20-F 1 d633137d20f.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

 

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

For the fiscal year ended 31 December 2013

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 2014   New York Stock Exchange
Floating Rate Guaranteed Notes due May 2015   New York Stock Exchange
Floating Rate Guaranteed Notes due November 2015   New York Stock Exchange
Floating Rate Guaranteed Notes due 2016   New York Stock Exchange
Floating Rate Guaranteed Notes due May 2018   New York Stock Exchange
Floating Rate Guaranteed Notes due September 2018   New York Stock Exchange
Floating Rate Guaranteed Notes due 2019   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
1.375% Guaranteed Notes due 2018   New York Stock Exchange
2.241% Guaranteed Notes due 2018   New York Stock Exchange
1.846% Guaranteed Notes due 2017   New York Stock Exchange
4.750% Guaranteed Notes due 2019   New York Stock Exchange
2.237% 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
2.750% Guaranteed Notes due 2023   New York Stock Exchange
3.994% Guaranteed Notes due 2023   New York Stock Exchange
3.814% Guaranteed Notes due 2024   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


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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

     20,426,632,529   

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  x

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  x

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  x    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  x                 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:

International Financial Reporting

Standards as issued by the

U.S. GAAP  ¨ International Accounting Standards Board  x 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  x

 

 

 

 


Table of Contents

Annual Report and

Form 20-F 2013

bp.com/annualreport

LOGO

 

 

LOGO

Building a stronger,

safer BP

 

LOGO


Table of Contents

 

Who we are

 

BP is one of the world’s leading integrated oil and
gas companies.a We aim to create long-term value
for shareholders by helping to meet growing
demand for energy in a safe and responsible way.
We strive to be 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. We employ more than 80,000 people, mostly in Europe and the US.    As a global group, our interests and activities are held or operated through subsidiaries, branches, joint arrangements or associates established in – and subject to the laws and regulations of – many different jurisdictions. The UK is a centre for trading, legal, finance, research and technology and other business functions. We have well-established operations in Europe, the US, Canada, Russia, South America, Australasia, Asia and parts of Africa.      
  

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

     

 

     

 

LOGO   

|

Front cover imagery

Our second BP-operated development in Angola consists of four oil fields – Plutăo, Saturno, Vénus and Marte (PSVM).

 

Left image: the converted hull, floating, production, storage and offloading vessel (FPSO) has 1.6 million barrels of storage capacity.

 

Centre image: a PSVM mechanical technician takes part in a site visit on board the vessel.

 

Right image: the hawser is a 75 metre rope that we use to tie the tanker to the back of the FPSO.

     

Your feedback

 

We welcome your comments and feedback on our reporting. Your views are important to us and help us shape our reporting for future years.

 

You can provide this at

bp.com/annualreportfeedback or by emailing or writing to the corporate reporting team. Details are on the back cover. For every survey completed, we will make a £2 donation to the British Paralympic Association.

BP Annual Report and Form 20-F 2013

 


Table of Contents

BP in 2013    

 

Our actions continue to make
BP stronger and safer. We are
growing shareholder returns
through operational efficiency
and financial discipline. We
report on our progress here.

        

Information about this report

 

       
   

 

1

 

  

 

Strategic report

  
    2    BP at a glance    25    Upstream   
    6    Chairman’s letter    31    Downstream   
    8    Group chief executive’s letter    35    Rosneft   
    10    Our market outlook    37    Other businesses and corporate   
    12    Our business model    38    Gulf of Mexico oil spill   
    13    Our strategy    41    Corporate responsibility   
    18    Our key performance indicators    49    Our management of risk   
    20    Our approach to executive directors’
remuneration
   51    Risk factors   
          56    Liquidity and capital resources   
    22    Group performance         
               
   

 

59

 

  

 

Corporate governance

  
    60    Board of directors    77    Safety, ethics and environment assurance committee   
    66    Executive team         
    69    Governance overview    78    Gulf of Mexico committee   
    71    How the board works    79    Nomination committee   
    72    Board effectiveness    80    Chairman’s committee   
    73    Shareholder engagement    81    Directors’ remuneration report   
    74    Audit committee    109    Regulatory information   
               
               
               
   

 

115

 

  

 

Financial statements

  
    120   

Consolidated financial statements of the BP group

   200    Supplementary information on oil and natural gas (unaudited)   
   

126

  

Notes on financial statements

        
               
               
               
               
               
               
               
               
LOGO    

 

235

 

  

 

Additional disclosures

  
    236    Selected financial information    267    Further note on certain activities   
    239    Upstream analysis by region    268    Material contracts   
    242    Downstream analysis by region    268    Property, plant and equipment   
    245    Oil and gas disclosures for the group    268    Related-party transactions   
    252    Environmental expenditure    269    Exhibits   
    252    Contractual obligations    269    Certain definitions   
    253    Regulation of the group’s business    271    Directors’ report information   
    257    Legal proceedings    271    Cautionary statement   
               
   

 

273

 

  

 

Shareholder information

  
    274    Called-up share capital    278    Fees and charges payable by ADSs holders   
    274    Share prices and listings         
    274    Dividends    279    Fees and payments made by the Depositary to the issuer   
    275    UK foreign exchange controls on dividends         
          279    Documents on display   
    275    Shareholder taxation information    280    Administration   
    277    Major shareholders    280    Annual general meeting   
    278    Purchases of equity securities by the issuer and affiliated purchasers         
               
               
               
   

 

282

  

 

Cross reference to Form 20-F

       

 

BP Annual Report and Form 20-F 2013   i


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.

bcf

Billion cubic feet.

bcf/d

Billion cubic feet per day.

bcfe

Billion cubic feet equivalent.

bcma

Billion cubic metres per annum.

b/d

Barrels per day.

boe

Barrels of oil equivalent.

GAAP

Generally accepted accounting practice.

Gas

Natural gas.

Hydrocarbons

Liquids 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.

mmcf

Million cubic feet.

mmcf/d

Million cubic feet per day.

MW

Megawatt.

NGLs

Natural gas liquids.

PSA

Production-sharing agreement.

RC

Replacement cost.

SEC

The United States Securities and

Exchange Commission.

Therm

100,000 British thermal units.

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 2013. A cross reference to Form 20-F requirements is included on page 282.

 

The BP Annual Report and 20-F 2013 reflects a number of significant changes in regulations in the UK. The most significant change is the requirement to produce a new strategic report that replaces the previous business review. The regulations require certain new disclosure to be included in the strategic report including a description of company’s strategy and business model – we have included a more focused and graphical presentation of BP’s strategy and business model in this report, compared with the 2012 report.

 

This document contains the Strategic report on pages 1-58 and the inside cover (Who we are section) and the Directors’ report on pages 59-80, 109-114, 116, 200-223 and 235-280. The Strategic report and the Directors’ report together include the management report required by DTR 4.1 of the UK Financial Conduct Authority’s Disclosure and Transparency Rules. The Directors’ remuneration report is on pages 81-108. The consolidated financial statements of the group are on pages 115-199 and the corresponding reports of the auditor are on pages 120-121.

 

BP Annual Report and Form 20-F 2013 and BP Strategic Report 2013 (comprising the Strategic report and supplementary information) 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 2013 or BP Strategic Report 2013 (comprising the Strategic report and supplementary information), forms any part of those documents. References in this document to other documents on the BP website, such as the BP Energy Outlook, are included as an aid to their location and are not incorporated by reference into this document.

 

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 non-controlling 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 (NYSE) in the form of ADSs (see page 274 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 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:

    

 

Aral

ARCO

BP

Castrol

Castrol EDGE

Field of the Future

Fluid Strength Technology

Hummingbird

 

  

LoSal

Project 20K

SaaBre

Veba Combi-Cracking (VCC)

Permasense is a trade mark of Permasense Limited.

Pick n Pay is a registered trademark of
Pick n Pay Stores 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’.

  
       

 

ii    BP Annual Report and Form 20-F 2013


Table of Contents

 

 

 

Strategic
report

 

An overview of the key
activities, events and results
in 2013, together with
commentary on BP’s
performance in the year and
our priorities as we move
forward.

    2   

BP at a glance

 

 

   
      6   

Chairman’s letter

 

 

   
      8   

Group chief executive’s letter

 

 

   
      10   

Our market outlook

 

 

   
      12   

Our business model

 

 

   
      13   

Our strategy

 

 

   
      18   

Our key performance indicators

 

 

   
      20   

Our approach to executive directors’ remuneration

 

 

   
      22   

Group performance

 

 

   
      25   

Upstream

 

 

   
      31   

Downstream

 

 

   
      35   

Rosneft

 

 

   
      37   

Other businesses and corporate

 

 

   
      38   

Gulf of Mexico oil spill

 

 

   
    LOGO        41    Corporate responsibility    
          

 

41

 

 

Safety

 

   
           44   Environment and society    
           47   Employees    
        49   

Our management of risk

 

 

   
        51   

Risk factors

 

 

   
        56   

Liquidity and capital resources

 

 

   
                
                
                
                
                
                
                
                
                
   

 

BP Annual Report and Form 20-F 2013      1

   

 

 

  


Table of Contents

BP at a glance

 

LOGO

 

2    BP Annual Report and Form 20-F 2013


Table of Contents

 

LOGO

 

BP Annual Report and Form 20-F 2013   3


Table of Contents

BP around the world

 

LOGO

 

4    BP Annual Report and Form 20-F 2013


Table of Contents

 

LOGO

 

BP Annual Report and Form 20-F 2013   5


Table of Contents

Chairman’s letter

 

LOGO

 

10-year dividend history

UK (pence per ordinary share)

 

LOGO   

 

US (cents per ADS)

 

LOGO

 

One ADS represents six 25 cent ordinary shares.

  

Dear fellow shareholder,

 

In 2013 BP continued the programme of renewal we began following the crisis of 2010. The measures taken to secure and reshape the group are taking hold. As this report shows, BP is stronger and safer as a result.

 

Change within the group has taken place against the backdrop of a rapidly evolving world. The energy landscape is developing at pace, for example, the growth of shale gas in the US. But the long-term supply challenge has not gone away. More energy is required to meet the needs and aspirations of a rising global population. The BP Energy Outlook projects an average increase in energy demand of 1.5% per year through to 2035. That’s like adding the needs of a country twice the size of the US over the next twenty years.

 

We are also seeing that society has ever higher expectations of business. This is reflected in the increasing scrutiny placed on the commercial sector, particularly by politicians and the media. Companies must work hard to maintain people’s trust and respect.

 

Shareholders’ expectations are shifting too, particularly in the extractive industries sector. Some investors feel that international oil companies have spent too much for too little return. A decade of mergers and acquisitions in our industry has generated little production growth. Capital expenditure has increased but profit margins have been squeezed. Rightly, shareholders expect better returns.

 

The board recognizes this changing world and the importance of our response. Throughout 2013 we gave close attention to strategy, project appraisal and capital discipline, working with Bob Dudley and his team to ensure the group spends its money wisely. BP’s strategy is rooted in three imperatives: clear priorities, a quality portfolio and distinctive capabilities.

 

Our first clear priority is to run safe and reliable operations. We must also make disciplined financial choices, selecting the smart options that can help meet demand and generate value. Furthermore, we must be competitive in how we execute our projects.

 

Our quality portfolio, which is at the core of our strategy, is the result of the choices we make. It contains assets that enable us to play to our areas of greatest strength, from exploration to high-value upstream projects – particularly deepwater operations, giant fields and gas value chains – and high-quality downstream businesses.

 

To these assets and activities we apply our distinctive capabilities – the expertise of our people, advanced technology and the ability to build the strong relationships required to access resources and deliver complex projects.

 

In all of this, we are focused on value before volume. In other words we don’t simply chase production for the sake of it, rather we choose projects where we can generate the most value through our production.

 

We know we must be disciplined, sticking to clear limits on capital expenditure, and balancing rewards for shareholders today with the long-term capital investment required for tomorrow. Safety and strong governance must underpin everything we do.

 

2013 was a busy and successful year for BP, with progress in our underlying operations. Our growing confidence was reflected in the dividend increase announced in October

 

6    BP Annual Report and Form 20-F 2013


Table of Contents

LOGO    Board performance

         For information about the board and its

         committees see page 71.

 

LOGO   Remuneration

         For information about our approach to

         executive directors’ remuneration see

         page 20.

 

 

 

Top: Members of BP’s safety, ethics and environment assurance committee (SEEAC) visited Canada to see the oil sands operations at the Sunrise project site and meet local community leaders and staff.

 

Bottom: Members of SEEAC travelled to the Gelsenkirchen refinery in Germany to speak with apprentices and control room operators about risk management and processes.

 

LOGO   

  

2013 – the third increase in two years. We also returned value to shareholders through the $8-billion share repurchase programme announced in March 2013. Additional distributions are planned as we make further divestments to reshape our portfolio. The milestones set for 2014 will be an important measure of progress and your board is monitoring this closely.

 

I am particularly pleased that in 2013 we completed our transaction with Rosneft, closing one chapter in Russia and opening another. This is an important investment with the potential to create substantial value for BP over the years to come.

 

2013 also saw the shocking attack at the In Amenas facility in Algeria. Our thoughts remain with the families and friends of those who died. The response of management to this tragedy was strong and the board acted positively and promptly.

 

We continue to address uncertainty in the US. In 2013, we once again met our responsibilities to the region by paying legitimate claims arising from the 2010 accident and oil spill in the Gulf of Mexico. And we met our responsibilities to shareholders by challenging and resisting any attempt to take advantage of BP with claims that are not legitimate. We will fight through the courts until matters are resolved properly, however long that takes. In the meantime, the board is working to ensure that BP is not distracted from growing the business and creating shareholder value.

 

Boards set the tone and values that shape performance and behaviour over the long term. An effective board creates an enduring framework within which management can lead. Having been through challenging times, the BP board has grown into a strong team with experienced non-executives drawn from relevant industries. This year, more than ever, they have been out to see BP’s operations for themselves, from India to Indiana. We continue to be assisted on geopolitical matters by the international advisory board.

 

Our approach to governance has enabled us to focus on critical strategic issues, with our board committees taking on the many oversight and compliance matters that require attention.

 

Remuneration continues to be a board matter of particular importance to shareholders, with executive pay policy now subject to a vote at the annual general meeting. BP has a record of ensuring there are clear links between strategy, performance and remuneration. This will continue.

 

I believe diversity helps to strengthen the effectiveness of a board. We plan succession well ahead and are developing a pipeline of potential board candidates. We are committed to progress and finding the right people for our board.

 

I would like to end by thanking you, our shareholders, for your continued support. I also want to acknowledge the people who drive your company forward every working day. From Bob Dudley and his management team to employees across the business; our people are doing a great job of transforming BP. Their hard work has moved us forward, with the promise of more to come.

 

LOGO

 

Carl-Henric Svanberg

Chairman

6 March 2014

  
  
  
  
  
  
  

 

BP Annual Report and Form 20-F 2013      7   


Table of Contents

Group chief executive’s letter

 

LOGO

 

95.3%

 

2013 refining availability.

 

129%

 

Reserves replacement ratio, excluding the impact of acquisitions and divestments.

See footnote b on page 14.

    

 

Dear fellow shareholder,

 

For BP, 2013 was a year of good progress in building a safer, stronger and better performing company. We made new discoveries, started up new operations, strengthened our portfolio and secured a new future in Russia. We also maintained our investment in the US while standing up for what we believe to be right.

 

Within BP, sadly, 2013 will also be remembered for the terrorist attack in Algeria in January, when four staff members and 36 colleagues from other companies were killed. Those who died had many friends in BP and our thoughts remain with their loved ones, and with those who survived that terrible ordeal. I was proud of the way people in BP responded – with great compassion, but also with great fortitude.

 

This report contains a wealth of information on our performance. I would like to draw out a few of the year’s highlights, all of which demonstrate how we are implementing our strategy, with its emphasis on clear priorities, a quality portfolio and distinctive capabilities.

 

Clear priorities: safety, capital discipline, project execution

The first of our priorities is to run safe and reliable operations. In 2013 we made good progress overall, but unfortunately we also suffered two driving-related fatalities as well as the loss of the four employees murdered at In Amenas. Our thoughts are with those who have been bereaved. We will implement the lessons learned.

 

In terms of general safety performance, however, we saw some encouraging progress. The number of tier 1 process safety events – the most significant incidents – fell to 20 from 43 in 2012 and 74 in 2011. We are definitely heading in the right direction, but there is always more to do and we remain vigilant.

 

We also saw improvements in measures that reflect the underlying health of our business. For example, in upstream BP-operated plant efficiencya reached 88%, and refining availability in downstream averaged 95.3% – the highest level for 10 years. These numbers reinforce my view that safety and value have the same roots: systematic, disciplined operations, undertaken by people who respect each other and work as one team.

 

In terms of capital discipline, in 2013 we invested $24.6 billionb, which kept us within our $25-billion limit, and we expect to keep capital expenditure broadly the same in 2014. We know we have to invest wisely so we maintain our shareholders’ trust.

 

Turning to project execution, we saw three upstream major projects start up in 2013 – in the Gulf of Mexico, Angola and Australia. Three more followed closely in the first months of 2014 – the Chirag oil project in Azerbaijan and the Mars B and Na Kika Phase 3 projects in the Gulf of Mexico.

 

Quality portfolio

Beyond these start-ups, we extended our portfolio as a platform for growth in several other ways.

 

For example, we grew our exploration position by participating in seven potentially commercial discoveries, in Angola, Brazil, Egypt, India and the Gulf of Mexico. We also drilled 17 exploration wells, more than in the previous two years put together. BP has built up great skills in finding oil and gas and we are seeing the results of investing in our explorers.

 

And in the US lower 48 – which excludes Alaska and Hawaii – we intend to create a separate BP business to manage our onshore oil and gas assets, which we believe will help to unlock the significant value associated with our extensive resource position there.

 

8    BP Annual Report and Form 20-F 2013


Table of Contents

LOGO   Our strategy

         For more on our strategic priorities and

         longer-term objectives see page 13.

 

 

 

 

Top: Bob Dudley and Iraq Oil Minister Abdul Karim Al Luaibi (right) being shown the first meter to be installed on one of the wells in Kirkuk. In October BP signed an agreement with the government of Iraq on providing technical assistance relating to the Kirkuk oil field.

 

Bottom: Investors see how BP manages the risks of deepwater drilling at a field trip in Houston. They tested our well simulator which gives rig operators a better understanding of both prevention and response techniques.

 

LOGO   

 

a See footnote a on page 25.

b Excludes acquisitions and Rosneft transaction.

c  See page 247 for further information.

d See footnote c on page 56.

e See footnote b on page 56.

  

Our reserves replacement ratio was 129% of production. When we include the net growth in our Russian portfolio as a result of the change of our holdings, the reserves replacement ratio on a combined basis was 199%.c

 

In the Downstream, we completed the commissioning of all major units for the Whiting refinery. This landmark modernization programme, our fourth major project start-up in 2013, is turning what began as a 19th century plant into a truly 21st century one. It is now able to compete strongly by processing a wide range of crudes, including heavy oil from Canada.

 

More generally, our Downstream business has transformed its shape over the last five years. In the US, we have sold two facilities and we now have three modern refineries that are well configured and well connected to important markets. In lubricants, 40% of revenue now comes from our premium brands. In petrochemicals, we are also focusing on high-growth regions and new technologies.

 

Distinctive capabilities

New acetic acid and ethylene technologies announced by the petrochemical team in 2013 are among a series of innovations we have developed in support of our exploration, production, refining and marketing activities. These include advanced seismic imaging capacity – using one of the world’s largest civilian supercomputers – enhanced oil recovery techniques and leading lubricant processes.

 

Our technologies are complemented by the capabilities of our people, which we continue to deepen through training and development, and our experience in building and maintaining relationships.

 

New future in Russia

Relationships have been vital in securing a new future for BP in Russia as a 19.75% shareholder in Rosneft. Rosneft is implementing its strategy for growth across a promising portfolio and paid us a dividend of $456 million in 2013. We look forward to exploring opportunities for BP to work with Rosneft in the years ahead.

 

Making our case in the US

BP has continued to meet its commitment to environmental and economic restoration in the Gulf of Mexico. We have also been swift to counter illegitimate claims and to argue for a fair resolution to compensation matters. By the end of the year the total cumulative cost to the company had reached $42.7 billion, the scale of that amount underlining once again that BP is living up to its responsibilities in the region and to the US as a whole. The US remains vitally important to today’s BP, with around 20,000 employees across the country and we estimate that our economic activity supports a further 240,000 additional jobs. Nearly 40% of our shares are held in the US, and we invest more there than in any other country.

 

Looking ahead

We are a smaller but stronger company, having divested $38 billion of assets over three years. In October we announced that we would divest around a further $10 billion of assets before the end of 2015 – a decision that reflects our commitment to balancing reinvestment with rewards for our shareholders. We expect to use the proceeds predominantly for distributions to shareholders, with a bias to share buybacks.

 

Our unrelenting focus on capital discipline and systematic operating is increasing the free cash flowd we have available. We are on track to meet our goal of generating more than $30 billion of operating cash flow in 2014, an increase of more than 50% on 2011.e

 

I’m looking forward to 2014 with great confidence. I think you will see a re-energized and refocused BP – a company that is set to become stronger and safer in every way, as we fulfil our mission of delivering energy to customers and value to shareholders.

 

LOGO

 

Bob Dudley

Group Chief Executive

6 March 2014

 

BP Annual Report and Form 20-F 2013     9   


Table of Contents

Our market outlook

 

We believe that a diverse mix of fuels and technologies will
be essential to meet the growing demand for energy
and the challenges facing our industry.

 

  
LOGO       LOGO
 



Our third PTA plant in Zhuhai, China, is planned to begin production in late 2014. It is expected to bring total capacity at the site to more than 2.7 million tonnes per year.

 

{

Thunder Horse in the Gulf of Mexico is one of the largest integrated offshore drilling and production platforms in the world.

  

Population and economic growth are the main drivers of global energy demand. The world’s population is projected to increase by 1.7 billion from 2012 to 2035, with real income likely to more than double over the same period.

 

Therefore, the overall trend is likely to be one of increased energy demand, even with energy and climate policies and a shift towards less energy-intense activities in fast-growing economies. We expect demand for energy to increase by as much as 41% between 2012 and 2035.

 

Challenges and opportunities

 

We seek energy sources that have the following attributes:

 

Affordability – meeting growing demand for secure and sustainable energy presents an affordability challenge. Fossil fuels will become increasingly difficult to access and many lower-carbon resources will remain costly to produce at scale.

 

Security – each country knowing where its supplies will come from. More than 60% of the world’s known reserves of natural gas are in just five countries and at least 80% of global oil reserves are located in nine countries, most of which are distant from the hubs of energy consumption. This represents a security challenge in its own right.

 

Sustainability – avoiding an unacceptable environmental and social impact that ultimately negates the economic benefits. While energy is available to meet growing demand, action is needed to limit carbon dioxide (CO2) and other greenhouse gases emitted through fossil fuel use.

  

A diverse mix

 

We believe a diverse mix of fuels and technologies can enhance national and global energy security while supporting the transition to a lower-carbon economy. These are reasons why BP’s portfolio includes oil sands, shale gas, deepwater oil and gas, and biofuels.

 

Oil and natural gas

Oil and natural gas are likely to play a significant part in meeting demand for several decades.

 

We believe these energy sources will represent about 54% of total energy consumption in 2035. Even under the International Energy Agency’s most ambitious climate policy scenario (the 450 scenario), oil and gas would still make up 47% of the energy mix in 2035.a 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.

 

We expect oil to remain the dominant source for transport fuels, accounting for as much as 87% of demand in 2035.

 

Natural gas, in particular, is likely to play an increasingly strategic role. Shale gas is expected to contribute 47% of the growth in global natural gas supplies between 2012 and 2035. The shale gas revolution has already had a significant impact on gas prices and demand in the US and may encourage similar developments elsewhere although the scale and speed of the roll out of shale gas technology will vary between countries. When used in place of coal for power, natural gas can reduce CO2 emissions by half.

 

a From World Energy Outlook 2013. © OECD/International
 Energy Agency 2013, page 573.

 

LOGO 2013 pricing

       See Upstream on page 26 and

       Downstream on page 32.

     

 

10    BP Annual Report and Form 20-F 2013


Table of Contents

 

LOGO

 

BP Energy Outlook contains our projections of future energy trends and factors that could affect them, based on our views of likely economic and population growth and developments in policy and technology. Available in PDF, Excel and video format.

 

LOGO See bp.com/energyoutlook.

 

 

Energy consumption by region

(billion tonnes of oil equivalent)

 

LOGO

 

Source: BP Energy Outlook 2035.

 

Energy consumption by fuel

(billion tonnes of oil equivalent)

 

LOGO

 

* Includes biofuels.

Source: BP Energy Outlook 2035.

  

New sources of hydrocarbons are more difficult to reach, extract and process. BP and others in our industry are working to improve techniques for maximizing recovery from existing and currently inaccessible or undeveloped fields. In many cases, the extraction of these resources might be more energy intensive, which means operating costs and greenhouse gas emissions from operations may also increase.

 

Renewable energy

Renewables will play an increasingly important role in addressing the challenges of energy security and climate change over the long term. Renewables are already the fastest-growing energy source, but they are starting from a low base.

 

By 2035, we estimate renewable energy, excluding large-scale hydro electricity, is likely to meet around 7% of total global energy demand.

 

Energy efficiency and innovation

 

Greater efficiency addresses several aspects of the energy challenge. It helps with affordability – because less energy is needed. It helps with security – because it reduces dependence on imports. And it helps with sustainability – because it reduces emissions.

 

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 technologies and combustion engines that use biofuels could offer the most cost-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. This includes secure access for exploration and development

  

of energy resources, mutual benefits for resource owners and development partners, and 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 a 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. A global carbon price should be the long-term goal, but regional and national approaches are a good first step, provided temporary financial relief is given to sectors that are exposed to international competition.

 

Beyond 2035

 

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.

 

LOGO Strategy

        Find out how BP can help meet energy

        demand for years to come on

        page 13.

 

LOGO

 



Air BP is one of the world’s largest aviation fuels suppliers, marketing aviation fuels and specialist products in more than 45 countries. It sells over seven billion gallons of fuel per year.

 

BP Annual Report and Form 20-F 2013     11   


Table of Contents

Our business model

 

We aim to create shareholder value across the

hydrocarbon value chain.

 

  
LOGO       LOGO
 



Toledo refinery in Ohio has been in constant operation since 1919. The facility has the capacity to process up to 160,000 barrels of crude per day.

 

{

The redevelopment project at Valhall was one of
BP’s most complex field expansion
developments and gives the field a further
40-year design life.

  

A rising global population and increasing levels of prosperity are set to create growing demand for energy for years to come. We can help to meet that demand by producing oil and gas safely and reliably.

 

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. We aim to create value for our investors and benefits for the communities and societies in which we operate, with the responsible supply of energy playing a vital role in economic development.

 

Every stage of the hydrocarbon value chain offers 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. In renewable energy our focus is on integrating biofuels into the hydrocarbon value chain, and on wind operations in the US.

  

Our approach spans everything from exploration to marketing. Integration across the group allows us to share functional excellence more efficiently across areas such as safety and operational risk, environmental and social practices, procurement, technology and treasury management.

 

A relentless focus on safety remains 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.

 

LOGO Our businesses

        For more information on our upstream,

        downstream and alternative energy

        businesses, see pages 25, 31 and 37

        respectively.

Our business model

 

Finding oil

and gas

  g      Developing and extracting   g    

Transporting

and trading

  g     Manufacturing and marketing

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

     When we find hydrocarbon resources, we create value by seeking to progress them into proved reserves or by divesting if they do not fit with our strategy. If we believe developing and producing the reserves will be advantageous for BP, we produce the oil and gas, then sell it to the market or distribute it to our downstream facilities.     We move oil and gas through pipelines and by ship, truck and train. Using our trading and supply skills and knowledge, we buy and sell at each stage in the value chain. Our presence across major trading hubs gives us a good understanding of regional and international markets and allows us to create value through entrepreneurial trading.     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 illustrated business model see page 2.

