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 Jamess Square, London SW1Y 4PD
United Kingdom
(Address of principal executive offices)
Dr Brian Gilvary
BP p.l.c.
1 St Jamess 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 |
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 issuers 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
NoteChecking 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
Building a stronger,
safer BP
Who we are
BP is one of the worlds leading integrated oil and |
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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. |
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| 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
BP Annual Report and Form 20-F 2013 | i |
Information about this report |
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.
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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 companys strategy and business model we have included a more focused and graphical presentation of BPs 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 Authoritys 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.
BPs 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 companys 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.
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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
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LoSal Project 20K SaaBre Veba Combi-Cracking (VCC) Permasense is a trade mark of Permasense Limited. Pick n Pay is a registered trademark of
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Registered office and our worldwide headquarters:
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Our agent in the US: | |||||
BP p.l.c. 1 St Jamess Square London SW1Y 4PD UK Tel +44 (0)20 7496 4000
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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. |
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ii | BP Annual Report and Form 20-F 2013 |
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BP Annual Report and Form 20-F 2013 1 |
2 | BP Annual Report and Form 20-F 2013 |
BP Annual Report and Form 20-F 2013 | 3 |
BP around the world
4 | BP Annual Report and Form 20-F 2013 |
BP Annual Report and Form 20-F 2013 | 5 |
10-year dividend history UK (pence per ordinary share)
US (cents per ADS)
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. Thats 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 peoples 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. BPs 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 dont 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 |
Board performance For information about the board and its committees see page 71.
Remuneration For information about our approach to executive directors remuneration see page 20.
Top: Members of BPs 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.
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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 BPs 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.
Carl-Henric Svanberg Chairman 6 March 2014 | |
BP Annual Report and Form 20-F 2013 | 7 |
Group chief executives letter
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 years 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 |
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.
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 worlds 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 todays 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
Im 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.
Bob Dudley Group Chief Executive 6 March 2014 |
BP Annual Report and Form 20-F 2013 | 9 |
We believe that a diverse mix of fuels and technologies will
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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 worlds 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 worlds 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 BPs 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 Agencys 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 | ||
2013 pricing See Upstream on page 26 and Downstream on page 32. |
10 | BP Annual Report and Form 20-F 2013 |
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.
See bp.com/energyoutlook.
Energy consumption by region (billion tonnes of oil equivalent)
Source: BP Energy Outlook 2035.
Energy consumption by fuel (billion tonnes of oil equivalent)
* 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 worlds 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.
Strategy Find out how BP can help meet energy demand for years to come on page 13.
Air BP is one of the worlds 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 |
We aim to create shareholder value across the hydrocarbon value chain.
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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 |
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.
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 |
Our goal is to be a focused oil and gas company that delivers value over volume.
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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.
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.
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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 |
Our strategy in action
14 | BP Annual Report and Form 20-F 2013 |
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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. | A commitment to safe operations Toledo refinery sets a safety record.
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. |
Maximizing value at Mad Dog Changing plans to make the best financial choices.
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. | Increasing oil production in Azerbaijan Local construction of BPs heaviest platform in the Caspian Sea.
See page 48.
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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 |
Discovering gas in India Two significant discoveries with Reliance Industries.
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 |
Preparing for Shah Deniz Stage 2 Largest gas sales contracts in Azerbaijans history.
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. | Creating our North American advantaged refinery Modernization project improves utilization and margin capture at Whiting.
See page 33. |
95.3% refining availability. |
Creating shareholder value by generating sustainable free cash flow
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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 They apply their diverse skills and expertise |
BP Annual Report and Form 20-F 2013 |
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Our distinctive capabilities
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.
See bp.com/technology.
The Pangbourne technology centre is home to chemists and liquid engineers dedicated to providing products and services for Castrols 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. |
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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.
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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.
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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. |
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. |
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. |
16 | BP Annual Report and Form 20-F 2013 |
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. |
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. |
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. | ||
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. |
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. |
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 peoples 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. |
BP Annual Report and Form 20-F 2013 | 17 |
Our key performance indicators
We assess the groups 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.
KPIs used to measure progress against our strategy.
KPIs used to determine 2013 and 2014 remuneration.
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Replacement cost profit (loss) per ordinary share (cents)
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)
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) (%)
Our gearing (net debt ratio) shows investors how significant net debt is relative to equity from shareholders in funding BPs 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%. | |||
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Refining availability (%)
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
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
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 |
Total shareholder return (%)
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 (%)
Proved reserves replacement ratio is the extent to which the years 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
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)
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 BPs 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
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 BPs operational HSSE reporting boundary. That boundary includes BPs own operated facilities and certain other locations or situations. |
Greenhouse gas emissions (million tonnes of CO2 equivalent)
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 BPs consolidated entities as well as our share of equity-accounted entities other than BPs share of TNK-BP and Rosneft. Rosnefts 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 (%)
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 BPs leadership, work is needed to further strengthen this.
c Relates to BP employees. |
Diversity and inclusionc d (%)
Each year we report the percentage of women and individuals from countries other than the UK and US among BPs 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 |
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. |
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:
20 | BP Annual Report and Form 20-F 2013 |
BP Annual Report and Form 20-F 2013 | 21 |
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.
~ 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 BPs 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
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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.
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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.
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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.
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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.
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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.
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We have a high-value, focused portfolio that plays to our strengths. | ||||||
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.
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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.
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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. |
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Major projects portfolio
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BP Annual Report and Form 20-F 2013 59 |
As at 6 March 2014
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 |
BP Annual Report and Form 20-F 2013 | 61 |
62 | BP Annual Report and Form 20-F 2013 |
BP Annual Report and Form 20-F 2013 | 63 |
64 | BP Annual Report and Form 20-F 2013 |
BP Annual Report and Form 20-F 2013 | 65 |
As at 6 March 2014 |
The executive team represents the principal executive leadership of the BP group. Its membership includes BPs executive directors (Bob Dudley, Iain Conn and Dr Brian Gilvary whose biographies appear on pages 61-64) and the senior management listed below. | |||||
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 |
66 | BP Annual Report and Form 20-F 2013 |
BP Annual Report and Form 20-F 2013 | 67 |
68 | BP Annual Report and Form 20-F 2013 |
BP Annual Report and Form 20-F 2013 | 69 |
Board and committee attendance in 2013
Board | Audit committee | SEEAC |
|
Remuneration committee |
|
|
Gulf of Mexico committee |
|
|
Nomination committee |
|
|
Chairmans committee |
| ||||||||||||||||||||||||||||||||||||||||||
A | B | A* | B | A* | B | A | B | A | B | A | B | A | B | |||||||||||||||||||||||||||||||||||||||||||
Non-executive directors | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Carl-Henric Svanberg |
11 | 11 | 4 | c | 4 | 6 | c | 6 | ||||||||||||||||||||||||||||||||||||||||||||||||
Paul Anderson1 |
11 | 11 | 7 | c | 7 | 13 | 12 | 4 | 4 | 6 | 6 | |||||||||||||||||||||||||||||||||||||||||||||
Frank Bowman |
11 | 11 | 7 | 7 | 13 | 13 | 6 | 6 | ||||||||||||||||||||||||||||||||||||||||||||||||
Antony Burgmans |
11 | 11 | 7 | 7 | 6 | c | 6 | 4 | 3 | 6 | 6 | |||||||||||||||||||||||||||||||||||||||||||||
Cynthia Carroll2 |
11 | 11 | 7 | 7 | 4 | 4 | 6 | 5 | ||||||||||||||||||||||||||||||||||||||||||||||||
George David3 |
11 | 11 | 12 | 12 | 6 | 6 | 13 | 12 | 6 | 5 | ||||||||||||||||||||||||||||||||||||||||||||||
Ian Davis4 |
11 | 11 | 6 | 5 | 13 | c | 13 | 4 | 3 | 6 | 5 | |||||||||||||||||||||||||||||||||||||||||||||
Ann Dowling |
11 | 11 | 7 | 7 | 6 | 6 | 6 | 6 | ||||||||||||||||||||||||||||||||||||||||||||||||
Brendan Nelson5 |
11 | 10 | 12 | c | 12 | 4 | 4 | 6 | 6 | |||||||||||||||||||||||||||||||||||||||||||||||
Phuthuma Nhleko6 |
11 | 10 | 12 | 12 | 6 | 5 | ||||||||||||||||||||||||||||||||||||||||||||||||||
Andrew Shilston7 |
11 | 9 | 12 | 11 | 6 | 6 | ||||||||||||||||||||||||||||||||||||||||||||||||||
Executive directors | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Bob Dudley |
11 | 11 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||
Iain Conn |
11 | 11 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||
Brian Gilvary |
11 | 11 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||
Byron Grote |
5 | 5 |
A = Total number of meetings the director was eligible to attend.
B = Total number of meetings the director did attend.
C | Committee chairman. |
* | Includes a joint Audit Committee-SEEAC meeting to review BPs system of internal control and risk management. |
1 | Paul Anderson was unable to attend the Gulf of Mexico committee meeting on 25 September 2013 due to a late change in the timing of the meeting. |
2 | Cynthia Carroll was unable to attend the chairmans committee on 5 December 2013 due to personal commitments. |
3 | George David was unable to attend the Gulf of Mexico committee meeting on 8 March 2013 due to a clash with travel arrangements; he was unable to attend the chairmans committee meeting on 24 July 2013 due to a late change in the timing of the meeting. |
4 | Ian Davis was unable to attend the meetings of the nomination and remuneration committees on 24 July 2013 due to a conflicting board meeting. |
5 | Brendan Nelson attended all scheduled board meetings in 2013, however he was unable to attend the board teleconference on 21 February 2013 that was called at short notice due to a prior commitment with the Royal Bank of Scotland plc. |
6 | Phuthuma Nhleko was unable to attend the chairmans committee meeting on 24 July 2013 and the board meeting on 25 July 2013 due to unforeseen urgent family commitments. |
7 | Andrew Shilston attended all scheduled board meetings in 2013, however he was unable to attend the two board teleconferences called at short notice on 16 January 2013 and 21 February 2013 due to prior commitments; he was unable to attend the audit committee meeting on 28 October 2013 due to major storms in the UK disrupting travel. |
70 | BP Annual Report and Form 20-F 2013 |
BP Annual Report and Form 20-F 2013 | 71 |
72 | BP Annual Report and Form 20-F 2013 |
BP Annual Report and Form 20-F 2013 | 73 |
74 | BP Annual Report and Form 20-F 2013 |
Audit committee focus in 2013
* | Undertaken jointly with the SEEAC. |
BP Annual Report and Form 20-F 2013 | 75 |
Permitted and non-permitted audit services | ||
Permitted services | ||
Audit related | ||
g Advice on accounting, auditing and financial reporting. | ||
g Internal accounting and risk management control reviews. | ||
g Non-statutory audit. | ||
g Project assurance/advice on business and accounting process improvement. | ||
g Due diligence (acquisition, disposals, joint arrangements). | ||
Tax services | ||
g Tax compliance. | ||
g Direct and indirect tax advisory services. | ||
g Transaction tax advisory services. | ||
g Assistance with tax audits and appeals. | ||
g Tax compliance/advisory relating to human capital and performance/reward. | ||
g Transfer pricing advisory services. | ||
g Tax legislative monitoring. | ||
g Tax performance advisory. | ||
Other services | ||
g Workshops, seminars and training on an arms length basis. | ||
g Assistance on non-financial regulatory requirements. | ||
g Provision of independent third-party audit on BPs Conflict Minerals Report. | ||
Prohibited services | ||
SEC principles of auditor independence | ||
g Book keeping/other services related to financial records. | ||
g Financial information systems design and implementation. | ||
g Appraisal, valuation, fairness opinions, contribution in-kind. | ||
g Actuarial services. | ||
g Internal audit outsourcing. | ||
g Management functions. | ||
g HR functions. | ||
g Broker-dealer, investment advisor, banking services. | ||
g Legal services. | ||
g Expert services unrelated to audit. | ||
PCAOB ethics and independence rules | ||
g Contingent fees. | ||
g Confidential or aggressive tax position transactions. | ||
g Tax services for persons in financial reporting oversight roles. |
76 | BP Annual Report and Form 20-F 2013 |
BP Annual Report and Form 20-F 2013 | 77 |
SEEAC focus in 2013
* | Undertaken jointly with the audit committee. |
78 | BP Annual Report and Form 20-F 2013 |
GoM committee focus in 2013
BP Annual Report and Form 20-F 2013 | 79 |
80 | BP Annual Report and Form 20-F 2013 |
report
|
82 |
|
||||||||||||||
84 | 2013 annual report on remuneration | |||||||||||||||
84 |
|
|||||||||||||||
95 |
|
|||||||||||||||
96 | Directors remuneration policy | |||||||||||||||
96 |
|
|||||||||||||||
107 | Non-executive directors | |||||||||||||||
BP Annual Report and Form 20-F 2013 81 |
82 | BP Annual Report and Form 20-F 2013 |
Remuneration the big picture
|
BP Annual Report and Form 20-F 2013 | 83 |
84 | BP Annual Report and Form 20-F 2013 |
Single figure table of remuneration of executive directors in 2013 (audited)
Remuneration is reported in the currency received by the individual
|
| |||||||||||||||||||||||||||||||
|
Bob Dudley thousand |
|
|
Iain Conn thousand |
|
|
Dr Brian Gilvary thousand |
|
|
Dr Byron Grote thousand |
| |||||||||||||||||||||
Annual remuneration 2013 | 2013 | 2012 | 2013 | 2012 | 2013 | 2012 | 2013 | 2012 | ||||||||||||||||||||||||
Salary |
$1,776 | $1,726 | £763 | £741 | £700 | £690 | $743 | $1,464 | ||||||||||||||||||||||||
Annual cash bonusa |
$2,344 | $837 | £961 | £374 | £924 | £366 | $1,470 | $710 | ||||||||||||||||||||||||
Benefits |
$90 | $86 | £59 | £39 | £45 | £13 | $10 | $15 | ||||||||||||||||||||||||
Total |
$4,210 | $2,649 | £1,783 | £1,154 | £1,669 | £1,069 | $2,223 | $2,189 | ||||||||||||||||||||||||
|
||||||||||||||||||||||||||||||||
Vested equity | ||||||||||||||||||||||||||||||||
Deferred bonus and matchb |
$0 | $0 | £242 | £0 | £0 | £0 | $893 | $0 | ||||||||||||||||||||||||
Performance shares |
$4,522 | c | $0 | £1,332 | c | £666 | £505 | c | £299 | $2,225 | c | $0 | ||||||||||||||||||||
Total |
$4,522 | $0 | £1,574 | £666 | £505 | £299 | $3,118 | $0 | ||||||||||||||||||||||||
|
||||||||||||||||||||||||||||||||
Total remuneration |
$8,732 | $2,649 | £3,357 | £1,820 | £2,174 | £1,368 | $5,341 | $2,189 | ||||||||||||||||||||||||
Pension | ||||||||||||||||||||||||||||||||
Pension value increased |
$4,447 | $6,535 | e | £46 | £0 | £44 | £1,024 | $141 | $747 | |||||||||||||||||||||||
Cash in lieu of future accrualf |
N/A | N/A | £267 | £259 | £245 | £242 | N/A | N/A | ||||||||||||||||||||||||
Total including pension |
$13,179 | $9,184 | £3,670 | £2,079 | £2,463 | £2,634 | $5,482 | $2,936 |
a | This reflects the amount of total overall bonus paid in cash with the deferred portion set out in the conditional equity table below. The relevant portions are two-thirds cash and one-third deferred. |
b | This relates to the deferred bonus from prior years that vests. |
c | Represents the assumed vesting of shares in 2014 following the end of the relevant performance period, based on anticipated performance achieved under the rules of the plan and includes re-invested dividends on shares vested. In accordance with UK regulations, the vesting price of the assumed vesting is the average market price for the fourth quarter of 2013 which was £4.69 for ordinary shares and $45.52 for ADSs. |
d | Represents the annual increase in accrued pension multiplied by 20 as prescribed by UK regulations. For Bob Dudley the increase in actuarial value of $1,319,000 is considered to be a more accurate reflection of the increase. |
e | The figure for 2012 has been restated on the same basis as 2013 to be consistent with the finalized UK regulations. |
f | As for all employees affected by UK pension tax limits and who wished to remain within these limits, with effect from April 2011, Iain Conn and Dr Brian Gilvary received a cash supplement of 35% of basic salary in lieu of future service pension accrual. |
Conditional equity to vest in future years, subject to performance
Bob Dudley | Iain Conn | Dr Brian Gilvary | Dr Byron Grote | |||||||||||||||||||||||||||||||||
Deferred bonus in respect of bonus year | 2013 | 2012 | 2013 | 2012 | 2013 | 2012 | 2013 | 2012 | ||||||||||||||||||||||||||||
Total deferred bonus |
Value (thousand) | $1,172 | $1,674 | £481 | £748 | £462 | £732 | $0 | $1,420 | |||||||||||||||||||||||||||
Total deferred converted to shares | Shares | 149,628 | 229,380 | 100,563 | 161,296 | 96,653 | 157,630 | 0 | 194,556 | |||||||||||||||||||||||||||
Total matched shares |
Shares | 149,628 | 229,380 | 100,563 | 161,296 | 96,653 | 157,630 | 0 | 32,424 | |||||||||||||||||||||||||||
Vesting date |
Feb 2017 | Feb 2016 | Feb 2017 | Feb 2016 | Feb 2017 | Feb 2016 | Feb 2017 | Feb 2016 | ||||||||||||||||||||||||||||
|
||||||||||||||||||||||||||||||||||||
Performance share element | 2013-2015 | 2012-2014 | 2013-2015 | 2012-2014 | 2013-2015 | 2012-2014 | 2013-2015 | 2012-2014 | ||||||||||||||||||||||||||||
Potential maximum shares |
1,384,026 | 1,343,712 | 694,688 | 660,633 | 637,413 | 624,434 | 142,278 | 414,468 | ||||||||||||||||||||||||||||
Vesting date |
Feb 2016 | Feb 2015 | Feb 2016 | Feb 2015 | Feb 2016 | Feb 2015 | Feb 2016 | Feb 2015 |
BP Annual Report and Form 20-F 2013 | 85 |
Total remuneration in more depth
|
2013 outcomes
|
Framework
2013 annual bonus outcomes
86 | BP Annual Report and Form 20-F 2013 |
2014 annual bonus measures
|
BP Annual Report and Form 20-F 2013 | 87 |
|
2011-2013 performance shares outcome
88 | BP Annual Report and Form 20-F 2013 |
2014-2016 performance shares
|
|
Service at 31 Dec 2013 |
|
|
Total accrued pension at 31 Dec 2013 |
|
|
Additional pension earned during 2013 (net of inflation) |
|
|
Actuarial value of increase earned during 2013 |
|
|
20 times increase earned during 2013 |
| ||||||
(thousand) | ||||||||||||||||||||
Bob Dudley (US) |
34 | $2,050 | $222 | $1,319 | $4,447 | |||||||||||||||
Iain Conn (UK) |
28 | £326 | £2 | £0 | £46 | |||||||||||||||
Brian Gilvary (UK) |
27 | £326 | £2 | £0 | £44 | |||||||||||||||
Byron Grote (US) |
n/a | $1,416 | $7 | -$93 | $141 |
BP Annual Report and Form 20-F 2013 | 89 |
90 | BP Annual Report and Form 20-F 2013 |
BP Annual Report and Form 20-F 2013 | 91 |
92 | BP Annual Report and Form 20-F 2013 |
Deferred shares (audited)a
Deferred share element interests | Interests vested in 2013 and 2014 | |||||||||||||||||||||||||||||||||||||||||||||
|
Bonus year |
|
|
Type |
|
|
Performance period |
|
|
Date of award of deferred shares |
|
|
Potential maximum deferred shares |
|
|
Number of ordinary |
|
Vesting date |
|
Face Value of the award at date of grant £ |
| |||||||||||||||||||||||||
|
At 1 Jan 2013 |
|
|
Awarded 2013 |
|
|
At 31 Dec 2013 |
|
|
Awarded 2014 |
|
|
shares vested |
|
||||||||||||||||||||||||||||||||
Bob Dudleyb |
2011 | c | Comp | 2012-2014 | 08 Mar 2012 | 109,206 | | 109,206 | | | | 539,478 | ||||||||||||||||||||||||||||||||||
Vol | 2012-2014 | 08 Mar 2012 | 109,206 | | 109,206 | | | | 539,478 | |||||||||||||||||||||||||||||||||||||
Mat | 2012-2014 | 08 Mar 2012 | 218,412 | | 218,412 | | | | 1,078,955 | |||||||||||||||||||||||||||||||||||||
2012 | d | Comp | 2013-2015 | 11 Feb 2013 | | 114,690 | 114,690 | | | | 521,840 | |||||||||||||||||||||||||||||||||||
Vol | 2013-2015 | 11 Feb 2013 | | 114,690 | 114,690 | | | | 521,840 | |||||||||||||||||||||||||||||||||||||
Mat | 2013-2015 | 11 Feb 2013 | | 229,380 | 229,380 | | | | 1,043,679 | |||||||||||||||||||||||||||||||||||||
2013 | d | Comp | 2014-2016 | 12 Feb 2014 | | | | 149,628 | | | 728,688 | |||||||||||||||||||||||||||||||||||
Mat | 2014-2016 | 12 Feb 2014 | | | | 149,628 | | | 728,688 | |||||||||||||||||||||||||||||||||||||
Iain Conn |
2010 | Comp | 2011-2013 | 09 Mar 2011 | 21,384 | | 21,384 | | 24,670 | f | 12 Feb 2014 | | ||||||||||||||||||||||||||||||||||
Mat | 2011-2013 | 09 Mar 2011 | 21,384 | | 21,384 | | 24,670 | f | 12 Feb 2014 | | ||||||||||||||||||||||||||||||||||||
2011 | c | Comp | 2012-2014 | 08 Mar 2012 | 80,652 | | 80,652 | | | | 398,421 | |||||||||||||||||||||||||||||||||||
Vol | 2012-2014 | 08 Mar 2012 | 80,652 | | 80,652 | | | | 398,421 | |||||||||||||||||||||||||||||||||||||
Mat | 2012-2014 | 08 Mar 2012 | 161,304 | | 161,304 | | | | 796,842 | |||||||||||||||||||||||||||||||||||||
2012 | d | Comp | 2013-2015 | 11 Feb 2013 | | 80,648 | 80,648 | | | | 366,948 | |||||||||||||||||||||||||||||||||||
Vol | 2013-2015 | 11 Feb 2013 | | 80,648 | 80,648 | | | | 366,948 | |||||||||||||||||||||||||||||||||||||
Mat | 2013-2015 | 11 Feb 2013 | | 161,296 | 161,296 | | | | 733,897 | |||||||||||||||||||||||||||||||||||||
2013 | d | Comp | 2014-2016 | 12 Feb 2014 | | | | 100,563 | | | 489,742 | |||||||||||||||||||||||||||||||||||
Mat | 2014-2016 | 12 Feb 2014 | | | | 100,563 | | | 489,742 | |||||||||||||||||||||||||||||||||||||
Dr Brian Gilvary |
2009 | DAB | e | 2010-2012 | 15 Mar 2010 | 87,394 | | | | 95,279 | f | 15 Jan 2013 | | |||||||||||||||||||||||||||||||||
2010 | DAB | e | 2011-2013 | 14 Mar 2011 | 44,971 | | 44,971 | | 51,118 | f | 09 Jan 2014 | | ||||||||||||||||||||||||||||||||||
2011 | h | DAB | e | 2012-2014 | 15 Mar 2012 | 73,624 | | 73,624 | | | | 362,966 | ||||||||||||||||||||||||||||||||||
2012 | d | Comp | 2013-2015 | 11 Feb 2013 | | 78,815 | 78,815 | | | | 358,608 | |||||||||||||||||||||||||||||||||||
Vol | 2013-2015 | 11 Feb 2013 | | 78,815 | 78,815 | | | | 358,608 | |||||||||||||||||||||||||||||||||||||
Mat | 2013-2015 | 11 Feb 2013 | | 157,630 | 157,630 | | | | 717,217 | |||||||||||||||||||||||||||||||||||||
2013 | d | Comp | 2014-2016 | 12 Feb 2014 | | | | 96,653 | | | 470,700 | |||||||||||||||||||||||||||||||||||
Mat | 2014-2016 | 12 Feb 2014 | | | | 96,653 | | | 470,700 | |||||||||||||||||||||||||||||||||||||
Former executive director | ||||||||||||||||||||||||||||||||||||||||||||||
Dr Byron Groteb |
2010 | Comp | 2011-2013 | 09 Mar 2011 | 26,604 | | 26,604 | | 30,174 | f | 12 Feb 2014 | | ||||||||||||||||||||||||||||||||||
Vol | 2011-2013 | 09 Mar 2011 | 26,604 | | 26,604 | | 30,174 | f | 12 Feb 2014 | | ||||||||||||||||||||||||||||||||||||
Mat | 2011-2013 | 09 Mar 2011 | 53,208 | | 44,340 | i | | 50,292 | f | 12 Feb 2014 | | |||||||||||||||||||||||||||||||||||
2011 | c | Comp | 2012-2014 | 08 Mar 2012 | 91,638 | | 91,638 | | | | 452,692 | |||||||||||||||||||||||||||||||||||
Vol | 2012-2014 | 08 Mar 2012 | 91,638 | | 91,638 | | | | 452,692 | |||||||||||||||||||||||||||||||||||||
Mat | 2012-2014 | 08 Mar 2012 | 183,276 | | 91,638 | i | | | | 452,692 | ||||||||||||||||||||||||||||||||||||
2012 | d | Comp | 2013-2015 | 11 Feb 2013 | | 97,278 | 97,278 | | | | 442,615 | |||||||||||||||||||||||||||||||||||
Vol | 2013-2015 | 11 Feb 2013 | | 97,278 | 97,278 | | | | 442,615 | |||||||||||||||||||||||||||||||||||||
Mat | 2013-2015 | 11 Feb 2013 | | 194,556 | 32,424 | i | | | | 147,529 |
Comp = Compulsory.
Vol = Voluntary.
Mat = Matching.
