20-F 1 d441093d20f.htm FORM 20-F Form 20-F
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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 20-F

(Mark One)

¨   REGISTRATION STATEMENT PURSUANT TO SECTION 12(b) or (g)   

OF THE SECURITIES EXCHANGE ACT OF 1934

OR

þ   ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)   

OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended 31 December 2012

OR

¨   TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934   

OR

¨   SHELL COMPANY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934   

Commission file number: 1-6262

BP p.l.c.

(Exact name of Registrant as specified in its charter)

England and Wales

(Jurisdiction of incorporation or organization)

1 St James’s Square, London SW1Y 4PD

United Kingdom

(Address of principal executive offices)

Dr Brian Gilvary

BP p.l.c.

1 St James’s Square, London SW1Y 4PD

United Kingdom

Tel +44 (0) 20 7496 5311

Fax +44 (0) 20 7496 4573

(Name, Telephone, E-mail and/or Facsimile number and Address of Company Contact Person)

Securities registered or to be registered pursuant to Section 12(b) of the Act

 

Title of each class   Name of each exchange on which registered
Ordinary Shares of 25c each     New York Stock Exchange*
Floating Rate Guaranteed Notes due June 2013   New York Stock Exchange
Floating Rate Guaranteed Notes due December 2013   New York Stock Exchange
Floating Rate Guaranteed Notes due 2014   New York Stock Exchange
5.250% Guaranteed Notes due 2013   New York Stock Exchange
3.625% Guaranteed Notes due 2014   New York Stock Exchange
1.700% Guaranteed Notes due 2014   New York Stock Exchange
0.700% Guaranteed Notes due 2015   New York Stock Exchange
3.875% Guaranteed Notes due 2015   New York Stock Exchange
3.125% Guaranteed Notes due 2015   New York Stock Exchange
2.248% Guaranteed Notes due 2016   New York Stock Exchange
3.200% Guaranteed Notes due 2016   New York Stock Exchange
1.375% Guaranteed Notes due 2017   New York Stock Exchange
1.846% Guaranteed Notes due 2017   New York Stock Exchange
4.750% Guaranteed Notes due 2019   New York Stock Exchange
4.500% Guaranteed Notes due 2020   New York Stock Exchange
4.742% Guaranteed Notes due 2021   New York Stock Exchange
3.561% Guaranteed Notes due 2021   New York Stock Exchange
2.500% Guaranteed Notes due 2022   New York Stock Exchange
3.245% Guaranteed Notes due 2022   New York Stock Exchange
 

*Not for trading, but only in connection with the registration of American  Depositary

Shares, pursuant to the requirements of the Securities and Exchange Commission

Securities registered or to be registered pursuant to Section 12(g) of the Act.

None

Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act.

None

Indicate the number of outstanding shares of each of the issuer’s classes of capital or common stock as of the close of the period covered by the annual report.

Ordinary Shares of 25c each      19,135,751,315   
Cumulative First Preference Shares of £1 each      7,232,838   
Cumulative Second Preference Shares of £1 each      5,473,414   

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

Yes ¨      No þ

If this report is an annual or transition report, indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934.

Yes ¨      No þ

Note — Checking the box above will not relieve any registrant required to file reports pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 from their obligations under those Sections.

Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes þ      No ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).*

Yes ¨      No ¨

* This requirement does not apply to the registrant in respect of this filing.

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of ‘‘accelerated filer and large accelerated filer’’ in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer þ   Accelerated filer ¨    Non-accelerated filer ¨

Indicate by check mark which basis of accounting the registrant has used to prepare the financial statements included in this filing:

U.S. GAAP ¨  

International Financial Reporting

Standards as issued by the

International Accounting Standards Board þ

   Other ¨

If “Other” has been checked in response to the previous question, indicate by check mark which financial statement item the registrant has elected to follow.

Item 17 ¨      Item 18 ¨

If this is an annual report, indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes ¨      No þ

 

 

 


Table of Contents

Annual Report and

Form 20-F 2012

bp.com/annualreport

LOGO

 

 

 

LOGO

Building a stronger,

safer BP


Table of Contents

 

LOGO


Table of Contents

BP in 2012    

 

The group made good progress
this year. We worked
to enhance safety and risk
management. We continued to
meet our commitments in the
Gulf of Mexico. We sold assets
and reduced complexity. And
we focused investment on areas
where we see higher margins.
Over the following pages,
we report on the actions taken
to build a stronger, safer BP.

    2   

Information about this report

 

       
   

 

3

 

  

 

Business review: Group overview

  
    4    BP at a glance    20    Our strategy   
    8    Chairman’s letter    22    Our performance   
    10    Group chief executive’s letter    28    Our key performance indicators   
    12    Energy outlook    30    Our management of risk   
    15    Our business model    32    Cautionary statement   
               
               
               
   

 

33

 

  

 

Business review: BP in more depth

  
    34    Financial review    63    Upstream   
    38    Risk factors    72    Downstream   
    46    Safety    80    TNK-BP   
    51    Environmental and social responsibility    82    Other businesses and corporate   
   

55

57

59

  

Employees

Technology

Gulf of Mexico oil spill

   84    Oil and gas disclosures for the group   
          90    Liquidity and capital resources   
          94    Regulation of the group’s business   
          98    Certain definitions   
               
               
   

 

101

 

  

 

Corporate governance

  
    102    Governance overview    122    Safety, ethics and environment
assurance committee
  
    104    Board of directors         
    109    Executive team    124    Gulf of Mexico committee   
    112    How the board works    125    Nomination committee   
    114    Board effectiveness    126    Chairman’s committee   
    116    Shareholder engagement    126    UK Corporate Governance Code
compliance
  
    117    Risk in BP         
    120    Audit committee    127    Directors’ remuneration report   
          147    Regulatory information   
               
LOGO       

 

153

 

  

 

Shareholder information

  
    154    Called-up share capital    158    Fees and charges payable by ADSs holders   
    154    Share prices and listings         
    155   

Dividends

   159    Fees and payments made by the Depositary to the issuer   
    155    UK foreign exchange controls on dividends         
    155    Shareholder taxation information    159    Documents on display   
    157    Major shareholders    159    Administration   
    158   

Purchases of equity securities by the issuer and affiliated purchasers

   159    Annual general meeting   
               
               
   

 

161

 

  

 

Additional disclosures

  
    162    Legal proceedings    174    Material contracts   
    171    Critical accounting policies    175    Related-party transactions   
    174    Relationships with suppliers and contractors    175    Exhibits   
               
               
               
               
               
               
   

 

177

 

  

 

Financial statements

  
    180    Consolidated financial statements of the BP group    263    Supplementary information on oil and natural gas (unaudited)   
    186   

Notes on financial statements

        
               
               
               
               
               
   

 

20F

  

 

Cross reference to Form 20-F

       

 

Introduction and contents     1   
BP Annual Report and Form 20-F 2012  


Table of Contents
Information about this report    LOGO

 

Frequent abbreviations

 

ADR

American depositary receipt.

 

ADS

American depositary share.

 

Barrel (bbl)

159 litres, 42 US gallons.

 

b/d

Barrels per day.

 

boe

Barrels of oil equivalent.

 

GAAP

Generally accepted accounting practice.

 

Gas

Natural gas.

 

Hydrocarbons

Crude oil and natural gas.

 

IFRS

International Financial Reporting Standards.

 

Liquids

Crude oil, condensate and natural gas liquids.

 

LNG

Liquefied natural gas.

 

LPG

Liquefied petroleum gas.

 

mb/d

Thousand barrels per day.

 

mboe/d

Thousand barrels of oil equivalent per day.

 

mmboe

Million barrels of oil equivalent.

 

mmBtu

Million British thermal units.

 

MW

Megawatt.

 

NGLs

Natural gas liquids.

 

PSA

Production-sharing agreement.

 

RC

Replacement cost.

 

SEC

The United States Securities and Exchange Commission.

 

Tonne

2,204.6 pounds.

 

LOGO

  

This document constitutes the Annual Report and Accounts in accordance with UK requirements and the Annual Report on Form 20-F in accordance with the US Securities Exchange Act of 1934, for BP p.l.c. for the year ended 31 December 2012. A cross reference to Form 20-F requirements is on page 20F.

 

This document contains the Directors’ Report, including the Business Review and Management Report, on pages 3-126 and 147-175 and 178. The Directors’ Remuneration Report is on pages 127-145. The consolidated financial statements of the group are on pages 177-286 and the corresponding reports of the auditor are on pages 179-181.

 

BP Annual Report and Form 20-F 2012 and BP Summary Review 2012 may be downloaded from bp.com/annualreport. No material on the BP website, other than the items identified as BP Annual Report and Form 20-F 2012 or BP Summary Review 2012, forms any part of those documents.

 

BP p.l.c. is the parent company of the BP group of companies. The company was incorporated in 1909 in England and Wales and changed its name to BP p.l.c. in 2001. Where we refer to the company, we mean BP p.l.c. Unless otherwise stated, the text does not distinguish between the activities and operations of the parent company and those of its subsidiaries, and information in this document reflects 100% of the assets and operations of the company and its subsidiaries that were consolidated at the date or for the periods indicated, including minority interests. BP’s primary share listing is the London Stock Exchange. Ordinary shares are also traded on the Frankfurt Stock Exchange in Germany and, in the US, the company’s securities are traded on the New York Stock Exchange in the form of ADSs (see page 154 for more details).

 

The term ‘shareholder’ in this report means, unless the context otherwise requires, investors in the equity capital of BP p.l.c., both direct and indirect. As BP shares, in the form of ADSs, are listed on the New York Stock Exchange (NYSE), an Annual Report on Form 20-F is filed with the US Securities and Exchange Commission (SEC). Ordinary shares are ordinary fully paid shares in BP p.l.c. of 25 cents each. Preference shares are cumulative first preference shares and cumulative second preference shares in BP p.l.c. of £1 each.

 

  

 

Trade marks of the BP group appear throughout this Annual Report and Form 20-F in italics.

They include:

 

ampm

Aral

ARCO

BP

BP Ultimate

Castrol

Castrol CRB

Castrol EDGE

Castrol Magnatec

Designer Water

Field of the Future

LoSal

Project 20K

Pushing Reservoir Limits

Veba Combi-Cracking (VCC)

 

EcoBoost is a trade mark of Ford Motor Company.

SkyMine is a trade mark of Skyonic Corporation.

Permasense is a trade mark of Permasense Limited.

 

         
  

 

Registered office and our worldwide

headquarters:

  

 

Our agent in the US:

     
  

BP p.l.c.

1 St James’s Square

London SW1Y 4PD

UK

Tel +44 (0)20 7496 4000

  

BP America Inc.

501 Westlake Park Boulevard

Houston, Texas 77079

US

Tel +1 281 366 2000

     
  

Registered in England and Wales No. 102498.

Stock exchange symbol ‘BP’.

  
     
     
     
     
     
     
     

 

 

2    Business review: Group overview
   BP Annual Report and Form 20-F 2012


Table of Contents

 

 

   

Business review

 

Group overview 

 

An overview of the key actions,
events and results in 2012,
together with commentary
on BP’s performance in the
year and our priorities as we
move forward.

 

 

LOGO

    4   

BP at a glance

 

 

   
     

 

8

  

 

Chairman’s letter

 

Carl-Henric Svanberg sets out the board’s priorities

in 2012 and BP’s prospects moving forward.

 

   
     

 

10

  

 

Group chief executive’s letter

 

Bob Dudley reviews the company’s progress as we work

to build a stronger, safer BP.

 

   
     

 

12

  

 

Energy outlook

 

Our views on the factors likely to shape energy demand and supply, from

population and the energy mix, to policy, prices and access.

 

   
     

 

15

  

 

Our business model

 

An overview of how we are organized, the ways in which

we create value, and our distinctive strengths.

 

   
     

 

20

  

 

Our strategy

 

Our priorities as we work to create a distinctive

platform for growth.

 

   
     

 

22

  

 

Our performance

 

From progress in Russia to new exploration access; a

review of important actions and events during the year.

 

   
     

 

28

  

 

Our key performance indicators

 

How we performed as measured by our key financial

and non-financial indicators.

 

   
     

 

30

  

 

Our management of risk

 

A summary of the risks we face in our business.

 

   
     

 

32

  

 

Cautionary statement

 

   
               
               
               
            
               
               
               
               
               
               
                 
                 
                 
                 
                 
                 
                 
                 
                     
     

Business review: Group overview      3

BP Annual Report and Form 20-F 2012        

   

 


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Chairman’s letter

 

LOGO

10-year dividend history

UK (pence per ordinary share)

 

LOGO

 

US (cents per ADS)

 

LOGO

 

1 ADS represents six 25 cent ordinary shares.

 

LOGO Board performance

         For information about the board and its

         committees see pages 101-126.

  

Dear fellow shareholder

 

In 2012 the board had three priorities. First, to address uncertainty from ongoing litigation in the US and our partnership in Russia. Second, to reinforce the strategic direction of the group. Third, to accelerate the company’s momentum and build confidence. All of these were pursued in the context of the board’s active monitoring of safety and risk management.

 

Substantial progress has been made in meeting these priorities. This progress gave the board confidence to raise the quarterly dividend by 14% in February 2012 and by 12.5% in October. The increased dividend represents an important milestone on the road to improved shareholder value. We are maintaining a progressive dividend policy, increasing returns to you, in line with financial performance and outlook.

 

The pursuit of energy will always involve risk, so it is essential that safety remains front of mind. From safe and reliable operations comes trust, and we need that trust if BP is to create value for you and to help meet the world’s energy needs.

 

Looking ahead, your board sees strong prospects for BP in a world that requires a growing supply of energy. We are aware that we still have some way to go. We continue to face a number of uncertainties in the US, for example. The board thanks you for your continued patience and support as we work to address these issues.

 

In working to resolve uncertainty, two matters demanded the close attention of your board.

 

In the US, the company has faced legal proceedings related to the Deepwater Horizon accident. Our settlements with the US government, the Securities and Exchange Commission and others were each important steps forward in reducing uncertainty.

 

In Russia, the agreed sale of our 50% shareholding in TNK-BP to Rosneft, and the settlement with our partners, have brought clarity. The disposal agreement will provide us with an increased stake in Rosneft, such that on completion, BP will have a 19.75% share of the biggest publicly traded oil company in the world in terms of oil production and reserves. In due course BP expects to have two seats on its nine-person board. BP has worked with Rosneft for some 15 years. Our joint ambition is that BP’s people, processes and technologies will help to significantly enhance Rosneft’s value over time, as they did at TNK-BP.

 

During the year the board supported Bob Dudley, our group chief executive, on the implementation of the 10-point plan and the further implementation of the functional organization. We worked with him to develop the group strategy beyond 2014. Bob, the executive team and all our employees have made a huge contribution, working to reach our milestones and secure a promising future for the company during a tough period. Bob has shown steady and determined leadership through this time. I thank him and everyone at BP for their hard work.

 

The qualities of BP’s employees were once again demonstrated in January 2013, following the violent attack at In Amenas in Algeria. This shocking event deeply affected us all, but across the company people responded with great resilience. We will always remember those who lost their lives in this terrible incident.

 

8    Business review: Group overview
   BP Annual Report and Form 20-F 2012


Table of Contents

LOGO  Our strategy
For more on our strategic priorities and longer-term objectives see pages 20-21.

 

Carl-Henric Svanberg at the Sangachal terminal control room during his three-day trip to Azerbaijan (top); Professor Dame Ann Dowling on the Thunder Horse platform in the Gulf of Mexico (middle); Brendan Nelson and Phuthuma Nhleko at BP’s North America Gas operations in east Texas, US (bottom).

 

LOGO

  

As 2012 progressed the board saw the company start to move forward with greater confidence. It is important that this momentum continues.

 

Our board committees have provided effective oversight of the company and its operations, which has enabled the board to focus on its three priorities. Outside the boardroom, our non-executive directors have continued to pay visits to key parts of the business. My own visits this year included Angola, Azerbaijan, the North Sea, Japan and the US.

 

The board has seen substantial change. For this reason, we have asked Antony Burgmans to serve for a further three years. I am pleased that we will continue to benefit from his experience and understanding of the company. Byron Grote is retiring after 33 years with BP, including more than 12 years on the board. I thank him for his dedication and the exceptional contribution he has made to this company. As we move through 2013, the board is well balanced, with deep experience in our industry and a broad range of skills across business and finance.

 

We will refresh the board as and when required. I believe board diversity – including the representation of women at the top – helps to make boards more effective. We will continue to work to identify candidates from a range of backgrounds who can make a unique and powerful contribution to BP.

 

One of the vital tasks of the board is to ensure strategy is matched to the world we see ahead. Energy remains the engine of progress, and we expect rising populations and increasing industrialization to generate strong demand to 2030 and beyond. The world will continue to be dependent on fossil fuels in the medium term. Along with providing the hydrocarbons needed, we are also involved in developing the resources, technologies and policies required over the long term.

 

Our industry keeps evolving. In the past international oil companies dominated access to resources. Then national oil companies took control of the greater share. But much of the easiest-to-reach oil has been developed. So we are now entering a third era, where co-operation between partners is the key to unlocking the resources found in the most challenging locations. For BP, advantage now comes from exceptional capability rather than exceptional scale. Our future is about high-margin, high-quality production, not simply volume.

 

Oil will continue to be BP’s prime focus, and we aim to extend our extraordinary track record in finding and developing new resources. We will keep making selective investments in natural gas, with an emphasis on assets that generate good margins. And we will be selective in the Downstream too, choosing to operate where our refining and marketing assets are connected to attractive markets.

 

Over the past three years BP has had to change. Through our reorganization, we are a simpler company. Through our asset sales, we are stronger financially. Through our actions, we have reduced complexity and risk. Our plans, priorities and direction are clear. I see great opportunities ahead, as we continue to build a stronger, safer BP that meets the expectations of our shareholders and the wider world.

 

LOGO

 

Carl-Henric Svanberg

Chairman

6 March 2013

 

 

Business review: Group overview      9   
BP Annual Report and Form 20-F 2012   


Table of Contents

Group chief executive’s letter

 

LOGO

 

Carl-Henric Svanberg and Bob Dudley with Igor Sechin, President of Rosneft, on the day the BP board approved the transaction.

 

LOGO

    

 

Dear fellow shareholder

 

BP made important progress in 2012. We achieved a series of strategic milestones and remained on course with our plans to 2014 and beyond. We made great strides forward in Russia and the US. We continued to enhance risk management. We focused on our areas of greatest strength. And we sold assets to capture value, simplify the business and reduce risk.

 

Before I say more about our activities and plans, I would like to reflect, with great sadness, on the terrible events that took place at the In Amenas joint venture facility in Algeria in January 2013. Our thoughts are with the families and friends of those who lost their lives in the attack. We are working with government agencies and others to determine what can be learned from this shocking incident.

 

Coming back to our work over the past few years, people may not be fully aware of the enormous scale of the change we have made. By the end of 2012 we had announced asset sales of $38 billion, essentially reaching our target a year early. Since the divestment programme began, we have sold around half our upstream installations and pipelines, and one-third of our wells – while retaining roughly 90% of our proved reserves base and production. Meanwhile, we are gaining new exploration access, rolling out high value projects and upgrading assets.

 

Our Downstream segment has had an excellent year with strong operational performance and record underlying profits.a We made good progress on the modernization programme of our Whiting refinery and reached agreement on the divestment of two major refineries in the US, completing the sale of our Texas City refinery in February 2013.

 

There is more to do and there will always be new challenges to face, but we are steadily acting to build a stronger, safer BP.

 

We are addressing uncertainty in the US

 

In 2012 we resolved federal criminal charges with the Department of Justice and securities claims with the SEC. We continue to work with the Environmental Protection Agency to resolve suspension and debarment issues.

 

We have consistently said we are willing to settle all outstanding claims on reasonable terms, but we are also prepared to defend the company and its actions in court. We will do what is in the best interests of our shareholders. I recognize that ongoing proceedings prolong uncertainty, so we will endeavour to update you as events unfold.

 

Back in 2010 we said that we would help restore the environment and economy of the Gulf. We are holding true to that promise. In 2012 we made our final payment into the $20-billion Trust fund, from which $9.5 billion has been distributed to date. We supported environmental research and provided funds for the local tourism industry. Having grown up in the Gulf, I am heartened that the tourists are back, beaches are busy and the fishing is good. To date, BP has made total payments directly related to the accident and oil spill of $32.8 billion. We will continue to meet our commitments in the region.

 

We are repositioning BP in Russia

 

In 2012 we agreed to sell our 50% shareholding in TNK-BP to Rosneft. TNK-BP proved to be an outstanding investment, generating substantial value for BP. From an initial commitment of around $8 billion, it has returned some $19 billion of dividends to us. But the time had come to move on.

 

10    Business review: Group overview
   BP Annual Report and Form 20-F 2012


Table of Contents

$19   billion

 

Dividends received by BP from TNK-BP since 2003.

 

The new US-based High-Performance Computing centre, which is currently under construction, will enable BP scientists to complete an imaging project in one day – whereas it would have taken four years nearly a decade ago.

 

LOGO

 

a   Downstream underlying profit is not a recognized GAAP measure. See page 27 for the equivalent measure on an IFRS basis, which is replacement cost profit before interest and tax. See Certain definitions on page 98 for further information on underlying profit.

b   See footnote e on page 21 for a definition of free cash flow.

    

The new agreement will provide us with an 18.5% share in Rosneft and $12.3 billion of cash, including a dividend of $0.7 billion received from TNK-BP in December 2012. Combined with our existing 1.25% shareholding, we will own 19.75% of Rosneft. We expect the transaction to be completed in the first half of 2013. Through it, we will maintain a strong position in the world’s largest oil and gas producing country. And we will be a major investor in a company transforming its asset base, management processes and corporate governance.

 

We will use our experience in large acquisitions and mergers to support Rosneft as it assimilates TNK-BP’s assets. We can also contribute technical skills in areas from exploration and enhanced oil recovery to integrating downstream businesses and international developments. We have confidence in the Russian business environment and we look forward to playing a valued role in the country’s future.

 

We are enhancing safety and risk management

Our employees have been working systematically to enhance safety and risk management. We have changed how we are organized, bringing greater clarity and consistency across the company. In the Gulf of Mexico and elsewhere, we are holding our operations to standards that in many cases go beyond regulatory requirements. And we have turned lessons learned from the 2010 accident into new oil spill response plans and technologies, which we are adopting within BP and sharing with others. I take encouragement from our 19% reduction in loss of primary containment this past year, continuing a multi-year trend.

 

2012 saw the appointment of Carl Sandlin, who will oversee the implementation of the recommendations of the Bly Report, BP’s internal accident investigation. In addition, following our agreement with the US government to resolve all federal criminal claims, we have agreed to take additional actions designed to further enhance the safety of drilling operations in the Gulf. Two independent monitors will be appointed to review and provide recommendations, one regarding process safety for deepwater drilling in the Gulf and the other BP’s code of conduct. An independent auditor will review and report on BP’s implementation of key terms of the agreement.

 

We are building a distinctive platform for growth

In shaping our portfolio, we are prioritizing shareholder value. Scale remains important, but we are focused on driving forward our financial performance rather than simply growing production volumes. Operating cash flow and replacement cost profit will take precedence over barrels of production. We are increasing investment in the areas with the greatest potential to generate strong and reliable growth in operating cash flow, from exploration and deepwater operations to giant fields and gas value chains. In the Downstream, we have a portfolio of world-class businesses that are positioned to deliver material and growing free cash flows.b

 

There is plenty for us to explore. During the year we gained new access in six countries. Since 2010 we have accessed around 400,000 square kilometres of new acreage. That is roughly the size of California and more than double the exploration acreage gained from 2000 to 2009.

 

We continue to have an important presence in many of the world’s largest economies and in fast-developing countries too. BP’s global footprint and prudent financial approach are important given the potential for turbulence in the world, including further economic and political upheaval. We are well placed to respond to unsettled conditions if and when they appear.

 

Looking ahead

While facing uncertainties and navigating through testing times, BP emerged from 2012 a somewhat smaller, but stronger company. As we move forward, you will see us keep working to focus, standardize and improve what we do and how we do it. We are building a platform for growth that should serve us well for many years to come.

 

I want to end by paying tribute to everyone here at BP. This has been another truly demanding year, and our employees have dedicated themselves to their jobs in a way that I find humbling. I am proud of the talent and the terrific spirit of determination to improve that is found within BP. Over the next 12 months and beyond, we will continue our work to enhance safety, earn back trust and create value.

 

LOGO

 

Bob Dudley

Group Chief Executive

6 March 2013

 

 

 

Business review: Group overview      11   
BP Annual Report and Form 20-F 2012   


Table of Contents

Energy outlook

 

 

Looking ahead, we expect demand for energy to grow

and the challenges facing our industry to be met by a diverse mix

of fuels and technologies.

    
LOGO
    
 

 

Our market in 2012

 

    

Crude oil and gas prices, and refining
margins
($ per barrel of oil equivalent)

 

LOGO

 

Source: Platts/BP.

*See Downstream on page 73 for further information on RMM.

 

World economic growth was weak in 2012 – below its historic trend – and we expect subdued global growth to continue in 2013. Emerging economies with stronger productivity and rising populations, led by China and India, are set to drive growth. Developed countries may lag as they continue to address internal fiscal imbalances.

 

Global demand for energy, including oil, continued to expand modestly in 2012, with a weak economy and high oil prices weighing on demand.

 

As a result, the growth in world oil consumption remained weak in 2012, with continued growth in China and other non-OECD countries offsetting yet another decline in OECD countries. With oil markets balancing lower production from certain countries against weak consumption and high OPEC production, average crude oil prices in 2012 were similar to the previous year, averaging $111.67 per barrel.

 

Natural gas prices continued to diverge globally in 2012, with lower prices in the US and increases in Europe and the Far East.

 

LOGO Crude prices

For more information on crude oil and natural gas prices see page 64.

 

  

Globally, refining margins improved on average as refinery closures and operational issues reduced product supply. Demand continues to grow in non-OECD countries but the weak financial environment in OECD countries has seen demand growth weaken.

 

LOGO Refining margins

For more information on the BP refining marker margin and other measures see page 73.

 

Concerns about the volatility of commodity and financial markets, energy security and climate change have led to continued debate over the appropriate role of markets, government regulation and other policy measures that affect the supply and consumption of energy. Given the pressures in the sector, we expect regulation and taxation of the energy industry and energy users to increase in many areas in the future.

