter 2013 because our investment was classified as an asset held for sale from 22 October 2012. Accordingly, underlying replacement cost profit before interest and tax for the segment in the first quarter was nil, compared with $1,157 million a year ago.

 

Total estimated hydrocarbon production for the first quarter was 886mboe/d which represents BP's share of TNK-BP's estimated production from 1 January to 20 March, averaged over the full quarter. This was 13% lower than production for the same period in 2012, primarily due to completion of the sale transaction on 21 March 2013.

 

(e)

Under equity accounting, BP's share of TNK-BP's earnings after interest and tax in 2012 was included in the BP group income statement within profit before interest and tax.

 

 

Top of page 9

Rosneft

 


First

Fourth

First



quarter

quarter

quarter



2013

2012

2012

$ million





Profit before interest and tax(a)(b)


 85

-   

-   

Inventory holding (gains) losses


- 

-   

-   

RC profit before interest and tax(c)


 85

-   

-   

Net charge (credit) for non-operating items


- 

-   

-   

Underlying RC profit before interest and tax(c)


 85

-   

-   

 

(a)

The Rosneft segment includes equity-accounted earnings from associates, representing BP's 19.75% share in Rosneft.

(b)

BP estimate based on Rosneft and TNK-BP historical financial data, adjusted for oil and gas prices and exchange rates.

(c)

Assumed to be the same as profit before interest and tax.

 


First

Fourth

First



quarter

quarter

quarter



2013

2012

2012

Production (net of royalties) (BP share)(d)





Crude oil (mb/d)


 102

-   

-   

Natural gas (mmcf/d)


 89

-   

-   

Total hydrocarbons (mboe/d)(e)


 117

-   

-   

 

(d)

BP estimates based on available information from Rosneft and TNK-BP and, in the case of natural gas, Rosneft historical information.

(e)

Natural gas is converted to oil equivalent at 5.8 billion cubic feet = 1 million barrels.

 

Balance sheet

31 March

31 December


2013

2012

$ million



Investments in associates


 12,970

-   

 

With effect from 21 March 2013, the completion date of the sale and purchase agreements with Rosneft and Rosneftegaz described in Note 3, BP's 19.75% shareholding in Rosneft meets the criteria to be accounted for using the equity method and is reported as a separate operating segment under IFRS. See Note 3 on page 28 for further information.

 

Inventory holding gains or losses and non-operating items in respect of the Rosneft segment have not been reported for the first quarter but we intend to begin reporting this information later this year. Replacement cost profit before interest and tax(f) for the Rosneft segment in the first quarter, which has been assumed to be the same as profit before interest and tax, was $85 million, reflecting BP's equity-accounted share of Rosneft's earnings from 21 March as estimated by BP.

 

Total hydrocarbon production for the first quarter as estimated by BP was 117mboe/d. This represents BP's 19.75% share of Rosneft's estimated production from 21 March to 31 March, averaged over the full quarter.

 

The operational and financial information of the Rosneft segment presented above is based on BP's estimates of Rosneft's and TNK-BP's operational and financial results for the period ended 31 March 2013. Actual results may differ from these estimates. Any adjustments to this operational and financial information based on BP's review of actual reported results will be reflected in BP's second quarter results. 

 

(f)

Under equity accounting, BP's share of Rosneft's earnings after interest and tax is included in the BP group income statement within profit before interest and tax.

 

 

The commentary above contains forward-looking statements and should be read in conjunction with the cautionary statement on page 34.

 

 

Top of page 10

Other businesses and corporate

 


First

Fourth

First



quarter

quarter

quarter



2013

2012

2012

$ million





Profit (loss) before interest and tax


(467)

(505)

(671)

Inventory holding (gains) losses


- 

-   

-   

RC profit (loss) before interest and tax


(467)

(505)

(671)

Net charge (credit) for non-operating items


 6

 57

 236

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


(461)

(448)

(435)






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





US


(121)

(291)

(165)

Non-US


(340)

(157)

(270)



(461)

(448)

(435)

Non-operating items





US


(4)

(54)

(142)

Non-US


(2)

(3)

(94)



(6)

(57)

(236)

RC profit (loss) before interest and tax





US


(125)

(345)

(307)

Non-US


(342)

(160)

(364)



(467)

(505)

(671)

 

(a)

See page 2 for information on underlying RC profit or loss.

 

Other businesses and corporate comprises the Alternative Energy business, Shipping, Treasury (which includes interest income on the group's cash and cash equivalents), and corporate activities worldwide.

 

The replacement cost loss before interest and tax for the first quarter was $467 million, compared with $671 million for the same period last year.

 

The first-quarter result included a net non-operating charge of $6 million, compared with a net non-operating charge of $236 million a year ago.

 

After adjusting for non-operating items, the underlying replacement cost loss before interest and tax for the first quarter was $461 million, compared with $435 million for the same period last year.

 

In Alternative Energy, net wind generation capacity(b) at the end of the first quarter was 1,590MW (2,619MW gross), compared with 1,274MW (1,988MW gross) at the end of the same period a year ago. BP's net share of wind generation from our US wind farms for the first quarter was 1,144GWh (2,063GWh gross), compared with 1,024GWh (1,675GWh gross) in the same period a year ago. BP intends to market its wind business for sale.

 

In our biofuels business, the first quarter is the inter-harvest period in Brazil so the mills were on planned turnaround and there was no production. In the UK, the Vivergo joint venture (BP 47%) was commissioned in late 2012 and commenced

start-up during the first quarter 2013.

 

(b)

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

 

 


The commentary above contains forward-looking statements and should be read in conjunction with the cautionary statement on page 34.

 

 

 

Top of page 11

Gulf of Mexico oil spill

 

Financial update

 

BP continues to support completing the operational clean-up response, facilitating economic restoration through claims processes, and facilitating environmental restoration through natural resource damage assessment and early restoration projects relating to the Gulf of Mexico oil spill.

 

The replacement cost loss before interest and tax for the first quarter was $22 million, compared with a $30 million profit for the same period last year. The first-quarter charge reflects the ongoing costs of the Gulf Coast Restoration Organization and adjustments to provisions. The cumulative pre-tax charge recognized to date amounts to $42.2 billion.

 

The cumulative income statement charge does not include amounts for obligations that BP considers are not possible, at this time, to measure reliably. The total amounts that will ultimately be paid by BP in relation to all the obligations relating to the incident are subject to significant uncertainty and the ultimate exposure and cost to BP will be dependent on many factors, as discussed under Contingent liabilities in Note 2 on page 27, including in relation to any new information or future developments. These could have a material impact on our consolidated financial position, results of operations and cash flows. The risks associated with the accident could also heighten the impact of the other risks to which the group is exposed, as further described under Risk factors on pages 38 - 44 of BP Annual Report and Form 20-F 2012.

 

Trust update

 

During the first quarter, $778 million was paid out of the Deepwater Horizon Oil Spill Trust (Trust) and qualified settlement funds (QSFs) toward provisions, including $680 million for claims payments, administrative costs of the Deepwater Horizon Court Supervised Settlement Program (DHCSSP) and other resolved items, and $98 million for natural resource damage assessment and early restoration. In addition, $318 million was paid out to claimants from the seafood compensation fund, for which the related provision and reimbursement asset had been previously derecognized upon funding of the QSF. At the end of the first quarter, the cash balances in the Trust and the QSFs amounted to $9.4 billion, with $20 billion contributed by BP and $10.6 billion paid out.

 

As at 31 March 2013, the cumulative charges for provisions to be paid from the Trust and the associated reimbursement asset recognized amounted to $18.3 billion. This represents an increase of $492 million for the quarter primarily for business economic loss claims received and processed by the DHCSSP. A further $1.7 billion could be provided in subsequent periods for items covered by the Trust, with no net impact on the income statement. The amount provided does not include any amounts for future business economic loss claims not yet received or processed by the DHCSSP as this liability cannot currently be estimated reliably. See Note 2 on pages 24 - 25 and Legal proceedings on pages 32 - 33 for further details.

 

Legal proceedings and investigations

 

Phase 1 of the MDL (Multi-District Litigation) 2179 trial took place in federal court in New Orleans, Louisiana between 25 February and 17 April. The presentation of evidence in the first trial phase addressed issues arising out of the conduct of various parties allegedly relevant to the loss of well control at the Macondo well, the ensuing fire and explosion on the Deepwater Horizon on 20 April 2010, the sinking of the vessel on 22 April 2010 and the initiation of the release of oil from the Deepwater Horizon or the Macondo well during those time periods, including whether BP or any other party was grossly negligent. BP does not know when the court will rule on the issues presented in phase 1 of the trial. Phase 2 will consider the issues of source control efforts and volume of oil spilled as a result of the accident. For further details, see Legal proceedings on pages 32 - 33.

 

 

The commentary above contains forward-looking statements and should be read in conjunction with the cautionary statement on page 34.