DAB = Deferred annual bonus plan.
a | Since 2010, vesting of the deferred shares has been subject to a safety and environmental sustainability hurdle, and this will continue. If the committee assesses that there has been a material deterioration in safety and environmental performance, or there have been major incidents, either of which reveal underlying weaknesses in safety and environmental management, then it may conclude that shares should vest only in part, or not at all. In reaching its conclusion, the committee will obtain advice from the SEEAC. There is no identified minimum vesting threshold level. |
b | Bob Dudley and Dr Byron Grote received awards in the form of ADSs. The above numbers reflect calculated equivalents in ordinary shares. One ADS is equivalent to six ordinary shares. |
c | The face value has been calculated using the market price of ordinary shares on 8 March 2012 of £4.94. |
d | The market price at closing of ordinary shares on 11 February 2013 was £4.55 and for ADSs was $43.01 and on 12 February 2014 was £4.87 and for ADSs was $48.38. The sterling value has been used to calculate the face value. |
e | Dr Brian Gilvary was granted the shares under the DAB prior to his appointment as a director. The vesting of these shares is not subject to further performance conditions and he receives deferred shares at each scrip payment date as part of his election choice. |
f | The market price of each share used to determine the total value at vesting on the vesting dates of 15 January 2013, 9 January 2014 and 12 February 2014 were £4.58, £4.97 and £4.90 respectively and for ADSs on 12 February 2014 was $48.41. |
h | The face value has been calculated using the market price of ordinary shares on 15 March 2012 of £4.93. |
i | All deferred and matched shares have been prorated to reflect actual service during the performance period and these figures have been used to calculate the face value. |
BP Annual Report and Form 20-F 2013 | 93 |
Performance shares (audited)
Share element interests | Interests vested in 2013 and 2014 | |||||||||||||||||||||||||||||||||||||
|
Performance period |
|
|
Date of award of performance shares |
|
|
Potential maximum performance sharesa |
|
|
Number of ordinary |
|
Vesting date | |
Face Value of the |
| |||||||||||||||||||||||
|
At 1 Jan 2013 |
|
|
Awarded 2013 |
|
|
At 31 Dec 2013 |
|
|
Awarded 2014 |
|
|
shares vested |
|
||||||||||||||||||||||||
Bob Dudleyb |
2010-2012 | 09 Feb 2010 | 581,082 | | | | 0 | | | |||||||||||||||||||||||||||||
2011-2013 | 09 Mar 2011 | 1,330,332 | | 1,330,332 | | 596,028 | c | March 2014 | | |||||||||||||||||||||||||||||
2012-2014 | d | 08 Mar 2012 | 1,343,712 | | 1,343,712 | | | | 6,637,937 | |||||||||||||||||||||||||||||
2013-2015 | d | 11 Feb 2013 | | 1,384,026 | 1,384,026 | | | | 6,297,318 | |||||||||||||||||||||||||||||
2014-2016 | d | 12 Feb 2014 | | | | 1,304,922 | | | 6,354,970 | |||||||||||||||||||||||||||||
Iain Conn |
2008-2013 | e | 13 Feb 2008 | 133,452 | | | | 145,489 | 07 Feb 2013 | | ||||||||||||||||||||||||||||
2010-2012 | 09 Feb 2010 | 656,813 | | | | 0 | | | ||||||||||||||||||||||||||||||
2011-2013 | 09 Mar 2011 | 623,025 | | 623,025 | | 283,920 | March 2014 | | ||||||||||||||||||||||||||||||
2012-2014 | d | 08 Mar 2012 | 660,633 | | 660,633 | | | | 3,263,527 | |||||||||||||||||||||||||||||
2013-2015 | d | 11 Feb 2013 | | 694,688 | 694,688 | | | | 3,160,830 | |||||||||||||||||||||||||||||
2014-2016 | d | 12 Feb 2014 | | | | 660,128 | | | 3,214,823 | |||||||||||||||||||||||||||||
Dr Brian Gilvary |
2010-2012 | f | 15 Mar 2010 | 60,000 | | | | 65,414 | c | 15 Jan 2013 | | |||||||||||||||||||||||||||
2011-2013 | f | 14 Mar 2011 | 67,500 | | 67,500 | | 76,726 | c | 09 Jan 2014 | | ||||||||||||||||||||||||||||
2010-2012 | g | 15 Mar 2010 | 22,500 | | | | 0 | | | |||||||||||||||||||||||||||||
2011-2013 | g | 14 Mar 2011 | 22,500 | | 22,500 | | 25,824 | c | 06 Feb 2014 | | ||||||||||||||||||||||||||||
2012-2014 | d | 08 Mar 2012 | 624,434 | | 624,434 | | | | 3,084,704 | |||||||||||||||||||||||||||||
2013-2015 | d | 11 Feb 2013 | | 637,413 | 637,413 | | | | 2,900,229 | |||||||||||||||||||||||||||||
2014-2016 | d | 12 Feb 2014 | | | | 605,544 | | | 2,948,999 | |||||||||||||||||||||||||||||
Former executive directors | ||||||||||||||||||||||||||||||||||||||
Dr Anthony Hayward |
2010-2012 | 09 Feb 2010 | 303,948 | h | | | | 0 | | | ||||||||||||||||||||||||||||
Andrew Inglis |
2010-2012 | 09 Feb 2010 | 218,938 | h | | | | 0 | | | ||||||||||||||||||||||||||||
Dr Byron Groteb |
2010-2012 | 09 Feb 2010 | 801,894 | | | | 0 | | | |||||||||||||||||||||||||||||
2011-2013 | 09 Mar 2011 | 785,394 | | 654,498 | h | | 293,232 | c | March 2014 | | ||||||||||||||||||||||||||||
2012-2014 | d | 08 Mar 2012 | 828,936 | | 414,468 | h | | | | 2,047,472 | ||||||||||||||||||||||||||||
2013-2015 | d | 11 Feb 2013 | | 853,650 | 142,278 | h | | | | 647,365 |
a | For awards under the 2010-2012 plan, performance conditions were measured one-third on TSR against ExxonMobil, Shell, Total, ConocoPhillips and Chevron and two-thirds on a balanced scorecard of underlying performance. For awards under the 2011-2013 plan, performance conditions are measured 50% on TSR against ExxonMobil, Shell, Total and Chevron; 20% on reserves replacement against the same peer group; and 30% against a balanced scorecard of strategic imperatives. For awards under the 2012-2014, 2013-2015 and 2014-2016 plans, performance conditions are measured one-third on TSR against ExxonMobil, Shell, Total and Chevron; one-third on operating cash flow; and one-third on a balanced scorecard of strategic imperatives. Each performance period ends on 31 December of the third year. There is no identified overall minimum vesting threshold level but to comply with UK regulations a value of 30%, which is conditional on the TSR, reserves replacement ratio and one of the strategic imperatives reaching the minimum threshold, has been calculated. |
b | Bob Dudley and Dr Byron Grote received awards in the form of ADSs. The above numbers reflect calculated equivalents in ordinary shares. One ADS is equivalent to six ordinary shares. |
c | Represents vestings of shares made at the end of the relevant performance period based on performance achieved under rules of the plan and includes reinvested dividends on the shares vested. The market price of each share at the vesting date of 15 January 2013 was £4.58, at 9 January 2014 was £4.97 and at 6 February 2014 was £4.77. For the assumed vestings dated March 2014 a price of £4.69 per ordinary share and $45.52 per ADS has been used. These are the average prices from the fourth quarter of 2013. |
d | The market price at closing of ordinary shares on 8 March 2012 was £4.94, on 11 February 2013 was £4.55 and for ADSs was $43.01 and on 12 February 2014 was £4.87 and for ADSs was $48.38. The sterling value has been used to calculate the face value. |
e | Restricted award under share element of EDIP. As reported in the 2007 directors remuneration report in February 2008, the committee awarded Iain Conn restricted shares, in two tranches of 133,452 shares each and on vesting include re-invested dividends on the shares vested. The total vesting of the first tranche was 155,695 shares at £4.91 on 22 February 2011. The remaining award, noted above, vested on 7 February 2013, the fifth anniversary of the award at £4.58. |
f | Dr Brian Gilvary was conditionally awarded shares under the Executive Performance Plan prior to his appointment as a director. The vesting of these shares is not subject to further performance conditions. |
g | Dr Brian Gilvary was conditionally awarded shares under the Competitive Performance Plan prior to his appointment as a director. The vesting of these shares is subject to performance conditions. |
h | Potential maximum of performance shares element have been pro-rated to reflect actual service during the performance period and these figures have been used to calculate the face value as appropriate. |
Share interests in share option plans (audited)
Option type | At 1 Jan 2013 | Granted | Exercised | At 31 Dec 2013 | Option price |
|
Market price at date of exercise |
|
|
Date from which first exercisable |
|
Expiry date | ||||||||||||||||||||||||
Bob Dudleya |
BP SOP | 17,835 | | 17,835 | b | | $38.10 | $43.99 | 17 Feb 2006 | 16 Feb 2013 | ||||||||||||||||||||||||||
Iain Conn |
SAYE | 605 | | 605 | c | | £4.20 | £4.54 | 01 Sep 2012 | 28 Feb 2013 | ||||||||||||||||||||||||||
SAYE | 3,017 | | | 3,017 | £3.68 | | 01 Sep 2016 | 28 Feb 2017 | ||||||||||||||||||||||||||||
SAYE | 797 | | | 797 | £3.16 | | 01 Sep 2015 | 28 Feb 2016 | ||||||||||||||||||||||||||||
Dr Brian Gilvary |
BP 2011 | 500,000 | | | 500,000 | £3.72 | | 07 Sep 2014 | 07 Sep 2021 | |||||||||||||||||||||||||||
SAYE | 4,191 | | | 4,191 | £3.68 | | 01 Sep 2016 | 28 Feb 2017 |
The closing market prices of an ordinary share and of an ADS on 31 December 2013 were £4.88 and $48.61 respectively.
During 2013 the highest market prices were £4.93 and $48.61 respectively and the lowest market prices were £4.31 and $40.19 respectively.
BP SOP = BP Share Option Plan. These options were granted to Bob Dudley prior to his appointment as a director and are not subject to performance conditions.
BP 2011 = BP 2011 Plan. These options were granted to Dr Brian Gilvary prior to his appointment as a director and are not subject to performance conditions.
SAYE = Save As You Earn all employee share scheme.
a | Numbers shown are ADSs under option. One ADS is equivalent to six ordinary shares. |
b | Options exercised on 6 February 2013. Market price at closing for information. Shares were sold in tranches after the exercise of options at an average price of $43.62 per ADS. |
c | Options exercised on 13 February 2013. Market price at closing for information. Shares were retained after the exercise of options. |
94 | BP Annual Report and Form 20-F 2013 |
Non-executive director interests
The figures below indicate and include all the beneficial and non-beneficial interests of each non-executive director of the company in shares of BP (or calculated equivalents) that have been disclosed to the company under the DTRs as at the applicable dates.
Current non-executive directors | |
Ordinary shares or equivalents at 1 Jan 2013 |
|
|
Ordinary shares or equivalents at 31 Dec 2013 |
|
|
Change from 31 Dec 2013 to 24 Feb 2014 |
|
|
Ordinary shares or equivalents total at 24 Feb 2014 |
|
|
Value of current shareholding |
|
|
% of policy achieved |
| ||||||
Carl-Henric Svanberg |
988,077 | 1,039,276 | | 1,039,276 | £5,258,737 | 670 | ||||||||||||||||||
Paul Anderson |
6,000 | a | 30,000 | a | | 30,000 | a | $251,350 | 168 | |||||||||||||||
Admiral Frank Bowman |
16,320 | a | 16,320 | a | | 16,320 | a | $136,734 | 91 | |||||||||||||||
Antony Burgmans |
10,156 | 10,156 | | 10,156 | £51,389 | 57 | ||||||||||||||||||
Cynthia Carroll |
10,500 | a | 10,500 | a | | 10,500 | a | $87,973 | 59 | |||||||||||||||
George David |
579,000 | a | 579,000 | a | | 579,000 | a | $4,851,055 | 3,241 | |||||||||||||||
Ian Davis |
10,866 | 11,449 | | 11,449 | £57,932 | 64 | ||||||||||||||||||
Professor Dame Ann Dowling |
11,630 | 22,320 | | 22,320 | £112,939 | 125 | ||||||||||||||||||
Brendan Nelson |
11,040 | 11,040 | | 11,040 | £55,862 | 62 | ||||||||||||||||||
Phuthuma Nhleko |
| | | | | 0 | ||||||||||||||||||
Andrew Shilston |
15,000 | 15,000 | | 15,000 | £75,900 | 63 | ||||||||||||||||||
a Held as ADSs. |
BP Annual Report and Form 20-F 2013 | 95 |
96 | BP Annual Report and Form 20-F 2013 |
BP Annual Report and Form 20-F 2013 | 97 |
Note: Further information is set out in the accompanying notes which follow this table.
98 | BP Annual Report and Form 20-F 2013 |
BP Annual Report and Form 20-F 2013 | 99 |
Remuneration policy in more depth
|
|
100 | BP Annual Report and Form 20-F 2013 |
|
BP Annual Report and Form 20-F 2013 | 101 |
|
102 | BP Annual Report and Form 20-F 2013 |
|
BP Annual Report and Form 20-F 2013 | 103 |
104 | BP Annual Report and Form 20-F 2013 |
BP Annual Report and Form 20-F 2013 | 105 |
106 | BP Annual Report and Form 20-F 2013 |
Board remuneration policy for the chairman
The maximum remuneration for non-executive directors is set in accordance with the Articles of Association. |
BP Annual Report and Form 20-F 2013 | 107 |
Board remuneration policy for non-executive directors
The maximum remuneration for non-executive directors is set in accordance with the Articles of Association. |
This directors remuneration report was approved by the board and signed on its behalf by David J Jackson, company secretary on 6 March 2014.
108 | BP Annual Report and Form 20-F 2013 |
Regulatory information |
110 | Internal Control Revised Guidance for Directors (Turnbull)
|
||||||||||||||
110 | Corporate governance practices
|
|||||||||||||||
111 |
|
|||||||||||||||
111 |
|
|||||||||||||||
111 | Principal accountants fees and services
|
|||||||||||||||
112 | Memorandum and Articles of Association | |||||||||||||||
BP Annual Report and Form 20-F 2013 109 |
110 | BP Annual Report and Form 20-F 2013 |
BP Annual Report and Form 20-F 2013 | 111 |
112 | BP Annual Report and Form 20-F 2013 |
BP Annual Report and Form 20-F 2013 | 113 |
114 | BP Annual Report and Form 20-F 2013 |
BP Annual Report and Form 20-F 2013 | 115 |
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This page does not form part of BPs Annual Report on Form 20-F as filed with the SEC.
116 | BP Annual Report and Form 20-F 2013 |
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BP Annual Report and Form 20-F 2013 | 117 |
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118 | BP Annual Report and Form 20-F 2013 |
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BP Annual Report and Form 20-F 2013 | 119 |
Consolidated financial statements of the BP group
Report of Independent Registered Public Accounting Firm on the Annual Report on Form 20-F
The Board of Directors and Shareholders of BP p.l.c.
We have audited the accompanying group balance sheets of BP p.l.c. as of 31 December 2013, 31 December 2012 and 1 January 2012, and the related group income statement, group statement of comprehensive income, group statement of changes in equity and group cash flow statement for each of the three years in the period ended 31 December 2013. These financial statements are the responsibility of the Companys management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the group financial position of BP p.l.c. at 31 December 2013, 31 December 2012 and 1 January 2012 and the group results of its operations and its cash flows for each of the three years in the period ended 31 December 2013, in accordance with International Financial Reporting Standards as adopted by the European Union and International Financial Reporting Standards as issued by the International Accounting Standards Board.
In forming our opinion we have considered the adequacy of the disclosures made in Note 2 to the financial statements concerning the provisions, future expenditures for which reliable estimates cannot be made and other contingencies related to the Gulf of Mexico oil spill significant event. The total amounts that will ultimately be paid by BP in relation to all obligations relating to the incident are subject to significant uncertainty and the ultimate exposure and cost to BP will be dependent on many factors. Furthermore, significant uncertainty exists in relation to the amount of claims that will become payable by BP, the amount of fines that will ultimately be levied on BP (including any determination of BPs culpability based on any findings of negligence, gross negligence or wilful misconduct), the outcome of litigation and arbitration proceedings, and any costs arising from any longer-term environmental consequences of the oil spill, which will also impact upon the ultimate cost for BP. Our opinion is not qualified in respect of these matters.
As discussed in Note 1 to the consolidated financial statements, the group has changed its accounting policies for employee benefits and interests in joint arrangements, including related disclosures, as a result of adopting new and revised International Financial Reporting Standards.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), BP p.l.c.s internal control over financial reporting as of 31 December 2013, based on criteria established in Internal Control: Revised Guidance for Directors on the Combined Code as issued by the Institute of Chartered Accountants in England and Wales (the Turnbull guidance) and our report dated 6 March 2014 expressed an unqualified opinion.
/s/ Ernst & Young LLP
London, England
6 March 2014
120 | BP Annual Report and Form 20-F 2013 |
Consolidated financial statements of the BP group
Report of Independent Registered Public Accounting Firm on the Annual Report on Form 20-F
The Board of Directors and Shareholders of BP p.l.c.
We have audited BP p.l.c.s internal control over financial reporting as of 31 December 2013, based on criteria established in Internal Control: Revised Guidance for Directors on the Combined Code as issued by the Institute of Chartered Accountants in England and Wales (the Turnbull guidance). BP p.l.c.s management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Managements report on internal control on page 111. Our responsibility is to express an opinion on the companys internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A companys internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A companys internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the companys assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, BP p.l.c. maintained, in all material respects, effective internal control over financial reporting as of 31 December 2013, based on the Turnbull guidance.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the group balance sheets of BP p.l.c. as of 31 December 2013 and 2012, and the related group income statement, group statement of comprehensive income, group statement of changes in equity and group cash flow statement for each of the three years in the period ended 31 December 2013, and our report dated 6 March 2014 expressed an unqualified opinion thereon.
/s/ Ernst & Young LLP
London, England
6 March 2014
Consent of independent registered public accounting firm
We consent to the incorporation by reference of our reports dated 6 March 2014, with respect to the group financial statements of BP p.l.c., and the effectiveness of internal control over financial reporting of BP p.l.c., included in this Annual Report and Form 20-F for the year ended 31 December 2013 in the following Registration Statements:
Registration Statement on Form F-3 (File No. 333-179953) of BP Capital Markets p.l.c. and BP p.l.c.; and
Registration Statements on Form S-8 (File Nos. 333-149778, 333-79399, 333-67206, 333-103924, 333-123482, 333-123483, 333-131583, 333-146868, 333-146870, 333-146873, 333-131584, 333-132619, 333-173136, 333-177423, 333-179406, 333-186463 and 333-186462) of BP p.l.c.
/s/ Ernst & Young LLP
London, England
6 March 2014
BP Annual Report and Form 20-F 2013 | 121 |
For the year ended 31 December | $ million | |||||||||||||||||
Note | 2013 | 2012a | 2011a | |||||||||||||||
Sales and other operating revenues |
7 | 379,136 | 375,765 | 375,713 | ||||||||||||||
Earnings from joint ventures after interest and tax |
17 | 447 | 260 | 767 | ||||||||||||||
Earnings from associates after interest and tax |
18 | 2,742 | 3,675 | 4,916 | ||||||||||||||
Interest and other income |
8 | 777 | 1,677 | 688 | ||||||||||||||
Gains on sale of businesses and fixed assets |
5 | 13,115 | 6,697 | 4,132 | ||||||||||||||
Total revenues and other income |
396,217 | 388,074 | 386,216 | |||||||||||||||
Purchases |
21 | 298,351 | 292,774 | 285,133 | ||||||||||||||
Production and manufacturing expensesb |
27,527 | 33,926 | 24,163 | |||||||||||||||
Production and similar taxes |
7 | 7,047 | 8,158 | 8,280 | ||||||||||||||
Depreciation, depletion and amortization |
7 | 13,510 | 12,687 | 11,357 | ||||||||||||||
Impairment and losses on sale of businesses and fixed assets |
5 | 1,961 | 6,275 | 2,058 | ||||||||||||||
Exploration expense |
10 | 3,441 | 1,475 | 1,520 | ||||||||||||||
Distribution and administration expenses |
13,070 | 13,357 | 13,958 | |||||||||||||||
Fair value gain on embedded derivatives |
26 | (459 | ) | (347 | ) | (68 | ) | |||||||||||
Profit before interest and taxation |
31,769 | 19,769 | 39,815 | |||||||||||||||
Finance costsb |
8 | 1,068 | 1,072 | 1,187 | ||||||||||||||
Net finance expense relating to pensions and other post-retirement benefits |
30 | 480 | 566 | 400 | ||||||||||||||
Profit before taxation |
30,221 | 18,131 | 38,228 | |||||||||||||||
Taxationb |
11 | 6,463 | 6,880 | 12,619 | ||||||||||||||
Profit for the year |
23,758 | 11,251 | 25,609 | |||||||||||||||
Attributable to |
||||||||||||||||||
BP shareholders |
32 | 23,451 | 11,017 | 25,212 | ||||||||||||||
Non-controlling interests |
32 | 307 | 234 | 397 | ||||||||||||||
23,758 | 11,251 | 25,609 | ||||||||||||||||
Earnings per share cents |
||||||||||||||||||
Profit for the year attributable to BP shareholders |
||||||||||||||||||
Basic |
13 | 123.87 | 57.89 | 133.35 | ||||||||||||||
Diluted |
13 | 123.12 | 57.50 | 131.74 |
a | See Note 1 for information on the restatement of comparative amounts as a result of the adoption of IFRS 11 Joint Arrangements and the amended IAS 19 Employee Benefits. |
b | See Note 2 for information on the impact of the Gulf of Mexico oil spill on these income statement line items. |
122 | BP Annual Report and Form 20-F 2013 |
Group statement of comprehensive income
For the year ended 31 December | $ million | |||||||||||||||||
Note | 2013 | 2012a | 2011a | |||||||||||||||
Profit for the year |
23,758 | 11,251 | 25,609 | |||||||||||||||
Other comprehensive income |
||||||||||||||||||
Items that may be reclassified subsequently to profit or loss |
||||||||||||||||||
Currency translation differences |
(1,608 | ) | 485 | (543 | ) | |||||||||||||
Exchange gains (losses) on translation of foreign operations reclassified to gain or loss on sale of businesses and fixed assets |
22 | (15 | ) | 19 | ||||||||||||||
Available-for-sale investments marked to market |
(172 | ) | 306 | (71 | ) | |||||||||||||
Available-for-sale investments reclassified to the income statement |
(523 | ) | (1 | ) | (3 | ) | ||||||||||||
Cash flow hedges marked to market |
26 | (2,000 | ) | 1,466 | 44 | |||||||||||||
Cash flow hedges reclassified to the income statement |
26 | 4 | 62 | (195 | ) | |||||||||||||
Cash flow hedges reclassified to the balance sheet |
26 | 17 | 19 | (13 | ) | |||||||||||||
Share of items relating to equity-accounted entities, net of tax |
(24 | ) | (39 | ) | (39 | ) | ||||||||||||
Income tax relating to items that may be reclassified |
11,32 | 147 | (170 | ) | 23 | |||||||||||||
(4,137 | ) | 2,113 | (778 | ) | ||||||||||||||
Items that will not be reclassified to profit or loss |
||||||||||||||||||
Remeasurements of the net pension and other post-retirement benefit liability or asset |
30 | 4,764 | (1,572 | ) | (5,301 | ) | ||||||||||||
Share of items relating to equity-accounted entities, net of tax |
2 | (6 | ) | | ||||||||||||||
Income tax relating to items that will not be reclassified |
11,32 | (1,521 | ) | 440 | 1,467 | |||||||||||||
3,245 | (1,138 | ) | (3,834 | ) | ||||||||||||||
Other comprehensive income |
(892 | ) | 975 | (4,612 | ) | |||||||||||||
Total comprehensive income |
22,866 | 12,226 | 20,997 | |||||||||||||||
Attributable to |
||||||||||||||||||
BP shareholders |
32 | 22,574 | 11,988 | 20,613 | ||||||||||||||
Non-controlling interests |
32 | 292 | 238 | 384 | ||||||||||||||
22,866 | 12,226 | 20,997 |
a | See Note 1 for information on the restatement of comparative amounts as a result of the adoption of IFRS 11 Joint Arrangements, the amended IAS 19 Employee Benefits and the amended IAS 1 Presentation of Financial Statements. |
Group statement of changes in equitya b
$ million | ||||||||||||||||||||||||||||||||||||||
Share capital and capital reserves |
Own shares and treasury shares |
Foreign currency translation reserve |
Fair value reserve |
Share- based payment reserve |
Profit and loss account |
BP shareholders equity |
Non- controlling interests |
Total equity |
||||||||||||||||||||||||||||||
At 1 January 2013 |
43,513 | (21,054 | ) | 5,128 | 1,775 | 1,608 | 87,576 | 118,546 | 1,206 | 119,752 | ||||||||||||||||||||||||||||
Profit for the year |
| | | | | 23,451 | 23,451 | 307 | 23,758 | |||||||||||||||||||||||||||||
Other comprehensive income |
| | (1,603 | ) | (2,470 | ) | | 3,196 | (877 | ) | (15 | ) | (892 | ) | ||||||||||||||||||||||||
Total comprehensive income |
| | (1,603 | ) | (2,470 | ) | | 26,647 | 22,574 | 292 | 22,866 | |||||||||||||||||||||||||||
Dividends |
| | | | | (5,441 | ) | (5,441 | ) | (469 | ) | (5,910 | ) | |||||||||||||||||||||||||
Repurchases of ordinary share capital |
| | | | | (6,923 | ) | (6,923 | ) | | (6,923 | ) | ||||||||||||||||||||||||||
Share-based payments, net of tax |
143 | 83 | | | 97 | 150 | 473 | | 473 | |||||||||||||||||||||||||||||
Share of equity-accounted entities changes in equity, net of tax |
| | | | | 73 | 73 | | 73 | |||||||||||||||||||||||||||||
Transactions involving non-controlling interests |
| | | | | | | 76 | 76 | |||||||||||||||||||||||||||||
At 31 December 2013 |
43,656 | (20,971 | ) | 3,525 | (695 | ) | 1,705 | 102,082 | 129,302 | 1,105 | 130,407 | |||||||||||||||||||||||||||
At 1 January 2012 |
43,454 | (21,323 | ) | 4,509 | 267 | 1,582 | 83,079 | 111,568 | 1,017 | 112,585 | ||||||||||||||||||||||||||||
Profit for the year |
| | | | | 11,017 | 11,017 | 234 | 11,251 | |||||||||||||||||||||||||||||
Other comprehensive income |
| | 619 | 1,508 | | (1,156 | ) | 971 | 4 | 975 | ||||||||||||||||||||||||||||
Total comprehensive income |
| | 619 | 1,508 | | 9,861 | 11,988 | 238 | 12,226 | |||||||||||||||||||||||||||||
Dividends |
| | | | | (5,294 | ) | (5,294 | ) | (82 | ) | (5,376 | ) | |||||||||||||||||||||||||
Share-based payments, net of tax |
59 | 269 | | | 26 | (70 | ) | 284 | | 284 | ||||||||||||||||||||||||||||
Transactions involving non-controlling interests |
| | | | | | | 33 | 33 | |||||||||||||||||||||||||||||
At 31 December 2012 |
43,513 | (21,054 | ) | 5,128 | 1,775 | 1,608 | 87,576 | 118,546 | 1,206 | 119,752 | ||||||||||||||||||||||||||||
At 1 January 2011 |
43,448 | (21,211 | ) | 5,036 | 469 | 1,586 | 65,754 | 95,082 | 904 | 95,986 | ||||||||||||||||||||||||||||
Profit for the year |
| | | | | 25,212 | 25,212 | 397 | 25,609 | |||||||||||||||||||||||||||||
Other comprehensive income |
| | (527 | ) | (202 | ) | | (3,870 | ) | (4,599 | ) | (13 | ) | (4,612 | ) | |||||||||||||||||||||||
Total comprehensive income |
| | (527 | ) | (202 | ) | | 21,342 | 20,613 | 384 | 20,997 | |||||||||||||||||||||||||||
Dividends |
| | | | | (4,072 | ) | (4,072 | ) | (245 | ) | (4,317 | ) | |||||||||||||||||||||||||
Share-based payments, net of tax |
6 | (112 | ) | | | (4 | ) | 102 | (8 | ) | | (8 | ) | |||||||||||||||||||||||||
Transactions involving non-controlling interests |
| | | | | (47 | ) | (47 | ) | (26 | ) | (73 | ) | |||||||||||||||||||||||||
At 31 December 2011 |
43,454 | (21,323 | ) | 4,509 | 267 | 1,582 | 83,079 | 111,568 | 1,017 | 112,585 |
a | See Note 32 for further information. |
b | See Note 1 for information on the restatement of comparative amounts as a result of the adoption of IFRS 11 Joint Arrangements and the amended IAS 19 Employee Benefits. |
BP Annual Report and Form 20-F 2013 | 123 |
$ million | ||||||||||||||||||
Note | 31 December 2013 |
31 December 2012a |
1 January 2012a |
|||||||||||||||
Non-current assets |
||||||||||||||||||
Property, plant and equipment |
14 | 133,690 | 125,331 | 123,431 | ||||||||||||||
Goodwill |
15 | 12,181 | 12,190 | 12,429 | ||||||||||||||
Intangible assets |
16 | 22,039 | 24,632 | 21,653 | ||||||||||||||
Investments in joint ventures |
17 | 9,199 | 8,614 | 8,303 | ||||||||||||||
Investments in associates |
18 | 16,636 | 2,998 | 13,291 | ||||||||||||||
Other investments |
20 | 1,565 | 2,704 | 2,635 | ||||||||||||||
Fixed assets |
195,310 | 176,469 | 181,742 | |||||||||||||||
Loans |
763 | 642 | 824 | |||||||||||||||
Trade and other receivables |
22 | 5,985 | 5,961 | 5,738 | ||||||||||||||
Derivative financial instruments |
26 | 3,509 | 4,294 | 5,038 | ||||||||||||||
Prepayments |
922 | 830 | 739 | |||||||||||||||
Deferred tax assets |
11 | 985 | 874 | 611 | ||||||||||||||
Defined benefit pension plan surpluses |
30 | 1,376 | 12 | 17 | ||||||||||||||
208,850 | 189,082 | 194,709 | ||||||||||||||||
Current assets |
||||||||||||||||||
Loans |
216 | 247 | 244 | |||||||||||||||
Inventories |
21 | 29,231 | 28,203 | 26,073 | ||||||||||||||
Trade and other receivables |
22 | 39,831 | 37,611 | 43,589 | ||||||||||||||
Derivative financial instruments |
26 | 2,675 | 4,507 | 3,857 | ||||||||||||||
Prepayments |
1,388 | 1,091 | 1,315 | |||||||||||||||
Current tax receivable |
512 | 456 | 235 | |||||||||||||||
Other investments |
20 | 467 | 319 | 288 | ||||||||||||||
Cash and cash equivalents |
23 | 22,520 | 19,635 | 14,177 | ||||||||||||||
96,840 | 92,069 | 89,778 | ||||||||||||||||
Assets classified as held for sale |
4 | | 19,315 | 8,420 | ||||||||||||||
96,840 | 111,384 | 98,198 | ||||||||||||||||
Total assets |
305,690 | 300,466 | 292,907 | |||||||||||||||
Current liabilities |
||||||||||||||||||
Trade and other payables |
25 | 47,159 | 46,673 | 52,000 | ||||||||||||||
Derivative financial instruments |
26 | 2,322 | 2,658 | 3,220 | ||||||||||||||
Accruals |
8,960 | 6,875 | 6,016 | |||||||||||||||
Finance debt |
27 | 7,381 | 10,033 | 9,039 | ||||||||||||||
Current tax payable |
1,945 | 2,503 | 1,943 | |||||||||||||||
Provisions |
29 | 5,045 | 7,587 | 11,238 | ||||||||||||||
72,812 | 76,329 | 83,456 | ||||||||||||||||
Liabilities directly associated with assets classified as held for sale |
4 | | 846 | 538 | ||||||||||||||
72,812 | 77,175 | 83,994 | ||||||||||||||||
Non-current liabilities |
||||||||||||||||||
Other payables |
25 | 4,756 | 2,292 | 3,214 | ||||||||||||||
Derivative financial instruments |
26 | 2,225 | 2,723 | 3,773 | ||||||||||||||
Accruals |
547 | 491 | 400 | |||||||||||||||
Finance debt |
27 | 40,811 | 38,767 | 35,169 | ||||||||||||||
Deferred tax liabilities |
11 | 17,439 | 15,243 | 15,220 | ||||||||||||||
Provisions |
29 | 26,915 | 30,396 | 26,462 | ||||||||||||||
Defined benefit pension plan and other post-retirement benefit plan deficits |
30 | 9,778 | 13,627 | 12,090 | ||||||||||||||
102,471 | 103,539 | 96,328 | ||||||||||||||||
Total liabilities |
175,283 | 180,714 | 180,322 | |||||||||||||||
Net assets |
130,407 | 119,752 | 112,585 | |||||||||||||||
Equity |
||||||||||||||||||
BP shareholders equity |
32 | 129,302 | 118,546 | 111,568 | ||||||||||||||
Non-controlling interests |
32 | 1,105 | 1,206 | 1,017 | ||||||||||||||
Total equity |
32 | 130,407 | 119,752 | 112,585 |
a | See Note 1 for information on the restatement of comparative amounts as a result of the adoption of IFRS 11 Joint Arrangements and the amended IAS 19 Employee Benefits. |
C-H Svanberg Chairman
R W Dudley Group Chief Executive
6 March 2014
124 | BP Annual Report and Form 20-F 2013 |
For the year ended 31 December | $ million | |||||||||||||||||
Note | 2013 | 2012a | 2011a | |||||||||||||||
Operating activities |
||||||||||||||||||
Profit before taxationb |
30,221 | 18,131 | 38,228 | |||||||||||||||
Adjustments to reconcile profit before taxation to net cash provided by operating activities |
||||||||||||||||||
Exploration expenditure written off |
10 | 2,710 | 745 | 1,024 | ||||||||||||||
Depreciation, depletion and amortization |
7 | 13,510 | 12,687 | 11,357 | ||||||||||||||
Impairment and (gain) loss on sale of businesses and fixed assets |
5 | (11,154 | ) | (422 | ) | (2,074 | ) | |||||||||||
Earnings from joint ventures and associates |
(3,189 | ) | (3,935 | ) | (5,683 | ) | ||||||||||||
Dividends received from joint ventures and associates |
1,391 | 1,763 | 5,040 | |||||||||||||||
Interest receivable |
(314 | ) | (379 | ) | (284 | ) | ||||||||||||
Interest received |
173 | 175 | 210 | |||||||||||||||
Finance costs |
8 | 1,068 | 1,072 | 1,187 | ||||||||||||||
Interest paid |
(1,084 | ) | (1,166 | ) | (1,125 | ) | ||||||||||||
Net finance expense relating to pensions and other post-retirement benefits |
30 | 480 | 566 | 400 | ||||||||||||||
Share-based payments |
297 | 156 | (88 | ) | ||||||||||||||