 

 

12    BP Annual Report and Form 20-F 2013


Table of Contents

Our strategy

 

Our goal is to be a focused oil and gas company that

delivers value over volume.

 

  

LOGO

 

a  See footnote a on page 56.

b  Equivalent to net cash used in investing activities.

c  See footnote c on page 56.

d  See footnote h on page 24.

e  Excludes acquisitions and asset exchanges.

f   Unit cash margin is net cash provided by operating activities

    by the relevant projects in our Upstream segment, divided

    by the total number of barrels of oil equivalent produced

    for the relevant projects.

 

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

h  See footnote b on page 56.

i   See footnote d on page 56.

  

We are pursuing our strategy by setting clear priorities, actively managing a quality portfolio and employing our distinctive capabilities. Our financial objective is to create shareholder value by generating sustainable free cash flow (operating cash flow less net investment). This disciplined approach enables us to invest for the future while aiming to increase distributions to our investors.

 

Clear priorities

 

First, we aim to run safe, reliable and compliant operations – leading to better operational efficiency and safety performance. We also aim to achieve competitive project execution, which is about delivering projects efficiently so they are on time and on budget. And we aim to make disciplined financial choices, so we can achieve continued growth in operating cash from our underlying businesses and disciplined allocation of capital.

 

Quality portfolio

 

We undertake active portfolio management to concentrate on areas where we can play to our strengths. This means we continue to grow our exploration position, reloading our upstream pipeline. We focus on high-value upstream assets in deepwater, giant fields and selected gas value chains. And, with our downstream businesses, we plan to leverage our newly upgraded assets, customer relationships and technology to grow free cash flow.

  

Our portfolio of projects and operations is focused where we can generate the most value, and not necessarily the most volume, through our production.

 

Distinctive capabilities

 

Our ability to deliver against our priorities and build the right portfolio depends on our distinctive capabilities. We apply advanced technology across the hydrocarbon value chain, from finding resources to developing energy-efficient and high-performance products for customers. We rely on our strong relationships – with governments, partners, civil society and others – to enable our operations in around 80 countries across the globe. And, the proven expertise of our employees comes to the fore in a wide range of disciplines.

 

LOGO Our strategy in action

        See page 14 for more information

        on how we are going to measure our

        progress.

  

 

10-point plan 2011-2014

 

In 2011 we laid out a 10-point plan designed to stabilize the company and restore trust and value in response to the tragic Deepwater Horizon accident. Our priority was to make BP a safer, more risk-aware business. The plan included a series of milestones by which our progress could be tracked, from 2012 through to 2014. Information on our progress during 2013 can be found in Group performance on page 22.

 

  

 

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.

  

 

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 marginsf around double the 2011 average by 2014.g

 

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

 

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 gearingi in the lower half of the 10-20% range over time.

 

BP Annual Report and Form 20-F 2013     13   


Table of Contents

Our strategy in action

 

LOGO

 

14    BP Annual Report and Form 20-F 2013


Table of Contents

LOGO

 

     

LOGO

 

     

LOGO

 

We prioritize the safety and reliability of our operations to protect the welfare of our workforce and the environment. This also helps preserve value and secure our right to operate around the world.     Recordable injury frequency, loss of primary containment, greenhouse gas emissions, tier 1 process safety events.     LOGO  

A commitment to

safe operations

Toledo refinery sets

a safety record.

 

LOGO See page 42.

 

31

fewer reported losses

of primary containment

than 2012.

We rigorously screen our investments and we work to keep our annual capital expenditure within a set range. Ongoing management of our portfolio helps ensure focus on more value-driven propositions. We balance funds between shareholder distributions and investment for the future.    

Operating cash flow,

gearinga, total shareholder

return, replacement cost

profit (loss) per ordinary

share.

    LOGO  

Maximizing value

at Mad Dog

Changing plans to make the best financial choices.

 

LOGO See page 29.

 

$21.1bn

operating cash flow.

We seek efficient ways to deliver projects on time and on budget, from planning through to day-to-day operations. Our wide-ranging project experience makes us a valued partner and enhances our ability to compete.       Major project delivery.       LOGO  

Increasing oil production

in Azerbaijan

Local construction of BP’s heaviest platform in the Caspian Sea.

 

LOGO See page 48.

 

 

4

major project start-ups

in Upstream and

Downstream.

We target basins and prospects with the greatest potential to create value, using our leading subsurface capabilities. This allows us to build a strong pipeline of future growth opportunities.    

Reserves replacement

ratio.b

    LOGO  

Discovering gas in India

Two significant discoveries with Reliance Industries.

 

LOGO See page 30.

 

129%

reserves replacement

ratio.

We are strengthening our portfolio of high return and longer life assets – across deep water, giant fields and gas value chains – to provide BP with momentum for decades to come.    

Production.c

    LOGO  

Preparing for Shah Deniz Stage 2

Largest gas sales contracts in Azerbaijan’s history.

 

LOGO See page 27.

 

3.2

million barrels of oil

equivalent per day.

We benefit from our high-performing fuels, lubricants, petrochemicals and biofuels businesses. Through premium products, powerful brands and supply and trading, Downstream provides strong cash generation for the group.     Refining availability.     LOGO  

Creating our North American advantaged refinery

Modernization project improves utilization and margin capture at Whiting.

 

LOGO See page 33.

 

95.3%

refining availability.

 

 

 

Creating shareholder value by generating

sustainable free cash flow

 

 

 

 

LOGO    LOGO    LOGO
   
Advanced technology    Strong relationships    Proven expertise
We develop and deploy technologies
we expect to make the greatest impact on
our businesses – from enhancing the safety
and reliability of our operations to creating
competitive advantage in energy discovery,
recovery, efficiency and products.
   We form enduring partnerships in the
countries in which we operate, building strong
relationships with governments, customers,
partners such as Rosneft, suppliers and
communities to create mutual advantage.
Co-operation helps unlock resources found in
challenging locations and transforms them into
products for our customers.
  

We attract and develop the talented people
required to drive our business forward.

They apply their diverse skills and expertise
to deliver complex projects across all areas
of our business.

 

BP Annual Report and Form 20-F 2013

  15


Table of Contents

Our distinctive capabilities

 

LOGO

 

We use technology to find and produce more hydrocarbons, improve our processes for converting raw materials and develop lower-carbon products.

 

The development of technology from research and development through to wide-scale deployment can take several years. For example, to reach the next generation of deepwater oil reserves, where rock pressures can reach 20,000 pounds per square inch, we are developing new subsea technologies through our Project 20K.

 

Technology programmes in our upstream business include advanced seismic imaging to help us find more oil and gas and enhanced oil recovery to get more from existing fields. New techniques are making recovery of unconventional oil and gas, like shale, economically viable.

 

LOGO See bp.com/technology.

 

LOGO

 



The Pangbourne technology centre is home to chemists and liquid engineers dedicated to providing products and services for Castrol’s customers.

 

We focus our downstream technology programmes on the safety, integrity and performance of our refineries and petrochemical plants and on creating high quality, energy efficient, cleaner fuels, lubricants and petrochemicals.

 

BP employs more than 2,000 scientists and technologists.

 

Our long-term research programmes with universities and research institutions around the world are exploring areas from reservoir fluid flow to energy biosciences. We have a strategic approach to university relationships across our portfolio for the purposes of research, recruitment, policy insights and education.

 

In 2013 we invested $707 million in research and development (2012 $674 million). See Financial statements – Note 8.

  LOGO
 

 

LOGO Seismic imaging

 

We use our imaging expertise to increase the productivity and quality of the data we capture on land and offshore. With 80% of future offshore oil and gas reserves thought to be under salt canopies up to 7 kilometres high, our new supercomputer in Houston helps to reduce the completion times for imaging jobs from several months to a matter of days.

 

 

 

LOGO Enhanced oil recovery (EOR)

 

Our LoSal EOR technology can help develop previously unexploited resources from existing oil fields. LoSal uses water with a low salt content to release more molecules of oil from the sandstone rock where they are held.

 

 

LOGO Production optimization

 

Our Field of the Future technologies provide real-time information to help manage operational risk, improve plant equipment reliability and optimize production. We use these technologies to monitor more than 600 wells.

 

LOGO Shipping efficiency

 

Our ‘virtual arrival’ system can reduce fuel consumption and emissions by allowing vessels, ports and other parties to work together and agree an optimum arrival time for each vessel.

 

 

LOGO

 

Our employees enable BP to deliver our strategy and meet our commitments to investors, partners and the wider world.

 

Our people are talented in a wide range of disciplines, from geoscience, mechanical engineering and research technology to government affairs, trading, marketing, legal and others. And our approach to professional development programmes and training helps build individual capabilities, reducing a potential skills gap. This is vital in a world where oil and gas companies face an increasing challenge to find and retain skilled and experienced people.

 

We aim to achieve a balance between building internal expertise and recruiting external professionals and graduates. We have a strong, experienced leadership team and a pipeline of talent for the future.

   LOGO

 

16    BP Annual Report and Form 20-F 2013


Table of Contents

 

LOGO

 

LOGO Improved conversion

 

Our Veba Combi-Cracking technology converts a wide variety of raw materials, ranging from crude oil residue to mixtures of coal and oil, into fuels. Using this technology we can convert 95% or more of our hydrocarbon resources to marketable products.

  

LOGO Fuels and lubricants

 

We focus on providing energy-efficient and high-performance products to customers. Castrol EDGE, which is underpinned by our proprietary Fluid Strength Technology, reduces contact between engine surfaces to improve performance and reduce wear from friction.

  

LOGO Biofuels

 

Conversion technology allows us to produce cellulosic ethanol using alternative raw materials such as agricultural waste and fast-growing energy grasses. At our biofuels technology centre in San Diego around 120 scientists are researching and advancing new biofuels technologies.

LOGO Corrosion prevention

 

Wireless Permasense® systems, developed in collaboration with Imperial College, London, are used across all our refineries to monitor the integrity of critical oil and gas assets.

  

LOGO Petrochemicals

 

Our SaaBre technology converts synthesis gas (carbon monoxide and hydrogen derived from hydrocarbons) into acetic acid. The process avoids the need to purify carbon monoxide or purchase methanol, reducing manufacturing costs and environmental impacts.

  

 

LOGO

 

Our relationships are crucial to the success of our business. We work closely with governments, national oil companies and other resource holders. By acting responsibly and meeting our obligations we build long-lasting relationships.

 

From experience we know that trust can be lost, so we place enormous importance on meeting people’s expectations. We work in partnership on big and complex projects with everyone from other oil companies through to suppliers and

  

contractors. Our activity creates value that benefits governments, customers, local communities and other partners.

 

Internally we put together collaborative teams of people with the skills and experience needed to address complex issues, work effectively with our partners and help create shared value.

   LOGO

 

BP Annual Report and Form 20-F 2013   17


Table of Contents

Our key performance indicators

 

We assess the group’s performance according to a wide range of measures and indicators. Our key performance indicators (KPIs) help the board and executive management measure performance against our strategic priorities and 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

This year, we introduced two new KPIs: tier 1 process safety events and major project delivery. These demonstrate two of our strategic objectives and are used as measures for executive remuneration.

 

We have removed the number of oil spills as a group KPI as this is reflected within the loss of primary containment and tier 1 process safety events KPIs. We continue to report on oil spills, see Safety on page 41.

 

Remuneration

To help align the focus of our board and executive management with the interests of our shareholders, certain measures are reflected in the variable elements of executive remuneration.

 

Overall annual bonuses, deferred bonuses and performance shares are all based on performance against measures and targets linked directly to strategy and KPIs. For details of our remuneration policy see page 96.

 

 

LOGO KPIs used to measure

       progress against our

       strategy.

 

LOGO KPIs used to determine 2013

and 2014 remuneration.

 

LOGO

  

Replacement cost profit (loss) per ordinary share (cents)

LOGO

 

Replacement cost profit (loss) is a useful measure for investors because it is a profitability measure BP management use to assess performance and allocate resources.

 

It reflects the replacement cost of supplies and is calculated by removing inventory holding gains and losses and their associated tax effect from profit. This is a non-GAAP measure for the group. The IFRS equivalent can be found on page 236.

 

2013 performance The increase in replacement cost profit per ordinary share for the year compared with 2012 reflected the gain on disposal of our interest in TNK-BP.

  

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.

 

2013 performance Higher operating cash flow in 2013 reflected a lower cash outflow relating to the Gulf of Mexico oil spill, partly offset by higher cash outflows as a result of working capital build.

  

Gearing (net debt ratio) (%)

 

LOGO

 

Our gearing (net debt ratio) shows investors how significant net debt is relative to equity from shareholders in funding BP’s operations.

 

We aim to keep our gearing within the 10-20% range to give us the flexibility to deal with an uncertain environment.

 

Gearing is calculated by dividing net debt by total equity plus net debt. Net debt is equal to gross finance debt, plus associated derivative financial instruments, less cash and cash equivalents. Net debt and net debt ratio are non-GAAP measures. See Financial statements – Note 28 for the nearest equivalent measure on an IFRS basis and for further information.

 

2013 performance Gearing at the end of 2013 was 16.2%, down 2.5% on 2012 and within our target band of 10-20%.

  

 

  

Refining availability (%)

 

LOGO

 

Refining availability represents Solomon Associates’ operational availability. The measure shows the percentage of the year that a unit is available for processing after deducting the time spent on turnaround activity and all mechanical, process and regulatory maintenance downtime.

 

Refining availability is an important indicator of the operational performance of our Downstream businesses.

 

2013 performance Refining availability increased by 0.5% from 2012 to 95.3% reflecting strong operations around our global refining portfolio.

  

Reported recordable injury

frequencya

LOGO

 

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

 

The measure gives an indication of the personal safety of our workforce.

 

2013 performance Our workforce RIF, which includes employees and contractors combined, was 0.31, compared with 0.35 in 2012 and 0.36 in 2011. These successive reductions are encouraging and we continue pursuing improvement in personal safety.

  

Loss of primary containmenta

 

LOGO

 

Loss of primary containment (LOPC) is the number of unplanned or uncontrolled releases of oil, gas or other hazardous materials from a tank, vessel, pipe, railcar or other equipment used for containment or transfer.

 

By tracking these losses we can monitor the safety and efficiency of our operations as well as our progress in making improvements.

 

2013 performance Our reported LOPC shows 31 fewer reported incidents in 2013 than in 2012, with divestments accounting for a significant part of the reduction. We remain committed to using our operating management system to further improve our operations.

 

18    BP Annual Report and Form 20-F 2013


Table of Contents

Total shareholder return (%)

 

LOGO

 

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

 

We are committed to maintaining a progressive and sustainable dividend policy.

 

2013 performance TSR grew as a result of increases in both the BP share price and in the dividend, with the improvement for ordinary shares slightly offset by exchange rate effects.

  

Reserves replacement ratio (%)

 

LOGO

 

Proved reserves replacement ratio is the extent to which the year’s production has been replaced by proved reserves added to our reserve base.

 

The ratio is expressed in oil-equivalent terms and includes changes resulting from discoveries, improved recovery and extensions and revisions to previous estimates, but excludes changes resulting from acquisitions and disposals. The ratio reflects both subsidiaries and equity-accounted entities.

 

The measure helps to demonstrate our success in accessing, exploring and extracting resources.

 

2013 performance The increase in our reserves replacement ratio included the impact of final investment decisions on two significant upstream projects in Oman and Azerbaijan.

  

Major project delivery

 

LOGO

 

Major projects are defined as large-scale projects with a high degree of complexity and a BP net investment of at least $250 million.

 

We monitor the progress of our major projects to gauge whether we are delivering our core pipeline of activity. Projects take many years to complete, requiring differing amounts of resource, so a smooth or increasing trend should not be anticipated.

 

2013 performance In total we delivered four major projects. Three started up in Upstream – Atlantis North expansion Phase 1 in the Gulf of Mexico; Angola LNG; and North Rankin Phase 2 in Australia, and one in Downstream – the Whiting refinery modernization project.

  

Production (mboe/d)

 

LOGO

 

We report the volume of crude oil, condensate, natural gas liquids (NGLs) and natural gas produced by 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.

 

2013 performance BP’s total reported production including our Upstream segment, and our share of TNK-BP (from 1 January to 20 March) and Rosneft (from 21 March to 31 December), was 3% lower than in 2012. This was mainly due to the effect of divestments in Upstream.

                

Tier 1 process safety eventsa

 

 

LOGO

 

We report tier 1 process safety events (PSE), which are the losses of primary containment of greatest consequence – causing harm to a member of the workforce, costly damage to equipment or exceeding defined quantities.

 

2013 performance Our reduction in reported tier 1 PSEs is supported by our efforts to drive improvement in process safety. Divestments also account for part of the reduction. We are aware there is always more to do to improve.

 

a   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.

  

Greenhouse gas emissions

(million tonnes of CO2 equivalent)

 

LOGO

 

We report greenhouse gas (GHG) emissions material to our business on a carbon dioxide-equivalent basis. This includes CO2 and methane for direct emissions.b Our GHG reporting encompasses all BP’s consolidated entities as well as our share of equity-accounted entities other than BP’s share of TNK-BP and Rosneft. Rosneft’s emissions data can be found on its website.

 

2013 performance Our total greenhouse gas emissions decreased by 18%, primarily due to the divestment of our Texas City and Carson refineries.

 

b For indirect emissions data see page 45.

  

Group priorities engagementc (%)

 

LOGO

 

We track how engaged our employees are with our strategic priorities for building long-term value. The measure is derived from answers to 12 questions about BP as a company and how it is managed in terms of leadership and standards.

 

2013 performance We saw continued improvement in 2013, and there was an increase in understanding of our operating management system, an area of focus identified the previous year. While the survey showed an increase in employee confidence in BP’s leadership, work is needed to further strengthen this.

 

c  Relates to BP employees.

  

Diversity and inclusionc d (%)

 

LOGO

 

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

 

This means we can track progress in building a diverse and well-balanced leadership team, helping to create a sustainable pipeline of diverse talent for the future.

 

2013 performance We have increased the percentage of female leaders again this year and have extended our focus on diversity and inclusion beyond the board and group leaders to include other levels of management.

 

d Minor amendments have been made to

  2012.

 

BP Annual Report and Form 20-F 2013   19


Table of Contents

Our approach to executive

directors’ remuneration

Remuneration is directly linked to strategy and performance, with

particular emphasis on matching rewards to results over the long term.

 

A simple approach   
Total remuneration is determined by a relatively simple approach to attract and retain high calibre executives. The largest components are share based and vest over a number of years – further aligning executives’ interests with those of our shareholders.    LOGO

 

LOGO

 

 

Underpinned by six key principles

The remuneration policy for executive directors and the

decisions of the remuneration committee of the board

are guided by six key principles:

 

 

 

1 Linked to strategy

A substantial portion of executive remuneration is linked to success in implementing the company’s strategy.

Strategic priorities and group key performance indicators (KPIs) provide key metrics for the performance shares and deferred bonus, and are focused through the annual plan to provide the measures for annual bonus.

 

 

LOGO

LOGO

 

 

 

 

2 Performance related

The major part of total remuneration varies with performance, with the largest elements share based, further aligning interests with shareholders.

High pay requires high performance. Achieving the maximum pay requires sustained high performance over several years.

LOGO

 

 

20    BP Annual Report and Form 20-F 2013


Table of Contents

 

3 Long-term based

The structure of pay is designed to reflect the long-term nature of BP’s business and the significance of safety and environmental risks.

The largest components of total remuneration are share based and vest over the longest period. The deferred bonus plan requires sustained safety and environmental performance

over three years. The matched shares that vest under the plan have an additional three-year retention period, resulting in a six-year time frame. Similarly, performance shares have a six-year time frame – a three-year performance period followed by an additional three-year retention period for those shares that vest.

 

 

LOGO

 

 

4 Informed judgement

There are quantitative and qualitative assessments of performance with the remuneration committee making informed judgements within a framework approved by shareholders.

The committee has a preference for quantifiable targets that can be factually measured and objectively assessed according to well understood principles and definitions. It seeks the views of other relevant committees when arriving at conclusions. It is not constrained when conditions change requiring different perspectives or when unanticipated events, both good and bad, occur.

LOGO

 

 

 

5 Shareholder engagement

The remuneration committee actively seeks to understand shareholder preferences and be transparent in explaining its policy and practice.

During 2013 the remuneration committee chairman met personally with shareholders representing nearly 15% of total outstanding shares. A number of adjustments to policy were made in response to the feedback received (see page 82).

94%

of votes cast were in favour of the 2012 Directors’ remuneration report.

 

 

 

6 Fair treatment

Total overall pay takes account of both the external market and company conditions to achieve a balanced, ‘fair’ outcome.

The committee attempts to balance sometimes conflicting perspectives to arrive at total pay results that not only reflect performance relative to strategy, but also are deemed fair by external stakeholders and employees, as well as the executive team.

LOGO

 

 

BP Annual Report and Form 20-F 2013   21


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Group performance

Our progress in 2013 has set us up well to deliver our

10-point plan and forms the foundations for delivering

value in the long term.

 

LOGO      LOGO
    

~

In May we completed the successful commissioning of a state-of-the-art diesel hydrotreater and hydrogen plant at the Cherry Point refinery in Washington state.

 

{

The Mad Dog field in the Gulf of Mexico was discovered in 1998 and is one of BP’s largest discoveries in the Gulf of Mexico to date.

     We continued to operate within a disciplined financial framework in 2013 – with organic capital expenditurea of $24.6 billion (within the expected $24-$25 billion range). Upstream BP-operated plant efficiencyb of 88% and strong refining availability of 95.3% in Downstream demonstrated our progress in operational efficiency. We completed the transactions to increase our shareholding in Rosneft to 19.75%. And, we are continuing to meet our commitments in the Gulf of Mexico, while making our case in court.
           
    

2013-2014 milestones set out in our 10-point plan

 

     Drilling up to 25 wells per year.
     g   

We completed 17 exploration wells and made seven potentially commercial discoveries in 2013. It was our most successful year for exploration drilling in almost a decade.

 

     A further nine major upstream project start-ups.
     g   

Three major projects were started up in 2013 and another three in January and February 2014. We expect a further four major upstream projects to start up in 2014.

 

     Unit operating cash marginsc from new upstream projects in 2014 are expected to be double the 2011 average.d
     g   

We continued to bring on major projects in key regions such as Angola and the Gulf of Mexico.

 

     Bringing onstream the major upgrade to the Whiting refinery in the second half of 2013.
     g   

We completed the commissioning of all major units for the refinery upgrade, transforming it into one of our advantaged downstream assets in our portfolio.

 

     Completing our $38-billion divestment programme by the end of 2013.
     g   

We completed our $38-billion divestment programme in 2012 – effectively a year early. In October 2013, we announced our plan to divest a further $10 billion before the end of 2015.

 

     We have a high-value, focused portfolio that plays to our strengths.

LOGO  Segment performance

For Upstream and Downstream performance see pages 25 and 31 respectively.

     g   

Our divestments have removed complexity, strengthened the balance sheet and left us with a more distinctive set of assets that play to our strengths – deep water, gas value chains, giant fields and high-quality downstream businesses.

 

     Increasing overall operating cash flowe by 50% in 2014 compared with 2011.f
     g   

We are on track to meet our goal of generating more than $30 billion of operating cash flow in 2014.

 

a Organic capital expenditure excludes acquisitions, asset

  exchanges, and other inorganic capital expenditure.

b See footnote a on page 25.

c  See footnote f on page 13.

d See footnote g on page 13.

e See footnote a on page 56.

f  See footnote b on page 56.

     We expect to use around half of the extra cash for increased investment and around half for other purposes, including increased distributions to shareholders.
     g    As at 31 December 2013 we had bought back 753 million shares for a total amount of $5.5 billion, including fees and stamp duty, since 22 March 2013. The dividend paid in 2013 was 36.5 cents per share, up 30% compared with the dividend of 28 cents per share paid in 2011.

 

 

22    BP Annual Report and Form 20-F 2013


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Group performance and outlook

Financial performance

 

                       $ million   
       2013        2012        2011   

Profit before interest and taxation

     31,769        19,769        39,815   

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

     (1,548     (1,638     (1,587

Taxation

     (6,463     (6,880     (12,619

Non-controlling interests

     (307     (234     (397

Profit for the yeara

     23,451        11,017        25,212   

Inventory holding (gains) losses, net of taxb

     230        411        (1,800

Replacement cost profitc

     23,681        11,428        23,412   

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

     (10,533     5,298        (2,195

Net (favourable) unfavourable impact of fair value accounting effectsd, net of tax

     280        345        (47

Underlying replacement cost profitc

     13,428        17,071        21,170   

Capital expenditure and acquisitions

     36,612        25,204        31,959   

 

LOGO

Profit for the year ended 31 December 2013 was $23,451 million. After adjusting for $230 million in respect of inventory holding losses and their associated tax effect, replacement cost (RC) profit was $23,681 million. After further adjusting for a net credit of $10,533 million for non-operating items and unfavourable fair value accounting effects (relative to management’s measure of performance) of $280 million, both net of tax, underlying RC profit was $13,428 million.

Non-operating items in 2013, on a pre-tax basis, were mainly relating to the $12.5-billion gain on disposal of TNK-BP partially offset by an $845-million write-off attributable to block BM-CAL-13 offshore Brazil as a result of the Pitanga exploration well not encountering commercial quantities of oil or

gas, impairment charges and further charges associated with the Gulf of Mexico oil spill. More information on non-operating items, and fair value accounting effects, can be found on page 237. See Gulf of Mexico oil spill on page 38 and Financial statements – Note 2 for further information on the impact of the Gulf of Mexico oil spill on BP’s financial results.

For the year ended 31 December 2012, profit was $11,017 million, RC profit was $11,428 million and underlying RC profit was $17,071 million. There was a net post-tax charge of $5,298 million for non-operating items, which included a $5.0-billion pre-tax charge relating to the Gulf of Mexico oil spill.

Compared with 2012, underlying RC profit in 2013 was impacted by the absence of equity-accounted earnings from TNK-BP and lower earnings from both Downstream and Upstream, partially offset by the equity-accounted earnings from Rosneft from 21 March 2013 (when sale and purchase agreements with Rosneft and Rosneftegaz completed).

For the year ended 31 December 2011, profit was $25,212 million, RC profit was $23,412 million and underlying RC profit was $21,170 million. There was a net post-tax credit for non-operating items of $2,195 million, which included a $3.8-billion pre-tax credit relating to the Gulf of Mexico oil spill.

Compared with 2011, underlying RC profit in 2012 was impacted by significantly lower earnings from Upstream and the absence of equity-accounted earnings from TNK-BP from 22 October 2012 (when our investment was reclassified as an asset held for sale, as required under IFRS), partially offset by improved earnings from Downstream.

See Upstream on page 25, Downstream on page 31, Rosneft on page 35 and Other businesses and corporate on page 37 for further information on segment results.

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.

Net finance expense relating to pensions and other post-retirement benefits in 2013 was $480 million (2012 $566 million, 2011 $400 million).

In 2013, we adopted the revised version of IAS 19 ‘Employee Benefits’, under which we apply the same expected rate of return on plan assets as we used to discount our pension liabilities. Financial information for prior periods has been restated – see Financial statements – Note 1 for further information.

Taxation

The charge for income taxes in 2013 was $6,463 million (2012 $6,880 million, 2011 $12,619 million). The effective tax rate was 21% in 2013 (2012 38%, 2011 33%). The decrease in the effective tax rate in 2013 compared with 2012 primarily relates to the gain on disposal of TNK-BP in 2013 for which there was no corresponding tax charge. 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 relating to the Gulf of Mexico oil spill, which is not tax deductible.

 

 

 

a  Profit attributable to BP shareholders.
b  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 segment is shown in Financial statements – Note 7 and further information on inventory holding gains and losses is provided on page 269.
c  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 and underlying RC profit or loss, see Certain definitions on page 269.