 

 

 

Top of page 12

Group income statement

 


First

Fourth

First



quarter

quarter

quarter



2013

2012

2012

$ million





Sales and other operating revenues (Note 5)


 94,107

 93,910

 94,878

Earnings from joint ventures - after interest and tax


 125

 38

 151

Earnings from associates - after interest and tax


 284

 322

 1,260

Interest and other income


 157

 1,129

 195

Gains on sale of businesses and fixed assets


 12,541

 4,412

 933

Total revenues and other income


 107,214

 99,811

 97,417

Purchases


 71,661

 74,061

 72,301

Production and manufacturing expenses(a)


 6,868

 12,240

 6,721

Production and similar taxes (Note 6)


 1,995

 2,073

 2,346

Depreciation, depletion and amortization


 3,197

 3,248

 3,261

Impairment and losses on sale of businesses and fixed assets


 110

 828

 140

Exploration expense


 322

 309

 260

Distribution and administration expenses


 2,954

 3,389

 3,128

Fair value (gain) loss on embedded derivatives


(31)

(104)

 99

Profit before interest and taxation


 20,138

 3,767

 9,161

Finance costs(a)


 282

 307

 269

Net finance expense relating to pensions and other





  post-retirement benefits


 122

 160

 136

Profit before taxation


 19,734

 3,300

 8,756

Taxation(a)


 2,792

 1,750

 2,928

Profit for the period


 16,942

 1,550

 5,828

Attributable to





  BP shareholders


 16,863

 1,488

 5,767

  Non-controlling interests


 79

 62

 61



 16,942

 1,550

 5,828

Earnings per share - cents (Note 7)





Profit for the period attributable to BP shareholders





  Basic


 88.07

 7.80

 30.39

  Diluted


 87.61

 7.75

 29.97

 

(a)

See Note 2 for further details of the impact of the Gulf of Mexico oil spill on the income statement line items.

 

 

Top of page 13

Group statement of comprehensive income

 


First

Fourth

First



quarter

quarter

quarter



2013

2012

2012

$ million





Profit for the period


 16,942

 1,550

 5,828

Other comprehensive income (expense)





Items that may be reclassified subsequently to profit or loss





  Currency translation differences


(587)

 246

 575

  Exchange (gains) losses on translation of foreign operations reclassified





    to gain or loss on sales of businesses and fixed assets


- 

(15)

- 

  Available-for-sale investments marked to market


(172)

 290

 64

  Available-for-sale investments reclassified to the income statement


(523)

(1)

- 

  Cash flow hedges marked to market(a)


(2,141)

 1,439

 75

  Cash flow hedges reclassified to the income statement


- 

 3

 2

  Cash flow hedges reclassified to the balance sheet


 3

 7

 5

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


 33

 13

 209

  Income tax relating to items that may be reclassified


 169

(245)

(32)



(3,218)

 1,737

 898

Items that will not be reclassified to profit or loss





  Remeasurements of the net pension and other post-retirement benefit





    liability or asset


(50)

(1,506)

 1,609

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


- 

-   

(6)

  Income tax relating to items that will not be reclassified


 1

 367

(457)



(49)

(1,139)

 1,146

Other comprehensive income (expense)


(3,267)

 598

 2,044

Total comprehensive income


 13,675

 2,148

 7,872

Attributable to





  BP shareholders


 13,600

 2,088

 7,805

  Non-controlling interests


 75

 60

 67



 13,675

 2,148

 7,872

 

(a)

First quarter 2013 includes $2,061 million loss relating to the contracts to acquire Rosneft shares (fourth quarter 2012 $1,410 million gain). See Note 3 for further information.

 

 

Group statement of changes in equity

 


 





BP shareholders' 

Non-controlling 

 



equity 

interests 

Total equity 

$ million




At 1 January 2013


 118,546

 1,206

 119,752





Total comprehensive income


 13,600

 75

 13,675

Dividends


(1,621)

(66)

(1,687)

Repurchases of ordinary share capital


(850)

- 

(850)

Share-based payments (net of tax)


 176

- 

 176

Transactions involving non-controlling interests


- 

 19

 19

At 31 March 2013


 129,851

 1,234

 131,085







 





BP shareholders' 

Non-controlling 

 



equity 

interests 

Total equity 

$ million




At 1 January 2012


 111,568

 1,017

 112,585





Total comprehensive income


 7,805

 67

 7,872

Dividends


(1,211)

(1)

(1,212)

Share-based payments (net of tax)


 59

-   

 59

Transactions involving non-controlling interests


- 

 11

 11

At 31 March 2012


 118,221

 1,094

 119,315

 

 

Top of page 14

Group balance sheet

 


31 March

31 December



2013

2012

$ million




Non-current assets




Property, plant and equipment


 126,848

 125,331

Goodwill


 11,940

 12,190

Intangible assets


 24,962

 24,632

Investments in joint ventures


 8,701

 8,614

Investments in associates


 16,077

 2,998

Other investments


 1,407

 2,704

Fixed assets


 189,935

 176,469

Loans


 586

 642

Trade and other receivables


 5,722

 5,961

Derivative financial instruments


 4,340

 4,294

Prepayments


 924

 830

Deferred tax assets


 787

 874

Defined benefit pension plan surpluses


 13

 12



 202,307

 189,082

Current assets




Loans


 227

 247

Inventories


 28,628

 28,203

Trade and other receivables


 41,649

 37,611

Derivative financial instruments


 2,967

 4,507

Prepayments


 1,262

 1,091

Current tax receivable


 548

 456

Other investments


 596

 319

Cash and cash equivalents


 27,679

 19,635



 103,556

 92,069

Assets classified as held for sale (Note 4)


 4,947

 19,315



 108,503

 111,384

Total assets


 310,810

 300,466

Current liabilities




Trade and other payables


 49,787

 46,673

Derivative financial instruments


 2,503

 2,658

Accruals


 6,688

 6,875

Finance debt


 8,901

 10,033

Current tax payable


 3,083

 2,503

Provisions


 6,908

 7,587



 77,870

 76,329

Liabilities directly associated with assets classified as held for sale (Note 4)


 722

  846



 78,592

 77,175

Non-current liabilities




Other payables


 4,888

 2,292

Derivative financial instruments


 2,706

 2,723

Accruals


 498

 491

Finance debt


 37,524

 38,767

Deferred tax liabilities


 16,044

 15,243

Provisions


 26,344

 30,396

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


 13,129

 13,627



 101,133

 103,539

Total liabilities


 179,725

 180,714

Net assets


 131,085

 119,752

Equity




BP shareholders' equity


 129,851

 118,546

Non-controlling interests


 1,234

 1,206



131,085

 119,752

 

 

Top of page 15

Condensed group cash flow statement

 


First

Fourth

First



quarter

quarter

quarter



2013

2012

2012

$ million





Operating activities





Profit before taxation(a)


 19,734

 3,300

 8,756

Adjustments to reconcile profit before taxation to net cash





  provided by operating activities





Depreciation, depletion and amortization and exploration





  expenditure written off


 3,369

 3,403

 3,341

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


(12,431)

(3,584)

(793)

Earnings from equity-accounted entities, less dividends received


(200)

(65)

(481)

Net charge for interest and other finance expense, less net





  interest paid


 172

 9

 136

Share-based payments


 46

(109)

 34

Net operating charge for pensions and other post-retirement benefits,





  less contributions and benefit payments for unfunded plans


(284)

(434)

(160)

Net charge for provisions, less payments


 197

 3,938

 163

Movements in inventories and other current and non-current





  assets and liabilities(b)


(5,345)

 1,190

(6,200)

Income taxes paid


(1,291)

(1,269)

(1,390)

Net cash provided by operating activities


 3,967

 6,379

 3,406

Investing activities





Capital expenditure


(5,729)

(7,059)

(5,447)

Investment in joint ventures


(51)

(457)

(226)

Investment in associates


(4,883)

(17)

(23)

Proceeds from disposal of fixed assets


 16,780

 6,804

 1,267

Proceeds from disposal of businesses, net of cash disposed


 1,501

 67

 71

Proceeds from loan repayments


 22

 70

 50

Net cash provided by (used in) investing activities


 7,640

(592)

(4,308)

Financing activities





Net issue (repurchase) of shares


 55

 61

 21

Proceeds from long-term financing


 63

 3,031

 3,813

Repayments of long-term financing


(288)

(3,592)

(2,416)

Net increase (decrease) in short-term debt


(1,491)

(668)

 669

Dividends paid - BP shareholders


(1,622)

(1,217)

(1,212)

- non-controlling interests


(31)

(10)

(1)

Net cash provided by (used in) financing activities


(3,314)

(2,395)

 874

Currency translation differences relating to





  cash and cash equivalents


(249)

 69

 118

Increase (decrease) in cash and cash equivalents


 8,044

 3,461

 90

Cash and cash equivalents at beginning of period


 19,635

 16,174

 14,177

Cash and cash equivalents at end of period


 27,679

 19,635

 14,267

 

(a)

Fourth quarter 2012 includes $709 million of dividends received from TNK-BP. See Note 3 for further information.

(b)

Includes

 

Inventory holding (gains) losses


(407)

 737

(1,410)

Fair value (gain) loss on embedded derivatives


(31)

(104)

 99

Movements related to Gulf of Mexico oil spill response


(828)

(771)

(1,861)

 

Inventory holding gains and losses and fair value gains and losses on embedded derivatives are also included within profit before taxation. See Note 2 for further information on the cash flow impacts of the Gulf of Mexico oil spill.

 

 

Top of page 16

Capital expenditure and acquisitions

 


First

Fourth

First



quarter

quarter

quarter



2013

2012

2012

$ million





By business





Upstream





US(a)


 1,539

 1,843

 1,646

Non-US(b)


 2,957

 3,345

 2,988



 4,496

 5,188

 4,634

Downstream





US


 839

 902

 697

Non-US


 215

 799

 212



 1,054

 1,701

 909

Rosneft





Non-US(c)


 11,941

- 

- 



 11,941

- 

- 

Other businesses and corporate





US


 24

 143

 158

Non-US


 136

 395

 139



 160

 538

 297



 17,651

 7,427

 5,840

By geographical area





US(a)


 2,402

 2,888

 2,501

Non-US(b)(c)


 15,249

 4,539

 3,339



 17,651

 7,427

 5,840

Included above:





Acquisitions and asset exchanges


- 

 45

 10

Other inorganic capital expenditure(a)(b)(c)


 11,941

 543

 311

 

(a)

First quarter and fourth quarter 2012 include $311 million and $388 million respectively, associated with deepening our natural gas asset base.