Net operating charge for pensions and other post-retirement benefits, less contributions and benefit payments for unfunded plans |
30 | (920 | ) | (858 | ) | (1,003 | ) | |||||||||||
Net charge for provisions, less payments |
1,061 | 5,338 | 2,988 | |||||||||||||||
(Increase) decrease in inventories |
(1,193 | ) | (1,720 | ) | (4,079 | ) | ||||||||||||
(Increase) decrease in other current and non-current assets |
(2,718 | ) | 2,933 | (9,860 | ) | |||||||||||||
Increase (decrease) in other current and non-current liabilities |
(2,932 | ) | (8,125 | ) | (5,957 | ) | ||||||||||||
Income taxes paid |
(6,307 | ) | (6,482 | ) | (8,063 | ) | ||||||||||||
Net cash provided by operating activities |
21,100 | 20,479 | 22,218 | |||||||||||||||
Investing activities |
||||||||||||||||||
Capital expenditure |
(24,520 | ) | (23,222 | ) | (17,978 | ) | ||||||||||||
Acquisitions, net of cash acquired |
3 | (67 | ) | (116 | ) | (10,909 | ) | |||||||||||
Investment in joint ventures |
(451 | ) | (1,526 | ) | (855 | ) | ||||||||||||
Investment in associates |
(4,994 | ) | (54 | ) | (55 | ) | ||||||||||||
Proceeds from disposals of fixed assets |
5 | 18,115 | 9,992 | 3,504 | ||||||||||||||
Proceeds from disposals of businesses, net of cash disposedc |
5 | 3,884 | 1,606 | (663 | ) | |||||||||||||
Proceeds from loan repayments |
178 | 245 | 203 | |||||||||||||||
Net cash used in investing activities |
(7,855 | ) | (13,075 | ) | (26,753 | ) | ||||||||||||
Financing activities |
||||||||||||||||||
Net issue (repurchase) of shares |
(5,358 | ) | 122 | 74 | ||||||||||||||
Proceeds from long-term financing |
8,814 | 11,087 | 11,600 | |||||||||||||||
Repayments of long-term financing |
(5,959 | ) | (7,177 | ) | (9,102 | ) | ||||||||||||
Net increase (decrease) in short-term debt |
(2,019 | ) | (666 | ) | 2,222 | |||||||||||||
Net increase (decrease) in non-controlling interests |
32 | | | |||||||||||||||
Dividends paid |
||||||||||||||||||
BP shareholders |
12 | (5,441 | ) | (5,294 | ) | (4,072 | ) | |||||||||||
Non-controlling interests |
(469 | ) | (82 | ) | (245 | ) | ||||||||||||
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 |
a | See Note 1 for information on the restatement of comparative amounts as a result of the adoption of IFRS 11 Joint Arrangements and the amended IAS 19 Employee Benefits. |
b | 2012 included $709 million of dividends received from TNK-BP. See Note 6 for further information. |
c | 2011 included the repayment of a deposit received in advance of $3,530 million following the termination of an agreement in respect of the expected sale of our interest in Pan American Energy LLC. |
BP Annual Report and Form 20-F 2013 | 125 |
Changes to the 2013 financial statements
BP aims for the highest standard of financial reporting and supports the initiatives of the UK Financial Reporting Council and the US Securities and Exchange Commission to improve understandability and transparency by cutting immaterial clutter from financial statements. We continually review the structure and content of our financial reports. For the 2013 financial statements, to increase their understandability and navigability, we have changed the grouping of certain notes, and have also sought to remove immaterial disclosures. In applying materiality to the financial statement disclosures, we consider both the amount and the nature of each item. The main changes compared with the financial statements included in the BP Annual Report and Form 20-F 2012 are as follows:
| Note 1 Significant accounting policies, judgements, estimates and assumptions this note includes the critical accounting estimates and judgements in boxed text following the relevant accounting policy. Last year this information was shown under Critical accounting policies in the Additional disclosures section of the Directors Report. |
| Note 2 Significant event Gulf of Mexico oil spill now contains all of our financial statement note disclosures in respect of the 2010 oil spill. Last year we also included information in the Provisions and Contingent liabilities notes to the financial statements. |
| Note 7 Segmental analysis now includes analysis of depreciation, depletion and amortization and production and similar taxes, previously provided in separate notes. |
| Note 8 Income statement analysis now combines a number of notes previously provided separately, simplifying the presentation while retaining materially the same content. |
| Note 15 Goodwill and impairment review of goodwill now contains the disclosures related to impairment testing of goodwill, which were provided in a separate note last year. |
| Note 19 Financial instruments and financial risk factors and Note 26 Derivative financial instruments have been rationalized to focus only on the material matters. |
| Note 38 Subsidiaries, joint arrangements and associates now lists only the most significant entities. |
| A separate share-based payment note is no longer presented. The share-based payment expense for the year is included in Note 33 Employee costs and numbers and information on the dilutive impact of employee share plans is included in Note 13 Earnings per ordinary share. |
1. Significant accounting policies, judgements, estimates and assumptions
Authorization of financial statements and statement of compliance with International Financial Reporting Standards
The consolidated financial statements of the BP group for the year ended 31 December 2013 were approved and signed by the group chief executive and chairman on 6 March 2014 having been duly authorized to do so by the board of directors. BP p.l.c. is a public limited company incorporated and domiciled in England and Wales. The consolidated financial statements have been prepared in accordance with International Financial Reporting Standards (IFRS) as issued by the International Accounting Standards Board (IASB), IFRS as adopted by the European Union (EU) and in accordance with the provisions of the UK Companies Act 2006. IFRS as adopted by the EU differs in certain respects from IFRS as issued by the IASB, however, the differences have no impact on the groups consolidated financial statements for the years presented. The significant accounting policies and critical accounting judgements, estimates and assumptions of the group are set out below.
Basis of preparation
The consolidated financial statements have been prepared in accordance with IFRS and IFRS Interpretations Committee (IFRIC) interpretations issued and effective for the year ended 31 December 2013. The standards and interpretations adopted in the year, and the corresponding impact on the financial statements, are described further on page 137.
The accounting policies that follow have been consistently applied to all years presented. Where retrospective restatements were required as a result of the implementation of new accounting standards or changes to existing accounting standards, these have been applied to all comparative years presented.
Subsequent to releasing our unaudited fourth quarter and full year 2013 results announcement dated 4 February 2014, a minor amendment has been made to the split of the Upstream replacement cost profit before interest and tax between US and non-US. The amount reported for US for the year has been reduced by $0.2 billion to $3.1 billion and the amount reported for non-US has been increased by $0.2 billion to $28.9 billion. Similarly, amendments have also been made to the geographical analysis for revenues and capital expenditure and acquisitions. There was no impact on the groups profit or loss, net assets or cash flows for the year.
The consolidated financial statements are presented in US dollars and all values are rounded to the nearest million dollars ($ million), except where otherwise indicated.
Critical accounting policies: use of judgements, estimates and assumptions
Inherent in the application of many of the accounting policies used in preparing the financial statements is the need for BP management to make judgements, estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the period. Actual outcomes could differ from the estimates and assumptions used. The critical accounting judgements and estimates that could have a significant impact on the results of the group are set out in boxed text below, and should be read in conjunction with the information provided in the Notes on financial statements. The areas requiring the most significant judgement and estimation in the preparation of the consolidated financial statements are in relation to acquisitions of interests in other entities, oil and natural gas accounting, including the estimation of reserves, the recoverability of asset carrying values, derivative financial instruments, including the application of hedge accounting, provisions and contingencies, in particular provisions and contingencies related to the Gulf of Mexico oil spill, pensions and other post-retirement benefits and taxation.
Basis of consolidation
The group financial statements consolidate the financial statements of BP p.l.c. and the entities it controls (its subsidiaries) drawn up to 31 December each year. Control of an investee exists when the investor is exposed, or has rights, to variable returns from its involvement with the investee and has the ability to affect those returns through its power over the investee. To have power over an investee, the investor must have existing rights that give it the current ability to direct the relevant activities of the investee. Subsidiaries are consolidated from the date of their acquisition, being the date on which the group obtains control, and continue to be consolidated until the date that such control ceases. The financial statements of subsidiaries are prepared for the same reporting year as the parent company, using consistent accounting policies. Intercompany balances and transactions, including unrealized profits arising from intragroup transactions, have been eliminated. Unrealized losses are eliminated unless the transaction provides evidence of an impairment of the asset transferred. Non-controlling interests represent the equity in subsidiaries that is not attributable, directly or indirectly, to the group.
126 | BP Annual Report and Form 20-F 2013 |
1. Significant accounting policies, judgements, estimates and assumptions continued
Interests in other entities
Business combinations and goodwill
A business combination is a transaction or other event in which an acquirer obtains control of one or more businesses. A business is an integrated set of activities and assets that is capable of being conducted and managed for the purpose of providing a return in the form of dividends or lower costs or other economic benefits directly to investors or other owners or participants. A business consists of inputs and processes applied to those inputs that have the ability to create outputs.
Business combinations are accounted for using the acquisition method. The identifiable assets acquired and liabilities assumed are measured at their fair values at the acquisition date. The cost of an acquisition is measured as the aggregate of the consideration transferred, measured at acquisition-date fair value, and the amount of any non-controlling interest in the acquiree. Non-controlling interests are stated either at fair value or at the proportionate share of the recognized amounts of the acquirees identifiable net assets. Acquisition costs incurred are expensed and included in distribution and administration expenses.
Goodwill is initially measured as the excess of the aggregate of the consideration transferred, the amount recognized for any non-controlling interest and the acquisition-date fair values of any previously held interest in the acquiree over the fair value of the identifiable assets acquired and liabilities assumed at the acquisition date.
At the acquisition date, any goodwill acquired is allocated to each of the cash-generating units, or groups of cash-generating units, expected to benefit from the combinations synergies.
Following initial recognition, goodwill is measured at cost less any accumulated impairment losses. Goodwill is reviewed for impairment annually or more frequently if events or changes in circumstances indicate the recoverable amount of the cash-generating unit to which the goodwill relates should be assessed. Where the recoverable amount of the cash-generating unit is less than the carrying amount, an impairment loss is recognized. An impairment loss recognized for goodwill is not reversed in a subsequent period.
Goodwill arising on business combinations prior to 1 January 2003 is stated at the previous carrying amount, less subsequent impairments, under UK generally accepted accounting practice.
Goodwill may also arise upon investments in joint ventures and associates, being the surplus of the cost of investment over the groups share of the net fair value of the identifiable assets and liabilities. Such goodwill is recorded within the corresponding investment in joint ventures and associates, and any impairment of the investment is included within the groups share of earnings from joint ventures and associates.
Interests in joint arrangements
A joint arrangement is an arrangement of which two or more parties have joint control. Joint control is the contractually agreed sharing of control of an arrangement, which exists only when decisions about the relevant activities require the unanimous consent of the parties sharing control.
A joint venture is a joint arrangement whereby the parties that have joint control of the arrangement have rights to the net assets of the arrangement. The results, assets and liabilities of a joint venture are incorporated in these financial statements using the equity method of accounting as described below.
Certain of the groups activities, particularly in the Upstream segment, are conducted through joint operations, which are joint arrangements whereby the parties that have joint control of the arrangement have rights to the assets, and obligations for the liabilities, relating to the arrangement. BP recognizes, on a line-by-line basis in the consolidated financial statements, its share of the assets, liabilities and expenses of these joint operations incurred jointly with the other partners, along with the groups income from the sale of its share of the output and any liabilities and expenses that the group has incurred in relation to the joint operation.
Interests in associates
An associate is an entity over which the group has significant influence, through the power to participate in the financial and operating policy decisions of the investee, but which is not a subsidiary or a joint arrangement. The results, assets and liabilities of an associate are incorporated in these financial statements using the equity method of accounting as described below.
Significant estimate or judgement
Judgement is required in assessing the level of control obtained in a transaction to acquire an interest in another entity: depending upon the facts and circumstances in each case, BP may obtain control, joint control or significant influence over the entity or arrangement. Transactions which give BP control of a business are business combinations. If BP obtains joint control of an arrangement, judgement is also required to assess whether the arrangement is a joint operation or a joint venture. If BP has neither control nor joint control, it may be in a position to exercise significant influence over the entity, which is then accounted for as an associate.
Accounting for business combinations and acquisitions of investments in equity-accounted joint ventures and associates requires judgements and estimates to be made in order to determine the fair value of the consideration transferred, together with the fair values of the assets acquired and the liabilities assumed in a business combination, or the identifiable assets and liabilities of the equity-accounted entity at the acquisition date. The group uses all available information, including external valuations and appraisals where appropriate, to determine these fair values. If necessary, the group has up to one year from the acquisition date to finalize the determinations of fair value for business combinations.
At 31 December 2013, and since the transaction described in Note 6 concluded on 21 March 2013, BP owned 19.75% of the voting shares of OJSC Oil Company Rosneft (Rosneft), a Russian oil and gas company. The Russian federal government, through its investment company OJSC Rosneftegaz, owned 69.5% of the voting shares of Rosneft at 31 December 2013. BP uses the equity method of accounting for its investment in Rosneft because under IFRS it is considered to have significant influence. Significant influence is defined as the power to participate in the financial and operating policy decisions of the investee but is not control or joint control. IFRS identifies several indicators that may provide evidence of significant influence, including representation on the board of directors of the investee and participation in policy-making processes. BPs group chief executive, Bob Dudley, has been elected to the board of directors of Rosneft, he is a member of the Rosneft boards Strategic Planning Committee and he participated in Rosnefts steering committee to integrate TNK-BP. Furthermore, under the Rosneft Charter BP has the right to nominate a second director to Rosnefts nine-person board of directors for election at a general meeting of shareholders should it choose to do so in the future. In addition, BP holds the voting rights at general meetings of shareholders conferred by its 19.75% stake in Rosneft. In managements judgement, the group has significant influence over Rosneft, as defined by the relevant accounting standard, and the investment is therefore accounted for as an associate. BPs share of Rosnefts oil and natural gas reserves is included in the estimated net proved reserves of equity-accounted entities.
BP Annual Report and Form 20-F 2013 | 127 |
1. Significant accounting policies, judgements, estimates and assumptions continued
The equity method of accounting
Under the equity method, the investment in an equity-accounted entity (joint venture or associate) is carried on the balance sheet at cost plus post-acquisition changes in the groups share of net assets of the equity-accounted entity, less distributions received and less any impairment in value of the investment. Loans advanced to equity-accounted entities that have the characteristics of equity financing are also included in the investment on the group balance sheet. The group income statement reflects the groups share of the results after tax of the equity-accounted entity, adjusted to account for depreciation, amortization and any impairment of the equity-accounted entitys assets based on their fair values at the date of acquisition.
The group statement of comprehensive income includes the groups share of the equity-accounted entitys other comprehensive income. The groups share of amounts recognized directly in equity by an equity-accounted entity is recognized directly in the groups statement of changes in equity.
Financial statements of equity-accounted entities are prepared for the same reporting year as the group. Where material differences arise, adjustments are made to those financial statements to bring the accounting policies used into line with those of the group.
Unrealized gains on transactions between the group and its equity-accounted entities are eliminated to the extent of the groups interest in the equity-accounted entity. Unrealized losses are also eliminated unless the transaction provides evidence of an impairment of the asset transferred.
The group assesses investments in equity-accounted entities for impairment whenever events or changes in circumstances indicate that the carrying value may not be recoverable. If any such indication of impairment exists, the carrying amount of the investment is compared with its recoverable amount, being the higher of its fair value less costs to sell and value in use. Where the carrying amount exceeds the recoverable amount, the investment is written down to its recoverable amount.
The group ceases to use the equity method of accounting on the date from which it no longer has joint control over the joint venture or significant influence over the associate, or when the interest becomes classified as an asset held for sale.
Segmental reporting
The groups operating segments are established on the basis of those components of the group that are evaluated regularly by the chief operating decision maker in deciding how to allocate resources and in assessing performance.
On 22 October 2012, BP announced that it had signed heads of terms for a proposed transaction to sell its 50% share in TNK-BP to Rosneft. Following this agreement, BPs investment in TNK-BP met the criteria to be classified as held for sale. On 21 March 2013, the disposal of BPs investment in TNK-BP completed and BP increased its investment in Rosneft. See Note 6 for further information. BPs investment in Rosneft is reported as a separate operating segment since that date, reflecting the way in which the investment is managed.
A separate organization within the group deals with the ongoing response to the Gulf of Mexico oil spill. This organization reports directly to the group chief executive and its costs are excluded from the results of the operating segments. Under IFRS its costs are presented as a reconciling item between the sum of the results of the reportable segments and the group results.
The accounting policies of the operating segments are the same as the groups accounting policies described in this note, except that IFRS requires that the measure of profit or loss disclosed for each operating segment is the measure that is provided regularly to the chief operating decision maker. For BP, this measure of profit or loss is replacement cost profit before interest and tax which reflects the replacement cost of supplies by excluding from profit inventory holding gains and losses. Replacement cost profit for the group is not a recognized measure under IFRS. For further information see Note 7.
Foreign currency translation
The functional currency is the currency of the primary economic environment in which an entity operates and is normally the currency in which the entity primarily generates and expends cash.
In individual subsidiaries, joint ventures and associates, transactions in foreign currencies are initially recorded in the functional currency by applying the rate of exchange ruling at the date of the transaction. Monetary assets and liabilities denominated in foreign currencies are retranslated into the functional currency at the rate of exchange ruling at the balance sheet date. Any resulting exchange differences are included in the income statement. Non-monetary assets and liabilities, other than those measured at fair value, are not retranslated subsequent to initial recognition.
In the consolidated financial statements, the assets and liabilities of non-US dollar functional currency subsidiaries, joint ventures and associates, including related goodwill, are translated into US dollars at the rate of exchange ruling at the balance sheet date. The results and cash flows of non-US dollar functional currency subsidiaries, joint ventures and associates are translated into US dollars using average rates of exchange. Exchange adjustments arising when the opening net assets and the profits for the year retained by non-US dollar functional currency subsidiaries, joint ventures and associates are translated into US dollars are taken to a separate component of equity and reported in the statement of comprehensive income. Exchange gains and losses arising on long-term intragroup foreign currency borrowings used to finance the groups non-US dollar investments are also taken to other comprehensive income. On disposal or partial disposal of a non-US dollar functional currency subsidiary, joint venture or associate, the deferred cumulative amount of exchange gains and losses recognized in equity relating to that particular non-US dollar operation is reclassified to the income statement.
Non-current assets held for sale
Non-current assets and disposal groups classified as held for sale are measured at the lower of carrying amount and fair value less costs to sell.
Non-current assets and disposal groups are classified as held for sale if their carrying amounts will be recovered through a sale transaction rather than through continuing use. This condition is regarded as met only when the sale is highly probable and the asset or disposal group is available for immediate sale in its present condition subject only to terms that are usual and customary for sales of such assets. Management must be committed to the sale, which should be expected to qualify for recognition as a completed sale within one year from the date of classification as held for sale.
Property, plant and equipment and intangible assets are not depreciated once classified as held for sale. The group ceases to use the equity method of accounting from the date on which an interest in a joint venture or associate becomes held for sale. If a non-current asset or disposal group has been classified as held for sale, but subsequently ceases to meet the criteria to be classified as held for sale, the group ceases to classify the asset or disposal group as held for sale. Non-current assets and disposal groups that cease to be classified as held for sale are measured at the lower of the carrying amount before the asset or disposal group was classified as held for sale (adjusted for any depreciation, amortization or revaluation that would have been recognized had the asset or disposal group not been classified as held for sale) and its recoverable amount at the date of the subsequent decision not to sell. Except for any interests in equity-accounted entities that cease to be classified as held for sale, any adjustment to the carrying amount is recognized in profit or loss in the period in which the asset ceases to be classified as held for sale. When an interest in an equity-accounted entity ceases to be classified as held for sale, it is accounted for using the equity method as from the date of its classification as held for sale and the financial statements for the periods since classification as held for sale are amended accordingly.
128 | BP Annual Report and Form 20-F 2013 |
1. Significant accounting policies, judgements, estimates and assumptions continued
Intangible assets
Intangible assets, other than goodwill, include expenditure on the exploration for and evaluation of oil and natural gas resources, computer software, patents, licences and trademarks and are stated at the amount initially recognized, less accumulated amortization and accumulated impairment losses. For information on accounting for expenditures on the exploration for and evaluation of oil and natural gas resources, see the accounting policy for oil and natural gas exploration, appraisal and development expenditure below.
Intangible assets acquired separately from a business are carried initially at cost. The initial cost is the aggregate amount paid and the fair value of any other consideration given to acquire the asset. An intangible asset acquired as part of a business combination is measured at fair value at the date of acquisition and is recognized separately from goodwill if the asset is separable or arises from contractual or other legal rights.
Intangible assets with a finite life are amortized on a straight-line basis over their expected useful lives. For patents, licences and trademarks, expected useful life is the shorter of the duration of the legal agreement and economic useful life, and can range from three to 15 years. Computer software costs generally have a useful life of three to five years.
The expected useful lives of assets are reviewed on an annual basis and, if necessary, changes in useful lives are accounted for prospectively.
The carrying value of intangible assets is reviewed for impairment whenever events or changes in circumstances indicate the carrying value may not be recoverable.
Oil and natural gas exploration, appraisal and development expenditure
Oil and natural gas exploration, appraisal and development expenditure is accounted for using the principles of the successful efforts method of accounting.
Licence and property acquisition costs
Exploration licence and leasehold property acquisition costs are capitalized within intangible assets and are reviewed at each reporting date to confirm that there is no indication that the carrying amount exceeds the recoverable amount. This review includes confirming that exploration drilling is still under way or firmly planned or that it has been determined, or work is under way to determine, that the discovery is economically viable based on a range of technical and commercial considerations and sufficient progress is being made on establishing development plans and timing. If no future activity is planned, the remaining balance of the licence and property acquisition costs is written off. Lower value licences are pooled and amortized on a straight-line basis over the estimated period of exploration. Upon recognition of proved reserves and internal approval for development, the relevant expenditure is transferred to property, plant and equipment.
Exploration and appraisal expenditure
Geological and geophysical exploration costs are charged against income as incurred. Costs directly associated with an exploration well are initially capitalized as an intangible asset until the drilling of the well is complete and the results have been evaluated. These costs include employee remuneration, materials and fuel used, rig costs and payments made to contractors. If potentially commercial quantities of hydrocarbons are not found, the exploration well is written off as a dry hole. If hydrocarbons are found and, subject to further appraisal activity, are likely to be capable of commercial development, the costs continue to be carried as an asset.
Costs directly associated with appraisal activity, undertaken to determine the size, characteristics and commercial potential of a reservoir following the initial discovery of hydrocarbons, including the costs of appraisal wells where hydrocarbons were not found, are initially capitalized as an intangible asset. When proved reserves of oil and natural gas are determined and development is approved by management, the relevant expenditure is transferred to property, plant and equipment.
Development expenditure
Expenditure on the construction, installation and completion of infrastructure facilities such as platforms, pipelines and the drilling of development wells, including service and unsuccessful development or delineation wells, is capitalized within property, plant and equipment and is depreciated from the commencement of production as described below in the accounting policy for property, plant and equipment.
Significant estimate or judgement
The determination of whether potentially economic oil and natural gas reserves have been discovered by an exploration well is usually made within one year after well completion, but can take longer, depending on the complexity of the geological structure. Exploration wells that discover potentially economic quantities of oil and natural gas and are in areas where major capital expenditure (e.g. offshore platform or a pipeline) would be required before production could begin, and where the economic viability of that major capital expenditure depends on the successful completion of further exploration work in the area, remain capitalized on the balance sheet as long as additional exploration appraisal work is under way or firmly planned.
It is not unusual to have exploration wells and exploratory-type stratigraphic test wells remaining suspended on the balance sheet for several years while additional appraisal drilling and seismic work on the potential oil and natural gas field is performed or while the optimum development plans and timing are established. All such carried costs are subject to regular technical, commercial and management review on at least an annual basis to confirm the continued intent to develop, or otherwise extract value from, the discovery. Where this is no longer the case, the costs are immediately expensed.