 

d  Non-operating items are charges and credits arising in consolidated entities and in TNK-BP and Rosneft that are included in the financial statements and that BP discloses separately because it considers such disclosures to be meaningful and relevant to investors. The main categories of non-operating items included here are: impairments; gains and losses on sale of businesses and fixed assets; environmental remediation costs; restructuring, integration and rationalization costs; and changes in the fair value of embedded derivatives. Fair value accounting effects are non-GAAP adjustments to our IFRS profit relating to certain physical inventories, pipelines and storage capacity. Management uses a fair-value basis to value these items which, under IFRS, are accounted for on an accruals basis with the exception of trading inventories, which are valued using spot prices. The adjustments have the effect of aligning the valuation basis of the physical positions with that of the derivative instruments, which are required to be fair valued under IFRS, in order to provide a more representative view of the ultimate economic value. See page 238 and Certain definitions on page 269 for more information.
 

 

BP Annual Report and Form 20-F 2013    23


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LOGO

Operating cash flow

Operating cash flow is net cash provided by operating activities, as presented in the group cash flow statement on page 125. Operating cash flow in 2013 was $21.1 billion (2012 $20.5 billion, 2011 $22.2 billion). Excluding the impact of the Gulf of Mexico oil spill, net operating cash flow in 2013 was $21.2 billion (2012 $22.9 billion, 2011 $29.0 billion).

Shareholder distributions

Total dividends paid in 2013 were 36.5 cents per share, up 11% compared with 2012 on a dollar basis and 12% in sterling terms. This equated to a total cash distribution to shareholders of $5.4 billion during the year.

Group reserves and production

 

       2013         2012         2011   

Estimated net proved reserves

(net of royalties)a

                          

Liquidsb

     million barrels   

Subsidiaries

     4,349         4,672         5,331   

Equity-accounted entitiesc

     5,721         5,378         5,234   
       10,070         10,050         10,565   

Natural gas

     billion cubic feet   

Subsidiaries

     34,187         33,264         36,381   

Equity-accounted entitiesc

     11,788         7,041         5,278   
       45,975         40,305         41,659   

Total hydrocarbonsd

     million barrels of oil equivalent   

Subsidiaries

     10,243         10,408         11,604   

Equity-accounted entitiesc

     7,753         6,592         6,144   
       17,996         17,000         17,748   

Production (net of royalties)e

                          

Liquidsf

     thousand barrels per day   

Subsidiaries

     879         896         992   

Equity-accounted entitiesg

     1,134         1,160         1,165   
       2,013         2,056         2,157   

Natural gas

     million cubic feet per day   

Subsidiaries

     5,845         6,193         6,393   

Equity-accounted entitiesg

     1,216         1,200         1,125   
     7,060         7,393         7,518   

Total hydrocarbonsd

     thousand barrels of oil equivalent per day   

Subsidiaries

     1,887         1,963         2,094   

Equity-accounted entitiesg

     1,343         1,367         1,360   
       3,230         3,331         3,454   

 

a  Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities.
b  Liquids comprise crude oil, condensate, NGLs and bitumen.
c  Includes BP’s share of Rosneft and TNK-BP reserves. See Rosneft on page 36 and Supplementary information on oil and natural gas on page 200 for further information.
d  Natural gas is converted to oil equivalent at 5.8 billion cubic feet = 1 million barrels.
e  Because of rounding, some totals may not agree exactly with the sum of their component parts.
f  Liquids comprise crude oil, condensate and NGLs.
g  Includes BP’s share of Rosneft and TNK-BP production. See Rosneft on page 36 and Oil and gas disclosures for the group on page 245 for further information.

Total hydrocarbon proved reserves, on an oil equivalent basis including equity-accounted entities, comprised 17,996mmboe (10,243mmboe for subsidiaries and 7,753mmboe for equity-accounted entities) at 31 December 2013, an increase of 6% (decrease of 2% for subsidiaries and increase of 18% for equity-accounted entities) compared with the 31 December 2012 reserves of 17,000mmboe (10,408mmboe for subsidiaries and 6,592mmboe for equity-accounted entities). Natural gas represented about 44% (58% for subsidiaries and 26% for equity-accounted entities) of these reserves. The change includes a net increase from acquisitions and disposals of 641mmboe (200mmboe net decrease for subsidiaries and 841mmboe net increase for equity-accounted entities). Net divestments in our subsidiaries occurred in the UK, the US, China and Canada. We had sales and purchases, as a consequence of our divestment of TNK-BP and investment in Rosneft.

Our total hydrocarbon production during 2013 averaged 3,230 thousand barrels of oil equivalent per day (mboe/d). This comprised 1,887mboe/d for subsidiaries and 1,343mboe/d for equity-accounted entities, a decrease of 4% (decreases of 2% for liquids and 6% for gas) and a decrease of 2% (decrease of 2% for liquids and increase of 1% for gas) respectively compared with 2012.

More information on reserves and production, see Oil and gas disclosures for the group on page 245.

Critical accounting policies

The accounting policies, judgements, estimates and assumptions which most affect the financial statements are described in Note 1 to the financial statements.

Outlook

This discussion contains forward-looking statements, which by their nature 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. You are urged to read Risk factors on page 51 and Cautionary statement on page 271, which describe the risks and uncertainties that may cause actual results and developments to differ materially from those expressed or implied by these forward-looking statements.

We expect net cash provided by operating activities of between $30-$31 billion in 2014.h

We expect capital expenditure, excluding acquisitions and asset exchanges, to be around $24-$25 billion in 2014, and between $24-$26 billion in the years 2015 to 2018.

We will continue to target our net debt ratio in the 10-20% range while uncertainties remain. Net debt is a non-GAAP measure.

Depreciation, depletion and amortization in 2014 is expected to be around $1 billion higher than in 2013.

For 2014, the underlying effective tax rate (ETR) (which excludes non-operating items and fair value accounting effects) is expected to be around 35%, which is the same as the underlying ETR in 2013.

 

 

h  Assumes $100/bbl oil and $5/mmBtu Henry Hub gas. The projection includes BP’s estimate of the Rosneft dividend and the impact of payments in respect of federal criminal and securities claims with the US government and SEC where settlements have already been reached, but 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.
 

 

24    BP Annual Report and Form 20-F 2013


Table of Contents

Upstream

In 2013 we continued to actively manage and simplify our portfolio, strengthening our incumbent positions to provide a platform for growing value.

 

LOGO

 

~

Skarv started up in December 2012 and produces up to 160mboe/d. The field development includes around 50 miles of gas export pipeline that allows export to markets in Europe.

 

 

Our business model and strategy

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. In 2013 our activities took place in 27 countries.

We deliver our exploration, development and production activities through five global technical and operating functions:

 

    The exploration function is responsible for renewing our resource base through access, exploration and appraisal, while the reservoir development function is responsible for the stewardship of our resource portfolio.

 

    The global wells organization and the global projects organization are responsible for the safe, reliable and compliant execution of wells (drilling and completions) and major projects, respectively.

 

    The global operations organization is responsible for safe, reliable and compliant operations, including upstream production assets and midstream transportation and processing activities.

The delivery of these activities is optimized and integrated with support from global functions with specialist areas of expertise: technology, finance, procurement and supply chain, human resources and information technology.

Technologies such as seismic imaging, enhanced oil recovery and real-time data support our upstream strategy by helping to gain new access, increasing recovery and reserves and improving production efficiency (see Our distinctive capabilities on page 16).

We actively manage our portfolio and are placing increasing emphasis on accessing, developing and producing from fields able to provide the greatest value (this includes those with the potential to make the highest contribution to our operating cash flow). We sell assets that we believe have more value 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 strategy is to invest to grow long-term value by continuing to build a portfolio of material, enduring positions in the world’s key hydrocarbon basins. Our strategy is enabled by:

 

    A continued focus on safety and the systematic management of risk.

 

    A simpler, more focused portfolio with strengthened incumbent positions and reduced operating complexity.

 

    Playing to our strengths – exploration, deep water, giant fields and gas value chains.

 

    An execution model that drives improvement in efficiency and reliability – through both operations and investment.

 

    A bias to oil with selective gas value chains focusing on where we have strong core positions, can play in premium growth markets or bring advantaged technology to bear.

 

    Strong relationships built on mutual advantage, deep knowledge of the basins in which we operate, and technology.

 

LOGO

 

Outlook

 

    We have announced plans to establish a separate BP business to manage our onshore oil and gas assets in the US lower 48, which we expect to be operational in early 2015. Our goal is to build a stronger, more competitive and sustainable business that we expect to be a key component of BP’s portfolio in the future.

 

    We expect reported production in 2014 to be lower than 2013, mainly due to the expiration of the Abu Dhabi onshore concession, with an impact of around 140mboe/d, and divestments. After adjusting for the impacts of the concession expiry, divestments and entitlement effects in our production-sharing agreements (PSAs), we expect underlying production to be higher in 2014.

 

    In addition to the Chirag oil, Mars B and Na Kika Phase 3 projects, which started up in January and February, we expect a further four major projects to come onstream in 2014, which will contribute to the group’s plan to generate an increase of around 50% in operating cash flow in 2014 compared with 2011.c

 

    Capital investment in 2014 is expected to increase, largely reflecting the progression of our major projects.

 

a  Plant efficiency is the actual production of a plant facility expressed as a percentage of the total achievable installed production capacity of the asset including the reservoir, well, plant and export systems.
b  Underlying replacement cost (RC) profit before interest and tax is not a recognized GAAP measure. See footnote c on page 23 for further information. The equivalent measure on an IFRS basis is RC profit before interest and tax.
c  See footnote b on page 56.
 

 

BP Annual Report and Form 20-F 2013    25


Table of Contents

Our markets

 

       2013         2012         2011   
Average oil marker pricesa      $ per barrel   

Brent

     108.66         111.67         111.26   

West Texas Intermediate

     97.99         94.13         95.04   
Average natural gas marker prices      $ per million British thermal units   

Average Henry Hub gas priceb

     3.65         2.79         4.04   
       pence per therm   

Average UK National Balancing Point gas pricea

     67.99         59.74         56.33   

 

a All traded days average.
b Henry Hub First of Month Index.

Crude oil benchmark prices

Brent remains an integral marker to the production portfolio, from which a significant proportion of production is priced directly or indirectly. Certain regions use other local markers, which are derived using differentials or a lagged impact from the Brent crude oil price.

Crude oil prices, as demonstrated by the industry benchmark of dated Brent, averaged $108.66 per barrel in 2013, compared with an average of $111.67 per barrel in 2012. This represented the third consecutive year with the dated Brent average price above $100 per barrel. Prices weakened in early 2013 amid strong growth of light, sweet oil production in the US, but rebounded later in the year due to a range of supply disruptions and heightened market perceptions of risks to supply.

Brent ($/bbl)

 

LOGO

Amid continued high oil prices, global oil consumption increased, rising by roughly 1.2 million barrels per day for the year compared with 2012 (1.3%), in part boosted by cold weather early in the year.c The growth in consumption was slightly exceeded by growth in non-OPEC production, which was dominated by continued strong growth in US output. However, OPEC crude oil production fell due to ongoing Iran sanctions and renewed outages in Libya. As a result, OECD commercial oil inventories remained relatively balanced.

Global oil consumption in 2012 grew by roughly 0.9 million barrels per day compared with 2011 (0.9%).d OPEC production met most of the growth in consumption, driven by the recovery in Libyan production.

We expect oil price movements in 2014 to continue to be driven by the pace of global economic growth and its resulting implications for oil consumption, by supply growth in North America, and OPEC production decisions. Risks to supply remain a key uncertainty.

 

c  From Oil Market Report 21 January 2014©, OECD/IEA 2014, page 1.
d  BP Statistical Review of World Energy June 2013.

Natural gas prices

Natural gas prices continued to show wide differentials between regions in 2013, although widening of the differentials stagnated as US gas prices recovered from their 2012 lows. The Henry Hub First of Month Index averaged $3.65 in 2013, an increase of 31% versus 2012.

Henry Hub ($/mmBtu)

 

LOGO

The US natural gas market saw a gradual return to balance in 2013, following the dramatic loss of heating demand in 2012 due to unusually warm winter weather, which pushed gas prices down to 10-year lows. A return to more normal weather in 2013 restored heating demand for gas, which meant less pressure on gas to compete with coal for a share of the power generation market, allowing gas prices to recover. US gas supply continued to expand in 2013, reaching yet another record production level, supported in particular by rising liquids-rich (wet) gas production.

In Europe, gas prices at the UK National Balancing Point increased by 14% to an average of 67.99 pence per therm for 2013. Record-low inventory levels, coming out of a prolonged winter, coupled with declining European gas production and continued diversion of LNG to the higher-priced Asian market, caused European spot prices to climb to a five-year high. European demand remained weak, especially in power generation where gas remained uncompetitive against coal.

Global LNG supply expanded in 2013, following a contraction in supply in 2012. However the LNG market remained tight, with continued strong demand in Asia due to economic growth and nuclear power outages, and also in Latin America due to the impact of a drought on hydroelectric production.

In 2012 the strength of shale gas production in the US, combined with an unusually warm winter, led the average Henry Hub First of Month Index to fall by 31% to $2.79/mmBtu. In the UK, National Balancing Point prices averaged 59.74 pence per therm, 6% above prices in 2011.

In 2014 we expect gas markets to continue to be driven by the economy, weather, production, trade developments and continued uncertainty surrounding nuclear power generation in Japan. Futures markets indicate that the large gap between US and European gas prices is expected to persist through 2014.

 

 

26    BP Annual Report and Form 20-F 2013


Table of Contents

 

LOGO

 

Financial performance

 

       $ million   
       2013         2012        2011   

Sales and other operating revenuese

     70,374         72,225        75,754   

RC profit before interest and tax

     16,657         22,491        26,358   

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

     1,608         (3,055     (1,141

Underlying RC profit before interest and taxg

     18,265         19,436        25,217   

Capital expenditure and acquisitions

     19,115         18,520        25,821   
BP average realizationsh      $ per barrel   

Crude oil

     105.38         108.94        107.91   

Natural gas liquids

     38.38         42.75        51.18   

Liquidsi

     99.24         102.10        101.29   
       $ per thousand cubic feet   

Natural gas

     5.35         4.75        4.69   

US natural gas

     3.07         2.32        3.34   
       $ per thousand barrels of oil equivalent   

Total hydrocarbonsj

     63.58         61.86        62.31   

 

e  Includes sales to other segments.
f  Fair value accounting effects are not a recognized GAAP measure and represent the (favourable) unfavourable impact relative to management’s measure of performance (see page 238 for further details).
g  Underlying RC profit is not a recognized GAAP measure. See footnote c on page 23 for information on underlying RC profit.
h  Realizations are based on sales of consolidated subsidiaries only, which excludes equity-accounted entities.
i  Liquids comprise crude oil, condensate and natural gas liquids (NGLs).
j  Natural gas is converted to oil equivalent at 5.8 billion cubic feet = 1 million barrels.

Sales and other operating revenues for 2013 were $70 billion (2012 $72 billion, 2011 $76 billion). The decrease in 2013, compared with 2012, primarily reflected lower volumes due to disposals and lower realizations, partially offset by higher gas marketing and trading revenues. The decrease in 2012, compared with 2011, primarily reflected lower production and persistently low Henry Hub gas prices.

In 2013 replacement cost (RC) profit before interest and tax for the segment was $16.7 billion (2012 $22.5 billion, 2011 $26.4 billion). The 2013 result included a net non-operating charge of $1,364 million, primarily related to an $845-million write-off attributable to block BM-CAL-13 offshore Brazil as a result of the Pitanga exploration well not encountering commercial quantities of oil or gas, and impairment and other charges partly offset by fair value gains on embedded derivatives and disposal gains. In addition, fair value accounting effects had an

unfavourable impact of $244 million relative to management’s measure of performance. The 2012 result included net non-operating gains of $3,189 million, primarily as a result of gains on disposals being partly offset by impairment charges. In addition, fair value accounting effects had an unfavourable impact of $134 million. The 2011 result included net non-operating gains of $1,130 million, primarily as a result of gains on disposals being partly offset by impairments, a charge associated with the termination of our agreement to sell our 60% interest in Pan American Energy LLC (PAE) to Bridas Corporation and other non-operating items. In addition, fair value accounting effects had a favourable impact of $11 million.

After adjusting for non-operating items and fair value accounting effects, underlying RC profit before interest and tax in 2013 was $18.3 billion (2012 $19.4 billion, 2011 $25.2 billion). Compared with 2012, the decrease in 2013 reflected lower production due to divestments, lower liquids realizations and higher costs, including exploration write-offs and higher depreciation, depletion and amortization, partly offset by an increase in underlying volumes, a benefit from stronger gas marketing and trading activities, a one-off benefit to production taxes as a result of fiscal relief allowing immediate deduction of past costs, a one-off benefit, mainly in respect of prior years, resulting from the US Federal Energy Regulatory Commission approval of cost pooling settlement agreements between the owners of the Trans-Alaska Pipeline System (TAPS) and higher gas realizations. Compared with 2011, the 2012 result reflected higher costs (primarily higher depreciation, depletion and amortization, as well as ongoing sector inflation), lower production and lower realizations.

Total capital expenditure including acquisitions and asset exchanges in 2013 was $19.1 billion (2012 $18.5 billion, 2011 $25.8 billion).

Provisions for decommissioning decreased from $17.4 billion at the end of 2012 to $17.2 billion at the end of 2013. The decrease reflects primarily a reduction due to the change in discount rate and utilization of provisions largely offset by updated estimates of the cost of future decommissioning and additions. Decommissioning costs are initially capitalized within fixed assets and are subsequently depreciated as part of the asset.

Acquisitions and disposals

In total, disposal transactions generated $1.3 billion in proceeds during 2013, with a corresponding reduction in net proved reserves of 200mmboe, all within our subsidiaries. There were no significant acquisitions in 2013.

Disposals

The major disposal transactions during 2013 were the sale of our interests in the Harding (BP 70%), Maclure (BP 37.04%), Braes (BP 27.7%),

 

 

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Major projects portfolio

 

LOGO

 

Braemar (BP 52%) and Devenick (BP 88.7%) fields in the North Sea to TAQA Bratani Ltd for $1,058 million plus future payments which, depending on oil price and production, are currently expected to exceed $180 million after tax; and the sale of our interests in the Yacheng (BP 34.3%) field in China for $308 million, both of which are subject to post-closing adjustments. More information on disposals is provided in Upstream analysis by region on page 239 and Financial statements – Note 5.

Exploration

The group explores for oil and natural gas under a wide range of licensing, joint arrangement and other contractual agreements. We may do this alone or, more frequently, with partners. BP acts as operator for many of these ventures.

New access in 2013

We gained access to new potential resources covering more than 43,000km2 in seven countries (Canada, Brazil, Greenland, Norway, Egypt, the UK and China). In addition, we entered into three farm-out agreements with Kosmos Energy, covering around 25,000km2 over three blocks offshore Morocco, one of which is still subject to government approval.

During the year we participated in seven potentially commercial discoveries including the following that we announced: two off the east coast of India on blocks KG D6 and CYD5; one in Egypt with the Salamat well in the East Nile Delta; one in the pre-salt play of Angola with the Lontra well in Block 20, operated by Cobalt International Energy, Inc.; one in the Paleogene play in the Gulf of Mexico with the Gila prospect; and one in Brazil on block BM-POT-17 in the Potiguar basin, operated by Petrobras.

Exploration and appraisal costs

Exploration and appraisal costs, excluding lease acquisitions, were $4,811 million (2012 $4,356 million, 2011 $2,413 million). These costs included exploration and appraisal drilling expenditures, which were capitalized within intangible fixed assets, and geological and geophysical exploration costs, which were charged to income as incurred. Approximately 47% of exploration

and appraisal costs were directed towards appraisal activity. We participated in 140 gross (41 net) exploration and appraisal wells in 11 countries.

Exploration expense

Total exploration expense of $3,441 million (2012 $1,475 million, 2011 $1,520 million) included the write-off of expenses related to unsuccessful drilling activities in Brazil ($388 million), the UK North Sea ($262 million), Angola ($232 million), the Gulf of Mexico ($210 million), Jordan ($121 million) and others ($91 million). It also included an $845-million write-off associated with the value ascribed to block BM-CAL-13 offshore Brazil as part of the accounting for the acquisition of upstream assets from Devon Energy in 2011 and a $257-million write-off for costs relating to the Risha concession in Jordan. In addition, exploration expense included an $88-million credit related to a reduction in provisions for the decommissioning of idle infrastructure, which is required by the Bureau of Ocean Energy Management Regulation and Enforcement’s Notice of Lessees 2010 G05 issued in October 2010.

Upstream reserves

 

       2013         2012         2011   

Estimated net proved reserves

(net of royalties)

        

Liquidsa

     million barrels   

Subsidiariesb

     4,349         4,672         5,331   

Equity-accounted entitiesc

     745         838         929   
       5,094         5,510         6,260   

Natural gas

     billion cubic feet   

Subsidiariesd

     34,187         33,264         36,381   

Equity-accounted entitiesc

     2,517         2,549         2,397   
       36,704         35,813         38,778   

Total hydrocarbons

     million barrels of oil equivalent   

Subsidiaries

     10,243         10,408         11,604   

Equity-accounted entitiesc

     1,179         1,277         1,342   
       11,422         11,685         12,946   
 

 

28    BP Annual Report and Form 20-F 2013


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a  Liquids comprise crude oil, condensate, NGLs and bitumen.
b  Includes 21 million barrels (14 million barrels at 31 December 2012 and 20 million barrels at 31 December 2011) in respect of the 30% non-controlling interest in BP Trinidad & Tobago LLC.
c  BP’s share of reserves of equity-accounted entities in the Upstream segment. During 2013, upstream operations in Abu Dhabi, Argentina and Bolivia, as well as some of our operations in Angola and Indonesia, were conducted through equity-accounted entities.
d  Includes 2,685 billion cubic feet of natural gas (2,890 billion cubic feet at 31 December 2012 and 2,759 billion cubic feet at 31 December 2011) in respect of the 30% non-controlling interest in BP Trinidad & Tobago LLC.

Reserves booking

Reserves booking from new discoveries will depend on the results of ongoing technical and commercial evaluations, including appraisal drilling. The Upstream segment’s total hydrocarbon reserves, on an oil equivalent basis including equity-accounted entities comprised 11,422mmboe (10,243mmboe for subsidiaries and 1,179mmboe for equity-accounted entities) at 31 December 2013, a decrease of 2% (decrease of 2% for subsidiaries and decrease of 8% for equity-accounted entities) compared with the 31 December 2012 reserves of 11,685mmboe (10,408mmboe for subsidiaries and 1,277mmboe for equity-accounted entities).

Proved reserves replacement ratio

The proved reserves replacement ratio is the extent to which production is replaced by proved reserves additions. This ratio is expressed in oil equivalent terms and includes changes resulting from revisions to previous estimates, improved recovery and extensions and discoveries. For 2013 the proved reserves replacement ratio for the Upstream segment, excluding acquisitions and disposals, was 93% for subsidiaries and equity-accounted entities, 105% for subsidiaries alone and 30% for equity-accounted entities alone. For more information on proved reserves replacement for the group, see page 247.

Developments

The map on page 28 shows our major development areas, which include Alaska, Angola, Australia, Azerbaijan, Canada, Egypt, the deepwater Gulf of Mexico and the UK North Sea.

Three major project start-ups were achieved in 2013: Atlantis North expansion Phase 1 in the Gulf of Mexico; Angola LNG; and North Rankin Phase 2 in Australia.

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

 

  Angola we had our first LNG cargo in June and at the end of 2013 around 1 million cubic metres of LNG had been produced. The Plutão, Saturno, Vénus and Marte (PSVM) project reached plateau
   

production of 150mb/d and the Cravo, Lirio, Orquidea, Violeta (CLOV) floating production storage and offloading vessel (FPSO) sailed away from Angola Paenal in January 2014 to start the offshore hook-up and commissioning campaign.

 

  Azerbaijan the Shah Deniz consortium – a seven-member group led by BP – selected the Trans Adriatic Pipeline to deliver gas volumes from the Shah Deniz Stage 2 project to customers in Greece, Italy and southern Europe. In August, 25-year sales agreements were concluded for over 10bcma of gas, to be produced from the Shah Deniz field as a result of Stage 2. This adds to existing agreements to sell 6bcma in Turkey. The final investment decision on the project was made in December.

 

  North Sea we continued to see high levels of activity, including the ramp-up of major project volumes, a significant level of turnaround activity, progress in the major redevelopment of the west of Shetland Schiehallion and Loyal fields, the installation of the platform jackets on the Clair Ridge project, a major milestone, and the sale of a number of non-strategic assets.

 

  Gulf of Mexico we had 10 rigs operating at the end of the year, the highest number ever. Atlantis North expansion Phase 1 started up in April. Following our strategic divestment programme, we now have a very focused portfolio with growth potential around four operated and three non-operated hubs.

In April the decision was taken not to move forward with the existing development plan for the Mad Dog Phase 2 project in the deepwater Gulf of Mexico, as market conditions and industry cost inflation made the project less attractive than previously modelled. This decision resulted in an impairment of $159 million. BP and its co-owners reviewed alternative development concepts and the current concept being considered is a single production host designed for future flexibility in evaluating how best to capture additional potential resource.

Development expenditure of subsidiaries incurred in 2013, excluding midstream activities, was $13.6 billion (2012 $12.6 billion, 2011 $10.4 billion).

Production

Our oil and natural gas production assets are located onshore and offshore and include wells, gathering centres, in-field flow lines, processing facilities, storage facilities, offshore platforms, export systems (e.g. transit lines), pipelines and LNG plant facilities. The principal areas of production are Angola, Argentina, Australia, Azerbaijan, Egypt, Trinidad, the UAE, the UK and the US.

 

 

LOGO

 

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LOGO

 

       2013         2012         2011   

Production (net of royalties)a

        

Liquidsb

     thousand barrels per day   

Subsidiaries

     879         896         992   

Equity-accounted entities

     297         284         294   
       1,176         1,179         1,285   

Natural gas

     million cubic feet per day   

Subsidiaries

     5,845         6,193         6,393   

Equity-accounted entities

     415         416         415   
       6,259         6,609         6,807   

Total hydrocarbonsc

     thousand barrels of oil equivalent per day   

Subsidiaries

     1,887         1,963         2,094   

Equity-accounted entities

     369         355         366   
       2,256         2,319         2,460   

 

a  Includes BP’s share of production of equity-accounted entities in the Upstream segment. Because of rounding, some totals may not agree exactly with the sum of their component parts.
b  Liquids comprise crude oil, condensate and NGLs.
c  Natural gas is converted to oil equivalent at 5.8 billion cubic feet = 1 million barrels.

Our total hydrocarbon production during 2013 averaged 2,256 thousand barrels of oil equivalent per day (mboe/d). This comprised 1,887mboe/d for subsidiaries and 369mboe/d for equity-accounted entities, a decrease of 4% (decreases of 2% for liquids and 6% for gas) and an increase of 4% (increase of 5% for liquids and no change for gas) respectively compared with 2012. More information on production can be found in Oil and gas disclosures for the group on page 245.

In aggregate, after adjusting for the impact of price movements on our entitlement to production in our PSAs and the effect of acquisitions and disposals, underlying production was 3.2% higher compared with 2012. This primarily reflects new major project volumes in Angola, the North Sea and the Gulf of Mexico.

The group and its equity-accounted entities have numerous long-term sales commitments in their various business activities, all of which are expected to be sourced from supplies available to the group that are not subject to priorities, curtailments or other restrictions. No single contract or group of related contracts is material to the group.

Gas marketing and trading activities

We market and trade natural gas, power and natural gas liquids (NGLs). This provides us with routes into liquid markets for the gas we produce. It also generates margins and fees from selling physical products and derivatives to third parties, together with income from asset optimization and trading. The integrated supply and trading function manages the group’s trading activities in natural gas, power and NGLs. This means we have a single interface with the gas trading markets and one consistent set of trading compliance processes, systems and controls.

Gas and power marketing and trading activity is undertaken primarily in the US, Canada and Europe to market both BP production and third-party natural gas, to support group LNG activities and manage market price risk, as well as to create incremental trading opportunities through the use of commodity derivative contracts. Additionally, this activity generates fee income and enhances margins from sources such as the management of price risk on behalf of third-party customers. These markets are large, liquid and historically volatile. Market conditions have become more challenging in recent years as volatility and geographic basis/seasonal spreads have fallen to very low levels with the emergence of shale gas in the US and generally over-supplied markets in Europe. However, the traded LNG business has benefited from wide price variations between the main gas consuming regions of North America, Europe and Asia. As part of the LNG strategy, during 2013 we entered into a 20-year gas liquefaction tolling contract for 4.4 million tons per annum capacity which is located in Texas, US.