 

 

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The facts and figures used in this section are derived from BP Energy Outlook 2030, published in January 2013, unless otherwise indicated, and represent a ‘base case’ or most likely projection.

 

LOGO For more information see

bp.com/energyoutlook

 

Energy consumption by region

(billion tonnes of oil equivalent)

 

LOGO

 

Source: BP Energy Outlook 2030.

 

Energy consumption by fuel

(billion tonnes of oil equivalent)

 

LOGO

 

*Includes biofuels.

Source: BP Energy Outlook 2030.

 

1.6% per annum

Projected world primary energy consumption growth to 2030.

  

Longer-term outlook

 

Challenges and opportunities

 

The world’s population is projected to increase by 1.3 billion from 2011 to 2030, with real income likely to double over the same period. These factors will lead to increased energy demand and consumption. Energy and climate policies, efficiency gains and a long-term structural shift in fast-growing economies away from industry and towards less energy-intensive activities will help to restrain any increase, but the overall trend is likely to be one of strong growth. We expect demand for energy to increase by as much as 36% between 2011 and 2030, with nearly 93% of the growth to occur in non-OECD countries.

 

We estimate that there are enough energy resources available to meet the increases in demand in the foreseeable future, but there will be challenges as well as opportunities.

 

Energy security represents a challenge. More than 60% of the world’s natural gas is concentrated in just four countries. More than 80% of global oil reserves are located in nine countries, most of which are well away from the hubs of energy consumption.

 

Meeting growing demand for secure and sustainable energy will also present an affordability challenge as the availability of easily accessible fossil fuels slowly diminishes, with many lower-carbon resources and technologies remaining costly to produce at scale.

 

While energy is available to meet growing demand, action is needed to limit carbon dioxide (CO2 ) and other greenhouse gases being emitted through fossil fuel use. Burning fossil fuels can also raise local and regional air quality issues.

  

Meeting the energy challenge

 

We believe that, increasingly, the global energy challenge can only be met through a diverse mix of fuels and technologies. A broad mix can enhance national and global energy security while supporting the transition to a lower-carbon economy. This is one reason why BP’s portfolio includes oil sands, shale gas, deepwater oil and natural gas production, biofuels and wind.

 

We estimate that today’s oil reserves could meet more than 45 years of demand at current consumption rates, while known supplies of natural gas could meet demand for nearly 60 years and coal could meet demand for up to 120 years.a

 

Our industry has a track record in expanding the availability of resources through investment and the application of technology. For example, in 1981 the world’s oil reserves stood at an estimated 700 billion barrels. By 2011 this had risen to 1,650 billion barrels, even though 800 billion barrels had been consumed in the intervening three decades.

 

Oil and natural gas

We believe oil and natural gas are likely to represent about 53% of total energy consumption in 2030. Even under the International Energy Agency’s (IEA) most ambitious climate policy scenario (the 450 scenario), oil and gas would still make up 50% of the energy mix in 2030, with combined demand projected to exceed current levels in absolute terms.b The 450 scenario assumes governments adopt commitments to limit the long-term concentration of greenhouse gases in the atmosphere to 450 parts-per-million of CO2 equivalent.

 

a   BP Statistical Review of World Energy June 2012. These reserve estimates are compiled from official sources and other third-party data, which may not be based on proved reserves as defined by SEC rules.

b   From World Energy Outlook 2012©, OECD/IEA 2012, page 553.

In the US, our biofuels business is focusing on the development of cellulosic ethanol technology at facilities in San Diego, California (right) and Jennings, Louisiana.    LOGO

 

 

 

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LOGO  

New sources of hydrocarbons are more difficult to reach, extract and process. This will require BP and others in our industry to develop new technologies to boost recovery from declining fields and commercialize currently inaccessible resources. Greater energy intensity could be required to extract these resources, which means operating costs and greenhouse gas emissions from operations are likely to increase.

 

Renewables

Renewable energy is the fastest growing fuel and is projected to grow by 7.6% per annum to 2030. Renewable energies are starting from a low base however, and we project that they are only likely to meet around 6% of total energy demand by 2030. With a few exceptions, renewables are not yet competitive with conventional power and transportation fuels. Sufficient policy support is required to help commercialize effective lower-carbon options and technologies, but renewables will ultimately need to become free from subsidy and commercially self-sustaining.

 

Energy efficiency and innovation

While overall energy consumption is set to increase, economic growth is expected to become significantly less energy intensive, especially in non-OECD economies. In fact, globally, demand for energy is expected to rise at less than half the rate of gross domestic product (GDP). The amount of energy required to generate $1 million in China has already dropped from 350 tonnes of oil equivalent in 1980 to 200 tonnes of oil equivalent or less today.

 

Innovation can play a key role in improving technology design, process and use of materials, bringing down cost and increasing efficiency. In transport, for example, we believe that efficient combustion engines and power train technologies could offer the quickest and most effective pathway to a secure, lower-carbon future.

 

Policy, prices and access

If the world’s growing demand for energy is to be met in a sustainable way, we believe that governments must set a stable and enduring framework for the private sector to invest and for consumers to choose wisely. As part of this, governments will need to provide secure access for exploration and development of energy resources; define mutual benefits for resource owners and development partners; and establish and maintain an appropriate legal and regulatory environment.

 

We believe open and competitive markets are the most effective way to encourage companies to find, produce and distribute diverse forms of energy sustainably. The US experience with shale gas shows how an open and competitive environment can drive technological innovation and unlock resources. We also believe that putting a price on carbon – one that treats all carbon equally, whether it comes out of an industrial smokestack or a car exhaust – will make energy efficiency and conservation more attractive to businesses and individuals, and lower-carbon energy sources more cost competitive.

 

Beyond 2030

 

We expect that growing population and per capita incomes will continue to drive growing demand for energy. These dynamics will be shaped by future technology developments, changes in tastes, and future policy choices – all of which are inherently uncertain. Concerns about energy security, affordability and environmental impacts are all likely to be important considerations. These factors may accelerate the trend towards more diverse sources of energy supply, a lower average carbon footprint, increased efficiency and demand management.

 

BP is sensitive to the challenges and opportunities outlined here. We actively monitor developments and continually assess a range of potential outcomes and their implications for our strategy.

 

 

 

93%

 

Non-OECD countries’ share of energy
consumption growth to 2030.

 

+45%

 

  LOGO
Net growth in unconventional global energy production from 2020 to 2030.    

 

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Our business model

 

   Through our business model we aim to create value across the hydrocarbon value chain. This starts with exploration and ends
with the supply of energy and other products fundamental to
everyday life.
LOGO
BP is the largest foreign investor in Azerbaijan and operates two production-sharing agreements – Azeri-Chirag-Gunashli and Shah Deniz – and other exploration leases. Above is the West Azeri platform.   

 

Who we are

 

BP is one of the world’s leading integrated oil and gas companies.a We aim to create value for shareholders by helping to meet growing demand for energy in a responsible way. We strive to be a safety leader in our industry, a world-class operator, a responsible corporate citizen and a good employer.

 

Through our work we provide customers with fuel for transportation, energy for heat and light, lubricants to keep engines moving, and the petrochemicals products used to make everyday items as diverse as paints, clothes and packaging. Our projects and operations help to generate employment, investment and tax revenues in countries and communities around the world.

 

At each stage of the hydrocarbon value chain there are opportunities for us to create value – both through the successful execution of activities that are core to our industry, and through the application of our own distinctive strengths and capabilities in performing those activities.

 

How we are organized

 

We have two main business segments: Upstream and Downstream. Through these we find, develop and produce essential sources of energy, and turn these sources into products that people need.

 

a   On the basis of market capitalization, proved reserves and production.

  

 

We also hold a 50% shareholding in the major Russian oil company TNK-BP, which owns upstream and downstream assets. In November, marking what we expect to be an exciting new future for BP in Russia, we signed final, binding agreements with Rosneft, Russia’s leading oil company, for the sale of our share in TNK-BP for $12.3 billion in cash (which includes a dividend of $0.7 billion received from TNK-BP in December 2012) and an 18.5% stake in Rosneft. The transaction is expected to complete in the first half of 2013. Combined with BP’s existing 1.25% shareholding, this will result in BP owning 19.75% of Rosneft.

 

In renewable energy, our investments and activities are focused on biofuels and wind. In addition, our emerging businesses and ventures unit invests in a broad range of energy projects and technologies. Our renewables and venturing activities are managed through our Alternative Energy business, which is reported in Other businesses and corporate on page 82.

 

Our commitments

 

Keeping a relentless focus on safety is the top priority for everyone at BP.

 

Rigorous management of risk helps to protect the people at the front line, the places in which we operate and the value we create. We understand that operating in politically complex regions and technically demanding geographies requires particular sensitivity to local environments.

 

 

 

 

 

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Our business model – continued

 

LOGO

  

The relationships we form with shareholders, governments, regulators, non-governmental organizations, local communities, customers, franchisees, partners, contractors, suppliers and others in our industry are crucial to the success of our business. We are committed to building long-lasting relationships, meeting our obligations and acting responsibly.

 

We believe that the best way to achieve sustainable success as a group is to act in the long-term interests of our shareholders, our partners and society. Through our work we aim to create value for our investors and benefits for the communities and societies in which we operate, with the safe and responsible supply of energy playing a vital role in economic development.

 

Our people

 

We employ nearly 86,000 people, including 14,700 service station staff in Europe and Asia. The majority of our employees are located in the US and Europe. The qualities and abilities of our employees have a powerful effect on our ability to compete and meet our commitments to investors and the wider world. We provide a range of professional development programmes and training to help our employees develop their skills and capabilities. We are committed to creating an inclusive work environment where everyone is treated fairly, with dignity, respect and without discrimination.

  

Our presence

 

As a global group, our interests and activities are held or operated through subsidiaries, branches, joint ventures or associates established in – and subject to the laws and regulations of – many different jurisdictions. Our worldwide headquarters is in London. The UK is a centre for trading, legal, finance and other business functions as well as three of BP’s major global research and technology groups. We have well-established operations in Europe, the US, Canada, Russia, South America, Australasia, Asia and parts of Africa. BP has freehold and leasehold interests in real estate in numerous countries, but no individual property is significant to the group as a whole. For more on the significant subsidiaries of the group at 31 December 2012 and the group percentage of ordinary share capital see Note 45 on page 255. For information on significant jointly controlled entities and associates of the group, see Notes 24 and 25 on pages 218-220.

 

Value creation

 

We seek to add value at each stage of our operations, from exploration to marketing. We believe that by operating across the full hydrocarbon value chain we can create more value for shareholders, as benefits and costs can often be shared by our segments. Integration also enables us to develop shared functional excellence in areas such as safety and operational risk, environmental and social practices, procurement, technology and treasury management more efficiently.

LOGO     Our employees

            For more on BP’s employees in 2012

            see pages 55-56.

     

 

LOGO

 

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LOGO

 

 

 

 

 

 

LOGO Our business model

For more information see BP at a glance on pages 4-5.

 

LOGO

  

We aim to protect value by maintaining a rigorous focus on safety, reliability and efficiency across our range of activities. We often work with partners to mitigate risk or gain from complementary skills.

 

Finding oil and gas

First, we acquire the rights to explore for oil and gas. Through new access we are able to renew our portfolio, discover new resources and replenish our development options.

 

Developing and extracting oil
and gas

When we are successful in finding hydrocarbon resources, we create value by seeking to progress them into proved reserves or by selling them on if they do not fit with our strategic objectives.

 

If we believe developing and producing the reserves will be advantageous for BP, we will produce the oil and gas, then sell it to the market or distribute it to our downstream facilities.

 

Transporting and trading oil
and gas

We move oil and gas through pipelines and by ship, truck and rail. We use our trading and supply skills and knowledge to find the best routes to deliver supplies to the most attractive markets.

 

Manufacturing and marketing fuels and products

Using our technology and expertise, we manufacture fuels and products, creating value by seeking to operate a high-quality portfolio of well-located assets safely, reliably and efficiently. We market our products to consumers and other end-users and add value through the strength of our brands.

  

Our distinctive strengths and capabilities

 

We consider our areas of distinctive strength to include:

 

• Exploration – acquiring access and searching for hydrocarbons.

• Deep water – we have a long track record in finding, developing and producing hydrocarbons in deep water.

• Giant fields – managing the scale and complexity of fields with resources believed to exceed 500 million boe.a

• Gas value chains – seeking to add value as gas moves from field to customer.

• Downstream – the pursuit of safe, reliable and efficient operations, and leading returns, across fuels, lubricants and petrochemicals.

 

These are underpinned by our development and application of technology and our ability to build strong relationships. In addition, we have a long-established integrated supply and trading function.

 

Strong relationships

We are seeing an evolution in our industry, with international oil companies such as BP establishing new kinds of partnerships and co-operation with governments, national oil companies and other resource holders. The benefits of our value-creating activity are shared with governments and other partners.

 

We seek opportunities to develop and deploy distinctive capabilities that complement those of our partners. We also partner with universities and governments in pursuit of improving the technologies available to us, so we can enhance our operations and develop new products. We aim to support and improve standards in our

 

a   Actual amount of proved reserves of such fields on a basis recognized by the SEC may be less than this.

 

 

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Upstream technology flagships

 

LOGO

 

LOGO

 

 

LOGO

 

 

Technology

For more on the role of technology at BP

see pages 57-59.

 

Upstream

For more on our upstream activities in 2012

see pages 63-71.

 

We increased our acreage in Trinidad & Tobago, where our production comprises oil, gas and NGLs, by 889,000 acres in 2012. Below is the Rowan drilling platform, offshore Trinidad.

 

LOGO

  

industry by participating in industry bodies, engaging with our peers on important issues, and – where appropriate – setting voluntary standards above those required by current regulation. And we carry out regular reviews and audit processes with contractors and suppliers, which help to maintain strong links across our operations and activities.

 

Technology

We believe our development and application of technology is central to our reputation and competitive advantage. For us, technology is the practical application of scientific knowledge to manage risks, capture business value and inform strategy development. This includes the research, development, demonstration and acquisition of new technical capabilities and support for the deployment of BP’s know-how.

 

Our investments are focused on access to resources, process efficiency, product formulation and lower-carbon opportunities. We monitor the potential opportunities and risks presented by emerging science, interdisciplinary innovation and new players; natural resource issues and climate concerns; and evolving policy, including the current emphasis on energy security and efficiency.

 

BP’s technology advisory council, comprised of eminent business and academic technology leaders, provides the board and executive management with an independent view of BP’s capabilities judged against the highest industrial and scientific standards.

 

Supply and trading

We buy and sell at each stage in the value chain to optimize value for the group, often selling our own production and buying from elsewhere to satisfy demand from our refineries and customers. We also aim to create value through entrepreneurial trading, where our presence across major energy trading hubs gives us a good understanding of regional and international markets.

 

  

Upstream

 

       

Our Upstream segment is responsible for our activities in oil and natural gas exploration, field development and production, and midstream transportation, storage and processing. We also market and trade natural gas, including liquefied natural gas, power and natural gas liquids. We focus on areas that play to our strengths, particularly exploration, deep water, gas value chains and giant fields.

       

 

In 2012 our upstream and midstream activities took place in 28 countries including Angola, Azerbaijan, Canada, Egypt, Norway, Trinidad & Tobago, the UK, the US and other locations within Asia, Australasia, South America, North Africa and the Middle East.

 

Our Upstream segment manages its exploration, development and production activities through global functions with specialist areas of expertise.

 

We actively manage our portfolio and are placing increasing emphasis on accessing, developing and producing from fields able to provide high-margin barrels (those with the potential to make the greatest contribution to our operating cash flow). We sell assets when we believe they may be more valuable to others. This allows us to focus our leadership, technical resources and organizational capability on the resources we believe are likely to add the most value to our portfolio.

 

Our upstream technologies support BP’s business strategy by focusing on safety and operational risks, helping to obtain new access, increasing recovery and reserves and improving production efficiency. Our strengths in exploration, deep water, giant fields and gas value chains are underpinned by dedicated flagship technology programmes.

 

 

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Downstream technology

 

LOGO

 

LOGO     Downstream

            For more on our downstream activities

            in 2012 see pages 72-79.

 

 

 

The lubricants business is focusing on the growth markets of Brazil, India and China. Below, a Castrol laboratory technician in Brazil, where Castrol lubricants have been sold since the 1950s.

 

LOGO

  

Downstream

 

  

co-engineered with Ford during the development of its newly released EcoBoost™ engine, which offers a significant improvement in efficiency.

 

The segment comprises three businesses: fuels, lubricants and petrochemicals, each of which operates as a value chain.

 

Our fuels business sells refined petroleum products including gasoline, diesel and aviation fuel and liquefied petroleum gas. Within the fuels business, fuels value chains integrate the activities of refining, logistics, marketing, and supply and trading on a regional basis. This provides the opportunity to optimize our activities – from crude oil purchases to end-consumer sales – all the way through our refineries, terminals, pipelines and retail stations.

 

Our lubricants business is involved in manufacturing and marketing lubricants and related services to markets around the world. We add value through the strength of our brands and through strategic collaboration with original equipment manufacturing partners where we seek to develop new high-performance lubricants such as Castrol EDGE.

 

Our global petrochemicals business manufactures and markets petrochemicals that are used in many everyday products, such as paints, plastic bottles and textiles. Value is derived from our strong customer relationships and joint-venture partners, and through the application of our world-class, proprietary technology.

  

 

Our Downstream segment is the product and service-led arm of BP, focused on fuels, lubricants and petrochemicals. It is responsible for the refining, manufacturing, marketing, transportation, and supply and trading of crude oil, petroleum, petrochemicals products and related services to wholesale and retail customers.

 

  
  

 

The Downstream segment markets products in over 70 countries and has significant operations in Europe, North America, Australasia and Asia. We also manufacture and market our products across southern Africa and Central and South America.

 

We aim to be excellent in the markets in which we choose to participate – those that allow BP to serve the major energy markets of the world. Our aim is to operate all of our businesses as safe and reliable value chains, where we participate in multiple stages of each supply chain, as we believe that way we can deliver greater returns than would arise from owning a collection of discrete assets. These value chains, combined with our advantaged manufacturing operations and expertise in technology, allow us to pursue competitive returns and sustainable growth, as we serve customers and promote BP and our brands through high quality products. As in our Upstream segment, we will sell assets when we believe that to do so would generate more value than retaining them in our own portfolio.

 

Technology makes a critical contribution to our downstream activities. Through the research, development and deployment of a wide range of technologies, processes and techniques, we aim to enhance safety and risk management, improve our margins, increase efficiency and reliability, and create new market opportunities. For example, in lubricants we launched an oil

  
 

 

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Our strategy

 

   Through our strategy we aim to create a distinctive platform for value growth over the long term.
LOGO

Our seismic technology helps minimize field appraisal and development risk. The above model of a hydrocarbon field in the Gulf of Mexico shows large salt deposits obscuring a hydrocarbon reservoir.

 

Upstream portfolio simplification

We have divested a significant proportion of our operated assets while still retaining virtually all our future major projectsa and around 90% of our proved reserves.

 

LOGO

 

a   See pages 67-71 for information on our major Upstream projects.

b   Since April 2010.

  

 

In 2011 we put forward a 10-point plan that outlined what could be expected from BP over the next three years. During 2012 we worked towards the milestones we had set out for 2014. We refined our plans and communicated further information on our longer-term strategic objectives beyond 2014.

 

Through this work and the actions taken to strengthen the group, BP enters 2013 a more focused oil and gas company with promising opportunities and a clear plan for the future. BP’s strengthened position, distinctive capabilities, strong financial framework and vision for the future provide the foundation for our long-term strategy. This strategy is intended to ensure BP is well positioned for the world we see ahead.

 

Our financial framework

 

We expect our organic capital expenditurea to be in the range of $24-27 billion per year through to the end of the decade, with investment prioritized towards the Upstream segment. All investments will continue to be subject to a rigorous capital allocation review process.

 

We expect to make around $2-3 billion of divestments per year in order to constantly optimize our portfolio. We will target gearingb in the 10-20% range while uncertainties remain. Our intention is to increase shareholder distributions in line with BP’s improving circumstances.

  

 

Our strategic priorities

 

Our aim is to be an oil and gas company that grows over the long term. We will seek to continually enhance safety and risk management, earn and keep people’s trust, and create value for shareholders. We will continue to simplify our organization and fine tune the portfolio. We will focus on efficient execution in our operations and our use of capital. We will build capability through the pursuit of greater standardization and increased functional expertise.

 

BP Energy Outlook 2030 projects that world demand for energy will continue to grow. In helping to meet this demand, BP has a large suite of opportunities – the legacy of years of success in gaining access to and developing resources. This allows us to select and invest in those projects with the potential to provide the highest returns. We will prioritize value rather than seek to grow production volume for its own sake. We will concentrate on higher quality assets in both our Upstream and Downstream segments, starting with safety and the delivery of strong and growing cash flows to the group.

 

a   Organic capital expenditure excludes acquisitions and asset exchanges.

b   See footnote d on page 21.

 

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The Skarv floating production, storage and offloading unit – one of the major project start-ups in 2012 – on tow in a Norwegian fjord.

 

10-point plan

Launched in October 2011 and set out in BP Annual Report and Form 20-F 2011, our 10-point plan described our intentions for building a stronger, safer BP.

 

What you can expect

 

1      A relentless focus on safety and managing risk through the systematic application of global standards.

 

2      We will play to our strengths in exploration, deep water, giant fields and gas value chains.

 

3      Stronger and more focused with an asset base that is high graded and higher performing.

 

4      Simpler and more standardized with fewer assets and operations in fewer countries; more streamlined internal reward and performance management processes.

 

5      Improved transparency through reporting TNK-BP as a separate segment and breaking out the numbers for the three downstream businesses.

 

What you can measure

 

6      Active portfolio management to continue by completing $38 billion of disposals over the four years to the end of 2013, in order to focus on our strengths.

 

7      We expect to bring new upstream projects onstream with unit operating cash marginsa around double the 2011 average by 2014.b

 

8      We are aiming to generate an increase of around 50% in net cash provided by operating activities by 2014 compared with 2011.c

 

9      We intend to use half our incremental operating cash for reinvestment, half for other purposes.

 

10    Strong balance sheet with intention to target our level of gearingd in the lower half of the 10-20% range over time.

   LOGO
  

We will pursue new opportunities by applying our distinctive strengths of relationships, technology and a strong balance sheet. Our past experience of co-ordinating complex projects around the world can help us to gain access to new areas.

 

LOGO Business model

For more information on our distinctive strengths and how we create value see pages 15-19.

  

conventional and unconventional resources. We expect to continue to invest in giant fields, where this expertise is particularly valuable.

 

We believe our ability to integrate complex gas value chains is another key strength. We intend to hold a portfolio of gas positions selected according to expected returns, with a balance across conventional and unconventional gas. We will optimize these through our trading activities.

 

We are committed to Russia and the Middle East – areas where we have a long history.

 

  

Upstream

Our analysis indicates that oil offers us the most attractive opportunities. Our investments will therefore be biased to oil. We also believe there will be opportunities to create high returns from advantaged gas assets.

 

We have a long track record of value creation through exploration. We will invest in our strong incumbent positions and look for new opportunities. Deepwater developments can provide good opportunities for companies with the requisite expertise. We will utilize our scale and capability as we invest further in this area. We believe we are able to manage scale and complexity, and improve the recovery of

  

Downstream

We believe BP has world-class downstream operations with a strong and improving track record of performance in recent years. We will continue to focus on safe and reliable operations and excellent execution, together with disciplined investment and portfolio management. Our focus on portfolio quality will include improving the margin capability of all of our businesses, and a focus on investing in attractive markets.

 

As the world changes, we expect to increase our exposure to growth markets and demand from new consumers.

 

a     Unit cash margin is net cash provided by operating activities for the relevant projects in our Upstream segment, divided by the total number of barrels of oil and gas equivalent produced for the relevant projects. It excludes dividends and production for TNK-BP.

b     Assuming a constant oil price of $100 per barrel.

c     Assuming an oil price of $100 per barrel and a Henry Hub gas price of $5/mmBtu in 2014. The projection assumes the completion of the agreed transaction with Rosneft and receipt of the projected Rosneft dividend and excludes BP’s share of the TNK-BP dividends from operating cash flow for 2011 and 2014. The projection includes BP’s payment commitments under the Department of Justice and SEC settlements. It does not reflect any cash flows relating to other liabilities, contingent liabilities, settlements or contingent assets arising from the Gulf of Mexico oil spill which may or may not arise at that time. We are not able to reliably estimate the amount or timing of a number of contingent liabilities. See Financial statements – Note 43 on page 253 for further information.

d     Gearing refers to the ratio of the group’s net debt to net debt plus equity and is a non-GAAP measure. See Financial statements – Note 35 on page 234 for further information including a reconciliation to gross debt, which is the nearest equivalent measure on an IFRS basis.

e     Free cash flow: net cash provided by operating activities less net cash used in investing activities.

     Longer-term objectives
     g    Maintain momentum on safety and risk reduction.
     g    Develop and apply new technologies that access new hydrocarbons or extract and process them more efficiently.
     Upstream
     g    Generate strong returns within a disciplined financial framework.
     g    Deliver growth through increased reinvestment in higher return opportunities.
     g    Maintain our strong incumbent positions and a diversified portfolio of deep water, giant fields and gas value chains.
     g    Build material new positions for the long term.
     Downstream
     g    Grow free cash flow.e
     g    Reduce our exposure to refining when not part of an integrated value chain.
     g    Re-orientate the geographic mix of our downstream footprint to growth markets.
       
       
       
       
       
       
       
       
 

 

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Our performance

 

   2012 saw BP build on the strong foundations laid in the previous year. Despite facing major uncertainties, we made progress against our 10-point plan and are reshaping our portfolio to increase efficiency, margins and cash flows.
LOGO    LOGO

In 2012 our refineries – particularly Toledo (above) and Whiting in the US – benefited from a location advantage, as they were able to access discounted crudes.

 

BP has been in Azerbaijan since 1992 and is the largest foreign investor in the country. Our assets include the West Chirag production and drilling platform (right) which is due to start up in late 2013.

 

LOGO     Safety

            For more information on our safety

            performance see pages 46-50.

  

During the year we made progress in our priority areas of enhancing safety and risk management, restoring trust by meeting our commitments in the Gulf of Mexico and delivering higher returns for shareholders, as evidenced by the increases in quarterly dividend announced in 2012 (see Dividends on page 25). We worked to resolve the uncertainties facing the company in the US and Russia. We continued the major programme of divestments announced in 2010, which we believe is making BP a more efficient organization. And we made investments in areas where we believe we have advantages and higher margin opportunities. Safety remained our number one priority throughout the year, across the company.