Property, plant and equipment
Property, plant and equipment is stated at cost, less accumulated depreciation and accumulated impairment losses. The initial cost of an asset comprises its purchase price or construction cost, any costs directly attributable to bringing the asset into the location and condition necessary for it to be capable of operating in the manner intended by management, the initial estimate of any decommissioning obligation, if any, and, for assets that necessarily take a substantial period of time to get ready for their intended use, borrowing costs. The purchase price or construction cost is the aggregate amount paid and the fair value of any other consideration given to acquire the asset. The capitalized value of a finance lease is also included within property, plant and equipment. Exchanges of assets are measured at fair value unless the exchange transaction lacks commercial substance or the fair value of neither the asset received nor the asset given up is reliably measurable. The cost of the acquired asset is measured at the fair value of the asset given up, unless the fair value of the asset received is more clearly evident. Where fair value is not used, the cost of the acquired asset is measured at the carrying amount of the asset given up. The gain or loss on derecognition of the asset given up is recognized in profit or loss.
Expenditure on major maintenance refits or repairs comprises the cost of replacement assets or parts of assets, inspection costs and overhaul costs. Where an asset or part of an asset that was separately depreciated is replaced and it is probable that future economic benefits associated with the item will flow to the group, the expenditure is capitalized and the carrying amount of the replaced asset is derecognized. Inspection costs associated with major maintenance programmes are capitalized and amortized over the period to the next inspection. Overhaul costs for major maintenance programmes, and all other maintenance costs are expensed as incurred.
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Oil and natural gas properties, including related pipelines, are depreciated using a unit-of-production method. The cost of producing wells is amortized over proved developed reserves. Licence acquisition, common facilities and future decommissioning costs are amortized over total proved reserves. The unit-of-production rate for the depreciation of common facilities takes into account expenditures incurred to date, together with estimated future capital expenditure expected to be incurred relating to as yet undeveloped reserves expected to be processed through these common facilities.
Other property, plant and equipment is depreciated on a straight-line basis over its expected useful life. The typical useful lives of the groups other property, plant and equipment are as follows:
Land improvements |
15 to 25 years | |
Buildings |
20 to 50 years | |
Refineries |
20 to 30 years | |
Petrochemicals plants |
20 to 30 years | |
Pipelines |
10 to 50 years | |
Service stations |
15 years | |
Office equipment |
3 to 7 years | |
Fixtures and fittings |
5 to 15 years |
The expected useful lives of property, plant and equipment are reviewed on an annual basis and, if necessary, changes in useful lives are accounted for prospectively.
The carrying amount of property, plant and equipment is reviewed for impairment whenever events or changes in circumstances indicate the carrying value may not be recoverable.
An item of property, plant and equipment is derecognized upon disposal or when no future economic benefits are expected to arise from the continued use of the asset. Any gain or loss arising on derecognition of the asset (calculated as the difference between the net disposal proceeds and the carrying amount of the item) is included in the income statement in the period in which the item is derecognized.
Significant estimate or judgement
The determination of the groups estimated oil and natural gas reserves requires significant judgements and estimates to be applied and these are regularly reviewed and updated. Factors such as the availability of geological and engineering data, reservoir performance data, acquisition and divestment activity, drilling of new wells and commodity prices all impact on the determination of the groups estimates of its oil and natural gas reserves. BP bases its proved reserves estimates on the requirement of reasonable certainty with rigorous technical and commercial assessments based on conventional industry practice and regulatory requirements.
The estimation of oil and natural gas reserves and BPs process to manage reserves bookings is described in Supplementary information on oil and natural gas on page 200, which is unaudited. Details on BPs proved reserves and production compliance and governance processes are provided on page 245.
Estimates of oil and natural gas reserves are used to calculate depreciation, depletion and amortization charges for the groups oil and gas properties. The impact of changes in estimated proved reserves is dealt with prospectively by amortizing the remaining carrying value of the asset over the expected future production. Oil and natural gas reserves also have a direct impact on the assessment of the recoverability of asset carrying values reported in the financial statements. If proved reserves estimates are revised downwards, earnings could be affected by higher depreciation expense or an immediate write-down of the propertys carrying value.
The 2013 movements in proved reserves are reflected in the tables showing movements in oil and natural gas reserves by region in Supplementary information on oil and natural gas (unaudited) on page 200. Information on the carrying amounts of the groups oil and natural gas properties, together with the amounts recognized in the income statement as depreciation, depletion and amortization is contained in Note 10 and Note 7 respectively.
Impairment of intangible assets and property, plant and equipment
The group assesses assets or groups of assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable, for example, changes in the groups business plans, changes in commodity prices leading to sustained unprofitable performance, low plant utilization, evidence of physical damage or, for oil and gas assets, significant downward revisions of estimated reserves or increases in estimated future development expenditure. If any such indication of impairment exists, the group makes an estimate of the assets recoverable amount. Individual assets are grouped for impairment assessment purposes at the lowest level at which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets. An asset groups recoverable amount is the higher of its fair value less costs to sell and its value in use. Where the carrying amount of an asset group exceeds its recoverable amount, the asset group is considered impaired and is written down to its recoverable amount. In assessing value in use, the estimated future cash flows are adjusted for the risks specific to the asset group and are discounted to their present value using a pre-tax discount rate that reflects current market assessments of the time value of money. Fair value less costs to sell is identified as the price that would be received to sell the asset in an orderly transaction between market participants and does not reflect the effects of factors that may be specific to the entity and not applicable to entities in general.
An assessment is made at each reporting date as to whether there is any indication that previously recognized impairment losses may no longer exist or may have decreased. If such an indication exists, the recoverable amount is estimated. A previously recognized impairment loss is reversed only if there has been a change in the estimates used to determine the assets recoverable amount since the last impairment loss was recognized. If that is the case, the carrying amount of the asset is increased to its recoverable amount. That increased amount cannot exceed the carrying amount that would have been determined, net of depreciation, had no impairment loss been recognized for the asset in prior years. Such reversal is recognized in profit or loss. After such a reversal, the depreciation charge is adjusted in future periods to allocate the assets revised carrying amount, less any residual value, on a systematic basis over its remaining useful life.
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Significant estimate or judgement
Determination as to whether, and how much, an asset is impaired involves management estimates on highly uncertain matters such as future commodity prices, the effects of inflation on operating expenses, discount rates, production profiles and the outlook for global or regional market supply-and-demand conditions for crude oil, natural gas and refined products.
For oil and natural gas properties, the expected future cash flows are estimated using managements best estimate of future oil and natural gas prices and reserves volumes. Prices for oil and natural gas used for future cash flow calculations are based on market prices for the first five years and the groups long-term price assumptions thereafter. As at 31 December 2013, the groups long-term price assumptions were $90 per barrel for Brent and $6.50/mmBtu for Henry Hub (2012 $90 per barrel and $6.50/mmBtu). These long-term price assumptions are subject to periodic review and revision. The estimated future level of production is based on assumptions about future commodity prices, production and development costs, field decline rates, current fiscal regimes and other factors.
For value in use calculations, future cash flows are adjusted for risks specific to the cash-generating unit and are discounted using a pre-tax discount rate. The discount rate is derived from the groups post-tax weighted average cost of capital and is adjusted where applicable to take into account any specific risks relating to the country where the cash-generating unit is located, although other rates may be used if appropriate to the specific circumstances. In 2013 the rates ranged from 12% to 14% nominal (2012 12% to 14% nominal). The discount rates applied in assessments of impairment are reassessed each year. In cases where fair value less costs to sell is used to determine the recoverable amount of an asset, where recent market transactions for the asset are not available for reference, accounting judgements are made about the assumptions market participants would use when pricing the asset. Fair value less costs to sell may be determined based on similar recent market transaction data or using discounted cash flow techniques. Where discounted cash flow analyses are used to calculate fair value less costs to sell, the discount rate used is the groups post-tax weighted average cost of capital.
Irrespective of whether there is any indication of impairment, BP is required to test annually for impairment of goodwill acquired in a business combination. The group carries goodwill of approximately $12.2 billion on its balance sheet (2012 $12.2 billion), principally relating to the Atlantic Richfield, Burmah Castrol, Devon Energy and Reliance transactions. In testing goodwill for impairment, the group uses a similar approach to that described above for asset impairment. If there are low oil or natural gas prices or refining margins or marketing margins for an extended period, the group may need to recognize significant goodwill impairment charges.
The recoverability of intangible exploration and appraisal expenditure is covered under Oil and natural gas exploration, appraisal and development expenditure above.
Details of impairment charges recognized in the income statement are provided in Note 5 and details on the carrying amounts of assets are shown in Note 14, Note 15 and Note 16.
Inventories
Inventories, other than inventory held for trading purposes, are stated at the lower of cost and net realizable value. Cost is determined by the first-in first-out method and comprises direct purchase costs, cost of production, transportation and manufacturing expenses. Net realizable value is determined by reference to prices existing at the balance sheet date.
Inventories held for trading purposes are stated at fair value less costs to sell and any changes in fair value are recognized in the income statement.
Supplies are valued at cost to the group mainly using the average method or net realizable value, whichever is the lower.
Leases
Finance leases, which transfer to the group substantially all the risks and benefits incidental to ownership of the leased item, are capitalized at the commencement of the lease term at the fair value of the leased item or, if lower, at the present value of the minimum lease payments. Finance charges are allocated to each period so as to achieve a constant rate of interest on the remaining balance of the liability and are charged directly against income.
Capitalized leased assets are depreciated over the shorter of the estimated useful life of the asset or the lease term. Operating lease payments are recognized as an expense in the income statement on a straight-line basis over the lease term. For both finance and operating leases, contingent rents are recognized in the income statement in the period in which they are incurred.
Financial assets
Financial assets are classified as loans and receivables; financial assets at fair value through profit or loss; derivatives designated as hedging instruments in an effective hedge; held-to-maturity financial assets; or as available-for-sale financial assets, as appropriate. Financial assets include cash and cash equivalents, trade receivables, other receivables, loans, other investments, and derivative financial instruments. The group determines the classification of its financial assets at initial recognition. Financial assets are recognized initially at fair value, normally being the transaction price plus, in the case of financial assets not at fair value through profit or loss, directly attributable transaction costs.
The subsequent measurement of financial assets depends on their classification, as follows:
Loans and receivables
Loans and receivables are non-derivative financial assets with fixed or determinable payments that are not quoted in an active market. Such assets are carried at amortized cost using the effective interest method if the time value of money is significant. Gains and losses are recognized in income when the loans and receivables are derecognized or impaired, as well as through the amortization process. This category of financial assets includes trade and other receivables. Cash and cash equivalents are short-term highly liquid investments that are readily convertible to known amounts of cash, are subject to insignificant risk of changes in value and have a maturity of three months or less from the date of acquisition.
Financial assets at fair value through profit or loss
Financial assets at fair value through profit or loss are carried on the balance sheet at fair value with gains or losses recognized in the income statement. Derivatives, other than those designated as effective hedging instruments, are classified as held for trading and are included in this category.
Derivatives designated as hedging instruments in an effective hedge
Such derivatives are carried on the balance sheet at fair value. The treatment of gains and losses arising from revaluation is described below in the accounting policy for derivative financial instruments and hedging activities.
Held-to-maturity financial assets
Held-to-maturity financial assets are non-derivative financial assets with fixed or determinable payments and fixed maturity that management has the positive intention and ability to hold to maturity. They are measured at amortized cost using the effective interest method, less any impairment.
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Available-for-sale financial assets
Available-for-sale financial assets are those non-derivative financial assets that are not classified as loans and receivables, financial assets at fair value through profit or loss, or held-to-maturity financial assets. After initial recognition, available-for-sale financial assets are measured at fair value, with gains or losses recognized within other comprehensive income, except for impairment losses, foreign exchange gains or losses and any changes in fair value arising from revised estimates of future cash flows, which are recognized in profit or loss.
Impairment of financial assets
The group assesses at each balance sheet date whether a financial asset or group of financial assets is impaired.
Loans and receivables
If there is objective evidence that an impairment loss on loans and receivables carried at amortized cost has been incurred, the amount of the loss is measured as the difference between the assets carrying amount and the present value of estimated future cash flows discounted at the financial assets original effective interest rate. The carrying amount of the asset is reduced, with the amount of the loss recognized in the income statement.
Significant estimate or judgement
Judgements are required in assessing the recoverability of overdue trade receivables, such as those in Egypt (see Note 19 for further details), and determining whether a provision against the future recoverability of those receivables is required. Factors considered include the credit rating of the counterparty, the amount and timing of anticipated future payments and any possible actions that can be taken to mitigate the risk of non-payment. See Note 19 for information on overdue receivables.
Financial liabilities
Financial liabilities are classified as financial liabilities at fair value through profit or loss; derivatives designated as hedging instruments in an effective hedge; or as financial liabilities measured at amortized cost, as appropriate. Financial liabilities include trade and other payables, accruals, most items of finance debt and derivative financial instruments. The group determines the classification of its financial liabilities at initial recognition. The measurement of financial liabilities depends on their classification, as follows:
Financial liabilities at fair value through profit or loss
Financial liabilities at fair value through profit or loss are carried on the balance sheet at fair value with gains or losses recognized in the income statement. Derivatives, other than those designated as effective hedging instruments, are classified as held for trading and are included in this category.
Derivatives designated as hedging instruments in an effective hedge
Such derivatives are carried on the balance sheet at fair value. The treatment of gains and losses arising from revaluation is described below in the accounting policy for derivative financial instruments and hedging activities.
Financial liabilities measured at amortized cost
All other financial liabilities are initially recognized at fair value. For interest-bearing loans and borrowings this is the fair value of the proceeds received net of issue costs associated with the borrowing.
After initial recognition, other financial liabilities are subsequently measured at amortized cost using the effective interest method. Amortized cost is calculated by taking into account any issue costs, and any discount or premium on settlement. Gains and losses arising on the repurchase, settlement or cancellation of liabilities are recognized respectively in interest and other income and finance costs.
This category of financial liabilities includes trade and other payables and finance debt.
Derivative financial instruments and hedging activities
The group uses derivative financial instruments to manage certain exposures to fluctuations in foreign currency exchange rates, interest rates and commodity prices as well as for trading purposes. Such derivative financial instruments are initially recognized at fair value on the date on which a derivative contract is entered into and are subsequently remeasured at fair value. Derivatives relating to unquoted equity instruments are carried at cost where it is not possible to reliably measure their fair value subsequent to initial recognition. Derivatives are carried as assets when the fair value is positive and as liabilities when the fair value is negative.
Contracts to buy or sell a non-financial item that can be settled net in cash or another financial instrument, or by exchanging financial instruments as if the contracts were financial instruments, with the exception of contracts that were entered into and continue to be held for the purpose of the receipt or delivery of a non-financial item in accordance with the groups expected purchase, sale or usage requirements, are accounted for as financial instruments. Contracts to buy or sell equity investments, including investments in associates, are also financial instruments. Gains or losses arising from changes in the fair value of derivatives that are not designated as effective hedging instruments are recognized in the income statement.
If, at inception of a contract, the valuation cannot be supported by observable market data, any gain or loss determined by the valuation methodology is not recognized in the income statement but is deferred on the balance sheet and is commonly known as day-one profit or loss. This deferred gain or loss is recognized in the income statement over the life of the contract until substantially all the remaining contract term can be valued using observable market data at which point any remaining deferred gain or loss is recognized in the income statement. Changes in valuation from the initial valuation are recognized immediately through the income statement.
For the purpose of hedge accounting, hedges are classified as:
| Fair value hedges when hedging exposure to changes in the fair value of a recognized asset or liability. |
| Cash flow hedges when hedging exposure to variability in cash flows that is either attributable to a particular risk associated with a recognized asset or liability or a highly probable forecast transaction. |
Hedge relationships are formally designated and documented at inception, together with the risk management objective and strategy for undertaking the hedge. The documentation includes identification of the hedging instrument, the hedged item or transaction, the nature of the risk being hedged, and how the entity will assess the hedging instrument effectiveness in offsetting the exposure to changes in the hedged items fair value or cash flows attributable to the hedged risk. Such hedges are expected at inception to be highly effective in achieving offsetting changes in fair value or cash flows. Hedges meeting the criteria for hedge accounting are accounted for as follows:
Fair value hedges
The change in fair value of a hedging derivative is recognized in profit or loss. The change in the fair value of the hedged item attributable to the risk being hedged is recorded as part of the carrying value of the hedged item and is also recognized in profit or loss.
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The group applies fair value hedge accounting for hedging fixed interest rate risk on borrowings. The gain or loss relating to the effective portion of the interest rate swap is recognized in the income statement within finance costs, offsetting the amortization of the interest on the underlying borrowings.
If the criteria for hedge accounting are no longer met, or if the group revokes the designation, the adjustment to the carrying amount of a hedged item for which the effective interest method is used is amortized to profit or loss over the period to maturity.
Cash flow hedges
For cash flow hedges, the effective portion of the gain or loss on the hedging instrument is recognized within other comprehensive income, while the ineffective portion is recognized in profit or loss. Amounts taken to other comprehensive income are transferred to the income statement when the hedged transaction affects profit or loss. The gain or loss relating to the effective portion of interest rate swaps hedging variable rate borrowings is recognized in the income statement within finance costs.
Where the hedged item is the cost of a non-financial asset or liability, such as a forecast transaction for the purchase of property, plant and equipment, the amounts recognized within other comprehensive income are transferred to the initial carrying amount of the non-financial asset or liability. Where the hedged item is an equity investment, such as an investment in an associate, the amounts recognized in other comprehensive income remain in the separate component of equity until the investment is sold or impaired.
If the hedging instrument expires or is sold, terminated or exercised without replacement or rollover, or if its designation as a hedge is revoked, amounts previously recognized within other comprehensive income remain in equity until the forecast transaction occurs and are transferred to the income statement or to the initial carrying amount of a non-financial asset or liability as above.
Significant estimate or judgement
The decision as to whether to apply hedge accounting or not can have a significant impact on the groups financial statements. Cash flow and fair value hedge accounting is applied to certain of the groups finance debt-related derivatives in the normal course of business. In addition, the financial statements reflect the application of cash flow hedge accounting to certain of the contracts signed in October 2012 for BP to sell its investment in TNK-BP and obtain an additional shareholding in Rosneft, which were accounted for as derivatives under IFRS. We applied all-in-one cash flow hedge accounting to the contracts to acquire shares in Rosneft, resulting in a pre-tax loss of $2,061 million being recognized in other comprehensive income for the year (2012 pre-tax gain of $1,410 million). See Note 26 for further information.
Embedded derivatives
Derivatives embedded in other financial instruments or other host contracts are treated as separate derivatives when their risks and characteristics are not closely related to those of the host contract. Contracts are assessed for embedded derivatives when the group becomes a party to them, including at the date of a business combination. Embedded derivatives are measured at fair value at each balance sheet date. Any gains or losses arising from changes in fair value are taken directly to the income statement.
Fair value measurement
Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants. The group categorizes assets and liabilities measured at fair value into one of three levels depending on the ability to observe inputs employed in their measurement. Level 1 inputs are quoted prices in active markets for identical assets or liabilities. Level 2 inputs are inputs that are observable, either directly or indirectly, other than quoted prices included within level 1 for the asset or liability. Level 3 inputs are unobservable inputs for the asset or liability reflecting significant modifications to observable related market data or BPs assumptions about pricing by market participants.
Significant estimate or judgement
In some cases the fair values of derivatives are estimated using internal models due to the absence of quoted prices or other observable, market-corroborated data. This applies to the groups longer-term derivative contracts and certain options, and to the forward contracts entered into in 2012 to purchase shares in Rosneft, as well as to the majority of the groups natural gas embedded contracts. The groups embedded derivatives arise primarily from long-term UK gas contracts that use pricing formulae not related to gas prices, for example, oil product and power prices. These contracts are valued using models with inputs that include price curves for each of the different products that are built up from active market pricing data and extrapolated to the expiry of the contracts using the maximum available external pricing information. Additionally, where limited data exists for certain products, prices are interpolated using historic and long-term pricing relationships. Price volatility is also an input for the models.
Changes in the key assumptions could have a material impact on the fair value gains and losses on derivatives and embedded derivatives recognized in the income statement. For more information see Note 26.
Offsetting of financial assets and liabilities
Financial assets and liabilities are presented gross in the balance sheet unless both of the following criteria are met: the group currently has a legally enforceable right to set off the recognized amounts; and the group intends to either settle on a net basis or realize the asset and settle the liability simultaneously. If both of the criteria are met, the amounts are set off and presented net.
Provisions, contingencies and reimbursement assets
Provisions are recognized when the group has a present obligation (legal or constructive) as a result of a past event, it is probable that an outflow of resources embodying economic benefits will be required to settle the obligation and a reliable estimate can be made of the amount of the obligation. Where appropriate, the future cash flow estimates are adjusted to reflect risks specific to the liability.
If the effect of the time value of money is material, provisions are determined by discounting the expected future cash flows at a pre-tax risk-free rate that reflects current market assessments of the time value of money. Where discounting is used, the increase in the provision due to the passage of time is recognized within finance costs. Provisions are split between amounts expected to be settled within 12 months of the balance sheet date (current) and amounts expected to be settled later (non-current). Contingent liabilities are possible obligations whose existence will only be confirmed by future events not wholly within the control of the group, or present obligations where it is not probable that an outflow of resources will be required or the amount of the obligation cannot be measured with sufficient reliability.
Contingent liabilities are not recognized in the financial statements but are disclosed unless the possibility of an outflow of economic resources is considered remote.
Where the group makes contributions into a separately administered fund for restoration, environmental or other obligations, which it does not control, and the groups right to the assets in the fund is restricted, the obligation to contribute to the fund is recognized as a liability where it is probable that
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such additional contributions will be made. The group recognizes a reimbursement asset separately, being the lower of the amount of the associated restoration, environmental or other provision and the groups share of the fair value of the net assets of the fund available to contributors.
Significant estimate or judgement
Detailed information on the Gulf of Mexico oil spill, including the financial impacts, is provided in Note 2.
The provision recognized is the best reliable estimate of expenditures required to settle certain present obligations at the end of the reporting period, however there are future expenditures for which it is not possible to measure the obligation reliably. These are not provided for and are disclosed as contingent liabilities. Accounting judgement is required to identify when a provision can be measured reliably, which can be especially challenging when complex litigation activities are ongoing.
In addition, for those provisions which are recognized, there is significant estimation uncertainty about the amounts that will ultimately be paid, especially with regard to amounts payable under the Deepwater Horizon Court Supervised Settlement Program (DHCSSP). A provision is made for these costs when the amount can be measured reliably; this requires an analysis of claims received and processed and consideration of the status of ongoing legal activity.
The provision for penalties under the US Clean Water Act is based on the estimated civil penalty for strict liability. This provision is calculated based on estimates as to the volume of oil spilled, as well as the assumption that BP did not act with gross negligence or engage in wilful misconduct, each of which will eventually be determined by the court on the basis of the trial proceedings.
Decommissioning
Liabilities for decommissioning costs are recognized when the group has an obligation to plug and abandon a well, dismantle and remove a facility or an item of plant and to restore the site on which it is located, and when a reliable estimate of that liability can be made. Where an obligation exists for a new facility or item of plant, such as oil and natural gas production or transportation facilities, this liability will be recognized on construction or installation. Similarly, where an obligation exists for a well, this liability is recognized when it is drilled. An obligation for decommissioning may also crystallize during the period of operation of a well, facility or item of plant through a change in legislation or through a decision to terminate operations; an obligation may also arise in cases where an asset has been sold but the subsequent owner is no longer able to fulfil its decommissioning obligations, for example due to bankruptcy. The amount recognized is the present value of the estimated future expenditure determined in accordance with local conditions and requirements.
A corresponding intangible asset (in the case of an exploration or appraisal well) or item of property, plant and equipment of an amount equivalent to the provision is also recognized. The item of property, plant and equipment is subsequently depreciated as part of the asset.
Other than the unwinding of discount on the provision, any change in the present value of the estimated expenditure is reflected as an adjustment to the provision and the corresponding asset. Such changes include foreign exchange gains and losses arising on the retranslation of the liability into the functional currency of the reporting entity, when it is known that the liability will be settled in a foreign currency.
Environmental expenditures and liabilities
Environmental expenditures that relate to future revenues are capitalized. Expenditures that relate to an existing condition caused by past operations that do not contribute to future earnings are expensed.
Liabilities for environmental costs are recognized when a clean-up is probable and the associated costs can be reliably estimated. Generally, the timing of recognition of these provisions coincides with the commitment to a formal plan of action or, if earlier, on divestment or on closure of inactive sites.
The amount recognized is the best estimate of the expenditure required. Where the liability will not be settled for a number of years, the amount recognized is the present value of the estimated future expenditure.
Significant estimate or judgement
The group holds provisions for the future decommissioning of oil and natural gas production facilities and pipelines at the end of their economic lives. The largest decommissioning obligations facing BP relate to the plugging and abandonment of wells and the removal and disposal of oil and natural gas platforms and pipelines around the world. Most of these decommissioning events are many years in the future and the precise requirements that will have to be met when the removal event actually occurs are uncertain. Decommissioning technologies and costs are constantly changing, as well as political, environmental, safety and public expectations. If oil and natural gas production facilities and pipelines are sold to third parties and the subsequent owner is unable to meet their decommissioning obligations, judgement must be used to determine whether BP is then responsible for decommissioning, and if so the extent of that responsibility. Consequently, the timing and amounts of future cash flows are subject to significant uncertainty. Any changes in the expected future costs are reflected in both the provision and the asset.
Decommissioning provisions associated with downstream and petrochemicals facilities are generally not recognized, as such potential obligations cannot be measured, given their indeterminate settlement dates. The group performs periodic reviews of its downstream and petrochemicals long-lived assets for any changes in facts and circumstances that might require the recognition of a decommissioning provision.
The provision for environmental liabilities is estimated based on current legal and constructive requirements, technology, price levels and expected plans for remediation. Actual costs and cash outflows can differ from estimates because of changes in laws and regulations, public expectations, prices, discovery and analysis of site conditions and changes in clean-up technology.
Other provisions and liabilities are recognized in the period when it becomes probable that there will be a future outflow of funds resulting from past operations or events and the amount of cash outflow can be reliably estimated. The timing of recognition and quantification of the liability require the application of judgement to existing facts and circumstances, which can be subject to change. Since the actual cash outflows can take place many years in the future, the carrying amounts of provisions and liabilities are reviewed regularly and adjusted to take account of changing facts and circumstances.
The timing and amount of future expenditures are reviewed annually, together with the interest rate used in discounting the cash flows. The interest rate used to determine the balance sheet obligation at the end of 2013 was a real rate of 1.0% (2012 0.5%), which was based on long-dated government bonds.
Provisions and contingent liabilities in relation to the Gulf of Mexico oil spill are discussed in Note 2. Information about the groups other provisions is provided in Note 29. As further described in Note 35, the group is subject to claims and actions. The facts and circumstances relating to particular cases are evaluated regularly in determining whether it is probable that there will be a future outflow of funds and, once established, whether a provision relating to a specific litigation should be established or revised. Accordingly, significant management judgement relating to provisions and contingent liabilities is required, since the outcome of litigation is difficult to predict.
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Employee benefits
Wages, salaries, bonuses, social security contributions, paid annual leave and sick leave are accrued in the period in which the associated services are rendered by employees of the group. Deferred bonus arrangements that have a vesting date more than 12 months after the period end are valued on an actuarial basis using the projected unit credit method and amortized on a straight-line basis over the service period until the award vests. The accounting policies for share-based payments and for pensions and other post-retirement benefits are described below.
Share-based payments
Equity-settled transactions
The cost of equity-settled transactions with employees is measured by reference to the fair value at the date at which equity instruments are granted and is recognized as an expense over the vesting period, which ends on the date on which the employees become fully entitled to the award. Fair value is determined by using an appropriate valuation model. In valuing equity-settled transactions, no account is taken of any vesting conditions, other than conditions linked to the price of the shares of the company (market conditions). Non-vesting conditions, such as the condition that employees contribute to a savings-related plan, are taken into account in the grant-date fair value, and failure to meet a non-vesting condition, where this is within the control of the employee is treated as a cancellation and expensed.
Cash-settled transactions
The cost of cash-settled transactions is measured at fair value at each balance sheet date and recognized as an expense over the vesting period, with a corresponding liability for the cumulative expense recognized on the balance sheet.
Pensions and other post-retirement benefits
The cost of providing benefits under the defined benefit plans is determined separately for each plan using the projected unit credit method, which attributes entitlement to benefits to the current period (to determine current service cost) and to the current and prior periods (to determine the present value of the defined benefit obligation). Past service costs, resulting from either a plan amendment or a curtailment (a reduction in future obligations as a result of a material reduction in the plan membership), are recognized immediately when the company becomes committed to a change.