(b)

Fourth quarter 2012 includes $155 million related to increasing our interest in North Sea assets.

(c)

First quarter 2013 includes $11,941 million related to our investment in Rosneft - see Note 3 for further information.

 

 

Exchange rates

 


First

Fourth

First



quarter

quarter

quarter



2013

2012

2012

US dollar/sterling average rate for the period


 1.55

 1.61

 1.57

US dollar/sterling period-end rate


 1.51

 1.62

 1.59

US dollar/euro average rate for the period


 1.32

 1.30

 1.31

US dollar/euro period-end rate


 1.28

 1.32

 1.33

 

 

Top of page 17

Analysis of replacement cost profit before interest and tax and

reconciliation to profit before taxation 

 


First

Fourth

First



quarter

quarter

quarter



2013

2012

2012

$ million





Upstream


 5,562

 7,688

 6,983

Downstream


 1,647

 1,329

 859

TNK-BP(a)


 12,500

 575

 1,064

Rosneft(b)


 85

- 

- 

Other businesses and corporate


(467)

(505)

(671)



 19,327

 9,087

 8,235

Gulf of Mexico oil spill response


(22)

(4,126)

 30

Consolidation adjustment - UPII


 427

(428)

(541)

RC profit before interest and tax


 19,732

 4,533

 7,724

Inventory holding gains (losses)





  Upstream


(2)

 4

(84)

  Downstream


 408

(765)

 1,495

  TNK-BP (net of tax)


- 

(5)

 26

Profit before interest and tax


 20,138

 3,767

 9,161

Finance costs


 282

 307

 269

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


 122

 160

 136

Profit before taxation


 19,734

 3,300

 8,756






RC profit before interest and tax





US


 1,771

 1,069

 1,935

Non-US


 17,961

 3,464

 5,789



 19,732

 4,533

 7,724

 

(a)

BP ceased equity accounting for its share of TNK-BP's earnings from 22 October 2012. See TNK-BP on page 8 for further information.

(b)

BP's investment in Rosneft is accounted under the equity method from 21 March 2013. See Rosneft on page 9 for further information.

 

IFRS requires that the measure of profit or loss disclosed for each operating segment is the measure that is provided regularly to the chief operating decision maker for the purposes of performance assessment and resource allocation. For BP, both replacement cost (RC) profit or loss before interest and tax and underlying RC profit or loss before interest and tax (see page 2 for further information) are provided regularly to the chief operating decision maker. In such cases IFRS requires that the measure of profit disclosed for each operating segment is the measure that is closest to IFRS, which for BP is RC profit or loss before interest and tax. In addition, a reconciliation is required between the total of the operating segments' measures of profit or loss and the group profit or loss before taxation.

 

RC profit or loss reflects the replacement cost of supplies. The RC profit or loss for the period is arrived at by excluding from profit or loss inventory holding gains and losses and their associated tax effect. RC profit or loss for the group is not a recognized GAAP measure.

 

Inventory holding gains and losses represent the difference between the cost of sales calculated using the average cost to BP of supplies acquired during the period 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 historic 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 if an average cost of supplies was used for the period. For this purpose, the average cost of supplies during the period is principally calculated on a monthly basis by dividing the total cost of inventory acquired in the period by the number of barrels acquired. 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.

 

Management believes this information 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 principally to changes in oil prices as well as changes to underlying inventory levels. In order for investors to understand the operating performance of the group excluding the impact of oil 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 information.

 

 

 

Top of page18

Non-operating items(a)

 


First

Fourth

First



quarter

quarter

quarter



2013

2012

2012

$ million





Upstream





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


(102)

 3,673

 928

Environmental and other provisions


- 

-   

-   

Restructuring, integration and rationalization costs


- 

-   

- 

Fair value gain (loss) on embedded derivatives


 31

 103

(100)

Other(b)


(9)

(430)

(6)



(80)

 3,346

 822

Downstream





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


 34

(81)

(85)

Environmental and other provisions


(9)

-   

-   

Restructuring, integration and rationalization costs


(2)

 13

(12)

Fair value gain (loss) on embedded derivatives


- 

- 

-   

Other


(4)

(5)

(9)



 19

(73)

(106)

TNK-BP





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


 12,500

-   

(93)

Environmental and other provisions


- 

(33)

-   

Restructuring, integration and rationalization costs


- 

-   

- 

Fair value gain (loss) on embedded derivatives


- 

-   

- 

Other(c)


- 

 384

- 



 12,500

 351

(93)

Other businesses and corporate





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


(1)

(8)

(50)

Environmental and other provisions


- 

-   

(15)

Restructuring, integration and rationalization costs


(2)

(14)

-   

Fair value gain (loss) on embedded derivatives


- 

 1

 1

Other(d)


(3)

(36)

(172)



(6)

(57)

(236)

Gulf of Mexico oil spill response


(22)

(4,126)

 30

Total before interest and taxation


 12,411

(559)

 417

Finance costs(e)


(10)

(6)

(6)

Total before taxation


 12,401

(565)

 411

Taxation credit (charge)(f)


 23

(1,258)

(226)

Total after taxation for period


 12,424

(1,823)

 185

 

(a)

Non-operating items are charges and credits arising in consolidated entities and in TNK-BP that are included in the financial statements and 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. An analysis of non-operating items by region is shown on pages 5, 7 and 10.

(b)

Fourth quarter 2012 includes $370 million relating to onerous gas marketing and trading contracts.

(c)

Fourth quarter 2012 includes dividend income of $709 million, partly offset by a charge of $325 million to settle disputes with Alfa, Access and Renova.

(d)

First quarter and fourth quarter 2012 include $161 million and $53 million respectively relating to our exit from the solar business.

(e)

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

(f)

For the Gulf of Mexico oil spill and certain disposal gains in the fourth quarter 2012, tax is based on US statutory tax rates, except for non-deductible items. For dividends received from TNK-BP in the fourth quarter 2012 and the gain on disposal of TNK-BP in the first quarter 2013 there is no tax arising. For other items reported by consolidated subsidiaries, tax is calculated using the group's discrete quarterly effective tax rate (adjusted for the items noted above and equity-accounted earnings). Non-operating items arising within the equity-accounted earnings of TNK-BP are reported net of tax.

 

 

Top of page 19

Non-GAAP information on fair value accounting effects

 


First

Fourth

First



quarter

quarter

quarter



2013

2012

2012

$ million





Favourable (unfavourable) impact relative to





  management's measure of performance





Upstream


(60)

(33)

(133)

Downstream


(13)

 8

 38



(73)

(25)

(95)

Taxation credit (charge)(a)


 30

 5

 40



(43)

(20)

(55)

 

(a)

Tax is calculated using the group's discrete quarterly effective tax rate (adjusted for Gulf of Mexico oil spill and equity-accounted earnings, and for the fourth quarter 2012, dividends received from TNK-BP and certain disposal gains, and for the first quarter 2013 the gain on disposal of TNK-BP).

 

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 historic 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 be 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, capacity, oil and gas processing and LNG contracts in question are valued based on fair value using relevant forward prices prevailing at the end of the period 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.

 


First

Fourth

First



quarter

quarter

quarter



2013

2012

2012

$ million





Upstream





Replacement cost profit before interest and tax





  adjusted for fair value accounting effects


 5,622

 7,721

 7,116

Impact of fair value accounting effects


(60)

(33)

(133)

Replacement cost profit before interest and tax


 5,562

 7,688

 6,983

Downstream





Replacement cost profit before interest and tax





  adjusted for fair value accounting effects


 1,660

 1,321

 821

Impact of fair value accounting effects


(13)

 8

 38

Replacement cost profit before interest and tax


 1,647

 1,329

 859

Total group





Profit before interest and tax





  adjusted for fair value accounting effects


 20,211

 3,792

 9,256

Impact of fair value accounting effects


(73)

(25)

(95)

Profit before interest and tax


 20,138

 3,767

 9,161

 

 

Top of page 20

Realizations and marker prices

 


First

Fourth

First



quarter

quarter

quarter



2013

2012

2012

Average realizations(a)





Liquids ($/bbl)(b)





US


 96.11

 94.36

 99.39

Europe


 107.15

 104.80

 116.96

Rest of World


 108.04

 104.59

 114.79

BP Average


 103.11

 100.00

 108.13

Natural gas ($/mcf)





US


 2.92

 2.62

 2.24

Europe


 9.78

 9.33

 7.83

Rest of World


 6.12

 5.58

 5.34

BP Average


 5.52

 5.03

 4.68

Total hydrocarbons ($/boe)





US


 62.94

 62.40

 62.94

Europe


 90.93

 84.38

 87.50

Rest of World


 62.22

 59.04

 60.30

BP Average


 65.11

 62.38

 64.02

Average oil marker prices ($/bbl)





Brent


 112.57

 110.08

 118.60

West Texas Intermediate


 94.29

 88.15

 103.10

Alaska North Slope


 110.97

 107.08

 118.47

Mars


 109.10

 103.56

 115.50

Urals (NWE - cif)


 110.53

 108.64

 116.87

Russian domestic oil


 55.24

 54.23

 58.22

Average natural gas marker prices





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


 3.34

 3.41

 2.72

UK Gas - National Balancing Point (p/therm)


 73.83

 65.26

 59.38

 

(a)

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

(b)

Crude oil and natural gas liquids.

(c)

Henry Hub First of Month Index.