 

We reached the majority of the 2012 milestones that we set out when we launched our 10-point plan in October 2011 (see 2012 in summary) and believe we are on course to improve our margins and cash flow by 2014.

 

Safety

 

We continued our work to enhance safety and risk management in everything we do. In personal safety, sadly, we had four fatalities in our operations during 2012. We reported 43 Tier 1 process safety events in 2012 and 74 in 2011. Loss of primary containment was reduced by 19% compared with 2011. We continued our programme of major upstream turnarounds, with 30 turnarounds completed in 2012. We expect to carry out up to 22 further turnarounds in 2013.

 

Over the past 12 months, our safety and operational risk function (S&OR) continued to

  

drive improvements to operational safety and reliability with enhanced independent assurance, improved engineering and operating practices, and training and coaching programmes. Our single global wells organization is driving greater consistency across our operations. Our performance and reward system is reinforcing that everyone at BP is responsible for safe operations.

 

BP’s operating management system (OMS) provides us with a systematic and controlled approach to the way the company’s operating facilities are managed. All of our operations, with the exception of those recently acquired, are now applying OMS and working to conform to these group-wide standards and practices.

 

We continue to make progress on all of the remaining recommendations from the Bly Report. As of December 2012, the total number of completed recommendations was 14 out of 26.

 

Independent advice and monitoring

In June 2012 we appointed Carl Sandlin to track the company’s implementation of the recommendations of the Bly Report, our internal investigation into the Deepwater Horizon incident. He brings extensive experience in overseeing global drilling operations. In this role, he will provide an objective and independent assessment to the board of BP’s progress against the report’s recommendations. He will also observe and report on process safety culture.

 

Following legal settlements with the US government, BP has agreed to take additional actions, enforceable by the court, to further

 

 

 

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$20 billion

Total BP payments made to the Deepwater Horizon Oil Spill Trust fund.

 

$11.6 billion

BP’s profita in 2012.

 

$12.0 billion

BP’s replacement cost profita b in 2012.

 

a Profit attributable to BP shareholders. This is the measure of profit required for the group under IFRS.

b Replacement cost profit reflects the replacement cost of supplies and, for the group, is not a recognized GAAP measure. See footnote b on page 34.

 

 

 

High-margin production was brought back onstream in 2012 in Angola – where the Deepsea Stavanger rig is currently operating at the Greater Plutonio development.

 

In 2012 we completed the acquisition of Shell and Cosan Industria e Commercio’s interests in aviation fuels assets at seven Brazilian airports, which is an important growth market (below).

 

LOGO

    

enhance the safety of drilling operations in the Gulf of Mexico (see US regulatory update on page 24). These actions include the appointment of two monitors, both with terms of four years. A process safety monitor will review, evaluate, and provide recommendations for the improvement of BP’s process safety and risk management procedures concerning deepwater drilling in the Gulf of Mexico. An ethics monitor will review and provide recommendations for the improvement of BP’s code of conduct and its implementation and enforcement. Additionally, an independent third-party auditor will review and report on BP’s implementation of key terms of the agreement, including procedures and systems related to safety and environmental management, operational oversight, and oil spill response training and drills.

 

Trust

 

BP has continued to meet its commitments to the Gulf Coast. During the year we worked with state and federal trustees to assess impacts on natural resources and progress early environmental restoration work. We supported independent research through the Gulf of Mexico Research Initiative, so we can better understand and mitigate the potential impacts of future oil spills. And we continued to clean up the Gulf shoreline, which involved responding promptly when Hurricane Isaac brought deposits of buried residual oil to the surface at some beaches. Of the 4,376 miles (7,043km) that were in the area

 

 

of response covered in the Shoreline Clean-up Completion Plana, 4,029 miles (6,484km) were deemed complete by the end of 2012.

 

We have continued to promote economic recovery by resolving legitimate claims and providing support to two of the region’s most important industries – tourism and seafood. In the fourth quarter we made a final payment into the Deepwater Horizon Oil Spill Trust fund (Trust), bringing our total payments to $20 billion. The Trust and BP had paid a total of $11.7 billion in claims, advances and other payments by the end of 2012.

 

Settlement reached with PSC

In April we announced we had reached definitive and fully documented agreements with the Plaintiffs’ Steering Committee (PSC) to resolve the substantial majority of eligible private economic loss and medical claims stemming from the Deepwater Horizon accident and oil spill. The agreements were approved by the court in December 2012 and January 2013 although BP is challenging a recent ruling by the court regarding the interpretation of certain protocols established in the economic and property damages settlement agreement. See Legal proceedings on page 167. The settlement includes BP’s commitment of $2.3 billion to help resolve economic loss claims related to the Gulf seafood industry.

 

a  Approved by the US Coast Guard’s Federal On-Scene Coordinator, the Shoreline Clean-up Completion Plan sets standards for the surveying, verification and completion of clean-up activities.

 

    

 

2012 in summary

 

g   We drew our TNK-BP partnership in Russia to a close through an agreed transaction with Rosneft, which will provide BP with a net $12.3 billion in cash (which includes a dividend of $0.7 billion received from TNK-BP in December 2012) and an additional 18.5% share in Rosneft, bringing our total shareholding to 19.75%.

 

    

g   We took the total of asset sales announced since the start of 2010 to around $38 billion, effectively reaching our target a year early.

 

    

g   We gained new exploration access in six countries.

 

    

g   Our 2012 reserves replacement ratio, on a combined basis of subsidiaries and equity-accounted entities, excluding acquisitions and disposals, was 77%, with net additions to reserves in 2012 being wholly from equity-accounted entities (see page 86).

 

    

The following points relate to particular milestones we set for 2012:

 

    

g   High-margin production was brought back onstream successfully in Angola, the North Sea and other regions during 2012.

 

    

g   Exploration drilling activity took place at nine wells against a target of 12 because additional time was required to ensure the rigs meet our enhanced safety standards.

 

    

g   Five major project start-ups were achieved (against a target of six): at Galapagos in the Gulf of Mexico; Clochas Mavacola and block 31 in PSVM in Angola; Devenick in the North Sea; and Skarv in Norway. The Angola LNG plant is being commissioned and is expected to start production in 2013.

 

    

g   Seven rigs were operational in the Gulf of Mexico in 2012 against a target of eight. An eighth rig is in place on the Mad Dog platform and is being commissioned and tested. It is expected to start up in 2013.

 

    

g   We made the final payment to the Deepwater Horizon Oil Spill Trust, taking total payments to the Trust to $20 billion.

 

    

g   In Downstream, we were unable to fully deliver the $2 billion of financial performance improvementb since 2009, which we had identified as an opportunity in 2010, due mainly to a significant reduction in the supply and trading contribution in 2012.

 

    

g   Organic capital expenditurec during the year was $23.1 billion compared with our original expectation of around $22 billion.

 

    

 

b See page 74 for further information on Downstream’s performance improvement, which is a non-GAAP measure.

c Organic capital expenditure excludes acquisitions and asset exchanges and, in 2012, expenditure associated with deepening our US natural gas and North Sea asset bases (see footnote b on page 35).

 

 

 

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Our performance – continued

LOGO US legal proceedings

For more information on our US settlements for criminal and securities claims see pages 162-171.

LOGO Financial review

For more on our performance in 2012 see pages 34-37.

 

 

 

400,000   km2

New exploration acreage accessed since 2010.

Significant uncertainties exist in relation to the amount of claims that are to be paid and will become payable through the claims process. There is significant uncertainty in relation to the amounts that ultimately will be paid in relation to current claims, and the number, type and amounts payable for claims not yet reported. In addition, there is further uncertainty in relation to interpretations of the claims administrator regarding the protocols under the settlement agreement and judicial interpretation of these protocols, and the outcomes of any further litigation including in relation to potential opt-outs from the settlement or otherwise. The PSC settlement is uncapped except for economic loss claims related to the Gulf seafood industry. There can be no certainty as to how BP’s challenge to the court’s ruling will ultimately be resolved or determined. To the extent that there are insufficient funds available in the Trust fund, payments under the PSC settlement will be made by BP directly and charged to the income statement. See Plaintiffs’ Steering Committee settlements on pages 60-61 for further information as well as Risk factors on pages 41-42 and Financial statements – Note 36 on page 235.

See page 59 for information on the federal multi-district litigation proceeding in New Orleans (MDL 2179), the first phase of which began on 25 February 2013.

US regulatory update

During the year, the US Department of Justice (DoJ) continued to conduct an investigation into the Deepwater Horizon incident regarding possible violations of US civil and criminal laws. Similarly, the US Securities and Exchange Commission (SEC) continued their investigation regarding possible violations of US securities laws.

BP reached an agreement with the US government in November 2012 to resolve all federal criminal claims arising out of the incident. BP pleaded guilty to 11 felony counts of misconduct or neglect of ships officers

relating to the loss of 11 lives; one misdemeanour count under the Clean Water Act; one misdemeanour count under the Migratory Bird Treaty Act; and one felony count of obstruction of Congress. BP will pay $4 billion – including criminal fines and payments to the National Fish & Wildlife Foundation and the National Academy of Sciences – in instalments over a period of five years. The court also ordered, as previously agreed with the US government, that BP serve a term of five years’ probation. BP has agreed to take additional actions, enforceable by the court, to further enhance the safety of drilling operations in the Gulf of Mexico. These activities relate to BP’s risk management processes, such as third-party auditing and verification, training, and well control equipment and processes such as blowout preventers and cementing.

BP reached a settlement with the SEC in November 2012, resolving the SEC’s Deepwater Horizon-related civil claims. BP has agreed to a civil penalty of $525 million and to an injunction prohibiting it from violating certain US securities laws and regulations. BP made its first payment of $175 million in December 2012.

The US Environmental Protection Agency (EPA) announced in November 2012 that it had temporarily suspended BP p.l.c. and other BP companies from participating in new federal contracts. As a result of the temporary suspension, the notified BP entities are ineligible to receive any new US government contracts or renewal of an expiring contract. The suspension does not affect existing contracts BP has with the US government, including those relating to current and ongoing drilling and production operations in the Gulf of Mexico. In February 2013 the EPA issued a notice of mandatory debarment for BP Exploration & Production Inc at its Houston headquarters. Mandatory debarment prevents that company from entering into new contracts or new leases

 

 

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LOGO

 

We made good progress on the Whiting refinery modernization programme (right) in 2012, and the project is on track to come onstream in the second half of 2013.

 

BP is accelerating the commercialization of advanced biobutanol technology – with partner Du Pont – at a purpose-built development and demonstration facility at our Saltend site, near Hull, UK (above).

 

$22.5 billion

 

Our Upstream segment’s replacement cost profit before interest and tax in 2012.

 

LOGO Upstream

For more on the segment’s financial performance see page 65 and for information on segmental changes affecting Upstream at the beginning of 2012 see page 64.

   LOGO
  

 

with the US government at those premises. We continue to work with the EPA to resolve suspension and debarment issues.

 

Value

We achieved a profit of $11.6 billion in 2012 compared with $25.7 billion in 2011. Excluding inventory holding gains, our replacement cost (RC) profita in 2012 was $12.0 billion compared with $23.9 billion in 2011. After adjusting for non-operating items and fair value accounting effectsb, our underlying RC profitb was $17.6 billion in 2012 compared with $21.7 billion in 2011. Underlying RC profit is a measure closely tracked by management to evaluate BP’s operating performance and to make financial, strategic and operating decisions.

 

Our goal is to grow operating cash flowc to enable us to invest for future growth and increase distributions to shareholders. This year we generated operating cash flow of $20.4 billion, compared with $22.2 billion in 2011. The cash outflow in respect of the Gulf of Mexico oil spill reduced from $6.8 billion in 2011 to $2.4 billion in 2012. Cash and cash equivalents at the end of 2012 totalled $19.5 billion. Gross debt at 31 December 2012 was $48.8 billion compared with $44.2 billion at 31 December 2011. Net debta was $27.5 billion at 31 December 2012, leaving our gearing (net debt ratio)d at 18.7% compared with 20.5% at the end of 2011. We continue to target gearing in the 10-20% range while uncertainties remain.

 

Dividends

Total dividends paid in 2012 were 33 cents per share, up 18% compared with 2011 on a dollar basis and 20% in sterling terms. This equated to a total cash distribution to shareholders of $5.3 billion during the year. We announced two increases in the quarterly dividend during 2012 – by 14%, to 8 cents per share, in February and by a further 12.5%, to 9 cents per share, in October. These increases reflected our confidence in the company’s progress against the 10-point plan and our growing belief in its longer-term prospects.

  

 

Portfolio reshaped

During the year we strengthened the group’s financial position, announcing further asset sales and, by the end of 2012, we had essentially reached our $38 billion target.

 

We began the divestment programme in 2010, increasing the focus of the company’s core portfolio on BP’s areas of distinctive strength and capability, while reducing operational complexity. We have since sold around 50% of our upstream installations, 32% of our wells and 50% of our pipelines, while only reducing our proved reserves base by approximately 10% and our production by about 9%. We have traded mature assets with declining cash flows so we can concentrate on assets with greater potential for growth.

 

In November 2012 we took a major step forward in repositioning BP within Russia, agreeing to sell our 50% shareholding in TNK-BP to Rosneft – the world’s largest publicly traded oil company in terms of oil production and reserves. Our intention is to use part of the cash proceeds from the agreed transaction to offset any dilution to BP’s earnings per share.

 

Upstream

 

We reported RC profit before interest and tax of $22.5 billion, compared with $26.4 billion in 2011. After adjusting for non-operating items and fair value accounting effects, underlying RC profit before interest and taxe was $19.4 billion in 2012, compared with $25.2 billion in 2011 reflecting higher costs, lower production and lower realizations.

 

a   Replacement cost profit for the group is not a recognized GAAP measure. The equivalent measure on an IFRS basis is ‘Profit for the year attributable to BP shareholders’. See footnote b on page 34 and page 98 for further information.

b   Underlying replacement cost profit and fair value accounting effects are not recognized GAAP measures. See pages 34, 37 and 98 for further information.

c   Operating cash flow is shown in our cash flow statement as net cash provided by operating activities.

d   Net debt and gearing are non-GAAP measures. See footnote d on page 21 for further information.

e   See footnote b on page 34.

     
     
     
     
     
 

 

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Our performance – continued

LOGO Downstream

For more on the segment’s financial performance see pages 74-75.

$2.8 billion

Our Downstream segment’s replacement cost profit before interest and tax in 2012.

94.8%

Our Solomon refining availability in 2012.

Our focus on safe, reliable and compliant operations has translated into improvements in both personal and process safety. We have seen a 16% improvement in our days away from work case frequency since the start of 2010, and a 22% improvement in our loss of primary containment incidents over the same period.

We have continued to open up new exploration opportunities. In 2012 we added almost 68,000 square kilometres (approximately 26,250 square miles) of new acreage in Brazil, Canada, Egypt, Namibia and Uruguay; and in the Gulf of Mexico and Ohio in the US. The Ohio acreage covers Utica/Point Pleasant, a promising shale basin. Since 2010 we have accessed around 400,000 square kilometres (approximately 154,500 square miles) of new acreage – an area roughly the size of California. This is more than double the acreage accessed by BP from 2000 to 2009.

We made good progress in the four areas we believe most likely to provide us with higher margin barrels – Angola, Azerbaijan, the North Sea and the Gulf of Mexico.

In Angola, we started production at two projects during 2012 (see page 23). We also continued a programme of exploration and appraisal.

In Azerbaijan, the Shah Deniz consortium – a seven-member group led by BP – selected Nabucco West as the single pipeline option for the potential export of gas to Central Europe, while the Trans-Adriatic Pipeline was selected as the potential route for exports to Italy. Negotiations on transit and marketing terms will

determine which project will be selected as the route to market, ahead of our final investment decision on Shah Deniz. We remain on course to start up the West Chirag production and drilling platform in late 2013.

In the North Sea, 2012 saw high levels of activity. We achieved start-ups, sold a number of non-strategic assets and moved forward with a major programme of long-term investment (see A new chapter in the North Sea, page 24). These actions reflect our strategy of focusing on higher margin projects.

Although uncertainties about the consequences of the Gulf of Mexico oil spill remain, we believe that the Gulf of Mexico remains an important source of medium and long-term growth. The sale of non-core assets in the region should allow us to concentrate on our four operated hubs, together with further exploration activity. In our existing Gulf of Mexico hubs, 80% of our estimated ultimate recovery is still in the ground. We are also continuing our Paleogene appraisal programme of high temperature/high pressure reservoirs in the Lower Tertiary area.

Following an 18-month review that reassessed the technical and economic challenges involved in developing the Liberty field in Alaska safely and profitably, we announced in June that we had suspended our development plans. We are working with regulators to develop alternative plans for the field.

 

 

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LOGO

 

  

 

Downstream

 

RC profit before interest and tax for 2012 was $2.8 billion, compared with $5.5 billion in 2011. After adjusting for non-operating items and fair value accounting effects, underlying RC profit before interest and taxb in 2012 was an all-time record of $6.4 billion compared with $6.0 billion in 2011. This reflected a favourable refining environment, which we were able to capture by virtue of our strong operations, partly offset by weak petrochemicals margins and a significantly lower supply and trading contribution than in 2011. 2012 was also our fourth consecutive year of growth in underlying RC profit before interest and tax. We also continued to make good progress in repositioning Downstream to improve our margin quality and the efficiency of the portfolio.

 

Since the start of 2008, our focus on safe and reliable operations in Downstream has translated into improvements in process safety. We have seen a 55% reduction in loss of primary containment and a 40% reduction in our process safety incident index over the period.

 

Refinery operations were strong this year, with Solomon refining availability of 94.8%. (See refining availability on page 74.) Utilization rates were at 88% despite a relatively high level of turnaround activity in 2012.

 

Our lubricants business continued to deliver robust performance in 2012, despite weak demand.

 

In petrochemicals, a combination of increased supply and lower demand growth in the market narrowed margins for our business in 2012, although we were able to maintain production volumes at around the same levels as 2011.

 

During the year we continued to make good progress in repositioning the Downstream business. In August 2012 we announced an agreement to sell our Carson refinery, in California, and related logistics and marketing assets in the region to Tesoro Corporation for an estimated $2.5 billion. In October 2012 we announced an agreement to sell our Texas City refinery and all associated assets in the south-east US to Marathon Petroleum Corporation. This sale was completed on 1 February 2013 for proceeds of up to $2.4 billion (see page 72).

 

Meanwhile, we made significant progress with the upgrade of our Whiting refinery. On completion, this modernization project is expected to allow us to capture additional margin through the processing of a greater proportion of heavy crudes. During the year the new crude oil unit, coker, upgraded sulphur recovery complex and gasoil hydrotreater all advanced towards their targeted start-up dates in 2013 and the whole project remains on schedule to start up in the second half of 2013.

 

We also made good progress towards our aim of divesting the LPG bulk and bottled business, completing the exit from three of the nine countries we originally identified and

  

announcing the sale of our operations in a further three countries in 2012.

 

In petrochemicals we sold our PTA interest in Malaysia during the year and made progress on major new projects in China and India. We also signed two licensing agreements for our proprietary petrochemicals technology (see page 16 for further details).

 

TNK-BP

 

We began reporting TNK-BP as a separate operating segment with effect from 1 January 2012, reflecting the way in which we were managing our investment.

 

Following the announcement of our proposed transaction with Rosneft on 22 October 2012, BP’s investment in TNK-BP met the criteria to be classified as an asset held for sale. Consequently, BP ceased equity accounting for its share of TNK-BP’s earnings from the date of the announcement.

 

RC profit before interest and taxbc for 2012 was $3.4 billion, compared with $4.1 billion in 2011. After adjusting for non-operating items, underlying RC profit before interest and taxbc for 2012 was $3.1 billion, compared with $4.1 billion in 2011. The most significant factor affecting performance in 2012 compared with 2011 was the absence of more than two months’ income following the cessation of equity accounting.

 

b   See footnote b on page 34.

c   Under equity accounting, BP’s share of TNK-BP’s earnings after interest and tax has been included in the BP group income statement within profit before interest and tax.

 

Outlook

 

The company’s divestment programme is fundamentally reshaping and repositioning our upstream and downstream portfolios. In the Upstream segment, we now have a portfolio that we believe plays to our distinctive strengths and capabilities in exploration, deep water, giant fields and gas value chains. In the Downstream segment, we expect that the measures we are taking to improve efficiency and margin quality will be largely complete by the end of 2013.

 

Looking ahead, we continue to expect that we can deliver around 50% growth in operating cash flow by 2014 compared with 2011.d We intend to use the proceeds of improved cash flow in a number of ways, including increased investment in upstream development. This will focus on four high-margin areas: Angola, Azerbaijan, the Gulf of Mexico and the North Sea.

 

More development, more exploration

The level of planned activity is reflected in the number of rigs we have at work. Across our portfolio, we had 53 rigs in operation at the end of 2012 – 20 onshore and 33 offshore, including 11 in the deep water. We expect to have around 60 rigs in operation in 2014.

 

We intend to increase investment in exploration. Our drilling programme is expected to test 15 new plays between 2012 and 2015.

 

d See footnote c on page 21.

Investing in renewable energy

Since 2005 we have invested $7.6 billion in lower-carbon businesses and are on track to meet our commitment to invest $8 billion by 2015. In biofuels, our three sugar cane mills in Brazil now have a total crush capacity of 7.2 million tonnes and produce fuels for use in transport and power. At the end of 2012 we started up the Vivergo JV bioethanol plant in Hull, UK. We also have research, demonstration and production facilities planned or operating in the US, UK and Brazil. During the year we cancelled plans to build a commercial-scale cellulosic ethanol plant in Florida and refocused our cellulosic strategy on research, development and technology licensing. In wind we have interests in 16 wind farms in the US, which together provide BP with a net generating capacity of 1,558MW.a

 

LOGO Alternative Energy

For more on our activities see Other businesses and corporate page 82.

 

     

 

a   Excludes 32MW of capacity in the Netherlands, which is managed by our Downstream segment.

 

LOGO TNK-BP

For more on the segment’s financial performance see pages 80-81.

 

PSVM is one of the largest subsea developments in the world and was one of BP’s key project start-ups for 2012. It is the second BP-operated development in Angola after Block 18’s Greater Plutonio (below).

 

LOGO

     
     
     
     
 

 

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Our key performance indicators

 

  

We track our performance against key financial and non-financial indicators.

 

  
              

Our board assesses the group’s performance according to a wide range of measures and indicators. The 13 key performance indicators on these pages help us measure performance against our strategic priorities – safety, trust and value – and our business plans. We keep these metrics under periodic review and test their relevance to our strategy regularly. We believe non-financial measures – such as safety and an engaged and diverse workforce – have a useful role to play as leading indicators of future performance.

 

Changes to KPIs

We have changed our employee engagement key performance indicator from a satisfaction measure to one that measures engagement with our strategic priorities of safety, trust and long-term value, as we believe this measure is more closely aligned with our longer-term objectives. Details of our employee engagement are on page 56.

 

Remuneration

To help ensure that the focus of our board and management is aligned with the interests of our shareholders, certain of these measures are reflected in the annual bonus element of executive remuneration.

 

Overall annual bonuses are based on performance relative to measures and targets linked to the annual group plan.

 

LOGO The measures used to determine 2012 and 2013 remuneration are identified with this symbol.

 

LOGO Remuneration

For details of our policy see pages 127-145.

  

LOGO Replacement cost profit (loss) per ordinary sharea (cents)

 

LOGO

 

Replacement cost profit (loss) reflects the replacement cost of supplies. It is arrived at by excluding from profit inventory holding gains and losses and their associated tax effect. Replacement cost profit for the group is a profitability measure used by management. It is a non-GAAP measure. See page 34 for the equivalent measure on an IFRS basis.

 

2012 performance Our results were impacted by the cost of the legal settlement agreed with the US government following the Gulf of Mexico oil spill, as well as by lower results in our operating segments.

  

LOGO Operating cash flow
($ billion)

 

LOGO

 

Operating cash flow is net cash flow provided by operating activities, from the group cash flow statement. Operating activities are the principal revenue-generating activities of the group and other activities that are not investing or financing activities.

 

2012 performance Lower operating cash flow in 2012 reflected the cash flow impact of lower profits, which was partly mitigated by a lower cash outflow relating to the Gulf of Mexico oil spill.

  

LOGO Gearing (net debt
ratio)a
(%)

 

LOGO

 

Gearing enables investors to see how significant net debt is relative to equity from shareholders. Net debt is equal to gross finance debt, plus associated derivatives, less cash and cash equivalents. Net debt and net debt ratio are non-GAAP measures. See Financial statements – Note 35 on page 234 for the nearest equivalent measure on an IFRS basis and for further information.

 

2012 performance We ended the year with gearing within our desired 10-20% range and we will continue to target this range while uncertainties remain.

 

              
  

LOGO Reported recordable injury frequencyb

 

LOGO

 

Reported recordable injury frequency (RIF) measures the number of reported work-related incidents that result in a fatality or injury (apart from minor first aid cases) per 200,000 hours worked.

 

2012 performance Our workforce RIF, which includes employees and contractors combined, was 0.35, compared with 0.36 in 2011 and 0.61 in 2010. The 2010 group RIF was affected by the Gulf Coast response efforts and we continue to focus on improving personal safety.

  

LOGO Loss of primary containmenta

 

LOGO

 

Loss of primary containment is the number of unplanned or uncontrolled releases of material, excluding non-hazardous releases, such as water from a tank, vessel, pipe, railcar or other equipment used for containment or transfer.

 

2012 performance There was a 19% reduction in loss of primary containment compared to 2011, which continues a year on year improvement. Tracking losses of integrity is a way of measuring safety performance and helping drive improvements.

  

Oil spillsb

 

LOGO

 

We report the number of spills of hydrocarbons greater than or equal to one barrel (159 litres, 42 US gallons). We include spills that were contained, as well as those that reached land or water.

 

2012 performance We continue to take measures to strengthen mandatory safety-related standards and processes, including operational risk and integrity management.

        

 

Not all financial KPIs are recognized GAAP measures, but are provided for investors because they are closely tracked by management to evaluate BP’s operating performance and to make financial, strategic and operating decisions.

