Form 6-K
Table of Contents

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

Form 6-K

 

 

Report of Foreign Private Issuer

Pursuant to Rule 13a-16 or 15d-16 of

the Securities Exchange Act of 1934

for the period ended 30 June 2011

Commission File Number 1-06262

 

 

BP p.l.c.

(Translation of registrant’s name into English)

 

 

1 ST JAMES’S SQUARE, LONDON, SW1Y 4PD, ENGLAND

(Address of principal executive offices)

 

 

Indicate by check mark whether the registrant files or will file annual reports under cover of Form 20-F or Form 40-F.

Form 20-F  x            Form 40-F  ¨

Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(1):  ¨

Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(7):  ¨

Indicate by check mark whether by furnishing the information contained in this Form, the registrant is also thereby furnishing the information to the Commission pursuant to Rule 12g3-2(b) under the Securities Exchange Act of 1934.

Yes  ¨             No  x

If “Yes” is marked, indicate below the file number assigned to the registrant in connection with Rule 12g3-2(b): 82-            

THIS REPORT ON FORM 6-K SHALL BE DEEMED TO BE INCORPORATED BY REFERENCE IN THE PROSPECTUS INCLUDED IN THE REGISTRATION STATEMENT ON FORM F-3 (FILE NO. 333-157906) OF BP CAPITAL MARKETS p.l.c. AND BP p.l.c.; THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-79399) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-67206) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-103924) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-102583) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-123482) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-123483) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-131583) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-131584) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-132619) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-146868) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-146870) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-146873) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-149778) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-173136) OF BP p.l.c., AND TO BE A PART THEREOF FROM THE DATE ON WHICH THIS REPORT IS FURNISHED, TO THE EXTENT NOT SUPERSEDED BY DOCUMENTS OR REPORTS SUBSEQUENTLY FILED OR FURNISHED.

 

 

 


Table of Contents

BP p.l.c. AND SUBSIDIARIES

FORM 6-K FOR THE PERIOD ENDED 30 JUNE 2011(a)

 

          Page  

1.

  

Management’s Discussion and Analysis of Financial Condition and Results of Operations for the period January-June 2011(b)

     3 –13, 20 –22  

2.

  

Consolidated Financial Statements including Notes to Consolidated Financial Statements for the period January-June 2011

     14 – 19, 23 – 38  

3.

  

Cautionary statement

     13  

4.

  

Principal risks and uncertainties

     39 – 45  

5.

  

Legal proceedings

     46 – 49  

6.

  

Signatures

     50  

7.

  

Exhibit 99.1: Computation of Ratio of Earnings to Fixed Charges

     51  
  

Exhibit 99.2: Capitalization and Indebtedness

     52  

 

(a) In this Form 6-K, references to the first half 2011 and first half 2010 refer to the six-month periods ended 30 June 2011 and 30 June 2010 respectively. References to second quarter 2011 and second quarter 2010 refer to the three-month periods ended 30 June 2011 and 30 June 2010 respectively.
(b) This discussion should be read in conjunction with the consolidated financial statements and related notes provided elsewhere in this Form 6-K and with the information, including the consolidated financial statements and related notes, in BP’s Annual Report on Form 20-F for the year ended 31 December 2010.

 

 

2


Table of Contents

Group results second quarter and half year 2011

 

 

Second
quarter
    

Second
quarter

         First half  
2010      2011          2011     2010  
     $ million     
  73,725        101,364     Sales and other operating revenues      186,693       146,796  

 

 

    

 

 

      

 

 

   

 

 

 
  (17,150)         5,620     Profit (loss) for the period(a)      12,744       (11,071
  177        (311   Inventory holding (gains) losses, net of tax      (1,954     (304

 

 

    

 

 

      

 

 

   

 

 

 
  (16,973)         5,309     Replacement cost profit (loss)(b)      10,790       (11,375

 

 

    

 

 

      

 

 

   

 

 

 
  (91.29)         29.75     – Profit (loss) per ordinary share (cents)      67.60       (58.96
  (5.48)         1.79     – Profit (loss) per ADS (dollars)      4.06       (3.54
  (90.35)         28.10     – Replacement cost profit (loss) per ordinary share (cents)      57.23       (60.58
  (5.42)         1.69     – Replacement cost profit (loss) per ADS (dollars)      3.43       (3.63

 

 

    

 

 

      

 

 

   

 

 

 

 

 

BP’s profit for the second quarter was $5,620 million, compared with a loss of $17,150 million a year ago. For the half year, the profit was $12,744 million, compared with a loss of $11,071 million a year ago. BP’s second quarter replacement cost profit was $5,309 million, compared with a loss of $16,973 million a year ago. For the half year, replacement cost profit was $10,790 million, compared with a loss of $11,375 million a year ago. Replacement cost profit or loss for the group is a non-GAAP measure. For further information see pages 6 and 19.

 

 

The group income statement for the second quarter and half year includes pre-tax credits related to the Gulf of Mexico oil spill of $0.6 billion and $0.2 billion respectively. All amounts relating to the incident have been treated as non-operating items. For further information on the Gulf of Mexico oil spill and its consequences see pages 4 – 5, Note 2 on pages 23 – 28, Principal risks and uncertainties on pages 39 – 45 and Legal proceedings on pages 46 – 49.

 

 

Non-operating items (including amounts relating to the Gulf of Mexico oil spill) and fair value accounting effects for the second quarter, on a post-tax basis, had a net unfavourable impact of $298 million compared with a net unfavourable impact of $21,953 million in the second quarter of 2010. For the half year, the respective amounts were $191 million and $22,002 million unfavourable. Information on fair value accounting effects is non-GAAP and further details are provided on page 21.

 

 

Finance costs and net finance income or expense relating to pensions and other post-retirement benefits were $249 million for the second quarter, compared with $214 million for the same period last year. For the half year, the respective amounts were $488 million and $442 million.

 

 

The effective tax rate on the profit for the second quarter and half year was 35% and 36% respectively, compared with 30% and 27% on the loss for the equivalent periods in 2010. Excluding the impact of the Gulf of Mexico oil spill, the effective tax rate on the loss a year ago was 35% for the quarter and 34% for the half year. The effective tax rate on replacement cost profit for the second quarter and half year was 35% and 36% respectively, compared with 30% and 27% a year ago. Excluding the impact of the Gulf of Mexico oil spill, the effective tax rate on replacement cost loss a year ago was 35% for the quarter and 34% for the half year.

 

 

Including the impact of the Gulf of Mexico oil spill, net cash provided by operating activities for the quarter and half year was $7.8 billion and $10.3 billion, compared with $6.8 billion and $14.4 billion in the same periods of last year. The amounts for the quarter and half year of 2011 included net cash outflows of $1.9 billion and $4.7 billion respectively relating to the Gulf of Mexico oil spill.

 

 

Gross debt at the end of the quarter was $46.9 billion compared with $30.6 billion a year ago. The ratio of gross debt to gross debt plus equity was 30%, compared with 26% a year ago. Net debt at the end of the quarter was $27.0 billion, compared with $23.2 billion a year ago. The ratio of net debt to net debt plus equity was 20% compared with 21% a year ago. Net debt information is non-GAAP and is defined on page 7.

 

 

Total capital expenditure for the second quarter and half year was $8.2 billion and $12.2 billion respectively. Organic capital expenditure(c) in the second quarter and half year was $4.2 billion and $8.2 billion respectively. Disposal proceeds were $1.6 billion for the quarter and $2.6 billion for the half year. As at 30 June 2011, we had entered into agreements for disposals with a total value of $25 billion, against our objective of $30 billion by the end of 2011.

 

 

The quarterly dividend expected to be paid on 20 September 2011 is 7 cents per share ($0.42 per ADS). The corresponding amount in sterling will be announced on 6 September 2011. 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 www.bp.com/scrip.

 

(a) Profit (loss) attributable to BP shareholders.
(b) Replacement cost profit or loss reflects the replacement cost of supplies and is the measure of profit or loss for each operating segment that is required to be disclosed under International Financial Reporting Standards (IFRS), as explained in more detail on page 19. The replacement cost 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. Replacement cost profit or loss for the group is not a recognized GAAP measure. 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.
(c) Organic capital expenditure excludes acquisitions and asset exchanges (see page 18).

The commentaries above and following should be read in conjunction with the cautionary statement on page 13.

 

 

3


Table of Contents

Gulf of Mexico oil spill

 

Completing the response

The majority of the shoreline clean-up phase of the incident response was completed during the first quarter. During the second quarter, limited work continued to clean impacted marshes and barrier islands, and access to some areas was restricted due to wildlife breeding seasons. Patrolling is ongoing to respond to any further residual tar balls. Monitoring against established criteria continues, with the aim of assigning cleaned shorelines to a status in which no further treatment (NFT) is required. The majority of impacted shoreline has already been transitioned to NFT. Further shoreline surveys are scheduled for the fourth quarter of 2011, after the hurricane season, to identify any remaining clean-up needs.

The pilot project to retrieve remaining boom anchors from the coastal waters of Louisiana was completed and the Federal On-Scene Coordinator (FOSC) has confirmed that further action is not warranted.

Following the completion of the majority of the subsea work during the first quarter, decontamination of the Enterprise drilling rig and seabed survey work were completed during the second quarter. No further activity is planned at the well site.

The phased transition from the Gulf Coast incident management team (GC-IMT) to BP’s Gulf Coast Restoration Organization (GCRO) continues, and the response organization continues to maintain resources in line with operational requirements.

Economic restoration

A total of $6.8 billion has been paid out to fund economic and environmental restoration of the Gulf of Mexico. These payments are for claims from individuals, businesses and government entities. $0.3 billion of this is for natural resource damage assessment.

Trust update

During the first half, BP made two scheduled contributions totalling $2.5 billion to the Deepwater Horizon Oil Spill Trust fund. The Trust was established in 2010 to satisfy legitimate individual and business claims administered by the Gulf Coast Claims Facility (GCCF), state and local government claims resolved by BP, final judgments and settlements, state and local response costs, and natural resource damages (NRD) and related costs. In early July, BP received a $1.1 billion settlement payment from MOEX which was also paid into the Trust.

Payments from the Trust during the second quarter and half year respectively totalled $1.0 billion and $2.1 billion, of which in the second quarter $873 million was paid through the GCCF to individual and business claimants, $87 million for NRD assessment costs, $17 million in relation to state and local government claims, and $33 million for other resolved items. As of 30 June 2011, the cumulative amount paid from the Trust since its inception was $5.1 billion and BP’s cumulative contributions to the Trust were $7.5 billion.

On 21 April 2011, BP announced a commitment of up to $1 billion for projects that will restore injured natural resources in the Gulf at the earliest opportunity. These projects will undergo public review before they are funded.

Claims update

As of 30 June 2011, a total of $6.3 billion had been paid for individual, business and government claims. This includes amounts paid directly by BP prior to the establishment of the Trust.

During the emergency advance phase in 2010, the GCCF paid 169,172(a) claimants amounts totalling $2.6 billion. In the first quarter of 2011, the GCCF issued its protocol for the resolution and finalization of claims allowing claimants submitting legitimate claims to elect to (i) receive interim payments for substantiated past losses, or (ii) receive an offer for full and final settlement payment and release, with certain exceptions, their right to sue all potentially liable entities including BP. During the second quarter, an additional 40,152 claimants filed claims at this second and final phase, taking the total number of claimants in this phase to 308,112 as of 30 June 2011. Of these, 150,672 claims have been paid and finalized for $1.7 billion, 88,873 have been denied by the GCCF, 8,776 have been determined to have no loss and 559 claims were withdrawn. The claims of the remaining 59,232 claimants have not yet been finalized and are at various stages of the GCCF’s claims review process. Claimants electing to receive interim payments have been paid $208 million. As of 30 June 2011, $5.0 billion had been paid either by the GCCF or by BP to individual and business claimants.

BP received 76 new claims from government entities during the second quarter, and has processed 88% of the total 965 claims filed. Government entities have received $1.3 billion in payments for 797 claims since the incident occurred. The remaining government claims are at various stages of the claims process.

Following the first-quarter agreement with the state of Alabama to provide $16 million for tourism promotion, BP completed similar agreements during the second quarter with the states of Florida and Mississippi for $30 million and $16 million respectively. Discussions are currently under way with the state of Mississippi regarding contributions for seafood testing and marketing.

 

(a) Number of claimants updated from 169,005 as published in our first-quarter results announcement, reflecting a small number of payments made in the second quarter 2011 as a result of the resolution of outstanding claims from the emergency advance phase. At the end of the second quarter 2011, 273 emergency advance phase claims remained unresolved.

 

 

4


Table of Contents

Gulf of Mexico oil spill (continued)

 

Environmental restoration

Last year, BP announced the creation of the independent Gulf of Mexico Research Initiative (GRI), a ten-year, $500-million scientific research programme directed at studying the potential environmental and public health impacts of the Deepwater Horizon accident. The master research agreement was signed in March 2011 and three Requests for Proposals (RFPs) from research consortia or individual researchers are planned for this year, two of which were issued during the second quarter.

Financial update

In the second quarter we recognized a $0.6 billion reduction in the pre-tax charge for the incident. This reflects the settlements with MOEX USA Corporation, the parent company of one of our partners in the MC252 exploration block, and Weatherford, a contractor on the Macondo well, partially offset by an incremental charge for spill response costs including provisioning for shoreline patrolling and maintenance costs, plus a charge for the ongoing quarterly expenses of the Gulf Coast Restoration Organization. For the half year, the reduction in the pre-tax charge was $0.2 billion. In 2010, the pre-tax charge recognized was $40.9 billion, which included the $20-billion Trust commitment.

Under the above settlement agreements, MOEX USA Corporation paid BP $1.1 billion in early July, which was subsequently paid to the Trust, and Weatherford have paid BP $75 million which will also be contributed to the $20-billion Trust.

The total amounts that will be paid by BP in relation to all obligations relating to the incident are subject to significant uncertainty as described further in Note 2 on pages 23 – 28. Also see Note 2, on page 28 under Contingent assets, for information on partner recovery.

Legal proceedings and investigations

See Gulf of Mexico oil spill on pages 34 – 39 of BP’s Annual Report and Form 20-F 2010 and Legal proceedings on pages 46 – 49 herein for details of legal proceedings, including external investigations relating to the incident.

 

 

5


Table of Contents

Analysis of replacement cost profit (loss) before interest and tax and reconciliation to profit (loss) for the period

 

 

Second
quarter
     Second
quarter
         First half  
2010      2011          2011     2010  
     $ million     
  6,244        6,614     Exploration and Production      15,034       14,536  
  2,075        1,338     Refining and Marketing      3,417       2,804  
  (70)         (598   Other businesses and corporate      (1,076     (398
  (32,192)         617     Gulf of Mexico oil spill response(a)      233       (32,192
  98        515     Consolidation adjustment      (27     306  

 

 

    

 

 

      

 

 

   

 

 

 
  (23,845)         8,486     RC profit (loss) before interest and tax(b)      17,581       (14,944

 

 

    

 

 

      

 

 

   

 

 

 
  (214)         (249  

Finance costs and net finance income or expense relating to pensions and other post-retirement benefits

     (488     (442
  7,188        (2,858   Taxation on a replacement cost basis      (6,172     4,222  
  (102)         (70   Minority interest      (131     (211

 

 

    

 

 

      

 

 

   

 

 

 
  (16,973)         5,309    

Replacement cost profit (loss) attributable to BP shareholders

     10,790       (11,375

 

 

    

 

 

      

 

 

   

 

 

 
  (284)         493     Inventory holding gains (losses)      2,905       421  
  107        (182  

Taxation (charge) credit on inventory holding gains and losses

     (951     (117

 

 

    

 

 

      

 

 

   

 

 

 
  (17,150)         5,620    

Profit (loss) for the period attributable to BP shareholders

     12,744       (11,071

 

 

    

 

 

      

 

 

   

 

 

 

 

(a) See Note 2 on pages 23 – 28 for further information on the accounting for the Gulf of Mexico oil spill response.
(b) Replacement cost profit or loss reflects the replacement cost of supplies. Replacement cost profit for the group is a non-GAAP measure. For further information see page 19.

Total of non-operating items and fair value accounting effects(a)(b)

 

 

Second
quarter
     Second
quarter
         First half  
2010      2011          2011     2010  
     $ million     
  (61)         (699   Exploration and Production      40       43  
  351        (54   Refining and Marketing      (171     291  
  71        (263   Other businesses and corporate      (444     (47
  (32,192)         617     Gulf of Mexico oil spill response      233       (32,192

 

 

    

 

 

      

 

 

   

 

 

 
  (31,831)         (399   Total before interest and taxation      (342     (31,905
  —           (15   Finance costs(c)      (31     —     

 

 

    

 

 

      

 

 

   

 

 

 
  (31,831)         (414   Total before taxation      (373     (31,905
  9,878        116     Taxation credit (charge)(d)      182       9,903  

 

 

    

 

 

      

 

 

   

 

 

 
  (21,953)         (298   Total after taxation for the period      (191     (22,002

 

 

    

 

 

      

 

 

   

 

 

 

 

(a) An analysis of non-operating items by type is provided on page 20 and an analysis by region is shown on pages 9, 11 and 12.
(b) Information on fair value accounting effects is non-GAAP. For further details, see page 21.
(c) Finance costs relate to the Gulf of Mexico oil spill. See Note 2 on pages 23 – 28 for further details.
(d) Tax is calculated by applying discrete quarterly effective tax rates (excluding the impact of the Gulf of Mexico oil spill and, for the first quarter 2011, the impact of a $683-million one-off deferred tax adjustment in respect of the recently enacted increase in the supplementary charge on UK oil and gas production) on group profit or loss. However, the US statutory tax rate has been used for expenditures relating to the Gulf of Mexico oil spill that qualify for tax relief.

 

 

6


Table of Contents

Per share amounts

 

 

Second
quarter
    

Second

quarter

          First half  
2010      2011           2011      2010  
     

Per ordinary share (cents)(a)

     
  (91.29)         29.75     

Profit (loss) for the period

     67.60        (58.96
  (90.35)         28.10     

RC profit (loss) for the period

     57.23        (60.58
     

Per ADS (dollars)(a)

     
  (5.48)         1.79     

Profit (loss) for the period

     4.06        (3.54
  (5.42)         1.69     

RC profit (loss) for the period

     3.43        (3.63

 

 

    

 

 

       

 

 

    

 

 

 

 

(a) See Note 6 on page 31 for details of the calculation of earnings per share.

Net debt ratio – net debt: net debt + equity

 

 

Second

quarter

    

Second

quarter

          First half  
2010      2011           2011      2010  
      $ million      
  30,580        46,890      Gross debt      46,890        30,580  
  53        1,173      Less: fair value asset of hedges related to finance debt      1,173        53  

 

 

    

 

 

       

 

 

    

 

 

 
  30,527        45,717           45,717        30,527  
  7,310        18,749      Cash and cash equivalents      18,749        7,310  

 

 

    

 

 

       

 

 

    

 

 

 
  23,217        26,968      Net debt      26,968        23,217  

 

 

    

 

 

       

 

 

    

 

 

 
  86,362        108,408      Equity      108,408        86,362  
  21%        20%      Net debt ratio      20%        21%  

 

 

    

 

 

       

 

 

    

 

 

 

See Note 7 on page 32 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 7 cents per ordinary share expected to be paid in September. The corresponding amount in sterling will be announced on 6 September 2011, calculated based on the average of the market exchange rates for the four dealing days commencing on 31 August 2011. Holders of American Depositary Shares (ADSs) will receive $0.42 per ADS. The dividend is due to be paid on 20 September 2011 to shareholders and ADS holders on the register on 5 August 2011. 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 including the second-quarter dividend and timetable are available at www.bp.com/scrip.