Net interest expense relating to pensions and other post-retirement benefits represents the net change in present value of plan obligations and the value of plan assets resulting from the passage of time, and is determined by applying the discount rate to the present value of the benefit obligation at the start of the year, and to the fair value of plan assets at the start of the year, taking into account expected changes in the obligation or plan assets during the year. Net interest expense relating to pensions and other post-retirement benefits is recognized in the income statement.
Remeasurements of the net defined benefit liability or asset, comprising actuarial gains and losses, and the return on plan assets (excluding amounts included in net interest described above) are recognized within other comprehensive income in the period in which they occur.
The defined benefit pension plan surplus or deficit in the balance sheet comprises the total for each plan of the present value of the defined benefit obligation (using a discount rate based on high quality corporate bonds), less the fair value of plan assets out of which the obligations are to be settled directly. Fair value is based on market price information and, in the case of quoted securities, is the published bid price.
Contributions to defined contribution plans are recognized in the income statement in the period in which they become payable.
Significant estimate or judgement
Accounting for pensions and other post-retirement benefits involves judgement about uncertain events, including estimated retirement dates, salary levels at retirement, mortality rates, determination of discount rates for measuring plan obligations and net interest expense, assumptions for inflation rates, US healthcare cost trend rates and rates of utilization of healthcare services by US retirees.
These assumptions are based on the environment in each country. The assumptions used may vary from year to year, which would affect future net income and net assets. Any differences between these assumptions and the actual outcome also affect future net income and net assets.
Pension and other post-retirement benefit assumptions are reviewed by management at the end of each year. These assumptions are used to determine the projected benefit obligation at the year end and hence the surpluses and deficits recorded on the groups balance sheet, and pension and other post-retirement benefit expense for the following year. In 2013, we adopted the revised version of IAS 19 Employee Benefits (see below for further information), and we now apply the same rate of return on plan assets as we use to discount our pension liabilities. The impact of this change on key financial statement line items is shown at the end of this note.
The pension and other post-retirement benefit assumptions at 31 December 2013, 2012 and 2011 are provided in Note 30.
The discount rate, inflation rate and the US healthcare cost trend rate have a significant effect on the amounts reported. A sensitivity analysis of the impact of changes in these assumptions on the benefit expense and obligation is provided in Note 30.
In addition to the financial assumptions, we regularly review the demographic and mortality assumptions. Mortality assumptions reflect best practice in the countries in which we provide pensions and have been chosen with regard to the latest available published tables adjusted where appropriate to reflect the experience of the group and an extrapolation of past longevity improvements into the future. A sensitivity analysis of the impact of changes in the mortality assumptions on the benefit expense and obligation is provided in Note 30.
Income taxes
Income tax expense represents the sum of current tax and deferred tax. Interest and penalties relating to income tax are also included in the income tax expense.
Income tax is recognized in the income statement, except to the extent that it relates to items recognized in other comprehensive income or directly in equity, in which case the related tax is recognized in other comprehensive income or directly in equity.
Current tax is based on the taxable profit for the period. Taxable profit differs from net profit as reported in the income statement because it is determined in accordance with the rules established by the applicable taxation authorities. It therefore excludes items of income or expense that are taxable or deductible in other periods as well as items that are never taxable or deductible. The groups liability for current tax is calculated using tax rates and laws that have been enacted or substantively enacted by the balance sheet date.
Deferred tax is provided, using the liability method, on all temporary differences at the balance sheet date between the tax bases of assets and liabilities and their carrying amounts for financial reporting purposes.
BP Annual Report and Form 20-F 2013 | 135 |
1. Significant accounting policies, judgements, estimates and assumptions continued
Deferred tax liabilities are recognized for all taxable temporary differences except:
| Where the deferred tax liability arises on the initial recognition of goodwill; or |
| Where the deferred tax liability arises on the initial recognition of an asset or liability in a transaction that is not a business combination and, at the time of the transaction, affects neither accounting profit nor taxable profit or loss; or |
| In respect of taxable temporary differences associated with investments in subsidiaries, joint ventures and associates, where the group is able to control the timing of the reversal of the temporary differences and it is probable that the temporary differences will not reverse in the foreseeable future. |
Deferred tax assets are recognized for all deductible temporary differences, carry-forward of unused tax credits and unused tax losses, to the extent that it is probable that taxable profit will be available against which the deductible temporary differences and the carry-forward of unused tax credits and unused tax losses can be utilized:
| Except where the deferred tax asset relating to the deductible temporary difference arises from the initial recognition of an asset or liability in a transaction that is not a business combination and, at the time of the transaction, affects neither accounting profit nor taxable profit or loss. |
| In respect of deductible temporary differences associated with investments in subsidiaries, joint ventures and associates, deferred tax assets are recognized only to the extent that it is probable that the temporary differences will reverse in the foreseeable future and taxable profit will be available against which the temporary differences can be utilized. |
The carrying amount of deferred tax assets is reviewed at each balance sheet date and reduced to the extent that it is no longer probable that sufficient taxable profit will be available to allow all or part of the deferred tax asset to be utilized.
Deferred tax assets and liabilities are measured at the tax rates that are expected to apply in the period when the asset is realized or the liability is settled, based on tax rates (and tax laws) that have been enacted or substantively enacted at the balance sheet date. Deferred tax assets and liabilities are not discounted.
Deferred tax assets and liabilities are offset only when there is a legally enforceable right to set off current tax assets against current tax liabilities and when the deferred tax assets and liabilities relate to income taxes levied by the same taxation authority on either the same taxable entity or different taxable entities where there is an intention to settle the current tax assets and liabilities on a net basis or to realize the assets and settle the liabilities simultaneously.
Significant estimate or judgement
The computation of the groups income tax expense and liability involves the interpretation of applicable tax laws and regulations in many jurisdictions throughout the world. The resolution of tax positions taken by the group, through negotiations with relevant tax authorities or through litigation, can take several years to complete and in some cases it is difficult to predict the ultimate outcome. Therefore, judgement is required to determine provisions for income taxes.
In addition, the group has carry-forward tax losses and tax credits in certain taxing jurisdictions that are available to offset against future taxable profit. However, deferred tax assets are recognized only to the extent that it is probable that taxable profit will be available against which the unused tax losses or tax credits can be utilized. Management judgement is exercised in assessing whether this is the case.
To the extent that actual outcomes differ from managements estimates, income tax charges or credits, and changes in current and deferred tax assets or liabilities, may arise in future periods. For more information see Note 35.
Judgement is also required when determining whether a particular tax is an income tax or another type of tax (for example a production tax). Accounting for deferred tax is applied to income taxes as described above, but is not applied to other types of taxes; rather such taxes are recognized in the income statement on an appropriate basis.
Customs duties and sales taxes
Customs duties and sales taxes which are passed on to customers are excluded from revenues and expenses. Assets and liabilities are recognized net of the amount of customs duties or sales tax except:
| Where the customs duty or sales tax incurred on a purchase of goods and services is not recoverable from the taxation authority, in which case the customs duty or sales tax is recognized as part of the cost of acquisition of the asset. |
| Receivables and payables are stated with the amount of customs duty or sales tax included. |
The net amount of sales tax recoverable from, or payable to, the taxation authority is included within receivables or payables in the balance sheet.
Own equity instruments
The groups holdings in its own equity instruments, including ordinary shares held by Employee Share Ownership Plans (ESOPs), are classified as treasury shares, or own shares for the ESOPs, and are shown as deductions from shareholders equity at cost. Consideration received for the sale of such shares is also recognized in equity, with any difference between the proceeds from sale and the original cost being taken to the profit and loss account reserve. No gain or loss is recognized in the income statement on the purchase, sale, issue or cancellation of equity shares. Shares repurchased under the share buy-back programme which are immediately cancelled are not shown as treasury shares or own shares, but are shown as a deduction from the profit and loss reserve in the group statement of changes in equity.
Revenue
Revenue arising from the sale of goods is recognized when the significant risks and rewards of ownership have passed to the buyer, which is typically at the point that title passes, and the revenue can be reliably measured.
Revenue is measured at the fair value of the consideration received or receivable and represents amounts receivable for goods provided in the normal course of business, net of discounts, customs duties and sales taxes.
Physical exchanges are reported net, as are sales and purchases made with a common counterparty, as part of an arrangement similar to a physical exchange. Similarly, where the group acts as agent on behalf of a third party to procure or market energy commodities, any associated fee income is recognized but no purchase or sale is recorded. Additionally, where forward sale and purchase contracts for oil, natural gas or power have been determined to be for trading purposes, the associated sales and purchases are reported net within sales and other operating revenues whether or not physical delivery has occurred.
136 | BP Annual Report and Form 20-F 2013 |
1. Significant accounting policies, judgements, estimates and assumptions continued
Generally, revenues from the production of oil and natural gas properties in which the group has an interest with joint operation partners are recognized on the basis of the groups working interest in those properties (the entitlement method). Differences between the production sold and the groups share of production are not significant.
Interest income is recognized as the interest accrues (using the effective interest rate that is the rate that exactly discounts estimated future cash receipts through the expected life of the financial instrument to the net carrying amount of the financial asset).
Dividend income from investments is recognized when the shareholders right to receive the payment is established.
Research
Research costs are expensed as incurred.
Finance costs
Finance costs directly attributable to the acquisition, construction or production of qualifying assets, which are assets that necessarily take a substantial period of time to get ready for their intended use, are added to the cost of those assets until such time as the assets are substantially ready for their intended use. All other finance costs are recognized in the income statement in the period in which they are incurred.
Impact of new International Financial Reporting Standards
Adopted for 2013
BP adopted several new and amended standards issued by the IASB with effect from 1 January 2013. Of these the following two standards have a significant effect on the groups consolidated financial statements:
IFRS 11 Joint Arrangements
In May 2011, the IASB issued IFRS 11 Joint Arrangements, one of a suite of standards relating to interests in other entities and related disclosures. IFRS 11 establishes a principle that applies to the accounting for all joint arrangements, whereby parties to the arrangement account for their underlying contractual rights and obligations relating to the joint arrangement. IFRS 11 identifies two types of joint arrangements. A joint venture is a joint arrangement whereby the parties that have joint control of the arrangement have rights to the net assets of the arrangement. A joint operation is a joint arrangement whereby the parties that have joint control of the arrangement have rights to the assets, and obligations for the liabilities, relating to the arrangement. Investments in joint ventures are accounted for using the equity method. Investments in joint operations are accounted for by recognizing the groups assets, liabilities, revenue and expenses relating to the joint operation.
The main impact of IFRS 11 is that certain of the groups former jointly controlled entities, which were equity accounted, now fall under the definition of a joint operation under IFRS 11. Whilst the effect of the new requirements on the groups reported income and net assets is not material, the change does impact certain of the component lines of the groups financial statements, as shown in the table below. We have derecognized approximately $7 billion of investments and we now recognize the groups assets, liabilities, revenue and expenses relating to these arrangements. BPs share of oil and natural gas reserves associated with former jointly controlled entities that were previously equity-accounted, and are now classified as joint operations, have been reclassified from equity-accounted entities to subsidiaries in the Supplementary information on oil and natural gas.
Amendments to IAS 19 Employee Benefits
In June 2011, the IASB issued an amended version of IAS 19 Employee Benefits, which brings in various changes relating to the recognition and measurement of post-retirement defined benefit expense and termination benefits, and to the disclosures for all employee benefits. The main impact for BP is that the expense for defined benefit pension and other post-retirement benefit plans now includes a net interest income or expense, which is calculated by taking the discount rate used for measuring the obligation and applying that to the net defined benefit asset or liability. This means that the expected return on assets credited to profit or loss (previously calculated based on the expected long-term return on pension assets) is now based on a lower corporate bond rate, the same rate that is used to discount the pension liability. The impact was to decrease profit before tax by $1,001 million for the year ended 31 December 2013 (2012 $763 million, 2011 $659 million) with other comprehensive income being increased by the same amount. There was no impact on the balance sheet at 31 December or on cash flows.
Adjustments made to certain selected financial statement line items
The following table sets out the adjustments made to certain selected financial statement line items of the previously reported comparative amounts as a result of the adoption of the amended IAS 19 Employee Benefits and the new standard IFRS 11 Joint Arrangements.
$ million (except per share amounts) | ||||||||||||||||||||||||||||||||||
Selected lines only | As reported | IFRS 11 | IAS 19 | 2012 As restated |
As reported | IFRS 11 | IAS 19 | 2011 As restateda |
||||||||||||||||||||||||||
Income statement |
||||||||||||||||||||||||||||||||||
Earnings from joint ventures after interest and tax |
744 | (484 | ) | | 260 | 1,304 | (537 | ) | | 767 | ||||||||||||||||||||||||
Net finance income (expense) relating to pensions and other post-retirement benefits |
201 | (4 | ) | (763 | ) | (566 | ) | 263 | (4 | ) | (659 | ) | (400 | ) | ||||||||||||||||||||
Profit for the year |
11,816 | 22 | (587 | ) | 11,251 | 26,097 | 2 | (490 | ) | 25,609 | ||||||||||||||||||||||||
Earnings per share cents |
||||||||||||||||||||||||||||||||||
Profit for the year attributable to BP shareholders |
||||||||||||||||||||||||||||||||||
Basic |
60.86 | 0.12 | (3.09 | ) | 57.89 | 135.93 | 0.01 | (2.59 | ) | 133.35 | ||||||||||||||||||||||||
Diluted |
60.45 | 0.11 | (3.06 | ) | 57.50 | 134.29 | 0.01 | (2.56 | ) | 131.74 | ||||||||||||||||||||||||
Balance sheet |
||||||||||||||||||||||||||||||||||
Property, plant and equipment |
120,448 | 4,883 | | 125,331 | 119,214 | 4,217 | | 123,431 | ||||||||||||||||||||||||||
Intangible assets |
24,041 | 591 | | 24,632 | 21,102 | 551 | | 21,653 | ||||||||||||||||||||||||||
Investments in joint ventures |
15,724 | (7,110 | ) | | 8,614 | 15,518 | (7,215 | ) | | 8,303 | ||||||||||||||||||||||||
Net assets |
119,620 | 132 | | 119,752 | 112,482 | 103 | | 112,585 | ||||||||||||||||||||||||||
Cash flow statement |
||||||||||||||||||||||||||||||||||
Profit (loss) before taxation |
18,809 | 85 | (763 | ) | 18,131 | 38,834 | 53 | (659 | ) | 38,228 | ||||||||||||||||||||||||
Net cash provided by operating activities |
20,397 | 82 | | 20,479 | 22,154 | 64 | | 22,218 | ||||||||||||||||||||||||||
Net cash used in investing activities |
(12,962 | ) | (113 | ) | | (13,075 | ) | (26,633 | ) | (120 | ) | | (26,753 | ) | ||||||||||||||||||||
Increase (decrease) in cash and cash equivalents |
5,481 | (23 | ) | | 5,458 | (4,489 | ) | (62 | ) | | (4,551 | ) |
a | Balance sheet amounts presented are as at 1 January 2012. |
BP Annual Report and Form 20-F 2013 | 137 |
1. Significant accounting policies, judgements, estimates and assumptions continued
Detailed restated financial information for 2012 and 2011 is shown in BP Financial and Operating Information 2008-2012 available on bp.com/investors.
Other standards
A number of other new or amended standards have been adopted by the group with effect from 1 January 2013 but do not have a significant impact on the financial statements. These include:
IFRS 10 Consolidated Financial Statements introduces a single consolidation model that identifies control as the basis for consolidation. The new model applies to all types of entities, including structured entities. Under the new model, an investor controls an investee when it is exposed, or has rights, to variable returns from its involvement with the investee and has the ability to affect those returns through its power over the investee. There was no effect on the groups reported income or net assets as a result of the adoption of IFRS 10.
IFRS 12 Disclosures of Interests in Other Entities combines all the disclosure requirements for an entitys interests in subsidiaries, joint arrangements, associates and structured entities into one comprehensive disclosure standard. There was no effect on the groups reported income or net assets as a result of the adoption of IFRS 12. The disclosures required by the standard are included in this report.
In May 2011, the IASB issued a new standard, IFRS 13 Fair Value Measurement. The new standard defines fair value, sets out a framework for measuring fair value and contains the required disclosures about fair value measurements. IFRS 13 does not require fair value measurements in addition to those already required or permitted by other standards, rather it prescribes how fair value should be measured if another standard requires it. Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date i.e. it is an exit price. There was no significant impact on the groups reported income or net assets as a result of the adoption of IFRS 13. The disclosures required by the new standard are included in this report.
In December 2011, the IASB issued an amendment to IFRS 7 Disclosures Offsetting Financial Assets and Financial Liabilities. This amendment introduces new disclosure requirements about the effects of offsetting financial assets and financial liabilities and related arrangements on an entitys balance sheet. The new disclosures are included in this report.
In June 2011, the IASB issued amendments to IAS 1 Presentation of Financial Statements on the presentation of other comprehensive income (OCI). The amendments require that those items of OCI that might be reclassified to profit or loss at a future date be presented separately from those items that will never be reclassified to profit or loss. The adoption of the amended standard has a presentational impact on the groups statement of comprehensive income, with no effect on the reported income, total comprehensive income, or net assets of the group. The presentation required by the amended standard is included in this report.
In May 2013, the IASB issued an amendment to IAS 36 Impairment of Assets in relation to the disclosure of recoverable amounts for non-financial assets. The amendment addressed certain unintended consequences arising from consequential amendments made to IAS 36 when IFRS 13 was issued. Although the mandatory effective date for application of the amendment is for annual periods beginning on or after 1 January 2014, the group has early-adopted it in these financial statements.
In addition, a number of other standards and interpretations were adopted in the year which had no significant impact on the groups reported income and net assets.
Not yet adopted
The following pronouncements from the IASB will become effective for future financial reporting periods and have not yet been adopted by the group.
As part of the IASBs project to replace IAS 39 Financial Instruments: Recognition and Measurement, in November 2009 the IASB issued the first phase of IFRS 9 Financial Instruments, dealing with the classification and measurement of financial assets. In October 2010, the IASB updated IFRS 9 by incorporating the requirements for the accounting for financial liabilities and in November 2013 the IASB published revised guidance for hedge accounting. The remaining phase of IFRS 9, dealing with impairment, and further changes to the classification and measurement requirements, are still to be completed. In November 2013, the IASB also removed the effective date from IFRS 9 and will decide on an effective date when the entire IFRS 9 project is closer to completion. BP has not yet decided the date of adoption for the group and has not yet completed its evaluation of the effect of adoption. The EU has not yet adopted IFRS 9.
In December 2011, the IASB issued an amendment to IAS 32 Offsetting Financial Assets and Financial Liabilities. This amendment clarifies the presentation requirements in relation to offsetting financial assets and financial liabilities on an entitys balance sheet. The amendment to IAS 32 is effective for annual periods beginning on or after 1 January 2014. BPs evaluation of the effect of adoption of the amendment to IAS 32 is substantially complete, and is not expected to result in any significant changes to the offsetting of financial assets and liabilities on the groups balance sheet.
There are no other standards and interpretations in issue but not yet adopted that the directors anticipate will have a material effect on the reported income or net assets of the group.
138 | BP Annual Report and Form 20-F 2013 |
2. Significant event Gulf of Mexico oil spill
As a consequence of the Gulf of Mexico oil spill in April 2010, BP continues to incur costs and has also recognized liabilities for certain future costs. Liabilities of uncertain timing or amount, for which no provision has been made, have been disclosed as contingent liabilities.
The cumulative pre-tax income statement charge since the incident amounts to $42.7 billion. For more information on the types of expenditure included in the cumulative income statement charge, see Impact upon the group income statement below. The cumulative income statement charge does not include amounts for obligations that BP considers are not possible, at this time, to measure reliably. For further information, including developments in relation to the interpretation of business economic loss claims under the Plaintiffs Steering Committee (PSC) settlement, see Provisions and contingent liabilities below.
The total amounts that will ultimately be paid by BP in relation to all the obligations relating to the incident are subject to significant uncertainty and the ultimate exposure and cost to BP will be dependent on many factors, as discussed under Provisions and contingent liabilities below, including in relation to any new information or future developments. These could have a material impact on our consolidated financial position, results of operations and cash flows. The risks associated with the incident could also heighten the impact of the other risks to which the group is exposed as further described under Risk factors on page 51 and Legal proceedings on page 257.
The impacts of the Gulf of Mexico oil spill on the income statement, balance sheet and cash flow statement of the group are included within the relevant line items in those statements and are shown in the table below.
$ million | ||||||||||||||||||||||||||
2013 | 2012 | 2011 | ||||||||||||||||||||||||
Total | Of which: amount related to the trust fund |
Total | Of which: amount related to the trust fund |
Total | Of which: amount related to the trust |
|||||||||||||||||||||
Income statement |
||||||||||||||||||||||||||
Production and manufacturing expenses |
430 | (1,542 | ) | 4,995 | (1,191 | ) | (3,800 | ) | (3,995 | ) | ||||||||||||||||
Profit (loss) before interest and taxation |
(430 | ) | 1,542 | (4,995 | ) | 1,191 | 3,800 | 3,995 | ||||||||||||||||||
Finance costs |
39 | | 19 | 12 | 58 | 52 | ||||||||||||||||||||
Profit (loss) before taxation |
(469 | ) | 1,542 | (5,014 | ) | 1,179 | 3,742 | 3,943 | ||||||||||||||||||
Less: Taxation |
73 | | 94 | | (1,387 | ) | | |||||||||||||||||||
Profit (loss) for the period |
(396 | ) | 1,542 | (4,920 | ) | 1,179 | 2,355 | 3,943 | ||||||||||||||||||
Balance sheet |
||||||||||||||||||||||||||
Current assets |
||||||||||||||||||||||||||
Trade and other receivables |
2,457 | 2,457 | 4,239 | 4,178 | ||||||||||||||||||||||
Current liabilities |
||||||||||||||||||||||||||
Trade and other payables |
(1,030 | ) | (1 | ) | (522 | ) | (22 | ) | ||||||||||||||||||
Provisions |
(2,951 | ) | | (5,449 | ) | | ||||||||||||||||||||
Net current assets (liabilities) |
(1,524 | ) | 2,456 | (1,732 | ) | 4,156 | ||||||||||||||||||||
Non-current assets |
||||||||||||||||||||||||||
Other receivables |
2,442 | 2,442 | 2,264 | 2,264 | ||||||||||||||||||||||
Non-current liabilities |
||||||||||||||||||||||||||
Other payables |
(2,986 | ) | | (175 | ) | | ||||||||||||||||||||
Provisions |
(6,395 | ) | | (9,751 | ) | | ||||||||||||||||||||
Deferred tax |
2,748 | | 4,002 | | ||||||||||||||||||||||
Net non-current assets (liabilities) |
(4,191 | ) | 2,442 | (3,660 | ) | 2,264 | ||||||||||||||||||||
Net assets (liabilities) |
(5,715 | ) | 4,898 | (5,392 | ) | 6,420 | ||||||||||||||||||||
Cash flow statement |
||||||||||||||||||||||||||
Profit (loss) before taxation |
(469 | ) | 1,542 | (5,014 | ) | 1,179 | 3,742 | 3,943 | ||||||||||||||||||
Finance costs |
39 | | 19 | 12 | 58 | 52 | ||||||||||||||||||||
Net charge for provisions, less payments |
1,129 | | 4,834 | | 2,699 | | ||||||||||||||||||||
(Increase) decrease in other current and non-current assets |
(1,481 | ) | (1,542 | ) | (998 | ) | (1,191 | ) | (4,292 | ) | (4,038 | ) | ||||||||||||||
Increase (decrease) in other current and non-current liabilities |
(618 | ) | | (5,090 | ) | (4,860 | ) | (11,113 | ) | (10,097 | ) | |||||||||||||||
Pre-tax cash flows |
(1,400 | ) | | (6,249 | ) | (4,860 | ) | (8,906 | ) | (10,140 | ) |
The impact on net cash provided by operating activities, on a post-tax basis, amounted to an outflow of $73 million (2012 outflow of $2,382 million and 2011 outflow of $6,813 million).
Trust fund
BP established the Deepwater Horizon Oil Spill Trust (the Trust) in 2010, to be funded in the amount of $20 billion, to satisfy legitimate individual and business claims, state and local government claims resolved by BP, final judgments and settlements, state and local response costs, and natural resource damages and related costs. The Trust is available to fund the qualified settlement funds (QSFs) established under the terms of the settlement agreements (comprising the Economic and Property Damages (EPD) Settlement Agreement and the Medical Benefits Class Action Settlement) with the PSC administered through the Deepwater Horizon Court Supervised Settlement Program (DHCSSP), and the separate BP claims programme see Provisions and contingent liabilities below for further information. Fines and penalties are not covered by the trust fund.
The funding of the Trust was completed in the fourth quarter of 2012. The obligation to fund the $20-billion trust fund, adjusted to take account of the time value of money, was recognized in full in 2010 and charged to the income statement.
BPs rights and obligations in relation to the $20-billion trust fund are accounted for in accordance with IFRIC 5 Rights to Interests Arising from Decommissioning, Restoration and Environmental Rehabilitation Funds. An asset has been recognized representing BPs right to receive reimbursement from the trust fund. This is the portion of the estimated future expenditure provided for that will be settled by payments from the trust fund. We use the term reimbursement asset to describe this asset. BP will not actually receive any reimbursements from the trust fund, instead payments will be made directly from the trust fund, and BP will be released from its corresponding obligation. The reimbursement asset is recorded within other receivables on the balance sheet apportioned between current and non-current elements. The table below shows movements in the
BP Annual Report and Form 20-F 2013 | 139 |
2. Significant event Gulf of Mexico oil spill continued
reimbursement asset during the period to 31 December 2013. The net increase in the provision of $1,542 million for the full year relates principally to business economic loss claims processed by the DHCSSP subsequent to finalization of the BP Annual Report and Form 20-F 2012 that have been paid as well as increases in the provision for claims administration costs. The amount of the reimbursement asset at 31 December 2013 is equal to the amount of provisions and payables recognized at that date that will be covered by the trust fund see below.
$ million | ||||||||||||||
2013 | 2012 | Cumulative since the incident |
||||||||||||
At 1 January |
6,442 | 9,875 | | |||||||||||
Increase in provision for items covered by the trust fund |
1,921 | 1,985 | 20,511 | |||||||||||
Derecognition of provision for items that cannot be reliably estimated |
(379 | ) | (794 | ) | (1,173 | ) | ||||||||
Amounts paid directly by the trust fund |
(3,085 | ) | (4,624 | ) | (14,439 | ) | ||||||||
At 31 December |
4,899 | 6,442 | 4,899 | |||||||||||
Of which current |
2,457 | 4,178 | 2,457 | |||||||||||
non-current |
2,442 | 2,264 | 2,442 |
Any increases in estimated future expenditure that will be covered by the trust fund (up to an aggregate of $20 billion) have no net income statement effect as a reimbursement asset is also recognized, as described above. As at 31 December 2013, the cumulative charges, and the associated reimbursement asset recognized, amounted to $19,338 million. Thus, a further $662 million could be charged in subsequent periods for items covered by the trust fund with no net impact on the income statement. Additional liabilities in excess of this amount regarding claims under the Oil Pollution Act of 1990 (OPA 90), claims that are currently administered by the DHCSSP, or otherwise, including the various claims described in Legal proceedings on page 257, would be expensed to the income statement. Information on those items that currently cannot be estimated reliably is provided under Provisions and contingent liabilities below.
Under the terms of the EPD Settlement Agreement with the PSC, several QSFs were established in 2012. These QSFs each relate to specific elements of the agreement, have been and will continue to be funded through payments from the Trust, and are available to make payments to claimants in accordance with those elements of the agreement.
As at 31 December 2013, the aggregate cash balances in the Trust and the QSFs amounted to $6.7 billion, including $1.2 billion remaining in the seafood compensation fund which has yet to be distributed and $0.9 billion held for natural resource damage early restoration. Should the cash balances in the trust fund not be sufficient, payments in respect of legitimate claims and other costs will be made directly by BP.
The EPD Settlement Agreement with the PSC provides for a court-supervised settlement programme which commenced operation on 4 June 2012. See Provisions below for further information on the current status of the EPD Settlement Agreement. In addition, a separate BP claims programme began processing claims from claimants not in the Economic and Property Damages class as determined by the EPD Settlement Agreement or who have requested to opt out of that settlement. Payments made to claimants through the BP claims programme are paid directly from the Trust. A separate claims administrator has been appointed to pay medical claims and to implement other aspects of the Medical Benefits Class Action Settlement. For further information on the PSC settlements, see Legal proceedings on page 257.