 

        

 

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LOGO Total shareholder return (%)

  

LOGO Reserves replacement ratio (%)

   Production (mboe/d)    Refining availability (%)
        
LOGO   

 

LOGO

  

 

LOGO

  

 

LOGO

Total shareholder return (TSR) represents the change in value of a BP shareholding over a calendar year, assuming that dividends are re-invested to purchase additional shares at the closing price applicable on the ex-dividend date.

 

2012 performance In 2012 the growth in TSR resulted from increases in the dividend, with the improvement for ordinary shares diminished by exchange rate effects.

  

Proved reserves replacement ratio (also known as the production replacement ratio) is the extent to which production is replaced by proved reserves additions. The ratio is expressed in oil-equivalent terms and includes changes resulting from revisions to previous estimates, improved recovery and extensions, and discoveries. The measure reflects both subsidiaries and equity-accounted entities, but excludes acquisitions and disposals.

 

2012 performance Our reserves replacement ratio was impacted by a lower than usual number of final investment decisions related to major projects, lower than expected reservoir performance, and the curtailing or replanning of certain development activities due to lower natural gas prices and higher costs.

 

  

We report crude oil, natural gas liquids (NGLs) and natural gas produced from subsidiaries and equity-accounted entities. These are converted to barrels of oil equivalent (boe) at 1 barrel of NGL = 1boe and 5,800 standard cubic feet of natural gas = 1boe.

 

2012 performance BP’s total reported production in 2012, including both our Upstream and TNK-BP segments, was 3.6% lower than in 2011, mainly due to the effect of transactions completed in Upstream as part of our $38-billion divestment programme.

  

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.

 

2012 performance Refining availability remained at a high level of 94.8%, reflecting strong operations around our global refining portfolio.

Greenhouse gas emissions

(million tonnes of CO2 equivalent)

   Group priorities engagementc (%)    Diversity and inclusionc (%)     

 

LOGO

  

 

LOGO

   LOGO   

We report greenhouse gas (GHG) emissions on a CO2-equivalent basis, including CO2 and methane. This represents all consolidated entities and BP’s share of equity-accounted entities, except TNK-BP. In 2010 we did not report on GHG emissions associated with the Deepwater Horizon incident or response (see page 52).

 

2012 performance The 2.0Mte decrease in direct GHG emissions in 2012 is primarily explained by operational changes due to temporary reductions in activity in some of our businesses and by the sale of upstream assets as part of our divestment programme.

  

We track how engaged our employees are with our strategic priorities of strengthening safety, earning back trust and building long-term value. The measure is derived from 12 questions about employee perceptions of BP as a company and how it is managed in terms of leadership and standards.

 

2012 performance Aggregate results for these questions showed a 4% improvement on 2011 to 71%.

  

Each year we record the percentage of women and individuals from countries other than the UK and US among BP’s group leaders.

 

2012 performance BP has increased the percentage of female leaders in 2012 and remains focused on building a more sustainable pipeline of diverse talent for the future.

  

a  Not a recognized GAAP measure.

b  This represents reported incidents occurring within BP’s operational HSSE reporting boundary. That boundary includes BP’s own operated facilities and certain other locations or situations.

c  Relates to BP employees.

 

 

Business review: Group overview      29   
BP Annual Report and Form 20-F 2012   


Table of Contents

Our management of risk

 

LOGO Risk management

         For information on BP’s risk management

         system see Risk in BP on page 117.

   Our system of risk management identifies and provides the response to risks of group significance through the establishment of standardized requirements and controls.

LOGO Risk factors

         For the risk factors that could have an adverse

         effect on our business see pages 38-44.

  

 

The following is a summary of how we seek to manage the risks we have identified as having a high priority in 2013. There can be no guarantee that our risk management activities will mitigate or prevent these, or other, risks from occurring.

 

Strategic and commercial risk

We aim to manage risks associated with the general macroeconomic outlook, and changes in prices and markets, by responding to early warnings from our economics and treasury teams and customer-facing businesses. To manage our liquidity, financial capacity and financial exposure risks, we apply our financial framework and we conduct liquidity stress testing and interventions based on scenario planning (see Liquidity and capital resources on pages 90-93).

 

The diverse locations of our operations around the world expose us to a wide range of political developments and consequent changes to the economic and operating environment. For example, our investments in Russia could be adversely affected by heightened political and other social and environment risks. As such, we try to actively manage our relationships in Russia, including with the Russian federal

  

 

government. We are also focused on completing our agreement to sell our interest in TNK-BP to, and purchase interests in, Rosneft.

 

Many of our major projects and operations are conducted through joint ventures or associates and through contracting and sub-contracting arrangements where BP may not have full operational control. We seek to manage the risks arising from such joint venture and contractor relationships actively, and this may include monitoring compliance with applicable standards.

 

In 2011 we set out a 10-point plan to address our near-term strategic priorities. Among other things, the plan aims to target investments and disposals efficiently, renew and reposition our portfolio and deliver our major projects to plan.

 

As part of managing the risks to delivery of the 10-point plan we conduct regular planning and performance-monitoring activity, including the planning of disposals; we focus on the successful delivery of major projects; and we pursue the development of continued technological advances and innovation.

 

LOGO

 

30    Business review: Group overview
   BP Annual Report and Form 20-F 2012


Table of Contents

LOGO

 

Operators descending coker structure, Castellon oil refinery, Castellon, Spain.

  

We seek to manage our reputation through actively managing our relationships with key stakeholders and through clear, consistent and coherent communications. We seek to engage with local communities in order to foster improved relationships.

 

There have been many important developments in 2012 related to the Deepwater Horizon accident, oil spill, and response including the agreement reached with the US government to resolve all federal criminal claims and with the SEC regarding its securities claims. There remains, however, continuing uncertainty regarding the final extent and timing of civil costs and liabilities relating to the incident (with the trial to address many of these issues, which started on 25 February 2013). Further, BP is in ongoing discussions with the EPA to lift the temporary suspension and mandatory debarment. As such, the long-term impact of the incident on our reputation remains uncertain.

 

In addressing these risks we have been working to review and adapt where necessary our current controls and procedures to assure compliance with the requirements contained within the settlements.

 

In addition we have been preparing for trial while remaining open to settlement of the remaining civil claims on reasonable terms. We are committed to rebuilding trust with all our stakeholders and continue to co-operate with all investigators, monitors and regulators. Further, we are clear that we always seek to comply with local regulations and, in some cases, our required practices will exceed regulations if our assessment of the operating risk indicates it would be beneficial to do so.

 

Safety and operational risk

The nature of the group’s operations exposes us to a wide range of significant health, safety and environmental risks such as incidents associated with the drilling of wells, operation of facilities, transportation of hydrocarbons and product quality. In addressing these risks we seek to apply our operating management system (OMS), including group and engineering technical practices, as applicable.

 

We seek to conduct maintenance and equipment testing and to apply product quality control and testing procedures. We also provide our staff with training and competency development. To better manage the risks inherent in drilling wells where we are the operator, we conduct activity through a global wells organization that is accountable for systems and processes for designing, constructing and managing wells.

  

We have also appointed an independent adviser to provide oversight and assurance regarding the company’s implementation of the Bly Report’s recommendation and to report on observed process safety culture.

 

Crisis and continuity management plans, including in respect of oil spill preparedness and response, have been developed to help us to respond effectively to emergencies to minimize impacts and to avoid potentially severe disruption in our business and operations. See Safety on pages 46-50 for information on the recommendations of BP’s internal investigation into the Deepwater Horizon oil spill and the actions we are pursuing to address them.

 

Security threats require continuous monitoring and control as hostile actions against our staff, our facilities (as in the In Amenas joint venture in Algeria) and our digital infrastructure (cyber security) could cause harm to people and could disrupt our operations. We have procedures that are intended to monitor for threats and vulnerabilities and policies to manage our physical and digital security. We also maintain disaster recovery, crisis and business continuity management plans.

 

Compliance and control risk

Ethical misconduct or breaches of applicable laws or regulations could be damaging to our reputation, results of operations and shareholder value and could affect our licence to operate. Central to managing these risks is our code of conduct and our values and behaviours (see page 56), the requirements of which apply to all employees, supported by our various group requirements covering issues such as anti-bribery and corruption, anti-money laundering, competition/anti-trust law compliance and trade sanctions. We seek to monitor for new regulations and legislation and plan our response to them. We also operate a range of compliance training and monitoring programmes for our employees, including OpenTalk, our confidential helpline for employees.

 

In the normal course of business, we are subject to risks around our treasury and trading activities, which could arise from shortcomings or failures in our systems, risk management methodology, internal control processes or employees. In addressing these risks, we have adopted specific operating standards and control processes, including guidelines in relation to trading, and seek to monitor compliance through dedicated compliance organizations. We also seek to maintain a positive and collaborative relationship with regulators and the industry at large.

 

 

Business review: Group overview      31   
BP Annual Report and Form 20-F 2012   


Table of Contents

Cautionary statement

 

This document contains certain forecasts, projections and forward looking statements – that is, statements related to future, not past events – with respect to the financial condition, results of operations and businesses of BP and certain of the plans and objectives of BP with respect to these items. These statements may generally, but not always, be identified by the use of words such as ‘will’, ‘expects’, ‘is expected to’, ‘aims’, ‘should’, ‘may’, ‘objective’, ‘is likely to’, ‘intends’, ‘believes’, ‘anticipates’, ‘plans’, ‘we see’ or similar expressions. In particular, among other statements, (i) certain statements in the Chairman’s letter (pages 8-9), the Group chief executive’s letter (pages 10-11), the Business review (pages 3-99) and Additional disclosures (pages 161-175), including but not limited to statements under the headings ‘Energy outlook’, ‘Our strategy’, ‘Outlook’ and ‘Looking Ahead’, with regard to expectations regarding BP’s agreement with and prospective shareholding in Rosneft, including BP’s expectations regarding its representations on the Rosneft board, the composition of the board of directors, expectations regarding our strategy and strategic priorities including our Upstream and Downstream strategies and our longer term objectives, plans to deliver shareholder value, plans to continue to simplify the organization and portfolio, plans to focus on efficient execution and use of capital, plans to prioritize value rather than seeking to grow production volume for its own sake, prospects for the settlement of outstanding claims related to the Gulf of Mexico oil spill, plans to continue to meet commitments in the Gulf Coast region, plans to implement the recommendations of the Bly Report, plans to appoint two independent monitors and an independent auditor, BP’s intention to prioritize operating cash flow and replacement cost operating profit over barrels of production, plans to work to focus and improve the business, plans to enhance safety and earn back trust, anticipated increases in regulation and taxation of the energy industry and energy users, projections regarding the ability of renewable energy sources to meet total energy demand, expectations regarding investments in proprietary technology, expectations regarding LoSal technology, plans to sell assets and entities, expectations regarding the future level of capital expenditures through the end of the decade, expectations regarding the amount of divestments per year, the expected level of gearing, expectations regarding the ‘10-point plan’, expectations regarding future dividend payments and BP’s plans to continue to pursue a progressive dividend policy, BP’s outlook on global energy trends to 2030 and beyond, BP’s outlook on its ability to meet the growing demand for energy, the intention to make $2-3 billion in disposals per annum on an ongoing basis, BP’s plans to grow operating cash flow and margins by 2014 and the expected quantum of growth, plans for the use of expected improved cash flow, plans to grow free cash flow in Downstream, expectations regarding the level and types of investments and divestments, expectations regarding the Shah Deniz consortium, BP’s plans for involvement in growth markets, the anticipated timing for completion of the disposition of certain BP assets and entities and estimates of the final proceeds therefrom, future production levels including expectations for an increase in high-margin production, the timing and composition of future projects including expected Final Investment Decisions, start-up, construction, commissioning, completion, timing of production, level of production and margins, expectations for drilling and rig activity in the Gulf of Mexico, the timing of measures taken to improve efficiency and margin quality, expectations for the number of rigs in operation, the timing of the delivery of new tankers and rigs, expectations regarding turnover time and the volume of proved undeveloped reserves held for more than five years, the estimated cost of the settlements with the Plaintiffs’ Steering Committee in MDL 2179, the expected amount, source and timing of payments under any settlements related to the Gulf of Mexico oil spill, expectations with regard to the terms of any settlements and BP’s compliance therewith, the anticipated effect of accounting changes on BP’s earnings and cash flow, the timing of the positioning of well cap systems and dispersant application equipment packages, expectations regarding employee training, expectations for an increase in the carbon intensity of operations, expectations regarding environmental research, plans regarding the launch of BP’s human rights policy, expectations regarding regulation and taxation of the energy industry and energy users, BP’s expectations with regard to employee diversity and inclusion, the timing for completion of and prospects for the High-Performance Computing centre in Houston, prospects for debarment of BP entities and the expected duration and consequences of any such debarment, the timing of the commissioning of the LNG train at Tangguh, plans to retain the petrochemicals manufacturing plants at Texas City, expectations regarding future levels of capital investment, plans regarding Project 20K, the expected impact of the expiry of the Abu Dhabi onshore concession, plans regarding environmental restoration of the Gulf Coast, future global refinery capacity and utilization, plans and timing for the completion of the upgrade to and start-up of the Whiting refinery, plans regarding upgrades to the Cherry Point refinery, expectations regarding oil price movements in 2013, expectations regarding the gas market in 2013 and the expected drivers thereof, prospects for the persistence in a large gap between US and European gas prices in 2013, BP’s plans to license back the ARCO brand, prospects for Upstream’s contribution to BP’s plans to increase operating cash flow by around 50% by 2014, expectations regarding the unit operating cash margins of new upstream projects, BP’s strategies with regard to optimizing value across the business, plans regarding BP’s PTA project, the timing of a review of BP’s assets and estimation processes, plans regarding the implementation of enhancements to BP’s risk management system, expectations regarding refining margins, expectations regarding the market for lubricants and petrochemicals, expectations regarding Downstream capital expenditures, expectations regarding the reduction of net debt and the net debt ratio, the expected future level of depreciation, depletion and amortization, the completion of

planned and announced divestments, expectations regarding the announced disposal of TNK-BP to Rosneft and acquisition of an 18.5% shareholding in Rosneft, BP’s intentions to use part of the cash proceeds from the planned disposal of TNK-BP to offset any dilution to BP’s earnings per share, expectations about BP’s future investments and operations in the North Sea, expectations regarding reported production and underlying production in Upstream, expectations regarding Vivergo, the timing of the completion of the Angola LNG plant, the timing for the completion of the Mad Dog spar, and the level of future turnaround activity; (ii) the statements in the Business review (pages 3-99), Corporate governance (pages 101-126), the Directors’ remuneration report (pages 127-145), and Shareholder information (pages 153-159) with regard to the board’s goals and plans stemming from the board’s annual evaluation, expectations regarding the timing of events with investors, plans to continue the ongoing process of embedding OMS and to ensure joint venture partners follow principles similar to those of the OMS, plans and timing for the implementation of the Bly report recommendations, plans regarding investments in research, the timing of projects, programs and initiatives, intentions to continue monitoring process safety at TNK-BP, intentions to implement group-wide practices for oil spill preparedness and response and crisis management, plans to spend $700 million on certain refinery-related safety measures, plans to implement enhanced and standardized technical practices across the refining business, the timing of, cost of, source of payment and provision for future remediation and restoration programmes and environmental operating and capital expenditures, plans to halve US refining capacity, plans and expectations with regard to the remuneration, pensions and other benefits of executive directors, expectations regarding the impact of various regulations upon BP’s business and expectations regarding greater regulation and increased operating costs in the Gulf of Mexico in the future; (iii) the statements in the Business review (pages 90-93) with regard to future dividend and optional scrip dividend payments, future capital expenditures and capital expenditure commitments, taxation, intentions to maintain a significant liquidity buffer, future working capital and cash flows, gearing and the net debt ratio, BP’s intention to maintain a strong cash position, expectations regarding taxes due upon repatriation of cash into the UK, expectations regarding total capital expenditure, expected payments under contractual and commercial commitments and purchase obligations, and including under ‘Liquidity and capital resources – Trend information’, with regard to production in Upstream, the expected financial impact of refinery turnarounds, expectations regarding petrochemicals margins and the average quarterly charge for Other businesses and corporate, estimated levels of capital expenditure in 2013 and to the end of the decade, estimated amount of divestments, intentions regarding net debt ratio and the expected level of depreciation, depletion and amortization, and the expected level of underlying effective tax rate; and (iv) certain statements in Additional disclosures (pages 161-175) regarding the anticipated timing of trial proceedings, court decisions and potential investigations and civil or criminal actions by US state and/or local governments; are all forward looking in nature.

By their nature, forward-looking statements involve risk and uncertainty because they relate to events and depend on circumstances that will or may occur in the future and are outside the control of BP. Actual results may differ materially from those expressed in such statements, depending on a variety of factors, including the specific factors identified in the discussions accompanying such forward-looking statements; the receipt of relevant third party and/or government approvals; the timing of bringing new fields onstream; the timing of certain disposals; future levels of industry product supply, demand and pricing, including supply growth in North America; 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 actions of prosecutors, regulatory authorities and courts; the actions of the Claims Administrator appointed under the Economic and Property Damages Settlement; the actions of all parties to the Gulf of Mexico oil spill-related litigation at various phases of the litigation; exchange rate fluctuations; development and use of new technology; the success or otherwise of partnering; the actions of competitors; the actions of contractors; natural disasters and adverse weather conditions; changes in public expectations and other changes to business conditions; wars and acts of terrorism or sabotage; and other factors discussed elsewhere in this report including under ‘Risk factors’ (pages 38-44). In addition to factors set forth elsewhere in this report, those set out above are important factors, although not exhaustive, that may cause actual results and developments to differ materially from those expressed or implied by these forward-looking statements.

Statements regarding competitive position

Statements referring to BP’s competitive position are based on the company’s belief and, in some cases, rely on a range of sources, including investment analysts’ reports, independent market studies and BP’s internal assessments of market share based on publicly available information about the financial results and performance of market participants.

 

 

32    Business review: Group overview
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Table of Contents

 

 

   

Business review

BP in more
depth

 

Detailed reporting on activity        
across the group during a
busy year.

    34     

Financial review

 

 

   
      38     

Risk factors

 

 

   
      46     

Safety

 

 

   
      51     

Environmental and social responsibility

 

 

   
      55     

Employees

 

 

   
      57     

Technology

 

 

   
      59     

Gulf of Mexico oil spill

 

 

   
      63     

Upstream

 

 

   
      72     

Downstream

 

 

   
      80     

TNK-BP

 

 

   
      82     

Other businesses and corporate

 

 

   
      84     

Oil and gas disclosures for the group

 

 

   
      90     

Liquidity and capital resources

 

 

   
      94     

Regulation of the group’s business

 

 

   
      98      Certain definitions    
                       
                       
                       
                    
                       
                       
                       
                       
                       
                       
                       
                       
                       
                       
                       
                       
                       
                       
                       
     

Business review: BP in more depth      33

BP Annual Report and Form 20-F 2012          

   

 


Table of Contents

Financial review

Selected financial informationa

 

                                          $ million   
          2012        2011        2010        2009        2008   

Income statement data

                                           

Sales and other operating revenues

        375,580        375,517        297,107        239,272        361,143   

Underlying replacement cost profit (loss) before interest and taxb

             

By business

             

Upstream

        19,419        25,225        25,073        19,668        37,318   

Downstream

        6,447        6,013        4,883        3,607        3,318   

TNK-BPc

        3,127        4,134        2,617        1,948        2,262   

Other businesses and corporate

        (1,997     (1,656     (1,316     (1,833     (590

Consolidation adjustment – unrealized profit in inventory

        (576     (113     447        (717     466   
          26,420        33,603        31,704        22,673        42,774   

Net favourable (unfavourable) impact of non-operating items and fair value accounting effectsb

             

By business

             

Upstream

        3,055        1,141        3,196        3,184        (1,272

Downstream

        (3,601     (539     672        (2,864     858   

TNK-BP

        246                               

Other businesses and corporate

        (798     (822     (200     (489     (633

Gulf of Mexico oil spill responsed

        (4,995     3,800        (40,858              
          (6,093     3,580        (37,190     (169     (1,047

Replacement cost profit (loss) before interest and taxb

             

By business

             

Upstream

        22,474        26,366        28,269        22,852        36,046   

Downstream

        2,846        5,474        5,555        743        4,176   

TNK-BPc

        3,373        4,134        2,617        1,948        2,262   

Other businesses and corporate

        (2,795     (2,478     (1,516     (2,322     (1,223

Gulf of Mexico oil spill responsed

        (4,995     3,800        (40,858              

Consolidation adjustment – unrealized profit in inventory

        (576     (113     447        (717     466   

Replacement cost profit (loss) before interest and taxationb

        20,327        37,183        (5,486     22,504        41,727   

Inventory holding gains (losses)e

        (594     2,634        1,784        3,922        (6,488

Profit (loss) before interest and taxation

        19,733        39,817        (3,702     26,426        35,239   

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

        (924     (983     (1,123     (1,302     (956

Taxation

        (6,993     (12,737     1,501        (8,365     (12,617

Profit (loss) for the year

        11,816        26,097        (3,324     16,759        21,666   

Profit (loss) for the year attributable to BP shareholders

        11,582        25,700        (3,719     16,578        21,157   

Inventory holding (gains) lossese, net of tax

        411        (1,800     (1,195     (2,623     4,436   

Replacement cost profit (loss) for the year attributable to BP shareholdersb

        11,993        23,900        (4,914     13,955        25,593   

Non-operating items and fair value accounting effectsb, net of tax

        (5,645     2,242        (25,436     (622     (650

Underlying replacement cost profit (loss) for the year attributable to BP shareholdersb

        17,638        21,658        20,522        14,577        26,243   

 

a  This information, insofar as it relates to 2012, has been extracted or derived from the audited consolidated financial statements of the BP group presented on pages 177-262. Note 1 to the financial statements includes details on the basis of preparation of these financial statements. The selected information should be read in conjunction with the audited financial statements and related notes elsewhere herein.
b  Replacement cost (RC) profit or loss reflects the replacement cost of supplies and is arrived at by excluding inventory holding gains and losses from profit or loss. RC profit or loss is the measure of profit or loss for each operating segment that is required to be disclosed under International Financial Reporting Standards (IFRS). RC profit or loss for the group is not a recognized GAAP measure. Underlying RC profit or loss is RC profit or loss after adjusting for non-operating items and fair value accounting effects. Underlying RC profit or loss and fair value accounting effects are not recognized GAAP measures. For further information on RC profit or loss, underlying RC profit or loss, non-operating items and fair value accounting effects, see page 37 and Certain definitions on pages 98-99.
c  BP ceased equity accounting for its share of TNK-BP earnings from 22 October 2012. See TNK-BP on pages 80-81 for further information.
d  Under IFRS these costs are presented as a reconciling item between the sum of the results of the reportable segments and the group results.
e  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 year 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. BP’s management believes it is helpful to disclose this information. An analysis of inventory holding gains and losses by business is shown in Financial statements – Note 6 on page 203 and further information on inventory holding gains and losses is provided on page 98.

 

 

34    Business review: BP in more depth
   BP Annual Report and Form 20-F 2012


Table of Contents

Selected financial information – continued

 

                            $ million except per share amounts   
          2012         2011         2010        2009         2008   

Per ordinary share – cents

                

Profit (loss) for the year attributable to BP shareholders

                

Basic

        60.86         135.93         (19.81     88.49         112.59   

Diluted

        60.45         134.29         (19.81     87.54         111.56   

Replacement cost profit (loss) for the year attributable to BP shareholders

        63.02         126.41         (26.17     74.49         136.20   

Underlying replacement cost profit for the year attributable to BP shareholders

        92.68         114.55         109.23        77.81         139.66   

Dividends paid per share – cents

        33.00         28.00         14.00        56.00         55.05   

 – pence

        20.852         17.404         8.679        36.417         29.387   

Capital expenditure and acquisitionsa

        24,342         31,518         23,016        20,309         30,700   

Acquisitions and asset exchanges

        200         11,283         3,406        308         2,514   

Organic capital expenditureb

        23,088         19,139         18,218        20,001         21,697   

Balance sheet data (at 31 December)

                                              

Total assets

        300,193         293,068         272,262        235,968         228,238   

Net assets

        119,620         112,482         95,891        102,113         92,109   

Share capital

        5,261         5,224         5,183        5,179         5,176   

BP shareholders’ equity

        118,414         111,465         94,987        101,613         91,303   

Finance debt due after more than one year

        38,767         35,169         30,710        25,518         17,464   

Net debt to net debt plus equityc

        18.7%         20.5%         21.2%        20.4%         21.4%   

Ordinary share datad

                                           Shares million   

Average number outstanding of 25 cent ordinary shares (undiluted)

        19,028         18,905         18,786        18,732         18,790   

Average number outstanding of 25 cent ordinary shares (diluted)

        19,158         19,136         18,998        18,936         18,963   

 

a  Includes asset exchanges. All capital expenditure and acquisitions during the past five years have been financed from cash flow from operations, disposal proceeds and external financing.
b  Organic capital expenditure excludes acquisitions and asset exchanges, and: in 2012, $1,054 million associated with deepening our US natural gas and North Sea asset bases; in 2011, $1,096 million associated with deepening our US natural gas asset bases; in 2010, $900 million relating to the formation of a partnership with Value Creation Inc. to develop the Terre de Grace oil sands acreage and $492 million for the purchase of additional interests in the Valhall and Hod fields in the North Sea; and, in 2008, $3,667 million in respect of our purchase of all Chesapeake Energy Corporation’s interest in the Arkoma Basin Woodford Shale assets and the purchase of a 25% interest in Chesapeake’s Fayetteville Shale assets and $2,822 million relating to the formation of an integrated North American oil sands business with Husky Energy Inc.
c  Net debt and the ratio of net debt to net debt plus equity are not recognized GAAP measures. We believe that these measures provide useful information to investors. Further information on net debt is given in Financial statements – Note 35 on page 234.
d  The number of ordinary shares shown has been used to calculate per share amounts.

 

Profit or loss for the year

Profit attributable to BP shareholders for the year ended 31 December 2012 was $11,582 million. After adjusting for $411 million in respect of inventory holding losses and their associated tax effect, replacement cost (RC) profit attributable to BP shareholders in 2012 was $11,993 million. After further adjusting for a net charge of $5,300 million for non-operating items and adverse fair value accounting effects (relative to management’s measure of performance) of $345 million, both net of tax, underlying RC profit attributable to BP shareholders in 2012 was $17,638 million. RC profit or loss for the group, underlying RC profit and fair value accounting effects are non-GAAP measures, see footnote b on page 34 for further information.