Dividends paid

 

Second
quarter
    

Second

quarter

          First half  
2010      2011           2011      2010  
     

Dividends paid per ordinary share

     
  —           7.000     

cents

     14.000        14.000  
  —           4.2809     

pence

     8.6181        8.679  
  —           42.00     

Dividends paid per ADS (cents)

     84.00        84.00  

 

 

    

 

 

       

 

 

    

 

 

 
     

Scrip dividends

     
  —           72.8     

Number of shares issued (millions)

     139.4        —     
  —           525     

Value of shares issued ($ million)

     1,035        —     

 

 

    

 

 

       

 

 

    

 

 

 

 

 

7


Table of Contents

Exploration and Production

 

 

Second
quarter
    

Second

quarter

         First half  
2010      2011          2011     2010  
    

$ million

    
  15,215        18,418    

Sales and other operating revenues

     36,823       33,295  
                                 
  6,189        6,619    

Profit before interest and tax

     15,154       14,505  
  55        (5  

Inventory holding (gains) losses

     (120     31  
                                 
  6,244        6,614    

Replacement cost profit before interest and tax(a)

     15,034       14,536  
                                 
    

By region

    
  1,798        731    

US

     2,606       4,560  
  4,446        5,883    

Non-US

     12,428       9,976  
                                 
  6,244        6,614          15,034       14,536  
                                 

 

(a) See page 19 for information on replacement cost reporting for operating segments.

Sales and other operating revenues for the second quarter and half year were $18 billion and $37 billion respectively, compared with $15 billion and $33 billion for the corresponding periods in 2010. The increases for both the quarter and half year were primarily due to higher realizations, partly offset by lower volumes. In addition, there were improved gas marketing and trading revenues.

The replacement cost profit before interest and tax for the second quarter and half year was $6,614 million and $15,034 million respectively, increases of 6% and 3% compared with the same periods in 2010. The second quarter was impacted by net non-operating charges of $664 million, mainly comprising impairment and other related charges in North America, partially offset by gains on disposals and fair value gains on embedded derivatives. The half year included a net non-operating gain of $46 million, with disposal gains more than offsetting impairment and other non-operating charges. In the second quarter and half year, fair value accounting effects had unfavourable impacts of $35 million and $6 million respectively compared with unfavourable impacts of $122 million and $59 million in the same periods of last year.

The primary additional factors impacting replacement cost profit for both periods, compared with a year ago, were higher realizations partially offset by lower production volumes including the impact of divestments. In addition, there were higher earnings from equity-accounted entities (mainly TNK-BP) and an improved contribution from gas marketing and trading, partly offset by higher costs including rig standby costs in the Gulf of Mexico, higher turnaround and related maintenance expenditure, higher exploration write-offs, and certain other one-off charges. In the third quarter, we expect costs to continue to be impacted by rig standby costs, and by turnaround and related maintenance expenditure.

Production for the quarter was 3,433mboe/d, 11% lower than the second quarter of 2010. After adjusting for the effect of acquisitions and divestments and entitlement impacts in our production-sharing agreements (PSAs), the decrease was 7%. This primarily reflects lower Gulf of Mexico production, as a result of ongoing decline owing to the suspension of drilling activity and also the impact of turnaround and maintenance activity, and continuing maintenance and turnaround activity weighted towards other higher-margin areas, including the Greater Plutonio turnaround in Angola and the North Sea. This was partly offset by Iraq production.

For the first half of the year, production was 3,505mboe/d, also 11% lower than in the same period last year. After adjusting for the effect of acquisitions and divestments and PSA entitlement impacts, first-half production was 7% lower than in 2010.

Looking ahead, production in the third quarter is expected to reflect the continuation of the divestment programme, ongoing seasonal turnaround activity across the portfolio and the ongoing decline in the Gulf of Mexico. We continue to expect production in 2011 to be in line with our February guidance of around 3.4 million barrels of oil equivalent per day, with the exact outcome depending on the timing of acquisitions and divestments and PSA entitlement impacts.

We continue to make strategic progress. In May, we received final regulatory approval and completed the purchase of ten exploration and production blocks in Brazil from Devon Energy, announced in March last year.

BP agreed in May to sell its interests in the Wytch Farm, Wareham, Beacon and Kimmeridge fields to Perenco UK Ltd for up to $610 million in cash.

Also in May, the Republic of Azerbaijan ratified the new PSA between BP and SOCAR on joint exploration and development of the Shafag-Asiman structure in the Azerbaijan sector of the Caspian Sea, which was originally signed in October 2010. Under the 30-year PSA, BP will be the operator with a 50% interest while SOCAR will hold the remaining 50% equity.

On 6 July, BP sold half of the 3.29% interest in the ACG development in the Caspian Sea, which had been acquired from Devon Energy last year, to Azerbaijan (ACG) Limited (an affiliate wholly owned and controlled by the State Oil Company of the Republic of Azerbaijan) for $585 million subject to completion adjustments.

On 22 July, the Indian Minister of Petroleum announced approval for BP’s alliance with Reliance Industries. While we await formal written approval, we understand the acquisition by BP of a 30% interest in 21 blocks, including the already producing KG-D6, have been unconditionally approved. Upon receipt of written approval, we can proceed with obtaining final regulatory approval of the Reserve Bank of India and then proceed to completion. The Sales and Purchase Agreement dated 21 February 2011 concerned 23 blocks and the Minister’s decision on the final two blocks will be taken in due course.

On 25 July, BP announced it had been awarded a 100% interest, under PSAs, in Trinidad and Tobago deepwater blocks 23(a) and TTDAA 14.

 

 

8


Table of Contents

Exploration and Production

 

 

Second

quarter

    

Second

quarter

         First half  
2010      2011          2011     2010  
    

$ million

    
    

Non-operating items

    
  (156)         (730  

US

     (726     (218
  217        66    

Non-US

     772       320  
                                 
  61        (664        46       102  
                                 
    

Fair value accounting effects(a)

    
  (35)         (18  

US

     7       46  
  (87)         (17  

Non-US

     (13     (105
                                 
  (122)         (35        (6     (59
                                 
    

Exploration expense

    
  64        625    

US(b)

     933       133  
  68        54    

Non-US(c)

     145       119  
                                 
  132        679          1,078       252  
                                 
    

Production (net of royalties)(d)

    
    

Liquids (mb/d)(e)

    
  581        465    

US

     494       623  
  184        151    

Europe

     158       199  
  859        860    

Russia

     858       854  
  759        653    

Rest of World

     689       779  
                                 
  2,383        2,129          2,199       2,455  
                                 
  1,149        1,165    

Of which equity-accounted entities

     1,164       1,140  
                                 
    

Natural gas (mmcf/d)

    
  2,240        1,833    

US

     1,869       2,231  
  551        391    

Europe

     382       575  
  647        675    

Russia

     697       660  
  5,046        4,664    

Rest of World

     4,626       5,076  
                                 
  8,484        7,563          7,574       8,542  
                                 
  1,080        1,101    

Of which equity-accounted entities

     1,114       1,086  
                                 
    

Total hydrocarbons (mboe/d)(f)

    
  968        781    

US

     816       1,007  
  279        218    

Europe

     224       298  
  971        976    

Russia

     978       968  
  1,628        1,458    

Rest of World

     1,487       1,655  
                                 
  3,846        3,433          3,505       3,928  
                                 
  1,335        1,355    

Of which equity-accounted entities

     1,356       1,328  
                                 
    

Average realizations(g)

    
  72.90        106.99    

Total liquids ($/bbl)

     99.98       72.35  
  3.76        4.54    

Natural gas ($/mcf)

     4.37       4.01  
  47.08        63.23    

Total hydrocarbons ($/boe)

     61.05       48.16  
                                 

 

(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 21.
(b) First half 2011 includes $93 million related to decommissioning of idle infrastructure, as required by BOEMRE’s Notice to Lessees No. 2010-GO5 issued in October 2010. Second quarter and first half 2011 include $395 million classified within the ‘other’ category of non-operating items.
(c) First half 2011 includes $44 million classified within the ‘other’ category of non-operating items.
(d) Includes BP’s share of production of equity-accounted entities.
(e) Crude oil and natural gas liquids.
(f) Natural gas is converted to oil equivalent at 5.8 billion cubic feet = 1 million barrels.
(g) 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.

 

 

9


Table of Contents

Refining and Marketing

 

 

Second

quarter

    

Second

quarter

         First half  
2010      2011          2011     2010  
    

$ million

    
  67,250        93,886    

Sales and other operating revenues

     171,319       131,536  
                                 
  1,850        1,820    

Profit before interest and tax

     6,187       3,258  
  225        (482  

Inventory holding (gains) losses

     (2,770     (454
                                 
  2,075        1,338    

Replacement cost profit before interest and tax(a)

     3,417       2,804  
                                 
    

By region

    
  757        (17  

US

     623       694  
  1,318        1,355    

Non-US

     2,794       2,110  
                                 
  2,075        1,338          3,417       2,804  
                                 

 

(a) See page 19 for information on replacement cost reporting for operating segments.

Sales and other operating revenues for the second quarter and half year were $94 billion and $171 billion respectively, compared with $67 billion and $132 billion for the corresponding periods in 2010. The increases for both the quarter and half year primarily reflected higher prices, partly offset by lower volumes. Both periods also benefited from favourable foreign exchange effects.

The replacement cost profit before interest and tax for the second quarter and half year was $1,338 million and $3,417 million respectively, compared with $2,075 million and $2,804 million for the same periods last year.

The 2011 results included net non-operating charges of $218 million for the second quarter and $235 million for the half year, mainly comprising impairment charges, primarily associated with our US divestment programme, partly offset by gains on disposal. A year ago, there were net non-operating gains of $232 million and $162 million respectively. Fair value accounting effects had favourable impacts of $164 million for the second quarter and $64 million for the half year. The corresponding periods in 2010 reflected favourable impacts of $119 million and $129 million respectively.

Compared with a year ago, the second-quarter result reflected an improved refining environment, which was more than offset by the swing to a small loss in supply and trading, reduced economic utilization at the Texas City refinery following the recent weather-related power outage, higher turnaround activities, and certain one-off charges. In addition to the factors mentioned above, the first half benefited from a particularly strong first-quarter supply and trading contribution, which more than offset the weak contribution in the second quarter, strong refining feedstock optimization in the US due to BP’s location advantage in accessing WTI-priced crude grades and higher petrochemicals’ aromatics margins.

In the second quarter, refining throughputs in the fuels value chains reduced by over 170mb/d compared with the same period last year primarily due to operational issues following the recent power outage at the Texas City refinery. Solomon refining availability (as defined in footnote (b) on page 11) was 94.8% for the quarter.

In the international businesses, petrochemicals production volumes were down in the second quarter by approximately 8% compared with the same period last year, driven primarily by shutdowns following the power outage at the Texas City petrochemicals site, a tornado strike at the Decatur plant and turnaround activity at the Cooper River plant.

Looking ahead, we expect a typical seasonal decline in refining margins in the third quarter. Throughput at the Texas City refinery has been largely restored and we expect the last of the impacted units to return to full capacity during August. We expect petrochemicals production volumes to improve compared with the second quarter following the recent full recovery of operations at our Decatur, Texas City and Cooper River petrochemicals sites. The planned turnaround activity in the second half of 2011 is expected to be lower than in the first half.

Early last year we announced our exit from five countries in southern Africa. The sale of BP Zambia and BP Malawi to Puma Energy was completed in the second quarter of 2011, with completion of BP Tanzania, the last piece of this disposal, to follow.

Following a strategic review, we announced earlier this year our intent to divest the Texas City refinery and the southern part of our US West Coast fuels value chain, including the Carson refinery.

In the second quarter, we also executed agreements confirming the sale of 33 refined products terminals and 992 miles of pipelines as part of the ongoing divestment programme of a number of non-strategic pipelines and terminals in the US.

 

 

10


Table of Contents

Refining and Marketing

 

 

Second

quarter

    

Second

quarter

         First half  
2010      2011          2011     2010  
    

$ million

    
    

Non-operating items

    
  151        (239  

US

     (255     148  
  81        21    

Non-US

     20       14  

 

 

    

 

 

      

 

 

   

 

 

 
  232        (218        (235     162  

 

 

    

 

 

      

 

 

   

 

 

 
    

Fair value accounting effects(a)

    
  37        71    

US

     23       53  
  82        93    

Non-US

     41       76  

 

 

    

 

 

      

 

 

   

 

 

 
  119        164          64       129  

 

 

    

 

 

      

 

 

   

 

 

 
    

Refinery throughputs (mb/d)

    
  1,350        1,190    

US

     1,192       1,358  
  770        749    

Europe

     758       775  
  309        314    

Rest of World

     311       295  

 

 

    

 

 

      

 

 

   

 

 

 
  2,429        2,253    

Total throughput

     2,261       2,428  

 

 

    

 

 

      

 

 

   

 

 

 
  94.6        94.8    

Refining availability (%)(b)

     94.3       94.9  

 

 

    

 

 

      

 

 

   

 

 

 
    

Sales volumes (mb/d)(c)

    
    

Marketing sales by region

    
  1,466        1,407    

US

     1,391       1,442  
  1,312        1,298    

Europe

     1,283       1,369  
  622        613    

Rest of World

     611       626  

 

 

    

 

 

      

 

 

   

 

 

 
  3,400        3,318    

Total marketing sales

     3,285       3,437  
  2,544        2,729    

Trading/supply sales

     2,494       2,583  

 

 

    

 

 

      

 

 

   

 

 

 
  5,944        6,047    

Total refined product sales

     5,779       6,020  

 

 

    

 

 

      

 

 

   

 

 

 
    

Refining Marker Margin (RMM) ($/bbl)(d)

    
  15.02        15.75    

US West Coast

     15.96       12.44  
  11.24        16.81    

US Gulf Coast

     13.83       10.78  
  7.24        13.00    

US Midwest

     8.31       6.13  
  11.21        11.69    

North West Europe

     11.38       10.51  
  9.59        8.49    

Mediterranean

     8.79       8.93  
  10.48        15.00    

Singapore

     14.85       10.54  
  11.04        13.92    

BP Average RMM

     12.48       10.06  

 

 

    

 

 

      

 

 

   

 

 

 
    

Chemicals production (kte)

    
  1,088        766    

US

     1,901       2,028  
  1,067        1,050    

Europe(e)

     2,035       2,130  
  1,846        1,846    

Rest of World

     3,764       3,734  

 

 

    

 

 

      

 

 

   

 

 

 
  4,001        3,662    

Total production(e)

     7,700       7,892  

 

 

    

 

 

      

 

 

   

 

 

 

 

(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 21.
(b) 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.
(c) Does not include volumes relating to crude oil.
(d) The Refining Marker Margin (RMM) is the average of regional indicator margins weighted for BP’s crude refining capacity in each region. Each regional marker margin is based upon product yields and a marker crude oil deemed appropriate for the region. The regional marker 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.
(e) A minor amendment has been made in the second quarter and first half 2010.

 

 

11


Table of Contents

Other businesses and corporate

 

 

Second
quarter
2010

     Second
quarter
2011
         First half  
          2011     2010  
     $ million     
  794        985     Sales and other operating revenues      1,841       1,584  
                                 
  (74)         (592   Profit (loss) before interest and tax      (1,061     (400
  4        (6   Inventory holding (gains) losses      (15     2  
                                 
  (70)         (598   Replacement cost profit (loss) before interest and tax(a)      (1,076     (398
                                 
     By region     
  (119)         (168   US      (356     (350
  49        (430   Non-US      (720     (48
                                 
  (70)         (598        (1,076     (398
                                 
     Results include Non-operating items     
  (7)         (12   US      (11     (113
  78        (251   Non-US      (433     66  
                                 
  71        (263        (444     (47
                                 

 

(a) See page 19 for information on replacement cost reporting for operating segments.

Other businesses and corporate comprises the Alternative Energy business, Shipping, the group’s aluminium business, 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 second quarter and half year was $598 million and $1,076 million respectively, compared with losses of $70 million and $398 million a year ago. The net non-operating charge for the second quarter was $263 million, compared with a net gain of $71 million a year ago. For the half year the net non-operating charge was $444 million, compared with a net charge of $47 million a year ago.

In addition, compared with the same periods a year ago, the results for the second quarter and first half primarily reflected higher corporate expenditure as a result of the Gulf of Mexico oil spill and lower income following business restructuring.

In Alternative Energy, BP completed the installation of the 250MW Cedar Creek 2 wind farm in Weld County, Colorado, a 50:50 joint venture with Sempra Generation. Construction commenced at the 150MW Sherbino 2 wind farm in Pecos County, Texas, and at the Trinity Hills wind farm in Archer and Young Counties, Texas. Both wind farms are 100% owned by BP. BP’s net wind generation capacity(b) at the end of the second quarter was 774MW (1,362MW gross), compared with 711MW (1,237MW gross) at the end of the same period a year ago.

In our biofuels business, on 27 April BP completed the purchase of 83% of the shares of Companhia Nacional de Açúcar e Álcool (CNAA), a Brazilian ethanol and sugar producer, for $680 million.

In our solar business, a $261 million non-operating charge has been recognized with respect to raw materials purchase contracts and we intend to exit the module-only sales business.

 

(b) Net wind 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 Refining and Marketing segment.

 

 

12


Table of Contents

Cautionary statement

 

Cautionary statement regarding forward-looking statements: The discussion in this results announcement contains forward-looking statements particularly those regarding the quarterly dividend payment; the timing of surveys of shoreline impacted by the Gulf of Mexico oil spill; the segregation of an additional $500 million of the Trust balance to cover costs associated with projects that will restore injured natural resources in the Gulf; the issuance of further Requests for Proposals pursuant to the Gulf of Mexico Research Initiative and the master research agreement thereunder; expectations regarding the impacts on costs of rig standby costs and of turnaround and related maintenance expenditures; the expected impact on third-quarter production of the divestment programme, ongoing seasonal turnaround activity across BP’s portfolio, and the ongoing decline of production in the Gulf of Mexico; expected full-year 2011 production, and the impact of acquisitions and divestments and PSA entitlement on full-year 2011 production; the magnitude and timing of remaining remediation costs related to the Gulf of Mexico oil spill; the factors that could affect the magnitude of BP’s ultimate exposure and the cost to BP in relation to the spill and any potential mitigation resulting from BP’s partners or others involved in the spill; the potential liabilities resulting from pending and future legal proceedings and potential investigations and civil or criminal actions that US state and/or local governments could seek to take against BP as a result of the spill; the timing of claims and litigation outcomes and of payment of legal costs; the anticipated timing for completion of the disposition of certain BP assets; contributions to and payments from the trust fund and the setting aside of assets while the fund is building; expectations for third-quarter refining margins; expectations for operations at the Texas City refinery; expected improvements in petrochemicals production volumes following the recent full recovery of operations at BP’s Decatur, Texas City and Cooper River petrochemicals sites; lower anticipated planned turnaround activity in the second half of 2011; the sale of BP Tanzania; the intentions of BP’s solar business to exit its module-only sales business; the anticipated timing of the completion of the disposition of ARCO Aluminum Inc.; exploration activity in four deepwater offshore blocks off of Australia; the timing for publication of investigation reports; the impact of BP’s potential liabilities relating to the Gulf of Mexico oil spill on the group, including its business, results and financial condition; the anticipated commencement of the trial regarding allegations pertaining to the Atlantis platform; and BP’s intentions to strongly defend itself against any claim for breach of the TNK-BP shareholders agreement that may be brought by Alfa, Access and Renova. 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; 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 our Annual Report and Form 20-F 2010 as filed with the US Securities and Exchange Commission (SEC).