Other payables
BP reached an agreement with the US government in 2012, which was approved by the court in 2013, to resolve all federal criminal claims arising from the incident. Under the agreement, BP will pay $4 billion over a period of five years. At 31 December 2013, the remaining payable was $3,525 million, of which $565 million falls due in 2014.
BP also reached a settlement with the US Securities and Exchange Commission (SEC) in 2012, resolving the SECs Gulf of Mexico oil spill-related civil claims. As part of the settlement, BP agreed to a civil penalty of $525 million. At 31 December 2013 the remaining payable, due in 2014, was $175 million plus accrued interest.
The amounts described above were reclassified from provisions to other payables upon court approval of the agreement with the US government and settlement with the SEC.
Provisions and contingent liabilities
Provisions
BP has recorded provisions relating to the Gulf of Mexico oil spill in relation to environmental expenditure, spill response costs, litigation and claims, and Clean Water Act penalties that can be measured reliably at this time.
Movements in each class of provision during the year and cumulatively since the incident are presented in the tables below.
$ million | ||||||||||||||||||||||
2013 | ||||||||||||||||||||||
Environmental | Spill response |
Litigation and claims |
Clean Water Act |
Total | ||||||||||||||||||
At 1 January |
1,862 | 345 | 9,483 | 3,510 | 15,200 | |||||||||||||||||
Increase (decrease) in provision items not covered by the trust fund |
(24 | ) | (66 | ) | 408 | | 318 | |||||||||||||||
items covered by the trust fund |
24 | | 1,897 | | 1,921 | |||||||||||||||||
Derecognition of provision for items that cannot be reliably estimateda |
| | (379 | ) | | (379 | ) | |||||||||||||||
Reclassification of amounts between categories of provision |
47 | (47 | ) | | | | ||||||||||||||||
Unwinding of discount |
1 | | | | 1 | |||||||||||||||||
Change in discount rate |
(5 | ) | | | | (5 | ) | |||||||||||||||
Reclassified to other payables items covered by the trust fund |
| | (84 | ) | | (84 | ) | |||||||||||||||
items not covered by the trust fund |
| | (3,849 | ) | | (3,849 | ) | |||||||||||||||
Utilization paid by BP |
(60 | ) | (143 | ) | (523 | ) | | (726 | ) | |||||||||||||
paid by the trust fund |
(255 | ) | | (2,796 | ) | | (3,051 | ) | ||||||||||||||
At 31 December |
1,590 | 89 | 4,157 | 3,510 | 9,346 | |||||||||||||||||
Of which current |
389 | 84 | 2,478 | | 2,951 | |||||||||||||||||
non-current |
1,201 | 5 | 1,679 | 3,510 | 6,395 | |||||||||||||||||
Of which payable from the trust fund |
1,253 | | 3,595 | | 4,848 |
a | Relates to items covered by the trust fund. |
140 | BP Annual Report and Form 20-F 2013 |
2. Significant event Gulf of Mexico oil spill continued
$ million | ||||||||||||||||||||||
Cumulative since the incident |
||||||||||||||||||||||
Environmental | Spill response |
Litigation and claims |
Clean Water Act |
Total | ||||||||||||||||||
Increase in provision items not covered by the trust fund |
544 | 11,456 | 8,529 | 3,510 | 24,039 | |||||||||||||||||
items covered by the trust fund |
2,353 | 56 | 18,102 | | 20,511 | |||||||||||||||||
Derecognition of provision for items that cannot be reliably estimateda |
| | (1,173 | ) | | (1,173 | ) | |||||||||||||||
Reclassification of amounts between categories of provision |
47 | (47 | ) | | | | ||||||||||||||||
Unwinding of discount |
12 | | 6 | | 18 | |||||||||||||||||
Change in discount rate |
17 | | | | 17 | |||||||||||||||||
Reclassified to other payables items covered by the trust fund |
| | (84 | ) | | (84 | ) | |||||||||||||||
items not covered by the trust fund |
| | (4,199 | ) | | (4,199 | ) | |||||||||||||||
Utilization paid by BP |
(237 | ) | (11,367 | ) | (3,773 | ) | | (15,377 | ) | |||||||||||||
paid by the trust fund |
(1,146 | ) | (9 | ) | (13,251 | ) | | (14,406 | ) | |||||||||||||
At 31 December 2013 |
1,590 | 89 | 4,157 | 3,510 | 9,346 |
a | Relates to items covered by the trust fund. |
Environmental
The environmental provision includes $320 million for BPs commitment to fund the Gulf of Mexico Research Initiative, which is a 10-year research programme to study the impact of the incident on the marine and shoreline environment of the Gulf of Mexico. In addition, BP faces claims under the Oil Pollution Act of 1990 (OPA 90) for natural resource damages. These damages include, among other things, the reasonable costs of assessing the injury to natural resources. During 2011, BP entered a framework agreement with natural resource trustees for the United States and five Gulf-coast states, providing for up to $1 billion to be spent on early restoration projects to address natural resource injuries resulting from the oil spill, to be funded from the $20-billion trust fund. In 2012, work began on the initial set of early restoration projects identified under this framework. At 31 December 2013 the amount provided for natural resource damage assessment costs and early restoration projects was $1,224 million. Until the size, location and duration of the impact is assessed, it is not possible to estimate reliably either the amounts or timing of the remaining natural resource damages claims other than the assessment and early restoration costs noted above, therefore no additional amounts have been provided for these items and they are disclosed as a contingent liability.
Spill response
The spill response provision relates primarily to ongoing shoreline operational activity.
Litigation and claims
The litigation and claims provision includes amounts that can be estimated reliably for the future cost of settling claims by individuals and businesses for damage to real or personal property, lost profits or impairment of earning capacity and loss of subsistence use of natural resources (Individual and Business Claims), and claims by state and local government entities for removal costs, damage to real or personal property, loss of government revenue and increased public services costs (State and Local Claims), under OPA 90 and other legislation, except as described under Contingent liabilities below. Claims administration costs and legal costs have also been provided for. The timing of payment of litigation and claims provisions classified as non-current is dependent on on-going legal activity and is therefore uncertain.
BP has provided for its best estimate of the cost associated with the PSC settlement agreements with the exception of the cost of business economic loss claims. As part of its monitoring of payments made by the DHCSSP, BP identified multiple business economic loss claim determinations that appeared to result from an interpretation of the EPD Settlement Agreement by the claims administrator that BP believes was incorrect.
Between March 2013 and March 2014, there were various rulings from both the federal District Court in New Orleans (the District Court) and a panel of the US Court of Appeals for the Fifth Circuit (the business economic loss panel) on matters relating to the interpretation of the EPD Settlement Agreement, in particular on the issue of matching revenue and expenses as well as causation requirements of the EPD Settlement Agreement.
As reported in BP Annual Report and Form 20-F 2012, the estimated cost of the PSC settlement for Individual and Business Claims was $7.7 billion at 31 December 2012. This estimate increased during the year to $9.6 billion to reflect all claims processed by the DHCSSP for which eligibility notices had been issued and increases in claims administration costs. As a result of the District Courts preliminary injunction issued on 18 October 2013 that, amongst other things, required the claims administrator to temporarily suspend payments of business economic loss claims other than those claims supported by sufficiently matched accrual-basis accounting or any other business economic loss claim for which the claims administrator determines that the matching of revenue and expenses is not an issue, the provision for $0.4 billion of claims for which eligibility notices had been issued but had not yet been paid was derecognized as BP considered and continues to consider that no reliable estimate can be made for these claims. At 31 December 2013, the total costs of the PSC settlement that BP considers can be reliably estimated is therefore $9.2 billion.
On 5 December 2013, the District Court amended its earlier preliminary injunction and temporarily suspended the issuance of final determination notices and payments of business economic loss claims, until the business economic loss issues have been resolved. On 24 December 2013, the District Court ruled on the issues in relation to the matching of revenue and expenses and causation that were remanded to it by the business economic loss panel. Regarding matching, the District Court reversed its earlier decision and ruled that the claims administrator, in administering business economic loss claims, must match revenue with the variable expenses incurred by claimants in conducting their business, even where the revenues and expenses were recorded at different times. The District Court assigned to the claims administrator the development of more detailed matching requirements. On 12 February 2014, the claims administrator 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. Regarding causation, the District Court ruled that the EPD Settlement Agreement contained no causation requirement beyond the revenue and related tests set out in an exhibit to that agreement. BP appealed the District Courts ruling on causation to the business economic loss panel and moved for a permanent injunction that would prevent the claims administrator from making awards to claimants whose alleged injuries are not traceable to the spill. On 3 March 2014, the business economic loss panel affirmed the District Courts ruling on causation and denied BPs motion for a permanent injunction. BP is considering its appeal options, including a potential petition that all the active judges of the Fifth Circuit review the 3 March decision. Under the terms of the business economic loss panels ruling, the injunction temporarily suspending issuance of final determination notices and payments of business economic loss claims will be lifted when the matter is transferred back to the District Court; the timing of this would be affected by the status of any such petition by BP.
BP Annual Report and Form 20-F 2013 | 141 |
2. Significant event Gulf of Mexico oil spill continued
In addition to the proceedings in relation to the interpretation of the EPD Settlement Agreement, following the District Courts final order and judgment approving the EPD Settlement in January 2013, groups of purported members of the Economic and Property Damages Settlement Class (the Appellants) appealed from the District Courts approval of that settlement to a different panel of the Fifth Circuit. On 10 January 2014, that other panel
of the Fifth Circuit affirmed the District Courts approval of the EPD Settlement but left to the business economic loss panel of the Fifth Circuit the question of how to interpret the EPD Settlement Agreement, including the meaning of the causation requirements of that agreement (see above). BP and several Appellants have filed petitions requesting that all the active judges of the Fifth Circuit review the decision to uphold approval of the EPD Settlement.
See Legal proceedings on page 257 for further details on the settlements with the PSC and related matters.
Until the uncertainties described below are resolved, management is unable to estimate reliably the value and volume of future business economic loss claims and whether and to what extent received or processed but unpaid business economic loss claims will be paid. Firstly, the inherent uncertainty as to the interpretation of the EPD Settlement Agreement in respect of matching and causation issues will continue until the more detailed matching requirements are finalized by the claims administrator and are implemented by the DHCSSP; the issue of causation and the requirements for class membership under the EPD Settlement Agreement are resolved on appeal; and the impact of any new policies and procedures in response to these issues on the value and volume of business economic loss claims becomes clear. Furthermore, the Fifth Circuit has yet to decide whether to grant the petitions seeking review of its decision affirming approval of the EPD Settlement and, if granted, whether to alter its decision in that appeal. Secondly, uncertainty arises from the lack of sufficient claims data under the DHCSSP from which to extrapolate any reliable trends the number of business economic loss claims received and the average amounts paid in respect of such claims prior to the District Courts injunction were higher than previously assumed by BP. This inability to extrapolate any reliable trends may or may not continue once the uncertainties concerning the interpretation of the EPD Settlement Agreement described above have been resolved. Thirdly, there is uncertainty as to the ultimate deadline for filing business economic loss claims, which is dependent on the date on which all relevant appeals are concluded. Management believes, therefore, that no reliable estimate can currently be made of any business economic loss claims not yet received, processed and paid by the DHCSSP. A provision for business economic loss claims will be established when a reliable estimate can be made of the liability.
The total cost of the PSC settlement is likely to be significantly higher than the amount recognized to date of $9.2 billion because the current estimate does not reflect business economic loss claims not yet received, processed and paid. The DHCSSP has issued eligibility notices, disputed by BP, in respect of business economic loss claims of $1,019 million which have not yet been paid. Furthermore, a significant number of business economic loss claims have been received but have not yet been processed, and further claims are likely to be received.
The provision recognized for litigation and claims includes an estimate for State and Local Claims. Although the provision recognized is BPs current reliable best estimate of the amount required to settle these obligations, significant uncertainty exists in relation to the outcome of any litigation proceedings and the amount of claims that will become payable by BP. See Legal proceedings on page 257 and Contingent liabilities below for further details.
Clean Water Act penalties
A charge for potential Clean Water Act Section 311 penalties was first included in BPs second-quarter 2010 interim financial statements. At the time that charge was taken, the latest estimate from the intra-agency Flow Rate Technical Group created by the National Incident Commander in charge of the spill response was between 35,000 and 60,000 barrels per day. The mid-point of that range, 47,500 barrels per day, was used for the purposes of calculating the charge. For the purposes of calculating the amount of the oil flow that was discharged into the Gulf of Mexico, the amount of oil that had been or was projected to be captured in vessels on the surface was subtracted from the total estimated flow up until when the well was capped on 15 July 2010. The result of this calculation was an estimate that approximately 3.2 million barrels of oil had been discharged into the Gulf. This estimate of 3.2 million barrels was calculated using a total flow of 47,500 barrels per day multiplied by the 85 days from 22 April 2010 to 15 July 2010 less an estimate of the amount captured on the surface (approximately 850,000 barrels).
This estimated discharge volume was then multiplied by $1,100 per barrel the maximum amount the statute allows in the absence of gross negligence or wilful misconduct for the purposes of estimating a potential penalty. This resulted in a provision of $3,510 million for potential penalties under Section 311.
BP intends to argue for a penalty lower than $1,100 per barrel. The actual penalty a court may impose could be lower than $1,100 per barrel if it were determined that such a lower penalty was appropriate based on the factors a court is directed to consider in assessing a penalty. In particular, in determining the amount of a civil penalty, Section 311 directs a court to consider a number of enumerated factors, including the seriousness of the violation or violations, the economic benefit to the violator, if any, resulting from the violation, the degree of culpability involved, any other penalty for the same incident, any history of prior violations, the nature, extent, and degree of success of any efforts of the violator to minimize or mitigate the effects of the discharge, the economic impact of the penalty on the violator, and any other matters as justice may require. Civil penalties above $1,100 per barrel up to a statutory maximum of $4,300 per barrel of oil discharged would only be imposed if alleged gross negligence or wilful misconduct were proven. The $1,100 per-barrel rate has been utilized for the purposes of calculating the provision after considering and weighing all possible outcomes and in light of: (i) the companys conclusion that it did not act with gross negligence or engage in wilful misconduct; and (ii) the uncertainty as to whether a court would assess a penalty below the $1,100 statutory maximum.
On 2 August 2010, the United States Department of Energy and the Flow Rate Technical Group had issued an estimate that 4.9 million barrels of oil had flowed from the Macondo well, and 4.05 million barrels had been discharged into the Gulf (the difference being the amount of oil captured by vessels on the surface as part of BPs well containment efforts).
It was and remains BPs view, based on the analysis of available data by its experts, that the 2 August 2010 Government estimate is not reliable. BP believes that the 2 August 2010 discharge estimate is overstated by at least 20%. If the flow rate were 20% lower than the 2 August 2010 estimate, then the amount of oil that flowed from the Macondo well would be approximately 3.9 million barrels and the amount discharged into the Gulf would be approximately 3.1 million barrels (using a current estimate of barrels captured by vessels on the surface of 810,000 in line with the stipulation entered with the US government see Legal proceedings), which is not materially different from the amount we used for our original estimate at the end of the second quarter 2010.
For the purposes of calculating a provision for fines and penalties under Section 311 of the Clean Water Act, BP has continued to use an estimate of 3.2 million barrels of oil discharged to the Gulf of Mexico and a penalty of $1,100 per barrel, as its current best estimate, as defined in paragraphs 36-40 of IAS 37 Provisions, Contingent Liabilities and Contingent Assets, of the amounts which may be used in calculating the penalty under Section 311 of the Clean Water Act and as a result, the provision at the end of the year was $3,510 million.
The amount and timing of the amount to be paid ultimately is subject to significant uncertainty since it will depend on what is determined by the court in the federal multi-district litigation proceedings in New Orleans (MDL 2179) as to negligence, gross negligence or wilful misconduct, the volume of oil spilled and the application of statutory penalty factors. The trial court could issue its decision on the first two phases of the trial (which considered the issues of negligence or gross negligence in phase one, and source control efforts and the volume of oil spilled in phase two) at any time and has not yet scheduled a hearing on the subsequent phase regarding the application of statutory penalty factors. The court has wide discretion in its determination as to whether a defendants 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.
142 | BP Annual Report and Form 20-F 2013 |
2. Significant event Gulf of Mexico oil spill continued
See Legal proceedings on page 257 for further details on all litigation and claims activity.
Provision movements
The total amount recognized as an increase in provisions during the year was $2,239 million, including $1,921 million for items covered by the trust fund and $318 million for other items (2012 $6,868 million, including $1,985 million for items covered by the trust fund and $4,883 million for other items). In addition, $379 million (2012 $794 million) was derecognized relating to items that will be covered by the trust fund but which can no longer be reliably estimated. After deducting amounts utilized during the year totalling $3,777 million, including payments from the trust fund of $3,051 million and payments made directly by BP of $726 million (2012 $5,864 million, including payments from the trust fund of $4,624 million and payments made directly by BP of $1,240 million), and after reclassifications and adjustments for discounting, the remaining provision as at 31 December 2013 was $9,346 million (2012 $15,200 million).
The total amounts that will ultimately be paid by BP in relation to all obligations relating to the incident are subject to significant uncertainty and the ultimate exposure and cost to BP will be dependent on many factors. Furthermore, significant uncertainty exists in relation to the amount of claims that will become payable by BP, the amount of fines that will ultimately be levied on BP (including any determination of BPs culpability based on any findings of negligence, gross negligence or wilful misconduct), the outcome of litigation and arbitration proceedings, and any costs arising from any longer-term environmental consequences of the oil spill, which will also impact upon the ultimate cost for BP. The amount and timing of any amounts payable could also be impacted by any further settlements which may or may not occur. Although the provision recognized is the current best reliable estimate of expenditures required to settle certain present obligations at the end of the reporting period, there are future expenditures for which it is not possible to measure the obligation reliably.
Contingent liabilities
BP has provided for its best estimate of amounts expected to be paid from the trust fund that can be measured reliably. This includes certain amounts expected to be paid pursuant to the Oil Pollution Act of 1990 (OPA 90). It is not possible, at this time, to measure reliably other obligations arising from the incident that are under the terms of the trust fund, namely any obligation in relation to natural resource damages claims or associated legal costs (except for the estimated costs of the assessment phase and costs relating to early restoration agreements under the $1-billion framework agreement referred to above), claims asserted in civil litigation including any further litigation through excluded parties from the PSC settlement including as set out in Legal proceedings, the cost of business economic loss claims under the PSC settlement not yet received, processed and paid by the DHCSSP, any further obligation that may arise from state and local government submissions under OPA 90 and any obligation in relation to other potential private or governmental litigation, nor is it practicable to estimate their magnitude or possible timing of payment. Therefore, no amounts have been provided for these obligations as at 31 December 2013.
Natural resource damages resulting from the oil spill are currently being assessed. BP and the federal and state trustees are collecting extensive data in order to assess the extent of damage to wildlife, shoreline, near shore and deepwater habitats, and recreational uses, among other things. The study data will inform an assessment of injury to the Gulf Coast natural resources and the development of a restoration plan to address the identified injuries.
Detailed analysis and interpretation continue on the data that have been collected. Any early restoration projects undertaken pursuant to the $1-billion framework agreement could mitigate the total damages resulting from the incident. Accordingly, until the size, location and duration of the impact is assessed, it is not possible to estimate reliably either the amounts or timing of the remaining natural resource damages claims, therefore no such amounts have been provided as at 31 December 2013.
As described under Provisions above, BP has identified multiple business economic loss claim determinations under the PSC settlement that appeared to result from an interpretation of the EPD Settlement Agreement by the claims administrator that BP believes was incorrect. Uncertainty as to the interpretation of the EPD Settlement Agreement will continue until the effects of the implementation of new policies and procedures are known, the issue of causation and the requirements for class membership under the EPD Settlement Agreement are resolved on appeal and the courts have ruled on the appeals in relation to the final order and judgment approving the EPD Settlement. Therefore the potential cost of business economic loss claims not yet received, processed and paid is not provided for and is disclosed as a contingent liability. A significant number of business economic loss claims have been received but have not yet been processed and paid, and further claims are likely to be received.
As described above in Provisions, a provision has been made for State and Local claims that can be measured reliably. In January 2013, the States of Alabama, Mississippi and Florida submitted or asserted claims to BP under OPA 90 for alleged losses including economic losses and property damage as a result of the Gulf of Mexico oil spill. BP is evaluating these claims. The States of Louisiana and Texas have also asserted similar claims. The amounts claimed, certain of which include punitive damages or other multipliers, are very substantial. However BP considers these claims unsubstantiated and the methodologies used to calculate these claims to be seriously flawed, not supported by OPA 90, not supported by documentation, and to substantially overstate the claims. Similar claims have also been submitted by various local government entities and a foreign government under OPA 90, and more claims are expected to be submitted. The amounts alleged in the submissions for these State and Local Claims total approximately $35 billion. BP will defend vigorously against these claims if adjudicated at trial.
Proceedings relating to securities class actions (MDL 2185) pending in federal court in Texas, 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. No reliable estimate can be made of the amounts that may be payable in relation to these proceedings, if any, so no provision has been recognized at 31 December 2013.
In addition to the State and Local claims and securities class actions described above, BP is named as a defendant in approximately 2,950 other civil lawsuits brought by individuals, corporations and government entities in US federal and state courts, as well as certain foreign jurisdictions, resulting from the Deepwater Horizon accident, the Gulf of Mexico oil spill, and the spill response efforts. Further actions are likely to be brought. Among other claims, these lawsuits assert claims for personal injury or wrongful death in connection with the accident and the spill response, commercial and economic injury, damage to real and personal property, breach of contract and violations of statutes, including, but not limited, to alleged violations of US securities and environmental statutes. Until further fact and expert disclosures occur, court rulings clarify the issues in dispute, liability and damage trial activity nears or progresses, or other actions such as further possible settlements occur, it is not possible given these uncertainties to arrive at a range of outcomes or a reliable estimate of the liabilities that may accrue to BP in connection with or as a result of these lawsuits. Therefore no amounts have been provided for these items as at 31 December 2013. See Legal proceedings on page 257 for further information.
For those items not covered by the trust fund it is not possible to measure reliably any obligation in relation to other litigation or potential fines and penalties except, subject to certain assumptions detailed above, for those relating to the Clean Water Act. There are a number of federal and state environmental and other provisions of law, other than the Clean Water Act, under which one or more governmental agencies could seek civil fines and penalties from BP. For example, a complaint filed by the United States sought to reserve the ability to seek penalties and other relief under a number of other laws. Given the unsubstantiated nature of certain claims that may be asserted, it is not possible at this time to determine whether and to what extent any such claims would be successful or what penalties or fines would be assessed. Therefore no amounts have been provided for these items.
BP Annual Report and Form 20-F 2013 | 143 |
2. Significant event Gulf of Mexico oil spill continued
Under the settlement agreements with Anadarko and MOEX, and with Cameron International, the designer and manufacturer of the Deepwater Horizon blowout preventer, with M-I L.L.C. (M-I), the mud contractor, and with Weatherford, the designer and manufacturer of the float collar used on the Macondo well, BP has agreed to indemnify Anadarko, MOEX, Cameron, M-I and Weatherford for certain claims arising from the accident. It is therefore possible that BP may face claims under these indemnities, but it is not currently possible to reliably measure any obligation in relation to such claims and therefore no amount has been provided as at 31 December 2013.
The magnitude and timing of all possible obligations in relation to the Gulf of Mexico oil spill continue to be subject to a very high degree of uncertainty as described further in Risk factors on page 51. Any such possible obligations are therefore contingent liabilities and, at present, it is not practicable to estimate their magnitude or possible timing of payment. Furthermore, other material unanticipated obligations may arise in future in relation to the incident.
Impact upon the group income statement
The amount of the provision recognized during the year can be reconciled to the charge to the income statement as follows:
$ million | ||||||||||||||||||
2013 | 2012 | 2011 | Cumulative since the incident |
|||||||||||||||
Net increase in provision |
2,239 | 6,868 | 5,183 | 44,551 | ||||||||||||||
Derecognition of provision for items that cannot be reliably estimated |
(379 | ) | (794 | ) | | (1,173 | ) | |||||||||||
Change in discount rate relating to provisions |
(5 | ) | | 17 | 17 | |||||||||||||
Costs charged directly to the income statement |
136 | 257 | 512 | 4,244 | ||||||||||||||
Trust fund liability discounted |
| | | 19,580 | ||||||||||||||
Change in discounting relating to trust fund liability |
| | 43 | 283 | ||||||||||||||
Recognition of reimbursement asset, net |
(1,542 | ) | (1,191 | ) | (4,038 | ) | (19,338 | ) | ||||||||||
Settlements credited to the income statement |
(19 | ) | (145 | ) | (5,517 | ) | (5,681 | ) | ||||||||||
(Profit) loss before interest and taxation |
430 | 4,995 | (3,800 | ) | 42,483 | |||||||||||||
Finance costs |
39 | 19 | 58 | 193 | ||||||||||||||
(Profit) loss before taxation |
469 | 5,014 | (3,742 | ) | 42,676 |
The group income statement for 2013 includes a pre-tax charge of $469 million (2012 pre-tax charge of $5,014 million) in relation to the Gulf of Mexico oil spill. The costs charged in 2013 relate primarily to the ongoing costs of operating the Gulf Coast Restoration Organization (GCRO) and increases in legal costs. Finance costs of $39 million (2012 $19 million) reflect the unwinding of the discount on payables and provisions. The cumulative amount charged to the income statement to date comprises spill response costs arising in the aftermath of the incident, GCRO operating costs, amounts charged upon initial recognition of the trust obligation, litigation, claims, environmental and legal costs not paid through the Trust, estimated obligations for future costs that can be estimated reliably at this time and rights and obligations relating to the trust fund, net of settlements agreed with the co-owners of the Macondo well and other third parties.
The total amount recognized in the income statement is analysed in the table below.
$ million | ||||||||||||||||||
2013 | 2012 | 2011 | Cumulative since the incident |
|||||||||||||||
Trust fund liability discounted |
| | | 19,580 | ||||||||||||||
Change in discounting relating to trust fund liability |
| | 43 | 283 | ||||||||||||||
Recognition of reimbursement asset |
(1,542 | ) | (1,191 | ) | (4,038 | ) | (19,338 | ) | ||||||||||
Other |
| | | 8 | ||||||||||||||
Total (credit) charge relating to the trust fund |
(1,542 | ) | (1,191 | ) | (3,995 | ) | 533 | |||||||||||
Environmental amount provided |
47 | 801 | 1,167 | 2,944 | ||||||||||||||
change in discount rate relating to provisions |
(5 | ) | | 17 | 17 | |||||||||||||
costs charged directly to the income statement |
| | | 70 | ||||||||||||||
Total (credit) charge relating to environmental |
42 | 801 | 1,184 | 3,031 | ||||||||||||||
Spill response amount provided |
(113 | ) | 109 | 586 | 11,465 | |||||||||||||
costs charged directly to the income statement |
| 9 | 85 | 2,839 | ||||||||||||||
Total (credit) charge relating to spill response |
(113 | ) | 118 | 671 | 14,304 | |||||||||||||
Litigation and claims amount provided, net of provision derecognized |
1,926 | 5,164 | 3,430 | 25,459 | ||||||||||||||
costs charged directly to the income statement |
| | | 184 | ||||||||||||||
Total charge relating to litigation and claims |
1,926 | 5,164 | 3,430 | 25,643 | ||||||||||||||
Clean Water Act penalties amount provided |
| | | 3,510 | ||||||||||||||
Other costs charged directly to the income statement |
136 | 248 | 427 | 1,143 | ||||||||||||||
Settlements credited to the income statement |
(19 | ) | (145 | ) | (5,517 | ) | (5,681 | ) | ||||||||||
(Profit) loss before interest and taxation |
430 | 4,995 | (3,800 | ) | 42,483 | |||||||||||||
Finance costs |
39 | 19 | 58 | 193 | ||||||||||||||
(Profit) loss before taxation |
469 | 5,014 | (3,742 | ) | 42,676 |
The total amounts that will ultimately be paid by BP in relation to all obligations relating to the incident are subject to significant uncertainty as described under Provisions and contingent liabilities above.
144 | BP Annual Report and Form 20-F 2013 |
BP undertook a number of minor business combinations in 2013 and 2012 for a total consideration of $67 million and $116 million in cash respectively.