Non-operating items in 2012, on a pre-tax basis, mainly related to further charges associated with the Gulf of Mexico oil spill (primarily the cost of the agreement with the US government to settle all federal criminal charges) and impairment charges, partially offset by gains on disposals. More information on non-operating items, and fair value accounting effects, can be found on page 37. See Gulf of Mexico oil spill on pages 59-62 and Financial statements – Note 2 on page 194 for further information on the impact of the Gulf of Mexico oil spill on BP’s financial results.

For the year ended 31 December 2011, profit attributable to BP shareholders was $25,700 million, replacement cost profit attributable to BP shareholders in 2011 was $23,900 million and underlying RC profit attributable to BP shareholders in 2011 was $21,658 million. Inventory holding gains and their associated tax effect were $1,800 million in 2011. There was a net post-tax credit for non-operating items of $2,195 million, which included a $3.7 billion pre-tax credit relating to the Gulf of Mexico oil spill, and fair value accounting effects had a favourable impact, net of tax, of $47 million.

Compared with 2011, underlying replacement cost profit in 2012 was impacted by higher upstream costs (driven primarily by sector inflation), lower production and realizations, the absence of equity-accounted earnings from TNK-BP as of 22 October 2012 (when our investment was

reclassified as an asset held for sale, as required under IFRS), weak petrochemicals margins and a significant reduction in the supply and trading contribution. These factors were partially offset by an improved refining environment, which we were able to capture as a result of strong refinery operations.

For the year ended 31 December 2010, there was a loss attributable to BP shareholders of $3,719 million, which included inventory holding gains, net of tax, of $1,195 million leading to a replacement cost loss attributable to BP shareholders of $4,914 million. After adjusting for a net charge for non-operating items of $25,449 million and net favourable fair value accounting effects of $13 million, both net of tax, underlying profit attributable to BP shareholders in 2010 was $20,522 million. Non-operating items in 2010 included a pre-tax charge relating to the Gulf of Mexico oil spill of $40.9 billion.

Compared with 2010, in 2011 there were higher realizations, higher earnings from equity-accounted entities, a higher refining margin environment and a stronger supply and trading contribution, partly offset by lower production volumes, rig standby costs in the Gulf of Mexico, higher costs related to turnarounds, higher exploration write-offs, and negative impacts of increased relative sweet crude prices in Europe and Australia, primarily caused by the loss of Libya production and the weather-related power outages in the US.

See Upstream on page 63, Downstream on page 72, TNK-BP on page 80 and Other businesses and corporate on page 82 for further information on segment results.

 
 

 

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

Finance costs comprise interest payable less amounts capitalized, and interest accretion on provisions and long-term other payables. Finance costs in 2012 were $1,125 million compared with $1,246 million in 2011 and $1,170 million in 2010.

Net finance income relating to pensions and other post-retirement benefits in 2012 was $201 million compared with $263 million in 2011 and $47 million in 2010. In 2012, compared with 2011, the reduced net income largely reflected lower expected returns on pension assets following reductions in the yield assumptions, mainly for bonds, being applied in 2012 compared to 2011.

In 2013, when we adopt the revised version of IAS 19 ‘Employee Benefits’, we will be required to apply the same expected rate of return on plan assets as we use to discount our pension liabilities. We expect this accounting change to adversely impact our annual earnings by approximately $1 billion on a pre-tax basis, with no impact on cash flow.

Taxation

The charge for corporate taxes in 2012 was $6,993 million, compared with a charge of $12,737 million in 2011 and a credit of $1,501 million in 2010. The effective tax rate was 37% in 2012, 33% in 2011 and 31% in 2010. The group earns income in many countries and, on average, pays taxes at rates higher than the UK statutory rate of 24%. The increase in the effective tax rate in 2012 compared with 2011 primarily reflects the impact of the provision for the settlement with the US government, which is not tax deductible. The increase in the effective tax rate in 2011 compared with 2010 primarily reflected a higher level of income earned in jurisdictions with a higher tax rate.

Acquisitions and disposals

In 2012 there were no significant acquisitions.

Total disposal proceeds received during 2012 were $11.4 billion.

In Upstream, total disposal proceeds of $10.7 billion included $5.55 billion for the disposal of BP’s interests in the Marlin hub, Horn Mountain, Holstein, Ram Powell and Diana Hoover fields in the Gulf of Mexico. Proceeds of $1.5 billion were received for the sale of the Canadian natural gas liquids (NGL) business to Plains Midstream Canada ULC, a wholly owned subsidiary of Plains All American Pipeline, L.P. and $1.2 billion for the Hugoton basin assets (including the Jayhawk NGL processing plant and associated producing gas fields in Kansas) to an affiliate of LINN Energy, LLC. The sale of BP’s interest in the Jonah and Pinedale upstream operations in Wyoming, also to LINN Energy, LLC generated disposal proceeds of $1.025 billion.

In Downstream, disposal proceeds totalled $0.5 billion, including the sale of our interests in purified terephthalic acid production in Malaysia.

There were no significant disposals during 2012 in Other businesses and corporate.

Prior years’ transactions

In 2011, BP acquired from Reliance Industries Limited (Reliance) a 30% interest in each of 21 oil and gas production-sharing agreements operated by Reliance in India for $7.0 billion. We completed the purchase, for $3.6 billion, of 10 exploration and production blocks in Brazil, which was the final part of a $7-billion transaction with Devon Energy that had been

announced in March 2010, and our Alternative Energy business acquired the Brazilian sugar and ethanol producer Companhia Nacional de Açúcar e Álcool (CNAA) for $0.7 billion. See Financial statements – Note 3 on page 198 for further details of business combinations.

Total disposal proceeds received during 2011, after the repayment of the disposal deposit relating to Pan American Energy LLC (PAE) (see below), were $2.7 billion.

In Upstream, disposal proceeds included $0.6 billion from the sale of our upstream assets in Pakistan to United Energy Pakistan Limited, a subsidiary of United Energy Group (UEG); $0.5 billion from the sale of half of the 3.29% interest in the Azeri-Chirag-Gunashli (ACG) development in the Caspian Sea, which we had acquired from Devon Energy in 2010, to Azerbaijan (ACG) Limited; and $0.5 billion from the sale of our interests in the Wytch Farm, Wareham, Beacon and Kimmeridge fields to Perenco UK Ltd. In addition, further payments of $1.1 billion were received on completion of the sales of our upstream and certain midstream interests in Venezuela and Vietnam and our oil and gas exploration, production and transportation business in Colombia, for which we had received $2.3 billion in 2010 as deposits. In November 2011, BP received from Bridas Corporation (Bridas) a notice of termination of the agreement for their purchase of BP’s 60% interest in PAE. As a result, the deposit of $3.5 billion relating to the sale of PAE, which had been received by BP in 2010, was repaid to Bridas.

In Downstream we made disposals totalling $0.7 billion, which included completion of the divestment of non-strategic pipelines and terminals in the US, announced in 2009, for $0.3 billion and the disposal of our fuels marketing businesses in several African countries for $0.2 billion.

Within Other businesses and corporate, we completed the sale of BP’s wholly-owned subsidiary, ARCO Aluminum Inc., to a consortium of Japanese companies for $0.7 billion.

In 2010, BP acquired a major portfolio of deepwater exploration acreage and prospects in the US Gulf of Mexico and an additional interest in the BP-operated ACG developments in the Caspian Sea, Azerbaijan, for $2.9 billion, as part of a $7-billion transaction with Devon Energy. Total disposal proceeds during 2010 were $17 billion, which included $7 billion from the sale of US Permian Basin, Western Canadian gas assets, and Western Desert exploration concessions in Egypt to Apache Corporation (and an existing partner that exercised pre-emption rights), and $6.2 billion of deposits received in advance of disposal transactions expected to complete in 2011. Of these deposits received, $3.5 billion was for the sale of our interest in PAE to Bridas; however, this was subsequently repaid to Bridas at the end of 2011 following the termination of the sale agreement.

The deposits received also included $1 billion for the sale of our upstream and midstream interests in Venezuela and Vietnam to TNK-BP, and $1.3 billion for the sale of our oil and gas exploration, production and transportation business in Colombia to a consortium of Ecopetrol and Talisman.

In Downstream we made disposals totalling $1.8 billion in 2010, which included our French retail fuels and convenience business to Delek Europe; the fuels marketing business in Botswana to Puma Energy; certain non-strategic pipelines and terminals in the US, our interests in ethylene and polyethylene production in Malaysia to Petronas; and our interest in a futures exchange.

 

 

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Non-operating items

Non-operating items are charges and credits arising in consolidated entities and in TNK-BP that are included in the financial statements and that BP discloses separately because it considers such disclosures to be meaningful and relevant to investors. They are items that management considers not to be part of underlying business operations and are disclosed in order to enable investors better to understand and evaluate the group’s reported financial performance. An analysis of non-operating items is shown in the table below.

 

                       $ million   
       2012        2011        2010   
Upstream       

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

     3,638        2,131        3,812   

Environmental and other provisions

     (48     (27     (54

Restructuring, integration and rationalization costs

                   (137

Fair value gain (loss) on embedded derivatives

     347        191        (309

Othera

     (748     (1,165     (113
       3,189        1,130        3,199   
Downstream       

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

     (2,935     (334     877   

Environmental and other provisions

     (172     (219     (98

Restructuring, integration and rationalization costs

     (32     (4     (97

Fair value gain (loss) on embedded derivatives

                     

Other

     (35     (45     (52
       (3,174     (602     630   
TNK-BPb       

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

     (55              

Environmental and other provisions

     (83              

Restructuring, integration and rationalization costs

                     

Fair value gain (loss) on embedded derivatives

                     

Other

     384                 
       246                 
Other businesses and corporate       

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

     (282     275        5   

Environmental and other provisions

     (261     (220     (103

Restructuring, integration and rationalization costs

     (15     (39     (81

Fair value gain (loss) on embedded derivativesc

            (123       

Otherd

     (240     (715     (21
       (798     (822     (200

Gulf of Mexico oil spill response

     (4,995     3,800        (40,858

Total before interest and taxation

     (5,532     3,506        (37,229

Finance costse

     (19     (58     (77

Taxation credit (charge)f

     251        (1,253     11,857   

Total after taxation

     (5,300     2,195        (25,449

 

a  2012 included a charge of $370 million relating to onerous gas marketing and trading contracts and $308 million relating to exploration expense associated with our US natural gas assets (2011 $395 million). 2011 included a charge of $700 million associated with the termination of the agreement to sell our 60% interest in Pan American Energy LLC to Bridas Corporation.
b  Disclosure of non-operating items for TNK-BP began in 2012. Non-operating items for TNK-BP were reported in the group income statement within earnings from associates until 22 October 2012 – after interest and tax. See TNK-BP on pages 80-81 for more information on non-operating items.
c  Relates to an embedded derivative arising from a financing arrangement.
d  2012 included charges of $244 million relating to our exit from the solar business (2011 $717 million).
e  Finance costs relate to the Gulf of Mexico oil spill. See Financial statements – Note 2 on page 194 for further details.
f  For the Gulf of Mexico oil spill and certain impairment losses and disposal gains in 2012, tax is based on US statutory tax rates, except for non-deductible items. For dividends received from TNK-BP in December 2012, there is no tax arising. For other items reported by consolidated subsidiaries, tax is calculated using the group’s discrete quarterly effective tax rate (adjusted for the items noted above, equity-accounted earnings from 2012 onwards and the deferred tax adjustments relating to changes to the taxation of UK oil and gas production (2011 $683 million and 2012 $256 million)). Non-operating items arising within the equity-accounted earnings of TNK-BP are reported net of tax.

Non-GAAP information on fair value accounting effects

The impacts of fair value accounting effects, relative to management’s internal measure of performance, and a reconciliation to GAAP information is also set out below. Further information on fair value accounting effects is provided on page 98.

 

                       $ million   
       2012        2011        2010   
Upstream       

Unrecognized gains (losses) brought forward from previous period

     (538     (527     (530

Unrecognized (gains) losses carried forward

     404        538        527   

Favourable (unfavourable) impact relative to management’s measure of performance

     (134     11        (3
Downstreama       

Unrecognized gains (losses) brought forward from previous period

     74        137        179   

Unrecognized (gains) losses carried forward

     (501     (74     (137

Favourable (unfavourable) impact relative to management’s measure of performance

     (427     63        42   
       (561            74               39   

Taxation credit (charge)b

          216        (27     (26
       (345     47        13   

By region

      
Upstream       

US

     (67     15        141   

Non-US

     (67     (4     (144
       (134     11        (3
Downstreama       

US

     (441            19   

Non-US

     14        63        23   
       (427     63        42   

 

a  Fair value accounting effects arise solely in the fuels business.
b  Tax is calculated using the group’s discrete quarterly effective tax rate (adjusted for the Gulf of Mexico oil spill, certain impairment losses and disposal gains in 2012, equity-accounted earnings from 2012 onwards and the deferred tax adjustments relating to changes to the taxation of UK oil and gas production (2011 $683 million, 2012 $256 million)).

Reconciliation of non-GAAP information

                        $ million   
       2012        2011         2010   
Upstream        

Replacement cost profit before interest and tax adjusted for fair value accounting effects

     22,608        26,355         28,272   

Impact of fair value accounting effects

     (134     11         (3

Replacement cost profit before interest and tax

     22,474        26,366         28,269   
Downstream        

Replacement cost profit before interest and tax adjusted for fair value accounting effects

     3,273        5,411         5,513   

Impact of fair value accounting effects

     (427     63         42   

Replacement cost profit before interest and tax

     2,846        5,474         5,555   
Total group        

Profit (loss) before interest and tax adjusted for fair value accounting effects

     20,294        39,743         (3,741

Impact of fair value accounting effects

     (561     74         39   

Profit (loss) before interest and tax

     19,733        39,817         (3,702

 

 

 

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Risk factors

We urge you to consider carefully the risks described below. The potential impact of the occurrence, or reoccurrence, of any of the risks described below could have a 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 and commercial; compliance and control; and safety and operational. In addition, we have also set out one further risk for your attention – those resulting from the 2010 Gulf of Mexico oil spill (the Incident).

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

While significant charges have been recognized in the income statement since the Incident occurred in 2010, there is significant uncertainty regarding the extent and timing of the remaining costs and liabilities relating to the Incident, the potential changes in applicable regulations and the operating environment that may result from the Incident, the impact of the Incident on our reputation and the resulting possible impact on our licence to operate including our ability to access new opportunities. The amount of claims that become payable by BP, the amount of fines ultimately levied on BP (including any potential determination of BP’s negligence or gross negligence), the outcome of litigation, the terms of any further settlements including the amount and timing of any payments thereunder, and any costs arising from any longer-term environmental consequences of the Incident, will also impact upon the ultimate cost for BP. Although the provisions recognized represent the current best estimates of expenditures required to settle certain present obligations that can be reasonably estimated at the end of the reporting period, there are future expenditures for which it is not possible to measure our obligations reliably and the total amounts paid by BP in relation to all obligations relating to the Incident are subject to significant uncertainty. These uncertainties are likely to continue for a significant period, increase the risks to which the group is exposed and may cause our costs to increase. 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. 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.

Strategic and commercial 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 could impact our future hydrocarbon production.

Moreover, the Incident 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, regulatory 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, following the Incident, could increase this risk.

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

Oil, gas and product prices and margins can be very volatile, and are subject to international supply and demand. Political developments (including conflict situations) 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 cash flow, profit and 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.

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. 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.

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. In particular, ongoing instability in or a collapse of the eurozone could trigger a new wave of financial crises and push the world back into recession, leading to lower demand and lower oil and gas prices.

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, could affect the recoverability of our assets and could cause us to incur additional costs. In particular, our investments in the US, Russia, the Middle East region, North Africa, Bolivia, Argentina, Angola, Azerbaijan and other countries could be adversely affected by heightened political and economic environment risks. See pages 6-7 for information on the locations of our major areas of operation and activities.

 

 

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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 or that we have not satisfactorily addressed all relevant stakeholder concerns in respect of our operations, our reputation and shareholder value could be damaged and development opportunities may be precluded.

Competition – BP’s group strategy depends upon continuous innovation and efficiency 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 the terms of access to new opportunities, licence costs and 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 require, if our innovation lagged the industry, or if we fail to adequately protect our company brands and trade marks. Our competitive position in comparison to our peers could be adversely affected if competitors offer superior terms for access rights or licences, if we fail to control our operating costs or manage our margins, or if we fail to sustain, develop and operate efficiently a high quality portfolio of assets.

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.

Rosneft transaction – BP’s failure to complete the agreed transaction with Rosneft, or any future erosion of our relationship with Rosneft, could adversely impact our business, the level of our reserves and our reputation.

On 22 November 2012, BP announced that it had signed definitive and binding agreements in respect of the sale of BP’s 50% interest in TNK-BP to Rosneft and BP’s investment in Rosneft (the Rosneft transaction). See TNK-BP on pages 80-81. Completion of the Rosneft transaction is subject to certain customary closing conditions, including governmental, regulatory and anti-trust approvals. Failure by BP to complete the Rosneft

transaction as contemplated due to the failure to receive required approvals or otherwise could negatively impact our reputation and result in a loss of stakeholder confidence in BP’s ability to meet its identified strategic objectives in Russia. In addition, to the extent we fail to maintain a good commercial relationship with Rosneft in the future, or to the extent that as a minority shareholder in Rosneft we are unable in the future to exercise influence over our investment in Rosneft or other growth opportunities in Russia, our business and strategic objectives in Russia and our ability to recognize our share of Rosneft’s reserves as contemplated may be adversely impacted.

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/or subsequent execution could lead to loss of value and higher capital expenditure.

Reserves progression – 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 due to commercial, technical or regulatory reasons or otherwise, we will be unable to sustain long-term replacement of reserves.

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 and/or any other major programme designed to enhance shareholder value, including maintenance turnaround programmes, 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 on page 40.

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, reputational damage, breaches of regulations, litigation, legal liabilities and reparation costs.

The reliability and security of our digital infrastructure are critical to maintaining the availability of our business applications, including the reliable operation of technology in our various business operations and the collection and processing of financial and operational data, as well as the confidentiality of certain third-party information. A breach of our digital security, either due to intentional actions or due to negligence, could cause serious damage to business operations and, in some circumstances, could result in the loss of data or sensitive information, injury to people, damage to assets, harm to the environment, reputational damage, breaches of regulations, litigation, legal liabilities and reparation costs.

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 our 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.

 

 

 

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Table of Contents

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

Successful recruitment of new staff, employee training, development and continuing enhancement 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. The group relies on recruiting and retaining high-quality employees to execute its strategic plans and to operate its business. The reputational damage suffered by the group as a result of the Incident and any consequent adverse impact on our business could affect employee recruitment and retention.

In addition, significant board and management focus continues to be required in responding to matters related to the Incident. Although BP set up the Gulf Coast Restoration Organization to manage the group’s long-term response, other key management personnel will need to continue to devote substantial attention to addressing the associated consequences for the group, which may negatively impact our staff’s capability to address and respond to other operational matters affecting the group but unrelated to the Incident.

Liquidity, financial capacity and financial, including credit, 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 (including a failure to understand and respond to potential liabilities) 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. Trade and other receivables, including overdue receivables, may not be recovered whether an impairment provision has been recognized or not. 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, to maintain our long-term investment programme and to meet our obligations, 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. The group’s financial framework may not be sufficient to respond to a substantial and unexpected cash call or funding request, and external events may materially impact the effectiveness of the group’s financial framework. In addition, operational challenges could impact the availability of the group’s assets, which could adversely affect the group’s operating cash flows.

BP’s potential liabilities resulting from pending and future claims, lawsuits, settlements 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 financial performance and liquidity. Further potential liabilities may continue to have a material adverse effect on the group’s results of operations and financial condition. See Financial statements – Note 43 on page 253 and Legal proceedings on pages 162-171. 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. In addition, a high proportion of our major project development costs are denominated in local currencies, which may be subject to volatile fluctuations against the US dollar. Fluctuations in exchange rates can therefore give rise to foreign exchange exposures, with a consequent impact on underlying costs and revenues. See Prices and markets on page 38.

See Financial statements – Note 26 on page 220 for more information on financial instruments and financial risk factors.

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.

Compliance and control risks

Our settlement with the US Department of Justice and the SEC in respect of federal criminal charges and US securities law violations related to the Gulf of Mexico oil spill may expose us to further penalties, liabilities and private litigation, and may impact our operations and adversely affect our ability to quickly and efficiently access US capital markets.

On 15 November 2012, BP reached an agreement with the US government to resolve all federal criminal and securities claims arising out of the Incident and comprising settlements with the US Department of Justice (DoJ) and the SEC. On 29 January 2013, the US District Court for the Eastern District of Louisiana accepted BP’s pleas regarding the federal criminal charges, and sentenced BP in accordance with the criminal plea agreement. BP pleaded guilty to 11 felony counts of Misconduct or Neglect of Ships Officers relating to the loss of 11 lives; one misdemeanour count under the Clean Water Act; one misdemeanour count under the Migratory Bird Treaty Act; and one felony count of obstruction of Congress. Pursuant to that sentence, BP will pay $4 billion, including $1.256 billion in criminal fines, in instalments over a period of five years. The court also ordered, as previously agreed with the US government, that BP serve a term of five years’ probation. Pursuant to the terms of the plea agreement, the court also ordered certain equitable relief, including additional actions, enforceable by the court, to further enhance the safety of drilling operations in the Gulf of Mexico. In addition, BP will undertake several initiatives with academia and regulators to develop new technologies related to deepwater drilling safety. The resolution also provides for the appointment of two monitors, both with terms of four years. A process safety monitor will review, evaluate, and provide recommendations for the improvement of BP’s process safety and risk management procedures concerning deepwater drilling in the Gulf of Mexico. An ethics monitor will review and provide recommendations for the improvement of BP’s code of conduct and its implementation and enforcement. BP has also agreed to hire an independent third-party auditor who will review and report to the probation officer, the DoJ, and BP regarding BP’s implementation of key terms of the proposed settlement, including procedures and systems related to safety and environmental management, operational oversight, and oil spill response training and drills. Under the plea agreement, BP has also agreed to co-operate in ongoing criminal actions and investigations, including prosecutions of four former employees who have been separately charged.

Also on 15 November 2012, BP reached a settlement with the SEC to resolve the SEC’s Deepwater Horizon-related claims against the company under Sections 10(b) and 13(a) of the Securities Exchange Act of 1934 and the associated rules. Under the SEC settlement, BP has agreed to a civil penalty of $525 million, payable in three instalments over a period of three years, and has consented to the entry of an injunction prohibiting it from violating certain US securities laws and regulations. The SEC settlement was approved by the US District Court for the Eastern District of Louisiana on 10 December 2012. See Legal proceedings on pages 162-171.

On 28 November 2012, the US Environmental Protection Agency (EPA) notified BP that it had temporarily suspended BP p.l.c., BP Exploration & Production Inc. (BPXP) and a number of other BP subsidiaries from participating in new federal contracts. As a result of the temporary suspension, the BP entities listed in the EPA notice are ineligible to receive any US government contracts either through the award of a new contract, or the extension of the term or renewal of an expiring contract. The suspension

 

 

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does not affect existing contracts the company has with the US government, including those relating to current and ongoing drilling and production operations in the Gulf of Mexico.

The charges to which BPXP pleaded guilty included one misdemeanour count under the Clean Water Act which, by operation of law following the court’s acceptance of BP’s plea, triggers a statutory debarment, also referred to as mandatory debarment, of the BPXP facility where the Clean Water Act violation occurred.

On 1 February 2013, the EPA issued a notice that BPXP was mandatorily debarred at its Houston headquarters. Mandatory debarment prevents a company from entering into new contracts or new leases with the US government that would be performed at the facility where the Clean Water Act violation occurred. A mandatory debarment does not affect any existing contracts or leases a company has with the US government and will remain in place until such time as the debarment is lifted through an agreement with the EPA.

With respect to the entities named in the temporary suspension, the temporary suspension may be maintained or the EPA may elect to issue a notice of proposed discretionary debarment to some or all of the named entities. Like suspension, a discretionary debarment would preclude BP entities listed in the notice from receiving new federal fuel contracts, as well as new oil and gas leases, although existing contracts and leases will continue. Discretionary debarment typically lasts three to five years and may be imposed for a longer period, unless it is resolved through an administrative agreement.

While BP’s discussions with the EPA have been taking place in parallel to the court proceedings on the criminal plea, the company’s work toward reaching an administrative agreement with the EPA is a separate process, and it may take some time to resolve issues relating to such an agreement. BP’s mandatory debarment applies following sentencing and is not an indication of any change in the status of discussions with the EPA. The process for resolving both mandatory and discretionary debarment is essentially the same as for resolving the temporary suspension. BP continues to work with the EPA in preparing an administrative agreement that will resolve suspension and debarment issues.

The DoJ criminal and SEC settlements impose significant compliance and remedial obligations on BP and its directors, officers and employees. Failure to comply with the terms of these settlements could result in further enforcement action by the DoJ and the SEC, expose BP to severe penalties, financial or otherwise, and subject BP to further private litigation, each of which could impact our operations and have a material adverse effect on the group’s business. Prolonged suspension or debarment from entering new federal contracts, or further suspension or debarment proceedings against BP and/or its subsidiaries as a result of violations of the terms of the DoJ or SEC settlements or otherwise, could have a material adverse impact on the group’s operations in the US.

As a result of the SEC settlement, as of the filing with the SEC of certain registration statements on Form S-8 on 5 February 2013, and for a period of three years thereafter, we will no longer be qualified as a ‘well known seasoned issuer’ (WKSI) as defined in Rule 405 of the Securities Act of 1933, as amended (Securities Act), and therefore will not be able to take advantage of the benefits available to a WKSI, including engaging in delayed or continuous offerings of securities using an automatic shelf registration statement. In addition, as of the settlement date and for a period of five years thereafter, we are no longer able to utilize certain registration exemptions provided by the Securities Act in connection with certain securities offerings. In addition, we may be denied certain trading authorizations under the rules of the US Commodities Futures Trading Commission, which may prevent us in the future from entering certain routine swap transactions for an indefinite period of time.

Regulatory – BP, and the oil industry in general, face increased regulation in the US and elsewhere that could increase the cost of regulatory compliance and limit our access to new exploration properties.

Due to the Gulf of Mexico oil spill and any remedial provisions contained in or resulting from the DoJ and SEC settlements (see Legal proceedings on pages 162-169), it is likely that there will be more stringent regulation of BP’s 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. New regulations and legislation, the terms of BP’s settlements with US government authorities and future settlements or litigation outcomes related to the Incident, and/or 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.