 

 

13


Table of Contents

Group income statement

 

 

Second

quarter

    

Second

quarter

         First half  
2010      2011          2011     2010  
    

$ million

    
  73,725        101,364    

Sales and other operating revenues (Note 4)

     186,693       146,796  
  257        303    

Earnings from jointly controlled entities – after interest and tax

     565       660  
  760        1,255    

Earnings from associates – after interest and tax

     2,664       1,523  
  158        151    

Interest and other income

     275       300  
  971        775    

Gains on sale of businesses and fixed assets

     1,963       1,009  
                                 
  75,871        103,848    

Total revenues and other income

     192,160       150,288  
  54,536        78,281    

Purchases

     140,002       106,177  
  37,979        6,200    

Production and manufacturing expenses(a)

     12,708       43,719  
  1,238        2,356    

Production and similar taxes (Note 5)

     4,187       2,514  
  2,780        2,671    

Depreciation, depletion and amortization

     5,506       5,776  
  (56)         1,383    

Impairment and losses on sale of businesses and fixed assets

     1,442       108  
  132        679    

Exploration expense

     1,078       252  
  2,939        3,448    

Distribution and administration expenses

     6,355       5,959  
  452        (149  

Fair value (gain) loss on embedded derivatives

     396       306  
                                 
  (24,129)         8,979    

Profit (loss) before interest and taxation

     20,486       (14,523
  225        314    

Finance costs(a)

     622       463  
  (11)         (65  

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

     (134     (21
                                 
  (24,343)         8,730    

Profit (loss) before taxation

     19,998       (14,965
  (7,295)         3,040    

Taxation(a)

     7,123       (4,105
                                 
  (17,048)         5,690    

Profit (loss) for the period

     12,875       (10,860
                                 
    

Attributable to

    
  (17,150)         5,620    

BP shareholders

     12,744       (11,071
  102        70    

Minority interest

     131       211  
                                 
  (17,048)         5,690          12,875       (10,860
                                 
    

Earnings per share – cents (Note 6)

    
    

Profit for the period attributable to BP shareholders

    
  (91.29)         29.75    

Basic

     67.60       (58.96
  (91.29)         29.39    

Diluted

     66.82       (58.96

 

(a) See Note 2 on pages 23 – 28 for further details of the impact of the Gulf of Mexico oil spill on the income statement line items.

 

 

14


Table of Contents

Group statement of comprehensive income

 

 

Second

quarter

    

Second

quarter

         First half  
2010      2011          2011     2010  
    

$ million

    
  (17,048)         5,690    

Profit (loss) for the period

     12,875       (10,860
                                 
  (1,000)         401    

Currency translation differences

     1,058       (1,526
  39        2    

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

     13       39  
  (230)         (95  

Available-for-sale investments marked to market

     171       (323
  (143)         (3  

Available-for-sale investments – recycled to the income statement

     (5     (143
  (245)         75    

Cash flow hedges marked to market

     193       (407
  21        (112  

Cash flow hedges – recycled to the income statement

     (128     (73
  18        (5  

Cash flow hedges – recycled to the balance sheet

     (3     31  
  (48)         57    

Taxation

     52       (167
                                 
  (1,588)         320    

Other comprehensive income (expense)

     1,351       (2,569
                                 
  (18,636)         6,010    

Total comprehensive income (expense)

     14,226       (13,429
                                 
    

Attributable to

    
  (18,737)         5,946    

BP shareholders

     14,085       (13,632
  101        64    

Minority interest

     141       203  
                                 
  (18,636)         6,010          14,226       (13,429
                                 

Group statement of changes in equity

 

 

     BP
shareholders’
equity
    Minority
interest
    Total
equity
 

$ million

      

At 1 January 2011

     94,987       904       95,891  
                        

Total comprehensive income

     14,085       141       14,226  

Dividends

     (1,603     (132     (1,735

Share-based payments (net of tax)

     25       —          25  

Transactions involving minority interests

     —          1       1  
                        

At 30 June 2011

     107,494       914       108,408  
                        
     BP
shareholders’

equity
    Minority
interest
    Total
equity
 

$ million

      

At 1 January 2010

     101,613       500       102,113  
                        

Total comprehensive income (expense)

     (13,632     203       (13,429

Dividends

     (2,626     (131     (2,757

Share-based payments (net of tax)

     135       —          135  

Transactions involving minority interests

     —          300       300  
                        

At 30 June 2010

     85,490       872       86,362  
                        

 

 

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Table of Contents

Group balance sheet

 

 

     30 June
2011
     31 December
2010
 

$ million

     

Non-current assets

     

Property, plant and equipment

     112,205        110,163  

Goodwill

     9,470        8,598  

Intangible assets

     16,768        14,298  

Investments in jointly controlled entities

     12,483        12,286  

Investments in associates

     14,093        13,335  

Other investments

     1,366        1,191  
                 

Fixed assets

     166,385        159,871  

Loans

     868        894  

Other receivables

     5,804        6,298  

Derivative financial instruments

     4,267        4,210  

Prepayments

     1,521        1,432  

Deferred tax assets

     546        528  

Defined benefit pension plan surpluses

     2,573        2,176  
                 
     181,964        175,409  
                 

Current assets

     

Loans

     256        247  

Inventories

     27,477        26,218  

Trade and other receivables

     42,922        36,549  

Derivative financial instruments

     3,796        4,356  

Prepayments

     3,983        1,574  

Current tax receivable

     268        693  

Other investments

     1,413        1,532  

Cash and cash equivalents

     18,749        18,556  
                 
     98,864        89,725  
                 

Assets classified as held for sale (Note 3)

     10,167        7,128  
                 
     109,031        96,853  
                 

Total assets

     290,995        272,262  
                 

Current liabilities

     

Trade and other payables

     51,010        46,329  

Derivative financial instruments

     3,273        3,856  

Accruals

     6,126        5,612  

Finance debt

     12,445        14,626  

Current tax payable

     3,883        2,920  

Provisions

     9,060        9,489  
                 
     85,797        82,832  
                 

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

     1,127        1,047  
                 
     86,924        83,879  
                 

Non-current liabilities

     

Other payables

     10,259        14,285  

Derivative financial instruments

     3,705        3,677  

Accruals

     391        637  

Finance debt

     34,445        30,710  

Deferred tax liabilities

     13,751        10,908  

Provisions

     23,287        22,418  

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

     9,825        9,857  
                 
     95,663        92,492  
                 

Total liabilities

     182,587        176,371  
                 

Net assets

     108,408        95,891  
                 

Equity

     

BP shareholders’ equity

     107,494        94,987  

Minority interest

     914        904  
                 
     108,408        95,891  
                 

 

 

16


Table of Contents

Condensed group cash flow statement

 

Second

quarter

    

Second

quarter

         First half  
2010      2011          2011     2010  
    

$ million

    
    

Operating activities

    
  (24,343)         8,730    

Profit (loss) before taxation

     19,998       (14,965
    

Adjustments to reconcile profit before taxation to net cash provided by operating activities

    
  2,833        3,275    

Depreciation, depletion and amortization and exploration expenditure written off

     6,402       5,850  
  (1,027)         608    

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

     (521     (901
  (92)         666    

Earnings from equity-accounted entities, less dividends received

     (780     (761
  (61)         (121  

Net charge for interest and other finance expense, less net interest paid

     (70     (15
  150        113    

Share-based payments

     (11     4  
  (171)         (159  

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

     (598     (661
  17,739        (64  

Net charge for provisions, less payments

     209       17,691  
  13,464        (3,283  

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

     (11,106     11,524  
  (1,739)         (1,917  

Income taxes paid

     (3,271     (3,320

 

 

    

 

 

      

 

 

   

 

 

 
  6,753        7,848    

Net cash provided by operating activities

     10,252       14,446  

 

 

    

 

 

      

 

 

   

 

 

 
    

Investing activities

    
  (4,273)         (4,289  

Capital expenditure(b)

     (10,063     (8,562
  (1,268)         (3,884  

Acquisitions, net of cash acquired

     (3,886     (1,268
  (100)         (66  

Investment in jointly controlled entities

     (155     (182
  (19)         (19  

Investment in associates

     (30     (25
  636        1,273    

Proceeds from disposal of fixed assets(c)

     1,657       744  
  87        376    

Proceeds from disposal of businesses, net of cash disposed(c)

     962       87  
  203        116    

Proceeds from loan repayments

     151       259  

 

 

    

 

 

      

 

 

   

 

 

 
  (4,734)         (6,493  

Net cash used in investing activities

     (11,364     (8,947

 

 

    

 

 

      

 

 

   

 

 

 
    

Financing activities

    
  31        18    

Net issue of shares

     30       159  
  756        2,696    

Proceeds from long-term financing

     7,613       1,098  
  (192)         (3,102  

Repayments of long-term financing

     (5,724     (2,687
  (1,855)         (157  

Net increase (decrease) in short-term debt

     792       (2,102
  —           (795  

Dividends paid – BP shareholders

     (1,603     (2,626
  (128)         (96  

                           – Minority interest

     (102     (131

 

 

    

 

 

      

 

 

   

 

 

 
  (1,388)         (1,436  

Net cash provided by (used in) financing activities

     1,006       (6,289

 

 

    

 

 

      

 

 

   

 

 

 
  (162)         104    

Currency translation differences relating to cash and cash equivalents

     299       (239

 

 

    

 

 

      

 

 

   

 

 

 
  469        23    

Increase (decrease) in cash and cash equivalents

     193       (1,029
  6,841        18,726    

Cash and cash equivalents at beginning of period

     18,556       8,339  

 

 

    

 

 

      

 

 

   

 

 

 
  7,310        18,749    

Cash and cash equivalents at end of period

     18,749       7,310  

 

 

    

 

 

      

 

 

   

 

 

 
  (a)    Includes:          
  284        (493  

Inventory holding (gains) losses

     (2,905     (421
  452        (149  

Fair value (gain) loss on embedded derivatives

     396       306  
  12,430        (2,912  

Movements related to Gulf of Mexico oil spill response

     (5,776     12,430  

 

 

    

 

 

      

 

 

   

 

 

 

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.

(b) First half 2011 included $2,000 million paid as a deposit relating to the transaction with Reliance Industries Limited.

See page 8 for further information.

(c) Included in disposal proceeds are deposits received in respect of disposal transactions expected to complete in subsequent periods as follows: second quarter 2011 $568 million; first half 2011 $625.5 million; second quarter 2010 nil. For further information see Note 7.

 

 

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Table of Contents

Capital expenditure and acquisitions

 

 

Second

quarter

    

Second

quarter

          First half  
2010      2011           2011      2010  
     

$ million

     
     

By business

     
     

Exploration and Production

     
  3,024        1,001     

US(a)

     2,024        4,157  
  2,172        5,439     

Non-US(b)

     7,550        4,987  
                                   
  5,196        6,440           9,574        9,144  
                                   
     

Refining and Marketing

     
  704        626     

US

     1,148        1,232  
  221        313     

Non-US

     528        365  
                                   
  925        939           1,676        1,597  
                                   
     

Other businesses and corporate

     
  30        126     

US

     256        58  
  61        689     

Non-US(c)

     709        100  
                                   
  91        815           965        158  
                                   
  6,212        8,194           12,215        10,899  
                                   
     

By geographical area

     
  3,758        1,753     

US(a)

     3,428        5,447  
  2,454        6,441     

Non-US(b)(c)

     8,787        5,452  
                                   
  6,212        8,194           12,215        10,899  
                                   
     

Included above:

     
  1,767        4,005     

Acquisitions and asset exchanges(a)(b)(c)

     4,014        1,767  
                                   

 

(a) Second quarter and first half 2010 included capital expenditure of $1,767 million in the US Deepwater Gulf of Mexico as part of the transaction with Devon Energy announced in first quarter 2010.
(b) Second quarter and first half 2011 include capital expenditure of $3,236 million in Brazil as part of the transaction with Devon Energy announced in first quarter 2010.
(c) Second quarter and first half 2011 include capital expenditure of $680 million in Brazil relating to the acquisition of CNAA. See page 12 for further information.

Exchange rates

 

 

Second

quarter

    

Second

quarter

          First half  
2010      2011           2011      2010  
  1.49        1.63     

US dollar/sterling average rate for the period

     1.62        1.52  
  1.51        1.60     

US dollar/sterling period-end rate

     1.60        1.51  
  1.27        1.44     

US dollar/euro average rate for the period

     1.40        1.32  
  1.22        1.44     

US dollar/euro period-end rate

     1.44        1.22  
                                   

 

 

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Table of Contents

Analysis of replacement cost profit (loss) before interest and tax and

reconciliation to profit (loss) before taxation(a)

 

 

Second
quarter
     Second
quarter
         First half  
2010      2011     $ million    2011     2010  
     By business     
     Exploration and Production     
  1,798        731     US      2,606       4,560  
  4,446        5,883     Non-US      12,428       9,976  

 

 

    

 

 

      

 

 

   

 

 

 
  6,244        6,614          15,034       14,536  

 

 

    

 

 

      

 

 

   

 

 

 
     Refining and Marketing     
  757        (17   US      623       694  
  1,318        1,355     Non-US      2,794       2,110  

 

 

    

 

 

      

 

 

   

 

 

 
  2,075        1,338          3,417       2,804  

 

 

    

 

 

      

 

 

   

 

 

 
     Other businesses and corporate     
  (119)         (168   US      (356     (350
  49        (430   Non-US      (720     (48

 

 

    

 

 

      

 

 

   

 

 

 
  (70)         (598        (1,076     (398

 

 

    

 

 

      

 

 

   

 

 

 
  8,249        7,354          17,375       16,942  
  (32,192)         617     Gulf of Mexico oil spill response      233       (32,192
  98        515     Consolidation adjustment      (27     306  

 

 

    

 

 

      

 

 

   

 

 

 
  (23,845)         8,486     Replacement cost profit (loss) before interest and tax(b)      17,581       (14,944
     Inventory holding gains (losses)(c)     
  (55)         5     Exploration and Production      120       (31
  (225)         482     Refining and Marketing      2,770       454  
  (4)         6     Other businesses and corporate      15       (2

 

 

    

 

 

      

 

 

   

 

 

 
  (24,129)         8,979     Profit (loss) before interest and tax      20,486       (14,523
  225        314     Finance costs      622       463  
     Net finance income relating to pensions and other     
  (11)         (65  

post-retirement benefits

     (134     (21

 

 

    

 

 

      

 

 

   

 

 

 
  (24,343)         8,730     Profit (loss) before taxation      19,998       (14,965

 

 

    

 

 

      

 

 

   

 

 

 
     Replacement cost profit (loss) before interest and tax     
     By geographical area     
  (29,171)         1,361     US      3,174       (26,581
  5,326        7,125     Non-US      14,407       11,637  

 

 

    

 

 

      

 

 

   

 

 

 
  (23,845)         8,486          17,581       (14,944

 

 

    

 

 

      

 

 

   

 

 

 

 

(a) 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, this measure of profit or loss is replacement cost 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.
(b) Replacement cost profit or loss reflects the replacement cost of supplies. The replacement cost 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. Replacement cost profit or loss for the group is not a recognized GAAP measure.
(c) 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.

 

 

19


Table of Contents

Non-operating items(a)

 

 

Second
quarter
     Second
quarter
         First half  
2010      2011          2011     2010  
     $ million     
     Exploration and Production     
  660        (403   Impairment and gain (loss) on sale of businesses and fixed assets(b)      686       647  
  —           —        Environmental and other provisions      —          —     
  (13)         —        Restructuring, integration and rationalization costs      —          (117
  (452)         142     Fair value gain (loss) on embedded derivatives      (186     (306
  (134)         (403   Other      (454     (122

 

 

    

 

 

      

 

 

   

 

 

 
  61        (664        46       102  

 

 

    

 

 

      

 

 

   

 

 

 
     Refining and Marketing     
  270        (209   Impairment and gain (loss) on sale of businesses and fixed assets      (204     225  
  —           (1   Environmental and other provisions      (1     —     
  (30)         (4   Restructuring, integration and rationalization costs      (5     (18
  —           —        Fair value gain (loss) on embedded derivatives      —          —     
  (8)         (4   Other      (25     (45

 

 

    

 

 

      

 

 

   

 

 

 
  232        (218        (235     162  

 

 

    

 

 

      

 

 

   

 

 

 
     Other businesses and corporate     
  97        4     Impairment and gain (loss) on sale of businesses and fixed assets      39       29  
  (4)         (12   Environmental and other provisions      (12     (4
  (22)         2     Restructuring, integration and rationalization costs      3       (60
  —           7     Fair value gain (loss) on embedded derivatives(c)      (210     —     
  —           (264   Other      (264     (12

 

 

    

 

 

      

 

 

   

 

 

 
  71        (263        (444     (47

 

 

    

 

 

      

 

 

   

 

 

 
  (32,192)         617     Gulf of Mexico oil spill response      233       (32,192

 

 

    

 

 

      

 

 

   

 

 

 
  (31,828)         (528   Total before interest and taxation      (400     (31,975
  —           (15   Finance costs(d)      (31     —     

 

 

    

 

 

      

 

 

   

 

 

 
  (31,828)         (543   Total before taxation      (431     (31,975
  9,877        160     Taxation credit (charge)(e)      204       9,927  

 

 

    

 

 

      

 

 

   

 

 

 
  (21,951)         (383   Total after taxation for period      (227     (22,048

 

 

    

 

 

      

 

 

   

 

 

 

 

(a) An analysis of non-operating items by region is shown on pages 9, 11 and 12.
(b) Second quarter 2011 included impairment charges of $1,049 million, partially offset by net gains on disposals of $646 million.
(c) Relates to an embedded derivative arising from a financing arrangement.
(d) Finance costs relate to the Gulf of Mexico oil spill. See Note 2 on pages 23 – 28 for further details.
(e) Tax is calculated by applying discrete quarterly effective tax rates (excluding the impact of the Gulf of Mexico oil spill and, for the first quarter 2011, the impact of a $683-million one-off deferred tax adjustment in respect of the recently enacted increase in the supplementary charge on UK oil and gas production) on group profit or loss. However, the US statutory tax rate has been used for expenditures relating to the Gulf of Mexico oil spill that qualify for tax relief.

Non-operating items are charges and credits arising in consolidated entities that BP discloses separately because it considers such disclosures to be meaningful and relevant to investors. These disclosures are provided in order to enable investors better to understand and evaluate the group’s financial performance.

 

 

20


Table of Contents

Non-GAAP information on fair value accounting effects

 

 

Second
quarter

    

 

Second
quarter

        

 

First half

 
2010      2011          2011     2010  
     $ million     
     Favourable (unfavourable) impact relative to management’s measure of performance     
  (122)         (35   Exploration and Production      (6     (59
  119        164     Refining and Marketing      64       129  

 

 

    

 

 

      

 

 

   

 

 

 
  (3)         129          58       70  
  1        (44   Taxation credit (charge)(a)      (22     (24

 

 

    

 

 

      

 

 

   

 

 

 
  (2)         85          36       46  

 

 

    

 

 

      

 

 

   

 

 

 

 

(a) Tax is calculated by applying discrete quarterly effective tax rates (excluding the impact of the Gulf of Mexico oil spill and, for the first quarter 2011, the impact of a $683-million one-off deferred tax adjustment in respect of the recently enacted increase in the supplementary charge on UK oil and gas production) on group profit or loss.

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.