In 2011, BP undertook a number of business combinations with total consideration paid in cash amounting to $11.3 billion, offset by cash acquired of $0.4 billion. The fair value of contingent consideration payable amounted to $0.1 billion. BP acquired from Reliance Industries Limited (Reliance) a 30% interest in 21 oil and gas production-sharing agreements (PSAs) operated by Reliance in India for $7,026 million. In addition, we completed the final part of the transaction with Devon Energy (Devon) for the acquisition of Devons equity stake in a number of assets in Brazil for consideration of $3.6 billion and BPs Alternative Energy business acquired Companhia Nacional de Açúcar e Álcool (CNAA) in Brazil for consideration of $0.7 billion. There were a number of other individually insignificant business combinations.
4. Non-current assets held for sale
There were no assets or associated liabilities classified as held for sale as at 31 December 2013. The disposal of the assets and associated liabilities classified as held for sale at 31 December 2012 completed during 2013.
Impairment losses amounting to $186 million (2012 $2,594 million) were recognized relating to certain assets that were classified as held for sale at 31 December 2012, of which $137 million related to the Carson refinery and associated assets. See Note 5 for further information.
Non-current assets classified as held for sale are not depreciated. It is estimated that the benefit arising from the absence of depreciation for the assets held for sale at 31 December 2012 until their disposal in 2013 amounted to approximately $201 million (2012 $435 million). In addition, profits of approximately $738 million (2012 $731 million) were not recognized as a result of the discontinuance of equity accounting for our interest in TNK-BP.
Non-current assets held for sale at 31 December 2012
At 31 December 2012 assets classified as held for sale included property, plant and equipment of $3,663 million, investments in associates of $12,322 million and inventories of $2,377 million.
Within the Upstream segment, BPs interests in the BP-operated Maclure, Harding and Devenick fields and non-operated interests in the Brae complex of fields and the Braemar field in the central North Sea were classified as held for sale. In the Downstream segment, the Texas City refinery and related assets, and the southern part of the US West Coast fuels value chain, including the Carson refinery, were classified as held for sale at 31 December 2012. BPs investment in TNK-BP was classified as an asset held for sale at 31 December 2012. All of the assets classified as held for sale at 31 December 2012 were sold during 2013. See Notes 5 and 6 for further information.
The following amounts were recognized in the income statement in respect of disposals and impairments.
$ million | ||||||||||||||
2013 | 2012 | 2011 | ||||||||||||
Gains on sale of businesses and fixed assets |
||||||||||||||
Upstream |
371 | 6,504 | 3,477 | |||||||||||
Downstream |
214 | 152 | 319 | |||||||||||
TNK-BP |
12,500 | | | |||||||||||
Other businesses and corporate |
30 | 41 | 336 | |||||||||||
13,115 | 6,697 | 4,132 | ||||||||||||
$ million | ||||||||||||||
2013 | 2012 | 2011 | ||||||||||||
Losses on sale of businesses and fixed assets |
||||||||||||||
Upstream |
144 | 109 | 49 | |||||||||||
Downstream |
78 | 195 | 52 | |||||||||||
Other businesses and corporate |
8 | 6 | 3 | |||||||||||
230 | 310 | 104 | ||||||||||||
Impairment losses |
||||||||||||||
Upstream |
1,255 | 3,046 | 1,443 | |||||||||||
Downstream |
484 | 2,892 | 599 | |||||||||||
Other businesses and corporate |
218 | 320 | 58 | |||||||||||
1,957 | 6,258 | 2,100 | ||||||||||||
Impairment reversals |
||||||||||||||
Upstream |
(226 | ) | (289 | ) | (146 | ) | ||||||||
Downstream |
| (1 | ) | | ||||||||||
Other businesses and corporate |
| (3 | ) | | ||||||||||
(226 | ) | (293 | ) | (146 | ) | |||||||||
Impairment and losses on sale of businesses and fixed assets |
1,961 | 6,275 | 2,058 |
BP Annual Report and Form 20-F 2013 | 145 |
5. Disposals and impairment continued
Disposals
As part of the response to the consequences of the Gulf of Mexico oil spill in 2010, the group announced plans to deliver up to $38 billion of disposal proceeds by the end of 2013. This target was reached during 2012; as at 31 December 2012, BP had announced disposals of $38 billion, and in addition, the sale of our 50% investment in TNK-BP. During 2013 the group announced that it expects to divest a further $10 billion of assets before the end of 2015.
$ million | ||||||||||||||
2013 | 2012 | 2011 | ||||||||||||
Proceeds from disposals of fixed assets |
18,115 | 9,992 | 3,504 | |||||||||||
Proceeds from disposals of businesses, net of cash disposed |
3,884 | 1,606 | (663 | ) | ||||||||||
21,999 | 11,598 | 2,841 | ||||||||||||
By segment |
||||||||||||||
Upstream |
1,288 | 10,667 | 1,080 | |||||||||||
Downstream |
3,991 | 637 | 830 | |||||||||||
TNK-BP |
16,646 | | | |||||||||||
Other businesses and corporate |
74 | 294 | 931 | |||||||||||
21,999 | 11,598 | 2,841 |
Proceeds from disposals for 2012 included a deposit of $632 million received in respect of the disposal in 2013 of interests in a number of central North Sea oil and gas fields. Disposal proceeds for 2011 included the repayment of a deposit of $3,530 million received in 2010 in advance of the expected sale of our interest in Pan American Energy LLC, which did not complete.
At 31 December 2013, deferred consideration relating to disposals amounted to $23 million receivable within one year (2012 $24 million and 2011 $117 million) and $1,374 million receivable after one year (2012 $1,433 million and 2011 $1,524 million). In addition, contingent consideration relating to the disposals of the Devenick field and the Texas City refinery amounted to $953 million at 31 December 2013 see Notes 20 and 26 for further information.
Upstream
In 2013, the major disposal transaction in the segment was the sale of our interests in the BP-operated Maclure, Harding and Devenick fields and non-operated interests in the Brae complex of fields and the Braemar field in the central North Sea to TAQA. In addition, we sold our interests in the Yacheng field in China to Kuwait Foreign Petroleum Exploration Company, as well as other interests in the North Sea and the US.
In 2012, the major disposal transactions were the sale of our interests in the Marlin, Horn Mountain, Holstein, Ram Powell and Diana Hoover fields in the Gulf of Mexico to Plains Exploration and Production Company, the sale of our interests in the Hugoton and Jayhawk gas production and processing assets in Kansas, and our interest in the Jonah and Pinedale upstream operations in Wyoming, to LINN Energy, LLC, and the sale of our interests in our Canadian natural gas liquids (NGL) business to Plains Midstream Canada ULC. In addition, we sold a number of interests in the North Sea, including the disposal of our Southern Gas Assets to Perenco UK Ltd.
In 2011, the major disposal transactions were the sale of our interests in Colombia to Ecopetrol and Talisman, the sale of our upstream and midstream assets in Vietnam and our investments in equity-accounted entities in Venezuela to TNK-BP, and the sale of our assets in Pakistan to United Energy Group. In addition, we completed the disposal of half of the 3.29% interest in the Azeri-Chirag-Gunashli development in Azerbaijan to SOCAR and a number of interests in the Gulf of Mexico to Marubeni Group.
Downstream
In 2013, gains resulted from the disposal of our global LPG business and closing adjustments on the sales of the Texas City and Carson refineries with their associated marketing and logistics assets. Losses principally resulted from the disposal of a number of assets, principally in our global fuels portfolio.
In 2012, gains on disposal resulted from the disposal of our interests in purified terephthalic acid production in Malaysia to Reliance Global Holdings Pte. Ltd., retail churn in the US and a number of other assets in the segment. Losses resulted from the ongoing costs associated with our US refinery divestments and the disposal of a number of assets in the segment portfolio.
In 2011, gains on disposal resulted from our disposal of the fuels marketing business in Namibia, Malawi, Zambia and Tanzania to Puma Energy, certain non-strategic pipelines and terminals in the US and other assets in the segment. Losses resulted from the disposal of a number of assets in the segment portfolio.
TNK-BP
In 2013, BP disposed of its 50% interest in TNK-BP. See Note 6 for further information.
Other businesses and corporate
In 2011, we disposed of our aluminium business in the US which resulted in a gain.
146 | BP Annual Report and Form 20-F 2013 |
5. Disposals and impairment continued
Summarized financial information relating to the sale of businesses is shown in the table below. The principal transactions categorized as business disposals in 2013 were the sales of the Texas City and Carson refineries with their associated marketing and logistics assets. Information relating to sales of fixed assets is excluded from the table.
$ million | ||||||||||||||
2013 | 2012 | 2011 | ||||||||||||
Non-current assets |
2,124 | 610 | 2,085 | |||||||||||
Current assets |
2,371 | 570 | 1,008 | |||||||||||
Non-current liabilities |
(94 | ) | (263 | ) | (212 | ) | ||||||||
Current liabilities |
(62 | ) | (232 | ) | (611 | ) | ||||||||
Total carrying amount of net assets disposed |
4,339 | 685 | 2,270 | |||||||||||
Recycling of foreign exchange on disposal |
23 | (15 | ) | 8 | ||||||||||
Costs on disposala |
13 | 39 | 17 | |||||||||||
4,375 | 709 | 2,295 | ||||||||||||
Profit on sale of businessesb |
69 | 675 | 2,232 | |||||||||||
Total consideration |
4,444 | 1,384 | 4,527 | |||||||||||
Consideration received (receivable)c |
(414 | ) | 76 | 116 | ||||||||||
Proceeds from the sale of businesses related to completed transactions |
4,030 | 1,460 | 4,643 | |||||||||||
Deposits received (repaid) related to assets classified as held for saled |
| 146 | (3,530 | ) | ||||||||||
Disposals completed in relation to which deposits had been received in prior year |
(146 | ) | | (1,776 | ) | |||||||||
Proceeds from the sale of businessese |
3,884 | 1,606 | (663 | ) |
a | 2013 includes pension and other post-retirement benefit plan curtailment gains of $109 million. |
b | In 2011 a $278-million gain was not recognized in the income statement as it represented an unrealized gain on the sale of business assets in Vietnam to our former associate TNK-BP. |
c | Consideration received from prior year business disposals or to be received from current year disposals. 2013 includes contingent consideration of $475 million relating to the disposal of the Texas City refinery. |
d | 2011 relates to the repayment of a deposit received in advance of $3,530 million following the termination of the sale agreement in respect of the expected sale of our interest in Pan American Energy LLC. |
e | Substantially all of the consideration received was in the form of cash and cash equivalents. Proceeds are stated net of cash and cash equivalents disposed of $42 million (2012 $4 million and 2011 $14 million). |
Impairment
Upstream
During 2013, the Upstream segment recognized impairment losses of $1,255 million. The main elements were impairment losses of $251 million and $159 million relating to the Browse project in Australia and the Mad Dog Phase 2 project in the Gulf of Mexico respectively, resulting from the selection of alternative development scenarios for both projects; write-downs of a number of assets in the North Sea, caused by increases in expected decommissioning costs, amounting to $253 million in aggregate; a $134-million write-down of pipelines in the North Sea due to cost increases; a $122-million write-down to fair value less costs to sell based on expected proceeds resulting from a decision to divest our interest in the Polvo field in Brazil; and other impairment losses amounting to $335 million in total that were not individually significant. These impairment losses were partly offset by reversals of impairment of certain of our interests in Alaska, the Gulf of Mexico, and the North Sea amounting to $226 million in total, triggered by reductions in expected decommissioning costs, partly as a result of an increase in the discount rate for provisions.
During 2012, the Upstream segment recognized impairment losses of $3,046 million. The main elements were a $1,082-million write-down of our interests in the Fayetteville and Woodford shale gas assets in the US, due to reserves revisions, lower values being attributed to recent market transactions and a fall in the gas price; a $999-million impairment loss relating to the decision to suspend the Liberty project in Alaska; a $706-million aggregate write-down of a number of assets, primarily in the Gulf of Mexico and North Sea, caused by increases in the decommissioning provision resulting from continued review of the expected decommissioning costs; a $144-million write-down of certain gas storage assets in Europe due to changes to the European gas market; and other impairment losses amounting to $116 million in total that were not individually significant. These impairment losses were partly offset by reversals of impairment of certain of our interests in the Gulf of Mexico amounting to $222 million, triggered by a decision to divest assets; and other reversals of impairment amounting to $67 million in total that were not individually significant.
During 2011, the Upstream segment recognized impairment losses of $1,443 million. The main elements were a $555-million impairment loss relating to a number of our interests in the Gulf of Mexico, caused by an increase in the decommissioning provision as a result of further assessments of the regulations relating to idle infrastructure and a decrease in our assumption of the discount rate for provisions; the $393-million write-down of our interest in the Fayetteville shale gas asset in the US, triggered by a decrease in value by reference to a sale transaction by a partner of its interest in the same asset; and the $153-million write-down of our interest in the proposed Denali gas pipeline in Alaska, resulting from a decision not to proceed with the project. There were several other impairment losses amounting to $342 million in total that were not individually significant. These impairment losses were partly offset by reversals of impairment of certain of our interests in the Gulf of Mexico and Egypt amounting to $146 million in total, triggered by an increase in our assumption of long-term oil prices.
Downstream
During 2013, the Downstream segment recognized impairment losses of $484 million which mainly relates to impairments of certain refineries in the US and elsewhere in our global fuels portfolio.
During 2012, the Downstream segment recognized impairment losses of $2,892 million largely related to assets held for sale for which sales prices had been agreed, see Note 4 for further information. This impairment loss included $1,552 million relating to the Texas City refinery and associated assets and $1,042 million relating to the Carson refinery and associated assets.
During 2011, the Downstream segment recognized impairment losses of $599 million, of which $398 million related to assets classified as held for sale. Other impairment losses, related to retail churn in Europe and other minor asset disposals, amounted to $201 million in total.
Other businesses and corporate
Impairment losses totalling $218 million, $320 million and $58 million were recognized in 2013, 2012 and 2011 respectively related to various assets in the Alternative Energy business. The amount for 2013 is principally in respect of our US wind business. The amount for 2012 includes $258 million in respect of the decision not to proceed with an investment in a biofuels production facility under development in the US.
BP Annual Report and Form 20-F 2013 | 147 |
6. Disposal of TNK-BP and investment in Rosneft
Disposal of TNK-BP
BP announced on 22 November 2012 that it, Rosneft and Rosneftegaz the Russian state-owned parent company of Rosneft had signed definitive and binding sale and purchase agreements (SPAs) for the sale of BPs 50% interest in TNK-BP to Rosneft, and for BPs further investment in Rosneft. The transaction would consist of three tranches:
| BP to sell its 50% shareholding in TNK-BP to Rosneft for cash consideration of $25.4 billion (which included a dividend of $0.7 billion received from TNK-BP in December 2012) and Rosneft shares representing a 3.04% stake in Rosneft. |
| BP would use $4.8 billion of the cash consideration to acquire a further 5.66% stake in Rosneft from the Russian government at a price of $8 per share (representing a premium of 12% to the Rosneft share price on the bid date of 18 October 2012). |
| BP would use $8.3 billion of the cash consideration to acquire a further 9.8% stake in Rosneft from a Rosneft subsidiary at a price of $8 per share. |
The net result of the overall transaction was that BP would receive $12.3 billion in cash (including $0.7 billion of TNK-BP dividends received by BP in December 2012) and acquire an 18.5% shareholding in Rosneft. Combined with BPs existing 1.25% shareholding, this would result in BP owning 19.75% of Rosneft.
On completion, the transactions between BP, Rosneft and the Rosneft subsidiary were instead settled on a net basis, so that BP received the 9.80% stake in Rosneft directly rather than receiving and immediately paying $8.3 billion in cash; however, the net result was the same.
BP accounts for its investment in Rosneft as an associate, and so equity accounts for its share of Rosnefts earnings, production and reserves. See Note 18 for more information on BPs investment in Rosneft.
The gain on disposal of BPs investment in TNK-BP, recognized in the TNK-BP segment in 2013, was $12.5 billion as shown in the table below.
$ million | ||||||
Agreed cash disposal proceeds |
25,425 | |||||
Amount settled net in Rosneft shares (9.80% stake) |
(8,309 | ) | ||||
TNK-BP dividend received by BP in December 2012 |
(709 | ) | ||||
Interest on cash proceeds |
239 | |||||
Disposal proceeds received in cash |
16,646 | |||||
Shares in Rosneft received (9.80% and 3.04% stake) |
10,755 | |||||
Consideration received |
27,401 | |||||
Less: carrying value of investment in TNK-BP |
(12,393 | ) | ||||
15,008 | ||||||
Deferral of gain |
(2,959 | ) | ||||
Gain on existing 1.25% investment in Rosneft |
523 | |||||
Other |
(72 | ) | ||||
Gain on disposal of investment in TNK-BP |
12,500 |
Disposal proceeds of $4.9 billion were used to purchase the 5.66% stake in Rosneft from Rosneftegaz ($4.8 billion described above plus $0.1 billion of interest). The net cash inflow relating to the transaction included in net cash flow from investing activities in the cash flow statement was $11.8 billion.
Part of the gain arising on the disposal, amounting to $3.0 billion, was deferred due to BP selling its investment in TNK-BP to Rosneft, which in turn is now accounted for by BP as an associate. The deferred gain will be released to BPs income statement over time as the TNK-BP assets are depreciated or amortized.
Investment in Rosneft
BPs investment in Rosneft is included in the group balance sheet within investments in associates, as described in Note 1. The investment is measured at cost less the deferred gain described above, plus post-acquisition changes in BPs share of Rosnefts net assets. The amount recognized as BPs initial investment in Rosneft was determined as shown in the table below.
$ million | ||||||
Shares in Rosneft received |
10,755 | |||||
Shares purchased from Rosneftegaz |
4,871 | |||||
Value of agreements to purchase Rosneft shares accounted for as derivatives (see Note 26) |
(726 | ) | ||||
Deferred gain |
(2,959 | ) | ||||
Amount included in capital expenditure |
11,941 | |||||
Value of existing 1.25% investment in Rosneft |
1,006 | |||||
Investment in Rosneft on completion |
12,947 |
The exercise to determine BPs share of the fair value of Rosnefts identifiable net assets and the consequent impact recognized via equity accounting in BPs income statement has been completed and the results are reflected in these financial statements.
148 | BP Annual Report and Form 20-F 2013 |
The groups organizational structure reflects the various activities in which BP is engaged. At 31 December 2013, BP had three reportable segments: Upstream, Downstream and Rosneft.
Upstreams activities include oil and natural gas exploration, field development and production; midstream transportation, storage and processing; and the marketing and trading of natural gas, including liquefied natural gas (LNG), together with power and natural gas liquids (NGLs).
Downstreams activities include the refining, manufacturing, marketing, transportation, and supply and trading of crude oil, petroleum, petrochemicals products and related services to wholesale and retail customers.
During 2013, BP completed transactions for the sale of BPs interest in TNK-BP to Rosneft, and for BPs further investment in Rosneft. BPs interest in Rosneft is accounted for using the equity method and is reported as a separate operating segment, reflecting the way in which the investment is managed.
Other businesses and corporate comprises the Alternative Energy business, the groups shipping and treasury functions, and corporate activities worldwide. The Alternative Energy business is an operating segment which is reported within Other businesses and corporate as it does not meet the materiality thresholds for separate segment reporting.
The Gulf Coast Restoration Organization (GCRO), which manages all aspects of our response to the 2010 Gulf of Mexico incident, reports directly to the group chief executive and is overseen by a board committee, however it is not an operating segment.
The accounting policies of the operating segments are the same as the groups accounting policies described in Note 1. However, IFRS requires that the measure of profit or loss disclosed for each operating segment is the measure that is provided regularly to the chief operating decision maker for the purposes of performance assessment and resource allocation. For BP, this measure of profit or loss is replacement cost profit or loss before interest and tax which reflects the replacement cost of supplies by excluding from profit or loss inventory holding gains and lossesa. Replacement cost profit or loss for the group is not a recognized measure under IFRS.
Sales between segments are made at prices that approximate market prices, taking into account the volumes involved. Segment revenues and segment results include transactions between business segments. These transactions and any unrealized profits and losses are eliminated on consolidation, unless unrealized losses provide evidence of an impairment of the asset transferred. Sales to external customers by region are based on the location of the seller. The UK region includes the UK-based international activities of Downstream.
All surpluses and deficits recognized on the group balance sheet in respect of pension and other post-retirement benefit plans are allocated to Other businesses and corporate. However, the periodic expense relating to these plans is allocated to the other operating segments based upon the business in which the employees work.
Certain financial information is provided separately for the US as this is an individually material country for BP, and for the UK as this is BPs country of domicile.