In addition, the oil industry in general 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. See pages 51-54 for more information on environmental regulation.

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, diversity, high ethical standards and the behaviours and actions we expect of our businesses and people wherever we operate. Our values are intended to guide the way we and our employees behave and do business. Under the terms of the DoJ settlement (see pages 40-41), an ethics monitor will review and provide recommendations for the improvement of our code of conduct and its implementation and enforcement. Incidents of ethical misconduct, non-compliance with the recommendations of the ethics monitor 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 and could subject us to further regulatory action or penalties under the terms of the DoJ settlement. 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 and in contravention of our values 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 162-171. For further information on the risks involved in BP’s trading activities, see Treasury and trading activities on page 43.

Liabilities and provisions – BP’s potential liabilities resulting from pending and future claims, lawsuits, settlements 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 Oil Pollution Act of 1990 (OPA 90), BP Exploration & Production Inc. and BP Corporation North America are among 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 certain natural resource damages associated with the spill and certain costs determined by federal and state trustees engaged in a joint assessment of such natural resource damages.

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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 162-169.

BP is subject to a number of investigations related to the Incident by numerous federal and State agencies. See Legal proceedings on pages 162-169. 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, in some circumstances, their assessment of BP’s culpability, if any, following their investigations. Under the Clean Water Act, any finding of gross negligence for purposes of penalties sought against BP would result in significantly higher fines and penalties than the amounts for which we have provided and would also have a material adverse impact on the group’s reputation, would affect our ability to recover costs relating to the Incident from other parties responsible under OPA 90 and could affect the fines and penalties payable by BP with respect to the Incident under enforcement actions outside the Clean Water Act context.

On 3 March 2012, BP reached an agreement (comprising two separate settlement agreements) with the Plaintiffs’ Steering Committee (PSC) in the Multi-District Litigation pending in New Orleans (MDL 2179) to resolve the substantial majority of legitimate private economic and property damages claims and medical benefits claims stemming from the Incident. The settlement agreement in respect of economic and property damages claims was approved by the Court on 21 December 2012, and the settlement agreement in respect of medical benefits claims was approved on 11 January 2013. The PSC settlement is uncapped except for economic loss claims related to the Gulf seafood industry. The cost of the PSC settlement is expected to be paid from the $20-billion Deepwater Horizon Oil Spill Trust fund (Trust). As at 31 December 2011, the estimate of items covered by the settlement with the PSC for Individual and Business claims was $7.8 billion. During 2012, BP increased its estimate of the cost of claims administration by $280 million and also increased the estimate by a further $400 million as described below.

Business economic loss claims received by the Deepwater Horizon Court Supervised Settlement Program (DHCSSP) to date are being paid at a significantly higher average amount than previously assumed by BP in formulating the original estimate of the cost. Further, BP’s initial estimate of aggregate liability under the settlement agreements was premised on BP’s interpretation of certain protocols established in the economic and property damages settlement agreement. As part of its monitoring of payments made by the court-supervised claims processes operated by the DHCSSP for the economic and property damages settlement, BP identified multiple claim determinations that appeared to result from an interpretation of the settlement agreement by that settlement’s claims administrator that BP believes was incorrect. This interpretation produced a higher number and value of awards than the interpretation BP assumed in making the initial estimate. Pursuant to the mechanisms in that settlement agreement, the claims administrator sought clarification from the court on this matter and on 30 January 2013, the court initially upheld the claims administrator’s interpretation of the agreement.

In its unaudited fourth quarter and full year 2012 results announcement dated 5 February 2013, BP stated that if the initial trend of higher average payments than assumed by BP in its original estimate of the cost continued, then it was likely that BP’s estimate of these claims would be increased significantly. Management’s initial assessment of the ruling regarding the interpretation of the settlement agreement led to an increase in the estimated cost of the settlement with the PSC of $400 million, bringing the total estimated cost to $8.5 billion. This estimate was based upon management’s initial assessment of the ruling’s impact on claims already submitted to and processed by the DHCSSP. At that time, BP was seeking reversal of the court’s decision in relation to this matter, management concluded that it was not possible to estimate reliably the impact of the interpretation on any future claims not yet received or processed by the DHCSSP.

On 6 February 2013, the court reconsidered and vacated its ruling of 30 January 2013 and stayed the processing of certain types of bussiness economic loss claims. The court lifted the stay on 28 February 2013. On 5 March 2013, the court affirmed the claims administrator’s interpretation of the economic and property damages settlement agreement and rejected BP’s position as it relates to business economic loss claims. BP strongly disagrees with the decision of 5 March 2013 and the current implementation of the agreement by the claims administrator. BP intends to pursue all available legal options, including rights of appeal, to challenge this ruling.

Other business economic loss claims have continued to be paid at a higher average amount than previously assumed by BP in determining its initial estimate of the total cost. Management has continued to analyse the claims in the period since 5 February 2013 to

gain a better understanding of whether or not the number and average value of claims received and processed to date are predictive of future claims (and so would allow management to estimate the total cost of the Settlements reliably). Management has concluded based upon this analysis that it is not possible to determine whether the claims experience to date is, or is not, an appropriate basis for determining the total cost. Therefore, given the inherent uncertainty that exists as BP pursues all available legal options to challenge the recent ruling and the higher number of claims received and higher average claims payments than previously assumed by BP, which may or may not continue, management has concluded that no reliable estimate can be made of any business economic loss claims not yet received or processed by the DHCSSP.

Therefore, BP’s estimate of the cost of business economic loss claims at 31 December 2012 now includes only the estimated cost of claims already received and processed by the DHCSSP. An amount of $0.8 billion previously provided for future claims not yet received and processed by the DHCSSP has been derecognized, with a corresponding reduction in the reimbursement asset and therefore no net impact on the income statement, as no reliable estimate can be made for this liability. It is therefore disclosed as a contingent liability in Note 43. A provision will be re-established when a reliable estimate can be made of the liability as explained more fully below.

BP’s current estimate of the total cost of those elements of the PSC settlement that can be estimated reliably, which excludes any future business economic loss claims not yet received or processed by the DHCSSP, is $7.7 billion.

If BP is successful in its challenge to the Court’s ruling, the total estimated cost of the settlement agreement will, nevertheless, be significantly higher than the current estimate of $7.7 billion, because business economic loss claims not yet received or processed are not reflected in the current estimate and the average payments per claim determined so far are higher than anticipated. If BP is not successful in its challenge to the Court’s ruling, a further significant increase to the total estimated cost of the settlement will be required. However, there can be no certainty as to how the dispute will ultimately be resolved or determined. To the extent that there are insufficient funds available in the Trust fund, payments under the PSC settlement will be made by BP directly and charged to the income statement.

As previously disclosed, significant uncertainties exist in relation to the amount of claims that are to be paid and will become payable through the claims process. There is significant uncertainty in relation to the amounts that ultimately will be paid in relation to current claims, and the number, type and amounts payable for claims not yet reported. In addition, there is further uncertainty in relation to interpretations of the claims administrator regarding the protocols under the economic and property damages settlement agreement and judicial interpretation of these protocols, and the outcomes of any further litigation including in relation to potential opt-outs from the settlement or otherwise.

While BP has determined its current best estimate of the cost of those aspects of the settlement with the PSC that can be measured reliably, it is possible that the actual cost could be significantly higher than this estimate due to the uncertainties noted above. In addition, the provision will be re-established for remaining business economic loss claims and the estimate will increase as more information becomes available, the interpretation of the protocols is clarified and the claims process matures, enabling BP to estimate reliably the cost of these claims. See Financial statements – Note 36 on page 235 and Note 43 on page 253 for further information.

The Gulf of Mexico oil spill has damaged BP’s reputation. This, combined with other past 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 any alleged breaches of safety or environmental regulations.

See Legal proceedings on pages 162-169 and Financial statements – Note 2 on page 194.

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.

As of the date of the SEC settlement, 10 December 2012, and for a period of three years thereafter, we are unable to rely on the safe harbor provisions regarding forward-looking statements provided by the regulations issued under the Securities Act, and the Securities Exchange Act of 1934, as amended. Our inability to rely on these safe harbor provisions may expose us to future litigation and liabilities in connection with forward-looking statements in our public disclosures.

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,

 

 

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environmental and legal liabilities. Potential changes to pension or financial market regulation could also impact funding requirements of the group.

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 that 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.

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 oil spill. 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 Strategic and commercial risks – Joint ventures and other contractual arrangements on page 39.

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 while at our facilities or premises 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 and safety 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, damage to our reputation or denial of our licence to operate.

BP’s group-wide operating management system (OMS) intends to address health, safety, security, environmental and operations risks, and to provide a consistent framework within which the group can analyse the performance of its activities and identify and remediate shortfalls. 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 conformance 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, cyber-attacks 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, among other things, conflict, civil strife or political unrest in areas where we operate.

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.

 

 

 

 

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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 oil spill 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 people and the environment and given the high volumes potentially involved.

 

 

 

 

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Further note on certain activities

During the period covered by this report, non-US subsidiaries or other non-US entities of BP conducted limited activities in, or with persons from, certain countries identified by the US Department of State as State Sponsors of Terrorism or otherwise subject to US sanctions (‘Sanctioned Countries’). These activities continue to be insignificant to the group’s financial condition and results of operations.

In July 2012, US President Obama signed Executive Order 13622 (‘EO’) authorizing the imposition of additional sanctions against persons who engage in certain dealings with Iran, and in August 2012, the US Congress enacted the US Iran Threat Reduction and Syria Human Rights Act of 2012 (‘ITRA’). Further, on 3 January 2013, US President Obama signed into law the National Defense Authorization Act for Fiscal Year 2013, containing a subtitle known as the Iran Freedom and Counter-Proliferation Act of 2012 (‘IFCPA’) that will impose additional sanctions against Iran when its provisions become effective in July 2013. Together, these measures impose additional sanctions against Iran which include new sanctions against persons involved with Iran’s energy, shipping and petrochemicals industries, and sanctions against financial institutions that engage in significant transactions with the Iran Central Bank.

Similarly the EU has strengthened its sanctions on Iran. On 23 March 2012 the Council of the European Union extended its existing measures against Iran by promulgating Regulation 267/2012 which included a prohibition on the import, purchase and transport of Iranian-origin crude oil and petroleum products. Further, on 15 October 2012, the EU announced new restrictive measures against Iran and certain Iranian entities, including Naftiran Intertrade Co. Limited, some of which were effective immediately, and some of which were implemented by an amending Regulation (1263/2012) on 22 December 2012, including a prohibition on the import, purchase and transport of Iranian-origin natural gas.

Both the US and the EU have enacted strong sanctions against Syria, including a prohibition on the purchase of Syrian-origin crude and a US prohibition on the provision of services to Syria by US persons. The EU sanctions against Syria include a prohibition on supplying certain equipment used in the production, refining, or liquefaction of petroleum resources as well as restrictions on dealing with the Central Bank of Syria and numerous other Syrian financial institutions.

BP seeks to comply with all applicable laws and regulations of the US, the EU and other countries where BP operates, and monitors its activities with Sanctioned Countries and persons from Sanctioned Countries.

BP has interests in and operates two fields – the North Sea Rhum field and the Azerbaijan Shah Deniz field – and has interests in a gas marketing entity and a gas pipeline entity which, respectively, market and transport Shah Deniz gas (both entities and related assets are located outside Iran), in which Naftiran Intertrade Co. Limited and NICO SPV Limited (collectively, ‘NICO’) or Iranian Oil Company (UK) Limited (‘IOC UK’) have interests. Production was suspended at the North Sea Rhum field (in which IOC UK has a 50% interest) in November 2010 and Rhum remains shut-in. The Shah Deniz field, its gas marketing entity and the gas pipeline entity (in which NICO has a 10% or less non-operating interest) continue in operation. The Shah Deniz joint venture and its gas marketing and pipeline entities were excluded from the main operative provisions of the EU Regulations as well as from the application of the new US sanctions, and fall within the exception for certain natural gas projects under Section 603 of ITRA.

BP has no operations in Iran and it is BP’s policy that it shall not purchase or ship crude oil or other products of Iranian origin. Participants in non-BP controlled or operated joint ventures may purchase Iranian-origin crude oil or other components as feedstock for facilities located outside the EU and US. It is also BP’s policy that BP shall not sell crude oil or other products into Iran, except that small quantities of lubricants are sold to non-Iranian third parties for resale or use in Iran. Further, until January 2010, BP held an equity interest in an Iranian joint venture that blended and marketed automotive lubricants for sale to domestic consumers in Iran. BP sold its equity interest but continues to sell small quantities of automotive lubricants and components and licence relevant trade marks to the current owner. Transactions with Iranian shipping companies have been terminated. BP currently holds a non-controlling interest in a non-BP operated joint venture

which sells crude oil to an Indian entity in which NICO holds a minority, non-controlling stake. In 2012, BP distributed certain scrip dividends to BP shareholder Naftiran Intertrade Co. Limited in accordance with applicable UK law in effect at the time of such scrip dividend distributions. In accordance with relevant EU sanctions under EU Regulation 945/2012, BP has withheld scrip dividend distributions to Naftiran Intertrade Co. Limited from October 2012.

BP has become aware that a Canadian university had been using graduate students, some of whom were nationals of Iran, on a research programme funded in part by BP. BP has suspended such programme and made an initial voluntary disclosure to the US Treasury Department’s Office of Foreign Assets Control (‘OFAC’), and is currently reviewing these activities to determine to what extent, if any, the activities may have violated OFAC Regulations.

In addition, BP has become aware that in 2010, as consideration for certain auditing services, BP effected a transfer of funds to a local Iranian consulting firm which may have been in violation of relevant EU notification requirements. BP is reviewing this funds transfer to determine to what extent, if any, BP may have violated relevant EU regulations.

Following the imposition in 2011 of further US and EU sanctions against Syria, BP terminated all sales of crude oil and petroleum products into Syria, though BP continues to supply aviation fuel to non-governmental Syrian resellers outside of Syria.

BP sells lubricants in Cuba through a 50:50 joint venture and trades in small quantities of lubricants. BP sold small quantities of lubricants to third parties that were resold in Sudan; BP has terminated these sales. In the first quarter of 2013, BP sold a small quantity of lubricants to a third-party drilling company for use in Myanmar.

BP has equity interests in non-operated joint ventures with air fuel sellers, resellers, and fuel delivery services around the world. From time to time, the joint venture operator may sell or deliver fuel to airlines from Sanctioned Countries or flights to Sanctioned Countries without BP’s knowledge or consent. BP has registered and paid required fees for patents and trade marks in Sanctioned Countries.

Disclosure pursuant to Section 219 of ITRA

To our knowledge, none of BP’s activities, transactions or dealings are required to be disclosed pursuant to ITRA Section 219, with the following possible exceptions:

The Rhum field (‘Rhum’), located in the UK sector of the North Sea, is operated by BP Exploration Operating Company Limited (‘BPEOC’), a non-US subsidiary of BP. Rhum is owned under a 50:50 unincorporated joint venture between BPEOC and Iranian Oil Company (U.K.) Limited (‘IOC’). The Rhum joint venture was originally formed in 1974. During the period of production from Rhum, the Rhum joint venture supplied natural gas and certain associated liquids to the UK. On 16 November 2010, production from Rhum was suspended in response to relevant EU sanctions. Rhum remains shut-in. During the year ended 31 December 2012, BP recorded gross revenues of £7,329.49 related to Rhum due to changes in prices related to hydrocarbon stock. These changes in prices were non-cash transactions that were recorded as revenue in accordance with BP accounting policy. BP had no net profits related to Rhum during the year ended 31 December 2012, recording an overall loss. BP currently intends to continue to hold its ownership stake in the Rhum joint venture, and to meet any applicable obligations in respect of safety and maintenance of the facilities related to the Rhum field.

BP distributed dividends in the form of new ordinary shares in accordance with BP’s Scrip Dividend Programme to Naftiran Intertrade Co. Limited in March, June and September 2012 as part of BP’s dividend distributions to shareholders during those periods. Such scrip dividends were distributed in accordance with applicable UK law in effect during such periods. BP subsequently declared and distributed a dividend to shareholders in December 2012, but a scrip alternative was not distributed to Naftiran Intertrade Co. Limited in accordance with relevant EU sanctions under EU Regulation 945/2012 which took effect in October 2012. As at 1 March 2013, Naftiran Intertrade Co. Limited is the registered owner of ordinary shares in BP amounting to less than 0.15% of BP’s total outstanding ordinary shares. BP intends to withhold or to procure the withholding of distribution of any form of dividends to Naftiran Intertrade Co. Limited until such time as applicable laws or regulations permit such distribution.

 

 

 

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Safety

We operate in a high-hazard industry so safety is our top priority. We continue working to embed safety and operational risk management into the heart of the company.

 

LOGO

In 2012 BP reported four workforce fatalities: a road-related fatality in Scotland; a fall from a roof in India; an incident at a compressor station in the US; and a tractor accident in our biofuels business in Brazil. Additionally, the armed attack on our joint venture gas facility in Algeria in January 2013 resulted in four BP fatalities. We deeply regret the loss of these lives.

Managing safety

We are delivering a programme of action to continuously improve safety and risk management across BP. Our approach to safety and risk management is informed by our experience, including what we have learned from the Deepwater Horizon oil spill in 2010 and the Texas City refinery explosion in 2005, operations audits, annual risk reviews, other

incident investigations and from industry practice of sharing experience. Three objectives guide our efforts:

 

  To promote deep capability and a safe operating culture across all levels of BP.

 

  To embed OMS as the way BP operates.

 

  To support self-verification and independent assurance that confirms our conduct of operating.

A dedicated function

We established a new safety and operational risk (S&OR) function in early 2011. Our S&OR function supports the business line in delivering safe, reliable and compliant operations across the group’s operated business. S&OR:

 

  Sets clear requirements.

 

  Maintains an independent view of operating risk.

 

  Provides deep technical support to the operating businesses.

 

  Intervenes and escalates as appropriate to cause corrective action.

In 2012 S&OR was led by Mark Bly, the executive vice president who led BP’s investigation into the Deepwater Horizon incident. Mark Bly stepped down from his position as executive vice president of safety and operational risk in February 2013 and has been replaced by Bob Fryar who will continue to report directly to the group chief executive.

S&OR consists of a central team and teams deployed in BP’s businesses. All teams report to the group chief executive via the head of S&OR, independently of the business line. S&OR includes some of BP’s top engineers and safety specialists, several of whom have experience in other industries where major hazards have to be managed, including the military, nuclear energy and space exploration.

The central team serves as the custodian of group-wide safety and operational risk requirements, and runs S&OR audit and capability programmes, with the support of a substantial dedicated audit team.

Our deployed S&OR staff work with our operating businesses – ranging from upstream oil and gas development and production to refineries, petrochemicals plants and retail networks. They help the businesses apply our standards to their operations and help provide assurance to the group as to the management of operational risks, business by business.

Operating businesses remain accountable for delivering safe, reliable and compliant operations with S&OR setting requirements and acting to provide independent advice, scrutiny, challenge and, if needed, intervention.

Governance

BP reviews risks at all levels of the organization, with our S&OR function providing an expert view on safety and operational risks that is independent of the business that remains responsible for management of the risks. While operating line managers are responsible for identifying and managing risks, we place strong emphasis on checks and balances, including both enhanced self-verification by individual BP operations – such as drilling rigs or refineries – and independent assurance by the S&OR function.

Each business segment or function has a safety and operational risk committee, chaired by the segment or function head, to manage safety and risk in their respective areas of the business. The group operations risk committee (GORC) reviews company safety and risk management across the company.

The board’s safety, ethics and environment assurance committee (SEEAC) receives updates from the group chief executive and the head of S&OR on management plans associated with the highest priority risks as part of its update on the GORC’s work. GORC also provides the SEEAC with updates on BP’s process and personal safety performance, and the monitoring of major incidents and near misses across the group. Where appropriate other senior managers attend to provide briefings on safety, environmental and operational integrity in their areas of responsibility. The SEEAC also receives information from external sources, including Carl Sandlin, who was appointed in 2012 to provide oversight and assurance including regarding the implementation of the recommendations of BP’s investigation into the Deepwater Horizon accident. See Corporate governance report on pages 101-126 for further information on the activities of the board’s committees, including the SEEAC and the Gulf of Mexico committee.

 

 

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In May 2012 Duane Wilson’s five-year board appointment as independent expert to provide an independent objective assessment of BP’s progress in implementing the recommendations of the BP US Refineries Independent Safety Review Panel came to an end. Following the end of his term, the SEEAC appointed him as process safety expert and assigned him to work, in a global capacity, with the Downstream business.

Operating management system

BP’s OMS is a group-wide framework designed to provide a basis for managing our operations in a systematic way. OMS integrates BP requirements on health, safety, security, environment, social responsibility and operational reliability, as well as related issues such as maintenance, contractor management and organizational learning, into a common management system. Our OMS evolves over time, for example by amending mandatory practices to reflect implementation experience as well as lessons learned from incident investigations, audits and risk assessments.

Integrated into the OMS are guiding principles and requirements for safe, reliable and compliant operations. Each operating unit has an OMS which describes how it addresses specific operating risks and delivers its operating activities. Business needs, applicable legal and regulatory requirements and group-wide BP requirements are translated into practical plans to reduce risk and deliver strong, sustainable performance.

Conformance and continuous improvement

Our OMS was introduced in 2008. The application of a comprehensive management system such as OMS across a global company is an ongoing process. OMS defines the process for BP operations to apply and conform to required standards and practices on an ongoing basis – including defined time periods for doing so – as well as to continuously improve their operational performance. All of our operations, with the exception of those recently acquired, are now applying our OMS to govern their BP operations and are working to achieve full conformance to standards and practices required by OMS through the performance improvement cycle. Recently acquired businesses are working to transition to OMS. See page 99 for information about joint ventures.

OMS is a dynamic system. Periodically, after an initial assessment as part of the annual performance improvement cycle, our operations are required to conduct a fresh assessment to develop an updated prioritized plan in respect of any existing gaps or new gaps that may have been identified. These actions form an integral part of each operation’s multi-year and annual planning cycle. Where appropriate, actions are aggregated to provide common solutions. S&OR reviews how these assessments are undertaken.

Capability development

BP strives to equip its staff with the skills needed to apply OMS and its associated processes and practices. For example, in addition to a dedicated programme to assess the technical well control competencies of BP’s well site leaders, we have been working to identify safety-critical roles and the associated technical and leadership competencies to do them. We are also strengthening capability and competence by consolidating and standardizing our competence management programme. Our approach is being tested in a number of job categories, such as offshore installation managers and well site leaders.

We continue to provide training programmes for our operations personnel at all levels. This training includes our operations academy programmes for senior management, delivered in partnership with the Massachusetts Institute of Technology, US; specialized operational and technical management programmes, for example, courses in engineering and project management at the University of Manchester, UK; and process safety and management training for our front-line leaders, delivered under our operating essentials programme. Since 2008 we have been running operating essentials modules and in 2012 over 6,000 modules were delivered to managers, supervisors and technicians across the BP group. Both non-executive and senior management team members addressed operations academy participants during sessions in 2012. We also offer a substantial programme of eLearning modules.

Crisis management

Crisis management planning is essential to respond effectively to emergencies and to avoid a potentially severe disruption in our business and operations. In 2012 we issued new group-wide OMS practices for

both crisis management and oil-spill preparedness and response, which are replacing the interim practices put in place following the Deepwater Horizon accident. All BP businesses and functions are required to achieve conformance within a defined time period.

See Environmental and social responsibility on pages 51-54 for information on BP’s approach to oil spill preparedness and response.

Safer drilling

BP has worked to centralize and standardize our approach to drilling practices and oversight of projects with the establishment of the global wells organization (GWO) and the global projects organization in 2011. The GWO now employs more than 2,000 people, bringing functional wells expertise into a single organization with common global standards. The GWO works with our safety and operational risk function with a view to continuously reducing risk in drilling and so reduce the likelihood of an oil spill or incident occurring. BP has already established requirements and standards for Gulf of Mexico drilling that exceed regulatory requirements.

Following the settlement with the US government of all federal criminal claims related to the Gulf of Mexico, BP has agreed to appoint a process safety monitor in the US for a term of four years. The monitor will review, evaluate and provide recommendations for the improvement of BP’s process safety and risk management procedures concerning deepwater drilling in the Gulf of Mexico. Additionally, an independent third-party auditor will review and report on BP’s implementation of key terms of the agreement, including procedures and systems related to safety and environmental management, operational oversight, and oil spill response training and drills. For more information on this agreement with the US government, see Legal proceedings on pages 162-169.

Building capability

BP is committed to establishing a global wells institute and has invested in state-of-the art simulator facilities to support practical learning and testing. The institute aims to build and sustain enhanced capability within the GWO by developing the skills to deliver safe and compliant wells that will align with our broader people processes, such as performance development plans and performance appraisals, contractor strategy and ways of working.

Competence testing is an important part of assuring safe operations. In a competence testing programme in the GWO, 532 well site leaders have been assessed on a risk-prioritized basis. Remediation activities have been carried out where areas for improvement have been identified.

We are also engaged in targeted recruitment to support critical work areas. One of these has been the cementing of wells – a key issue as identified in the investigation reports into the Deepwater Horizon accident. For this reason, we are enhancing oversight of cementing services. We have recruited additional expertise into the company and now have 21 cementing specialists.

The Bly Report – implementing the recommendations

The Bly Report concluded that no single cause was responsible for the accident. The investigation instead found that a complex, inter-linked series of mechanical failures, human judgements, engineering design, operational implementation and team interfaces, involving several companies including BP, contributed to the accident.

The Bly Report made 26 recommendations that were specific to drilling. We accepted all of the recommendations and are working to implement them across our drilling operations worldwide. The recommendations include measures to improve contractor management, as well as to strengthen design and assurance on blowout preventers (BOPs), well control, pressure-testing for well integrity, emergency systems, cement testing, rig audit, verification and personnel competence.

Implementing the 26 recommendations across the group requires detailed work and many activities – from creating new practices and guidance, training and testing identified staff, changing requirements and expectations of our contractors, and establishing verification processes.

A project of this scale takes time. Implementing these recommendations across all BP-operated drilling activity across the world is an enormous undertaking involving a programme team of around 85 people, consisting of a central team based in Houston and others embedded in BP’s businesses. We are working to assure that all actions are delivered to a

 

 

 

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high standard across all of our well operations, and are independently verified by our S&OR audit or internal audit function.