The gas and power marketing and trading function operates primarily from offices in Houston and London and employs around 1,200 people.

The group’s risk governance framework seeks to manage and oversee the financial risks associated with this trading activity, which is described in Financial statements – Note 19.

In connection with its trading activities, the group uses a range of commodity derivative contracts, storage and transport contracts. The range of contracts that the group enters into is described in Certain definitions – commodity trading contracts on page 270.

Analysis by region

See Upstream analysis by region on page 239.

 

 

30    BP Annual Report and Form 20-F 2013


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Downstream

2013 was a year of improved safety performance, operational improvements and delivery of significant milestones to enhance the quality of our portfolio.

 

LOGO

 

~

Cherry Point refinery processes around 230,000 barrels of crude oil per day, primarily for transportation fuels.

 

 

Our business model and strategy

Our Downstream segment is the product and service-led arm of BP, focused on fuels, lubricants and petrochemicals. We have significant operations in Europe, North America and Asia, and also manufacture and market our products across Australasia, southern Africa and Central and South America.

The segment comprises three businesses:

 

    Fuels fuels value chains (FVCs) including refineries, fuels marketing businesses and global oil supply and trading activities. We sell refined petroleum products including gasoline, diesel, aviation fuel and LPG.

 

    Lubricants manufactures and markets lubricants and related products and services globally, adding value through brand, technology and relationships, such as collaboration with original equipment manufacturing partners.

 

    Petrochemicals manufactures products at locations around the world, using proprietary BP technology. These products are then used by others to make vital consumer products such as paint, plastic bottles and textiles.

We aim to operate all of our businesses as safe and reliable value chains. We participate in multiple stages of each value chain as we believe we can deliver greater returns from integration than from owning a collection of discrete assets. These value chains, combined with our advantaged manufacturing operations, supply and trading capability and expertise in technology, allow us to pursue long-term competitive returns and sustainable growth, serving customers and promoting BP and our brands through high quality products.

We research, develop and deploy a wide range of technologies, processes and techniques, aiming to enhance safety and risk management, increase efficiency and reliability, improve our margins and create new market opportunities.

 

Our strategy focuses on four priorities executed in a systematic and disciplined way:

 

    Safety performance.

 

    High-quality downstream portfolio.
    Competitive returns.

 

    Material and growing cash flows for the group through exposure to growth opportunities and markets.

This strategy is about winning sustainably in the markets where we choose to participate. We seek to outperform the best competitor in a region and do it safely; investing to strengthen our established positions while maintaining overall capital employed, and still seeking to shift the mix of participation and capital employed from established to growing markets. We do this while operating within a stable financial framework to deliver attractive returns and growth in earnings and cash flow.

The delivery of these activities is optimized and integrated with support from global functions with specialist areas of expertise: technology, finance, procurement and supply chain, human resources, global business services and information technology.

 

LOGO

 

Outlook

 

    In 2014 we anticipate refining margins will remain under pressure due to high gasoline stocks and new competitor capacity additions, as well as weak demand in many markets.

 

    We expect the financial impact of refinery turnarounds in 2014 to be lower than in 2013.

 

    Whiting continues to progressively increase heavy crude processing, and we expect to reach heavy crude processing levels of 280,000 barrels per day during the second quarter 2014.

 

    We anticipate demand for lubricants in 2014 will be similar to 2013.

 

    We expect a similarly challenging environment for petrochemicals in 2014, characterized by excess supply.

 

    Capital expenditure is forecast to be slightly lower in 2014 than in 2013, post commissioning of all major units of the Whiting refinery modernization project.

 

a  Underlying RC profit before interest and tax is not a recognized GAAP measure. See footnote c on page 23 for further information. The equivalent measure on an IFRS basis is RC profit before interest and tax.
 

 

BP Annual Report and Form 20-F 2013    31


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Our markets

Economic growth in 2013 varied widely, with certain economies shrinking and others showing some signs of recovery. OECD oil consumption was up slightly in 2013, rising for the first time since 2010. Demand in non-OECD economies also continued to grow, but at a slower rate than 2012 partly due to reduced GDP growth, for example in India, South East Asia and the Middle East.

In oil markets in 2013, European refineries were impacted by limited economic options to process sour grades, such as Urals, and by the loss of Libyan sweet crude supplies for much of the year. In addition, crude supplies were constrained by the loss of Iranian oil due to US and European trade embargoes and by ongoing decline in European oil production. This was partially offset by Saudi Arabia crude production, which reached a 30-year high.

Non-OPEC oil supply increased by over 1 million barrels per day in 2013, primarily in the US due to increased production of shale oil. North American crudes remained cheaper than waterborne crudes of a similar quality, such as European Brent and Gulf Coast LLS, due to increased production, combined with logistical constraints in transporting inland crude production to the coast. Our refineries, particularly Toledo and Whiting in the US, benefited from a location advantage as they were able to access these discounted crudes. In addition, these refineries benefited from a wider discount of Canadian heavy to West Texas intermediate (WTI) crude in 2013, a factor that will become increasingly important to the BP refining portfolio in 2014 with the commissioning of the Whiting refinery modernization project.

Refining marker margin

We track the margin environment by way of a global refining marker margin (RMM). Refining margins are a measure of the difference between the price a refinery pays for its inputs (crude oil) and the market price of its products. Although refineries produce a variety of petroleum products, we track the margin environment using a simplified indicator that reflects the margins achieved on gasoline and diesel only. The RMM may not be representative of the margin achieved by BP in any period because of BP’s particular refinery configurations and crude and product slates. The RMM does not include estimates of fuel costs or other variable costs.

 

     $ per barrel   
     Crude marker      2013         2012         2011   

Refining marker margin (RMM)

        

US North West

  

Alaska North

Slope

     15.2         18.0         14.1   

US Midwest

   West Texas         
   Intermediate      21.7         27.8         24.7   

Northwest Europe

   Brent      12.9         16.1         11.9   

Mediterranean

   Azeri Light      10.5         12.7         9.0   

Australia

   Brent      13.4         14.8         12.2   

BP average RMM

          15.4         18.2         14.5   

In February 2013 BP updated the RMM methodology and regions to reflect the changes to our US portfolio after the refinery divestments and account for trends in regional crude markets since the RMM was established. The effect of this update is that the 2012 and 2011 BP average RMMs were restated from $15.0 per barrel (as originally reported) to $18.2 per barrel and from $11.6 per barrel to $14.5 per barrel, respectively.

Global refining marker margin ($/bbl)

 

LOGO

The average RMM for 2013 was $2.8 per barrel lower compared to 2012, with a slightly stronger first half and falling sharply in the second half of the year. However, it was higher than 2011. Margins in 2013 declined primarily due to increased product and gasoline supply, high gasoline inventories, competitor capacity additions and lower seasonal turnarounds.

Financial performance

 

       $ million   
       2013        2012        2011   

Sale of crude oil through spot and term contracts

     79,394        56,383        57,055   

Marketing, spot and term sales of refined products

     258,015        274,666        273,940   

Other sales and operating revenues

     13,786        15,342        13,038   

Sales and other operating revenuesa

     351,195        346,391        344,033   

RC profit before interest and taxb

      

Fuels

     1,518        1,403        2,999   

Lubricants

     1,274        1,276        1,350   

Petrochemicals

     127        185        1,121   
       2,919        2,864        5,470   

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

      

Fuels

     712        3,609        640   

Lubricants

     (2     9        (100

Petrochemicals

     3        (19     (1
       713        3,599        539   

Underlying RC profit before interest and taxb d

      

Fuels

     2,230        5,012        3,639   

Lubricants

     1,272        1,285        1,250   

Petrochemicals

     130        166        1,120   
       3,632        6,463        6,009   

Capital expenditure and acquisitions

     4,506        5,249        4,285   

 

a  Includes sales to other segments.
b  Income from petrochemicals produced at our Gelsenkirchen and Mülheim sites is reported within the fuels business. Segment-level overhead expenses are included within the fuels business.
c  Fair value accounting effects are not a recognized GAAP measure and represent the (favourable) unfavourable impact relative to management’s measure of performance (see page 238 for further details). For Downstream, these arise solely in the fuels business.
d  Underlying RC profit is not a recognized GAAP measure. See footnote c on page 23 for information on underlying RC profit.

Sales and other operating revenues in 2013 were $351 billion (2012 $346 billion, 2011 $344 billion). This increase in 2013, compared with 2012 reflects increased crude sales volumes, largely offset by lower prices. The increase in 2012, compared with 2011, reflected higher prices almost offset by lower volumes and foreign exchange losses.

In 2013 RC profit before interest and tax for the segment was $2.9 billion (2012 $2.9 billion, 2011 $5.5 billion). The 2013 result included a net non-operating charge of $535 million, primarily relating to impairment charges in our fuels business, versus charges of $3,172 million in 2012 mainly related to impairment charges and $602 million in 2011 for impairment charges associated with our disposal programme, partially offset by gains on disposal. In addition, fair value accounting effects had an unfavourable impact of $178 million in 2013 versus an unfavourable impact of $427 million in 2012 and a favourable impact of $63 million in 2011.

 

 

32    BP Annual Report and Form 20-F 2013


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After adjusting for non-operating items and fair value accounting effects, underlying RC profit before interest and tax was $3.6 billion (2012 $6.5 billion, 2011 $6.0 billion).

The fuels business delivered an underlying RC profit before interest and tax of $2,230 million for the year (2012 $5,012 million, 2011 $3,639 million). Compared with 2012, 2013 saw significantly weaker refining margins. Margins were weakened by reduced throughput due to the planned crude unit outage at our Whiting refinery and commissioning of the new units that were part of the refinery modernization project and the absence of earnings from the divested Texas City and Carson refineries. This was partially offset by a significantly improved supply and trading contribution and lower overall turnaround activity during the year. Compared with 2011, the 2012 result reflected strong operations that enabled us to capture the higher refining margin environment, partly offset by a lower supply and trading contribution.

The lubricants business delivered an underlying RC profit before interest and tax of $1,272 million for the year (2012 $1,285 million, 2011 $1,250 million). These results reflect sustained underlying performance for the lubricants business.

The petrochemicals business delivered an underlying RC profit before interest and tax of $130 million for the year (2012 $166 million, 2011 $1,120 million). Compared with 2012, the 2013 result reflected weaker product margins resulting from over supply in certain markets partially offset by lower turnaround activity in the US and Europe.

Our petrochemicals productiona of 13,943 thousand tonnes (kte) in 2013 was lower than the previous two years (2012 14,727kte, 2011 14,866kte) due to the sale of our BPCM Kuantan PTA plant in 2012 as well as reduced output in both years for commercial reasons given the low-margin environment.

A summary of our interests in petrochemicals production capacity as at 31 December 2013 is provided on page 244.

 

a  Petrochemicals production includes 1,494kte of petrochemicals produced at our Gelsenkirchen and Mülheim sites in Germany for which the income is reported in our fuels business.

Our fuels business

The fuels strategy focuses largely on fuels value chains (FVCs) which include large-scale, highly upgraded and feedstock advantaged refineries that are integrated with logistics and marketing as well as fuels marketing businesses primarily supplied by our global supply and trading organization.

The FVCs seek to optimize the activities of our assets across the supply chain through: advantaged feedstock delivery to the refineries; manufacture of high-quality fuels; distribution through pipeline and terminal infrastructure; and marketing and sales to our customers on a regional basis. This integration, together with a focus on excellent execution and cost management as well as a strong brand, market presence and customer base, are key to our financial performance.

Refining

At 31 December 2013 we owned or had a share in 14 refineries producing refined petroleum products that we supply to retail and commercial customers. A summary of our interests in refineries and average daily crude distillation capacities as at 31 December 2013 is provided on page 243. As part of our plan to reshape BP’s US fuels business, we completed the sales of the Texas City and Carson, California refineries and associated logistic and marketing assets. The Texas City refinery and a portion of our retail and logistics network in the south-east US were sold to Marathon Petroleum Corporation on 1 February 2013 for consideration of up to $2.5 billion. On 3 June 2013 we completed the sale of the Carson refinery in California, ARCO network and related regional logistics assets to Tesoro Corporation for approximately $2.4 billion.

Strategic investments in our refineries are focused on maintaining the safety and reliability of our assets while improving unit margins versus the competition. The most important of these strategic investments in 2013 was the Whiting refinery modernization project. During the year the new coker, crude oil unit, gasoil hydrotreater, and an upgraded sulphur recovery complex were all commissioned. We plan to progressively ramp up heavy crude processing to approximately 280,000 barrels per day during the second quarter of 2014. This major investment transforms Whiting into one of the key advantaged downstream assets in our portfolio, with the capacity to process a greater proportion of heavy crudes, and underpins our ability to deliver increased cash flow from 2014 onwards.

Refinery operations were strong this year, with Solomon refining availability of 95.3%. Utilization rates were at 86% principally due to the planned crude unit outage at our Whiting refinery as part of the modernization project. Overall refinery throughputs in 2013 were lower than those in 2012, mostly driven by the divestment of the Texas City and Carson refineries and associated logistics and marketing activities in 2013.

 

 

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BP Annual Report and Form 20-F 2013    33


Table of Contents
       thousand barrels per day   
Refinery throughputsa      2013         2012         2011   

US

     726         1,310         1,277   

Europe

     766         751         771   

Rest of world

     299         293         304   

Total

     1,791         2,354         2,352   
                         %   

Refining availabilityb

     95.3         94.8         94.8   
       thousand barrels per day   

Sales volumes

                          

Marketing salesc

     3,084         3,213         3,311   

Trading/supply salesd

     2,485         2,444         2,465   

Total refined product sales

     5,569         5,657         5,776   

Crude oile

     2,142         1,518         1,532   

Total

     7,711         7,175         7,308   

 

a  Refinery throughputs reflect crude oil and other feedstock volumes.
b  Refining availability represents Solomon Associates’ operational availability, which is defined as the percentage of the year that a unit is available for processing after subtracting the annualized time lost due to turnaround activity and all planned mechanical, process and regulatory maintenance downtime.
c  Marketing sales include sales to service stations, end-consumers, bulk buyers and jobbers (i.e. third parties who own networks of a number of service stations) and small resellers.
d  Trading/supply sales are sales to large unbranded resellers and other oil companies.
e  Crude oil sales relate to transactions executed by our integrated supply and trading function, primarily for optimizing crude oil supplies to our refineries and in other trading. Fifty-nine thousand barrels per day relate to revenues reported by the Upstream segment.

Logistics and marketing

Downstream of our refineries, we operate an advantaged infrastructure and logistics network which includes pipelines, storage terminals and road or rail tankers, where we seek to drive excellence in operational and transactional processes, and deliver compelling customer offers in the various markets in which we operate.

We blend and market biofuels in our FVCs; almost 6.5 billion litres of biofuels were blended into finished product in 2013, mainly in Europe and the US. Biogasoline (bioethanol) and biodiesel (hydrogenated vegetable oils and fatty acid methyl esters) demand continues to grow, primarily in Europe and the US, as regulatory requirements demand higher blending levels. In response we continue to develop blend capabilities and to work with regulators, biofuels suppliers and other stakeholders to improve the sustainability of the biofuels we blend and supply.

We supply fuel and related convenience services to retail consumers through company-owned and franchised retail sites, as well as other channels, including wholesalers and jobbers. In addition, we supply commercial customers within the transport and industrial sectors.

 

Number of retail sites operated under a BP brand

  

Retail sitesf

     2013         2012         2011   

US

     7,700         10,100         11,300   

Europe

     8,000         8,300         8,200   

Rest of world

     2,100         2,300         2,300   

Total

     17,800         20,700         21,800   

 

f  The number of retail sites includes sites not operated by BP but instead operated by dealers, jobbers, franchisees or brand licensees that operate under a BP brand. These may move to or from the BP brand as their fuel supply or brand licence agreements expire and are renegotiated in the normal course of business. Retail sites are primarily branded BP, ARCO and Aral. Excludes our interests in equity-accounted entities that are dual-branded.

Supply and trading

BP’s integrated supply and trading function is responsible for delivering value across the overall crude and oil products supply chain. This structure enables the optimization of BP’s FVCs to maintain a single interface with the oil trading markets and to operate with a single set of trading compliance processes, systems and controls. The oil trading function (including support functions) has trading offices in Europe, the US and Asia and employs around 1,800 people. This enables the function to maintain a presence in the more actively traded regions of the global oil markets in order to gain an overall understanding of the supply and demand forces across this market. It has a two-fold strategic purpose in our Downstream business.

First, it seeks to identify the best markets and prices for our crude oil, source optimal feedstocks for our refineries, and provide competitive supply for our marketing businesses. Wherever possible, the group will

look to optimize value across the supply chain. For example, BP will often sell its own crude and purchase alternative crudes from third parties for its refineries where this will provide incremental margin.

Second, the function seeks to create and capture incremental trading opportunities by entering into a full range of exchange-traded commodity derivatives, over-the-counter (OTC) contracts and spot and term contracts. In order to facilitate the generation of trading margin from arbitrage, blending and storage opportunities, it also owns and contracts for storage and transport capacity.

The group’s risk governance framework seeks to manage and oversee the financial risks associated with this trading activity, which is described in Financial statements – Note 19.

The range of contracts that the group enters into is described in Certain definitions – commodity trading contracts on page 270.

Aviation

Our global aviation business, Air BP, is one of the world’s largest and best-known aviation fuels suppliers, serving many major commercial airlines as well as the general aviation sectors. We have marketing sales in excess of 465,000 barrels per day. Air BP’s strategic aim is to maintain its position in the core locations of Europe and the US, while expanding its portfolio in airports that offer long-term competitive advantage in material growing markets such as Asia and South America.

LPG

We have neared completion of the sale of our global LPG marketing business, which sells bulk and bottled LPG products. We will retain focus on LPG when it is deeply integrated in refinery operations and autogas sectors in order to optimize refinery and retail operations. As of 31 December 2013, the sales of the LPG business in six out of eight countries had been completed. The remaining two countries are expected to be completed in 2014.

Our lubricants business

Our strategy is to leverage technology, brand, and relationships, with a focus on our premium brands, to deliver growth and sustainable returns.

Our lubricants business manufactures and markets lubricants and related products and services to the automotive, industrial, marine, aviation and energy markets across the world. Our key brands are Castrol, BP and Aral. Castrol is a recognized brand worldwide and we believe it provides us with a significant competitive advantage. In technology, we apply our expertise to create quality lubricants and high performance fluids for customers in on-road, off-road, air, sea and industrial applications globally. We divide our lubricants business up into five customer sectors: automotive, marine, industrial, aviation and energy.

We are one of the largest purchasers of base oil in the market, but have chosen not to produce at scale in base oil or additives manufacturing. Our participation in the value chain is focused on areas of competitive differentiation and strength. These fall into three main areas:

 

  We develop formulation and the application of cutting-edge technologies.

 

  We create and develop product brands and clearly communicate their benefits to our customers.

 

  We build and extend our relationships with customers so we can better understand and meet their needs.

In 2013, the automotive sector saw signs of recovery in new passenger vehicle demand across several key markets including China, the US and certain European countries. For 2013, lubricants base oil prices averaged below 2012, which benefited margins. A significant share of profit growth has come from emerging markets, where we are developing a strong base to capture further growth.

The global lubricants market remained challenging in 2013 as a result of economic slowdown and low demand growth. The automotive sector saw declines in new passenger vehicle demand across Europe and India, which were partially offset with growth in North America, China and Brazil. Industrial demand remained under pressure from a weak manufacturing sector.

We continue to increase lubricants revenues through our strategy of exposure to growing markets, technology investments and targeted marketing programmes. More than 35% of sales revenues were from non-OECD countries in 2013.

 

 

34    BP Annual Report and Form 20-F 2013


Table of Contents

Our lubricants business continued to increase the proportion of total sales resulting from premium product sales; in 2013 the percentage of premium sales was 40% compared with 39% in 2012 and 37% in 2011.

In January 2014, BP announced that it had agreed to sell its specialist global aviation turbine oils business. The transaction, which is subject to regulatory and other approvals, is expected to be completed in the second quarter of 2014.

Our petrochemicals business

Our strategy is to own and develop petrochemical value chain businesses which are built around proprietary technology. We apply this technology to existing businesses and to access new growth markets where we wish to build material shares. Overall, the business targets attractive absolute returns and material, increasing cash flows by satisfying demand growth, particularly in Asia.

We manufacture and market four main product lines:

 

  Purified terephthalic acid (PTA).

 

  Paraxylene.

 

  Acetic acid.

 

  Olefins and derivatives.

We also produce a number of other speciality petrochemicals products.

Our portfolio is underpinned with proprietary technology and leading cost positions allowing BP assets to remain competitive against the newest world-scale units being built in China. These capacity additions and technology advances have resulted in a sharp fall in margins leading to losses for the older, less efficient producers. New capacity additions are targeted principally in the higher-growth Asian markets.

We both own and operate assets, and have also invested in a number of joint arrangements in Asia, where our partners are leading companies within their domestic market. For example, the construction of our new, third PTA plant with our partner, Zhuhai Port Co. in Guangdong, China is progressing well and is planned to begin production in late 2014. The retro-fit of key elements of our PTA technology to existing plants is under way. We expect these investments to have a material impact on efficiency and reduce annual operating costs.

Our technology team develops, deploys and optimizes chemicals technology to advance the competitiveness of the installed asset base and deliver competitively advantaged projects to access growth. We plan to continue deploying our technology in new asset platforms to access Asian demand and advantaged feedstock sources.

In 2013 we announced two new proprietary petrochemicals technologies, SaaBre and Hummingbird. SaaBre significantly reduces the cost of production of acetic acid from syngas and avoids the need to purify carbon monoxide or purchase methanol. SaaBre technology could also be used to produce methanol and ethanol. Hummingbird simplifies the process of converting ethanol to ethylene, a key component for the manufacture of plastics. Hummingbird could open the way for the production of biopolymers from bioethanol. Both technologies are expected to deliver significant reductions in variable manufacturing costs and simplify the manufacturing process.

In December 2013, we agreed to purchase all interests held by our partners, Mitsui Chemicals, Inc. (MCI) and Mitsui & Co. Ltd. (MBK) in PT Amoco Mitsui PTA Indonesia (AMI) which produces and markets PTA in the Republic of Indonesia. This transaction completed on 28 February 2014 and is consistent with our strategy of growing our PTA business in our chosen markets.

In September 2013, we signed a non-binding memorandum of understanding with Oman Oil Corporation to assess jointly a facility in Oman for the manufacture of acetic acid, deploying our SaaBre technology.

The economic environment for some of our products is likely to remain under pressure in 2014. The impact of capacity additions in Asia continues to depress margins for PTA. The environments for our acetic acid and olefins and derivative value chains are expected to improve in the latter part of 2014 as the high growth markets absorb excess capacity.

Rosneft

In March 2013 BP completed sale and purchase agreements with Rosneft and Rosneftegaz.

 

LOGO

 



Central processing and pumping facility at the Yuganskneftegaz field, onshore Russia.

 

BP and Rosneft

 

    BP sold its investment in TNK-BP in exchange for $11.8 billion in cash and an 18.5% stake in Rosneft. Together with its existing 1.25% shareholding, BP now holds a 19.75% stake in the company.

 

    BP’s shareholding in Rosneft allows us to benefit from a diversified set of existing and potential projects in the Russian oil and gas sector. BP considers Rosneft share price appreciation and dividend growth as primary sources of value for its shareholders.

 

    Rosneft’s strategy is to pursue sustainable growth of crude oil production, develop its gas business and complete its refinery modernization programme.

 

    BP is positioned to contribute to Rosneft’s strategy through the sharing of technology, people, processes and best practice. We also have the potential to undertake standalone projects with Rosneft, both in Russia and internationally.

 

    Bob Dudley was elected to the Rosneft board of directors in June 2013, and became a member of the Rosneft board’s strategic planning committee.

Rosneft – 2013 summary

 

    Rosneft announced in June 2013 that it had completed the process of integrating TNK-BP and subsequently the Rosneft board approved a modified business plan for 2013 incorporating the acquisition of TNK-BP.

 

    Rosneft concluded long-term crude oil supply agreements with China National Petroleum Corporation (CNPC) and Sinopec, signalling China as an additional market for Russian crude.

 

    Rosneft completed the acquisition of the remaining 49% in the Itera joint venture, 51% of Sibneftegaz and agreed to buy gas assets from ALROSA.

 

    Rosneft made a voluntary offer in October 2013 to buy out the non-controlling shareholders of RN Holding (formerly TNK-BP Holding). By the closing date of the offer in January 2014, Rosneft had received acceptances of its offer from over 98% of such shareholders.

 

 

 

BP Annual Report and Form 20-F 2013       35   


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Upstream

Rosneft is the largest oil company in Russia and the largest publicly traded oil company in the world based on hydrocarbon production volume. Rosneft also has significant hydrocarbon reserves.

Rosneft has assets in all key hydrocarbon regions of Russia: Western Siberia, Eastern Siberia, Timan-Pechora, Volga-Urals, North Caucasus and Far East. Internationally, Rosneft participates in exploration projects or has operations in countries including the US, Canada, Vietnam, Venezuela, Brazil, Algeria, UAE, Kazakhstan and Norway. Rosneft and Gazprom, the majority of whose shares are owned by the Russian state, have exclusive rights to explore and develop significant hydrocarbon resources in the Russian Arctic offshore (including the Sea of Okhotsk). To progress Arctic exploration, Rosneft has concluded partnerships with ExxonMobil, ENI, Statoil, CNPC and Inpex.

In 2013 Rosneft signed new gas sales contracts with Enel, Fortum and others to monetize produced gas. Also Russian legislation introduced in December 2013 allows Rosneft and Novatek to export LNG for the first time.

Downstream

Rosneft has interests in 23 refineries including four in Germany through its Ruhr Oel GmbH partnership with BP. In 2013 Rosneft acquired a 21% share in the Saras S.p.A. refinery in Italy.

Rosneft refinery throughput in 2013 amounted to 1,818mb/d. Rosneft continues to implement its refinery modernization programme which is intended to significantly upgrade and expand its refining capacity. As at 31 December 2013, Rosneft owned and operated more than 2,400 retail service stations, representing the largest network in Russia. This included BP-branded sites acquired as part of Rosneft’s acquisition of TNK-BP which will continue to operate under the BP brand. Rosneft’s downstream operations also include jet fuel, bunkering, bitumen and lubricants.

Rosneft segment performance

BP’s investment in Rosneft is managed and reported as a separate segment under IFRS. The Rosneft segment result includes equity-accounted earnings from Rosneft, representing BP’s share in Rosneft and foreign currency effects on the dividends received in 2013. For more information on the sale and purchase agreements, see Financial statements – Note 6.

 

       $ million    
       2013a   

Profit before interest and taxb c

     2,053   

Inventory holding (gains) losses

     100   

Replacement cost profit before interest and taxc

     2,153   

Net charge (credit) for non-operating items

     45   

Underlying replacement cost profit before interest and
taxc d

     2,198   

 

a  From 21 March 2013.
b  BP’s share of Rosneft’s earnings after finance costs, taxation and non-controlling interests is included in the BP group income statement within profit before interest and taxation.
c  Includes $5 million of foreign exchange losses arising on the dividend received. This amount is not reflected in the following table.
d  Underlying replacement cost profit is not a recognized GAAP measure. See footnote c on page 23 for information on underlying replacement cost profit.

Replacement cost profit before interest and tax for the Rosneft segment was $2.2 billion in 2013. The result included a net non-operating charge of $45 million, primarily relating to impairment charges. After adjusting for non-operating items, underlying replacement cost profit before interest and tax in 2013 was $2.2 billion.

BP received a dividend from Rosneft in 2013 of $456 million, after the deduction of withholding tax.

BP completed the exercise to determine the fair value of its share of Rosneft’s assets and liabilities as at 21 March 2013, as required under IFRS, and the results of this exercise are reflected in the 2013 reported amounts.