 

 

Top of page 21

Notes

 

1.       Basis of preparation

 

(a) 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 the periods presented. 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 2012 included in BP Annual Report and Form 20-F 2012.

 

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, however, the differences have no impact on the group's consolidated financial statements for the periods presented.

 

To the greatest extent possible, 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 2013. These accounting policies differ from those used in BP Annual Report and Form 20-F 2012 as noted below.

 

Segmental reporting

 

On 21 March 2013, BP completed sale and purchase agreements with Rosneft and Rosneftegaz - the Russian state-owned parent company of Rosneft - for the sale of BP's 50% interest in TNK-BP to Rosneft, and for BP's further investment in Rosneft. With effect from that date, BP's 19.75% shareholding in Rosneft is accounted for using the equity method and is reported as a separate operating segment.

 

Comparative group income statement and group balance sheet

 

In addition to the changes made to the comparative data presented in this report as a result of the adoption of the amended IAS 19 and the new standard IFRS 11 (as detailed below), the comparative group balance sheet as at 31 December 2012 also reflects an adjustment, made subsequent to releasing our unaudited fourth quarter and full year 2012 results announcement dated 5 February 2013, which was included in the balance sheet approved by the board of directors on 6 March 2013 and published in BP Annual Report and Form 20-F 2012. The difference relates to an adjustment of $0.8 billion that was made to decrease provisions relating to the Gulf of Mexico oil spill as at 31 December 2012, with a corresponding decrease in the reimbursement asset. There was no impact on profit or loss for the year. A further adjustment was made to the group income statement to correct a $4.7 billion understatement of revenue and purchases for the year ended 31 December 2012. There was no impact on profit or loss for the year. For further information, see BP Annual Report and Form 20-F 2012.

 

New or amended International Financial Reporting Standards adopted

 

BP adopted several new or amended accounting standards issued by the IASB with effect from 1 January 2013.

 

IFRS 10 'Consolidated Financial Statements', IFRS 11 'Joint Arrangements' and IFRS 12 'Disclosure of Interests in Other Entities' were issued in May 2011. The main impact of this suite of new standards for BP is that certain of the group's jointly controlled entities, which were previously being equity accounted, now fall under the definition of a joint operation under IFRS 11 and thus we now recognize the group's assets, liabilities, revenue and expenses relating to these arrangements. Whilst the effect on the group's reported income and net assets as a result of the new requirements is not material, the change impacts certain of the component lines of the income statement, balance sheet and cash flow statement. On the balance sheet, there is a reduction in investments in joint ventures of approximately $7 billion as at 31 December 2012, which is replaced with the recognition (on the relevant line items, principally intangible assets and property, plant and equipment) of our share of the assets and liabilities relating to these arrangements.

 

An amended version of IAS 19 'Employee Benefits' was issued in June 2011. The main impact for BP is that the expense for defined benefit pension and other post-retirement benefit plans now includes a net interest income or expense, which is calculated by applying the discount rate used for measuring the obligation and applying that to the net defined benefit asset or liability. This means that the expected return on assets credited to profit or loss (previously calculated based on the expected long-term return on pension assets) is now based on a lower corporate bond rate, the same rate that is used to discount the pension liability. Under the amended IAS 19, net finance expense (income) relating to pensions and other post-retirement benefits and profit before tax was $767 million and $250 million lower for full year 2012 and the first quarter of 2013 respectively, with corresponding pre-tax increases in other comprehensive income. There is no impact on cash flows or on the balance sheet at 31 December 2012 or 31 March 2013.

 

 

Top of page 22

Notes

 

1.       Basis of preparation (continued)

 

The accounting policies which will be used in preparing BP Annual Report and Form 20-F 2013 which differ from those used in BP Annual Report and Form 20-F 2012 are shown in full in BP Financial and Operating Information 2008-2012 available on bp.com/investors.

 

There are no other new or amended standards or interpretations adopted with effect from 1 January 2013 that have a significant effect on the financial statements.

 

(b) Impact of the adoption of new or amended International Financial Reporting Standards

 

The following tables set out the adjustments made to certain selected line items of the previously reported comparative amounts as a result of the adoption of the amended IAS 19 'Employee Benefits' and the new standard IFRS 11 'Joint Arrangements'.

 

Annual restated information for 2012 is shown in BP Financial and Operating Information 2008-2012 available on bp.com/investors. Full restated quarterly information for 2012 will be available in the quarterly supplement of BP Financial and Operating Information 2008-2012 on bp.com/investors in early May 2013.

 

  
First
Second
Third
Fourth
Full
  
quarter
quarter
quarter
quarter
year
 
2012
2012
2012
2012
2012
Selected lines only
As
As
As
As
As
As
As
As
As
As
 
  
reported
restated
reported
restated
reported
restated
reported
restated
reported
restated
$ million
  
  
  
  
  
  
  
  
  
  
(except per share amounts)  
  
  
  
  
  
  
  
  
  
Income statement
  
  
  
  
  
  
  
  
  
  
Earnings from joint
  
  
  
  
  
  
  
  
  
  
 ventures – after interest
  
  
  
  
  
  
  
  
  
  
 and tax
290
151
88
(36)
235
107
131
38
744
260
Net finance income
  
  
  
  
  
  
  
  
  
  
 (expense) relating to
  
  
  
  
  
  
  
  
  
  
 pensions and other
  
  
  
  
  
     
  
  
  
  
 post-retirement benefits
53
(136)
55
(137)
58
(133)
35
(160)
201
(566)
Profit (loss) for the period
5,976
5,828
(1,340)
(1,474)
5,500
5,347
1,680
1,550
11,816
11,251
 
  
  
  
  
  
  
  
  
  
  
Earnings per share
  
  
  
 
 
 
 
  
  
  
 Basic (cents)
31.17
30.39
(7.29)
(7.99)
28.54
27.74
8.48
7.80
60.86
57.89
 Diluted (cents)
30.74
29.97
(7.29)
(7.99)
28.39
27.59
8.43
7.75
60.45
57.50
  
  
  
  
  
  
  
  
  
  
  
Replacement cost profit
  
  
  
  
  
  
      
  
  
 (loss) before interest
  
  
  
  
  
  
  
  
  
  
 and tax
  
  
  
  
  
  
  
  
  
  
Upstream
  
  
  
  
  
  
  
  
  
  
 US
2,534
2,534
(1,584)
(1,584)
1,178
1,178
4,790
4,790
6,918
6,918
 Non-US
4,445
4,449
4,497
4,497
3,732
3,729
2,882
2,898
15,556
15,573
  
6,979
6,983
2,913
2,913
4,910
4,907
7,672
7,688
22,474
22,491
Downstream
  
  
  
  
  
  
  
  
  
  
 US
158
158
(1,984)
(1,984)
1,106
1,106
478
478
(242)
(242)
 Non-US
698
701
248
252
1,297
1,302
845
851
3,088
3,106
  
856
859
(1,736)
(1,732)
2,403
2,408
1,323
1,329
2,846
2,864
Group
  
  
  
  
  
  
  
  
  
  
 US
1,935
1,935
(4,246)
(4,246)
1,422
1,422
1,069
1,069
180
180
 Non-US
5,781
5,789
4,967
4,971
5,956
5,959
3,443
3,464
20,147
20,183
  
7,716
7,724
721
725
7,378
7,381
4,512
4,533
20,327
20,363
 
  
  
  
  
  
  
  
  
  
  
Balance sheet
  
  
  
  
  
  
  
  
  
  
Property, plant and
  
  
  
  
  
  
  
  
  
  
 equipment
119,991
124,379
117,565
121,960
119,687
124,288
120,488
125,331
120,488
125,331
Intangible assets
22,000
22,570
22,345
22,919
23,184
23,766
24,041
24,632
24,041
24,632
Investments in joint
  
  
  
  
  
  
     
  
  
  
 ventures
15,862
8,578
15,672
8,532
15,920
8,843
15,724
8,614
15,724
8,614
Net assets
119,220
119,315
113,323
113,415
118,773
118,883
119,620
119,752
119,620
119,752
  
  
  
  
  
  
  
  
  
  
  
Cash flow statement
  
  
  
  
  
     
  
  
  
  
Profit (loss) before
  
  
  
  
  
  
  
  
  
  
 taxation
8,923
8,756
(1,815)
(1,989)
8,239
8,064
3,462
3,300
18,809
18,131
Net cash provided by
  
  
  
  
  
  
  
  
  
  
 (used in) operating
  
  
  
  
  
  
  
  
  
  
 activities
3,367
3,406
4,403
4,448
6,287
6,246
6,340
6,379
20,397
20,479
Net cash provided by
  
  
  
  
  
  
  
  
  
  
 (used in) investing
  
  
  
  
  
  
  
  
  
  
 activities
(4,329)
(4,308)
(3,462)
(3,473)
(4,672)
(4,702)
(499)
(592)
(12,962)
(13,075)
Increase (decrease) in
  
  
  
  
  
  
  
  
  
  
 cash and cash
  
  
  
  
  
  
  
  
  
  
 equivalents
25
90
789
808
1,160
1,099
3,507
3,461
5,481
5,458
 

 

Top of page 23

Notes

 

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 2012 - Financial statements - Note 2, Note 36 and Note 43 and Legal proceedings on pages 162 - 169 and on pages 32 - 33 of this report.

 

The group income statement includes a pre-tax charge of $32 million for the first quarter in relation to the Gulf of Mexico oil spill. The cumulative pre-tax income statement charge since the incident amounts to $42,239 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 Contingent liabilities below.