Reconciliation of non-GAAP information

 

Second
quarter
     Second
quarter
         First half  
2010      2011    

 

   2011     2010  
     $ million     
     Exploration and Production     
  6,366        6,649     Replacement cost profit before interest and tax adjusted for fair value accounting effects      15,040       14,595  
  (122)         (35   Impact of fair value accounting effects      (6     (59

 

 

    

 

 

      

 

 

   

 

 

 
  6,244        6,614     Replacement cost profit before interest and tax      15,034       14,536  

 

 

    

 

 

      

 

 

   

 

 

 
     Refining and Marketing     
  1,956        1,174     Replacement cost profit before interest and tax adjusted for fair value accounting effects      3,353       2,675  
  119        164     Impact of fair value accounting effects      64       129  

 

 

    

 

 

      

 

 

   

 

 

 
  2,075        1,338     Replacement cost profit before interest and tax      3,417       2,804  

 

 

    

 

 

      

 

 

   

 

 

 
     Total group     
  (24,126)         8,850     Profit (loss) before interest and tax adjusted for fair value accounting effects      20,428       (14,593
  (3)         129     Impact of fair value accounting effects      58       70  

 

 

    

 

 

      

 

 

   

 

 

 
  (24,129)         8,979     Profit (loss) before interest and tax      20,486       (14,523

 

 

    

 

 

      

 

 

   

 

 

 

 

 

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Table of Contents

Realizations and marker prices

 

 

Second
quarter

    

 

Second
quarter

         

 

First half

 
2010      2011           2011      2010  
      Average realizations(a)      
      Liquids ($/bbl)(b)      
  70.77        101.40      US      93.51        70.23  
  75.46        114.43      Europe      108.14        75.59  
  74.44        111.12      Rest of World      104.81        73.67  
  72.90        106.99      BP Average      99.98        72.35  
                                   
      Natural gas ($/mcf)      
  3.52        3.61      US      3.40        4.19  
  5.14        7.82      Europe      7.41        5.02  
  3.71        4.63      Rest of World      4.52        3.80  
  3.76        4.54      BP Average      4.37        4.01  
                                   
      Total hydrocarbons ($/boe)      
  50.87        68.43      US      64.20        52.80  
  59.89        92.91      Europe      88.84        60.16  
  41.47        53.45      Rest of World      53.11        41.84  
  47.08        63.23      BP Average      61.05        48.16  
                                   
      Average oil marker prices ($/bbl)      
  78.24        117.04      Brent      111.09        77.31  
  77.81        102.22      West Texas Intermediate      98.39        78.32  
  78.31        115.26      Alaska North Slope      109.29        78.72  
  77.42        111.68      Mars      106.85        76.64  
  76.92        113.73      Urals (NWE– cif)      108.00        76.12  
  35.61        50.26      Russian domestic oil      49.75        35.57  
                                   
      Average natural gas marker prices      
  4.09        4.32      Henry Hub gas price ($/mmBtu)(c)      4.21        4.69  
  38.26        57.47      UK Gas – National Balancing Point (p/therm)      57.20        36.96  
                                   

 

(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.

 

 

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Table of Contents

Notes

 

 

1. Basis of preparation

The interim financial information included in this report has been prepared in accordance with IAS 34 ‘Interim Financial Reporting’.

The results for the interim periods are unaudited and in the opinion of management include all adjustments necessary for a fair presentation of the results for the periods presented. All such adjustments are of a normal recurring nature. After making enquiries, the directors have a reasonable expectation that the group has adequate resources to continue in operational existence for the foreseeable future. Accordingly, they continue to adopt the going concern basis of accounting in preparing the interim financial statements. This report should be read in conjunction with the consolidated financial statements and related notes for the year ended 31 December 2010 included in the BP Annual Report and Form 20-F 2010.

BP prepares its consolidated financial statements included within its Annual Report and Accounts 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. 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 2011, which do not differ significantly from those used in the BP Annual Report and Form 20-F 2010.

New or amended International Financial Reporting Standards adopted

There are no new or amended standards or interpretations adopted with effect from 1 January 2011 that have a significant impact on the financial statements.

 

2. Gulf of Mexico oil spill

(a) Overview

As a consequence of the Gulf of Mexico oil spill, BP continues to incur 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 2010 – Financial Statements – Note 2, Note 37 and Note 44, and Legal proceedings on pages 46 – 49 herein.

The group income statement includes a pre-tax credit of $602 million for the second quarter in relation to the Gulf of Mexico oil spill, and a pre-tax credit of $202 million for the first half of 2011. The amount for the second quarter includes credits of $1.1 billion relating to the settlement reached with MOEX Offshore 2007 LLC (MOEX), one of BP’s co-owners in the Macondo well, and $75 million relating to the settlement with Weatherford U.S., L.P., the contractor that manufactured the float collar used in the well. These amounts are partially offset by higher costs associated with the ongoing spill response, mainly increased costs of patrolling and maintenance of shoreline, as well as functional expenses of the GCRO. The total pre-tax income statement charge in 2010 amounted to $40.9 billion.

The settlement amounts with MOEX and Weatherford were not received during the second quarter, but were recorded as receivables on the balance sheet at 30 June 2011.

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 pages 4 – 5. The income statement, balance sheet and cash flow statement impacts are included within the relevant line items in those statements as set out below.

 

Second
quarter
     Second
quarter
         First half  
2010      2011          2011     2010  
     $ million     
     Income statement     
  32,192        (617   Production and manufacturing expenses      (233     32,192  
                                 
  (32,192)         617     Profit (loss) before interest and taxation      233       (32,192
  —           15     Finance costs      31       —     
                                 
  (32,192)         602     Profit (loss) before taxation      202       (32,192
  10,003        (234   Less: Taxation      (33     10,003  
                                 
  (22,189)         368     Profit (loss) for the period      169       (22,189
                                 

 

 

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Table of Contents

Notes

 

 

2. Gulf of Mexico oil spill (continued)

 

 

     30 June 2011     31 December 2010  
     Total     Of which:
amount related
to the trust fund
    Total     Of which:
amount related
to  the trust fund
 

$ million

        

Balance sheet

        

Current assets

        

Trade and other receivables

     7,170       6,030       5,943       5,943  

Current liabilities

        

Trade and other payables

     (6,796     (6,146     (6,587     (5,002

Provisions

     (7,414     —          (7,938     —     
  

 

 

   

 

 

   

 

 

   

 

 

 

Net current assets (liabilities)

     (7,040     (116     (8,582     941  
  

 

 

   

 

 

   

 

 

   

 

 

 

Non-current assets

        

Other receivables

     2,667       2,667       3,601       3,601  

Non-current liabilities

        

Other payables

     (6,307     (6,307     (9,899     (9,899

Provisions

     (6,964     —          (8,397     —     

Deferred tax

     10,497       —          11,255       —     
  

 

 

   

 

 

   

 

 

   

 

 

 

Net non-current assets (liabilities)

     (107     (3,640     (3,440     (6,298
  

 

 

   

 

 

   

 

 

   

 

 

 

Net assets

     (7,147     (3,756     (12,022     (5,357
  

 

 

   

 

 

   

 

 

   

 

 

 

 

Second
quarter
     Second
quarter
         First half  
2010      2011          2011     2010  
     $ million     
     Cash flow statement – Operating activities     
  (32,192)         602     Profit (loss) before taxation      202       (32,192
     Adjustments to reconcile profit (loss) before taxation to net cash provided by operating activities     
  —           15     Net charge for interest and other finance expense, less net interest paid      31       —     
  17,646        (90   Net charge for provisions, less payments      112       17,646  
  12,430        (2,912   Movements in inventories and other current and non-current assets and liabilities      (5,776     12,430  

 

 

    

 

 

      

 

 

   

 

 

 
  (2,116)         (2,385   Pre-tax cash flows      (5,431     (2,116

 

 

    

 

 

      

 

 

   

 

 

 

Net cash used in operating activities relating to the Gulf of Mexico oil spill, on a post-tax basis, amounted to $1,898 million and $4,706 million in the second quarter and half year 2011 respectively.

Trust fund

In 2010, BP established the Deepwater Horizon Oil Spill Trust (the Trust) to be funded in the amount of $20 billion over the period to the fourth quarter of 2013, which is available to satisfy legitimate individual and business claims administered by the Gulf Coast Claims Facility (GCCF), state and local government claims resolved by BP, final judgments and settlements, state and local response costs, and natural resource damages and related costs. In 2010 BP contributed $5 billion to the fund, and further contributions of $2.5 billion were made in the first half of 2011. The income statement charge for 2010 included $20 billion in relation to the trust fund, adjusted to take account of the time value of money. Fines, penalties and claims administration costs are not covered by the trust fund.

Under the settlement agreement noted above, MOEX paid BP $1.1 billion in early July, which was subsequently contributed to the trust fund, and Weatherford have paid BP $75 million which will also be contributed to the trust fund.

 

 

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Notes

 

 

2. Gulf of Mexico oil spill (continued)

 

The table below shows movements in the funding obligation during the period to 30 June 2011. This liability is recognized within other payables on the balance sheet apportioned between current and non-current elements according to the agreed schedule of contributions.

 

     Second     First  
     quarter     half  
     2011     2011  

$ million

    

Opening balance

     13,668       14,901  

Unwinding of discount

     14       28  

Contribution

     (1,250     (2,500

Other

     21       24  
  

 

 

   

 

 

 

At 30 June 2011

     12,453       12,453  
  

 

 

   

 

 

 

Of which – current

     6,146       6,146  

  – non-current

     6,307       6,307  
  

 

 

   

 

 

 

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 to claimants 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 30 June 2011. The amount of the reimbursement asset at 30 June 2011 is equal to the amount of provisions recognized at that date that will be covered by the trust fund – see below.

 

     Second     First  
     quarter     half  
     2011     2011  

$ million

    

Opening balance

     9,544       9,544  

Increase in provision for items covered by the trust fund

     163       1,225  

Amounts paid directly by the trust fund

     (1,010     (2,072
  

 

 

   

 

 

 

At 30 June 2011

     8,697       8,697  
  

 

 

   

 

 

 

Of which – current

     6,030       6,030  

  – non-current

     2,667       2,667  
  

 

 

   

 

 

 

As noted above, the obligation to fund the $20-billion trust fund has been recognized in full. Any increases in the provision 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 30 June 2011, the cumulative charges for provisions, and the associated reimbursement asset recognized, amounted to $13,792 million. Thus, a further $6,208 million could be provided in subsequent periods for items covered by the trust fund with no net impact on the income statement. Such future increases in amounts provided could arise from adjustments to existing provisions, or from the initial recognition of provisions for items that currently cannot be estimated reliably, namely final judgments and settlements and natural resource damages and related costs. Further information on those items that currently cannot be reliably estimated is provided under Provisions and contingencies below.

It is not possible at this time to conclude whether the $20-billion trust fund will be sufficient to satisfy all claims under the Oil Pollution Act 1990 (OPA 90) that will ultimately be paid.

The Trust agreement does not require BP to make further contributions to the trust fund in excess of the agreed $20 billion should this be insufficient to cover all claims administered by the GCCF, or to settle other items that are covered by the trust fund, as described above. Should the $20-billion trust fund not be sufficient, BP would commence settling legitimate claims and other costs by making payments directly to claimants. In this case, increases in estimated future expenditure above $20 billion would be recognized as provisions with a corresponding charge in the income statement. The provisions would be utilized and derecognized at the point that BP made the payments.

 

 

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Notes

 

 

2. Gulf of Mexico oil spill (continued)

 

(b) Provisions and contingencies

BP has recorded certain provisions and disclosed certain contingencies 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 2010 – Financial statements – Notes 2, 37 and 44.

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.

On 21 April 2011, BP entered a framework agreement with natural resource trustees for the United States and five Gulf coast states, providing for up to $1 billion to be spent on early restoration projects to address natural resource injuries resulting from the Gulf of Mexico oil spill. Funding for these projects will come from the $20-billion Deepwater Horizon Oil Spill Trust.

BP considers that it is not possible, at this time, to measure reliably any obligation in relation to Natural Resources Damages claims under OPA 90 (other than the estimated costs of the assessment phase and the costs of the early and emergency restoration agreements referred to above) or litigation arising from alleged violations of OPA 90, any amounts in relation to fines and penalties except for those relating to the Clean Water Act and any obligation in relation to litigation or in relation to legal fees beyond 2012. These items are therefore disclosed as contingent liabilities – see below.

Movements in the provision during the second quarter and the half year are presented in the tables below.

 

           Spill     Litigation     Clean Water         
     Environmental     response     and claims     Act penalties      Total  

$ million

           

At 1 April 2011

     1,740       470       9,757       3,510        15,477  

Increase in provision – items not covered by the trust fund

     30       338       (9     —           359  

Increase in provision – items covered by the trust fund

     —          —          163       —           163  

Unwinding of discount

     1       —          —          —           1  

Utilization – paid by BP

     (7     (270     (335     —           (612

    – paid by the trust fund

     (89     —          (921     —           (1,010
  

 

 

   

 

 

   

 

 

   

 

 

    

 

 

 

At 30 June 2011

     1,675       538       8,655       3,510        14,378  
  

 

 

   

 

 

   

 

 

   

 

 

    

 

 

 

Of which – current

     773       538       6,103       —           7,414  

  – non-current

     902       —          2,552       3,510        6,964  
  

 

 

   

 

 

   

 

 

   

 

 

    

 

 

 

Of which – payable from the trust fund

     1,226       —          7,471       —           8,697  
  

 

 

   

 

 

   

 

 

   

 

 

    

 

 

 

 

 

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Table of Contents

Notes

 

 

2. Gulf of Mexico oil spill (continued)

 

           Spill     Litigation     Clean Water         
     Environmental     response     and claims     Act penalties      Total  

$ million

           

At 1 January 2011

     809       1,043       10,973       3,510        16,335  

Increase in provision – items not covered by the trust fund

     30       640       (9     —           661  

Increase in provision – items covered by the trust fund

     1,000       —          225       —           1,225  

Unwinding of discount

     3       —          —          —           3  

Utilization – paid by BP

     (10     (1,145     (619     —           (1,774

    – paid by the trust fund

     (157     —          (1,915     —           (2,072
  

 

 

   

 

 

   

 

 

   

 

 

    

 

 

 

At 30 June 2011

     1,675       538       8,655       3,510        14,378  
  

 

 

   

 

 

   

 

 

   

 

 

    

 

 

 

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

 

     Second     First  
     quarter     half  
     2011     2011  

$ million

    

Increase in provision

     522       1,886  

Recognition of reimbursement asset

     (163     (1,225

Other costs charged directly to the income statement

     199       281  

Settlements credited to the income statement

     (1,175     (1,175
  

 

 

   

 

 

 

(Profit) loss before interest and taxation

     (617     (233

Finance costs

     15       31  
  

 

 

   

 

 

 

(Profit) loss before taxation

     (602     (202
  

 

 

   

 

 

 

The total amounts that will ultimately be paid by BP in relation to all obligations relating to the incident are subject to significant uncertainty and the ultimate exposure and cost to BP will be dependent on many factors. Furthermore, the amount of claims that become payable by BP, the amount of fines ultimately levied on BP (including any determination of BP’s negligence), the outcome of litigation and arbitration proceedings, and any costs arising from any longer-term environmental consequences of the oil spill, will also impact upon the ultimate cost for BP.

In estimating the amount of the provision at 30 June 2011 for Individual and Business Claims, as administered by the GCCF, and State and Local Claims, BP has concluded that a reasonable range of possible outcomes is $4.4 billion to $10.8 billion. BP believes that the provision recorded at 30 June 2011 of $7.2 billion represents a reliable best estimate from within this range of possible outcomes. This amount is included within amounts payable from the trust fund under Litigation and claims in the table above.

Although the provision recognized is the current best reliable estimate of expenditures required to settle certain present obligations at the end of the reporting period, there are future expenditures for which it is not possible to measure the obligation reliably as noted below under Contingent liabilities.

As noted above, an agreement has been reached with MOEX, one of the co-owners of the Macondo prospect leasehold, to settle all claims between the companies related to the incident and the prospect. The settlement has been recorded in the income statement in the second quarter. No amount has been recognized for recovery of costs from the other co-owner, Anadarko Petroleum Corporation (Anadarko), because under IFRS the recovery must be virtually certain before such receivables can be recognized. This item is therefore disclosed as a contingent asset.

Further information on provisions is provided in BP Annual Report and Form 20-F 2010 – Financial statements – Note 37.

 

 

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Notes

 

 

2. Gulf of Mexico oil spill (continued)

 

Contingent liabilities

BP has provided for its best estimate of certain claims under OPA 90 that will be paid through the $20-billion trust fund. It is not possible, at this time, to measure reliably any other items that will be paid from the trust fund, 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 and emergency restoration agreements as described above under Provisions) and claims resolved by civil litigation, nor is it practicable to estimate their magnitude or possible timing of payment. Therefore no amounts have been provided for these items as of 30 June 2011.

For those items not covered by the trust fund it is not possible to measure reliably any obligation in relation to other litigation or potential fines and penalties except, subject to certain assumptions, for those relating to the Clean Water Act. It is also not possible to reliably estimate legal fees beyond 2012. Therefore no amounts have been provided for these items as of 30 June 2011.

See Legal proceedings on pages 46 – 49 and BP Annual Report and Form 20-F 2010 – Financial statements – Note 44 for further information on contingent liabilities.

Contingent assets

See Legal proceedings on pages 46 – 49 and BP Annual Report and Form 20-F 2010 – Financial statements – Note 44 for information on contingent assets.

As of 30 June 2011, $5.5 billion had been billed to our co-owner, Anadarko, which BP believes to be contractually recoverable pursuant to the terms of the Macondo Prospect Offshore Deepwater Operating Agreement. Billings to co-owners under this Operating Agreement are based upon costs incurred to date rather than amounts provided in the period. As further costs are incurred, BP believes that certain of the costs will be billable to Anadarko under the Operating Agreement. No recovery amounts from Anadarko have been recognized in the financial statements as at 30 June 2011.

On 4 April 2011, BP initiated contractual out-of-court dispute resolution proceedings against Anadarko, claiming that it has breached the parties’ contract by failing to reimburse BP for their working-interest share of incident-related costs. These procedures will culminate in arbitration if the parties cannot resolve their disputes through negotiation. On 19 April 2011, Anadarko filed a cross-claim against BP, alleging gross negligence and 15 other counts under state and federal laws. Anadarko seeks a declaration that it is excused from its contractual obligation to pay incident-related costs. Anadarko also seeks damages from alleged economic losses and contribution or indemnity for claims filed against it by other parties. BP disputes Anadarko’s cross-claims and intends to defend against them vigorously.

On 15 July 2011, the judge in the federal multi-district litigation proceeding in New Orleans stayed Anadarko’s claims against BP pursuant to the arbitration clause in the operating agreement between the parties pertaining to the Macondo well.

There are also audit rights concerning billings under the Operating Agreement which may be exercised by Anadarko, and which may or may not lead to an adjustment of the amount billed. BP may ultimately need to enforce its rights to collect payment from Anadarko following any successful arbitration proceedings as provided for in the Operating Agreement. There is a risk that amounts billed to Anadarko may not ultimately be recovered should Anadarko be found not liable for these costs or be unable to pay them. Moreover, negotiations with Anadarko could result in settlement of these claims, which if reached, may result in amounts to be received by BP differing from the amounts billed.

 

3. Non-current assets held for sale

As a result of the group’s disposal programme following the Gulf of Mexico oil spill, various assets, and associated liabilities, have been presented as held for sale in the group balance sheet at 30 June 2011. The carrying amount of the assets held for sale is $10,167 million, with associated liabilities of $1,127 million. Included within these amounts are the following items, all of which relate to the Exploration and Production segment unless otherwise stated.