 

BP’s share of the components of Rosneft’s net income are shown in the table below.

 

       $ million    
       2013a   
Income statement (BP share)   

Profit before interest and tax

     2,786   

Finance costs

     (264

Taxation

     (422

Non-controlling interests

     (42

Net income

     2,058   

Inventory holding (gains) losses, net of tax

     100   

Net income on a replacement cost basis

     2,158   

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

     45   

Net income on an underlying replacement cost basis

     2,203   
Balance sheet         
       $ million    
      

 

31 December 

2013 

  

  

Investments in associates

     13,681   
Production and reserves         
       2013   
Production (net of royalties) (BP share)e f   

Liquids (mb/d)g

     650   

Natural gas (mmcf/d)

     617   

Total hydrocarbons (mboe/d)h

     756   

Estimated net proved reserves (net of royalties)

(BP share)

  

Liquids (million barrels)g

     4,975   

Natural gas (billion cubic feet)

     9,271   

Total hydrocarbons (mmboe)

     6,574   
Average oil marker prices      $ per barrel   

Urals (Northwest Europe – CIF)

     107.38   

Russian domestic oil

     54.97   

 

e  Reflects production for the period 21 March to 31 December, averaged over the full year.
f  Information on BP’s share of TNK-BP’s production for comparative periods is provided on pages 248 and 250.
g  Liquids comprise crude oil, condensate and natural gas liquids.
h  Natural gas is converted to oil equivalent at 5.8 billion cubic feet = 1 million barrels.
 

 

36    BP Annual Report and Form 20-F 2013


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Other businesses

and corporate

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

Financial performance

 

                       $ million   
       2013        2012        2011   

Sales and other operating revenuesa

     1,805        1,985        2,957   

Replacement cost profit (loss) before interest and tax

     (2,319     (2,794     (2,468

Net (favourable) unfavourable impact of non-operating items

     421        798        822   

Underlying replacement cost profit (loss) before interest and taxb

     (1,898     (1,996     (1,646

Capital expenditure and acquisitions

     1,050        1,435        1,853   

 

a  Includes sales to other segments.
b  Underlying replacement cost profit (loss) is not a recognized GAAP measure. See footnote c on page 23 for information on underlying replacement cost profit (loss).

The replacement cost loss before interest and tax for the year ended 31 December 2013 was $2.3 billion (2012 $2.8 billion, 2011 $2.5 billion). The 2013 result included a net charge for non-operating items of $421 million (2012 $798 million, 2011 $822 million).

After adjusting for non-operating items, the underlying replacement cost loss before interest and tax for the year ended 31 December 2013 was $1.9 billion (2012 $2.0 billion, 2011 $1.6 billion). This result reflected higher income on cash balances and lower corporate costs. The 2012 result was impacted by the loss of income from the sale of the aluminium business in 2011, adverse foreign exchange effects and higher corporate costs.

Alternative Energy

BP is committed to alternative energy and our strategy is focused on operating large scale businesses and commercializing our innovative technologies. BP continues to invest in expanding the scale of our biofuels business and in leveraging our unique capabilities and experience in agri-business, bio-technology and bio-refining. We also have an operating wind business. As at 31 December 2013, we have invested approximately $8.3 billionc, exceeding our 2005 commitment of $8 billion over 10 years.

 

c  The majority of costs were initially capitalized, although some were expensed under IFRS.

Biofuels

BP believes that it has a key role to play in enabling the transport sector to respond to the dual challenges of energy security and climate change. We have a focused programme of biofuels development based on the most efficient transformation of sustainable and low-cost sugars into a range of fuel molecules. Our strategy is to focus on the conversion of cost-advantaged feedstocks that are materially scalable and that can be competitive in an $80/bbl crude oil environment without subsidies.

We operate three sugar cane mills in Brazil producing bioethanol and sugar, and exporting power to the grid. We continue to evaluate options to increase production at these facilities and have already started work on expanding ethanol production capacity at one mill and this work is expected to be completed in 2014. Likewise, we are ramping up production at our Vivergo joint venture plant, which is the largest bioethanol facility in the UK and one of the largest in Europe. Once up to full production capacity of 420 million litres per year, the Vivergo facility will represent around 20% of the UK’s total 2012-13 requirements under the Renewable Transport Fuels Obligation (RTFO).

BP continues to invest throughout the entire biofuels value chain, from growing sustainable higher-yielding and lower-carbon feedstocks through to the development, production and marketing of the advantaged fuel molecule biobutanol, which has higher energy content than ethanol and delivers improved fuel economy.

In conjunction with its partner DuPont, BP is undertaking leading-edge research into the production of biobutanol under the company name Butamax.

Across our biofuels business, BP’s share of ethanol-equivalent productiond for 2013 was 521 million litres (552 million litres gross) compared with 404 million litres a year ago. The majority of this production is from BP’s sugar cane mills in Brazil. In the US, BP has made the strategic decision to focus its biofuels business on the research, development, and commercialization of cellulosic ethanol technology at its facilities in San Diego, California, and Jennings, Louisiana.

 

d  Ethanol-equivalent production includes ethanol and sugar.

Wind

In wind power, our business is focused onshore in the US. In 2013 we marketed our wind business for sale. Despite receiving a number of bids, we determined it was not the right time to sell and instead are focusing on optimizing performance at our 16 wholly owned and joint-venture wind farms.

BP maintained its net wind generation capacity in the US at 1,558MWe during 2013. BP’s net share of wind generation for 2013 was 4,203GWh (7,363GWh gross), compared with 3,587GWh (5,739GWh gross) a year ago.

 

e  BP also has 32MW of wind capacity in the Netherlands, operated by our Downstream segment.

Emerging business and ventures

Our emerging business and ventures unit invests in technology entrepreneurs working at the frontiers of their fields – across the entire energy spectrum. Investments focus on emerging, strategic technologies, oil and gas, downstream technologies including fuels and chemicals, and biotech and bioenergy. The unit has made 37 separate investments, with $210 million of committed capital.

Shipping

We transport our products across oceans, around coastlines and along waterways using a combination of BP-operated, time-chartered and spot-chartered vessels. All vessels conducting BP activities are subject to our health, safety, security and environmental requirements. The primary purpose of our shipping and chartering activities is the transportation of our hydrocarbon products. In addition, we may use surplus capacity to transport third-party products. In December 2013, BP announced it had signed a contract with Hyundai Mipo Dockyard Co., Ltd to build 14 new product tankers in Korea. The first of these will be delivered in 2016.

Treasury

Treasury manages the financing of the group centrally, ensuring liquidity is sufficient to meet group requirements, and manages key financial risks including interest rate, foreign exchange, pension and financial institution credit risk. From locations in the UK, the US and Singapore, Treasury provides the interface between BP and the international financial markets and supports the financing of BP’s projects around the world. Treasury trades foreign exchange and interest rate products in the financial markets, hedging group exposures and generating incremental value through optimizing and managing cash flows and the short-term investment of operational cash balances. Trading activities are underpinned by the compliance, control and risk management infrastructure common to all BP trading activities. For further information, see Financial statements – Note 19.

Insurance

The group generally restricts its purchase of insurance to situations where this is required for legal or contractual reasons. Losses are borne as they arise, rather than being spread over time through insurance premiums with attendant transaction costs. This approach is reviewed on a regular basis and if specific circumstances require such a review.

Outlook

In 2014 Other businesses and corporate annual charges, excluding non-operating items, are expected to be in the range of $1.6-$2.0 billion.

 

 

BP Annual Report and Form 20-F 2013       37   


Table of Contents

Gulf of Mexico oil spill

We remain committed to meeting our responsibilities to the US federal, state and local governments and communities of the Gulf Coast following the Deepwater Horizon accident.

 

LOGO

We have made significant progress in completing the response to the accident and supporting economic and environmental recovery efforts in affected areas.

Completing the response

BP, working under the direction of the US Coast Guard’s Federal On-Scene Coordinator, continued to complete the Deepwater Horizon operational response activities. By the end of 2013, operational activity continued on just 37 of the approximately 4,400 shoreline miles in the area of response. These 37 shoreline miles were all in Louisiana and were subject to patrolling and maintenance, final monitoring or inspection, or were pending final Coast Guard approval at the end of 2013. The US Coast Guard ended active clean-up in Mississippi, Alabama and Florida in June 2013.

The US Coast Guard has indicated that if oil is later discovered in a shoreline segment where removal actions have been deemed complete, they will follow long-standing response protocols established under the law and contact whoever it believes is the responsible party or parties.

Environmental restoration

BP is responsible for the reasonable and necessary costs of assessing potential injury to natural resources resulting from the oil spill as well as the reasonable and necessary costs of restoration as defined under the Oil Pollution Act of 1990. In 2013 activity was focused on natural resource damage assessment but some early restoration work has also begun.

Natural resource damage assessment

Scientists from BP, government agencies, academia and other organizations are studying a range of species and habitats to understand how wildlife populations and the environment may have been affected by the accident and oil spill. Since May 2010, more than 240 initial and amended work plans have been developed by state and federal trustees and BP to study resources and habitat. The study data will inform an assessment of injury to natural resources in the Gulf of Mexico and the development of a restoration plan to address the identified injuries. By the end of 2013, BP had paid approximately $1 billion to support the assessment process.

Early restoration projects

While the injury assessment is still ongoing, restoration work has begun. In April 2011 BP committed to provide up to $1 billion in early restoration funding to expedite recovery of natural resources injured as a result of the Deepwater Horizon accident and oil spill. BP and the trustees, as at December 2013, had reached agreement or agreement in principle on a

 

total of 54 early restoration projects that are expected to cost approximately $698 million, including 10 projects that are already in place or under way.

Projects announced in 2013 include ecological projects that will restore habitat and resources, as well as projects that enhance recreational use of natural resources. These projects will proceed through a further regulatory review and public comment process. Once that process is complete, BP and the trustees will seek to proceed with approved projects. BP will provide project funding in exchange for restoration credit to be applied to the final assessment of natural resource damages.

Gulf of Mexico Research Initiative

In May 2010 BP committed $500 million over 10 years to fund independent scientific research through the Gulf of Mexico Research Initiative. The goal of the research initiative is to improve society’s ability to understand, respond to and mitigate the potential impacts of oil spills to marine and coastal ecosystems. As at 31 December 2013, the aggregate contribution by BP was $169 million. The continued fulfilment of this commitment is one of the conditions of the US government criminal plea agreement (see below).

Economic recovery

BP continued to support economic recovery efforts in local communities through a variety of actions and programmes in 2013. By 31 December 2013, BP had spent $12.8 billion on economic recovery, including claims, advances, settlements and other payments, such as state tourism grants and funding for state-led seafood testing and marketing. BP has committed $2.3 billion to help resolve economic loss claims related to the Gulf of Mexico seafood industry, of which $1.2 billion has been paid in to the seafood compensation fund but has not yet been distributed to final claimants.

Plaintiffs’ Steering Committee settlements

BP reached settlements in 2012 with the Plaintiffs’ Steering Committee (PSC) to resolve the substantial majority of legitimate individual and business claims and medical claims stemming from the accident and oil spill. The PSC acts on behalf of individual and business plaintiffs in the multi-district litigation proceedings in New Orleans (see Legal update below). During 2013, amounts paid out under the PSC settlements totalled $2.7 billion.

As part of its monitoring of payments made by the court-supervised settlement programme for the economic and property damages settlement, BP identified and disputed multiple business economic loss claim determinations that appeared to result from an incorrect interpretation of the economic and property damages settlement agreement by the claims administrator. See further details under Legal update below. BP has also raised issues about misconduct and inefficiency in the facility administering the settlement.

The medical benefits class action settlement provides for claims to be paid to qualifying class members from the agreement’s effective date. Following the resolution of all appeals relating to this settlement, the agreement’s effective date was 12 February 2014. The deadline for submitting claims under the settlement is one year from the effective date.

OPA claims programme

There is a separate BP claims programme which handles claims under the Oil Pollution Act of 1990 (OPA) by individuals and businesses who are not covered by the PSC economic and property damages settlement, who have opted out of the settlement or who are pursuing claims separately, as permitted by the terms of the settlement. During 2013, amounts paid out in relation to the OPA claims programme totalled $31 million.

State and local claims

Several states and local government entities have presented claims for alleged losses, including economic and property damage, under OPA. BP has provided for the current best estimate of the amount required to settle these obligations. BP considers most of these claims to be unsubstantiated and the methodologies used to calculate them to be seriously flawed, not supported by OPA, not supported by documentation and to be substantially overstated. A total of $89 million was paid in relation to state and local claims in 2013.

For further information on the PSC settlements and state and local claims, see Legal proceedings on page 257, Financial Statements – Note 2 and bp.com/uslegalproceedings.

 

 

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Legal update

BP is subject to a number of different legal proceedings in connection with the Deepwater Horizon incident. These include the legal proceedings relating to the PSC settlements; the multi-district litigation proceedings in New Orleans; a range of civil lawsuits, including claims brought by states and local government entities; other civil claims by individuals and businesses; and the multi-district litigation proceedings in Houston in relation to alleged violations of securities legislation. In 2012, BP reached a settlement with the US Department of Justice relating to all federal criminal charges and a settlement with the SEC resolving certain civil claims. Certain BP entities have been subject to suspension and debarment by the US Environmental Protection Agency (EPA).

PSC settlements

There have been various rulings from the district court and the US Court of Appeals for the Fifth Circuit (Fifth Circuit) on matters relating to interpretation of the PSC economic and property damages settlement agreement, including the meaning of the causation requirements of the agreement.

In 2013 a panel of the Fifth Circuit (the business economic loss panel) set aside the claims administrator’s interpretation of the business economic loss framework of the settlement agreement and instructed the district court in New Orleans to undertake additional proceedings to determine the correct interpretation of the agreement. In December 2013, the district court ruled that, for the purposes of determining business economic loss claims, revenues must be matched with expenses incurred by claimants in conducting their business even where the revenues and expenses were recorded at different times. The district court assigned the development of more detailed matching requirements to the claims administrator. The claims administrator has issued a draft policy addressing the matching of revenue and expenses for business economic loss claims. The parties have made written submissions on the draft policy and the claims administrator will issue a final policy to which BP and the PSC have the right to object and seek review by the district court.

The district court also ruled that the settlement agreement did not contain a causation requirement beyond the revenue and related tests set out in an exhibit to that agreement. BP appealed the district court’s ruling on causation to the business economic loss panel, but the panel affirmed the district court’s ruling on 3 March 2014. BP is considering its appeal options, including a potential petition that all the active judges of the Fifth Circuit review the 3 March decision. The temporary injunction on business economic loss claims offers and payments will be lifted when the case is transferred back to the district court; the timing of this would be affected by the status of any such petition by BP.

A separate but related appeal was brought by objectors to the economic and property damages settlement challenging the overall fairness and lawfulness of the agreement. This appeal was heard by a different panel of the Fifth Circuit, which, in January 2014, upheld the district court’s approval of the settlement agreement and left to the business economic loss panel the question of how to interpret the agreement, including the meaning of the agreement’s causation requirements. BP and several of the objectors have filed petitions requesting that all the active judges of the Fifth Circuit review the decision to uphold the approval of the settlement.

BP has filed a lawsuit alleging that it relied on fraudulent representations by a former PSC lawyer when negotiating aspects of the PSC settlement relating to the $2.3-billion seafood compensation fund. The district court granted the lawyer’s motion to stay this lawsuit, pending developments in the government’s criminal investigation and possible indictment. The district court also denied BP’s motion requesting that further payments from the seafood compensation fund be suspended on the basis that no further payment from the fund is imminent. The district court deferred ruling on a motion by BP seeking to determine the extent of the fraud and what portion, if any, of the seafood fund should be returned as a result.

Multi-district litigation proceedings in New Orleans

The multi-district litigation trial relating to liability, limitation, exoneration and fault allocation (MDL 2179) began in the federal district court in New Orleans in February 2013. The first phase of the trial focused on the causes of the accident and the allocation of fault among the defendants. The second phase focused on efforts to stop the flow of oil and the volume of oil spilled. BP is not aware of the timing of the district court’s rulings in respect of these first two phases of the trial and the court could issue its decision at any time.

In a subsequent trial phase, for which no trial date has yet been set, the district court will consider the statutory per-barrel penalty rate to be applied in determining penalties under the Clean Water Act. There is significant uncertainty about the amount of Clean Water Act penalties to be paid, and the timing of payment, as these will depend on the finding as to negligence or gross negligence, the volume of oil spilled and the application of statutory penalty factors. The district court has wide discretion in its determination as to whether a defendant’s conduct involved negligence or gross negligence as well as in its determinations on the volume of oil spilled and the application of statutory penalty factors.

Civil claims

BP p.l.c., BP Exploration & Production Inc. (BPXP – the BP group company that conducts exploration and production operations in the Gulf of Mexico) and various other BP entities have been among the companies named as defendants in approximately 2,950 civil lawsuits resulting from the accident and oil spill, including the claims by several states and local government entities referred to above. The majority of these lawsuits assert claims under OPA, as well as various other claims, including for economic loss and real property damage, and claims under maritime law and state law. These lawsuits seek various remedies including economic and compensatory damages, punitive damages, removal costs and natural resource damages. Many of the lawsuits assert claims excluded from the PSC settlements, such as claims for recovery for losses allegedly resulting from the 2010 federal deepwater drilling moratoria and the related permitting process. Many of these lawsuits have been consolidated with the multi-district litigation proceedings in New Orleans.

Multi-district litigation proceedings in Houston

The MDL 2185 proceedings pending in federal court in Houston, including a purported class action on behalf of purchasers of American Depository Shares under US federal securities law, are continuing. A jury trial is scheduled to begin in October 2014.

SEC settlement

In connection with the 2012 settlement with the SEC resolving the SEC’s Deepwater Horizon-related civil claims, as of 31 December 2013, BP had completed its first two payments totalling $350 million. A final $175 million payment, plus accrued interest, is scheduled for 2014.

US government criminal plea agreement

Under the terms of the criminal plea agreement reached with the US government in 2012 to resolve all federal criminal claims arising out of the Deepwater Horizon incident, BP is taking additional actions, enforceable by the court, to further enhance the safety of drilling operations in the Gulf of Mexico. The first annual update on BP’s compliance with the plea agreement is expected to be available by 31 March 2014 and to be published at bpxpcompliancereports.com.

The plea agreement also provides for the US government to appoint two independent monitors – a process safety monitor and an ethics monitor – as well as an independent third-party auditor. The process safety monitor has been retained, for a period of up to four years from February 2014, and will review and provide recommendations concerning BPXP’s process safety and risk management procedures for deepwater drilling in the Gulf of Mexico. The ethics monitor has been retained, for a term of up to four years from 2013, and will review and provide recommendations concerning BP’s ethics and compliance programme. The third-party auditor has also been retained and will review and report to the probation officer, the US government and BP on BPXP’s compliance with the plea agreement’s implementation plan.

US Environmental Protection Agency (EPA) suspension and debarment

In November 2012, the EPA suspended BP p.l.c., BPXP and other BP companies from receiving new federal contracts or renewing existing ones. In 2013, the EPA debarred the Houston headquarters of BPXP, thus effectively preventing it from entering into new contracts or leases with the US government. In November 2013, the EPA continued the suspensions of the previously suspended companies, suspended two new BP entities and proposed discretionary debarment of all suspended BP entities. BP is challenging the EPA’s suspension and debarment decisions. Neither the suspensions nor the proposed debarments 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. BP

 

 

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continues to work with the EPA in preparing an administrative agreement to resolve these suspension and debarment issues.

For further information on these matters, see Risk factors on page 51 and Legal proceedings on page 257.

Financial update

The group income statement for 2013 includes a pre-tax charge of $469 million in relation to the Gulf of Mexico oil spill. The charge for the year reflects adjustments to provisions and the ongoing costs of the Gulf Coast Restoration Organization. As at 31 December 2013, the total cumulative charges recognized to date amount to $42.7 billion. BP has provided for spill response costs, environmental expenditure, litigation and claims and Clean Water Act penalties that can be measured reliably. At 31 December 2013, provisions related to the Gulf of Mexico oil spill amounted to $9.3 billion (2012 $15.2 billion).

The cumulative income statement charge does not include amounts for obligations that BP considers are not possible, at this time, to measure reliably. Nothing is currently provided for natural resource damages, except for $1 billion for early restoration projects and no provision has been made for amounts arising from MDL 2185 (securities class action). In addition, management believes that no reliable estimate can be made of any business economic loss claims not yet received, processed and paid. This is because of the significant uncertainties which exist currently, as noted in the Plaintiffs’ Steering Committee section above (see also Financial statements – Note 2). The additional amounts payable for these and other items (such as state and local claims) could be considerable.

The total amounts that will ultimately be paid by BP in relation to all the obligations relating to the accident and oil spill are subject to significant uncertainty. The ultimate exposure and cost to BP will be dependent on many factors, including any new information or future developments. These could have a material impact on our consolidated financial condition, results of operations and cash flows. The risks associated with the accident and oil spill could also heighten the impact of the other risks to which the group is exposed.

For details regarding the impacts and uncertainties relating to the Gulf of Mexico oil spill, see Risk factors on page 51 and Financial statements – Note 2.

Deepwater Horizon Oil Spill Trust update

BP, in agreement with the US government, set up the $20-billion Deepwater Horizon Oil Spill Trust (the Trust) to provide confidence that funds would be available to satisfy individual and business claims, final judgments in litigation and litigation settlements, state and local response costs and claims, and natural resource damages and related costs. The Trust was fully funded by the end of 2012.

Payments made out of the Trust during 2013 totalled $3.1 billion for individual and business claims, medical settlement programme payments, natural resource damage assessment and early restoration, state and local government claims, costs of the court supervised settlement progamme and other resolved items. As at 31 December 2013, the aggregate cash balances in the Trust and the associated qualified settlement funds amounted to $6.7 billion, including $1.2 billion remaining in the seafood compensation fund, which is yet to be distributed, and $0.9 billion held for natural resource damage early restoration projects.

As at 31 December 2013, the cumulative charges to the Trust amounted to $19.3 billion. Thus, a further $0.7 billion could be charged in subsequent periods for items covered by the Trust with no net impact on the income statement. Additional liabilities in excess of this amount would be expensed to the income statement. See Legal proceedings on page 257 and Financial statements – Note 2 for more information.

 

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Clean Water Act penalties

BP has recognized a provision of $3.5 billion for the estimated civil penalties for strict liability under the Clean Water Act, which are based on a specified range per barrel of oil released. The penalty rate per barrel used to calculate this provision is based upon BP’s conclusion, among other things, that it did not act with gross negligence or engage in wilful misconduct.

If BP is found to have been grossly negligent, the penalty is likely to be significantly higher than the amount currently provided. See further details under Multi-district litigation proceedings in New Orleans above and in Financial statements – Note 2.

 

 

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Corporate responsibility

We believe we have a positive role to play in shaping the long-term future of energy.

 

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

Fire safety training in Angola.

Safety

We continue to promote deep capability and a safe operating culture across BP.

 

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Group safety performance

In 2013 BP reported six fatalities. These were four employees in the terrorist attack at In Amenas, Algeria and two contractors in heavy goods vehicle incidents, one in Brazil and one in South Africa. We deeply regret the loss of these lives.

Personal safety performance

 

       2013         2012         2011   

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

     0.31         0.35         0.36   

Day away from work case frequencyb (group) – incidents per 200,000 hours worked

     0.070         0.076         0.090   

 

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

Process safety performance

 

       2013         2012         2011   

Tier 1 process safety events

     20         43         74   

Loss of primary containment –
number of all incidentsc

     261         292         361   

Loss of primary containment –
number of oil spillsd

     185         204         228   

Number of oil spills to land and water

     74         102         102   

Volume of oil spilled (thousand litres)

     724         801         556   

Volume of oil unrecovered
(thousand litres)

        261            320            281   

 

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

We report tier 1 process safety events defined as 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. We use the American Petroleum Institute (API) RP-754 standard. Our loss of primary containment (LOPC) metric 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. We seek to record all LOPCs regardless of the volume of the release and report on losses over a severity threshold.

Managing safety

We are working to continuously improve safety and risk management across BP. Three objectives guide our efforts:

 

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

 

  To embed OMS as the way BP operates.

 

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

Within BP, operating businesses are accountable for delivering safe, compliant and reliable operations. They are supported in this by our safety and operational risk (S&OR) function whose role is to:

 

  Set clear requirements.

 

  Maintain an independent view of operating risk.

 

  Provide deep technical support to the operating businesses.

 

  Intervene and escalate as appropriate to cause corrective action.

Governance

BP reviews risks at all levels of the organization. Each business segment has a safety and operational risk committee, chaired by the business head, to oversee the management of safety and risk in their respective areas of the business. In addition, the group operations risk committee (GORC) reviews safety and risk management across BP.

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 GORC’s work. GORC also provides SEEAC with updates on BP’s process and personal safety performance, and the monitoring of major incidents and near misses across the group. See Our management of risk on page 49.

 

 

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Operating management system (OMS)

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.

All BP businesses covered by the OMS are required to progressively align with this framework through an annual performance improvement cycle. Recently acquired operations need to transition to the OMS as the initial step in this process. The application of a comprehensive management system such as OMS across a global company is an ongoing process. See page 44 for information about joint arrangements.

Capability development

BP’s capability development programmes are designed to equip our staff with the skills needed to run safe and efficient operations. The programmes cover our OMS, process safety and risk and safety leadership. Our global wells institute offers courses in areas such as applied deepwater well control, drilling engineering and well site leadership with more than 100 sessions delivered in 2013. It includes a simulator facility and an applied deepwater well control course where drilling personnel, including our contractors, can work together and practice a variety of well control situations. Trainers include experts from both inside and outside of the oil and gas industry.

Security and crisis management

The scale and spread of BP’s operations means we must prepare for a range of potential business disruptions and emergency events. BP monitors for and aims to guard against hostile actions that could cause harm to our people or disrupt our operations, including physical and digital threats and vulnerabilities.

We also maintain disaster recovery, crisis and business continuity management plans and work to build day-to-day response capabilities to support local management of incidents and group-wide practices and response techniques. See page 44 for information on BP’s approach to oil spill preparedness and response.

In January 2013, the In Amenas gas plant in Algeria, which is run as a joint operation between BP, Sonatrach (the national gas company of Algeria) and Statoil, came under armed terrorist attack. A total of 40 people from 10 countries and 10 organizations were killed in the attack. Four employees and a former employee lost their lives in the incident. BP and Statoil jointly carried out an extensive review of security arrangements in Algeria following the attack and we are working with Sonatrach on implementing a programme of security enhancements.

Safety in the Upstream business

 

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In our Upstream business the recordable injury frequency for 2013 remained stable at 0.32, the same as in 2012. Our day away from work case frequency, incidents that resulted in an injury where a person is unable to work for a day (shift) or more, was 0.068 in 2013 compared to 0.053 in 2012. The number of reported loss of primary containment (LOPC) incidents was 143, down from 151 in 2012.

Safer drilling

Our global wells organization (GWO) is responsible for planning and executing our wells operations across the world. It brings wells expertise into a single organization to drive standardization and consistent implementation. It is also responsible for establishing new GWO standards on compliance, risk management, contractor management, performance indicators, technology and capability.

We have been developing and finalizing OMS conformance plans for activities which represent the highest risk areas in our wells operations. For example we have developed and applied new and revised engineering technical practices for activities such as well barriers and testing.

The Bly Report recommendations

BP’s investigation into the Deepwater Horizon accident in 2010, the Bly Report, made 26 recommendations aimed at further reducing risk across BP’s global drilling activities. They included strengthening contractor management, improving assurance on blowout preventers, well control, pressure-testing for well integrity, emergency systems, cement testing, rig audit and verification, and personnel competence.

At the end of 2013, 15 of the Bly Report recommendations had been completed. All 26 recommendations have been worked on in parallel and progress has been made towards each of them. By the end of 2013, over 75% of the deliverables that make up the 26 recommendations had been completed. A recommendation is defined as complete when it has been approved by senior management in our global wells organization and submitted for internal verification.

The outstanding recommendations relate to well control and well integrity, drilling and competence, the management of risk and change, and blowout preventers.