 

The total amounts that will ultimately be paid by BP in relation to all the obligations relating to the incident are subject to significant uncertainty and the ultimate exposure and cost to BP will be dependent on many factors, as discussed under Provisions below, including in relation to any new information or future developments. These could have a material impact on our consolidated financial position, results of operations and cash flows. The risks associated with the incident could also heighten the impact of the other risks to which the group is exposed as further described under Risk factors on pages 38 - 44 of BP Annual Report and Form 20-F 2012.

 

The amounts set out below reflect the impacts on the financial statements of the Gulf of Mexico oil spill for the periods presented, as described on page 11. The income statement, balance sheet and cash flow statement impacts are included within the relevant line items in those statements as set out below.

 



First

Fourth

First




quarter

quarter

quarter




2013

2012

2012


$ million






Income statement






Production and manufacturing expenses


 22

 4,126

(30)


Profit (loss) before interest and taxation


(22)

(4,126)

 30


Finance costs


 10

 6

 6


Profit (loss) before taxation


(32)

(4,132)

 24


Taxation


(5)

 69

(26)


Profit (loss) for the period


(37)

(4,063)

(2)

 

 



31 March 2013

31 December 2012





Of which: 


Of which: 





amount related 


amount related 




Total

to the trust fund 

Total

to the trust fund 


$ million







Balance sheet







Current assets







  Trade and other receivables


 4,082

 4,082

 4,239

 4,178


Current liabilities







  Trade and other payables


(1,082)

(1)

(522)

(22)


  Provisions


(4,810)

- 

(5,449)

- 


Net current assets (liabilities)


(1,810)

 4,081

(1,732)

 4,156


Non-current assets







  Other receivables


 2,074

 2,074

 2,264

 2,264


Non-current liabilities







  Other payables


(3,160)

- 

(175)

- 


  Provisions


(5,984)

- 

(9,751)

-   


  Deferred tax


 3,782

- 

 4,002

-   


Net non-current assets (liabilities)


(3,288)

 2,074

(3,660)

 2,264


Net assets (liabilities)


(5,098)

 6,155

(5,392)

 6,420

 

 

Top of page 24

Notes

 

2.       Gulf of Mexico oil spill (continued)

 



First

Fourth

First




quarter

quarter

quarter




2013

2012

2012


$ million






Cash flow statement - Operating activities






Profit (loss) before taxation


(32)

(4,132)

 24


Adjustments to reconcile profit (loss) before taxation to net cash






   provided by operating activities






Net charge for interest and other finance expense, less net






  interest paid


 10

 6

 6


Net charge for provisions, less payments


 304

 3,618

 85


Movements in inventories and other current and non-current






  assets and liabilities


(828)

(771)

(1,861)


Pre-tax cash flows


(546)

(1,279)

(1,746)

 

Net cash from operating activities relating to the Gulf of Mexico oil spill, on a post-tax basis, amounted to an outflow of $331 million in the first quarter of 2013. For the first quarter and fourth quarter of 2012, the amounts were an outflow of $1,208 million and an inflow of $629 million respectively.

 

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. The Trust is available to fund the qualified settlement funds (QSFs) established under the terms of the settlement agreements (comprising the Economic and Property Damages Settlement Agreement (EPD Settlement Agreement) and the Medical Benefits Class Action Settlement) with the Plaintiffs' Steering Committee (PSC) administered through the Deepwater Horizon Court Supervised Settlement Program (DHCSSP), and the separate BP claims programme - see below for further information. Fines and penalties are not covered by the trust fund.

 

The funding of the Trust was completed in the fourth quarter of 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. We use the term 'reimbursement asset' to describe this asset. BP will not actually receive any reimbursements from the trust fund, instead payments will be made directly from the trust fund, and BP will be released from its corresponding obligation. The reimbursement asset is recorded within other receivables on the balance sheet apportioned between current and non-current elements. The table below shows movements in the reimbursement asset during the period to 31 March 2013. The increase in the provision of $492 million relates principally to business economic loss claims processed by the DHCSSP for which eligibility notices have been issued. The amount of the reimbursement asset at 31 March 2013 is equal to the amount of provisions and payables recognized at that date that will be covered by the trust fund - see below.

 



First




quarter




2013


$ million




Opening balance


 6,442


Increase in provision for items covered by the trust fund


 492


Amounts paid directly by the trust fund


(778)


At 31 March 2013


 6,156


Of which - current


 4,082


                 - non-current


 2,074

 

Any increases in estimated future expenditure that will be covered by the trust fund (up to the amount of $20 billion) have no net income statement effect as a reimbursement asset is also recognized, as described above. As at 31 March 2013, the cumulative charges, and the associated reimbursement asset recognized, amounted to $18,288 million. Thus, a further $1,712 million could be charged in subsequent periods for items covered by the trust fund with no net impact on the income statement. To the extent that there is any additional liability in excess of this amount regarding claims under the Oil Pollution Act of 1990 (OPA 90), claims that are currently administered by the DHCSSP, or otherwise, including the various claims described in Legal proceedings on pages 32 - 33 in this report and on pages 162 - 171 of BP Annual Report and Form 20-F 2012, such amounts would be paid by BP directly and expensed to the income statement at that time. Information on those items that currently cannot be reliably estimated is provided under Provisions below.

 

 

Top of page 25

Notes

 

2.       Gulf of Mexico oil spill (continued)

 

Under the terms of the EPD Settlement Agreement with the PSC, several QSFs were established in 2012. These QSFs each relate to specific elements of the agreement, have been and will continue to be funded through payments from the Trust, and are available to make payments to claimants in accordance with those elements of the agreement.

 

As at 31 March 2013, the aggregate cash balances in the Trust and the QSFs amounted to $9,396 million, including $1,529 million remaining in the seafood compensation fund which is yet to be distributed.

 

The EPD Settlement Agreement with the PSC provides for a court-supervised settlement programme which commenced operation on 4 June 2012. In addition, a separate BP claims programme began processing claims from claimants not in the Economic and Property Damages class as determined by the EPD Settlement Agreement or who have requested to opt out of that settlement. Payments made to claimants through the BP claims programme are paid directly from the Trust. A separate court-supervised settlement programme has been established to pay medical claims and to implement other aspects of the Medical Benefits Class Action Settlement.  For further information on the PSC settlements, see Legal proceedings on

pages 166 - 168 in BP Annual Report and Form 20-F 2012.

 

(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 2012 - Financial statements - Notes 2, 36 and 43.

 

Provisions

 

BP has recorded provisions relating to the Gulf of Mexico oil spill in relation to environmental expenditure, spill response costs, litigation and claims, and Clean Water Act penalties. Movements in each class of provision during the first quarter of 2013 are presented in the table below.

 





Spill 

Litigation 

Clean Water 






Environmental

response 

and claims 

Act penalties 

Total 


$ million 









At 1 January 2013


 1,862

 345

 9,483

 3,510

 15,200


Increase (decrease) in provision -








 items not covered by the trust fund


(24)

 6

 8

- 

(10)


Increase in provision - items








 covered by the trust fund


 24

- 

 468

- 

 492


Unwinding of discount


 1

- 

- 

- 

 1


Reclassified to other payables


- 

- 

(3,933)

- 

(3,933)


Utilization

- paid by BP


(23)

(31)

(124)

- 

(178)


                

- paid by the trust fund


(98)

- 

(680)

- 

(778)


At 31 March 2013


 1,742

 320

 5,222

 3,510

 10,794


Of which

- current


 911

 243

 3,656

- 

 4,810


               

- non-current


 831

 77

 1,566

 3,510

 5,984


Of which

- payable from









    the trust fund


 1,363

 47

 4,662

- 

 6,072

 

Environmental

The environmental provision includes amounts for BP's commitment to fund the Gulf of Mexico Research Initiative, estimated natural resource damage (NRD) assessment costs and early NRD restoration projects under the $1-billion framework agreement.

 

Spill response

The spill response provision relates primarily to ongoing patrolling and maintenance of the shoreline.

 

Litigation and claims

The litigation and claims provision includes amounts that can be reliably estimated for the future cost of settling claims by individuals and businesses for removal costs, 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"), other than as noted below, and claims by state and local government entities for removal costs, physical damage to real or personal property, loss of government revenue and increased public services costs ("State and Local Claims") under OPA 90, except as described under Contingent liabilities below. Claims administration costs and legal fees have also been provided for.

 

 

Top of page 26

Notes

 

BP has provided for its best estimate of the cost associated with the PSC settlement agreements with the exception of business economic loss claims.  BP has provided for business economic loss claims for which eligibility notices have been issued by the DHCSSP but has concluded that no reliable estimate can be made of business economic loss claims not yet received or processed by the DHCSSP. Further details are provided below.

 

The provision for claims under the PSC settlement was increased by $0.5 billion during the first quarter of 2013 to reflect additional eligibility notices issued by the DHCSSP for business economic loss claims received and processed subsequent to finalizing BP Annual Report and Form 20-F 2012 which was published in early March 2013.

 

As disclosed in BP Annual Report and Form 20-F 2012, as part of its monitoring of payments made by the DHCSSP during 2012, BP identified multiple business economic loss claim determinations that appeared to result from an interpretation of the EPD Settlement Agreement by the claims administrator that BP believes was incorrect. On 5 March 2013, the District Court affirmed the claims administrator's interpretation of the agreement and rejected BP's position as it relates to business economic loss claims and BP's related motions for injunctions and other relief. BP has subsequently appealed the District Court's 5 March 2013 rulings to the Fifth Circuit. On 23 April 2013, the Fifth Circuit denied BP's motion for a stay pending appeal, but granted BP's request for expedited consideration. For further information, see Legal proceedings on pages 32 - 33 in this report.