On 14 December 2010, BP announced that it had reached agreement to sell its exploration and production assets in Pakistan to United Energy Group Limited for $775 million in cash. These assets, and associated liabilities, have been classified as held for sale in the group balance sheet at 30 June 2011. An interim injunction entered by the Islamabad High Court on 9 March 2011 in a preferential rights dispute affecting the Mirpur Khas and Khipro concessions has now been lifted. The sale is expected to be completed in the third quarter of 2011, subject to certain conditions precedent, including the satisfaction of closing conditions and the receipt of government and regulatory approvals.

 

 

28


Table of Contents

Notes

 

 

3. Non-current assets held for sale (continued)

 

On 18 October 2010, BP announced that it had reached agreement to sell its upstream and midstream assets in Vietnam, together with its upstream businesses and associated interests in Venezuela, to TNK-BP for $1.8 billion in cash, subject to post-closing adjustments. The sale of the Venezuelan business completed during the second quarter of 2011. The sale of the Vietnam business is expected to be completed in the third quarter of 2011, subject to regulatory and other approvals and conditions. The assets, and associated liabilities, of the Vietnam business have been classified as held for sale in the group balance sheet at 30 June 2011.

On 28 November 2010, BP announced that it had reached agreement to sell its interests in Pan American Energy (PAE) to Bridas Corporation for $7.06 billion in cash. PAE is an Argentina-based oil and gas company owned by BP (60%) and Bridas Corporation (40%). The transaction excludes the shares of PAE E&P Bolivia Ltd. BP’s investment in PAE has been classified as held for sale in the group balance sheet at 30 June 2011. The sale is expected to be completed in 2011, subject to closing conditions and government and regulatory approvals.

On 4 April 2011, BP announced that it had agreed the sale of its wholly-owned subsidiary, ARCO Aluminum Inc. (reported within Other businesses and corporate), to a consortium of Japanese companies for cash consideration of $680 million, subject to closing adjustments. The assets, and associated liabilities, of this subsidiary have been classified as held for sale in the group balance sheet at 30 June 2011. Subject to obtaining required regulatory approvals, the parties expect to complete the transaction in the third quarter of 2011.

In Canada, BP intends to dispose of its NGL business. The assets, and associated liabilities, of this business have been classified as held for sale in the group balance sheet at 30 June 2011. The sale is expected to be completed in 2011.

On 17 May 2011, BP announced that it had reached agreement to sell its interests in the Wytch Farm, Wareham, Beacon and Kimmeridge fields to Perenco UK Ltd (‘Perenco’) for up to $610 million in cash. The price includes $55 million contingent on Perenco’s future development of the Beacon field and on oil prices in 2011-13. The sale is expected to be completed in early 2012, subject to a number of third party and regulatory approvals. These assets, and associated liabilities, have been classified as held for sale in the group balance sheet at 30 June 2011.

As previously announced, following a strategic review of our Refining and Marketing business, BP intends to divest the Texas City refinery. The non-current assets, together with the inventories, of this business have been classified as held for sale in the group balance sheet at 30 June 2011. The sale is expected to be completed in 2012.

Disposal proceeds of $4.6 billion ($6.2 billion at 31 December 2010) received in advance of completion of certain of these transactions have been classified as finance debt on the group balance sheet. See Note 7 for further information.

The majority of the transactions noted above 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 above.

 

 

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Table of Contents

Notes

 

 

4. Sales and other operating revenues

 

Second
quarter
     Second
quarter
          First half  
2010      2011           2011      2010  
      $ million      
      By business      
  15,215        18,418      Exploration and Production      36,823        33,295  
  67,250        93,886      Refining and Marketing      171,319        131,536  
  794        985      Other businesses and corporate      1,841        1,584  

 

 

    

 

 

       

 

 

    

 

 

 
  83,259        113,289           209,983        166,415  

 

 

    

 

 

       

 

 

    

 

 

 
      Less: sales between businesses      
  9,042        11,539      Exploration and Production      22,064        18,788  
  281        165      Refining and Marketing      791        416  
  211        221      Other businesses and corporate      435        415  

 

 

    

 

 

       

 

 

    

 

 

 
  9,534        11,925           23,290        19,619  

 

 

    

 

 

       

 

 

    

 

 

 
      Third party sales and other operating revenues      
  6,173        6,879      Exploration and Production      14,759        14,507  
  66,969        93,721      Refining and Marketing      170,528        131,120  
  583        764      Other businesses and corporate      1,406        1,169  

 

 

    

 

 

       

 

 

    

 

 

 
  73,725        101,364      Total third party sales and other operating revenues      186,693        146,796  

 

 

    

 

 

       

 

 

    

 

 

 
      By geographical area      
  27,762        38,817      US      69,664        53,870  
  53,111        73,350      Non-US      137,205        107,120  

 

 

    

 

 

       

 

 

    

 

 

 
  80,873        112,167           206,869        160,990  
  7,148        10,803      Less: sales between areas      20,176        14,194  

 

 

    

 

 

       

 

 

    

 

 

 
  73,725        101,364           186,693        146,796  

 

 

    

 

 

       

 

 

    

 

 

 

 

5. Production and similar taxes

 

Second
quarter
     Second
quarter
          First half  
2010      2011           2011      2010  
      $ million      
  209        563      US      937        522  
  1,029        1,793      Non-US      3,250         1,992  

 

 

    

 

 

       

 

 

    

 

 

 
  1,238        2,356           4,187        2,514  

 

 

    

 

 

       

 

 

    

 

 

 

 

 

30


Table of Contents

Notes

 

 

6. 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. 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.

 

Second
quarter
     Second
quarter
         First half  
2010      2011          2011     2010  
     $ million     
     Results for the period     
  (17,150)         5,620     Profit (loss) for the period attributable to BP shareholders      12,744       (11,071
  1        1     Less: preference dividend      1       1  

 

 

    

 

 

      

 

 

   

 

 

 
  (17,151)         5,619     Profit (loss) attributable to BP ordinary shareholders      12,743       (11,072
  177        (311   Inventory holding (gains) losses, net of tax      (1,954     (304

 

 

    

 

 

      

 

 

   

 

 

 
  (16,974)         5,308     RC profit (loss) attributable to BP ordinary shareholders      10,789       (11,376

 

 

    

 

 

      

 

 

   

 

 

 
  18,787,629        18,886,382     Basic weighted average number of shares outstanding (thousand)(a)      18,851,483       18,779,227  
  3,131,272        3,147,730     ADS equivalent (thousand)(a)      3,141,914       3,129,871  

 

 

    

 

 

      

 

 

   

 

 

 
  19,031,671        19,118,850     Weighted average number of shares outstanding used to calculate diluted earnings per share (thousand)(a)      19,071,882       19,007,478  
  3,171,945        3,186,475     ADS equivalent (thousand)(a)      3,178,647       3,167,913  

 

 

    

 

 

      

 

 

   

 

 

 
  18,791,926        18,940,090     Shares in issue at period-end (thousand)(a)      18,940,090       18,791,926  
  3,131,988        3,156,682     ADS equivalent (thousand)(a)      3,156,682       3,131,988  

 

 

    

 

 

      

 

 

   

 

 

 

 

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

 

 

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Notes

 

 

7. Analysis of changes in net debt

 

Second

quarter

    

Second

quarter

         First half  

2010

     2011          2011     2010  
    

$ million

    
    

Opening balance

    
  32,153        47,102    

Finance debt

     45,336       34,627  
  6,841        18,726    

Less: Cash and cash equivalents

     18,556       8,339  
  152        870    

Less: FV asset of hedges related to finance debt

     916       127  

 

 

    

 

 

      

 

 

   

 

 

 
  25,160        27,506    

Opening net debt

     25,864       26,161  

 

 

    

 

 

      

 

 

   

 

 

 
    

Closing balance

    
  30,580        46,890    

Finance debt

     46,890       30,580  
  7,310        18,749    

Less: Cash and cash equivalents

     18,749       7,310  
  53        1,173    

Less: FV asset of hedges related to finance debt

     1,173       53  

 

 

    

 

 

      

 

 

   

 

 

 
  23,217        26,968    

Closing net debt

     26,968       23,217  

 

 

    

 

 

      

 

 

   

 

 

 
  1,943        538    

Decrease (increase) in net debt

     (1,104     2,944  

 

 

    

 

 

      

 

 

   

 

 

 
  631        (81  

Movement in cash and cash equivalents (excluding exchange adjustments)

     (106     (790
  1,291        563    

Net cash outflow (inflow) from financing (excluding share capital)

     (2,681     3,691  
  —           2    

Movement in finance debt relating to investing activities(a)

     1,597       —     
  20        5    

Other movements

     (16     27  

 

 

    

 

 

      

 

 

   

 

 

 
  1,942        489    

Movement in net debt before exchange effects

     (1,206     2,928  
  1        49    

Exchange adjustments

     102       16  

 

 

    

 

 

      

 

 

   

 

 

 
  1,943        538    

Decrease (increase) in net debt

     (1,104     2,944  

 

 

    

 

 

      

 

 

   

 

 

 

 

(a) During the second quarter 2011 disposal transactions were completed in respect of which deposits of $502 million, (first half 2011 $2,097 million) had been received in 2010. In addition, deposits of $500 million were received in the second quarter 2011, in respect of disposals expected to complete within the next year.

At 30 June 2011, $626 million of finance debt, ($1,155 million at 30 June 2010) was secured by the pledging of assets, and $3,530 million was secured in connection with deposits received relating to certain disposal transactions expected to complete in subsequent periods. In addition, in connection with $3,014 million of finance debt, BP has entered into crude oil sales contracts in respect of oil produced from certain fields in offshore Angola and Azerbaijan to provide security to the lending banks. The remainder of finance debt was unsecured.

During the first quarter 2011 the company signed new three-year committed standby facilities totalling $6.8 billion, available to draw and repay until mid-March 2014, largely replacing existing arrangements. At 30 June 2011 the total available undrawn committed borrowing facilities stood at $7.2 billion.

 

 

32


Table of Contents

Notes

 

 

8. TNK-BP operational and financial information

 

Second

quarter

    

Second

quarter

         First half  

2010

     2011          2011     2010  
    

Production (Net of royalties) (BP share)

    
  859        860    

Crude oil (mb/d)

     858       854  
  647        675    

Natural gas (mmcf/d)

     697       660  
  971        976    

Total hydrocarbons (mboe/d)(a)

     978       968  
                                 
    

$ million

    
    

Income statement (BP share)

    
  843        1,419    

Profit before interest and tax

     2,945       1,631  
  (34)         (34  

Finance costs

     (69     (72
  (266)         (238  

Taxation

     (484     (434
  (53)         (84  

Minority interest

     (143     (92
                                 
  490        1,063    

Net income

     2,249       1,033  
                                 
    

Cash flow

    
  505        1,634    

Dividends received

     1,634       761  
                                 
Balance sheet    30 June     31 December  
                  2011     2010  

 

Investments in associates

     10,536       9,995  
                     

 

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

 

9. Statutory accounts

The financial information shown in this publication, which was approved by the Board of Directors on 25 July 2011, is unaudited and does not constitute statutory financial statements.

 

 

33


Table of Contents

Notes

 

 

10. Condensed consolidating information

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

 

     Issuer     Guarantor                     
Income statement    BP
Exploration
(Alaska) Inc.
    BP p.l.c.     Other
subsidiaries
     Eliminations
and
reclassification
    BP
group
 
First half 2011    $ million  

Sales and other operating revenues

     3,084       —          186,693        (3,084     186,693  

Earnings from jointly controlled entities – after interest and tax

     —          —          565        —          565  

Earnings from associates – after interest and tax

     —          —          2,664        —          2,664  

Equity-accounted income of subsidiaries – after interest and tax

     266        13,038       —           (13,304     —     

Interest and other income

     3       76       293        (97     275  

Gains on sale of businesses and fixed assets

     —          —          1,963        —          1,963  
  

 

 

   

 

 

   

 

 

    

 

 

   

 

 

 

Total revenues and other income

     3,353       13,114       192,178        (16,485     192,160  

Purchases

     540       —          142,546        (3,084     140,002  

Production and manufacturing expenses

     590       —          12,118        —          12,708  

Production and similar taxes

     898       —          3,289        —          4,187  

Depreciation, depletion and amortization

     163       —          5,343        —          5,506  

Impairment and losses on sale of businesses and fixed assets

     —          3       1,439        —          1,442  

Exploration expense

     —          —          1,078        —          1,078  

Distribution and administration expenses

     9       561       5,820        (35     6,355  

Fair value (gain) loss on embedded derivatives

     —          —          396        —          396  
  

 

 

   

 

 

   

 

 

    

 

 

   

 

 

 

Profit (loss) before interest and taxation

     1,153       12,550       20,149        (13,366     20,486  

Finance costs

     13       11       660        (62     622  

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

     (1     (267     134        —          (134
  

 

 

   

 

 

   

 

 

    

 

 

   

 

 

 

Profit (loss) before taxation

     1,141       12,806       19,355        (13,304     19,998  

Taxation

     359       62       6,702        —          7,123  
  

 

 

   

 

 

   

 

 

    

 

 

   

 

 

 

Profit (loss) for the period

     782       12,744       12,653        (13,304     12,875  
  

 

 

   

 

 

   

 

 

    

 

 

   

 

 

 

Attributable to:

           

BP shareholders

     782       12,744       12,522        (13,304     12,744  

Minority interest

     —          —          131        —          131  
  

 

 

   

 

 

   

 

 

    

 

 

   

 

 

 
     782       12,744       12,653        (13,304     12,875  
  

 

 

   

 

 

   

 

 

    

 

 

   

 

 

 

 

 

34


Table of Contents

Notes

 

 

10. Condensed consolidating information (continued)

 

     Issuer      Guarantor                    
Income statement    BP
Exploration
(Alaska) Inc.
     BP p.l.c.     Other
subsidiaries
    Eliminations
and
reclassifications
    BP
group
 
First half 2010    $ million  

Sales and other operating revenues

     2,452        —          146,796       (2,452     146,796  

Earnings from jointly controlled entities – after interest and tax

     —           —          660       —          660  

Earnings from associates – after interest and tax

     —           —          1,523       —          1,523  

Equity-accounted income of subsidiaries – after interest and tax

     385        (11,056     —          10,671       —     

Interest and other income

     —           40       315       (55     300  

Gains on sale of businesses and fixed assets

     —           68       1,002       (61     1,009  
  

 

 

    

 

 

   

 

 

   

 

 

   

 

 

 

Total revenues and other income

     2,837        (10,948     150,296       8,103       150,288  

Purchases

     478        —          108,151       (2,452     106,177  

Production and manufacturing expenses

     486        —          43,233       —          43,719  

Production and similar taxes

     462        —          2,052       —          2,514  

Depreciation, depletion and amortization

     182        —          5,594       —          5,776  

Impairment and losses on sale of businesses and fixed assets

     —           —          108       —          108  

Exploration expense

     —           —          252       —          252  

Distribution and administration expenses

     14        220       5,749       (24     5,959  

Fair value (gain) loss on embedded derivatives

     —           —          306       —          306  
  

 

 

    

 

 

   

 

 

   

 

 

   

 

 

 

Profit (loss) before interest and taxation

     1,215        (11,168     (15,149     10,579       (14,523

Finance costs

     5        8       481       (31     463  

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

     2        (191     168       —          (21
  

 

 

    

 

 

   

 

 

   

 

 

   

 

 

 

Profit (loss) before taxation

     1,208        (10,985     (15,798     10,610       (14,965

Taxation

     279        86       (4,470     —          (4,105
  

 

 

    

 

 

   

 

 

   

 

 

   

 

 

 

Profit (loss) for the period

     929        (11,071     (11,328     10,610       (10,860
  

 

 

    

 

 

   

 

 

   

 

 

   

 

 

 

Attributable to:

           

BP shareholders

     929        (11,071     (11,539     10,610       (11,071

Minority interest

     —           —          211       —          211  
  

 

 

    

 

 

   

 

 

   

 

 

   

 

 

 
     929        (11,071     (11,328     10,610       (10,860
  

 

 

    

 

 

   

 

 

   

 

 

   

 

 

 

 

 

35


Table of Contents

Notes

 

 

10. Condensed consolidating information (continued)

 

     Issuer      Guarantor                      
Balance sheet    BP
Exploration

(Alaska) Inc
     BP p.l.c.      Other
subsidiaries
     Eliminations
and
reclassification
    BP
group
 

At 30 June 2011

Non-current assets

   $ million  

Property, plant and equipment

     7,849        —           104,356        —          112,205  

Goodwill

     —           —           9,470        —          9,470  

Intangible assets

     466        —           16,302        —          16,768  

Investments in jointly controlled entities

     —           —           12,483        —          12,483  

Investments in associates

     —           2        14,091        —          14,093  

Other investments

     —           —           1,366        —          1,366  

Subsidiaries – equity-accounted basis

     4,755        126,513        —           (131,268     —     
  

 

 

    

 

 

    

 

 

    

 

 

   

 

 

 

Fixed assets

     13,070        126,515        158,068        (131,268     166,385  

Loans

     —           40        5,140        (4,312     868  

Other receivables

     —           —           5,804        —          5,804  

Derivative financial instruments

     —           —           4,267        —          4,267  

Prepayments

     —           —           1,521        —          1,521  

Deferred tax assets

     —           —           546        —          546  

Defined benefit pension plan surpluses

     —           2,286        287        —          2,573  
  

 

 

    

 

 

    

 

 

    

 

 

   

 

 

 
     13,070        128,841        175,633        (135,580     181,964  
  

 

 

    

 

 

    

 

 

    

 

 

   

 

 

 

Current assets

             

Loans

     —           —           256        —          256  

Inventories

     153        —           27,324        —          27,477  

Trade and other receivables

     3,341        12,417        49,180        (22,016     42,922  

Derivative financial instruments

     —           —           3,796        —          3,796  

Prepayments

     165        —           3,818        —          3,983  

Current tax receivable

     —           —           268        —          268  

Other investments

     —           —           1,413        —          1,413  

Cash and cash equivalents

     —           13        18,736        —          18,749  
  

 

 

    

 

 

    

 

 

    

 

 

   

 

 

 
     3,659        12,430        104,791        (22,016     98,864  
  

 

 

    

 

 

    

 

 

    

 

 

   

 

 

 

Assets classified as held for sale

     —           —           10,167        —          10,167  
  

 

 

    

 

 

    

 

 

    

 

 

   

 

 

 

Total assets

     16,729        141,271        290,591        (157,596     290,995  
  

 

 

    

 

 

    

 

 

    

 

 

   

 

 

 

Current liabilities

             

Trade and other payables

     4,789        2,451        65,786        (22,016     51,010  

Derivative financial instruments

     —           —           3,273        —          3,273  

Accruals

     —           27        6,099        —          6,126  

Finance debt

     —           —           12,445        —          12,445  

Current tax payable

     168        —           3,715        —          3,883  

Provisions

     —           —           9,060        —          9,060  
  

 

 

    

 

 

    

 

 

    

 

 

   

 

 

 
     4,957        2,478        100,378        (22,016     85,797  
  

 

 

    

 

 

    

 

 

    

 

 

   

 

 

 

Liabilities directly associated with assets classified as held for sale

     —           —           1,127        —          1,127  
  

 

 

    

 

 

    

 

 

    

 

 

   

 

 

 
     4,957        2,478        101,505        (22,016     86,924  
  

 

 

    

 

 

    

 

 

    

 

 

   

 

 

 

Non-current liabilities

             

Other payables

     9        4,264        10,298        (4,312     10,259  

Derivative financial instruments

     —           —           3,705        —          3,705  

Accruals

     —           26        365        —          391  

Finance debt

     —           —           34,445        —          34,445  

Deferred tax liabilities

     2,122        499        11,130        —          13,751  

Provisions

     950        —           22,337        —          23,287  

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

     —           —           9,825        —          9,825  
  

 

 

    

 