The board’s safety, ethics and environment assurance committee monitors BP’s global implementation of the measures recommended in the Bly Report, and progress is tracked quarterly by executive

 

 

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management. For the full report and periodic updates on progress see bp.com/internalinvestigation.

The Bly Report – independent assessment

The BP board appointed Carl Sandlin as independent expert to provide an objective assessment of BP’s global progress in implementing the deliverables from the Bly Report.

As part of his work, Mr Sandlin visited the regional wells teams with active operation twice in 2013. During each visit Mr Sandlin conducted reviews with their senior management and held discussions with key wells personnel and drilling contractors onsite.

The BP board and Mr Sandlin have agreed, in principle, that his engagement, initially scheduled to finish in June 2014, will be extended to June 2016.

Process safety monitor

Following legal settlements with the US government in 2012, BP has retained a process safety monitor for a term of up to four years from February 2014. The process safety monitor will review and provide recommendations concerning BP Exploration & Production Inc’s process safety and risk management procedures for deepwater drilling in the Gulf of Mexico.

Sharing lessons learned

We continue to share what we have learned to advance global deepwater capabilities and practices that enhance safety in our company and the deepwater industry. We have conducted more than 200 briefings over the past three years to share lessons learned. We have worked with a range of industry partners including trade associations, host governments, national oil companies and regulators. For example we are working with the International Association of Oil & Gas Producers, Marine Well Containment Company, API and the International Association of Drilling Contractors.

Safety in the Downstream business

 

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The process safety incident index (PSII) is a weighted index that reflects both the number and severity of events per 200,000 hours worked. In 2013 our PSII was down 60% compared to a baseline year of 2009. There were 101 LOPCs in 2013 down from 117 in 2012, with divestments accounting for a significant part of this reduction.

We measure personal safety performance through recordable injury frequency (RIF) and day away from work case frequency (DAFWCF) as well as severe vehicle accident rate (SVAR). In 2013 our RIF was 0.25 compared to 0.33 in 2012. The 2013 DAFWCF, the number of cases where an employee misses one or more days from work per 200,000 hours worked, was 0.063 compared to 0.089 in 2012.

Our SVAR which is the number of vehicle incidents that result in death, injury, a spill, a vehicle rollover, or serious disabling vehicle damage per one million kilometres travelled, was 0.10 in 2013 compared to 0.16 in 2012. Driving safety remains an area of focus for us.

We focus on the safe storage, handling and processing of hydrocarbons in our facilities across the Downstream business. 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.

 

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

Some areas where we worked to manage risks in our refining and petrochemicals portfolio in 2013 included:

 

  Corrosion: Improving the way we detect, measure and monitor corrosion with the aim of reducing the risk of leaks and increasing the reliability of our equipment. We are using industry benchmarks and technology to improve routine detection.

 

  Coaching: Nine manufacturing facilities participated in the Exemplar programme which aims to help sites apply our operating management system using continuous improvement processes.

 

  Site occupied buildings: We moved workforce further away from higher risk processing areas at our petrochemical plant in Zhuhai, China and installed an improved evacuation alert system at our chemical plant in Hull in the UK, as part of a multi-year programme.

Process safety expert for our Downstream business

The board’s safety, ethics and environment assurance committee appointed Duane Wilson in May 2012 as process safety expert and assigned him to work in a global capacity with the Downstream business. In his role as process safety expert, Mr Wilson provides an independent perspective on the progress that BP’s fuels, lubricants and petrochemicals businesses are making globally toward becoming industry leaders in process safety performance. Mr Wilson’s contract has been extended to April 2015.

Working with partners and contractors

BP, like all our industry peers, rarely works in isolation – we need to work with suppliers, contractors and partners to carry out our operations. In 2013, 54% of the 373 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 and contractors. To this end we set operational standards through legally-binding agreements. Training and dialogue also help build the capability of our contractors.

Contractors

We expect our contractors to comply with legal and regulatory requirements and to operate consistently with the principles of our code of conduct when working on our behalf. Our OMS includes requirements

 

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A contractor checks a pump in the production module on the Thunder Horse platform in the Gulf of Mexico, US.

 

 

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and practices for working with contractors and our operations are obliged to plan and execute actions to reach conformance with OMS on contractor management.

We seek to set clear and consistent expectations of our contractors. In our Upstream business our standard model contracts include, for example, health, safety, security and environmental requirements.

Bridging documents are necessary in some cases to define how our safety management system and that of our contractors co-exist to manage risk on the work site.

In 2011 we undertook a review of how we manage contractors in our Upstream business, which examined best practice in BP and other industries that use contractors to perform potentially high-consequence activities. As a result of this review, we are focusing on developing deeper, longer-term relationships with selected contractors in our Upstream business. We have:

 

  Established global agreements that help to strengthen our relationships with strategic contractors and suppliers, manage risks more effectively and leverage economies of scale.

 

  Increased the rigour of health and safety qualification and selection criteria when approving contractor and supplier capabilities.

 

  Piloted guidance for the operating line on parts of our OMS that relate to working with contractors.

 

  Continued working with our strategic contractors and suppliers to create standardized technical specifications and quality requirements for certain equipment, initially focused on new projects.

 

  Worked on incorporating safety and quality key performance metrics into contracts for potentially high-consequence activities.

Our partners in joint arrangements

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 arrangement is linked to the size of our financial stake compared with other participants. Our code of conduct provides that we will do everything we reasonably can to make sure joint arrangements follow similar principles to those in our code. In some joint arrangements 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 arrangement.

In other cases, one of our joint arrangement partners may be the designated operator, or the operator may be an incorporated joint arrangement 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.

We introduced a group policy in 2013 to provide a consistent framework for identifying and managing BP’s exposure related to safety and operational risk, as well as bribery and corruption risk, from our participation in new and existing non-operated joint arrangements.

Environment and society

Throughout the life cycle of our projects and operations, we aim to manage the environmental and social impacts of our presence.

 

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Managing our impacts

At a group level, we review our management of material issues such as GHG emissions, water, oil spill response, sensitive and protected areas and human rights annually. Using our operating management system (OMS), we seek to identify emerging risks and assess methods to reduce them across the company.

Our OMS includes environmental and social practices that set out how our major projects identify and manage environmental and social impacts. The practices 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 to identify the most significant environmental and social impacts. Projects are required to identify mitigation measures and implement these in design, construction and operations. From April 2010 to the end of 2013, 91 projects had completed the screening process, and used outputs from the process to implement measures to reduce negative impacts.

BP’s environmental expenditure in 2013 totalled $4,288 million (2012 $7,230 million, 2011 $8,491 million). This figure includes a credit of $66 million relating to the Gulf of Mexico oil spill. For reference, expenditure related to the Gulf of Mexico oil spill was a charge of $919 million in 2012 and $1,838 million in 2011. See page 252 for a breakdown of environmental expenditure. See Regulation of the group’s business – Environmental regulation on page 254.

Oil spill preparedness and response

We issued new group-wide requirements for oil spill preparedness and response planning, and crisis management in July 2012. These incorporate what we have learned from the Deepwater Horizon accident. All of our businesses that have the potential to spill oil have been updating oil spill planning scenarios and response strategies in line with the requirements.

Meeting the requirements is a substantial piece of work and we believe this work has already resulted in a significant increase in our oil spill

 

 

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response capability. For example, this includes using specialized modelling techniques and the provision of response capabilities, such as stockpiles of dispersants and planning for major offshore recovery operations.

Enhancing response capabilities

Improving our existing oil spill modelling tools helps BP to better define different oil spill scenarios and associated response plans. For example, following modelling for exploration in the Omani desert, we modified the planned location of pipelines to reduce the impact to groundwater if a spill were to occur.

We consider the environmental and socio-economic sensitivities of a region to help inform oil spill response planning. Sensitivity mapping helps us to identify the various types of habitats, resources and communities that could potentially be impacted by oil spills and develop appropriate response strategies. Sensitivity mapping is conducted around the world and in 2013 we updated sensitivity maps in Angola, Australia, Azerbaijan, Egypt, Libya, Trinidad & Tobago and the UK.

The use of dispersants is an important option in oil spill response planning. We have gained a greater understanding of dispersants and their use as a response option through scientific research programmes. We are examining topics such as the effectiveness of dispersants in the deep ocean and the efficiency of naturally occurring marine microbes to degrade dispersed oil in the Gulf of Mexico and in the seas of Australia, Azerbaijan and Egypt.

We seek to work collaboratively with government regulators in planning for oil spill response, with the aim of improving any potential future response. For example, in 2013 we shared lessons on dispersant use, controlled burning response strategies and oil spill modelling with government regulators in Azerbaijan, Brazil and Libya.

See page 42 for information on progress on the recommendations of BP’s internal investigation into the Deepwater Horizon accident.

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 taking a number of practical steps, such as increasing energy efficiency in our operations, factoring a carbon cost into the investment and engineering decisions for new projects, and investing in lower-carbon energy products. We also require our operations to incorporate energy use considerations in their business plans and to assess, prioritize and implement technologies and systems to improve energy usage.

Climate change adaptation

We consider and identify risks and potential impacts of a changing climate on our facilities and operations. Where climate change impacts are identified as a risk for a new 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.

Greenhouse gas emissions

We report on GHG emissions on a carbon dioxide-equivalent (CO2e) basis. This includes CO2 and methane for direct emissions and CO2 for indirect emissions, which are associated with the purchase of electricity, heat or steam into our operations. Our GHG reporting encompasses all BP’s consolidated entities as well as our share of equity-accounted entities other than BP’s share of TNK-BP and Rosneft. Rosneft’s emissions data can be found on its website.

Our approach to calculating GHG emissions is aligned with the Greenhouse Gas Protocol and the IPIECA/API/OGP Petroleum Industry Guidelines for Reporting GHG Emissions. We calculate emissions based on the fuel consumption and fuel properties for major sources rather than the use of generic emission factors. We do not include nitrous oxide, hydrofluorocarbons, perfluorocarbons and sulphur hexafluoride as they are not material and therefore it is not practical to collect this data.

Greenhouse gas emissions

 

       2013         2012         2011   

Direct GHG emissions (Mte CO2e)

     49.2         59.8         61.8   

Indirect GHG emissions (Mte CO2e)

     6.6         8.4         9.0   

The decrease in our direct GHG emissions is primarily due to the divestment of our Texas City and Carson refineries.

Intensity

The ratio of our total greenhouse gas emissions to adjusted revenue of those entities (or share of entities) included in our GHG reporting was 0.15kte/$million in 2013. Adjusted revenue reflects total revenues and other income, less gains on sales of businesses and fixed assets. Additionally, we publish the ratios for greenhouse gas emissions to upstream production, refining throughput and chemicals produced at bp.com/greenhousegas.

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.

Accordingly, 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, our standard cost assumption is currently $40 per tonne of CO2e. 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.

Water

BP recognizes the importance of access to fresh water and the need to manage water discharges at our operations. We assess risks, such as water scarcity, wastewater disposal and the long-term social and environmental pressures on water resources within the local area.

We are investing in research with several universities in the US to help understand future risks in water management, such as the allocation and use of water in the Middle East and the impact of water policies and regulation around the world.

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 Algeria, Indonesia, Oman and the US.

Some stakeholders have raised concerns about the potential environmental and community impacts of hydraulic fracturing. BP seeks to apply responsible well design and construction, surface operation and fluid handling practices to mitigate these impacts.

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 the fracturing process help to reduce friction and control bacterial growth in the well. Some of these chemicals when used in certain concentrations are classified as hazardous by the relevant regulatory authorities, and each chemical used in the fracturing process is listed in the material safety data sheets kept at each operational site. We submit data on chemicals used at our hydraulically fractured wells in the US, to the extent allowed by our suppliers who own the chemical formulas, at fracfocus.org.

We aim to minimize air pollutant and greenhouse gas emissions by using responsible practices at our operating sites. For example, at our drilling sites in the US we use a process called green completions, whenever possible, to manage methane emissions associated with well completions following hydraulic fracturing. This process recovers natural gas for sale and minimizes the amount of natural gas either flared or vented from our wells.

 

 

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LOGO

 

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Environmental monitoring at our Terre de Grace oil sands lease area in Northern Alberta, Canada.

We seek to design and locate our equipment and manage our work patterns in ways that reduce potential impacts to communities such as increased traffic, noise, dust and light. 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

Oil sands in Canada are the third-largest proven crude oil reserves in the world, after Saudi Arabia and Venezuela. About half of the world’s total oil reserves that are open to private sector investment are contained in Canada’s oil sands. BP is involved in three oil sands lease areas, all of which are located in the province of Alberta. We expect the Sunrise Energy Project, operated by Husky Energy, to be the first onstream with production expected to begin in late 2014. Engineering and appraisal activities are under way to design and plan the construction of the first phase of Pike, which is operated by Devon Energy. Terre de Grace, which is BP-operated, is currently under appraisal for development.

Our decision to invest in Canadian oil sands projects takes into consideration GHG emissions, impacts on land, water use, local communities and commercial viability. In the case of joint arrangements in which we are not the operator, we monitor both 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.

Human rights

BP’s human rights policy, published in 2013, outlines our commitment to respect internationally-recognized human rights, as set out in the International Bill of Human Rights and the International Labour Organization’s Declaration on Fundamental Principles and Rights at Work. The policy applies to all employees and officers in BP wholly owned entities and in joint arrangements to the extent possible and reasonable given BP’s level of participation.

The United Nations Guiding Principles on Business and Human Rights outline specific responsibilities for businesses in relation to human rights. We are committed to working towards aligning with the Guiding Principles using a risk-based approach. In 2013 our actions included:

 

  Human rights workshops for senior leaders in Indonesia and the Middle East, with plans to roll these out in other high-priority regions.

 

  Inclusion of human rights in our impact assessment for the LNG expansion project in Tangguh, Indonesia.

 

  Collaboration with industry peers on the development of good practice guidance for integrating human rights into environmental and social impact assessments.
  Participation in the work of oil and gas industry organization IPIECA’s taskforce on developing shared industry approaches to managing human rights risks in the supply chain.

We plan to monitor the effectiveness of these actions. More information about our approach to human rights may be found at bp.com/humanrights.

Business ethics

Bribery and corruption are significant 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, whether in the public or private sector. We operate a group-wide anti-bribery and corruption standard, which applies to all BP employees and contractor staff. The standard requires annual bribery and corruption risk assessments; risk-based 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. Our processes are designed to enable us to choose suppliers carefully on merit, avoiding conflicts of interest and inappropriate gifts and entertainment.

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 (Dodd-Frank) in the US.

Financial transparency

As a member of the Extractive Industries Transparency Initiative (EITI), we work with governments, non-governmental organizations and international agencies to improve transparency and disclosure of payments to governments. BP is supporting several countries that are working towards becoming EITI compliant.

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 EU for companies in the extractive industries. We are awaiting the publication of the revised rules of the Dodd-Frank legislation from the SEC and are preparing to comply with the disclosure requirements.

We are contributing to the consultation process initiated by the UK government in preparation for the adoption of the EU accounting directive into UK law.

Enterprise and community development

In a number of BP locations, we run programmes to help build the skills of businesses and to develop the local supply chain. For example, we have helped some local companies reach the standards needed to supply BP and other organizations through training and sharing of our standards in areas such as health and safety.

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.

In 2013, we contributed $78.8 million in social investment. More information about our social contribution can be found at bp.com/society.

 

 

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Employees

BP seeks employees who have the right skills for their roles and who understand and embody the values and expected behaviours that guide everything we do as a group.

 

LOGO

BP headcount

 

Number of employees at 31 Decembera      US         Non-US         Total   

2013

        

Upstream

     9,300         15,400         24,700   

Downstream

     8,300         39,700         48,000   

Other businesses and corporate

     1,900         9,200         11,100   

Gulf Coast Restoration Organization

     100                 100   
       19,600         64,300         83,900   

2012

        

Upstream

     9,500         14,700         24,200   

Downstream

     11,900         39,900         51,800   

Other businesses and corporate

     1,900         8,400         10,300   

Gulf Coast Restoration Organization

     100                 100   
       23,400         63,000         86,400   

2011

        

Upstream

     8,900         13,500         22,400   

Downstream

     12,000         39,500         51,500   

Other businesses and corporate

     1,900         8,200         10,100   

Gulf Coast Restoration Organization

     100                 100   
       22,900         61,200         84,100   

 

a  Reported to the nearest 100.

As at the end of December 2013, we had 83,900 employees. This includes 14,100 service station staff and 4,300 agricultural, operational and seasonal workers in Brazil. The numbers for 2011 and 2012 have been restated following the adoption of IFRS 11, see Financial statements – Note 1 for further information.

During 2013, 4,300 people left BP through divestments, while there was an increase in seasonal workers in our biofuels business – resulting in an overall headcount decrease of 3% from 2012.

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 are 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

We are focused on protecting 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.

The group people committee, chaired by the group chief executive, has overall responsibility for key policy decisions relating to employees. The committee is responsible for governance of BP’s people management processes. The committee discussed longer-term people priorities, reward, progress in our diversity and inclusion programme, recruitment priorities (including graduate recruitment), and improvements to our learning and development programmes in 2013.

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. We want to develop the skills we need from within our existing workforce and we complement this with targeted external recruitment.

To address increasing demand for skilled people across the globe, 44% of our graduate recruitment came from universities outside the UK and US in 2013. 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 achieve 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 being considered.

Building enduring capability

We provide development opportunities for all our employees, including international assignments, mentoring, team development days, workshops, seminars and online learning.

We continue to work to embed appropriate leadership skills throughout our organization. By 2013 our group-wide suite of leadership development programmes had been attended by employees from 32 countries and were conducted in six different languages.

We provide leading education opportunities for our people through our internal academies and institutes that deliver leadership development, technical learning and compliance programmes.

Diversity

We are a global company and aim for a workforce that is representative of the societies in which we operate.

We have set out our ambitions for diversity and our group people committee reviews performance on a quarterly basis. We aim for 25% of our group leaders – the most senior managers of our businesses and functions – to be women by 2020.

Workforce by gender

 

Numbers as at 31 December      Male         Female         Female %   

Board directors

     12         2         14   

Group leaders

     477         105         18   

Subsidiary directors

     494         107         18   

All employees

     58,500         25,400         30   

At the end of 2013, 22% of our group leaders came from countries other than the UK and the US. 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 support the UK government-commissioned Lord Davies review which recommends increasing gender diversity on the boards of listed companies. See page 70 for information on our board composition.

Inclusion

Our goal is to create an environment of inclusion and acceptance. For our employees to be 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.

 

 

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LOGO

We aim to ensure equal opportunity in recruitment, career development, promotion, training and reward for all employees, including women; ethnic minorities and different nationalities; lesbian, gay, bisexual and transgender people; those with disabilities; and people of all ages. Where existing employees become disabled, our policy is to provide continuing employment and training wherever possible.

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. We seek to maintain constructive relationships with labour unions.

We conduct an annual engagement survey among our employees. In 2013 approximately 37,000 employees in more than 70 countries gave their views on a wide range of business topics and to identify areas where we can improve.

We measure how engaged our employees are with our strategic priorities. The group priorities index is derived from 12 questions about employee perceptions of BP as a company and how it is managed in terms of leadership and standards. We saw continued improvement in 2013 with a score of 72% (2012 71%, 2011 67%).

Business leadership teams review the results of the survey and agree actions to address identified issues. In 2013, safety scores remained strong and there was an increase in employees’ understanding of the operating management system, an area of focus identified in the previous year. While the survey showed an increase in employee confidence in BP’s leadership, work is needed to further strengthen this.

 

LOGO

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Global business services (GBS) supports BP’s business processes across the globe. Here, members of the family day organizing committee in Malaysia prepare the registration booth.

Share ownership

We encourage employee share ownership. For example, through our ShareMatch plan, which operates in more than 50 countries, we match BP shares purchased by our employees. We operate a single company-wide equity plan, which allows employee participation at different levels globally and is linked to the company’s performance.

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.

Employees, contractors or other third parties who have concerns that laws, regulations or the code of conduct may be breached, can get help through OpenTalk, a helpline operated by an independent company. The number of cases raised through OpenTalk in 2013 was 1,121 (2012 1,295, 2011 796). The increase in OpenTalk cases over the past few years is due, in part, to initiatives to promote our code of conduct and speak up culture. This is supported by high scores in our employee engagement survey relating to employee understanding of the importance of speaking up. The most common issues raised in 2013 related to the people section of the code. This includes treating people fairly, with dignity and giving everyone equal opportunity; creating a respectful, harassment-free workplace; and protecting privacy and confidentiality.

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 2013, 113 employee dismissals were reported by BP’s businesses for non-adherence to the code of conduct or unethical behaviour. This excludes dismissals of staff employed at our retail service station sites, for incidents such as thefts of small amounts of money.

Following legal settlements with the US government in 2012, BP agreed to retain an ethics monitor for a term of up to four years from 2013. The ethics monitor will review and provide recommendations concerning BP’s ethics and compliance programme (see page 39).

Policy on political activity

BP has a policy of not participating directly in party political activity as a group or making any contributions to political candidates, whether in cash or in kind. Employees’ rights to participate in political activity are governed by the applicable laws in the countries in which we operate. For example, in the US, BP supports the operation of the BP employee political action committee to facilitate employee involvement and to assess whether contributions comply with the law and are publicly disclosed.

 

 

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Our management of risk

BP manages, monitors and reports on the principal risks and uncertainties that can impact our ability to deliver our strategy of meeting the world’s energy needs responsibly while creating long-term shareholder value; these risks are described in the Risk factors on page 51.

Our management systems, organizational structures, processes, standards, code of conduct and behaviours together form a system of internal control that governs how we conduct the business of BP and manage associated risks.

BP’s risk management system

BP’s risk management system is designed to be a simple, consistent and clear framework for managing and reporting risks from the group’s operations to the board. The system seeks to avoid incidents and maximize business outcomes by allowing us to:

 

  Understand the risk environment, and assess the specific risks and potential exposure for BP.

 

  Determine how best to deal with these risks to manage overall potential exposure.

 

  Manage the identified risks in appropriate ways.

 

  Monitor and seek assurance of the effectiveness of the management of these risks and intervene for improvement where necessary.

 

  Report up the management chain to the board on a periodic basis about how risks are being managed, monitored, assured and the improvements that are being made.

Our risk management activities

 

LOGO

Day-to-day risk management – management and staff at our facilities, assets and functions identify and manage risk, promoting safe, compliant and reliable operations. For example, our group-wide operating management system (OMS) integrates BP requirements on health, safety, security, environment, social responsibility, operational reliability and related issues. These BP requirements, along with business needs and the applicable legal and regulatory requirements, underpin the practical plans developed to help reduce risk and deliver strong, sustainable performance.

Business and strategic risk management – our businesses and functions integrate risk into key business processes such as strategy, planning, performance management, resource and capital allocation, and project appraisal. We do this by collating risk data, assessing risk management activities, making further improvements and planning new activities. By using a standardized risk management report, we aim for a consistent view of risks across BP.

Oversight and governance – the board, executive and functional leadership provide oversight to identify and understand significant risks to BP. They also put in place systems of risk management, compliance and control to mitigate these risks. Executive committees set policy and oversee the management of group risks, and dedicated board committees review and monitor certain risks throughout the year.

BP’s group risk team analyses the group’s risk profile and maintains the group risk management system. Our group audit team provides independent assurance to the group chief executive and board, through its committees, over whether the group’s system of internal control is adequately designed and operating effectively to respond appropriately to the risks that are significant to BP.

Risk governance and oversight

Key risk governance and oversight committees include the following:

 

Executive committees

 

g  Executive team meeting – for strategic and commercial risks.

 

g  Group operations risk committee – for health, safety, security, environment and operations integrity risks.

 

g  Group financial risk committee – for finance, treasury, trading and cyber risks.

 

g  Group disclosure committee – for financial reporting risks.

 

g  Group people committee – for employee risks.

 

g  Resource commitment meeting – for risks related to investment decisions.

 

g  Group ethics and compliance committee – for risks associated with legal and regulatory compliance and ethics.

 

Board and its committees

 

g  BP board.

 

g  Audit committee.

 

g  Safety, ethics and environment assurance committee.

 

g  Gulf of Mexico committee.

 

LOGO   Board committees
 

For information on the board and its committees see page 71.

 

 

Our risk profile

The nature of our business operations is long term, resulting in many of our identified risks being enduring in nature. Nonetheless, risks can develop and evolve over time and their potential impact or likelihood may vary in response to internal and external events.

As part of BP’s annual planning process, we review the principal risks and uncertainties to the group. We identify those as having a high priority for particular oversight by the board and its various committees in the coming year; the risks identified for particular review in 2014 are listed below. These may be updated throughout the year in response to changes in internal and external circumstances. The oversight and management of the other risks is undertaken in the normal course of business – throughout the business and in executive and board committees.

Further details of the principal risks and uncertainties we face are set out in the Risk factors on page 51. There can be no guarantee that our risk management activities will mitigate or prevent these, or other, risks from occurring.

 

Gulf of Mexico oil spill

There is a wide range of risks arising out of the Gulf of Mexico accident and oil spill. These include legal, operational, reputational and compliance risks.

BP’s management and mitigation of these risks is overseen by the board’s Gulf of Mexico committee, which seeks to ensure that BP fulfils all legitimate obligations whilst protecting and defending BP’s interests.

 

 

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The committee’s responsibilities include oversight and review of the following activities: the legal strategy for litigation; investigations and suspension and debarment actions arising from the accident and oil spill; the strategy connected with settlements and claims; the environmental work to remediate or mitigate the effects of the oil spill; management strategy and actions to restore the group’s reputation in the US; and compliance with government settlement agreements arising out of the accident and oil spill.

See Legal proceedings page 257 and Gulf of Mexico committee page 78 for further information.

 

Strategic and commercial risks

10-point plan

In 2011 we set out a 10-point plan to address our priorities through 2014. Among other things, the plan aims to focus on safety and risk management, efficient investments and disposals, successful delivery of operating cashflows, renewal and repositioning of our portfolio, and delivery of our major projects to plan. We conduct regular planning and performance monitoring activity as part of managing the risks to delivery of this plan. For an update on our progress against the plan see page 22.

Geopolitical

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. Geopolitical risk is inherent to many regions in which we operate; heightened political or social tensions or changes in key relationships could adversely affect the group. We seek to manage this risk actively through the development and maintenance of relationships with governments and stakeholders in each country and region. In addition, we closely monitor events (such as the situation that arose in the Ukraine in February 2014) and implement risk mitigation plans where appropriate.

Cybersecurity

The threats to the security of our digital infrastructure continue to evolve and, like many other global organizations, our reliance on computers and network technology is increasing. A cybersecurity breach could have a significant impact on business operations. We seek to manage this risk through cybersecurity standards, ongoing monitoring of threats, close co-operation with authorities and awareness initiatives throughout the company. We also maintain disaster recovery, crisis and business continuity management plans.

 

Compliance and control risks

Ethical misconduct and legal or regulatory non-compliance

Ethical misconduct or breaches of applicable laws or regulations could damage our reputation, adversely affect operational results and shareholder value, and potentially affect our licence to operate. Our code of conduct and our values and behaviours, applicable to all employees, are central to managing this risk. Additionally, we have various group requirements covering areas such as anti-bribery and corruption, anti-money laundering, competition/anti-trust law and trade sanctions. We keep abreast of new regulations and legislation and plan our response to them. We also operate a range of compliance training and monitoring programmes for our employees. We offer an independent confidential helpline, OpenTalk, for employees, contractors and other third parties. For information on our code of conduct, see page 48.

Under the terms of the US Department of Justice settlement (see Legal proceedings on page 257), an ethics monitor will also review and provide recommendations concerning BP’s ethics and compliance programme.

Trading non-compliance

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

Safety and operational risks

Process safety, personal safety and environmental risks

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 releases of hydrocarbons when drilling wells, operating facilities and transporting hydrocarbons. We apply our operating management system (OMS), including group and engineering technical practices as applicable, to address these risks. See page 41 for more information on safety and our OMS. Activities include inspection, maintenance, testing, business continuity and crisis response planning, and competency development for our employees and contractors. In addition, we conduct our drilling activity through a global wells organization in order to promote a consistent approach for designing, constructing and managing wells.