We have estimated and communicated delivery timelines for each of the recommendations and will continue to provide periodic updates of our progress. These timelines are based on existing facts and circumstances and can shift due to complexity, resource availability and evolving regulatory requirements.

At the end of 2012, 14 of the Bly Report recommendations had been completed. We continue to make progress on all of the remaining recommendations largely in line with our planned schedule. Progress is tracked quarterly by executive management. We also regularly update investors. See bp.com/internalinvestigation for the full report and periodic updates on progress.

Independent advice

In June 2012 the BP board appointed Carl Sandlin to provide SEEAC with an objective and independent assessment of BP’s global progress in implementing the 26 Bly Report recommendations and on process safety. Carl Sandlin will also on occasion be asked to provide his views to the board on other matters related to, but not specifically within the scope of the Bly Report recommendations, for example, his views on organizational effectiveness or culture of the GWO and process safety observations in the upstream. He has direct access to the chair of SEEAC and will report to the committee in person at least twice a year. See BP Sustainability Review 2012 for more information on Carl Sandlin’s activities.

Delivering enhanced processes and practices

Eight interim actions were issued to our operating regions immediately following the publication of the Bly Report. Seven of those actions have now been incorporated into engineering technical practices or other documents being developed as part of the work towards completing the 26 recommendations. The final interim action is scheduled to be incorporated into a new practice in early 2013.

During 2012, as we continued to work towards delivering the recommendations, we developed or refreshed key operating practices and engineering standards on:

 

  Cementing or zonal isolation: we have issued new mandatory requirements and nine associated guides covering cementing activities. As of December 2012, 711 technical professionals in BP have now undergone training on the revised practices. We have also strengthened the technical approval process for some cementing operations. Systematic input into the well design workflow now requires both the regional and global BP specialist to agree on the basis of design for complex zonal isolation activities.

 

  Integrating process safety concepts into management of wells: we have produced a technical practice specifying minimum requirements for well barrier management – managing the movement of fluids and gas within the well – throughout the life cycle of the well. Implementation of this practice has commenced with two-day workshops training 624 people as of December 2012.

 

  Well casing design: we have updated our design manual for well casing and inner tubing to include new requirements for pressure tests and revised technical practices. A one-day training workshop on this revised practice has been developed for BP professionals and 247 people have been trained as of December 2012.

 

  BOP stacks: we have issued a revised technical practice on well control, defining and documenting our requirements for subsea BOP configurations. We require two sets of blind shear rams and a casing shear ram for all subsea BOPs used on dynamically positioned rigs in deep water. This exceeds regulatory requirements. We also require that third-party verification is carried out on the testing and maintenance of subsea BOPs in accordance with industry recommended practice, and that remotely operated vehicles capable of operating these BOPs are available in an emergency.

 

  Rig intake and start-up operating procedure: we have continued the rig audit process enhanced in 2011. We have also conducted detailed hazard and operability reviews for key fluid handling systems on all offshore rigs in the BP fleet. All drilling rigs joining the BP fleet are subject to an independent S&OR audit and readiness to operate is verified with a detailed go/no-go process assured by S&OR. This includes a checklist that, among other things, assists in assessing that
   

the rig conforms to BP practices and industry standards, that it has the necessary technical specification, and that the actions required for start-up are completed. All rigs are also subject to subsequent periodic rig audits.

BP is in the process of issuing the above guides and implementing the above practices across all our operating regions. Practices are implemented through training workshops and accompanying training materials, gap assessments, and requirements for reaching conformance. We continue to progress the remaining recommendations of the Bly Report.

External investigations

There have also been a number of external investigations into the Gulf of Mexico oil spill, including those of the National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling (oilspillcommission.gov) and the joint investigation team of the Bureau of Ocean Energy Management, Regulation and Enforcement and the US Coast Guard (boemre.gov/ooc/press/2011/press0914.htm). Additionally, the US National Academy of Engineering undertook an independent study. All of these reports were consistent with the general conclusion that the accident resulted from multiple causes and was due to the actions of multiple parties. We are committed to understanding the causes, impacts and implications of the Deepwater Horizon incident and to learn and act on lessons from it. As part of this commitment, BP is reviewing the recommendations from government and industry reports.

Sharing lessons learned

We are committed to sharing what we have learned globally to advance the capabilities and practices that enhance safety in our company and the deepwater industry and help to prevent an accident of this magnitude from happening again. We have conducted more than 200 briefings in nearly 30 countries over the past two years to share lessons learned. Other examples of our collaboration include:

 

  Participating in the International Association of Oil & Gas Producers’ Well Expert Committee that is working to prevent well control incidents by improving well engineering design and well operations management.

 

  Providing equipment and expertise developed during the Deepwater Horizon accident response to the Marine Well Containment Company to help industry meet regulatory requirements for drilling in the Gulf of Mexico.

 

  Participating in the Subsea Well Response Project to enhance the industry’s global well capping capabilities – resulting in a collaboration with Oil Spill Response Limited to build four well cap systems and two dispersant application equipment packages due to be positioned in Europe, Africa, Asia and South America in 2013.

 

  Filing patent applications in the US and elsewhere to cover about 30 technical innovations related to well capping and containment work, with the aim of ensuring the capping and containment technology we have developed will be open for access and further development for the benefit of the industry.

 

  Implementing a technology licence agreement with Petróleos Mexicanos (PEMEX) that will share BP capping system technology and know-how with the national oil company of Mexico.

 

  Participating in the 19 sub-committees of the IPIECA/International Oil and Gas Producers Association, Joint Industry Project on Oil Spill Response, focused on developing recommendations for effective and fit-for-purpose oil spill response preparedness and capability.

 

  Establishing the Center for Offshore Safety with the American Petroleum Institute with a mission to promote the highest level of safety in the deepwater Gulf of Mexico.

Safety in the Downstream business

In our hydrocarbon facilities across the Downstream business we focus on the safe storage, handling and processing of hydrocarbons via systematic management of associated operating risks. In seeking to manage these risks, BP takes measures to:

 

  Prevent loss of hydrocarbon containment through well-designed, maintained and operated equipment.

 

  Reduce the likelihood of any hydrocarbon releases and the possibility of ignition that may occur by controlling ignition sources.

 

  Provide safe locations, emergency procedures and other mitigation measures in the event of a release, fire or explosion.
 

 

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Senior downstream leaders, led by the segment chief executive, participate in the segment operations risk committee, which provides leadership and expectations on the management of operations. Quarterly, this committee also reviews safety and operations performance indicators. All of our businesses use a set of common leading and lagging safety metrics that are intended to monitor performance and help identify opportunities for improvement.

BP continues to implement the BP US Refineries Independent Safety Review Panel recommendations as part of ongoing process safety management.

Risk management

Hazard identification and risk management are key components of our OMS and are fundamental to the success of safely managing hydrocarbons. Over the past two years, our Downstream business has implemented a risk management programme under OMS that focuses on identification, assessment, response and action to manage safety and operational risk combined with monitoring and review of identified and newly emerging risks.

Management plans for the Downstream businesses’ high-consequence, low-probability risks are reviewed annually by the segment chief executive and the chief operating officers.

Some examples of specific risk reduction work across our refining and petrochemicals portfolio in 2012 include:

 

  Installation of additional safety instrumentation and equipment to reduce the likelihood of identified risks occurring.

 

  Continuing work to improve the safety of site occupied buildings. We have a major programme under way to install safety shelters for personnel; to move people further away from hydrocarbon-containing equipment; and to reduce the number of vehicles onsite. For example, during 2012 a building-hardening programme was completed at our Toledo refinery, and at our Bulwer refinery we constructed new offices to move employees away from higher risk processing areas. The business also continues to train and drill personnel to respond to emergencies.

 

  Work to reduce explosion and toxic risks through inventory reduction by, for example, reducing ethylene and propylene refrigerants in our petrochemical plants and by eliminating or reducing the use of ammonia across the refining portfolio.

Where similar risks have been identified across multiple facilities, new guidance for gasoline storage, tanker loading and buildings were developed and issued to drive consistent risk mitigation efforts across the segment.

Capability development

Each facility has experienced and trained operational staff and a system for assessing their competency. We are developing a consistent competency framework that standardizes this assessment process for safety-critical roles supported by and in conjunction with S&OR direction and expertise.

To support the competency development plan for operations personnel, our refineries and chemical manufacturing plants are in the process of installing high fidelity process simulators for selected process units. These will be used to train operators via simulations to respond to low-probability, high-consequence scenarios, similar to methods used with airline pilots.

Measurement, evaluation and corrective action

The oversight of the management of hydrocarbons across our operations is supported by our S&OR function. S&OR personnel work with our operating businesses to provide independent perspectives on the quality of our operations and the management of risks.

A quarterly assurance process enables S&OR to provide an ongoing independent view of OMS conformance by the sites. Each site is assessed on its OMS self-verification processes, the strength of existing risk mitigations and progress on risk reduction plans. Periodic S&OR audits against OMS requirements also provide valuable insights and result in actions to close any identified findings.

Lessons learned from incidents and near-misses are important for identifying ways to improve safety practices. In 2012 we issued a number of briefings and alerts on lessons learned from incidents and near-misses and we require our sites to provide assurance that similar risks have been assessed and appropriate corrective actions undertaken.

New process safety expert for our Downstream business

Duane Wilson’s five-year board appointment as independent expert to provide an independent objective assessment of BP’s progress in implementing the recommendations of the BP US Refineries Independent Safety Review Panel came to an end in May 2012. Recognizing the extensive experience he has acquired during his years as independent expert and following the end of his term, SEEAC appointed him as process safety expert and assigned him to work, in a global capacity, with the Downstream business.

In this new role, he is providing an independent perspective on the progress that BP’s fuels and petrochemicals businesses are making globally toward becoming industry leaders in process safety performance. Specifically, Duane Wilson is focusing and reporting to the SEEAC on three topics:

 

  Downstream’s prioritization of the agenda to become an industry leader in process safety.

 

  Downstream’s progress in embedding BP’s OMS – including process safety risk assessment processes, process safety culture and interpretation of trends in process safety performance.

 

  The effectiveness of the Downstream safety and operational risk function’s agenda.

Duane Wilson continues to have frequent and direct access not only to the board, but also to BP employees from the most senior executives down to the shop floor. He visits facilities, conducts interviews and reviews relevant documents, such as audit and incident reports, to fulfil his duties. Additionally, he is an ex officio member of the Downstream segment operations risk committee and regularly attends its meetings with the senior executives of the business. His contract is for a two-year term ending in May 2014, and may be renewed for up to an additional two years on mutual agreement.

Safety performance

Workforce fatalities

In 2012 BP reported four workforce fatalities: a road related fatality in Scotland; a fall from a roof in India; an incident at a compressor station in the US; and a tractor accident in our biofuels business in Brazil. Additionally, the armed attack on our joint venture gas facility in Algeria in January 2013 resulted in four BP fatalities. We deeply regret the loss of these lives.

Oil spills and other loss of primary containment

We monitor the integrity of our assets used to produce, process and transport oil and other hydrocarbons with the aim of preventing the loss of material from its primary containment.

Accordingly, we track loss of primary containment as a metric, which includes unplanned or uncontrolled releases from a tank, vessel, pipe, rail car or equipment used for containment or transfer of materials within our operational boundary, excluding non-hazardous releases such as water.

The US government and third parties have announced various estimates of the flow rate or total volume of oil spilled from the Deepwater Horizon incident. The multi-district litigation pending in New Orleans will address the amount of oil spilled. See Financial statements – Note 36 on page 235 for information about the volume used to determine the estimated liabilities.

 

 

 

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Loss of primary containment and oil spills (excluding Deepwater Horizon oil spill in respect of 2010 volume)

 

       2012         2011         2010   

Loss of primary containment – number of all incidentsa

     292         361         418   

Loss of primary containment – number of oil spillsb

     204         228         261   

Number of oil spills to land and water

     102         102         142   

Volume of oil spilled (thousand litres)

     801         556         1,719   

Volume of oil unrecovered (thousand litres)

     320         281         758   

 

a Does not include either small or non-hazardous releases.
b Number of spills greater than or equal to one barrel (159 litres, 42 US gallons).

Process safety

We monitor the number of process safety events occurring across our operations using the American Petroleum Institute (API) RP-754 standard. Introduced in 2010 it sets out process safety indicators, organized into different tiers and is used as the basis for our internal and external process safety reporting. API tier 1 process safety events are the loss of primary containment from a process of greatest consequence – causing harm to a member of the workforce or costly damage to equipment, or exceeding defined quantities. API tier 2 process safety events are loss of primary containment, from a process, of lesser consequence. Forty-three tier 1 process safety events were reported in BP in 2012, compared with 74 in 2011. This is our first year reporting API tier 2 safety events externally.

Personal safety

BP reports publicly on its personal safety performance according to standard industry metrics.

Personal safety performance

 

       2012         2011         2010   

Recordable injury frequency (group) – incidents per 200,000 hours worked

     0.35         0.36         0.61   

Days away from work case frequencya (group) – incidents per 200,000 hours worked

     0.076         0.090         0.193   

 

a Incidents that resulted in an injury where a person is unable to work for a day (shift) or more.

Working with partners and contractors

BP, like our industry peers, rarely works in isolation – we need to work with suppliers, contractors and partners to carry out our operations. In 2012, 55% of the 402 million hours worked by BP were carried out by contractors.

Our ability to be a safe and responsible operator depends in part on the conduct of our suppliers, contractors and partners. We address this in a variety of ways, from training and dialogue to requiring adherence to operational standards through legally binding agreements.

Our OMS is a group-wide framework designed to provide business-specific requirements and practices, including for working with contractors and our operations are obliged to plan and execute actions to reach conformance with OMS on contractor management. OMS is also designed to drive continuous improvement, including how BP businesses continue to work towards full conformance with the elements relevant to working with contractors.

In 2012 we prepared guidance for conformance with OMS, where it relates to working with contractors, in order to support the accountable line organizations. We intend to field test this in 2013.

We expect our contractors to comply with legal requirements and to operate consistently with the principles of our code of conduct when they work on our behalf. The objective is to provide assurance that goods, equipment and services provided by third parties meet contractual and BP requirements and that there is a consistent, shared understanding of responsibilities.

Following the Deepwater Horizon incident, we undertook an in-depth review of contractor management practices, with the aim of documenting and learning from the latest proven practices throughout BP and across a number of sectors and industries that use contractors in potentially high-consequence activities. The review confirmed to us the value of building long-term relationships with a limited number of contractors, supported by shared structures and common processes.

Initially our work has focused on contracts in our upstream supply chain involving potentially high-consequence activities. In 2012 we built on this work to identify contracts involving potentially higher-consequence activities across the group and bringing a consistent level of oversight to the management of these contracts as a priority. In our global projects organization, we have put in place global agreements with seven suppliers for plant inspection and surveillance services, covering the work previously undertaken by more than 60 suppliers.

The review also highlighted the importance of clearly defined responsibilities and decision rights at every stage of each process – including training, monitoring and auditing – as well as rigorous qualification of suppliers, including their demonstration of the competency of key personnel. In 2012 we focused, including through our OMS, on practical assistance to operational line management to build competence in this area.

In 2013, we plan to continue our work on the management of contractors through our OMS framework and actions related to additional supplier audits, competence testing and other programmes.

Our partners in joint ventures

We seek to work with companies that share our commitment to ethical, safe and sustainable working practices. However, we do not control how our co-venturers and their employees approach these issues.

Typically, our level of influence or control over a joint venture is linked to the size of our financial stake compared with other participants. In some joint ventures we act as the operator. Our OMS provides that where we are the operator, and where legal and contractual arrangements allow, OMS applies to the operations of that joint venture.

In other cases, one of our joint venture partners may be the designated operator, or the operator may be an incorporated joint venture company owned by BP and other companies. In those cases our OMS does not apply as the management system to be used by the operator, but is available to our businesses as a reference point for their engagement with operators and co-venturers. Where BP does not have overall control of a joint venture, we will do everything we reasonably can to make sure joint ventures follow similar principles.

 

 

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Environmental and social responsibility

We strive to minimize our impact on the environment and communities, to respect human rights and to conserve cultural heritage.

 

LOGO

Managing our environmental and social risks and impacts

At a group level, we review our management of material issues such as GHG emissions, water, sensitive and protected areas and human rights annually. We seek to identify emerging risks and assess methods to reduce them across the company.

Our OMS helps our operations around the world to assess and manage their environmental and social impacts. This includes conducting an annual OMS assessment to identify risks and impacts, and then putting in place action plans to manage them.

The principles and standards of OMS are supported by our environmental and social practices. These set out how our major projects identify and manage environmental and social impacts. They also apply to projects that involve new access, projects that could affect an international protected area and some BP acquisition negotiations.

In the early planning stages, these projects complete a screening process. Results are used to identify the most significant environmental and social impacts associated with the project, with a requirement to identify mitigation measures and implement these in project design, construction and operations. From April 2010 to the end of 2012, 88 projects had completed the screening process, and used outputs of the process to implement measures to reduce impact.

During screening, we identify any international protected areas that could be affected by the project, using the UNEP World Conservation Monitoring Centre’s World Database on Protected Areas. Our international protected areas classification includes areas designated as protected by the International Union for the Conservation of Nature (categories I-IV),

Ramsar and World Heritage sites, as well as areas proposed for international protected status.

Where screening indicates that a proposed BP project could affect an international protected area a high-level risk assessment is carried out, including identification of potential avoidance and mitigation measures. Our safety and operational risk function provides an independent review of the risk assessment, and before any physical activity begins, permission is sought from senior management. In 2012 no new projects sought permission for entry into an international protected area.

Our operations are expected to work to continually reduce their impacts and risks. All our major operating sites, with the exception of recently acquired operations, are required to be certified to the environmental management system standard ISO 14001, and publish an externally verified environmental statement. In 2012 our Gelsenkirchen refinery in Germany was not recertified due to conflicts in scheduling a verification audit. They completed a verification audit in late 2012 and were recertified in January 2013.

More information about our approach to environmental and social issues can be found in BP Sustainability Review 2012 and at bp.com/sustainability.

Oil spill preparedness and response

We have used lessons from our Deepwater Horizon oil spill response to further enhance our internal approaches to preparedness and response planning. In July 2012 new group requirements for oil spill preparedness and response planning, and for crisis management were issued, with timeframes established for required conformance by the businesses. To facilitate understanding of these new requirements, workshops have been conducted with more than 600 staff from 45 countries, ranging from senior leaders to on-site oil spill response teams.

Understanding and mitigating the risks

Identifying and assessing the potential oil spill risks and potential impacts helps us to develop appropriate oil spill response and crisis management plans. These plans are backed up by the tools and people required to mount an effective response to an incident and mitigate potential impacts.

We further developed our oil spill modelling systems and capabilities in 2012. Improving existing modelling tools, conducting staff training in our regions and enhancing the environmental and socio-economic data required in the models have all helped to better define different oil spill scenarios and to plan for responding to them. Modelling for two deepwater drilling operations, Salamat and North Uist, indicated that international protected areas could potentially be affected from the worst case oil spill scenario. As a result, additional mitigations were put in place to try to reduce this risk.

Understanding the environmental and socio-economic sensitivities can help inform response planning. Across our operating regions, we are developing enhanced, high resolution sensitivity maps aided by the use of technologies such as remote sensing satellites. In 2012 we used high resolution satellite imagery to enhance sensitivity maps of coastlines in Brazil and Africa.

The use of oil spill dispersants as a response tool for major oil spills in the deep-sea environment continued to be a focus area in 2012. We continue to gain a greater understanding of dispersants and their use through scientific research programmes, conducted individually: for example, characterizing the ‘oil-degrading bacterial communities’ in our operating regions and collectively, through joint industry programmes such as IPIECA-OGP and the API.

Collaboration on lessons learned

We seek to work collaboratively with government regulators in planning for oil spill response, sharing lessons learned and our technical approaches, with the aim of improving any potential future response. In the past two years we conducted workshops on issues such as dispersant use and in-situ burn response to regulators in Australia, Brazil, China, Egypt, Indonesia, Norway and the UK.

We are advancing our capability to respond to potential incidents and are working with our industry to further enhance access to equipment and technologies around the world. BP’s global deepwater well capping and tooling package is stored in Houston and can be deployed in a matter of days to anywhere in the world in the event of a deepwater well blowout.

 

 

 

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The equipment is designed to operate in water depths of up to 10,000 feet. It includes a remotely operated vehicles intervention system, a subsea dispersant injection system and subsea debris removal equipment and a deepwater well cap.

See Safety on pages 46-50 for further information on BP’s approach to oil spill prevention and for performance data on loss of primary containment.

Gulf of Mexico – our long-term commitments

See Gulf of Mexico oil spill on pages 59-62 for further information on BP’s response to the incident and environmental and economic restoration efforts.

Climate change

Climate change represents a significant challenge for society and the energy industry, including BP. In response to the challenges and opportunities, BP is continuing to take a number of practical steps, including investing in lower-carbon energy products such as biofuels and wind, and ventures focused on sustainable energy solutions. We seek to manage our own GHG emissions through our OMS, by requiring our operations to incorporate energy use considerations in their business plans and to assess, prioritize and implement technologies and systems to improve energy usage.

As part of our OMS and project screening process, we consider and identify risks and potential impacts of a changing climate on our facilities and operations.

Greenhouse gas emissions

Our direct GHG emissionsa were 59.8 million tonnes (Mte) in 2012, compared with 61.8Mte in 2011, a decrease of 2.0Mte versus 2011. The net effect of acquisitions and divestments is a decrease of 0.7Mte, primarily the result of the sale of upstream assets as part of our divestment programme. Operational changes led to a decrease of 0.7Mte, principally due to temporary reductions in activity at some of our upstream sites and one of our major US refineries and lower mileage by our shipping vessels. Improvements made by our businesses to calculate their emissions more accurately resulted in a net decrease of 0.4Mte. We achieved 0.2Mte of sustainable emissions reductions in 2012.

 

a  We report GHG emissions on a CO2 -equivalent basis, including CO2 and methane. This represents all consolidated entities and BP’s share of equity-accounted entities except TNK-BP.

Over the long term it is likely that the carbon intensity of our upstream operations will continue to trend upwards as we move further into technically challenging and potentially more energy-intensive areas. The carbon intensity will likely remain relatively flat or even decrease in certain refining operations because of improved energy efficiency even with the trend towards processing heavier crudes.

Greenhouse gas regulation

In the future, we expect that additional regulation of GHG emissions aimed at addressing climate change will have an increasing impact on our businesses, operating costs and strategic planning, but may also offer opportunities for the development of lower-carbon technologies and businesses.

To help address potential future regulation, we factor a carbon cost into our investment appraisals and engineering designs for new projects where appropriate. We do this in order to assess, and protect the value of, our new investments under future scenarios in which the cost of carbon emissions is higher than it is today. We require larger projects, and those for which emissions costs would be a material part of the project, to apply a standard carbon cost to the projected GHG emissions over the life of the project. The standard cost is based on our estimate of the carbon price that might realistically be expected in particular parts of the world. In industrialized countries, this standard cost assumption is currently $40 per tonne of CO2 equivalent. We use this cost as a basis for assessing the economic value of the investment and as one consideration in optimizing the way the project is engineered with respect to emissions.

See Regulation of the group’s business – Greenhouse gas regulation on pages 96-97.

Climate change adaptation

We are taking steps to prepare for the potential physical impacts of climate change on our existing and future operations. We are working closely with Imperial College in the UK to develop specialized climate models that help us better understand and predict possible impacts resulting from the changing climate.

Projects implementing our environmental and social practices are required to assess the potential impacts to the project from the changing climate and manage any identified significant potential impacts. Where climate change impacts are identified as a risk for a project, our engineers seek to address them in the project design like any other physical and ecological hazard. We periodically review and adjust existing design criteria and engineering technology practices. For example, a regional climate model was used in 2012 to inform decisions on the depth of cover required for river crossings for the South Caucasus Pipeline and to review any risks associated with landslides.

We regularly update and improve our climate impact modelling tools and make them available to both new projects and existing operations. An internal guide, available to both existing operations and projects, has been in place since 2010. It sets out guidance on how to assess potential risks and impacts from a changing climate to enable mitigation steps to be incorporated into project planning, design and operations.

Water

BP recognizes the importance of managing water effectively and efficiently in areas of water stress or scarcity, the need to minimize water quality impacts from our discharges, and the need to protect water resources at our operations.

We are continuing to pilot and develop standardized tools to more deeply understand the nature of the risks and opportunities associated with water management at a strategic and local level. This includes an assessment of water scarcity, the impact of changing effluent discharge standards, and the long-term social and environmental pressures on water resources within the local area. We also commissioned Harvard University in the US to conduct research in 2012 on the allocation and use of water in Jordan, the United Arab Emirates, Iraq and Oman. This will be followed through in 2013 and 2014 with more detailed research in three or four of these countries. This will equip BP with peer-reviewed science as a basis for planning water needs for oil and gas developments in the Middle East.

Unconventional gas and hydraulic fracturing

Natural gas resources, including unconventional gas, have an increasingly important role in meeting the world’s growing energy needs. New technologies are making it possible to extract unconventional gas resources safely, responsibly and economically. BP has unconventional gas operations in the US, Algeria, Indonesia and Oman.

Hydraulic fracturing is the process of pumping water, mixed with a small proportion of sand and chemicals, underground at a high enough pressure to split and keep open the rock and release natural gas that would otherwise not be accessible. Some stakeholders have expressed concerns about the potential environmental and community impacts of this process.

BP recognizes these concerns and seeks to apply responsible well design, construction and operation to mitigate the risk that natural gas and hydraulic fracturing fluids enter underground aquifers, including drinking water sources. We are trialling a number of water-saving innovations to minimize the amount of fresh water used in our drilling and hydraulic fracturing operations.

Water and sand constitute on average 99.5% of the injection fluid. This is mixed with chemicals to create the fracturing fluid that is pumped underground at high pressure to fracture the rock with the sand propping the fractures open. The chemicals used in this process help to reduce friction and control bacterial growth in the well. Some of them are classified as hazardous materials, as are the constituents of many everyday products when in concentrated form. Each chemical used in the fracturing process is listed in the material safety data sheets at each site, which detail safe dosage limits. We submit data on chemicals used at our hydraulically fractured wells in the US at fracfocus.org.

At our operating sites, we aim to minimize air pollutant and GHG emissions by, for example, seeking to use natural gas or electricity instead

 

 

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of more carbon-intensive conventional fuel sources to power operations at sites where these energy sources are readily available and affordable. We introduced ‘green completion’ technology in our North American gas operations in 2001 to recover natural gas for sale and minimize the amount of natural gas either flared or vented from our wells.