 

    

 

 

    

 

 

   

 

 

 
     3,081        4,789        92,105        (4,312     95,663  
  

 

 

    

 

 

    

 

 

    

 

 

   

 

 

 

Total liabilities

     8,038        7,267        193,610        (26,328     182,587  
  

 

 

    

 

 

    

 

 

    

 

 

   

 

 

 

Net assets

     8,691        134,004        96,981        (131,268     108,408  
  

 

 

    

 

 

    

 

 

    

 

 

   

 

 

 

Equity

             

BP shareholders’ equity

     8,691        134,004        96,067        (131,268     107,494  

Minority interest

     —           —           914        —          914  
  

 

 

    

 

 

    

 

 

    

 

 

   

 

 

 

Total Equity

     8,691        134,004        96,981        (131,268     108,408  
  

 

 

    

 

 

    

 

 

    

 

 

   

 

 

 

 

 

36


Table of Contents

Notes

 

 

10. Condensed consolidating information (continued)

 

     Issuer      Guarantor                      
Balance sheet    BP
Exploration

(Alaska) Inc
     BP p.l.c.      Other
subsidiaries
     Eliminations
and
reclassification
    BP
group
 

At 30 June 2010

Non-current assets

   $ million  

Property, plant and equipment

     7,530        —           98,964        —          106,494  

Goodwill

     —           —           8,250        —          8,250  

Intangible assets

     373        —           13,825        —          14,198  

Investments in jointly controlled entities

     —           —           15,256        —          15,256  

Investments in associates

     —           2        13,472        —          13,474  

Other investments

     —           —           1,071        —          1,071  

Subsidiaries – equity-accounted basis

     4,809        85,822        —           (90,631     —     
                                           

Fixed assets

     12,712        85,824        150,838        (90,631     158,743  

Loans

     192        38        5,386        (4,692     924  

Other receivables

     —           —           3,905        —          3,905  

Derivative financial instruments

     —           —           4,404        —          4,404  

Prepayments

     —           —           1,292        —          1,292  

Deferred tax assets

     —           —           421        —          421  

Defined benefit pension plan surpluses

     —           1,360        317        —          1,677  
                                           
     12,904        87,222        166,563        (95,323     171,366  
                                           

Current assets

             

Loans

     —           —           244        —          244  

Inventories

     154        —           21,952        —          22,106  

Trade and other receivables

     18,920        31,399        41,792        (56,403     35,708  

Derivative financial instruments

     —           —           4,479        —          4,479  

Prepayments

     109        15        2,512        —          2,636  

Current tax receivable

     —           —           139        —          139  

Other investments

     —           —           1,654          1,654  

Cash and cash equivalents

     —           31        7,279        —          7,310  
                                           
     19,183        31,445        80,051        (56,403     74,276  
                                           

Assets classified as held for sale

     —           —           2,973        —          2,973  
                                           

Total assets

     32,087        118,667        249,587        (151,726     248,615  
                                           

Current liabilities

             

Trade and other payables

     4,797        2,322        94,786        (56,403     45,502  

Derivative financial instruments

     —           —           4,583        —          4,583  

Accruals

     —           21        5,463        —          5,484  

Finance debt

     —           —           8,321        —          8,321  

Current tax payable

     145        —           2,469        —          2,614  

Provisions

     —           —           13,439        —          13,439  
                                           
     4,942        2,343        129,061        (56,403     79,943  
                                           

Liabilities directly associated with assets classified as held for sale

     —           —           363        —          363  
                                           
     4,942        2,343        129,424        (56,403     80,306  
                                           

Non-current liabilities

             

Other payables

     211        4,255        16,498        (4,692     16,272  

Derivative financial instruments

     —           —           4,181        —          4,181  

Accruals

     —           17        575        —          592  

Finance debt

     —           —           22,259        —          22,259  

Deferred tax liabilities

     1,880        305        8,864        —          11,049  

Provisions

     1,052        —           17,536        —          18,588  

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

     —           —           9,006        —          9,006  
                                           
     3,143        4,577        78,919        (4,692     81,947  
                                           

Total liabilities

     8,085        6,920        208,343        (61,095     162,253  
                                           

Net assets

     24,002        111,747        41,244        (90,631     86,362  
                                           

Equity

             

BP shareholders’ equity

     24,002        111,747        40,372        (90,631     85,490  

Minority interest

     —           —           872        —          872  
                                           

Total Equity

     24,002        111,747        41,244        (90,631     86,362  
                                           

 

 

37


Table of Contents

Notes

 

 

10. Condensed consolidating information (continued)

 

     Issuer     Guarantor                    
Cash flow statement    BP
Exploration
(Alaska) Inc
    BP p.l.c.     Other
subsidiaries
    Eliminations
and
reclassification
    BP
group
 
     $ million  

First half 2011

          

Net cash provided by operating activities

     365       1,867        8,050       (30     10,252  

Net cash used in investing activities

     (364     (3     (10,997     —          (11,364

Net cash used in financing activities

     —          (1,855     2,831       30        1,006  

Currency translation differences relating to cash and cash equivalents

     —          —          299       —          299  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Increase in cash and cash equivalents

     1       9        183       —          193  

Cash and cash equivalents at beginning of period

     (1     4        18,553       —          18,556  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Cash and cash equivalents at end of period

     —          13        18,736       —          18,749  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

     Issuer     Guarantor                    
Cash flow statement    BP
Exploration
(Alaska) Inc
    BP p.l.c.     Other
subsidiaries
    Eliminations
and
reclassification
    BP
group
 
     $ million  

First half 2010

          

Net cash provided by operating activities

     422       2,952       13,775       (2,703     14,446  

Net cash used in investing activities

     (381     (189     (8,377     —          (8,947

Net cash used in financing activities

     (19     (2,760     (6,213     2,703        (6,289

Currency translation differences relating to cash and cash equivalents

     —          —          (239     —          (239
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

(Decrease) increase in cash and cash equivalents

     22       3       (1,054     —          (1,029

Cash and cash equivalents at beginning of period

     (22     28       8,333       —          8,339  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Cash and cash equivalents at end of period

     —          31       7,279       —          7,310  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

 

38


Table of Contents

Principal risks and uncertainties

 

We urge you to consider these risks carefully. The potential impact of their occurrence could be for our business, financial condition and results of operations to suffer and the trading price and liquidity of our securities to decline.

Our system of risk management identifies and provides the response to risks of group significance through the establishment of standards and other controls. Any failure of this system could lead to the occurrence, or re-occurrence, of any of the risks described below and a consequent material adverse effect on BP’s business, financial position, results of operations, competitive position, cash flows, prospects, liquidity, shareholder returns and/or implementation of its strategic agenda.

The risks are categorized against the following areas: strategic; compliance and control; and safety and operational. In addition, we have also set out two further risks for your attention – those resulting from the 2010 Gulf of Mexico oil spill (the Incident) and those related to the general macroeconomic outlook.

The Gulf of Mexico oil spill has had and could continue to have a material adverse impact on BP.

There is significant uncertainty in the extent and timing of costs and liabilities relating to the Incident, the impact of the Incident on our reputation and the resulting possible impact on our ability to access new opportunities. There is also significant uncertainty regarding potential changes in applicable regulations and the operating environment that may result from the Incident. These increase the risks to which the group is exposed and may cause our costs to increase. These uncertainties are likely to continue for a significant period. Thus, the Incident has had, and could continue to have, a material adverse impact on the group’s business, competitive position, financial performance, cash flows, prospects, liquidity, shareholder returns and/or implementation of its strategic agenda, particularly in the US.

We recognized charges totalling $40.9 billion in 2010 and a credit of $0.2 billion during the first half of 2011 as a result of the Incident. The total amounts that will ultimately be paid by BP in relation to all obligations relating to the Incident are subject to significant uncertainty and the ultimate exposure and cost to BP will be dependent on many factors. Furthermore, the amount of claims that become payable by BP, the amount of fines ultimately levied on BP (including any determination of BP’s negligence), the outcome of litigation, and any costs arising from any longer-term environmental consequences of the oil spill, will also impact upon the ultimate cost for BP. Although the provision recognized is the current best estimate of expenditures required to settle certain present obligations at the end of the reporting period, there are future expenditures for which it is not possible to measure the obligation reliably. The risks associated with the Incident could also heighten the impact of the other risks to which the group is exposed as further described below.

The general macroeconomic outlook can affect BP’s results given the nature of our business.

In the continuing uncertain financial and economic environment, certain risks may gain more prominence either individually or when taken together. Oil and gas prices can be very volatile, with average prices and margins influenced by changes in supply and demand. This is likely to exacerbate competition in all businesses, which may impact costs and margins. At the same time, governments are facing greater pressure on public finances, which may increase their motivation to intervene in the fiscal and regulatory frameworks of the oil and gas industry, including the risk of increased taxation, nationalization and expropriation. The global financial and economic situation may have a negative impact on third parties with whom we do, or may do, business. Any of these factors may affect our results of operations, financial condition, business prospects and liquidity and may result in a decline in the trading price and liquidity of our securities.

Capital markets have regained some confidence after the banking crisis of 2008 but are still subject to volatility and if there are extended periods of constraints in these markets, or if we are unable to access the markets, including due to our financial position or market sentiment as to our prospects, at a time when cash flows from our business operations may be under pressure, our ability to maintain our long-term investment programme may be impacted with a consequent effect on our growth rate, and may impact shareholder returns, including dividends and share buybacks, or share price. Decreases in the funded levels of our pension plans may also increase our pension funding requirements.

Strategic risks

Access and renewal – BP’s future hydrocarbon production depends on our ability to renew and reposition our portfolio. Increasing competition for access to investment opportunities, the effects of the Gulf of Mexico oil spill on our reputation and cash flows, and more stringent regulation could result in decreased access to opportunities globally.

Successful execution of our group strategy depends on implementing activities to renew and reposition our portfolio. The challenges to renewal of our upstream portfolio are growing due to increasing competition for access to opportunities globally among both national and international oil companies, and heightened political and economic risks in certain countries where significant hydrocarbon basins are located. Lack of material positions in new markets could impact our future hydrocarbon production.

 

 

39


Table of Contents

Principal risks and uncertainties (continued)

 

 

Moreover, the Gulf of Mexico oil spill has damaged BP’s reputation, which may have a long-term impact on the group’s ability to access new opportunities, both in the US and elsewhere. Adverse public, political and industry sentiment towards BP, and towards oil and gas drilling activities generally, could damage or impair our existing commercial relationships with counterparties, partners and host governments and could impair our access to new investment opportunities, exploration properties, operatorships or other essential commercial arrangements with potential partners and host governments, particularly in the US. In addition, responding to the Incident has placed, and will continue to place, a significant burden on our cash flow over the next several years, which could also impede our ability to invest in new opportunities and deliver long-term growth.

More stringent regulation of the oil and gas industry generally, and of BP’s activities specifically, arising from the Incident, could increase this risk.

Prices and markets – BP’s financial performance is subject to the fluctuating prices of crude oil and gas as well as the volatile prices of refined products and the profitability of our refining and petrochemicals operations.

Oil, gas and product prices are subject to international supply and demand. Political developments and the outcome of meetings of OPEC can particularly affect world supply and oil prices. Previous oil price increases have resulted in increased fiscal take, cost inflation and more onerous terms for access to resources. As a result, increased oil prices may not improve margin performance. In addition to the adverse effect on revenues, margins and profitability from any fall in oil and natural gas prices, a prolonged period of low prices or other indicators would lead to further reviews for impairment of the group’s oil and natural gas properties. Such reviews would reflect management’s view of long-term oil and natural gas prices and could result in a charge for impairment that could have a significant effect on the group’s results of operations in the period in which it occurs. Rapid material or sustained change in oil, gas and product prices can impact the validity of the assumptions on which strategic decisions are based and, as a result, the ensuing actions derived from those decisions may no longer be appropriate. A prolonged period of low oil prices may impact our ability to maintain our long-term investment programme with a consequent effect on our growth rate and may impact shareholder returns, including dividends and share buybacks, or share price. Periods of global recession could impact the demand for our products, the prices at which they can be sold and affect the viability of the markets in which we operate.

Refining profitability can be volatile, with both periodic over-supply and supply tightness in various regional markets, coupled with fluctuations in demand. Sectors of the petrochemicals industry are also subject to fluctuations in supply and demand, with a consequent effect on prices and profitability.

Climate change and carbon pricing – climate change and carbon pricing policies could result in higher costs and reduction in future revenue and strategic growth opportunities.

Compliance with changes in laws, regulations and obligations relating to climate change could result in substantial capital expenditure, taxes, reduced profitability from changes in operating costs, and revenue generation and strategic growth opportunities being impacted. Our commitment to the transition to a lower-carbon economy may create expectations for our activities, and the level of participation in alternative energies carries reputational, economic and technology risks.

Socio-political – the diverse nature of our operations around the world exposes us to a wide range of political developments and consequent changes to the operating environment, regulatory environment and law.

We have operations, and are seeking new opportunities, in countries where political, economic and social transition is taking place. Some countries have experienced, or may experience in the future, political instability, changes to the regulatory environment, changes in taxation, expropriation or nationalization of property, civil strife, strikes, acts of war and insurrections. Any of these conditions occurring could disrupt or terminate our operations, causing our development activities to be curtailed or terminated in these areas, or our production to decline, could limit our ability to pursue new opportunities and could cause us to incur additional costs. In particular, our investments in the US, Russia, Iraq, Egypt, Libya and other countries could be adversely affected by heightened political and economic environment risks. See Annual Report and Form 20-F 2010 pages 14 – 15 for information on the locations of our major assets and activities.

We set ourselves high standards of corporate citizenship and aspire to contribute to a better quality of life through the products and services we provide. If it is perceived that we are not respecting or advancing the economic and social progress of the communities in which we operate, our reputation and shareholder value could be damaged.

Competition – BP’s group strategy depends upon continuous innovation in a highly competitive market.

The oil, gas and petrochemicals industries are highly competitive. There is strong competition, both within the oil and gas industry and with other industries, in supplying the fuel needs of commerce, industry and the home. Competition puts pressure on product prices, affects oil products marketing and requires continuous management focus on reducing unit costs and improving efficiency, while ensuring safety and operational risk is not compromised. The implementation of group strategy requires continued technological advances and innovation including advances in exploration, production, refining, petrochemicals manufacturing technology and advances in technology related to energy usage. Our performance could be impeded if competitors developed or acquired intellectual property rights to technology that we required or if our innovation lagged the industry.

Investment efficiency – poor investment decisions could negatively impact our business.

Our organic growth is dependent on creating a portfolio of quality options and investing in the best options. Ineffective investment selection and development could lead to loss of value and higher capital expenditure.

 

 

40


Table of Contents

Principal risks and uncertainties (continued)

 

 

Reserves replacement – inability to progress upstream resources in a timely manner could adversely affect our long-term replacement of reserves and negatively impact our business.

Successful execution of our group strategy depends critically on sustaining long-term reserves replacement. If upstream resources are not progressed in a timely and efficient manner, we will be unable to sustain long-term replacement of reserves.

Liquidity, financial capacity and financial exposure – failure to operate within our financial framework could impact our ability to operate and result in financial loss. Exchange rate fluctuations can impact our underlying costs and revenues.

The group seeks to maintain a financial framework to ensure that it is able to maintain an appropriate level of liquidity and financial capacity. This framework constrains the level of assessed capital at risk for the purposes of positions taken in financial instruments. Failure to accurately forecast or maintain sufficient liquidity and credit to meet these needs could impact our ability to operate and result in a financial loss. Commercial credit risk is measured and controlled to determine the group’s total credit risk. Inability to determine adequately our credit exposure could lead to financial loss. A credit crisis affecting banks and other sectors of the economy could impact the ability of counterparties to meet their financial obligations to the group. It could also affect our ability to raise capital to fund growth and to meet our obligations. The change in the group’s financial framework during 2010 to make it more prudent may not be sufficient to avoid a substantial and unexpected cash call.

BP’s clean-up costs and potential liabilities resulting from pending and future claims, lawsuits and enforcement actions relating to the Gulf of Mexico oil spill, together with the potential cost of implementing remedies sought in the various proceedings, cannot be fully estimated at this time but they have had, and could continue to have, a material adverse impact on the group’s business, competitive position, financial performance, cash flows, prospects, liquidity, shareholder returns and/or implementation of its strategic agenda, particularly in the US. Furthermore, we have recognized a total charge of $40.9 billion during 2010 and a credit of $0.2 billion during the first half of 2011, and further potential liabilities may continue to have a material adverse effect on the group’s results of operations and financial condition. See Note 2 on page 23 – 28 and Legal proceedings on pages 46 – 49. More stringent regulation of the oil and gas industry arising from the Incident, and of BP’s activities specifically, could increase this risk.

Crude oil prices are generally set in US dollars, while sales of refined products may be in a variety of currencies. Fluctuations in exchange rates can therefore give rise to foreign exchange exposures, with a consequent impact on underlying costs and revenues.

For more information on financial instruments and financial risk factors see Annual Report and Form 20-F 2010 – Note 27 on page 185.

Insurance – BP’s insurance strategy means that the group could, from time to time, be exposed to material uninsured losses which could have a material adverse effect on BP’s financial condition and results of operations.

In the context of the limited capacity of the insurance market, many significant risks are retained by BP. The group generally restricts its purchase of insurance to situations where this is required for legal or contractual reasons. This means that the group could be exposed to material uninsured losses, which could have a material adverse effect on its financial condition and results of operations. In particular, these uninsured costs could arise at a time when BP is facing material costs arising out of some other event which could put pressure on BP’s liquidity and cash flows. For example, BP has borne and will continue to bear the entire burden of its share of any property damage, well control, pollution clean-up and third-party liability expenses arising out of the Gulf of Mexico oil spill incident.

Compliance and control risks

Regulatory – the oil industry in general, and in particular the US industry following the Gulf of Mexico oil spill, may face increased regulation that could increase the cost of regulatory compliance and limit our access to new exploration properties.

The Gulf of Mexico oil spill is likely to result in more stringent regulation of oil and gas activities in the US and elsewhere, particularly relating to environmental, health and safety controls and oversight of drilling operations, as well as access to new drilling areas. Regulatory or legislative action may impact the industry as a whole and could be directed specifically towards BP. The US government imposed a moratorium on certain offshore drilling activities, which was subsequently lifted in October 2010. While the industry has resumed drilling activity, BP has not yet done so. BP has, however, restarted rig operations. Similar actions may be taken by governments elsewhere in the world. New regulations and legislation, as well as evolving practices, could increase the cost of compliance and may require changes to our drilling operations, exploration, development and decommissioning plans, and could impact our ability to capitalize on our assets and limit our access to new exploration properties or operatorships, particularly in the deepwater Gulf of Mexico. In addition, increases in taxes, royalties and other amounts payable to governments or governmental agencies, or restrictions on availability of tax relief, could also be imposed as a response to the Incident.

 

 

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In addition, the oil industry is subject to regulation and intervention by governments throughout the world in such matters as the award of exploration and production interests, the imposition of specific drilling obligations, environmental, health and safety controls, controls over the development and decommissioning of a field (including restrictions on production) and, possibly, nationalization, expropriation, cancellation or non-renewal of contract rights. We buy, sell and trade oil and gas products in certain regulated commodity markets. Failure to respond to changes in trading regulations could result in regulatory action and damage to our reputation. The oil industry is also subject to the payment of royalties and taxation, which tend to be high compared with those payable in respect of other commercial activities, and operates in certain tax jurisdictions that have a degree of uncertainty relating to the interpretation of, and changes to, tax law. As a result of new laws and regulations or other factors, we could be required to curtail or cease certain operations, or we could incur additional costs.