 

Given the inherent uncertainty that currently exists as to the interpretation of the EPD Settlement Agreement which is subject to ongoing appeals, the lack of sufficient claims data from which to extrapolate any reliable trends and the higher number of claims received and higher average claims payments than previously assumed by BP, which may or may not continue, management continues to believe that no reliable estimate can be made of any business economic loss claims not yet received or processed by the DHCSSP. A provision will be re-established when a reliable estimate can be made of the liability as explained more fully below.

 

BP's current estimate of the total cost of those elements of the PSC settlement that can be estimated reliably, which excludes any future business economic loss claims not yet received or processed by the DHCSSP, is $8.2 billion. If BP is successful in challenging the claims administrator's interpretation of the EPD Settlement Agreement, the total estimated cost of the PSC settlement will, nevertheless, be significantly higher than the current estimate of $8.2 billion because business economic loss claims not yet received or processed are not reflected in the current estimate and the average payments per claim determined so far are higher than anticipated. If BP is not successful in challenging the claims administrator's interpretation of the EPD Settlement Agreement, a further significant increase to the total estimated cost of the PSC settlement will be required. BP is continuing to evaluate available legal options to challenge the District Court's rulings. However, there can be no certainty as to how the dispute will ultimately be resolved or determined. To the extent that there are insufficient funds available in the Trust, payments under the PSC settlement will be made by BP directly and charged to the income statement. The PSC settlement is uncapped except for economic loss claims related to the Gulf seafood industry.

 

The provision recognized for litigation and claims includes an estimate for State and Local Claims. Although the provision recognized is BP's current reliable best estimate of the amount required to settle these obligations, significant uncertainty exists in relation to the outcome of any litigation proceedings and the amount of claims that will become payable by BP. See Legal proceedings on pages 32 - 33 and Contingent liabilities below for further details.

 

Clean Water Act penalties

A provision was recognized in 2010 for the estimated civil penalties for strict liability under the Clean Water Act, which are based on a specified range per barrel of oil released. No adjustments have been made subsequently to this estimate. The penalty rate per barrel used to calculate the provision is based upon the company's conclusion, amongst other things, that it did not act with gross negligence or engage in wilful misconduct.

 

Provision movements and analysis of income statement charge

During the first quarter of 2013, a net increase in the provision for the estimated cost of the settlement with the PSC and various other costs of $482 million was recognized. In addition, the provisions relating to the agreement with the US government to resolve all criminal claims and relating to the Gulf Region Health Outreach Program, amounting to $3.9 billion, have been reclassified to payables during the quarter, upon court approval. Utilization of the provision of $956 million during the first quarter 2013 included $629 million paid out under the PSC settlement from the Trust.

 

The total charge in the income statement is analysed in the table below.

 



First




quarter




2013


$ million 




Net increase in provisions


 482


Recognition of reimbursement asset


(492)


Other net costs charged (credited) directly to the income statement


 32


Loss before interest and taxation


 22


Finance costs


 10


Loss before taxation


 32

 

 

Top of page 27

Notes

 

2.       Gulf of Mexico oil spill (continued)

 

Items not provided for and uncertainties

BP considers that it is not possible, at this time, to measure reliably any obligation in relation to Natural Resource Damages claims under OPA 90 (other than the estimated costs of the assessment phase and the costs of early restoration agreements as described above under Provisions). It is not possible, at this time, to measure reliably other obligations arising from the incident, namely any obligation in relation to Natural Resource Damages claims (except for the estimated costs of the assessment phase and the costs relating to early restoration agreements referred to above), claims asserted in civil litigation including any further litigation through excluded parties from the PSC settlement including as set out in Legal proceedings on pages 32 - 33, the cost of business economic loss claims under the PSC settlement not yet received or processed by the DHCSSP, any further obligation that may arise from state and local government submissions under OPA 90 and any obligation in relation to other potential private or governmental litigation, fines or penalties (except for the Clean Water Act civil penalty claims and governmental claims as described above under Provisions), nor is it practicable to estimate their magnitude or possible timing of payment. These items are therefore disclosed as contingent liabilities - see below.

 

Significant uncertainties exist in relation to the amount of claims that are to be paid and will become payable, including claims payable under the DHCSSP and State and Local Claims. There is significant uncertainty in relation to the amounts that ultimately will be paid in relation to current claims, and the number, type and amounts payable for claims not yet reported. In addition, there is further uncertainty in relation to interpretations of the claims administrator regarding the protocols, relating to business economic loss claims, (which, as set out more fully in Legal Proceedings on pages 32- 33, are subject to appeal) under the EPD Settlement Agreement and judicial interpretation of these protocols, and the outcomes of any further litigation including in relation to potential opt-outs from the settlement or otherwise.

 

Furthermore, significant uncertainty exists in relation to the amount of fines that will ultimately be levied on BP (including any determination of BP's culpability based on any findings of negligence, gross negligence or wilful misconduct), the outcome of litigation and arbitration proceedings, and any costs arising from any longer-term environmental consequences of the oil spill, which will also impact upon the ultimate cost for BP. The amount and timing of any amounts payable could also be impacted by any further settlements which may or may not occur.

 

Further information on provisions is provided in BP Annual Report and Form 20-F 2012 - Financial statements -Note 36.

 

Contingent liabilities

 

Since 6 March 2013, BP has been named as a defendant in more than 2,200 additional civil lawsuits brought by individuals, corporations and government entities related to the incident, and further actions are likely to be brought. See Legal proceedings on pages 32 - 33 for further information. Until further fact and expert disclosures occur, court rulings clarify the venue for these lawsuits and the issues in dispute, liability and damage trial activity nears or progresses, or other actions such as possible settlements occur, it is not possible given these uncertainties to arrive at a range of outcomes or a reliable estimate of the liabilities that may accrue to BP in connection with or as a result of these lawsuits. Therefore no amounts have been provided for these additional civil lawsuits as at 31 March 2013. 

 

See also BP Annual Report and Form 20-F 2012 - Financial statements - Note 43. At 31 March 2013, the magnitude and timing of all possible obligations in relation to the Gulf of Mexico oil spill continue to be subject to a very high degree of uncertainty. Furthermore, for those items where a provision has been recorded, significant uncertainty also exists in relation to the ultimate exposure and cost to BP.

 

 

Top of page 28

Notes

 

3.       Disposal of TNK-BP and investment in Rosneft

 

Disposal of TNK-BP

 

In BP Annual Report and Form 20-F 2012 the transaction to sell BP's investment in TNK-BP and acquire an investment in Rosneft was described as consisting of three tranches under which BP would receive $25.4 billion (including the $0.7 billion dividend received from TNK-BP in December 2012) and Rosneft shares representing a 3.04% stake in Rosneft; BP would then use $4.8 billion of the cash to acquire a further 5.66% in Rosneft from Rosneftegaz and $8.3 billion to acquire a further 9.80% stake in Rosneft from a Rosneft subsidiary. On completion, the transactions between BP, Rosneft and the Rosneft subsidiary were instead settled on a net basis, so that BP received the 9.80% stake in Rosneft directly rather than receiving and immediately paying $8.3 billion in cash. The net result was the same.

 

The gain on disposal of BP's investment in TNK-BP, recognized in the TNK-BP segment, was $12.5 billion as shown in the table below.

 



$ billion


Agreed cash disposal proceeds


25.4


Amount settled net in Rosneft shares (9.80% stake)


(8.3)


TNK-BP dividend received by BP in December 2012


(0.7)


Interest on cash proceeds


0.3


Disposal proceeds received in cash in the quarter


16.7


Shares in Rosneft received (9.80% and 3.04% stake)


10.8


Consideration received


27.5


Less: carrying value of investment in TNK-BP


(12.5)




15.0


Deferral of gain


(3.0)


Gain on existing 1.25% investment in Rosneft


0.5


Gain on disposal of investment in TNK-BP


12.5

 

Disposal proceeds of $4.9 billion were used to purchase the 5.66% stake in Rosneft from Rosneftegaz ($4.8 billion described above plus $0.1 billion of interest). The net cash inflow relating to the transaction included in net cash flow from investing activities in the cash flow statement was $11.8 billion.

 

Part of the gain arising on the disposal, amounting to $3.0 billion, has been deferred due to BP selling its investment in TNK-BP to Rosneft, which in turn is now accounted for by BP as an associate. The deferred gain will be released to BP's income statement over time as the TNK-BP assets are depreciated or amortized.

 

Investment in Rosneft

 

BP's investment in Rosneft is included in the balance sheet within investments in associates. The investment is measured at cost less the deferred gain described above (in Roubles), plus post-acquisition changes in BP's share of Rosneft's net assets, and amounted to $13.0 billion at 31 March 2013 as shown in the table below.

 



$ billion


Shares in Rosneft received


10.8


Shares purchased from Rosneftegaz


4.9


Value of agreements to purchase Rosneft shares accounted for as derivatives


(0.7)


Deferred gain


(3.0)


Amount included in capital expenditure


11.9


Value of existing 1.25% investment in Rosneft


1.0


Investment in Rosneft on completion


12.9


BP's share of Rosneft's post-acquisition earnings after tax


0.1


Investment in Rosneft at 31 March 2013


13.0

 

During the quarter a charge of $2.1 billion (fourth quarter 2012 $1.4 billion credit) was recognized in other comprehensive income in relation to the agreements which were accounted for as derivatives in a cash flow hedge. The resulting cumulative charge of $0.7 billion recognized in other comprehensive income would only be recognized in the income statement if the investment in Rosneft were either sold or impaired. The cash flow hedge derivatives were valued using the quoted Rosneft share price at the time the deal completed, of $7.60 per share. BP's share of the fair value of Rosneft's identifiable net assets, and the consequent impact on the depreciation and amortization recognized via equity accounting in BP's income statement, are provisional at 31 March, and will be finalized during the remainder of 2013.