Security

Hostile acts such as terrorism or piracy could harm our people and disrupt our operations. We monitor for emerging threats and vulnerabilities to manage our physical and digital security. Physical security threats tend to vary geographically and by type of business. Our central security team provides guidance and support to a network of regional security advisers who advise and conduct assurance with respect to the management of security risks affecting our people and operations. We also maintain disaster recovery, crisis and business continuity management plans.

 

 

50    BP Annual Report and Form 20-F 2013


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Risk factors

We urge you to consider carefully the risks described below. The potential impact of the occurrence, or recurrence, 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, including the 10-point plan.

The risks are categorized against the following areas: strategic and commercial; compliance and control; and safety and operational. In addition, we have set out one separate risk for your attention – the risk resulting from the 2010 Gulf of Mexico oil spill.

 

Gulf of Mexico oil spill

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

There is significant uncertainty regarding the extent and timing of the remaining costs and liabilities relating to the 2010 Gulf of Mexico oil spill (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, fines and penalties that become payable by BP (including as a result of 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. These uncertainties are likely to continue for a significant period and may cause our costs to increase materially. 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. See, in particular, Access and renewal; Liquidity, financial capacity and financial, including credit, exposure; Insurance; US government settlements and debarment; Regulatory; Liabilities and provisions; Reporting; and Process safety, personal safety and environmental risks 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 and the effects of the Incident on our reputation and cash flows 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 affected 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, costs and liabilities relating to the Incident have placed, and will continue to place, a significant burden on our cash flow, which could impede our ability to invest in new opportunities and deliver long-term growth.

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 exchange rate fluctuations and 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), increased supply from the development of new oil and gas sources, technological change, global economic conditions and the influence 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. Decreases in oil, gas or product prices are likely to have an adverse effect on revenues, margins and profitability, and a material rapid change, or a sustained change, in oil, gas or product prices may mean investment or other decisions need to be reviewed, assets may be impaired, and the viability of projects may be affected. 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.

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.

Periods of global recession or prolonged instability in financial markets could negatively impact parties with whom we do or may do business, the demand for our products and the prices at which they can be sold and could affect the viability of the markets in which we operate.

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, potential restrictions on the commercial viability of, or our ability to progress, upstream resources and reserves, and impacts on revenue generation and strategic growth opportunities. In addition, the changed nature of our participation in alternative energies could carry reputational, economic and technology risks.

Geopolitical – 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 and regions 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 terrorism, 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. See page 4 for information on the locations of our major areas of operation and activities.

We set ourselves high standards of corporate citizenship and aspire to contribute to a better quality of life through the products and services we provide. If it is perceived that we are not respecting or advancing the economic and social progress of the communities in which we operate or that we have not satisfactorily addressed all relevant stakeholder concerns

 

 

BP Annual Report and Form 20-F 2013       51   


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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 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 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 arrangements or associates and through contracting and sub-contracting arrangements. These arrangements often involve complex risk allocation, decision-making processes and indemnification arrangements, and BP has less control of such activities than we would have if BP had full ownership and 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 arrangement’s or associate’s best interests, or approve such matters without our consent. Additionally, our joint arrangement 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, then safety, the performance of the project and BP’s costs may be adversely affected. Our joint arrangement 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 arrangement 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 or contractual arrangement. Should a key sub-contractor, such as a lessor of drilling rigs, no longer be 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 investment – any future erosion of our relationship with Rosneft could adversely impact our business, strategic objectives, the level of our reserves and our reputation.

On 21 March 2013, we completed the sale of our 50% interest in TNK-BP to Rosneft and the purchase of additional shares in Rosneft. We now own a total shareholding in Rosneft of 19.75%. To the extent we fail to maintain a good commercial relationship with Rosneft in the future, or to the extent that as a non-controlling shareholder in Rosneft we are unable in the future to exercise significant 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 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 group strategy, investment selection and/or subsequent execution could lead to loss of opportunity, 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, regulatory or other reasons, 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 major projects over the plan period. Poor delivery of or operational challenges at 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 and our operating cash flows.

Digital infrastructure – a breach of our digital security or a failure of our digital infrastructure 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 or failure of our digital infrastructure, due to intentional actions such as cyber-attacks, negligence or otherwise, could cause serious damage to business operations and, in some circumstances, could result in the loss of data or sensitive information, injury to people, loss of control of or damage to assets, harm to the environment, reputational damage, breaches of regulations, litigation, legal liabilities and reparation costs.

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

Crisis management and contingency plans are required to respond to, and to continue or recover operations following, a disruption or an incident. 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. 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.

 

 

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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 and retain 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.

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.

The group seeks to maintain a financial framework to ensure that it is able to maintain an appropriate level of liquidity and financial capacity, and commercial credit risk is measured and controlled to determine the group’s total credit risk. Failure to accurately forecast, manage or maintain sufficient liquidity and credit to meet our needs (including a failure to understand and respond to potential liabilities) could impact our ability to operate and result in a financial loss. Trade and other receivables, including overdue receivables, may not be recovered whether an impairment provision has been recognized or not. Inability to determine adequately our credit exposure could lead to financial loss. Furthermore, a substantial and unexpected cash call or funding request could disrupt our financial framework or overwhelm our capacity to meet our obligations.

External events could materially impact the effectiveness of the group’s financial framework. A credit crisis or significant economic shock 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.

In addition, a significant operational incident could result in decreases in our credit ratings which, together with the assessments published by analysts, the reputational consequences of any such incident and concerns about the group’s costs arising from any such incident, ongoing contingencies, liquidity, financial performance and credit spreads, could increase the group’s financing costs and limit the group’s access to financing. The group’s ability to engage in both its trading activities and non-trading businesses could also be impacted in such circumstances due to counterparty concerns about the group’s financial and business risk profile and resulting collateral demands, which could be significant. 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. Any 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. If such constraints occur at a time when cash flows from our business operations are constrained, such as following a significant operational incident, 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 Incident.

See Financial statements – Note 19 for more information on financial instruments and financial risk factors.

Insurance – The limited capacity of the insurance market and BP’s insurance strategy could, from time to time, expose the group 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 may 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 Incident.

 

Compliance and control risks

US government settlements and debarment – our settlement with the US Department of Justice and the SEC in respect of certain charges related to the Incident 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. For a description of the terms of the DoJ and SEC settlements, see Legal proceedings on page 264. Under the DoJ settlement, BP has agreed to retain an independent third-party auditor who will review and report to the probation officer, the DoJ, and BP regarding BP Exploration & Production’s (BPXP) compliance with the key terms of the settlement including the completion of safety and environmental management systems audits, operational oversight enhancements, oil spill response training and drills and the implementation of best practices. The DoJ settlement also provides for the appointment of an ethics monitor and a process safety monitor. See Gulf of Mexico oil spill on page 39. 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.

The US Environmental Protection Agency (EPA) has temporarily suspended a number of BP entities from participating in new federal contracts and subjected BPXP to mandatory debarment at its Houston headquarters. In addition, the EPA has initiated administrative proceedings to convert the temporary suspension of these BP entities into discretionary debarment. On 26 November 2013, the EPA issued a Notice of Continued Suspensions and Proposed Debarments that continued the suspensions of the previously suspended BP entities, suspended two new BP entities (BP Alternative Energy and BP Pipelines (Alaska) Inc.), and proposed discretionary debarment of all suspended BP entities. Both temporary suspension and mandatory debarment prevent a company from entering into new contracts or new leases with the US government that would be performed at the facility where a Clean Water Act violation occurred. See Legal proceedings on page 264. BP has a significant amount of operations in the US. See Upstream on page 25 and Oil and gas disclosures for the group on page 245. Prolonged suspension or debarment from entering new federal contracts, or further suspension or debarment proceedings in the future 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 in the future. In particular, prolonged suspension or debarment could prevent BP from accessing and developing material new oil and gas resources located in the US, or prevent BP from engaging in certain development arrangements with third parties that are standard in the oil and gas industry, which could make the development of certain of BP’s existing reserves located in the US less commercially attractive than if relevant BP entities were not suspended or debarred.

 

 

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As a result of the SEC settlement, as of 5 February 2013 and for a period of three years thereafter, we are no longer 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 SEC settlement date of 10 December 2012 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. We also 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, affect the adequacy of our provisions and limit our access to new exploration properties.

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. 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. We remain exposed to changes in the regulatory and legislative 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, the imposition of trade or other sanctions, government actions to cancel or renegotiate contracts or other factors. 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 and we remain exposed to increases in amounts payable to governments or government agencies. 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 curtail or cease certain operations, or affect the adequacy of our provisions for pensions, tax, environmental and legal liabilities. Potential changes to pension or financial market regulation could also impact funding requirements of the group.

Due to the Incident and remedial provisions contained in or that may result from the DoJ and SEC settlements and other past events in the US, it is likely that there will be additional oversight and 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. BP may be subjected to a higher number of citations and/or level of fines imposed in relation to any alleged breaches of safety or environmental regulations. 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, require changes to our drilling operations, exploration, development and decommissioning plans, 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.

We buy, sell and trade oil and gas products in certain regulated commodity markets. Failure to respond to changes in or to comply with trading regulations could result in regulatory action and damage to our reputation.

See page 254 for more information on environmental regulation.

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

Incidents of ethical misconduct, non-compliance with the recommendations of the ethics monitor appointed under the terms of the DoJ settlement or non-compliance with applicable laws and regulations, including anti-bribery, anti-corruption and anti-manipulation laws and trade or other sanctions, could be damaging to our reputation and shareholder value and could subject us to litigation and regulatory action or penalties under the terms of the DoJ settlement or otherwise. Multiple events of non-compliance could call into question the integrity of our operations. For example, in our trading functions, 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 page 257. For further information on the risks involved in BP’s trading activities, see Treasury and trading activities below.

Liabilities and provisions – BP’s potential liabilities resulting from pending and future claims, lawsuits, settlements and enforcement actions relating to the Incident, together with the potential cost and burdens of implementing remedies sought in the various proceedings, 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 Incident 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. BP and certain of its subsidiaries have also been named as defendants in numerous lawsuits in the US arising out of the Incident, including actions for personal injury and wrongful death, purported class actions for commercial or economic injury, actions for breach of contract, violations of statutes, property and other environmental damage, securities law claims and various other claims, and additional lawsuits or private claims arising out of the Incident may be brought in the future.

While significant charges have been recognized in the income statement since the Incident occurred in 2010, the provisions recognized represent only the current best estimates of expenditures required to settle certain present obligations that can be reasonably estimated at the end of the reporting period, and there are future expenditures for which it is not possible to measure our obligations reliably. BP’s total potential liabilities resulting from pending and future claims, lawsuits, settlements and enforcement actions relating to the Incident (including as a result of any potential determination of BP’s negligence or gross negligence), together with the potential cost and burdens of implementing remedies sought in the various proceedings, cannot be fully estimated at this time and are subject to significant uncertainty but they have had, and are expected to continue to have, a material adverse impact on the group’s business.

See Financial statements – Note 2 and Legal proceedings on page 257.

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.

 

 

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

In the normal course of business, we are subject to operational risk around our treasury and trading activities. Control of these activities is highly dependent on our ability to process, manage and monitor a large number of complex transactions across many markets and currencies. Shortcomings or failures in our systems, risk management methodology, internal control processes or people could lead to disruption of our business, financial loss, regulatory intervention or damage to our reputation. See Legal proceedings on page 257.

 

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 arrangement partners and associates. See Strategic and commercial risks – Joint and other contractual arrangements above.

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 hazardous, remote 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) addresses health, safety, security, environmental and operations risks, and aims 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.

Under the terms of the DoJ settlement (see Legal proceedings on page 264), a process safety monitor will review, evaluate, and provide recommendations concerning BPXP’s process safety and risk management procedures for deepwater drilling in the Gulf of Mexico. Incidents of non-compliance with the recommendations of the process safety monitor 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.

Security – hostile acts 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 facilities, 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.

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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Liquidity and capital resources

Since the Gulf of Mexico oil spill in 2010 and the significant costs relating to the response activities and the uncertainty regarding the ultimate magnitude of its liabilities and timing of cash outflows, the group’s situation has continued to stabilize. This has been reflected in the group’s liquidity and capital resources position, which has continued to strengthen underpinned by a prudent financial framework.

The group’s long-term credit ratings are A (positive outlook) from Standard & Poor’s, and A2 (stable outlook) from Moody’s Investor Services, both remaining unchanged during 2013.

We increased our financial flexibility in 2013 with the completion of the sale of BP’s 50% share in TNK-BP to Rosneft in return for cash and shares. We received net $11.8 billion cash on completion (in addition to $0.7 billion already received as a dividend in December 2012), as well as increasing our shareholding in Rosneft from 1.25% to 19.75%.

Financial framework

We continue to refine our financial framework to support the pursuit of value growth for shareholders, while maintaining a secure financial base. BP intends to increase operating cash flowa by around 50% in 2014 compared with 2011b, and thereafter maintain focus on growing sustainable free cash flowc. We expect that the improvement in operating cash flow will be delivered partly from the completion of the Deepwater Horizon Oil Spill Trust fund payments, and partly through high-margin projects coming onstream. Any growth in operating cash flow will be available to increase both organic capital expenditure and shareholder distributions.

The financial framework remains prudent and we expect to operate within a gearingd range of 10-20%, and to be robust to cash break-even levels in an oil price environment between $80 and $100 per barrel. We expect to continue to maintain a significant liquidity buffer while uncertainties remain.

Dividends and other distributions to shareholders

We are committed to maintaining a progressive and sustainable dividend policy through our focus on increasing sustainable free cash flows.

Since resuming dividend payments in 2011, we have steadily increased the dividend. From the quarterly dividend of 7 cents per share paid in 2011 it has increased by 36% to 9.5 cents per share paid in the fourth quarter of 2013. Going forward, the board will review the dividend level with the first and third quarter results each year.

The total dividend paid in cash to BP shareholders in 2013 was $5.4 billion with shareholders also having the option to receive a scrip dividend (2012 $5.3 billion cash). The dividend is determined in US dollars, the economic currency of BP.

During 2013 we started to buy back shares as part of an $8-billion share repurchase programme, fulfilling a commitment to offset any dilution to earnings per share from the Rosneft transaction. The total cash paid for share buybacks in 2013 was $5.5 billion (2012 nil). Details of share repurchases to satisfy the requirements of certain employee share-based payment plans are set out on page 278.

 

a  Operating cash flow is net cash provided by operating activities, as presented in the group cash flow statement on page 125.
b  Assuming an oil price of $100 per barrel and a Henry Hub gas price of $5/mmBtu in 2014. The projection assumes BP’s estimate of a Rosneft dividend. 2011 excludes BP’s share of TNK-BP dividends. 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 2 for further information.
c  Free cash flow is operating cash flow less net cash used in investing activities, as presented in the group cash flow statement on page 125.
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 28 for information on gross debt, which is the nearest equivalent measure to net debt on an IFRS basis.

Financing the group’s activities

The group’s principal commodity, oil, is priced internationally in US dollars. Group policy has generally been to minimize economic exposure to currency movements by financing operations with US dollar debt. Where debt is issued in other currencies, including euros, it is generally swapped back to US dollars using derivative contracts, or else hedged by maintaining offsetting cash positions in the same currency. The cash balances of the group are mainly held in US dollars or swapped to US dollars and holdings are well-diversified to reduce concentration risk. The group is not therefore exposed to significant currency risk regarding its borrowings. Also see Risk factors on page 51 for further information on risks associated with prices and markets and Financial statements – Note 19.

The group’s finance debt at 31 December 2013 amounted to $48.2 billion (2012 $48.8 billion). Of the total finance debt, $7.4 billion is classified as short term at the end of 2013 (2012 $10.0 billion). The short-term balance includes $6.2 billion for amounts repayable within the next 12 months relating to long-term borrowings (2012 $6.2 billion). Commercial paper markets in the US and Europe are a further source of short-term liquidity for the group to provide timing flexibility. At 31 December 2013, outstanding commercial paper amounted to $1.0 billion (2012 $3.0 billion). We have a European Debt Issuance Programme (DIP) in place under which the group may raise up to $30 billion of debt for maturities of one month or longer. At 31 December 2013, the amount drawn down against the DIP was $13.9 billion (2012 $14.0 billion). Since 5 February 2013 the group has had a US shelf registration statement with a limit of $30 billion. This was converted from an unlimited shelf registration following the approval in December 2012 of the SEC settlement in respect of Deepwater Horizon-related claims. At 31 December 2013 $6.9 billion had been drawn down since conversion. In addition, the group has an Australian Note Issuance Programme of $5 billion Australian dollars, and as at 31 December 2013 the amount drawn down was $0.8 billion Australian dollars (2012 A$0.5 billion).

None of the capital market bond issuances since the Gulf of Mexico oil spill contain any additional financial covenants compared with the group’s capital markets issuances prior to the incident.

BP accessed international capital markets throughout the year using its US, European and Australian issuance programmes, with bond issuances amounting to $8.6 billion in 2013.

The maturity profile and fixed/floating rate characteristics of the group’s debt are described in Financial statements – Note 19.

Net debt was $25.2 billion at the end of 2013, a reduction of $2.3 billion from the 2012 year-end position of $27.5 billion. The ratio of net debt to net debt plus equity was 16.2% at the end of 2013 (2012 18.7%). Net debt and the ratio of net debt to net debt plus equity are non-GAAP measures. We believe that these measures provide useful information to investors. Net debt enables investors to see the economic effect of gross debt, related hedges and cash and cash equivalents in total. The net debt ratio enables investors to see how significant net debt is relative to equity from shareholders. See Financial statements – Note 28 for gross debt, which is the nearest equivalent measure on an IFRS basis, and for further information on net debt.

Cash and cash equivalents of $22.5 billion at 31 December 2013 (2012 $19.6 billion) are included in net debt. We manage our cash position to ensure the group has adequate cover to respond to potential short-term market illiquidity, and expect to maintain a strong cash position. Cash balances are pooled centrally where permissible, and deployed globally as required. Cash surpluses are deposited with creditworthy banks or invested in high grade commercial paper and money market funds with short maturities to ensure availability. The group holds $2 billion of cash outside the UK and it is not expected that any significant tax will arise on repatriation. Further information on the management of liquidity risk and credit risk is provided in Financial statements – Note 19, and on the cash position in Financial statements – Note 23.

 

 

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The group also has access to significant sources of liquidity in the form of committed bank facilities. We renegotiated our committed bank facilities during 2013, putting in place borrowing facilities of $7.4 billion (2012 $6.8 billion) with 26 international banking counterparties, of which $7.0 billion is available to draw and repay over a term of five years and $0.4 billion is available to draw and repay over a term of three years. In addition, the group continued to strengthen its access to commercial bank letters of credit (LC) and at the end of 2013 had in place committed LC facilities of $7.5 billion and secured LC arrangements of $2.4 billion, to supplement its uncommitted and unsecured LC lines.

We believe that the group has sufficient working capital for foreseeable requirements, taking into account the amounts of undrawn borrowing facilities and increased levels of cash and cash equivalents, and the ongoing ability to generate cash.

Uncertainty remains regarding the amount and timing of future expenditures relating to the Gulf of Mexico oil spill and the implications for future activities. See Risk factors on page 51 and Financial statements – Note 2 for further information.

Off-balance sheet arrangements

At 31 December 2013, the group’s share of third-party finance debt of equity-accounted entities was $17,008 million (2012 $6,884 million). These amounts are not reflected in the group’s debt on the balance sheet. The group has issued third-party guarantees under which amounts outstanding at 31 December 2013 were $199 million (2012 $237 million) in respect of liabilities of joint ventures and associates and $648 million (2012 $713 million) in respect of liabilities of other third parties. Of these amounts, $115 million (2012 $166 million) of the joint ventures and associates guarantees relate to borrowings and for other third-party guarantees, $487 million (2012 $543 million) relates to guarantees of borrowings. Details of operating lease commitments, which are not recognized on the balance sheet, are shown in the table on page 252 and provided in Financial statements – Note 9.

Contractual obligations

The following table summarizes the group’s contractual obligations, capital expenditure commitments for property, plant and equipment at 31 December 2013 and the proportion of that expenditure for which contracts have been placed.

 

                         $ million   
        Capital expenditure   
Expected payments by period     

 

Contractual

obligationsa

  

  

     Committed        

 

of which is

contracted

  

  

2014

     134,075         17,973         8,676   

2015

     40,471         9,010         2,581   

2016

     29,279         5,703         1,321   

2017

     23,186         4,021         685   

2018

     20,360         2,292         189   

2019 and thereafter

     105,377         3,443         253   

Total

     352,748         42,442         13,705   

 

a  Including $100,805 million for which a liability is recognized on the balance sheet.

The group’s principal contractual obligations and a description of the nature of the group’s unconditional purchase obligations are provided on page 252.

Capital expenditure is considered to be committed when the project has received the appropriate level of internal management approval. For joint operations, the net BP share is included in the amounts above.

In addition, at 31 December 2013, the group had committed to capital expenditure relating to investments in equity-accounted entities amounting to $1,458 million. Contracts were in place for $161 million of this total.

Cash flow

The following table summarizes the group’s cash flows.

 

                       $ million   
       2013        2012        2011   

Net cash provided by operating activities

     21,100        20,479        22,218   

Net cash used in investing activities

     (7,855     (13,075     (26,753

Net cash provided by (used in) financing activities

     (10,400     (2,010     477   

Currency translation differences relating to cash and cash equivalents

     40        64        (493

Increase (decrease) in cash and cash equivalents

     2,885        5,458        (4,551

Cash and cash equivalents at beginning of year

     19,635        14,177        18,728   

Cash and cash equivalents at end of year

     22,520        19,635        14,177   

Net cash provided by operating activities for the year ended 31 December 2013 was $21,100 million compared with $20,479 million for 2012. The cash outflow in respect of the Gulf of Mexico oil spill reduced from $2,382 million in 2012 to $73 million in 2013. Excluding the impacts of the Gulf of Mexico oil spill, net cash provided by operating activities was $21,173 million for 2013, compared with $22,861 million for 2012, a decrease of $1,688 million. Profit before taxation excluding the impact of the Gulf of Mexico oil spill increased by $7,545 million, of which $9,163 million related to the non-cash impacts of higher depreciation, impairments and gains and losses on disposal offset by lower earnings from joint ventures and associates. An increase in working capital requirements of $3,920 million was largely offset by lower income taxes paid.

Net cash provided by operating activities for the year ended 31 December 2012 was $20,479 million compared with $22,218 million for 2011. The cash outflow in respect of the Gulf of Mexico oil spill reduced from $6,813 million in 2011 to $2,382 million in 2012. Excluding the impacts of the Gulf of Mexico oil spill, net cash provided by operating activities was $22,861 million for 2012, compared with $29,031 million for 2011, a decrease of $6,170 million. Profit before taxation excluding the impacts of the Gulf of Mexico oil spill decreased by $11,341 million, of which $4,730 million related to the non-cash impacts of higher depreciation, impairments and gains and losses on disposal and lower equity-accounted earnings of joint ventures and associates. A reduction in working capital requirements of $3,667 million was largely offset by lower dividends received from joint ventures and associates, principally TNK-BP.

Net cash used in investing activities was $7,855 million in 2013 (2012 $13,075 million and 2011 $26,753 million). The decrease in cash used in 2013 reflected an increase in disposal proceeds of $10,401 million, partly offset by an increase in our investments in equity-accounted entities, mainly relating to the completion of the sale of our interest in TNK-BP and subsequent investment in Rosneft. There was also an increase in our other capital expenditure excluding acquisitions of $1,298 million. The decrease in cash used in 2012 reflected an absence of significant expenditure on business combinations compared with 2011 when we spent $10,909 million, mainly for the Reliance and Devon acquisitions, as well as an increase in disposal proceeds of $8,757 million. This was partially offset by an increase in capital expenditure excluding acquisitions of $5,914 million.

The group has had significant levels of capital investment for many years. Cash flow in respect of capital investment, excluding acquisitions, was $30 billion in 2013 (2012 $24.8 billion and 2011 $18.9 billion). Sources of funding are fungible, but the majority of the group’s funding requirements for new investment come from cash generated by existing operations.

 

 

BP Annual Report and Form 20-F 2013       57   


Table of Contents

Net cash used in financing activities was $10,400 million in 2013 (2012 $2,010 million and 2011 $477 million net cash provided by financing activities). The increase in net cash used in 2013 primarily reflected the buyback of shares of $5.5 billion as part of our $8-billion share repurchase programme, lower net proceeds of $1,055 million from long-term financing and an increase in the net repayment of short-term debt of $1,353 million. The increase in net cash used in 2012 primarily reflected a net decrease in short-term debt of $2,888 million and an increase in dividends paid of $1,222 million, partly offset by an increase in net proceeds from long-term financing of $1,412 million.

During the period 2011 to 2013, our total sources of cash amounted to $101 billion, and our total uses of cash amounted to $106 billion. The increase in cash and cash equivalents held of $4 billion was financed by an increase in finance debt of $9 billion over the three-year period. During this period, the price of Brent crude oil has averaged $110.53 per barrel. Sources and uses of cash over the three-year period as a whole, are analysed in the table below.

 

       $ billion   

Sources of cash:

  

Net cash provided by operating activities

     64   

Disposals

     37   
       101   

Uses of cash:

  

Capital expenditure

     74   

Acquisitions

     11   

Net repurchase of shares

     5   

Dividends paid to BP shareholders

     15   

Dividends paid to non-controlling interests

     1   
       106   

Net use of cash

     (5

Increase in finance debt

     9   

Increase in cash and cash equivalents

     4   

Disposal proceeds received in cash during the three-year period exceeded cash used for acquisitions, as a result in particular of our ongoing disposal programme started in 2010 and the disposal of our interest in TNK-BP in 2013. Net investment (capital expenditure and acquisitions less disposal proceeds) during this period averaged $16 billion per year. Dividends paid to BP shareholders totalled $15 billion during the three-year period. In the past three years, $4 billion has been contributed to funded pension plans. This is reflected in net cash provided by operating activities in the table above.

Acquisitions and disposals

There were no significant acquisitions in 2013 and 2012.

In 2011, we acquired a 30% interest in each of 21 oil and gas production-sharing agreements operated by Reliance Industries Limited in India for $7.0 billion. We also 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.

During 2013 BP completed sale and purchase agreements for the sale of BP’s 50% interest in TNK-BP to Rosneft, and for BP’s further investment in Rosneft. For more information on this transaction see Financial statements – Note 6.

Total cash disposal proceeds received during 2013 were $22 billion. This included $16.7 billion for the disposal of BP’s interest in TNK-BP, $1.4 billion for the disposal of our Texas City refinery and a portion of its retail and logistics network in the south-eastern US to Marathon Petroleum Corporation and $2.2 billion for the sale of the Carson refinery in California, and related assets in the region to Tesoro Corporation. We also completed the sale of our interests in a number of central North Sea oil and gas fields to TAQA.

Total disposal proceeds received during 2012 were $11.6 billion. This 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, $1.5 billion for the sale of the Canadian natural gas liquids (NGL) business to Plains Midstream Canada ULC and $1.025 billion for the sale of BP’s interest in the Jonah and Pinedale upstream operations in Wyoming, to LINN Energy, LLC.

Total disposal proceeds received during 2011, after the repayment of the disposal deposit relating to Pan American Energy LLC (PAE), were $2.8 billion.

See Financial statements – Note 3 and Note 4 for further details of business combinations and non-current assets held for sale.

 

 

 

The Strategic report was approved by the board and signed on its behalf by David J Jackson, Company Secretary on 6 March 2014.