For more information on environmental regulation, see Annual Report and Form 20-F 2010 pages 78 – 81.

Ethical misconduct and non-compliance – ethical misconduct or breaches of applicable laws by our employees could be damaging to our reputation and shareholder value.

Our code of conduct, which applies to all employees, defines our commitment to integrity, compliance with all applicable legal requirements, high ethical standards and the behaviours and actions we expect of our businesses and people wherever we operate. Incidents of ethical misconduct or non-compliance with applicable laws and regulations, including non-compliance with anti-bribery, anti-corruption and other applicable laws could be damaging to our reputation and shareholder value. Multiple events of non-compliance could call into question the integrity of our operations. For example, in our trading businesses, there is the risk that a determined individual could operate as a ‘rogue trader’, acting outside BP’s delegations, controls or code of conduct in pursuit of personal objectives that could be to the detriment of BP and its shareholders.

For certain legal proceedings involving the group, see Legal proceedings on pages 46 – 49. For further information on the risks involved in BP’s trading activities, see Operational risks – Treasury and trading activities on page 45.

Liabilities and provisions – BP’s potential liabilities resulting from pending and future claims, lawsuits and enforcement actions relating to the Gulf of Mexico oil spill, together with the potential cost and burdens of implementing remedies sought in the various proceedings, cannot be fully estimated at this time but they have had, and are expected to continue to have, a material adverse impact on the group’s business.

Under the OPA 90 BP Exploration & Production Inc. is one of the parties financially responsible for the clean-up of the Gulf of Mexico oil spill and for certain economic damages as provided for in OPA 90, as well as any natural resource damages associated with the spill and certain costs incurred by federal and state trustees engaged in a joint assessment of such natural resource damages.

BP and certain of its subsidiaries have also been named as defendants in numerous lawsuits in the US arising out of the Incident, including actions for personal injury and wrongful death, purported class actions for commercial or economic injury, actions for breach of contract, violations of statutes, property and other environmental damage, securities law claims and various other claims. See Legal proceedings on pages 46 – 49.

BP is subject to a number of investigations related to the Incident by numerous federal and State agencies. See Legal proceedings on pages 46 – 49. The types of enforcement action pursued and the nature of the remedies sought will depend on the discretion of the prosecutors and regulatory authorities and their assessment of BP’s culpability following their investigations. Such enforcement actions could include criminal proceedings against BP and/or employees of the group. In addition to fines and penalties, such enforcement actions could result in the suspension of operating licences and debarment from government contracts. Debarment of BP Exploration & Production Inc. would prevent it from bidding on or entering into new federal contracts or other federal transactions, and from obtaining new orders or extensions to existing federal contracts, including federal procurement contracts or leases. Dependent on the circumstances, debarment or suspension may also be sought against affiliated entities of BP Exploration & Production Inc. Although BP believes that there are costs arising out of the spill that are recoverable from its partners and other parties responsible under OPA 90, and although settlements have been agreed with one partner and one contractor during the second quarter, further recoveries are not certain and so have not been recognized in the financial statements (see Note 2 on pages 23 – 28).

Any finding of gross negligence for purposes of penalties sought against the group under the Clean Water Act would also have a material adverse impact on the group’s reputation, would affect our ability to recover costs relating to the Incident from our partners and other parties responsible under OPA 90 and could affect the fines and penalties payable by the group with respect to the Incident under enforcement actions outside the Clean Water Act context.

The Gulf of Mexico oil spill has damaged BP’s reputation. This, combined with other recent events in the US (including the 2005 explosion at the Texas City refinery and the 2006 pipeline leaks in Alaska), may lead to an increase in the number of citations and/or the level of fines imposed in relation to the Gulf of Mexico oil spill and any future alleged breaches of safety or environmental regulations.

 

 

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Claims by individuals and businesses under OPA 90 are adjudicated by the Gulf Coast Claims Facility (GCCF) headed by Kenneth Feinberg, who was jointly appointed by BP and the US Administration. On 18 February 2011, the GCCF announced its final rules governing payment options, eligibility and substantiation criteria, and final payment methodology. The impact of these rules, or other events related to the adjudication of claims, on future payments by the GCCF is uncertain. Payments could ultimately be significantly higher or lower than the amount we have estimated for individual and business claims under OPA 90 included in the provision BP recognized for litigation and claims. See Note 2 on pages 23 – 28.

Changes in external factors could affect our results of operations and the adequacy of our provisions.

We remain exposed to changes in the external environment, such as new laws and regulations (whether imposed by international treaty or by national or local governments in the jurisdictions in which we operate), changes in tax or royalty regimes, price controls, government actions to cancel or renegotiate contracts, market volatility or other factors. Such factors could reduce our profitability from operations in certain jurisdictions, limit our opportunities for new access, require us to divest or write-down certain assets or affect the adequacy of our provisions for pensions, tax, environmental and legal liabilities. Potential changes to pension or financial market regulation could also impact funding requirements of the group.

Reporting – failure to accurately report our data could lead to regulatory action, legal liability and reputational damage.

External reporting of financial and non-financial data is reliant on the integrity of systems and people. Failure to report data accurately and in compliance with external standards could result in regulatory action, legal liability and damage to our reputation.

Safety and operational risks

The risks inherent in our operations include a number of hazards that, although many may have a low probability of occurrence, can have extremely serious consequences if they do occur, such as the Gulf of Mexico incident. The occurrence of any such risks could have a consequent material adverse impact on the group’s business, competitive position, cash flows, results of operations, financial position, prospects, liquidity, shareholder returns and/or implementation of the group’s strategic goals.

Process safety, personal safety and environmental risks – the nature of our operations exposes us to a wide range of significant health, safety, security and environmental risks, the occurrence of which could result in regulatory action, legal liability and increased costs and damage to our reputation.

The nature of the group’s operations exposes us to a wide range of significant health, safety, security and environmental risks. The scope of these risks is influenced by the geographic range, operational diversity and technical complexity of our activities. In addition, in many of our major projects and operations, risk allocation and management is shared with third parties, such as contractors, sub-contractors, joint venture partners and associates. See ‘Joint ventures and other contractual arrangements – BP may not have full operational control and may have exposure to counterparty credit risk and disruptions to our operations due to the nature of some of its business relationships’ on page 45.

There are risks of technical integrity failure as well as risk of natural disasters and other adverse conditions in many of the areas in which we operate, which could lead to loss of containment of hydrocarbons and other hazardous material, as well as the risk of fires, explosions or other incidents.

In addition, inability to provide safe environments for our workforce and the public could lead to injuries or loss of life and could result in regulatory action, legal liability and damage to our reputation.

Our operations are often conducted in difficult or environmentally sensitive locations, in which the consequences of a spill, explosion, fire or other incident could be greater than in other locations. These operations are subject to various environmental laws, regulations and permits and the consequences of failure to comply with these requirements can include remediation obligations, penalties, loss of operating permits and other sanctions. Accordingly, inherent in our operations is the risk that if we fail to abide by environmental and safety and protection standards, such failure could lead to damage to the environment and could result in regulatory action, legal liability, material costs and damage to our reputation or licence to operate.

To help address health, safety, security, environmental and operations risks, and to provide a consistent framework within which the group can analyze the performance of its activities and identify and remediate shortfalls, BP implemented a group-wide operating management system (OMS). The embedding of OMS continues and following the Gulf of Mexico oil spill an enhanced S&OR function has been established, reporting directly to the group chief executive. There can be no assurance that OMS will adequately identify all process safety, personal safety and environmental risk or provide the correct mitigations, or that all operations will be in compliance with OMS at all times.

Security – hostile activities against our staff and activities could cause harm to people and disrupt our operations.

Security threats require continuous oversight and control. Acts of terrorism, piracy, sabotage and similar activities directed against our operations and offices, pipelines, transportation or computer systems could cause harm to people and could severely disrupt business and operations. Our business activities could also be severely disrupted by civil strife and political unrest in areas where we operate.

 

 

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Product quality – failure to meet product quality standards could lead to harm to people and the environment and loss of customers.

Supplying customers with on-specification products is critical to maintaining our licence to operate and our reputation in the marketplace. Failure to meet product quality standards throughout the value chain could lead to harm to people and the environment and loss of customers.

Drilling and production – these activities require high levels of investment and are subject to natural hazards and other uncertainties. Activities in challenging environments heighten many of the drilling and production risks including those of integrity failures, which could lead to curtailment, delay or cancellation of drilling operations, or inadequate returns from exploration expenditure.

Exploration and production require high levels of investment and are subject to natural hazards and other uncertainties, including those relating to the physical characteristics of an oil or natural gas field. Our exploration and production activities are often conducted in extremely challenging environments, which heighten the risks of technical integrity failure and natural disasters discussed above. The cost of drilling, completing or operating wells is often uncertain. We may be required to curtail, delay or cancel drilling operations because of a variety of factors, including unexpected drilling conditions, pressure or irregularities in geological formations, equipment failures or accidents, adverse weather conditions and compliance with governmental requirements. In addition, exploration expenditure may not yield adequate returns, for example in the case of unproductive wells or discoveries that prove uneconomic to develop. The Gulf of Mexico incident illustrates the risks we face in our drilling and production activities.

Transportation – all modes of transportation of hydrocarbons involve inherent and significant risks.

All modes of transportation of hydrocarbons involve inherent risks. An explosion or fire or loss of containment of hydrocarbons or other hazardous material could occur during transportation by road, rail, sea or pipeline. This is a significant risk due to the potential impact of a release on the environment and people and given the high volumes involved.

Major project delivery – our group plan depends upon successful delivery of major projects, and failure to deliver major projects successfully could adversely affect our financial performance.

Successful execution of our group plan depends critically on implementing the activities to deliver the major projects over the plan period. Poor delivery of any major project that underpins production or production growth, including maintenance turnaround programmes, and/or a major programme designed to enhance shareholder value could adversely affect our financial performance. Successful project delivery requires, among other things, adequate engineering and other capabilities and therefore successful recruitment and development of staff is central to our plans. See ‘People and capability – successful recruitment and development of staff is central to our plans’ below.

Digital infrastructure is an important part of maintaining our operations, and a breach of our digital security could result in serious damage to business operations, personal injury, damage to assets, harm to the environment and breaches of regulations.

The reliability and security of our digital infrastructure are critical to maintaining the availability of our business applications. A breach of our digital security could cause serious damage to business operations and, in some circumstances, could result in injury to people, damage to assets, harm to the environment and breaches of regulations.

Business continuity and disaster recovery – the group must be able to recover quickly and effectively from any disruption or incident, as failure to do so could adversely affect our business and operations.

Contingency plans are required to continue or recover operations following a disruption or incident. Inability to restore or replace critical capacity to an agreed level within an agreed timeframe would prolong the impact of any disruption and could severely affect business and operations.

Crisis management – crisis management plans are essential to respond effectively to emergencies and to avoid a potentially severe disruption in our business and operations.

Crisis management plans and capability are essential to deal with emergencies at every level of our operations. If we do not respond, or are perceived not to respond, in an appropriate manner to either an external or internal crisis, our business and operations could be severely disrupted.

People and capability – successful recruitment and development of staff is central to our plans.

Successful recruitment of new staff, employee training, development and long-term renewal of skills, in particular technical capabilities such as petroleum engineers and scientists, are key to implementing our plans. Inability to develop human capacity and capability, both across the organization and in specific operating locations, could jeopardize performance delivery.

In addition, significant management focus is required in responding to the Gulf of Mexico oil spill Incident. Although BP set up the Gulf Coast Restoration Organization to manage the group’s long-term response, key management and operating personnel will need to continue to devote substantial attention to responding to the Incident and to address the associated consequences for the group. The group relies on recruiting and retaining high-quality employees to execute its strategic plans and to operate its business. The Incident response has placed significant demands on our employees, and the reputational damage suffered by the group as a result of the Incident and any consequent adverse impact on our performance could affect employee recruitment and retention.

 

 

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Treasury and trading activities – control of these activities depends on our ability to process, manage and monitor a large number of transactions. Failure to do this effectively could lead to business disruption, financial loss, regulatory intervention or damage to our reputation.

In the normal course of business, we are subject to operational risk around our treasury and trading activities. Control of these activities is highly dependent on our ability to process, manage and monitor a large number of complex transactions across many markets and currencies. Shortcomings or failures in our systems, risk management methodology, internal control processes or people could lead to disruption of our business, financial loss, regulatory intervention or damage to our reputation.

Following the Gulf of Mexico oil spill, Moody’s Investors Service, Standard and Poor’s and Fitch Ratings downgraded the group’s long-term credit ratings. Since that time, the group’s credit ratings have improved somewhat but are still lower than they were immediately before the Gulf of Mexico oil spill. The impact that a significant operational incident can have on the group’s credit ratings, taken together with the reputational consequences of any such incident, the ratings and assessments published by analysts and investors’ concerns about the group’s costs arising from any such incident, ongoing contingencies, liquidity, financial performance and volatile credit spreads, could increase the group’s financing costs and limit the group’s access to financing. The group’s ability to engage in its trading activities could also be impacted due to counterparty concerns about the group’s financial and business risk profile in such circumstances. Such counterparties could require that the group provide collateral or other forms of financial security for its obligations, particularly if the group’s credit ratings are downgraded. Certain counterparties for the group’s non-trading businesses could also require that the group provide collateral for certain of its contractual obligations, particularly if the group’s credit ratings were downgraded below investment grade or where a counterparty had concerns about the group’s financial and business risk profile following a significant operational incident. In addition, BP may be unable to make a drawdown under certain of its committed borrowing facilities in the event we are aware that there are pending or threatened legal, arbitration or administrative proceedings which, if determined adversely, might reasonably be expected to have a material adverse effect on our ability to meet the payment obligations under any of these facilities. Credit rating downgrades could trigger a requirement for the company to review its funding arrangements with the BP pension trustees. Extended constraints on the group’s ability to obtain financing and to engage in its trading activities on acceptable terms (or at all) would put pressure on the group’s liquidity. In addition, this could occur at a time when cash flows from our business operations would be constrained following a significant operational incident, and the group could be required to reduce planned capital expenditures and/or increase asset disposals in order to provide additional liquidity, as the group did following the Gulf of Mexico oil spill.

Joint ventures and other contractual arrangements – BP may not have full operational control and may have exposure to counterparty credit risk and disruptions to our operations and strategic objectives due to the nature of some of its business relationships.

Many of our major projects and operations are conducted through joint ventures or associates and through contracting and sub-contracting arrangements. These arrangements often involve complex risk allocation, decision-making processes and indemnification arrangements. In certain cases, we may have less control of such activities than we would have if BP had full operational control. Our partners may have economic or business interests or objectives that are inconsistent with or opposed to, those of BP, and may exercise veto rights to block certain key decisions or actions that BP believes are in its or the joint venture’s or associate’s best interests, or approve such matters without our consent. Additionally, our joint venture partners or associates or contractual counterparties are primarily responsible for the adequacy of the human or technical competencies and capabilities which they bring to bear on the joint project, and in the event these are found to be lacking, our joint venture partners or associates may not be able to meet their financial or other obligations to their counterparties or to the relevant project, potentially threatening the viability of such projects. Furthermore, should accidents or incidents occur in operations in which BP participates, whether as operator or otherwise, and where it is held that our sub-contractors or joint-venture partners are legally liable to share any aspects of the cost of responding to such incidents, the financial capacity of these third parties may prove inadequate to fully indemnify BP against the costs we incur on behalf of the joint venture or contractual arrangement. Should a key sub-contractor, such as a lessor of drilling rigs, be no longer able to make these assets available to BP, this could result in serious disruption to our operations. Where BP does not have operational control of a venture, BP may nonetheless still be pursued by regulators or claimants in the event of an incident.

 

 

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Legal proceedings

 

Proceedings relating to the Gulf of Mexico oil spill

BP p.l.c., BP Exploration & Production Inc. (BP E&P) and various other BP entities (collectively referred to as BP) are among the companies named as defendants in more than 500 private civil lawsuits resulting from the 20 April 2010 explosions and fire on the semi-submersible rig Deepwater Horizon and resulting oil spill (the Incident) and further actions are likely to be brought. BP E&P is lease operator of Mississippi Canyon, Block 252 in the Gulf of Mexico (Macondo), where the Deepwater Horizon was deployed at the time of the Incident, and holds a 65% working interest. The other working interest owners are Anadarko Petroleum Company (Anadarko) and MOEX Offshore 2007 LLC (MOEX). The Deepwater Horizon, which was owned and operated by certain affiliates of Transocean, Ltd. (Transocean), sank on 22 April 2010. The pending lawsuits and/or claims arising from the Incident have been brought in US federal and state courts. Plaintiffs include individuals, corporations and governmental entities and many of the lawsuits purport to be class actions. The lawsuits assert, among other things, claims for personal injury in connection with the Incident itself and the response to it, wrongful death, commercial and economic injury, breach of contract and violations of statutes. The lawsuits seek various remedies including compensation to injured workers and families of deceased workers, recovery for commercial losses and property damage, claims for environmental damage, remediation costs, injunctive relief, treble damages and punitive damages. Purported classes of claimants include residents of the states of Louisiana, Mississippi, Alabama, Florida, Texas, Tennessee, Kentucky, Georgia and South Carolina, property owners and rental agents, fishermen and persons dependent on the fishing industry, charter boat owners and deck hands, marina owners, gasoline distributors, shipping interests, restaurant and hotel owners, cruise lines and others who are property and/or business owners alleged to have suffered economic loss. Among other claims arising from the spill response efforts, lawsuits have been filed claiming that additional payments are due by BP under certain Master Vessel Charter Agreements entered into in the course of the Vessels of Opportunity Program.

Shareholder derivative lawsuits related to the Incident have also been filed in US federal and state courts against various current and former officers and directors of BP alleging, among other things, breach of fiduciary duty, gross mismanagement, abuse of control and waste of corporate assets. Purported class action lawsuits have also been filed in US federal courts against BP entities and various current and former officers and directors alleging, among other things, securities fraud claims, violations of the Employee Retirement Income Security Act (ERISA) and contractual and quasi-contractual claims related to the cancellation of the dividend on 16 June 2010. In addition, BP has been named in several lawsuits alleging claims under the Racketeer-Influenced and Corrupt Organizations Act (RICO). In August 2010, many of the lawsuits pending in federal court were consolidated by the Federal Judicial Panel on Multidistrict Litigation into two multi-district litigation proceedings, one in federal court in Houston for the securities, derivative and ERISA cases and another in federal court in New Orleans for the remaining cases. Since late September 2010, most of the Deepwater Horizon related cases have been pending before these courts.

On 1 June 2010, the US Department of Justice (DoJ) announced that it is conducting an investigation into the Incident encompassing possible violations of US civil or criminal laws. The United States filed a civil complaint against BP E&P and others on 15 December 2010 (DoJ Action). The complaint seeks a declaration of liability under the Oil Pollution Act of 1990 (OPA 90) and civil penalties under the Clean Water Act and sets forth a purported reservation of rights on behalf of the US to amend the complaint or file additional complaints seeking various remedies under various US federal laws and statutes.

On 18 February 2011, Transocean filed a third party complaint against BP, the US government, and other corporations involved in the Incident, naming those entities as formal parties in its Limitation of Liability action pending in federal court in New Orleans.

On 4 April 2011, BP initiated contractual out-of-court dispute resolution proceedings against Anadarko and MOEX, claiming that they have breached the parties’ contract by failing to reimburse BP for their working-interest share of Incident-related costs. On 19 April 2011, Anadarko filed a cross-claim against BP, alleging gross negligence and 15 other counts under state and federal laws. Anadarko seeks a declaration that it is excused from its contractual obligation to pay Incident-related costs. Anadarko also seeks damages from alleged economic losses and contribution or indemnity for claims filed against it by other parties. On 20 May 2011, BP and MOEX announced a settlement agreement of all claims between them, including a cross-claim brought by MOEX on 19 April 2011 similar to the Anadarko claim. On 15 July 2011, the judge in the federal multi-district litigation proceeding in New Orleans stayed Anadarko’s claims against BP pursuant to the arbitration clause in the operating agreement between the parties pertaining to the Macondo well.