 

 

Top of page 29

Notes

 

4.       Non-current assets held for sale

 

As a result of the group's disposal programme, various assets, and associated liabilities, have been presented as held for sale in the group balance sheet at 31 March 2013. The carrying amount of the assets held for sale is $4,947 million, with associated liabilities of $722 million.

 

The majority of the transactions noted below are subject to post-closing adjustments, which may include adjustments for working capital and adjustments for profits attributable to the purchaser between the agreed effective date and the closing date of the transaction. Such post-closing adjustments may result in the final amounts received by BP from the purchasers differing from the disposal proceeds noted below.

 

The sale of BP's investment in TNK-BP completed during the quarter, as described in Note 3, as did the sale of the Texas City refinery. The assets held for sale at 31 March 2013 are described below.

 

Upstream

 

On 28 November 2012, BP announced that it had agreed to sell its interests in a number of central North Sea oil and gas fields to TAQA for $1,058 million plus future payments which, dependent on oil price and production, are currently expected to exceed $250 million after tax. The assets included in the sale are BP's interests in the BP-operated Maclure, Harding and Devenick fields and non-operated interests in the Brae complex of fields and the Braemar field. The assets and associated liabilities are classified as held for sale in the group balance sheet at 31 March 2013. The sale is subject to third-party and regulatory approvals and is expected to complete this year.

 

Downstream

 

On 13 August 2012, BP announced that it had reached an agreement to sell its Carson refinery in California and related assets in the region, including marketing and logistics assets, to Tesoro Corporation for $2.5 billion, including the estimated value of hydrocarbon inventories of $1.3 billion. The assets, and associated liabilities, of the refinery and related assets are classified as held for sale in the group balance sheet at 31 March 2013. Completion is subject to regulatory and other approvals, and the transaction is expected to close by the middle of 2013.

 

 

5.       Sales and other operating revenues

 



First

Fourth

First




quarter

quarter

quarter




2013

2012

2012


$ million






By business






Upstream


 18,218

 19,429

 19,339


Downstream


 86,784

 86,142

 86,688


Other businesses and corporate


 420

 570

 428




 105,422

 106,141

 106,455








Less: sales and other operating revenues between businesses






Upstream


 10,861

 11,800

 10,657


Downstream


 240

 187

 746


Other businesses and corporate


 214

 244

 174




 11,315

 12,231

 11,577








Third party sales and other operating revenues






Upstream


 7,357

 7,629

 8,682


Downstream


 86,544

 85,955

 85,942


Other businesses and corporate


 206

 326

 254


Total third party sales and other operating revenues


 94,107

 93,910

 94,878








By geographical area






US


 35,281

 33,648

 34,502


Non-US


 68,316

 69,069

 70,403




 103,597

 102,717

 104,905


Less: sales and other operating revenues between areas


 9,490

 8,807

 10,027




 94,107

 93,910

 94,878

 

 

Top of page 30

Notes

 

6.       Production and similar taxes

 



First

Fourth

First




quarter

quarter

quarter




2013

2012

2012


$ million






US


 372

 438

 490


Non-US


 1,623

 1,635

 1,856




 1,995

 2,073

 2,346

 

 

7.       Earnings per share and shares in issue

 

Basic earnings per ordinary share (EpS) amounts are calculated by dividing the profit or loss for the period attributable to ordinary shareholders by the weighted average number of ordinary shares outstanding during the period. During the quarter the company repurchased 21.4 million ordinary shares at a cost of $151 million as part of the share repurchase programme announced on 22 March 2013. The number of shares in issue is reduced when shares are repurchased, but is not reduced in respect of the period-end commitment to repurchase shares subsequent to the end of the period, for which an amount of $699 million has been accrued at 31 March 2013. The calculation of EpS is performed separately for each discrete quarterly period, and for the year-to-date period. As a result, the sum of the discrete quarterly EpS amounts in any particular year-to-date period may not be equal to the EpS amount for the year-to-date period.

 

For the diluted EpS calculation the weighted average number of shares outstanding during the period is adjusted for the number of shares that are potentially issuable in connection with employee share-based payment plans using the treasury stock method. If the inclusion of potentially issuable shares would decrease the loss per share, the potentially issuable shares are excluded from the diluted EpS calculation.

 



First

Fourth

First




quarter

quarter

quarter




2013

2012

2012


$ million






Results for the period






Profit for the period attributable to BP shareholders


 16,863

 1,488

 5,767


Less: preference dividend


- 

 1

- 


Profit attributable to BP ordinary shareholders


 16,863

 1,487

 5,767


Inventory holding (gains) losses, net of tax


(267)

 521

(986)


RC profit attributable to BP ordinary shareholders


 16,596

 2,008

 4,781


Net (favourable) unfavourable impact of non-operating items






  and fair value accounting effects, net of tax


(12,381)

 1,843

(130)


Underlying RC profit attributable to BP shareholders


 4,215

 3,851

 4,651








Number of shares (thousand)(a)






Basic weighted average number of shares outstanding


 19,147,437

 19,071,754

 18,976,062


ADS equivalent


 3,191,239

 3,178,626

 3,162,677








Weighted average number of shares outstanding used






  to calculate diluted earnings per share


 19,247,671

 19,177,841

 19,240,896


ADS equivalent


 3,207,945

 3,196,307

 3,206,816








Shares in issue at period-end


 19,153,586

 19,119,757

 19,016,208


ADS equivalent


 3,192,264

 3,186,626

 3,169,368

 

(a)

Excludes treasury shares and the shares held by the Employee Share Ownership Plans (ESOPs) and includes certain shares that will be issued in the future under employee share plans.

 

 

Top of page 31

Notes

 

8.        Analysis of changes in net debt(a) 

 



First

Fourth

First




quarter

quarter

quarter




2013

2012

2012


$ million






Opening balance






Finance debt


 48,800

 49,071

 44,208


Less: cash and cash equivalents


 19,635

 16,174

 14,177


Less: FV asset of hedges related to finance debt


 1,700

 1,572

 1,133


Opening net debt


 27,465

 31,325

 28,898


Closing balance






Finance debt


 46,425

 48,800

 46,471


Less: cash and cash equivalents(b)


 27,679

 19,635

 14,267


Less: FV asset of hedges related to finance debt


 1,083

 1,700

 1,224


Closing net debt


 17,663

 27,465

 30,980


Decrease (increase) in net debt


 9,802

 3,860

(2,082)


Movement in cash and cash equivalents






  (excluding exchange adjustments)


 8,293

 3,392

(28)


Net cash outflow (inflow) from financing






  (excluding share capital and dividends)


 1,716

 1,229

(2,066)


Movement in finance debt relating to investing activities(c)


- 

(602)

-   


Other movements


(126)

(93)

(7)


Movement in net debt before exchange effects


 9,883

 3,926

(2,101)


Exchange adjustments


(81)

(66)

 19


Decrease (increase) in net debt


 9,802

 3,860

(2,082)

 

(a)

Net debt is a non-GAAP measure.

(b)

The cash balance at 31 December 2012 included $709 million relating to the dividend received from TNK-BP in the fourth quarter 2012 which met the criteria to be treated as restricted cash until completion of the sale of BP's interest in TNK-BP to Rosneft. This is no longer restricted because the transaction completed in March 2013.

(c)

During the first quarter 2013 no disposal transactions were completed in respect of which deposits had been received in advance (fourth quarter 2012 and first quarter 2012 nil). No deposits were received in the first quarter 2013, in respect of disposals expected to complete within the next year (fourth quarter 2012 $632 million, first quarter 2012 nil). In the fourth quarter 2012, deposits of $30 million were repaid in respect of assets no longer held for sale. At 31 March 2013, finance debt includes $632 million deposits received in advance relating to disposal transactions ($632 million at 31 December 2012, $30 million at 31 March 2012).

 

At 31 March 2013, $141 million of finance debt ($142 million at 31 December 2012 and $136 million at 31 March 2012) was secured by the pledging of assets. The remainder of finance debt was unsecured.

 

During the first quarter the company has renegotiated its committed bank standby facilities and by the end of the quarter had in place five-year facilities totalling $6.9 billion, available to draw and repay until early March 2018. The facilities replace previous similar arrangements having a 3-year duration that were in place until mid-March 2014 and totalling $6.8 billion at 31 December 2012. No drawings have ever been made against any of the standby facilities.

 

 

9.       Inventory valuation

 

A provision of $194 million was held at 31 March 2013 ($124 million at 31 December 2012) to write inventories down to their net realizable value. The net movement in the provision during the first quarter 2013 was an increase of $70 million (fourth quarter 2012 was a decrease of $16 million and first quarter 2012 was a decrease of $38 million).

 

 

10.     Statutory accounts

 

The financial information shown in this publication, which was approved by the Board of Directors on 29 April 2013, is unaudited and does not constitute statutory financial statements. BP Annual Report and Form 20-F 2012 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 32

Legal proceedings

 

The following discussion sets out the material developments in the group's material legal proceedings during the recent period. For a full discussion of the group's material legal proceedings, see pages 162 - 171 of BP Annual Report and Form 20-F 2012.