 

 

58    BP Annual Report and Form 20-F 2013


Table of Contents

 

 

 

Corporate

governance 

    60   

Board of directors

 

   
     

 

66

  

 

Executive team

 

   
     

 

69

  

 

Governance overview

 

   
     

 

71

  

 

How the board works

   
        

 

71

  

 

Board governance in BP

   
         71    Role of the board    
         71    Board composition    
         71    Key roles and responsibilities    
         71    Appointment and time commitment    
         71    Independence and conflicts of interest    
         71    Succession    
         72    Board activity    
         72    Risk and assurance    
         72   

International advisory board

 

   
     

 

72

  

 

Board effectiveness

   
            

 

72

  

 

Induction and board learning

   
             73   

Board evaluation

 

   
         

 

73

  

 

Shareholder engagement

   
            

 

73

  

 

Institutional investors

   
             73    Private investors    
             73    AGM    
             73   

UK Corporate Governance Code compliance

 

   
         

 

74

  

 

Committee reports

   
            

 

74

  

 

Audit committee

   
             77    Safety, ethics and environment assurance committee    
             78    Gulf of Mexico committee    
             79    Nomination committee    
             80   

Chairman’s committee

 

   
         

 

81

  

 

Directors’ remuneration report

   
            

 

82

  

 

Chairman’s annual statement

   
             84    2013 annual report on remuneration    
             96   

Directors’ remuneration policy

 

   
         

 

109

  

 

Regulatory information

   
            

 

110

  

 

Internal Control Revised Guidance for Directors (Turnbull)

   
             110    Corporate governance practices    
             111    Code of ethics    
             111    Controls and procedures    
             111    Principal accountants’ fees and services    
             112    Memorandum and Articles of Association    
                   
                   
                   
    BP Annual Report and Form 20-F 2013            59    

 


Table of Contents

Board of directorsa

As at 6 March 2014

 

LOGO
Key to portraits      
  1    Carl-Henric Svanberg     2    Bob Dudley     3    Paul Anderson     4    Admiral Frank Bowman
  5    Antony Burgmans     6    Cynthia Carroll     7     Iain Conn     8    George David
  9    Ian Davis   10    Professor Dame Ann Dowling   11    Dr Brian Gilvary   12    Brendan Nelson
13    Phuthuma Nhleko   14    Andrew Shilston    

 

a  The ages of the board are correct as at 31 December 2013.

 

60    BP Annual Report and Form 20-F 2013


Table of Contents

Carl-Henric Svanberg

 

Chairman

Tenure

Appointed to the board 1 September 2009 (4 years)

Board and committee activities

Chairman

Chairman of the chairman’s committee

Chairman of the nomination committee

Attends the safety, ethics and environment assurance committee (SEEAC)

Attends the Gulf of Mexico committee

Attends the remuneration committee

Outside interests

Chairman of AB Volvo

Age

61

Nationality

Swedish

 

Career

Carl-Henric Svanberg became chairman of the BP board on 1 January 2010.

He spent his early career at Asea Brown Boveri and the Securitas Group, before moving to the Assa Abloy Group as president and chief executive officer.

From 2003 until 31 December 2009, when he left to join BP, he was president and chief executive officer of Ericsson, also serving as the chairman of Sony Ericsson Mobile Communications AB. He was a non-executive director of Ericsson between 2009 and 2012.

He was appointed chairman and a member of the board of AB Volvo on 4 April 2012.

He is a member of the External Advisory Board of the Earth Institute at Columbia University, a member of the Advisory Board of Harvard Kennedy School and on the Leadership Council of the United Nations Sustainable Development Solutions Network. He is also the recipient of the King of Sweden’s medal for his contribution to Swedish industry.

Relevant experience and skills

Carl-Henric Svanberg’s career in global business, latterly as chief executive officer of Ericsson, is particularly relevant to BP as has been demonstrated during his tenure as chairman. In leading the board, he has focused on the development of the group’s strategy and its communication to shareholders. He has also concentrated on the work of the nomination committee in endeavouring to ensure that the board has a strong list of candidates to secure its stewardship of the company.

Carl-Henric Svanberg’s performance during the year has been evaluated by the chairman’s committee, led by Antony Burgmans.

Bob Dudley

 

Group chief executive

Tenure

Appointed to the board 6 April 2009 (4 years)

Outside interests

Non-executive director of Rosneft

Member of Tsinghua Management University Advisory Board, Beijing, China

Member of BritishAmerican Business International Advisory Board

Member of UAE/UK CEO Forum

Member of Turkish/British CEO Forum

Member of Russian Geographical Society

Age

58

Nationality

American

 

Career

Bob Dudley became group chief executive on 1 October 2010.

Bob joined Amoco Corporation in 1979, working in a variety of engineering and commercial posts. Between 1994 and 1997, he worked on corporate development in Russia.

In 1997, he became general manager for strategy for Amoco and in 1999, following the merger between BP and Amoco, was appointed to a similar role in BP.

Between 1999 and 2000, he was executive assistant to the group chief executive, subsequently becoming group vice president for BP’s renewables and alternative energy activities. In 2002, he became group vice president responsible for BP’s upstream businesses in Russia, the Caspian region, Angola, Algeria and Egypt.

From 2003 to 2008, he was president and chief executive officer of TNK-BP in Moscow. On his return to BP in 2009 he was appointed to the BP board and oversaw the group’s activities in the Americas and Asia. Between 23 June and 30 September 2010, he served as the president and chief executive officer of BP’s Gulf Coast Restoration Organization in the US. He was appointed a director of Rosneft in March 2013 following BP’s acquisition of a stake in Rosneft.

Relevant experience and skills

Bob Dudley has spent his entire career in the oil and gas industry. His broad range of roles with Amoco and BP has given him substantial global experience.

Since his appointment as group chief executive in 2010, Bob has re-organized the operations of the group and has moved its focus to value not volume; all without any compromise on safety. During the year he has successfully completed the disposal of the group’s interest in TNK-BP and the acquisition of a significant stake in Rosneft.

Bob Dudley’s performance has been considered and evaluated by the chairman’s committee.

 

 

BP Annual Report and Form 20-F 2013       61   


Table of Contents

Paul Anderson

 

Independent non-executive director

Tenure

Appointed 1 February 2010 (4 years)

Board and committee activities

Chairman of the SEEAC

Member of the chairman’s committee

Member of the nomination committee

Member of the Gulf of Mexico committee

Outside interests

Non-executive director of BAE Systems PLC.

Age

68

Nationality

American

 

Career

Paul Anderson was formerly chief executive at BHP Billiton and Duke Energy, where he also served as chairman of the board. Having previously been chief executive officer and managing director of BHP Limited and then BHP Billiton Limited and BHP Billiton Plc, he rejoined these latter two boards in 2006 as a non-executive director, retiring on 31 January 2010. He also served as a non-executive director on a number of boards in the US and Australia and as chief executive officer of Pan Energy Corp.

Relevant experience and skills

Paul Anderson became a board member in early 2010, joining the SEEAC. He was a member of the Gulf of Mexico committee from its formation in August 2010. He took the chair of the SEEAC in December 2012. As chair he has continued the committee’s focus on safety matters. His broad experience of the global oil and gas industry and of the US business environment has benefited the board, the SEEAC and the Gulf of Mexico committee. He has actively supported the work of the BP Massachusetts Institute of Technology (MIT) academy.

He has led the SEEAC on several visits to the company’s operations and has commenced a dialogue with the company’s socially responsible investors.

Admiral Frank Bowman

 

Independent non-executive director

Tenure

Appointed 8 November 2010 (3 years)

Board and committee activities

Member of the SEEAC

Member of the chairman’s committee

Member of the Gulf of Mexico committee

Outside interests

President of Strategic Decisions, LLC.

Director of Morgan Stanley Mutual Funds

Director of the American Shipbuilding Suppliers Association

Director of Naval and Nuclear Technologies, LLP.

Age

69

Nationality

American

 

Career

Frank Bowman joined the United States Navy in 1966. During his naval service, he commanded the nuclear submarine USS City of Corpus Christi and the USS Holland. He served as a flag officer: as the Navy’s chief of personnel; on the joint staff as director of Political-Military Affairs; and as a director of the naval nuclear propulsion programme in the Department of the Navy and the Department of Energy for over eight years. He also completed two masters degrees in engineering at the Massachusetts Institute of Technology in 1973.

After his retirement as an Admiral in 2004, he was president and chief executive officer of the Nuclear Energy Institute until 2008. He served on the BP Independent Safety Review Panel and was a member of the BP America external advisory council. He was appointed Honorary Knight Commander of the British Empire in 2005 by Queen Elizabeth II. He was elected to the US National Academy of Engineering in 2009.

Relevant experience and skills

Frank Bowman has a deep knowledge of engineering coupled with exceptional experience in process safety arising from his time with the US Navy and, later, the Nuclear Energy Institute. His service on the BP Independent Safety Review Panel gave him direct experience of BP’s safety aims and requirements, which has been important for his work on the SEEAC. He has made a significant contribution to the work of the Gulf of Mexico committee.

Antony Burgmans

 

Independent non-executive director

Tenure

Appointed 5 February 2004 (10 years)

Board and committee activities

Chairman of the remuneration committee

Member of the SEEAC

Member of the chairman’s committee

Member of nomination committee

Outside interests

Member of the supervisory boards of Akzo Nobel N.V., AEGON N.V. and SHV Holdings N.V.

Chairman of the supervisory board of TNT Express

Age

66

Nationality

Dutch

 

Career

Antony Burgmans joined Unilever in 1972, holding a succession of marketing and sales posts, including the chairmanship of PT Unilever Indonesia from 1988 until 1991.

In 1991, he was appointed to the board of Unilever, becoming business group president, ice cream and frozen foods, Europe in 1994, and chairman of Unilever’s Europe committee, co-ordinating its European activities. In 1998, he became vice chairman of Unilever NV and in 1999, chairman of Unilever NV and vice chairman of Unilever PLC. In 2005, he became non-executive chairman of Unilever NV and Unilever PLC until his retirement in 2007. During his career he has lived and worked in London, Hamburg, Jakarta, Stockholm and Rotterdam.

Antony Burgmans has been nominated chairman of Akzo Nobel’s supervisory board from April 2014.

Relevant experience and skills

Antony Burgmans’ executive career has been in the fields of international production, distribution and marketing. Over the years he has made a significant contribution to the work of the board, adding insight to the areas of reputation, brand and culture. His global perspective has particular value as chairman of the remuneration committee and also to his work on the SEEAC, on whose behalf he has made several visits to operations of the group.

He led the remuneration committee in its task of preparing a formal remuneration policy for adoption by shareholders. In this role he has had extensive dialogue with shareholders. He continues to provide wise counsel to the board and leads the evaluation of the chairman.

 

 

62    BP Annual Report and Form 20-F 2013


Table of Contents

Cynthia Carroll

 

Independent non-executive director

Tenure

Appointed 6 June 2007 (6 years)

Board and committee activities

Member of the SEEAC

Member of the chairman’s committee

Member of nomination committee

Outside interests

Non-executive director of Hitachi Ltd.

Age

57

Nationality

American

 

Career

Early in her career in 1989, Cynthia Carroll joined Alcan (Aluminum Company of Canada) and ran a packaging company, led a global bauxite, alumina and speciality chemicals business and later was president and chief executive officer of the Primary Metal Group, responsible for operations in more than 20 countries. In 2007 she became the chief executive of Anglo American plc, the global mining group, operating in 45 countries with 150,000 employees, and was chairman of Anglo Platinum Limited and of De Beers s.a. She stepped down from these roles in April 2013.

Relevant experience and skills

Cynthia Carroll’s leadership of global businesses, particularly in the extractive industry sector has enabled her to make a strong contribution to the work of the BP board and the SEEAC. She has been a leader in working to enhance safety performance in the mining industry, and her geo-political experience has been valuable during the course of the year, as has her work on the nomination committee.

She recently visited BP’s operations in Alaska on behalf of the SEEAC.

Iain Conn

 

Chief executive, Downstream

Tenure

Appointed to the board 1 July 2004 (9 years)

Group responsibilities

Manufacturing, logistics, marketing operations of BP’s fuels, petrochemicals and lubricants businesses

Group regional responsibility for Europe, southern Africa and Asia BP brand and related matters

Outside interests

Non-executive director and senior independent director of Rolls-Royce Holdings plc.

Chairman of the advisory board of Imperial College Business School

Member of the council of Imperial College

Age

51

Nationality

British

 

Career

Iain Conn was appointed chief executive, Downstream on 1 June 2007.

He joined BP Oil International in 1986, working in a variety of roles in oil trading, commercial refining and exploration before becoming, on the merger between BP and Amoco in 1999, vice president of BP Amoco Exploration’s mid-continent business unit.

At the end of 2000, he returned to London as group vice president and a member of the Refining and Marketing segment’s executive committee, taking over responsibility in 2001 for BP’s marketing operations in Europe. In 2002 he was appointed chief executive of BP Petrochemicals. Following his appointment to the board in 2004, he served for three years as group executive officer, strategic resources, with responsibility for a number of group functions and regions.

Relevant experience and skills

Iain Conn’s career has given him extensive knowledge of a broad range of BP’s businesses, particularly in the Downstream, which he has led since 2007. In this last period he has successfully remodelled BP’s downstream business. He has deep knowledge of safety, manufacturing, energy markets and technology. He has continued to refocus the group’s downstream operations whilst growing the contribution of that segment.

Iain Conn’s performance has been evaluated by the group chief executive and considered by the chairman’s committee.

George David

 

Independent non-executive director

Tenure

Appointed 11 February 2008 (6 years)

Board and committee activities

Member of the audit committee

Member of the remuneration committee

Member of the Gulf of Mexico committee

Member of the chairman’s committee

Outside interests

Vice-Chairman of the Peterson Institute for International Economics

Age

71

Nationality

American

 

Career

George David began his career in The Boston Consulting Group before joining the Otis Elevator Company in 1975. He held various roles in Otis and later in United Technologies Corporation (UTC), following Otis’s merger with UTC in 1976. In 1992, he became UTC’s chief operating officer. He served as UTC’s chief executive officer from 1994 until 2008 and as chairman from 1997 until his retirement in 2009.

Relevant experience and skills

George David has substantial global business and financial experience through his long career with UTC, a business with significant reliance on safety and technology. He previously chaired BP’s technology advisory council and has brought insights from that task to the board.

He is an active member of the audit, remuneration and Gulf of Mexico committees, bringing a strong US and global view to their deliberations.

 

 

BP Annual Report and Form 20-F 2013       63   


Table of Contents

Ian Davis

 

Independent non-executive director

Tenure

Appointed 2 April 2010 (3 years)

Board and committee activities

Chairman of the Gulf of Mexico committee

Member of the remuneration committee

Member of the chairman’s committee

Member of the nomination committee

Outside interests

Chairman of Rolls-Royce Holdings plc.

Non-executive member of the UK Cabinet Office

Non-executive director of Johnson & Johnson, Inc.

Senior adviser to Apax Partners LLP.

Age

62

Nationality

British

 

Career

Ian Davis spent his early career at Bowater, moving to McKinsey & Company in 1979. He was managing partner of McKinsey’s practice in the UK and Ireland from 1996 to 2003. In 2003, he was appointed as chairman and worldwide managing director of McKinsey, serving in this capacity until 2009. During his career with McKinsey, he served as a consultant to a range of global organizations across the private, public and not-for-profit sectors. He retired as senior partner on 30 July 2010.

Relevant experience and skills

Ian Davis brings significant financial and strategic experience to the board. He has had a lengthy career working with and advising global organizations and companies in the oil and gas industry. This experience has been recognized by the board in his membership of the remuneration committee and chairmanship of the Gulf of Mexico committee.

As chairman of the Gulf of Mexico committee he has led the board’s oversight of the response in the Gulf and guided their consideration of the various legal issues which continue to arise following the Deepwater Horizon accident.

Professor Dame Ann Dowling

 

Independent non-executive director

Tenure

Appointed 3 February 2012 (2 years)

Board and committee activities

Member of the SEEAC

Member of the remuneration committee

Member of the chairman’s committee

Outside interests

Professor of Mechanical Engineering, head of the Department of Engineering and Deputy Vice-Chancellor at the University of Cambridge

Chair of the Physical Sciences, Engineering and Mathematics Panel in the Research Excellence Framework – the UK Government’s review of research in universities

Non-executive director of the Department for Business, Innovation & Skills (BIS)

Age

61

Nationality

British

 

Career

Dame Ann Dowling was appointed a Professor of Mechanical Engineering in the Department of Engineering at the University of Cambridge in 1993 (the Department of Engineering is one of the leading centres for engineering research worldwide). Between 1999 and 2000 she was the Jerome C Hunsaker Visiting Professor at MIT,

subsequently becoming a Moore distinguished scholar at Caltech in 2001. When she returned to the University of Cambridge, she became Head of the Division of Energy, Fluid Mechanics and Turbomachinery in the Department of Engineering, becoming UK lead of the Silent Aircraft Initiative in 2003 – a collaboration between researchers at Cambridge and MIT. She became head of the Department of Engineering at the University of Cambridge in 2009. She was appointed director of the University Gas Turbine Partnership with Rolls-Royce in 2001 and chairman in 2009.

Between 2003 and 2008 she chaired the Rolls-Royce Propulsion and Power Advisory Board. She chaired the Royal Society/Royal Academy of Engineering study on nanotechnology. She is a Fellow of the Royal Society and the Royal Academy of Engineering and is a foreign associate of the US National Academy of Engineering and of the French Academy of Sciences.

She has been nominated President of the Royal Academy of Engineering from September 2014.

Relevant experience and skills

Dame Ann Dowling has a strong academic and engineering background.

Having initially been a member of the SEEAC, she joined the remuneration committee in 2012. Her contributions on both of these committees are valued, as is her work with the BP technology advisory council, which she also joined during 2012 and which she now chairs.

Dr Brian Gilvary

 

Group chief financial officer

Tenure

Appointed to the board 1 January 2012 (2 years)

Group responsibilities

Finance, tax, planning, treasury, mergers and acquisitions, investor relations, audit, procurement and information technology activities Chairs the group financial risk committee

Outside interests

Visiting professor at Manchester University

Age

51

Nationality

British

 

Career

Dr Brian Gilvary was appointed chief financial officer on 1 January 2012.

He joined BP in 1986 after obtaining a PhD in mathematics from the University of Manchester. Following a variety of roles in the upstream, downstream and trading in Europe and the United States, he became the downstream’s chief financial officer and commercial director from 2002 to 2005.

He was a director of TNK-BP over two periods, from 2003 to 2005 and from 2010 until the sale of the business and acquisition of Rosneft equity in 2013. From 2005 until 2009 he was chief executive of the integrated supply and trading function, BP’s commodity trading arm. In 2010 he was appointed deputy group chief financial officer with responsibility for the finance function.

Relevant experience and skills

Dr Brian Gilvary has 27 years of experience within BP, gaining a strong knowledge of finance and trading, and a deep understanding of BP’s assets and businesses, including its interests in Russia through his time on the board of TNK-BP.

Brian has consistently worked to further strengthen the finance function. He has also developed the company’s engagement with shareholders and continues to focus on financial efficiency.

Brian Gilvary’s performance has been evaluated by the group chief executive and considered by the chairman’s committee.

 

 

64    BP Annual Report and Form 20-F 2013


Table of Contents

Brendan Nelson

 

Independent non-executive director

Tenure

Appointed 8 November 2010 (3 years)

Board and committee activities

Chairman of the audit committee

Member of the nomination committee

Member of the chairman’s committee

Outside interests

Non-executive director and chairman of the group audit committee of The Royal Bank of Scotland Group plc.

President of the Institute of Chartered Accountants of Scotland Member of the Financial Reporting Review Panel

Age

64

Nationality

British

 

Career

Brendan Nelson is a chartered accountant. He was made a partner of KPMG in 1984. He served as a member of the UK board of KPMG from 2000 to 2006, subsequently being appointed vice chairman until his retirement in 2010. At KPMG International he held a number of senior positions including global chairman, banking and global chairman, financial services.

He served six years as a member of the Financial Services Practitioner Panel.

Relevant experience and skills

Brendan Nelson has had a long career in finance and auditing, particularly in the areas of financial services and trading which qualifies him to chair the audit committee and to act as its financial expert.

This is complemented by his broader business experience and his role as the chair of the audit committee of a major bank. During the year he has led the audit committee in meeting the many challenges from increased changes to regulation.

Phuthuma Nhleko

 

Independent non-executive director

Tenure

Appointed 1 February 2011 (3 years)

Board and committee activities

Member of the audit committee

Member of the chairman’s committee

Outside interests

Non-executive director of Anglo American plc

Non-executive director and chairman of MTN Group Ltd.

Age

53

Nationality

South African

 

Career

Phuthuma Nhleko began his career as a civil engineer in the US and as a project manager for infrastructure developments in southern Africa. Following this he became a senior executive of the Standard Corporate and Merchant Bank in South Africa. He later held a succession of directorships before joining MTN Group, a pan-African and Middle Eastern telephony group represented in 21 countries, as group president and chief executive officer in 2002. During his tenure at the MTN Group he led a number of substantial mergers and acquisitions transactions.

He stepped down as group chief executive of MTN Group at the end of March 2011. He was formerly a director of a number of listed South African companies, including Johnnic Holdings (formerly a subsidiary of the Anglo American group of companies), Nedbank Group, Bidvest Group and Alexander Forbes.

Relevant experience and skills

Phuthuma Nhleko’s background in engineering and his broad experience as a chief executive of a multi-national company enables him to contribute to the board, particularly in the areas of emerging market economies and the evolution of the group’s strategy. His financial and commercial experience is particularly relevant to his work on the audit committee.

Andrew Shilston

 

Independent non-executive director

Tenure

Appointed 1 January 2012 (2 years)

Board and committee activities

Senior independent director

Member of the audit committee

Member of the chairman’s committee

Attends the nomination committee

Outside interests

Non-executive director of Circle Holdings plc.

Chairman of Morgan Advanced Materials plc.

Age

58

Nationality

British

 

Career

Andrew Shilston trained as a chartered accountant before joining BP as a management accountant. He subsequently joined Abbott Laboratories before moving to Enterprise Oil plc in 1984 at the time of flotation. In 1989 he became treasurer of Enterprise Oil and was appointed finance director in 1993. After the sale of Enterprise Oil to Shell in 2002, in 2003 he became finance director of Rolls-Royce plc until his retirement on 31 December 2011.

He has served as a non-executive director on the board of Cairn Energy plc where he chaired the audit committee.

Relevant experience and skills

Andrew Shilston has had a long career in finance within the oil and gas industry. His knowledge and experience as a chief financial officer, firstly in Enterprise Oil and then Rolls-Royce, and as audit committee chairman at Cairn Energy makes him well suited as a member of BP’s audit committee.

His experience of the oil and gas industry has been important in assisting the board in their evaluation of projects and capital expenditure. As senior independent director he has attended meetings of the nomination committee.

 

 

BP Annual Report and Form 20-F 2013       65   


Table of Contents

Executive teama

 

As at 6 March 2014

  The executive team represents the principal executive leadership of the BP group. Its membership includes BP’s executive directors (Bob Dudley, Iain Conn and Dr Brian Gilvary whose biographies appear on pages 61-64) and the senior management listed below.
LOGO
Key to portraits      
1    Rupert Bondy     2    Bob Fryar     3    Andy Hopwood     4    Katrina Landis
5    Bernard Looney     6    Lamar McKay     7    Dev Sanyal     8    Helmut Schuster

 

 

Rupert Bondy

 

Current position

Group general counsel

Executive team tenure

Appointed 1 May 2008 (5 years)

Outside interests

No external appointments

Age

52

Nationality

British

 

Career

Rupert Bondy is responsible for legal and compliance matters across the BP group.

Rupert began his career as a lawyer in private practice. In 1989 he joined US law firm Morrison & Foerster, working in San Francisco and London, and from 1994 he worked for UK law firm Lovells in London. In 1995 he joined SmithKline Beecham as senior counsel for mergers and acquisitions and other corporate matters. He subsequently held positions of increasing responsibility and, following the merger of SmithKline Beecham and GlaxoWellcome to form GlaxoSmithKline, he was appointed senior vice president and general counsel of GlaxoSmithKline in 2001.

In April 2008 he joined the BP group, and he became the group general counsel on 1 May 2008.

 

 

a  The ages of the executive team are correct as at 31 December 2013.

Bob Fryar

 

Current position

Executive vice president, safety and operational risk

Executive team tenure

Appointed 1 October 2010 (3 years)

Outside interests

No external appointments

Age

50

Nationality

American

 

Career

Bob Fryar is responsible for strengthening safety, operational risk management, and the systematic management of operations across the BP corporate group. He is group head of safety and operational risk, with accountability for group-level disciplines including engineering, health, safety, security, and environment. In this capacity, he looks after the group-wide operating management system implementation and capability programmes.

Bob has 28 years’ experience in the oil and gas industry having joined Amoco Production Company in 1985. From October 2010 to February 2013 Bob was executive vice president of the production division and was accountable for safe and compliant exploration and production operations and stewardship of resources across all regions. In addition, he was also responsible for local government and stakeholder management and regional integration of all exploration and production activities.

Prior to February 2013, Bob held several management positions in Trinidad, including chief operating officer for Atlantic LNG, and vice president of operations.

Prior to that, Bob served in a variety of engineering and management positions in onshore US and deepwater Gulf of Mexico including petroleum engineer, field manager, operations manager, resource manager, and asset manager. In addition, he worked on the Vastar integration team.

 

 

66    BP Annual Report and Form 20-F 2013


Table of Contents

Andy Hopwood

 

Current position

Chief operating officer, strategy and regions, Upstream

Executive team tenure

Appointed 1 November 2010 (3 years)

Outside interests

Chair of the BP Foundation

Age

55

Nationality

British

 

Career

Andy Hopwood is responsible for BP’s upstream strategy, including changes to its portfolio and investment planning. He is also responsible for the upstream regional footprint through leadership of its regional presidents, who are the upstream’s senior leaders in the regions where the upstream operates.

After joining BP in 1980 as a petroleum engineer, Andy gained ten years of operating experience in the North Sea, Wytch Farm, and Indonesia, and developing expertise in reservoir engineering in BP’s London headquarters.

In 1989 Andy joined the corporate planning team supporting the formulation of BP’s exploration strategy, and the subsequent rationalization of BP’s portfolio. Following this corporate work, his international endeavours led to positions in South America, first in Mexico and then as commercial manager for BP’s Venezuela business, prior to a return to London as the exploration and production planning manager.

In 1999, following the BP-Amoco merger, he was appointed business unit leader in Azerbaijan, before returning to London in 2001 as the Upstream chief of staff. He was then appointed business unit leader for BP’s interests in Trinidad & Tobago until 2005, when he moved to Houston to become strategic performance unit leader for the North American gas business.

In 2009, he joined the Upstream executive as head of portfolio and technology and in October 2010 was appointed executive vice president, exploration and production.

Katrina Landis

 

Current position

Executive vice president, corporate business activities

Executive team tenure

Appointed 1 May 2013

Outside interests

Independent director of Alstom SA

Founding member of Alstom’s Ethics, Compliance and Sustainability Committee

Member of Earth Day Network’s Global Advisory Committee Ambassador to the U.S. Department of Energy’s U.S. Clean Energy Education & Empowerment program

Age

54

Nationality

American

 

Career

Katrina Landis is responsible for BP’s integrated supply and trading activities, Alternative Energy, shipping, technology and remediation management.

Katrina began her career with BP in 1992 in Anchorage, Alaska and held a variety of senior roles. She was chief executive officer of BP’s integrated supply and trading – Oil Americas – from 2003 to 2006, group vice president of BP’s integrated supply and trading from 2007 to 2008 and chief operating officer of BP Alternative Energy from 2008 to 2009. She was then appointed chief executive officer of BP Alternative Energy in 2009. On 1 May 2013, she became executive vice president, corporate business activities.

Bernard Looney

 

Current position

Chief operating officer, production

Executive team tenure

Appointed 1 November 2010 (3 years)

Outside interests

Member of the Stanford University Graduate School of Business Advisory Council

Fellow of the Energy Institute

Age

43

Nationality

Irish

 

Career

Bernard Looney is responsible for production operations, drilling, engineering, procurement and supply-chain management, as well as health, safety and environment in the upstream.

Bernard joined BP in 1991 as a drilling engineer, working in the North Sea, Vietnam and the Gulf of Mexico. In 2001 Bernard took on responsibility for drilling operations on Thunder Horse in the Deepwater Gulf of Mexico.

In 2005 Bernard became senior vice president within BP Alaska, before moving in 2007 to be head of the group chief executive’s office.

In 2009 he became the managing director of BP’s North Sea business in the UK and Norway.

Bernar