On 20 April 2011, Transocean filed claims in its Limitation of Liability action alleging that BP had breached BP America Production Company’s contract with Transocean Holdings LLC by BP not agreeing to indemnify Transocean against liability related to the Incident and by not paying certain invoices. Transocean also asserted claims against BP under state law, maritime law, and OPA 90 for contribution.

On 20 April 2011, Halliburton Energy Services, Inc. (Halliburton), filed claims in Transocean’s Limitation of Liability action seeking indemnification from BP for claims brought against Halliburton in that action, and Cameron International Corporation (Cameron) asserted claims against BP for contribution under state law, maritime law, and OPA 90, as well as for contribution on the basis of comparative fault. Halliburton also asserted a claim for negligence, gross negligence and willful misconduct against BP and others. On 19 April 2011, Halliburton filed a separate lawsuit in Texas state court seeking indemnification from BP E&P for certain tort and pollution-related liabilities resulting from the Incident and resulting oil spill.

 

 

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On 20 April 2011, BP asserted claims against Cameron, Halliburton, and Transocean in the Limitation of Liability action. BP’s claims against Transocean include breach of contract, unseaworthiness of the Deepwater Horizon vessel, negligence (or gross negligence and/or gross fault as may be established at trial based upon the evidence), contribution and subrogation for costs (including those arising from litigation claims) resulting from the Incident and oil spill, as well as a declaratory claim that Transocean is wholly or partly at fault for the Incident and responsible for its proportionate share of the costs and damages. BP’s claims against Cameron assert that Cameron is liable under maritime law for providing a Blowout Preventer (BOP) that was unreasonably dangerous in design based on certain design defects, that Cameron was negligent with respect to certain maintenance and repair that it conducted on the Deepwater Horizon BOP, and that Cameron is liable to BP for contribution and subrogation of the damages, costs and expenses that BP has paid and will continue to pay relating to BP’s response efforts and the various claims brought against BP. BP asserted claims against Halliburton for fraud and fraudulent concealment based on Halliburton’s misrepresentations to BP concerning, among other things, the stability testing on the foamed cement used at the Macondo well; for negligence (or, if established by the evidence at trial, gross negligence) based on Halliburton’s performance of its professional services, including cementing and mud logging services; and for contribution and subrogation for amounts that BP has paid in responding to the Incident and oil spill, as well as in OPA assessments and in payments to plaintiffs. BP filed a similar complaint in federal court in the Southern District of Texas, Houston Division, against Halliburton, and the action was transferred on 4 May 2011 to the federal multi-district litigation proceedings pending in New Orleans.

On 20 April 2011, BP filed claims against Cameron, Halliburton, and Transocean in the DoJ Action, seeking contribution for any assessments against BP under OPA 90 based on those entities’ fault. On 20 June 2011, Cameron moved to strike BP’s tender of Cameron as liable to the US. That motion remains pending.

On 20 May 2011, Dril-Quip, Inc. and M-I L.L.C. filed claims against BP in Transocean’s Limitation of Liability action, each claiming a right to contribution from BP for damages assessed against them as a result of the Incident, based on allegations of negligence. M-I L.L.C. also claimed a right to indemnity for such damages based on their well services contracts with BP. On 20 June 2011, BP filed counter-complaints against Dril-Quip, Inc. and M-I L.L.C., asking for contribution and subrogation based on those entities’ fault in connection with the Incident and under OPA, and seeking declaratory judgment that Dril-Quip, Inc. and M-I L.L.C. caused or contributed to, and are responsible in whole or in part for damages incurred by BP in relation to, the Incident.

On 30 May 2011, Transocean filed claims against BP in the DoJ Action alleging that BP America Production Company had breached its contract with Transocean Holdings LLC by not agreeing to indemnify Transocean against liability related to the Incident. Transocean also asserted claims against BP under state law, maritime law, and OPA 90 for contribution. On 20 June 2011, Cameron filed similar claims against BP in the DoJ Action.

The State of Alabama has filed a lawsuit seeking damages for alleged economic and environmental harms, including natural resource damages, civil penalties under state law, declaratory and injunctive relief, and punitive damages as a result of the Incident. The State of Louisiana has filed a lawsuit to declare various BP entities (as well as other entities) liable for removal costs and damages, including natural resource damages under federal and state law, to recover civil penalties, attorney’s fees, and response costs under state law, and to recover for alleged negligence, nuisance, trespass, fraudulent concealment and negligent misrepresentation of material facts regarding safety procedures and BP’s (and other defendants’) ability to manage the oil spill, unjust enrichment from economic and other damages to the State of Louisiana and its citizens, and punitive damages. The Louisiana Department of Environmental Quality has issued an administrative order seeking injunctive relief and environmental civil penalties under state law, and several local governments in the State of Louisiana have filed suits under state wildlife statutes seeking penalties for damage to wildlife as a result of the spill. On 10 December 2010, the Mississippi Department of Environmental Quality issued a Complaint and Notice of Violation alleging violations of several State environmental statutes.

On 15 September 2010, three Mexican states bordering the Gulf of Mexico (Veracruz, Quintana Roo, and Tamaulipas) filed lawsuits in federal court in Texas against several BP entities. These lawsuits allege that the Incident harmed their tourism, fishing, and commercial shipping industries (resulting in, among other things, diminished tax revenue), damaged natural resources and the environment, and caused the states to incur expenses in preparing a response to the Incident. On 5 April 2011, the State of Yucatan submitted a claim to the GCCF alleging potential damage to its natural resources and environment, and seeking to recover the cost of assessing the alleged damage.

Citizens groups have also filed either lawsuits or notices of intent to file lawsuits seeking civil penalties and injunctive relief under the Clean Water Act and other environmental statutes. On 16 June 2011, the judge in the federal multi-district litigation proceeding in New Orleans granted BP’s motion to dismiss a master complaint raising claims for injunctive relief under various federal environmental statutes brought by various citizens groups and others. The judge did not, however, lift an earlier stay on the underlying individual complaints raising those claims for injunctive relief or otherwise apply his dismissal of the master complaint to those individual complaints. A motion for clarification has been filed asking the judge to clarify whether the dismissal of the master complaint also applies to the individual complaints. On 15 July 2011, the judge granted BP’s motion to dismiss a master complaint raising RICO claims against BP. The court’s order dismissed the claims of the plaintiffs in four RICO cases encompassed by the master complaint.

The DoJ announced on 7 March 2011 that it created a unified task force of federal agencies, led by the DoJ Criminal Division, to investigate the Gulf of Mexico incident. Other US federal agencies may commence investigations relating to the Incident. The SEC and DoJ are investigating securities matters arising in relation to the Incident.

 

 

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On 21 April 2011, BP entered a framework agreement with natural resource trustees for the United States and five Gulf coast states, providing for up to $1 billion to be spent on early restoration projects to address natural resource injuries resulting from the Gulf of Mexico oil spill. Funding for these projects will come from the $20-billion Deepwater Horizon Oil Spill Trust.

BP’s potential liabilities resulting from threatened, pending and potential future claims, lawsuits and enforcement actions relating to the Incident, together with the potential cost of implementing remedies sought in the various proceedings, cannot be fully estimated at this time but they have had and are expected to have a material adverse impact on the group’s business, competitive position, cash flows, prospects, liquidity, shareholder returns and/or implementation of its strategic agenda, particularly in the US. These potential liabilities may continue to have a material adverse effect on the group’s results and financial condition. See Note 2 on pages 23 – 28 for information regarding the financial impact in 2011 of the Incident and see the financial statements contained in BP’s Annual Report and Form 20-F 2010 for information regarding 2010.

Investigations and reports relating to the Gulf of Mexico Oil Spill

BP is subject to a number of investigations related to the Incident by numerous agencies of the US government. The related published reports are available on the websites of the agencies and commissions referred to below.

On 11 January 2011, the National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling (National Commission), established by President Obama, published its report on the causes of the Incident and its recommendations for policy and regulatory changes for offshore drilling. On 17 February 2011, the National Commission’s Chief Counsel published a separate report on his investigation that provides additional information regarding the causes of the Incident.

In a report dated 20 March 2011, with an Addendum dated 30 April 2011, the Joint Investigation Team (JIT) for the Marine Board of Investigation established by the US Coast Guard and Bureau of Ocean Energy Management (BOEMRE) issued the Final Report of the Forensic Examination of the Deepwater Horizon Blowout Preventer (BOP) prepared by Det Norske Veritas (BOP Report). The BOP Report concludes that the position of the drill pipe against the blind shear rams prevented the BOP from functioning as intended. Subsequently, BP helped to sponsor additional BOP testing conducted by Det Norske Veritas under court auspices, which concluded on 21 June 2011. BP continues to review the BOP Report and is in the process of evaluating the data obtained from the additional testing.

On 22 April 2011, the US Coast Guard issued its report (Maritime Report) focused upon the maritime aspects of the Incident. The Maritime Report criticizes Transocean’s maintenance operations and safety culture, while also criticizing the Republic of the Marshall Islands — the flag state responsible for certifying Transocean’s Deepwater Horizon vessel. The BOEMRE is expected to issue a subsequent report that will likely focus more heavily on the drilling aspects of the Incident and hence the roles of BP, Halliburton and Cameron.

The US Chemical Safety and Hazard Investigation Board (CSB) is also conducting an investigation of the Incident that is focused on the explosions and fire, and not the resulting oil spill or response efforts. The CSB is expected to issue a single investigation report in late 2011 or early 2012 that will seek to identify the alleged root cause(s) of the Incident, and recommend improvements to BP and industry practices and to regulatory programmes to prevent recurrence and mitigate potential consequences.

Also, at the request of the Department of the Interior, the National Academy of Engineering/National Research Council established a Committee (Committee) to examine the performance of the technologies and practices involved in the probable causes of the Incident and to identify and recommend technologies, practices, standards and other measures to avoid similar future events. On 17 November 2010 the Committee publicly released its interim report setting forth the Committee’s preliminary findings and observations on various actions and decisions including well design, cementing operations, well monitoring, and well control actions. The interim report also considers management, oversight, and regulation of offshore operations. The Committee has stated that it will issue its final report, including findings and/or recommendations, in late summer 2011 (a public pre-publication version of report), with a published version to follow by 30 December 2011. A second, unrelated National Academies’ Committee will be looking at the methodologies available for assessing spill impacts on ecosystems in the Gulf of Mexico, with a final report expected in the latter part of 2012, and a third National Academies’ Committee will be studying methods for assessing the effectiveness of safety and environmental management systems (SEMS) established by offshore oil and gas operators. This third Committee expects to complete the final report of recommendations by 30 December 2011.

On 10 March 2011, the Flow Rate Technical Group (FRTG), Department of the Interior, issued its final report titled “Assessment of Flow Rate Estimates for the Deepwater Horizon/Macondo Well Oil Spill.” The report provides a summary of the strengths and limitations of the different methods used by the US government to estimate the flow rate and a range of estimates from 13mb/d to over 100mb/d. The report concludes that the most accurate estimate was 53mb/d just prior to shut in, with an uncertainty on that value of ±10% based on FRTG collective experience and judgment, and, based on modeling, the flow on day one of the Incident was 62mb/d. BP is currently reviewing the report.

On 18 March 2011 the US Coast Guard ISPR team released its final report capturing lessons learned from the incident as well as making recommendations on how to improve future oil spill response and recovery efforts.

Additionally, BP representatives have appeared before multiple committees of the US Congress that have been conducting inquiries into the Incident. BP has provided documents and written information in response to requests by these committees and will continue to do so.

 

 

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Legal proceedings (continued)

 

 

Other legal proceedings

The following discussion sets forth the developments in the group’s other material legal proceedings during the recent period. Other pending material legal proceedings are described in the group’s results announcement for the period ended 31 March 2011.

A shareholder derivative action was filed against several current and former BP officers and directors based on alleged violations of the US Clean Air Act (CAA) and Occupational Safety and Health Administration (OSHA) regulations at the Texas City refinery subsequent to the March 2005 explosion and fire. An investigation by a special committee of BP’s board into the shareholder allegations has been completed and the committee has recommended that the allegations do not warrant action by BP against the officers and directors. BP has filed a motion to dismiss the shareholder derivative action and a plea to the jurisdiction. On 16 June 2011, the court granted BP’s plea to the jurisdiction and dismissed the action in its entirety.

On 29 November 2007, BP Exploration (Alaska) Inc. (BPXA) entered into a criminal plea agreement with the DoJ relating to leaks of crude oil in March and August 2006. BPXA’s guilty plea, to a misdemeanour violation of the US Water Pollution Control Act, included a term of three years’ probation. On 29 November, 2009 a spill of approximately 360 barrels of crude oil and produced water was discovered beneath a line running from a well pad to the Lisburne Processing Center in Prudhoe Bay, Alaska. On 17 November 2010, the US Probation Officer filed a petition in federal district court to revoke BPXA’s probation based on an allegation that the Lisburne event was a criminal violation of state or federal law. A hearing is scheduled for the week of 11 October 2011. On 12 May 2008, a BP p.l.c. shareholder filed a consolidated complaint alleging violations of federal securities law on behalf of a putative class of BP p.l.c. shareholders against BP p.l.c., BPXA, BP America, and four officers of the companies, based on alleged misrepresentations concerning the integrity of the Prudhoe Bay pipeline before its shutdown on 6 August 2006. On 8 February 2010, the Ninth Circuit Court of Appeals accepted BP’s appeal from a decision of the lower court granting in part and denying in part BP’s motion to dismiss the lawsuit. On 29 June 2011, the Ninth Circuit ruled in BP’s favor that the filing of a trust related agreement with the SEC containing contractual obligations on the part of BP was not a misrepresentation which violated federal securities laws. On 31 March 2009, the State of Alaska filed a complaint seeking civil penalties and damages relating to these events. The complaint alleges that the two releases and BPXA’s corrosion management practices violated various statutory, contractual and common law duties to the State, resulting in penalty liability, damages for lost royalties and taxes, and liability for punitive damages.

In April 2009, Kenneth Abbott, as relator, filed a US False Claims Act lawsuit against BP, alleging that BP violated federal regulations, and made false statements in connection with its compliance with those regulations, by failing to have necessary documentation for the Atlantis subsea and other systems. BP is the operator and 56% interest owner of the Atlantis unit in production in the Gulf of Mexico. That complaint was unsealed in May 2010 and served on BP in June 2010. In September 2010, Kenneth Abbott and Food & Water Watch filed an amended complaint in the False Claims Act lawsuit seeking an injunction shutting down the Atlantis platform. The court denied BP’s motion to dismiss the complaint in March 2011. Separately, also in March 2011, BOEMRE issued its investigation report of the Abbott Atlantis allegations, which concluded that Mr. Abbott’s allegations that Atlantis operations personnel lacked access to critical, engineer-approved drawings were without merit and that his allegations about false submissions by BP to BOEMRE were unfounded. Trial is scheduled to begin on 5 March 2012.

On 17 May 2011, BP announced that both the Rosneft Share Swap Agreement and the Arctic Opportunity, originally announced on 14 January 2011, had terminated. This termination was as a result of the deadline for the satisfaction of conditions precedent having expired following delays resulting from interim orders granted by the English High Court and a UNCITRAL arbitration tribunal after applications brought by Alfa Petroleum Holdings Limited (Alfa) and OGIP Ventures Limited (OGIP) against BP International Limited (BPIL) and BP Russian Investments Limited (BPRIL) alleging breach of the related TNK-BP shareholders agreement (SHA). These interim orders did not address the question of whether or not BP breached the SHA.

The UNCITRAL arbitration proceedings with Alfa, Access and Renova (AAR) are still ongoing and AAR has now provided notice of its intention to bring a claim for breach of the SHA in the arbitration although they have stated they do not require the tribunal to determine the question of loss or quantum of damages. BP intends to strongly defend any such action or claim. No procedural timetable for the resolution of this dispute has yet been determined.

 

 

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Signatures

 

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

BP p.l.c.

(Registrant)

 

Dated: 26 July 2011    

/s/ D J Pearl

   

D J PEARL

Deputy Company Secretary

 

 

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Exhibit 99.1

Computation of ratio of earnings to fixed charges

 

 

     Half year 2011  
     $ million, except ratios  

Profit before taxation

     19,998  

Group’s share of income in excess of dividends of equity-accounted entities

     (780

Capitalized interest, net of amortization

     (82
  

 

 

 

Profit as adjusted

     19,136  
  

 

 

 

Fixed charges:

  

Interest expense

     399  

Rental expense representative of interest

     821  

Capitalized interest

     171  
  

 

 

 
     1,391  
  

 

 

 

Total adjusted earnings available for payment of fixed charges

     20,527  
  

 

 

 

Ratio of earnings to fixed charges

     14.8  
  

 

 

 

 

 

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Exhibit 99.2

Capitalization and indebtedness

 

The following table shows the unaudited consolidated capitalization and indebtedness of the BP group as of 30 June 2011 in accordance with IFRS:

 

     30 June 2011  
     $ million  

Share capital

  

Capital shares (1-2)

     5,218  

Paid-in surplus (3)

     11,027  

Merger reserve (3)

     27,206  

Own shares

     (121

Available-for-sale investments

     629  

Cash flow hedges

     66  

Foreign currency translation reserve

     6,027  

Treasury shares

     (21,027

Share-based payment reserve

     1,396  

Profit and loss account

     77,073  
  

 

 

 

BP shareholders’ equity

     107,494  
  

 

 

 

Finance debt (4-6)

  

Due within one year

     12,445  

Due after more than one year

     34,445  
  

 

 

 

Total finance debt

     46,890  
  

 

 

 

Total capitalization (7)

     154,384  
  

 

 

 

 

(1) Issued share capital as of 30 June 2011 comprised 18,941,250,151 ordinary shares, par value $0.25 per share, and 12,706,252 preference shares, par value £1 per share. This excludes 1,845,638,661 ordinary shares which have been bought back and held in treasury by BP. These shares are not taken into consideration in relation to the payment of dividends and voting at shareholders’ meetings.
(2) Capital shares represent the ordinary shares of BP which have been issued and are fully paid.
(3) Paid-in surplus and merger reserve represent additional paid-in capital of BP which cannot normally be returned to shareholders.
(4) Finance debt recorded in currencies other than US dollars has been translated into US dollars at the relevant exchange rates existing on 30 June 2011.
(5) Obligations under finance leases are included within finance debt in the above table.
(6) As of 30 June 2011, the parent company, BP p.l.c., had outstanding guarantees totalling $37,157 million, of which $37,127 million related to guarantees in respect of liabilities of its subsidiary undertakings, including $36,386 million relating to borrowings by subsidiaries. Thus 78% of the Group’s finance debt had been guaranteed by BP p.l.c.

At 30 June 2011, $626 million of finance debt ($1,155 at 30 June 2010) was secured by the pledging of assets, and $3,530 million was secured in connection with deposits received relating to certain disposal transactions expected to complete in subsequent periods, BP has entered into crude oil sales contracts in respect of oil produced from certain fields in offshore Angola and Azerbaijan to provide security to the lending banks. The remainder of finance debt was unsecured. BP had, as of 30 June 2011 no material outstanding contingent indebtedness and there have been no material changes since that date.

 

(7) There has been no material change since 30 June 2011 in the consolidated capitalization and indebtedness of BP.

 

 

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