 

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

 

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

 

As disclosed in BP Annual Report and Form 20-F 2012, on 25 February 2013, the first phase of a Trial of Liability, Limitation, Exoneration and Fault Allocation commenced in MDL 2179. The presentation of evidence in the first trial phase, which completed on 17 April 2013, addressed issues arising out of the conduct of various parties allegedly relevant to the loss of well control at the Macondo well, the ensuing fire and explosion on the Deepwater Horizon on 20 April 2010, the sinking of the vessel on 22 April 2010 and the initiation of the release of oil from the Deepwater Horizon or the Macondo well during those time periods, including whether BP or any other party was grossly negligent. BP is not currently aware of the timing of the court's ruling in respect of issues addressed in the first trial phase. The second trial phase is scheduled to commence on 16 September 2013, and will address the amount of oil that was spilled as a result of the Incident and source control efforts. For further information, see page 162 of BP Annual Report and Form 20-F 2012.

 

Additional civil lawsuits and related OPA 90 matters

 

Since 6 March 2013, BP has been among the companies named as defendants in more than 2,200 additional civil lawsuits related to the Incident which have been brought in US federal and state courts, and further actions are likely to be brought. Plaintiffs in these lawsuits include individuals, corporations, certain States and local government entities and a foreign government. While BP is currently evaluating these lawsuits, preliminary review suggests that the vast majority of the lawsuits assert claims under the Oil Pollution Act of 1990 (OPA 90). Certain of these lawsuits relate to earlier submissions of claims to BP under OPA 90 by certain States and local governments, as disclosed in our Group results fourth quarter and full year, dated 5 February 2013 and BP Annual Report and Form 20-F 2012. BP believes that claimants in these new additional civil lawsuits may have sought to file these lawsuits in advance of the third anniversary of the Incident on 20 April 2013, on which date certain OPA 90 claims may have been subject to time bar challenges by BP under OPA 90's three-year statute of limitations. The new lawsuits also assert various other claims (including, but not limited to, claims for economic loss and/or real property damage and under maritime law, state law and the Declaratory Judgment Act) as well as seeking various remedies including economic and compensatory damages, punitive damages, removal costs and natural resource damages. Many of the lawsuits assert claims which are excluded from the Economic and Property Damages Settlement Agreement, including claims for recovery for losses allegedly resulting from the 2010 federal deepwater drilling moratoria and/or the related permitting process. BP intends to apply to have these lawsuits consolidated with MDL 2179. For further information, see Contingent liabilities in Note 2 on page 27.

 

As disclosed in BP Annual Report and Form 20-F 2012, the States of Alabama, Mississippi, Louisiana and Florida and various local governments have submitted or asserted claims to BP under OPA 90 for alleged losses as a result of the Incident. As disclosed above, since 6 March 2013, certain of these States and local governments (including the states of Alabama, Florida and Mississippi) have filed civil lawsuits that pertain to claims asserted by them under their earlier OPA 90 submissions to BP. 

 

Plaintiffs' Steering Committee (PSC) Settlements

 

As part of its monitoring of payments made by the court-supervised claims processes operated by the Deepwater Horizon Court Supervised Settlement Program (DHCSSP) for the Economic and Property Damages Settlement between BP and the PSC, BP identified multiple business economic loss claim determinations that appeared to result from an interpretation of the Economic and Property Damages Settlement Agreement by that settlement's claims administrator that BP believes was incorrect. This interpretation produced a higher number and value of awards than the interpretation BP used in making its initial estimate of the total cost of the Economic and Property Damages Settlement. Pursuant to the mechanisms in the Economic and Property Damages Settlement Agreement, the claims administrator sought clarification from the federal district court in New Orleans (the District Court) on this matter and on 30 January 2013, the District Court initially upheld the claims administrator's interpretation of the agreement. On 6 February 2013, the District Court reconsidered and vacated its ruling of 30 January 2013 and stayed the processing of certain types of business economic loss claims. The District Court lifted the stay on 28 February 2013. On 5 March 2013, the District Court affirmed the claims administrator's interpretation of the agreement and rejected BP's position as it relates to business economic loss claims. Business economic loss claims have continued to be paid at a higher average amount than the amount BP assumed in determining its initial estimate of the total cost.

 

 

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Legal proceedings (continued)

 

On 15 March 2013, BP filed an emergency motion in MDL 2179 seeking a preliminary injunction against the DHCSSP and the claims administrator to enjoin payments and awards based on the disputed interpretation of the Economic and Property Damages Settlement Agreement. That same day BP also filed a substantially identical motion and complaint with the District Court in a separate action against the DHCSSP and the claims administrator seeking a similar preliminary injunction, a permanent injunction against the DHCSSP and the claims administrator from acting upon the disputed interpretation of the agreement, as well as other relief. On 25 March 2013, the District Court granted the Economic and Property Damages Settlement Class leave to intervene in the new action. On 4 April 2013, BP filed a motion for preliminary injunction or stay pending appeal with the District Court. On 5 April 2013, after holding a public hearing, the District Court denied BP's motions and granted the DHCSSP's motion to dismiss the separate action BP had brought against it. On 9 April 2013, the District Court issued an order declaring that BP, the Economic and Property Damages Settlement Class and the DHCSSP (along with its internal appeal panellists) must follow and are bound by (i) the 5 March 2013 ruling; (ii) the 12 December 2012 ruling of the District Court regarding non-profit entity revenue and (iii) an analysis of causation as set forth in paragraph 2 of the Claims Administrator's "Announcement of Policy Decisions Regarding Claims Administration", dated 10 October 2012.

 

BP continues to strongly disagree with the District Court ruling of 5 March 2013 (including its confirmation in the District Court's order on 9 April 2013) and the current implementation of the agreement by the claims administrator. BP appealed the District Court's 5 March 2013 and 5 April 2013 rulings to the US Court of Appeals for the Fifth Circuit (the Fifth Circuit), and filed motions for injunctions and stays pending appeal to prevent the claims administrator from paying business economic loss claims pursuant to his interpretation. BP also moved to consolidate and expedite consideration of its appeals, proposing that briefing be completed in the Fifth Circuit by 31 May 2013. On 22 April 2013, the Fifth Circuit denied BP's motions for injunctions and stays pending appeal, but granted BP's motion to expedite the appeal. BP is continuing to evaluate other available legal options to challenge the District Court rulings.

 

For information about BP's current estimate of the total cost of the PSC settlements, see Note 2. For further information about the PSC settlements, see pages 166 - 168 of BP Annual Report and Form 20-F 2012.

 

MDL 2185 and other securities-related litigation

 

From July 2012 to March 2013, eleven cases were filed in Texas state and federal courts (later consolidated into eight actions) by pension or investment funds or advisors against BP entities and current and former officers, asserting state law and other claims and seeking damages for alleged losses that those funds suffered because of their purchases of BP ordinary shares and/or ADSs. All of the cases have been transferred to the judge presiding over the federal multi-district litigation proceeding in Houston (MDL 2185). Oral argument on a motion to dismiss three of the eleven cases is scheduled for 10 May 2013.

 

On 5 July 2012, the judge in MDL 2185 issued a decision granting a motion to dismiss, for lack of personal jurisdiction, the lawsuit against BP p.l.c. for cancelling its dividend payment in June 2010. On 10 August 2012, the plaintiffs filed an amended complaint, which BP moved to dismiss on 9 October 2012. On 12 April 2013, the judge granted BP's motion to dismiss.

 

For further information about MDL 2185 and other securities-related litigation, see pages 162 - 163 of BP Annual Report and Form 20-F 2012.

 

 

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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, certain statements regarding the expected quarterly dividend payment; BP's intentions in respect of its announced share repurchase programme, including the total quantum of shares expected to be purchased in connection therewith; the expected level of reported production in the second quarter of 2013; the expected level of Upstream costs in the second quarter of 2013; expectations regarding the level of oil production at the Valhall field in the second half of 2013; the timing of and prospects for the decision regarding the pipeline for transportation of Shah Deniz Stage 2 gas to Europe; the expected timing of the commissioning of the new crude unit at the Whiting refinery and the completion of the Whiting refinery modernization project; the expected timing of completion of planned and announced divestments, including the disposal of BP's interest in the Carson refinery and related assets; prospects for BP-Husky Refining LLC's new naphtha reformer at the Toledo refinery; the expected level of petrochemicals margins in 2013; BP's plans to report inventory holding gains or losses and non-operating items in respect of the Rosneft segment later in 2013; BP's intentions to market its wind business for sale; the expected quantum of funds that could be provided in subsequent periods for items covered by the $20-billion Trust fund with no net impact on the income statement; and certain statements regarding the anticipated timing of, prospects for and BP's prospective responses to legal and trial proceedings, court decisions, potential investigations and civil actions by regulators, government entities and/or other entities or parties ; 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. Actual results may differ from those expressed in such statements, depending on a variety of factors including the timing of bringing new fields onstream; the timing and level of turnaround activity; the timing, quantum and nature of divestments; the receipt of relevant third-party and/or regulatory approvals; future levels of industry product supply; demand and pricing; OPEC quota restrictions; PSA effects; operational problems; general economic conditions; 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; the impact on our reputation following the Gulf of Mexico oil spill; exchange rate fluctuations; development and use of new technology; the success or otherwise of partnering; the actions of competitors, trading partners, creditors, rating agencies and others; natural disasters and adverse weather conditions; changes in public expectations and other changes to business conditions; wars and acts of terrorism or sabotage; and other factors discussed under "Risk factors" in BP Annual Report and Form 20-F 2012 as filed with the US Securities and Exchange Commission.

 

 

 

 

 

 

 

 

 

 

 

Contacts

 

London

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David Nicholas

Scott Dean


+44 (0)20 7496 4708

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Investor Relations

Jessica Mitchell

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+44 (0)20 7496 4962

+1 281 366 3123

 

 


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