To help manage potential impacts on the community, such as increased traffic, noise, dust and light, we seek to design and locate our equipment and manage our work patterns in ways that reduce impact to relevant communities. We also listen to suggestions or complaints from nearby local communities and try to address their concerns.

More information about our approach to unconventional gas and hydraulic fracturing may be found at bp.com/unconventionalgas.

Canada’s oil sands

Canada’s oil sands are believed to hold one of the world’s largest supplies of oil, third in size to the resources in Saudi Arabia and Venezuela.

BP is involved in three oil sands properties, all of which are located in the province of Alberta. Development of the Sunrise project, our joint venture operated by Husky Energy, is under way, with production from Phase 1 expected to start in 2014. The other two proposed projects – Pike, which will be operated by Devon Energy, and Terre de Grace, which will be BP-operated – are still in the early stages of development.

Our decision to invest in Canadian oil sands projects takes into consideration GHG emissions, impacts on land, water use and local communities, and commercial viability. In the case of joint ventures in which we are not the operator, we monitor the progress of these projects and the mitigation of risk. In the Terre de Grace project where we are the operator, we are responsible for managing these potential impacts and the mitigation of risk.

More information on BP’s investments in Canada’s oil sands can be found at bp.com/oilsands.

Environmental expenditure

 

                         $ million   
       2012         2011         2010   

Environmental expenditure relating to the Gulf of Mexico oil spill

        

Spill response

     118         671         13,628   

Additions to environmental remediation provision

     801         1,167         929   
Other environmental expenditure         

Operating expenditure

     742         704         716   

Capital expenditure

     1,207         819         911   

Clean-ups

     46         53         55   

Additions to environmental remediation provision

     549         510         361   

Additions to decommissioning provision

     3,756         4,596         1,800   

Environmental expenditure relating to the Gulf of Mexico oil spill

BP continues to incur significant costs related to the 2010 Gulf of Mexico oil spill. The spill response cost incurred during 2012 is $118 million (2011 $671 million), and $345 million (2011 $336 million) remains as a provision at 31 December 2012.

The environmental remediation provision includes amounts for BP’s commitment to fund the Gulf of Mexico Research Initiative, estimated natural resource damage (NRD) assessment costs and early NRD restoration projects under the $1-billion framework agreement. The provision for NRD assessment costs was increased during the year. Further amounts for spill response costs were provided during the year, primarily to reflect increased costs for patrolling and maintenance and shoreline treatment projects. The majority of the active clean-up of the shorelines was completed in 2011.

See Financial statements – Note 2 on page 194, Note 36 on page 235 and Note 43 on page 253 for further information relating to the Gulf of Mexico oil spill.

Other environmental expenditure

Operating and capital expenditure on the prevention, control, abatement or elimination of air, water and solid waste pollution is often not incurred as a separately identifiable transaction. Instead, it forms part of a larger transaction that includes, for example, normal maintenance expenditure. The figures for environmental operating and capital expenditure in the table are therefore estimates, based on the definitions and guidelines of the American Petroleum Institute.

Environmental operating expenditure of $742 million in 2012 was at a similar level to 2010 and 2011.

Capital expenditure in 2012 was higher than in 2011 principally due to the high level of construction activity at our Whiting refinery in relation to new units as part of the Whiting refinery modernization project which is due to be completed in the second half of 2013. Similar levels of operating and capital expenditures are expected in the foreseeable future.

In addition to operating and capital expenditures, we also establish provisions for future environmental remediation. Expenditure against such provisions normally occurs in subsequent periods and is not included in environmental operating expenditure reported for such periods.

Provisions for environmental remediation are made when a clean-up is probable and the amount of the obligation can be reliably estimated. Generally, this coincides with the commitment to a formal plan of action or, if earlier, on divestment or on closure of inactive sites.

The extent and cost of future environmental restoration, remediation and abatement programmes are inherently difficult to estimate. They often depend on the extent of contamination, and the associated impact and timing of the corrective actions required, technological feasibility and BP’s share of liability. Though the costs of future programmes could be significant and may be material to the results of operations in the period in which they are recognized, it is not expected that such costs will be material to the group’s overall results of operations or financial position.

Additions to our environmental remediation provision increased in 2012 largely due to scope reassessments of the remediation plans of a number of our sites in the US and Canada. The charge for environmental remediation provisions in 2012 included $19 million in respect of provisions for new sites (2011 $12 million and 2010 $54 million).

In addition, we make provisions on installation of our oil- and gas-producing assets and related pipelines to meet the cost of eventual decommissioning. On installation of an oil or natural gas production facility a provision is established that represents the discounted value of the expected future cost of decommissioning the asset.

The level of increase in the decommissioning provision varies with the number of new fields coming onstream in a particular year and the outcome of the periodic reviews. The significant increases in 2010 and 2011 were driven by changes in estimation and detailed reviews of expected future costs. The majority of these increases related to our sites in Trinidad, the Gulf of Mexico and the North Sea.

The Gulf of Mexico was impacted by the Bureau of Ocean Energy Management, Regulation and Enforcement’s (BOEMRE) Notice to Lessees (NTL) 2010-G05, issued in October 2010, which requires that idle infrastructure on active leases is decommissioned earlier than previously was required and establishes guidelines to determine the future utility of idle infrastructure on active leases.

In 2012 additions to the decommissioning provision were less than in 2011, although still significant, and were again driven by detailed reviews of expected future costs. The majority of the additions related to our sites in the North Sea, Alaska, the Gulf of Mexico and Angola.

We undertake periodic reviews of existing provisions. These reviews take account of revised cost assumptions, changes in decommissioning requirements and any technological developments.

Provisions for environmental remediation and decommissioning are usually established on a discounted basis, as required by IAS 37 ‘Provisions, Contingent Liabilities and Contingent Assets’.

Further details of decommissioning and environmental provisions appear in Financial statements – Note 36 on page 235.

 

 

 

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Respecting human rights

In 2012 we developed a human rights policy in consultation with businesses and functions, and we expect to launch it in 2013. The policy builds on commitments in our code of conduct regarding communities, workforces and the supply chain and we expect to report annually on its implementation. See page 56 for further information about our code of conduct.

We understand our responsibility to respect the human rights of the communities and workforces with whom we interact. BP supports the Universal Declaration of Human Rights, which lays out the rights to which all human beings are entitled. Our policy sets out our commitment to respect all internationally recognized human rights, including those set out in the International Bill of Human Rights and the International Labour Organization’s Declaration on Fundamental Principles and Rights at Work.

We are a signatory to two voluntary agreements with implications for specific aspects of human rights: the UN Global Compact, which includes principles on protecting internationally proclaimed human rights, and the Voluntary Principles on Security and Human Rights, which define good practice for security operations in the extractive industry.

In 2011 we used external consultants to carry out a comparison between our current policies and practices and the expectations in the Guiding Principles. In 2012 we used the findings to create an action plan designed to achieve closer alignment with the Guiding Principles over a number of years. Planned actions include:

 

  Developing and implementing human rights training prioritizing specific businesses and functions.

 

  Developing guidance on integrating human rights into impact assessments and community grievance processes.

 

  Embedding human rights requirements into our procurement and supply chain management processes.

A steering committee has provided oversight for the development of the planned actions.

We are participating in the work of oil and gas industry organization IPIECA’s human rights taskforce, and are contributing our experience to develop practical guidance for the industry on integrating human rights into impact assessments and community grievance processes.

More information about our approach to human rights may be found at bp.com/humanrights.

Revenue transparency and business ethics

As a member of the Extractive Industries Transparency Initiative (EITI), we work with governments, non-governmental organizations and international agencies to improve transparency on revenue disclosures. In several countries that are in the process of becoming EITI compliant, BP is supporting the process. For example, BP is an active member of the Trinidad & Tobago EITI steering committee. In countries that have achieved EITI compliance, including Azerbaijan and Norway, BP submits an annual report on payments to their governments.

We have taken part in consultations in relation to new or proposed revenue transparency reporting requirements in the US and Europe for companies in the extractive industries. BP will comply with the relevant laws and regulations in force.

We are working to respond effectively to the standards arising from the UK Bribery Act as well as other anti-corruption legislation such as the Foreign Corrupt Practices Act and certain regulations promulgated under the Dodd-Frank Wall Street Reform and Consumer Protection Act in the US.

Bribery and corruption are serious risks in the oil and gas industry. Our code of conduct requires that our employees or others working on behalf of BP do not engage in bribery or corruption in any form in both the public and private sectors. We operate a group-wide anti-bribery and corruption standard, which applies to all BP employees and contractors. The standard requires annual bribery and corruption risk assessments; due diligence on all parties with whom BP does business; appropriate anti-bribery and corruption clauses in contracts; and the training of personnel in anti-bribery and corruption measures.

Enterprise and community development

We run a range of programmes to build the skills of businesses in places where we work and to develop the local supply chain. The programmes can benefit local companies by empowering them to reach the standards needed to supply BP and other organizations. For example, we provide training and share standards in areas such as health and safety. At the same time BP benefits from the local sourcing of goods and services.

BP’s social investments, the contributions we make to social and community programmes in locations where we operate, support development activities that aim for a meaningful and sustainable impact. We look for social investment opportunities that are relevant to local needs, aligned with BP’s business, and offer partnerships with local organizations. The programmes we support include building business skills and developing enterprise, supporting education and other community needs and sharing technical expertise with local and national host governments. In a few locations we also support small community infrastructure programmes that help people improve their access to basic resources such as drinking water and public health services. We work with local authorities, community groups and specialists to deliver these community programmes.

Our direct spending on community programmes in 2012 was $90.6 million, which included contributions of $31.7 million in the US, $16.3 million in the UK (including $6.9 million to UK charities, of which $4.8 million for arts and culture, and $2.1 million for education), $2.3 million in other European countries and $40.3 million in the rest of the world, including disaster relief. These reported amounts exclude social bonuses paid by BP to governments as part of licence acquisition costs and that have been capitalized as intangible assets on the group balance sheet. In such cases the group has no direct oversight of the expenditure. Contributions relating to economic recovery following the Deepwater Horizon oil spill are also excluded, see page 60 for details of these contributions.

 

 

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Employees

To be sustainable as a business, BP needs employees who have the right skills for their roles and who understand the values and expected behaviour that guide everything we do as a group.

 

LOGO

 

Number of employees at 31 Decembera      US         Non-US         Total   

2012

        

Upstream

     9,500         14,500         24,000   

Downstreamb

     11,900         39,400         51,300   

Other businesses and corporate

     1,900         8,400         10,300   

Gulf Coast Restoration Organization

     100                 100   
       23,400         62,300         85,700   

2011

        

Upstream

     8,900         13,300         22,200   

Downstreamb

     12,000         39,000         51,000   

Other businesses and corporate

     1,900         8,200         10,100   

Gulf Coast Restoration Organization

     100                 100   
       22,900         60,500         83,400   

2010

        

Upstream

     7,900         13,200         21,100   

Downstreamb

     12,400         39,900         52,300   

Other businesses and corporate

     1,700         4,500         6,200   

Gulf Coast Restoration Organization

     100                 100   
       22,100         57,600         79,700   

 

a  Reported to the nearest 100.
b  Includes 14,700 (2011 14,600 and 2010 15,200) service station staff, all of whom are non-US.

We had approximately 85,700 employees at 31 December 2012, compared with approximately 83,400 at the same time in 2011. During 2012 our headcount has increased by about 3%. This is a result of a focused effort to re-shape the business and strengthen capability.

Our values

Our values of safety, respect, excellence, courage and one team align explicitly with BP’s code of conduct and translate into the responsible actions necessary for the work we do every day. Our values represent the qualities and actions we wish to see in BP, they guide the way we do business and the decisions we make.

We work with our employees to raise their awareness of our values and to help them embed the values in all activities. In 2012 we worked on embedding BP’s values into many of our group-wide systems and processes, including our recruitment, promotion and development assessments. See bp.com/values for more information.

People policies

The group people committee, chaired by the group chief executive, has overall responsibility for key policy decisions relating to employees. In 2012 subjects discussed included longer-term people priorities; quarterly reviews of progress in our diversity and inclusion programme; the rolling out and embedding of our revised performance review procedures; and the continuing development of our learning programmes.

We have a good understanding of our future demand for people and where they will come from. Building our employees’ capability is a priority, as is rewarding them in a way that aligns with our goals. We focus on ensuring the safety of our employees, engaging with them, and increasing the diversity of our workforce so that it reflects the societies in which we operate.

Attracting and retaining our people

The increasing demand for energy products and the complexity of our projects means that attracting and retaining skilled and talented people is vital to the delivery of our strategy and plans.

In support of this, the group chief executive and each member of the executive team hold regular review meetings to ensure that appropriate plans to build capability are in place and that a rigorous and consistent succession process is followed for all group leadership roles.

To supplement our existing internal capability, we also target experienced and skilled professionals in the external market and are continuing to increase our intake of graduates to create a strong internal talent pipeline for the future. We have tailored training programmes for graduates and post-graduates to develop BP’s future leaders.

Our graduate development programme currently has around 1,600 participants. To address increasing demands for skilled people outside the US and UK, more than 40% of 2013’s graduate recruitment is targeted at universities in growing markets. We invest in universities worldwide to further develop the quality of our potential recruits.

We conduct external assessments for all new hires into BP at senior levels and for internal promotions to senior level and group leader level roles. These assessments help ensure rigour and objectivity in our hiring and talent processes. They give an in-depth analysis of leadership behaviour, intellectual capacity and the required experience and skills for the role in question.

Building enduring capability

We provide development opportunities for all our employees, including external and on-the-job training, international assignments, mentoring, team development days, workshops, seminars and online learning. We encourage all employees to take at least five training days a year.

We continue to work to embed appropriate leadership behaviours throughout our organization. By 2012 our group-wide suite of management development programmes, managing essentials, had been attended by employees from 74 countries, in four regions and in 10 different languages.

We provide world-class education opportunities for our people, partnering with 19 academies and institutes that deliver technical learning and development.

Meeting the expectations of our people

We have reviewed our reward strategy, including how the group incentivizes business performance, with the aim of encouraging excellence in safety, compliance and operational risk management. In annual performance reviews all staff are required to set priorities for themselves in these three areas.

We encourage employee share ownership. For example, through our ShareMatch plan run in around 50 countries, we match BP shares purchased by our employees. We have also consolidated our equity plans into one single company-wide plan, and extended this to more junior members of staff. The plan is linked to the company’s performance, with the same measure for everyone.

We aim to treat employees affected by divestments, mergers, acquisitions and joint ventures fairly and with respect, through open and regular communication. When divestments do occur, BP seeks the same or comparable pay and benefits for employees transferring to other companies.

 

 

 

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Diversity and inclusion

We are a global company and aim for a workforce that is representative of the societies in which we operate. For our employees to be properly motivated and to perform to their full potential, and for the business to thrive, our people need to be treated with respect and dignity, and without discrimination.

Through living our values we create an inclusive working environment where everyone can make a difference and give their best. Our work on diversity and inclusion is overseen by the group people committee who reviews performance on a quarterly basis. The committee agrees strategic direction and group standards which are then implemented through business-specific diversity and inclusion plans. In 2012 we launched a framework to set out our ambition and drive further progress across the group. It includes statements of wide-ranging improvements we hope to achieve by 2016.

By 2020, more than half our operations are expected to be in non-OECD countries and we see this as an opportunity to develop a new generation of experts and skilled employees. At the end of 2012, 17% of our group leaders were female and 22% came from countries other than the UK and the US. When we started tracking the composition of our group leadership in 2000, these percentages were 9% and 14% respectively. We supported the UK government-commissioned Lord Davies review in 2011, which made recommendations on increasing gender diversity on the boards of listed companies. See page 113 – governance report.

We are also incorporating detailed diversity and inclusion analysis into talent reviews, with processes to identify actions where any issues are found. We continue to increase the number of local leaders and employees in our operations so that they reflect the communities in which we operate and this is monitored at a local, business or national level.

We aim to ensure equal opportunity in recruitment, career development, promotion, training and reward for all employees, including those with disabilities. Where existing employees become disabled, our policy is to provide continuing employment and training wherever practicable.

Employee engagement

Executive team members hold regular town-hall style meetings and webcasts to communicate with our employees around the world.

Team meetings and one-to-one meetings are complemented by formal processes through works councils in parts of Europe. These communications, along with training programmes, are designed to contribute to employee development and motivation by raising awareness of financial, economic, ethical, social and environmental factors affecting our performance. The group seeks to maintain constructive relationships with labour unions.

We conduct an annual survey of our employees – with more than 55,000 employees in around 70 countries for 2012 – to monitor employee engagement and identify areas where we can improve this. The 2012 results show levels of engagement are up across all levels and business areas.

Business leadership teams review the results of the survey and agree actions to address the identified issues. Safety scores remain strong although there is more work for us to do in continuing to embed our OMS as the way BP operates so people fully understand what it means for them.

We also measure how engaged our employees are with our strategic priorities of safety, trust and value. The group priorities engagement measure is derived from 12 questions about employee perceptions of BP as a company and how it is managed in terms of leadership and standards. Aggregate results for these questions showed a 4% improvement on 2011 to 71%.

Alongside engagement, a new indicator of employee and workplace satisfaction was introduced in 2012, replacing the previous employee satisfaction index (ESI). This new measure is more comprehensive than the previous index and looks at management behaviour, job satisfaction, development and reward. The aggregate score for employee and workplace satisfaction in 2012 was 71%. For comparison, the ESI, based on a narrower set of measures, rose by 4% to 66%.

The BP code of conduct

The BP code of conduct sets the standard that all BP employees are required to work to. It is based on our values and it clarifies the ethics and compliance expectations for everyone who works at BP.

The code defines what BP expects of its people in key areas such as safety, workplace behaviour, bribery and corruption and financial integrity. The code is based on four foundations: what we do, what we stand for, what we value and speaking up.

Employees, contractors or other third parties who have questions or concerns that laws, regulations or the code of conduct may be breached, can get help through OpenTalk, a helpline that is operated by an independent company. The number of cases raised through OpenTalk in 2012 was 1,295, compared with 796 in 2011. In the US, former district court Judge Stanley Sporkin acts as an ombudsperson. Employees and contractors can contact him confidentially to report any suspected breach of compliance, ethics or the code of conduct, including safety concerns.

We take steps to identify and correct areas of non-compliance and take disciplinary action where appropriate. In 2012, 424 dismissals were reported by BP’s businesses for non-adherence to the code of conduct or unethical behaviour compared with 529 in 2011. This excludes dismissals of staff employed at our retail service station sites, for incidents such as thefts of small amounts of money. A new reporting process to capture information on dismissals is presently being put in place for 2013.

Following the settlement with the US government of all federal criminal claims related to the Gulf of Mexico, BP has agreed to appoint an ethics monitor in the US for a term of four years to review and provide recommendations for the improvement of BP’s code of conduct and its implementation and enforcement.

BP continues to apply a policy that the group will not participate directly in party political activity or make any political contributions, whether in cash or in kind. We review employees’ rights to political activity in each country where we operate. For example, in the US, BP facilitates staff participation in the political process by providing staff support to ensure BP employee political action committee contributions are publicly disclosed and comply with the law.

 

 

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Technology

BP develops and deploys technology to find and produce more hydrocarbons, improve conversion efficiency and build new lower-carbon businesses.

Technology investment

 

LOGO

 

2012 highlights:

 

    We spent $674 million on research and development (R&D) in 2012, supporting business priorities across our portfolio.

 

    We successfully progressed a suite of technologies aimed at improving safety and operational risk management. Highlights include: demonstration of our real-time blowout preventer (BOP) monitoring tool offshore Brazil; digital radiography to assess the integrity of subsea systems in the North Sea; and deployment of Permasense® corrosion probes to monitor the wall thickness of equipment in refineries in real time.

 

    We announced plans to deploy LoSal enhanced oil recovery technology at our Clair Ridge development in the UK North Sea, which we believe will lead to significantly increased amounts of recoverable oil (see Salt reduction promises healthy returns on page 17).

 

    We awarded first contracts for Project 20K, a multi-year initiative to develop next-generation systems and tools to unlock high pressure oil and gas resources in deep water.

 

    We began construction of a new High-Performance Computing (HPC) centre in Houston, designed to ensure BP remains at the forefront of subsurface imaging technology.

 

    We licensed our latest-generation purified terephthalic acid (PTA) and paraxylene (PX) technologies to non-affiliated third-parties for the first time, and sold our third licence for Veba combi-cracking (VCC) technology.

 

    In lubricants, we launched new Castrol products: EDGE with Titanium to deliver enhanced protection under extreme conditions; and Magnatec Hybrid to tackle the challenges of engines working with hybrid and stop/start powertrains.

 

    We are investing $100 million over 10 years to set up the International Centre for Advanced Materials (ICAM) to fund research into fundamental understanding and use of advanced materials, from self-healing coatings to membranes, across the energy industry.

How we manage technology

We define technology in BP as the practical application of science to manage risks, capture business value and inform strategy development. This includes the research, development, demonstration and acquisition of new technical capabilities and support for the deployment of BP’s know-how.

Our investments are focused on safe operations and areas of competitive advantage: access to resources, process efficiency, product formulation and lower-carbon opportunities.

In 2012 we invested $674 million in R&D (2011 $636 million). (See Financial statements – Note 13 on page 210.)

The group technology function provides input to BP’s strategy, oversees our major technology programmes, supports technology development and deployment across the company, builds science capability and conducts long-term research.

The technology advisory council, comprised of eminent business and academic technology leaders, provides the board and executive management with an independent view of BP’s capabilities judged against the highest industrial and scientific standards.

BP has more than 2,000 scientists and technologists across the group, with seven major technology centres in the US, the UK and Germany.

We also access external expertise through various forms of partnership and collaboration, from joint research agreements to venturing. We have a strategic approach to university relationships across our portfolio for the purposes of research, recruitment, policy insights and education.

Long-term research programmes

International Centre for Advanced Materials (ICAM)

In 2012 BP announced the establishment of ICAM, a $100-million 10-year research partnership to fund research aimed at advancing the fundamental understanding and use of advanced materials from self-healing coatings to membranes, across a variety of energy and industrial applications. The University of Manchester will be the ‘hub’ for a network of world-class academic institutions, with the University of Cambridge, Imperial College London and the University of Illinois at Urbana-Champaign already participating.

Energy Sustainability Challenge (ESC)

BP is partnering with leading research universities to establish trusted peer-reviewed data on the relationships between natural resource usage and energy. The ESC is a multi-disciplinary research programme, aimed at building a better understanding of natural resource constraints on energy production and consumption – including land, water and mineral resources.

Initial findings of the ESC suggest that energy-related natural resource constraints can be managed, but doing so will not be easy, and will require wise policy decisions and technology choices. The next phase of the research will focus on a number of specific natural resource challenges for our businesses and operations across the world.

More information on the ESC can be found at

bp.com/energysustainabilitychallenge.

The Energy Biosciences Institute (EBI)

The EBI is BP’s largest external R&D collaboration, with up to $500-million funding over 10 years for a multi-disciplinary research effort with the University of California Berkeley, the Lawrence Berkeley National Laboratory, and the University of Illinois at Urbana-Champaign. Its goal is to perform groundbreaking research aimed at the development of next-generation biofuels, as well as other bioscience applications to the energy sector. Now in its fifth year, the EBI is generating multiple innovations, particularly in the field of cellulosic conversion.

Massachusetts Institute of Technology Energy Initiative (MITEI)

In 2012 BP renewed its commitment to the MITEI through an agreement to provide another $25 million for continued energy research over the next five years, bringing the company’s total programme funding to $50 million. The MITEI conducts multi-disciplinary research aimed at tackling complex energy challenges such as increasing energy supply, improving efficiency, and addressing environmental impacts of

 

 

 

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energy consumption. To date, the initiative has sponsored hundreds of energy projects ranging from unconventional sources of hydrocarbons to renewables and nuclear fusion.

Energy Technologies Institute (ETI)

BP is a founding member of the UK’s Energy Technologies Institute – a public/private partnership established in 2008 to accelerate lower-carbon technology development. By the end of 2012 the ETI had commissioned more than $281 million of work covering 41 projects across a wide range of technologies.

Upstream

Our upstream technologies support BP’s business strategy by:

 

 

    Focusing on safety and operational risks.

 

    Helping to obtain new access.

 

    Increasing recovery and reserves.

 

    Improving production efficiency.

Our strengths in exploration, deep water, giant fields and gas are underpinned by dedicated flagship technology programmes. These undertake proprietary scientific research to develop industry-leading technologies such as imaging, enhanced recovery and real-time data capabilities. (See Upstream technology flagships on page 18.)

In 2012:

 

  We began construction of a new HPC centre in Houston, our laboratory for processing and analysing seismic images. BP’s investment in the new 110,000 square foot (10,209 square metres) facility will help drive seismic imaging beyond the methods we know today, extending BP’s scientific and technical capability. The facility is due for completion in mid-2013.

 

  The BP Well Advisor suite of technologies aims to bring wells online more efficiently and enhance safety through providing real-time information for decision making. A major programme is under way to develop and deploy BP Well Advisor tools, from casing running, already installed in Azerbaijan, to BOP monitoring in Brazil, cementing in the North Sea and pressure testing in the Gulf of Mexico. These integrated systems provide consoles for the rig crew and onshore engineers to monitor operations in real-time, during well construction and over the life of the well. BP has selected Kongsberg as vendor for the consoles, which will provide a standard interface for drilling teams across the world. In 2012 we continued industry-first field trials of our BOP diagnostic tool on the Ensco DS4 rig offshore Brazil. This technology has been shared with the industry and with the US Bureau of Safety and Environmental Enforcement.

 

  In February 2012 we announced the launch of Project 20K, a multi-year initiative to develop next-generation systems and tools to help recover high-pressure, high-temperature deepwater oil and gas resources. We intend to develop technologies over the next decade in four key areas: well intervention and containment; well design and completions; drilling rigs, riser and BOP equipment; and subsea production systems. In November 2012 we awarded the first contracts for Project 20K to KBR and FMC Technologies. KBR will develop programme execution and management plans, including capital cost and schedule estimates, risk assessments and technical designs. FMC Technologies will participate in a technology development agreement in which it will work jointly with BP to design and develop 20,000 pounds per square inch rated subsea production equipment, including a subsea production tree and a subsea high integrity pressure protection system.