a | Inventory holding gains and losses represent the difference between the cost of sales calculated using the average cost to BP of supplies acquired during the period and the cost of sales calculated on the first-in first-out (FIFO) method after adjusting for any changes in provisions where the net realizable value of the inventory is lower than its cost. Under the FIFO method, which we use for IFRS reporting, the cost of inventory charged to the income statement is based on its historic cost of purchase, or manufacture, rather than its replacement cost. In volatile energy markets, this can have a significant distorting effect on reported income. The amounts disclosed represent the difference between the charge (to the income statement) for inventory on a FIFO basis (after adjusting for any related movements in net realizable value provisions) and the charge that would have arisen if an average cost of supplies was used for the period. For this purpose, the average cost of supplies during the period is principally calculated on a monthly basis by dividing the total cost of inventory acquired in the period by the number of barrels acquired. The amounts disclosed are not separately reflected in the financial statements as a gain or loss. No adjustment is made in respect of the cost of inventories held as part of a trading position and certain other temporary inventory positions. |
BP Annual Report and Form 20-F 2013 | 149 |
7. Segmental analysis continued
$ million | ||||||||||||||||||||||||||||||||||
2013 | ||||||||||||||||||||||||||||||||||
By segment | Upstream | Downstream | Rosneft | TNK-BP | Other businesses and corporate |
Gulf of Mexico oil spill response |
Consolidation adjustment and eliminations |
Total group |
||||||||||||||||||||||||||
Segment revenues |
||||||||||||||||||||||||||||||||||
Sales and other operating revenues |
70,374 | 351,195 | | | 1,805 | | (44,238 | ) | 379,136 | |||||||||||||||||||||||||
Less: sales and other operating revenues between segments |
(42,327 | ) | (1,045 | ) | | | (866 | ) | | 44,238 | | |||||||||||||||||||||||
Third party sales and other operating revenues |
28,047 | 350,150 | | | 939 | | | 379,136 | ||||||||||||||||||||||||||
Equity-accounted earnings |
1,027 | 195 | 2,058 | | (91 | ) | | | 3,189 | |||||||||||||||||||||||||
Interest income |
76 | 93 | | | 113 | | | 282 | ||||||||||||||||||||||||||
Segment results |
||||||||||||||||||||||||||||||||||
Replacement cost profit (loss) before interest and taxation |
16,657 | 2,919 | 2,153 | 12,500 | (2,319 | ) | (430 | ) | 579 | 32,059 | ||||||||||||||||||||||||
Inventory holding gains (losses)a |
4 | (194 | ) | (100 | ) | | | | | (290 | ) | |||||||||||||||||||||||
Profit (loss) before interest and taxation |
16,661 | 2,725 | 2,053 | 12,500 | (2,319 | ) | (430 | ) | 579 | 31,769 | ||||||||||||||||||||||||
Finance costs |
(1,068 | ) | ||||||||||||||||||||||||||||||||
Net finance expense relating to pensions and other post-retirement benefits |
(480 | ) | ||||||||||||||||||||||||||||||||
Profit before taxation |
30,221 | |||||||||||||||||||||||||||||||||
Other income statement items |
||||||||||||||||||||||||||||||||||
Depreciation, depletion and amortization |
||||||||||||||||||||||||||||||||||
US |
3,538 | 747 | | | 181 | | | 4,466 | ||||||||||||||||||||||||||
Non-US |
7,514 | 1,343 | | | 187 | | | 9,044 | ||||||||||||||||||||||||||
Impairment losses |
1,255 | 484 | | | 218 | | | 1,957 | ||||||||||||||||||||||||||
Impairment reversals |
(226 | ) | | | | | | | (226 | ) | ||||||||||||||||||||||||
Fair value (gain) loss on embedded derivatives |
(459 | ) | | | | | | | (459 | ) | ||||||||||||||||||||||||
Charges for provisions, net of write-back of unused provisions, including change in discount rate |
161 | 270 | | | 295 | 1,855 | | 2,581 | ||||||||||||||||||||||||||
Segment assets |
||||||||||||||||||||||||||||||||||
Equity-accounted investments |
7,780 | 3,302 | 13,681 | | 1,072 | | | 25,835 | ||||||||||||||||||||||||||
Additions to non-current assets |
19,499 | 4,449 | 11,941 | | 1,027 | | | 36,916 | ||||||||||||||||||||||||||
Additions to other investments |
41 | |||||||||||||||||||||||||||||||||
Element of acquisitions not related to non-current assets |
39 | |||||||||||||||||||||||||||||||||
Additions to decommissioning asset |
(384 | ) | ||||||||||||||||||||||||||||||||
Capital expenditure and acquisitions |
19,115 | 4,506 | 11,941 | | 1,050 | | | 36,612 |
a | See explanation of inventory holding gains and losses on page 149. |
150 | BP Annual Report and Form 20-F 2013 |
7. Segmental analysis continued
$ million | ||||||||||||||||||||||||||||||
2012 | ||||||||||||||||||||||||||||||
By segment | Upstream | Downstream | TNK-BP | Other businesses and corporate |
Gulf of Mexico oil spill response |
Consolidation adjustment and eliminations |
Total group |
|||||||||||||||||||||||
Segment revenues |
||||||||||||||||||||||||||||||
Sales and other operating revenues |
72,225 | 346,391 | | 1,985 | | (44,836 | ) | 375,765 | ||||||||||||||||||||||
Less: sales and other operating revenues between segments |
(42,572 | ) | (1,365 | ) | | (899 | ) | | 44,836 | | ||||||||||||||||||||
Third party sales and other operating revenues |
29,653 | 345,026 | | 1,086 | | | 375,765 | |||||||||||||||||||||||
Equity-accounted earnings |
915 | 101 | 2,986 | (67 | ) | | | 3,935 | ||||||||||||||||||||||
Interest income |
107 | 108 | | 104 | | | 319 | |||||||||||||||||||||||
Segment results |
||||||||||||||||||||||||||||||
Replacement cost profit (loss) before interest and taxation |
22,491 | 2,864 | 3,373 | (2,794 | ) | (4,995 | ) | (576 | ) | 20,363 | ||||||||||||||||||||
Inventory holding gains (losses)a |
(104 | ) | (487 | ) | (3 | ) | | | | (594 | ) | |||||||||||||||||||
Profit (loss) before interest and taxation |
22,387 | 2,377 | 3,370 | (2,794 | ) | (4,995 | ) | (576 | ) | 19,769 | ||||||||||||||||||||
Finance costs |
(1,072 | ) | ||||||||||||||||||||||||||||
Net finance expense relating to pensions and other post-retirement benefits |
(566 | ) | ||||||||||||||||||||||||||||
Profit before taxation |
18,131 | |||||||||||||||||||||||||||||
Other income statement items |
||||||||||||||||||||||||||||||
Depreciation, depletion and amortization |
||||||||||||||||||||||||||||||
US |
3,437 | 586 | | 213 | | | 4,236 | |||||||||||||||||||||||
Non-US |
6,918 | 1,343 | | 190 | | | 8,451 | |||||||||||||||||||||||
Impairment losses |
3,046 | 2,892 | | 320 | | | 6,258 | |||||||||||||||||||||||
Impairment reversals |
(289 | ) | (1 | ) | | (3 | ) | | | (293 | ) | |||||||||||||||||||
Fair value (gain) loss on embedded derivatives |
(347 | ) | | | | | | (347 | ) | |||||||||||||||||||||
Charges for provisions, net of write-back of unused provisions, including change in discount rate |
897 | 141 | | 505 | 6,074 | | 7,617 | |||||||||||||||||||||||
Segment assets |
||||||||||||||||||||||||||||||
Equity-accounted investments |
7,329 | 3,212 | | 1,071 | | | 11,612 | |||||||||||||||||||||||
Additions to non-current assets |
22,603 | 5,246 | | 1,419 | | | 29,268 | |||||||||||||||||||||||
Additions to other investments |
33 | |||||||||||||||||||||||||||||
Element of acquisitions not related to non-current assets |
(72 | ) | ||||||||||||||||||||||||||||
Additions to decommissioning asset |
(4,025 | ) | ||||||||||||||||||||||||||||
Capital expenditure and acquisitions |
18,520 | 5,249 | | 1,435 | | | 25,204 |
a | See explanation of inventory holding gains and losses on page 149. |
BP Annual Report and Form 20-F 2013 | 151 |
7. Segmental analysis continued
$ million | ||||||||||||||||||||||||||||||
2011 | ||||||||||||||||||||||||||||||
By segment | Upstream | Downstream | TNK-BP | Other businesses and corporate |
Gulf of Mexico oil spill response |
Consolidation adjustment and eliminations |
Total group |
|||||||||||||||||||||||
Segment revenues |
||||||||||||||||||||||||||||||
Sales and other operating revenues |
75,754 | 344,033 | | 2,957 | | (47,031 | ) | 375,713 | ||||||||||||||||||||||
Less: sales and other operating revenues between segments |
(44,766 | ) | (1,396 | ) | | (869 | ) | | 47,031 | | ||||||||||||||||||||
Third party sales and other operating revenues |
30,988 | 342,637 | | 2,088 | | | 375,713 | |||||||||||||||||||||||
Equity-accounted earnings |
1,150 | 381 | 4,185 | (33 | ) | | | 5,683 | ||||||||||||||||||||||
Interest income |
(10 | ) | 108 | | 146 | | | 244 | ||||||||||||||||||||||
Segment results |
||||||||||||||||||||||||||||||
Replacement cost profit (loss) before interest and taxation |
26,358 | 5,470 | 4,134 | (2,468 | ) | 3,800 | (113 | ) | 37,181 | |||||||||||||||||||||
Inventory holding gains (losses)a |
81 | 2,487 | 51 | 15 | | | 2,634 | |||||||||||||||||||||||
Profit (loss) before interest and taxation |
26,439 | 7,957 | 4,185 | (2,453 | ) | 3,800 | (113 | ) | 39,815 | |||||||||||||||||||||
Finance costs |
(1,187 | ) | ||||||||||||||||||||||||||||
Net finance expense relating to pensions and other post-retirement benefits |
(400 | ) | ||||||||||||||||||||||||||||
Profit before taxation |
38,228 | |||||||||||||||||||||||||||||
Other income statement items |
||||||||||||||||||||||||||||||
Depreciation, depletion and amortization |
||||||||||||||||||||||||||||||
US |
3,201 | 860 | | 151 | | | 4,212 | |||||||||||||||||||||||
Non-US |
5,540 | 1,431 | | 174 | | | 7,145 | |||||||||||||||||||||||
Impairment losses |
1,443 | 599 | | 58 | | | 2,100 | |||||||||||||||||||||||
Impairment reversals |
(146 | ) | | | | | | (146 | ) | |||||||||||||||||||||
Fair value (gain) loss on embedded derivatives |
(191 | ) | | | 123 | | | (68 | ) | |||||||||||||||||||||
Charges for provisions, net of write-back of unused provisions, including change in discount rate |
213 | 373 | | 942 | 5,200 | | 6,728 | |||||||||||||||||||||||
Segment assets |
||||||||||||||||||||||||||||||
Equity-accounted investments |
7,301 | 3,256 | 10,013 | 1,024 | | | 21,594 | |||||||||||||||||||||||
Additions to non-current assets |
34,813 | 4,281 | | 1,864 | | | 40,958 | |||||||||||||||||||||||
Additions to other investments |
27 | |||||||||||||||||||||||||||||
Element of acquisitions not related to non-current assets |
(1,089 | ) | ||||||||||||||||||||||||||||
Additions to decommissioning asset |
(7,937 | ) | ||||||||||||||||||||||||||||
Capital expenditure and acquisitions |
25,821 | 4,285 | | 1,853 | | | 31,959 |
a | See explanation of inventory holding gains and losses on page 149. |
152 | BP Annual Report and Form 20-F 2013 |
7. Segmental analysis continued
$ million | ||||||||||||||
2013 | ||||||||||||||
By geographical area | US | Non-US | Total | |||||||||||
Revenues |
||||||||||||||
Third party sales and other operating revenuesa |
128,764 | 250,372 | 379,136 | |||||||||||
Other income statement items |
||||||||||||||
Production and similar taxes |
1,112 | 5,935 | 7,047 | |||||||||||
Results |
||||||||||||||
Replacement cost profit before interest and taxation |
3,114 | 28,945 | 32,059 | |||||||||||
Non-current assets |
||||||||||||||
Other non-current assetsb c |
70,228 | 124,439 | 194,667 | |||||||||||
Other investments |
1,565 | |||||||||||||
Loans |
763 | |||||||||||||
Trade and other receivables |
5,985 | |||||||||||||
Derivative financial instruments |
3,509 | |||||||||||||
Deferred tax assets |
985 | |||||||||||||
Defined benefit pension plan surpluses |
1,376 | |||||||||||||
Total non-current assets |
208,850 | |||||||||||||
Capital expenditure and acquisitions |
9,176 | 27,436 | 36,612 |
a | Non-US region includes UK $82,381 million. |
b | Non-US region includes UK $18,967 million. |
c | Excluding financial instruments, deferred tax assets and defined benefit pension plan surpluses. |
$ million | ||||||||||||||
2012 | ||||||||||||||
By geographical area | US | Non-US | Total | |||||||||||
Revenues |
||||||||||||||
Third party sales and other operating revenuesa |
130,940 | 244,825 | 375,765 | |||||||||||
Other income statement items |
||||||||||||||
Production and similar taxes |
1,472 | 6,686 | 8,158 | |||||||||||
Results |
||||||||||||||
Replacement cost profit before interest and taxation |
180 | 20,183 | 20,363 | |||||||||||
Non-current assets |
||||||||||||||
Other non-current assetsb c |
66,751 | 107,844 | 174,595 | |||||||||||
Other investments |
2,704 | |||||||||||||
Loans |
642 | |||||||||||||
Trade and other receivables |
5,961 | |||||||||||||
Derivative financial instruments |
4,294 | |||||||||||||
Deferred tax assets |
874 | |||||||||||||
Defined benefit pension plan surpluses |
12 | |||||||||||||
Total non-current assets |
189,082 | |||||||||||||
Capital expenditure and acquisitions |
10,541 | 14,663 | 25,204 |
a | Non-US region includes UK $75,364 million. |
b | Non-US region includes UK $17,545 million. |
c | Excluding financial instruments, deferred tax assets and defined benefit pension plan surpluses. |
BP Annual Report and Form 20-F 2013 | 153 |
7. Segmental analysis continued
$ million | ||||||||||||||
2011 | ||||||||||||||
By geographical area | US | Non-US | Total | |||||||||||
Revenues |
||||||||||||||
Third party sales and other operating revenuesa |
131,488 | 244,225 | 375,713 | |||||||||||
Other income statement items |
||||||||||||||
Production and similar taxes |
1,854 | 6,426 | 8,280 | |||||||||||
Results |
||||||||||||||
Replacement cost profit before interest and taxation |
10,202 | 26,979 | 37,181 | |||||||||||
Non-current assets |
||||||||||||||
Other non-current assetsb c |
66,523 | 113,323 | 179,846 | |||||||||||
Other investments |
2,635 | |||||||||||||
Loans |
824 | |||||||||||||
Trade and other receivables |
5,738 | |||||||||||||
Derivative financial instruments |
5,038 | |||||||||||||
Deferred tax assets |
611 | |||||||||||||
Defined benefit pension plan surpluses |
17 | |||||||||||||
Total non-current assets |
194,709 | |||||||||||||
Capital expenditure and acquisitions |
8,931 | 23,028 | 31,959 |
a | Non-US region includes UK $75,816 million. |
b | Non-US region includes UK $18,363 million. |
c | Excluding financial instruments, deferred tax assets and defined benefit pension plan surpluses. |
$ million | ||||||||||||||
2013 | 2012 | 2011 | ||||||||||||
Interest and other income |
||||||||||||||
Interest income |
282 | 319 | 244 | |||||||||||
Other incomea |
495 | 1,358 | 444 | |||||||||||
777 | 1,677 | 688 | ||||||||||||
Currency exchange losses (gains) charged (credited) to the income statementb |
180 | 106 | (69 | ) | ||||||||||
Expenditure on research and development |
707 | 674 | 636 | |||||||||||
Finance costs |
||||||||||||||
Interest payable |
1,082 | 1,234 | 1,151 | |||||||||||
Capitalized at 2% (2012 2.25% and 2011 2.63%)c |
(238 | ) | (390 | ) | (349 | ) | ||||||||
Unwinding of discount on provisionsd |
147 | 140 | 244 | |||||||||||
Unwinding of discount on other payablesd |
77 | 88 | 141 | |||||||||||
1,068 | 1,072 | 1,187 |
a | 2012 includes $709 million of dividends received from TNK-BP. See Note 6 for further information. |
b | Excludes exchange gains and losses arising on financial instruments measured at fair value through profit or loss. |
c | Tax relief on capitalized interest is approximately $62 million (2012 $93 million and 2011 $107 million). |
d | Unwinding of discount on provisions relating to the Gulf of Mexico oil spill was $1 million (2012 $7 million and 2011 $6 million) and unwinding of discount on other payables relating to the Gulf of Mexico oil spill was $38 million (2012 $12 million and 2011 $52 million). See Note 2 for further information on the financial impacts of the Gulf of Mexico oil spill. |
In the case of an operating lease entered into by BP as the operator of a joint operation, the amounts shown in the tables below represent the net operating lease expense and net future minimum lease payments. These net amounts are after deducting amounts reimbursed, or to be reimbursed, by joint operators, whether the joint operators have co-signed the lease or not. Where BP is not the operator of a joint operation, BPs share of the lease expense and future minimum lease payments is included in the amounts shown, whether BP has co-signed the lease or not.
The table below shows the expense for the year in respect of operating leases.
$ million | ||||||||||||||
2013 | 2012 | 2011 | ||||||||||||
Minimum lease payments |
5,961 | 5,257 | 4,868 | |||||||||||
Contingent rentals |
(50 | ) | (79 | ) | (97 | ) | ||||||||
Sub-lease rentals |
(88 | ) | (228 | ) | (153 | ) | ||||||||
5,823 | 4,950 | 4,618 |
154 | BP Annual Report and Form 20-F 2013 |
9. Operating leases continued
The future minimum lease payments at 31 December 2013, before deducting related rental income from operating sub-leases of $223 million (2012 $271 million), are shown in the table below. This does not include future contingent rentals. Where the lease rentals are dependent on a variable factor, the future minimum lease payments are based on the factor as at inception of the lease.
$ million | ||||||||||
Future minimum lease payments | 2013 | 2012 | ||||||||
Payable within |
||||||||||
1 year |
5,188 | 4,533 | ||||||||
2 to 5 years |
10,408 | 9,735 | ||||||||
Thereafter |
3,590 | 4,195 | ||||||||
19,186 | 18,463 |
The group enters into operating leases of ships, plant and machinery, commercial vehicles and land and buildings. Typical durations of the leases are as follows:
Years | ||||||
Ships |
up to 15 | |||||
Plant and machinery |
up to 10 | |||||
Commercial vehicles |
up to 15 | |||||
Land and buildings |
up to 40 |
The group has entered into a number of structured operating leases for ships and in most cases the lease rental payments vary with market interest rates. The variable portion of the lease payments above or below the amount based on the market interest rate prevailing at inception of the lease is treated as contingent rental expense. The group also routinely enters into bareboat charters, time-charters and voyage-charters for ships on standard industry terms.
The most significant items of plant and machinery hired under operating leases are drilling rigs used in the Upstream segment. At 31 December 2013, the future minimum lease payments relating to drilling rigs amounted to $8,776 million (2012 $8,527 million).
Commercial vehicles hired under operating leases are primarily railcars. Retail service station sites and office accommodation are the main items in the land and buildings category.
The terms and conditions of these operating leases do not impose any significant financial restrictions on the group. Some of the leases of ships and buildings allow for renewals at BPs option, and some of the groups operating leases contain escalation clauses.
10. Exploration for and evaluation of oil and natural gas resources
The following financial information represents the amounts included within the group totals relating to activity associated with the exploration for and evaluation of oil and natural gas resources. All such activity is recorded within the Upstream segment.
$ million | ||||||||||||||
2013 | 2012 | 2011 | ||||||||||||
Exploration and evaluation costs |
||||||||||||||
Exploration expenditure written offa |
2,710 | 745 | 1,024 | |||||||||||
Other exploration costs |
731 | 730 | 496 | |||||||||||
Exploration expense for the year |
3,441 | 1,475 | 1,520 | |||||||||||
Impairment losses |
253 | | 7 | |||||||||||
Impairment reversals |
| (42 | ) | | ||||||||||
Intangible assets exploration and appraisal expenditure |
20,865 | 23,434 | 20,433 | |||||||||||
Liabilities |
212 | 287 | 306 | |||||||||||
Net assets |
20,653 | 23,147 | 20,127 | |||||||||||
Capital expenditure |
4,464 | 5,176 | 8,926 | |||||||||||
Net cash used in operating activities |
731 | 730 | 496 | |||||||||||
Net cash used in investing activities |
4,275 | 5,010 | 8,571 |
a | 2013 included an $845-million write-off relating to the value ascribed to block BM-CAL-13 offshore Brazil as a result of the Pitanga exploration well not encountering commercial quantities of oil or gas and a $257-million write-off of costs relating to the Risha concession in Jordan as our exploration activities did not establish the technical basis for a development project in the concession. For further information see Upstream Exploration on page 28. |
The carrying amount, by location, of exploration and appraisal expenditure capitalized as intangible assets at 31 December 2013 is shown in the table below.
Carrying amount | Location | |||||
$1-2 billion |
Angola; US North America gas | |||||
$2-3 billion |
Canada; Egypt; India | |||||
$3-4 billion |
Brazil | |||||
$4-5 billion |
US Gulf of Mexico |
BP Annual Report and Form 20-F 2013 | 155 |
Tax on profit
$ million | ||||||||||||||
2013 | 2012 | 2011 | ||||||||||||
Current tax |
||||||||||||||
Charge for the year |
5,724 | 6,664 | 7,500 | |||||||||||
Adjustment in respect of prior years |
61 | 252 | 111 | |||||||||||
5,785 | 6,916 | 7,611 | ||||||||||||
Deferred tax |
||||||||||||||
Origination and reversal of temporary differences in the current year |
529 | 67 | 5,523 | |||||||||||
Adjustment in respect of prior years |
149 | (103 | ) | (515 | ) | |||||||||
678 | (36 | ) | 5,008 | |||||||||||
Tax charge on profit |
6,463 | 6,880 | 12,619 |
In 2013, the total tax charge recognized within other comprehensive income was $1,374 million (2012 $270 million credit and 2011 $1,490 million credit), and the total tax credit recognized directly in equity was $33 million (2012 $6 million credit and 2011 $7 million credit). See Note 32 for further information.
Reconciliation of the effective tax rate
The following table provides a reconciliation of the UK statutory corporation tax rate to the effective tax rate of the group on profit before taxation. With effect from 1 April 2013 the UK statutory corporation tax rate reduced from 24% to 23% on profits arising from activities outside the North Sea.
$ million | ||||||||||||||
2013 | 2012 | 2011 | ||||||||||||
Profit before taxation |
30,221 | 18,131 | 38,228 | |||||||||||
Tax charge on profit |
6,463 | 6,880 | 12,619 | |||||||||||
Effective tax rate |
21% | 38% | 33% | |||||||||||
% of profit before taxation | ||||||||||||||
UK statutory corporation tax rate |
23 | 24 | 26 | |||||||||||
Increase (decrease) resulting from |
||||||||||||||
UK supplementary and overseas taxes at higher or lower ratesa |
4 | 12 | 14 | |||||||||||
Tax reported in equity-accounted entities |
(2 | ) | (5 | ) | (3 | ) | ||||||||
Adjustments in respect of prior years |
1 | 1 | (1 | ) | ||||||||||
Movement in deferred tax not recognized |
2 | 2 | | |||||||||||
Tax incentives for investment |
(2 | ) | (2 | ) | (1 | ) | ||||||||
Gulf of Mexico oil spill non-deductible costs |
| 8 | | |||||||||||
Permanent differences relating to disposalsb |
(8 | ) | | (2 | ) | |||||||||
Foreign exchange |
2 | (1 | ) | 1 | ||||||||||
Other |
1 | (1 | ) | (1 | ) | |||||||||
Effective tax rate |
21 | 38 | 33 |
a | Jurisdictions which contribute significantly to this item are Angola, with an applicable statutory tax rate of 50%, the UK, currently with an applicable statutory tax rate of 62% for North Sea activities, and Trinidad and Tobago, with an applicable statutory tax rate of 55%. |
b | For 2013, this relates to the non-taxable gain on disposal of our investment in TNK-BP; for 2011, this mainly relates to the sale of our Upstream interests in Columbia. |
156 | BP Annual Report and Form 20-F 2013 |
11. Taxation continued
Deferred tax
$ million | ||||||||||||||||||||||
Income statement | Balance sheet | |||||||||||||||||||||
2013 | 2012 | 2011 | 2013 | 2012 | ||||||||||||||||||
Deferred tax liability |
||||||||||||||||||||||
Depreciation |
(474 | ) | (75 | ) | 4,774 | 31,551 | 32,065 | |||||||||||||||
Pension plan surpluses |
(691 | ) | | | 284 | | ||||||||||||||||
Other taxable temporary differences |
(199 | ) | (2,239 | ) | 141 | 3,653 | 3,671 | |||||||||||||||
(1,364 | ) | (2,314 | ) | 4,915 | 35,488 | 35,736 | ||||||||||||||||
Deferred tax asset |
||||||||||||||||||||||
Pension plan and other post-retirement benefit plan deficits |
787 | (33 | ) | 224 | (2,026 | ) | (3,421 | ) | ||||||||||||||
Decommissioning, environmental and other provisions |
1,385 | 1,872 | (1,443 | ) | (11,301 | ) | (12,705 | ) | ||||||||||||||
Derivative financial instruments |
30 | (7 | ) | 24 | (579 | ) | (281 | ) | ||||||||||||||
Tax credits |
(174 | ) | 1,802 | (401 | ) | (888 | ) | (714 | ) | |||||||||||||
Loss carry forward |
(343 | ) | (911 | ) | (223 | ) | (2,585 | ) | (2,214 | ) | ||||||||||||
Other deductible temporary differences |
357 | (445 | ) | 1,912 | (1,655 | ) | (2,032 | ) | ||||||||||||||
2,042 | 2,278 | 93 | (19,034 | ) | (21,367 | ) | ||||||||||||||||
Net deferred tax charge (credit) and net deferred tax liability |
678 | (36 | ) | 5,008 | 16,454 | 14,369 | ||||||||||||||||
Of which deferred tax liabilities |
17,439 | 15,243 | ||||||||||||||||||||
deferred tax assets |
985 | 874 |
$ million | ||||||||||
Analysis of movements during the year in the net deferred tax liability | 2013 | 2012 | ||||||||
At 1 January |
14,369 | 14,609 | ||||||||
Exchange adjustments |
43 | (27 | ) | |||||||
Charge (credit) for the year on profit |
678 | (36 | ) | |||||||
Charge (credit) for the year in other comprehensive income |
1,397 | (272 | ) | |||||||
Charge (credit) for the year in equity |
(33 | ) | 4 | |||||||
Acquisitions |
| 11 | ||||||||
Reclassified as assets/liabilities held for sale |
| 48 | ||||||||
Deletions |
| 32 | ||||||||
At 31 December |
16,454 | 14,369 |
A summary of temporary differences, unused tax credits and unused tax losses for which deferred tax has not been recognized is shown in the table below.
$ billion | ||||||||||
At 31 December | 2013 | 2012 | ||||||||
Unused tax lossesa |
1.8 | 0.9 | ||||||||
Unused tax credits |
18.0 | 18.3 | ||||||||
of which arising in the UKb |
16.3 | 16.0 | ||||||||
arising in the USc |
1.7 | 2.3 | ||||||||
Other deductible temporary differencesd |
11.2 | 7.0 | ||||||||
Other taxable temporary differences associated with investments in subsidiaries and equity-accounted entities |
0.5 | 0.5 |
a | Substantially all the tax losses have no fixed expiry date. |
b | The UK tax credits arise predominantly in overseas branches of UK entities based in jurisdictions with high tax rates. No deferred tax asset has been recognized on these tax credits as they are unlikely to have value in the future; UK taxes on these overseas branches are largely mitigated by double tax relief on the overseas tax. These tax credits have no fixed expiry date. |
c | The US tax credits expire 10 years after generation and will all expire in the period 2015-2021. |
d | Other deductible temporary differences of $0.7 billion are expected to expire in the period 2014-2020, the remainder do not have an expiry date. |
$ billion | ||||||||||||||
Benefit of previously unrecognized deferred tax on current year tax charge | 2013 | 2012 | 2011 | |||||||||||
Current tax benefit relating to the utilization of previously unrecognized tax losses |
| | 0.1 | |||||||||||
Current tax benefit relating to the utilization of previously unrecognized tax credits |
0.2 | 0.4 | 0.1 | |||||||||||
Deferred tax benefit relating to the recognition of previously unrecognized tax credits |
0.2 | 0.1 | |
BP Annual Report and Form 20-F 2013 | 157 |
The quarterly dividend expected to be paid on 28 March 2014 in respect of the fourth quarter 2013 is 9.5 cents per ordinary share ($0.57 per American Depositary Share (ADS)). The corresponding amount in sterling will be announced on 17 March 2014. A scrip dividend alternative is available, allowing shareholders to elect to receive their dividend in the form of new ordinary shares and ADS holders in the form of new ADSs.
Pence per share | Cents per share | $ million | ||||||||||||||||||||||||||||||||||||
2013 | 2012 | 2011 | 2013 | 2012 | 2011 | 2013 | 2012 | 2011 | ||||||||||||||||||||||||||||||
Dividends announced and paid in cash |
||||||||||||||||||||||||||||||||||||||
Preference shares |
2 | 2 | 2 | |||||||||||||||||||||||||||||||||||
Ordinary shares |
||||||||||||||||||||||||||||||||||||||
March |
6.0013 | 5.0958 | 4.3372 | 9.0 | 8.0 | 7.0 | 1,621 | 1,211 | 808 | |||||||||||||||||||||||||||||
June |
5.8342 | 5.1498 | 4.2809 | 9.0 | 8.0 | 7.0 | 1,399 | 1,448 | 794 | |||||||||||||||||||||||||||||
September |
5.7630 | 5.0171 | 4.3160 | 9.0 | 8.0 | 7.0 | 1,245 | 1,417 | 1,224 | |||||||||||||||||||||||||||||
December |
5.8008 | 5.5890 | 4.4694 | 9.5 | 9.0 | 7.0 | 1,174 | 1,216 | 1,244 | |||||||||||||||||||||||||||||
23.3993 | 20.8517 | 17.4035 | 36.5 | 33.0 | 28.0 | 5,441 | 5,294 | 4,072 | ||||||||||||||||||||||||||||||
Dividend announced, payable in March 2014 |
9.5 | 1,733 |
The details of the scrip dividends issued are shown in the table below.
2013 | 2012 | 2011 | ||||||||||||
Number of shares issued (thousand) |
202,124 | 138,406 | 165,601 | |||||||||||
Value of shares issued ($ million) |
1,470 | 982 | 1,219 |
The financial statements for the year ended 31 December 2013 do not reflect the dividend announced on 4 February 2014 and expected to be paid in March 2014; this will be treated as an appropriation of profit in the year ended 31 December 2014.
13. Earnings per ordinary share
Cents per share | ||||||||||||||
2013 | 2012 | 2011 | ||||||||||||
Basic earnings per share |
123.87 | 57.89 | 133.35 | |||||||||||
Diluted earnings per share |
123.12 | 57.50 | 131.74 |
Basic earnings per ordinary share amounts are calculated by dividing the profit for the year attributable to ordinary shareholders by the weighted average number of ordinary shares outstanding during the year. The average number of shares outstanding excludes treasury shares and the shares held by the Employee Share Ownership Plan trusts (ESOPs) and includes certain shares that will be issuable in the future under employee share-based payment plans.
For the diluted earnings per share calculation, the weighted average number of shares outstanding during the year is adjusted for the dilutive effect of shares that are potentially issuable in connection with employee share-based payment plans using the treasury stock method.
$ million | ||||||||||||||
2013 | 2012 | 2011 | ||||||||||||
Profit attributable to BP shareholders |
23,451 | 11,017 | 25,212 | |||||||||||
Less: dividend requirements on preference shares |
2 | 2 | 2 | |||||||||||
Profit for the year attributable to BP ordinary shareholders |
23,449 | 11,015 | 25,210 |
Shares thousand |
||||||||||||||
2013 | 2012 | 2011 | ||||||||||||
Basic weighted average number of ordinary shares |
18,931,021 | 19,027,929 | 18,904,812 | |||||||||||
Potential dilutive effect of ordinary shares issuable under employee share-based payment plans |
115,152 | 129,959 | 231,388 | |||||||||||
19,046,173 | 19,157,888 | 19,136,200 |
The number of ordinary shares outstanding at 31 December 2013, excluding treasury shares and the shares held by the ESOPs, and including certain shares that will be issuable in the future under employee share-based payment plans was 18,611,489,958. Between 31 December 2013 and 18 February 2014, the latest practicable date before the completion of these financial statements, there was a net decrease of 171,061,543 in the number of ordinary shares outstanding as a result of share issues in relation to employee share-based payment plans. During the same period, the group repurchased 195 million of its own ordinary shares as part of the share repurchase programme announced on 22 March 2013.
Employee share-based payment plans
The group operates share and share option plans for directors and certain employees to obtain ordinary shares and ADSs in the company. Information on these plans for directors is shown in the Directors remuneration report on page 81.
158 | BP Annual Report and Form 20-F 2013 |
13. Earnings per ordinary share continued
The following table shows the number of shares potentially issuable under employee share option plans, including the number of options outstanding, the number of options exercisable at the end of each year, and the corresponding weighted average exercise prices. The dilutive effect of the employee share option plans at 31 December included in the diluted earnings per share is also shown.
Share options | 2013 | 2012 | ||||||||||||||||
Number of thousand |
Weighted average exercise price $ |
Number of thousand |
Weighted average exercise price $ |
|||||||||||||||
Outstanding |
286,725 | 7.71 | 324,096 | 7.62 | ||||||||||||||
Exercisable |
127,290 | 10.01 | 159,419 | 9.33 | ||||||||||||||
Dilutive effect |
23,169 | n/a | 16,435 | n/a |
a | Numbers of options shown are ordinary share equivalents (one ADS is equivalent to six ordinary shares). |
b | At 31 December 2013, the quoted market price of one BP ordinary share was $8.10 (2012 $6.94). |
In addition, the group operates a number of equity-settled employee share plans under which share units are granted to the groups senior leaders and certain other employees. These plans typically have a three-year performance or restricted period during which the units accrue net notional dividends which are treated as having been reinvested. Leaving employment will normally preclude the conversion of units into shares, but special arrangements apply for participants that leave for qualifying reasons. The number of shares that are expected to vest each year under employee share plans are shown in the table below. The dilutive effect of the employee share plans at 31 December included in the diluted earnings per share is also shown.
Shares | 2013 | 2012 | ||||||||
Vesting | Number of thousand |
Number of thousand |
||||||||
Within one year |
35,442 | 29,138 | ||||||||
1 to 2 years |
120,056 | 67,593 | ||||||||
2 to 3 years |
115,387 | 120,621 | ||||||||
3 to 4 years |
14,231 | 25,066 | ||||||||
4 to 5 years |
123 | 233 | ||||||||
285,239 | 242,651 | |||||||||
Dilutive effect |
95,014 | 95,683 |
a | Numbers of shares shown are ordinary share equivalents (one ADS is equivalent to six ordinary shares). |
There has been a net decrease of 32,378,757 in the number of potential ordinary shares in relation to employee share-based payment plans between 31 December 2013 and 18 February 2014.
BP Annual Report and Form 20-F 2013 | 159 |
14. Property, plant and equipment
$ million | ||||||||||||||||||||||||||||||||||
Land and land |
Buildings | Oil and gas properties |
Plant, machinery and equipment |
Fixtures, fittings and office equipment |
Transportation | Oil depots, storage tanks and service stations |
Total | |||||||||||||||||||||||||||
Cost |
||||||||||||||||||||||||||||||||||
At 1 January 2013 |
3,279 | 2,812 | 171,772 | 45,200 | 3,346 | 13,436 | 9,059 | 248,904 | ||||||||||||||||||||||||||
Exchange adjustments |
(4 | ) | (26 | ) | | (235 | ) | 5 | (55 | ) | (36 | ) | (351 | ) | ||||||||||||||||||||
Additions |
120 | 286 | 14,272 | 4,386 | 299 | 51 | 625 | 20,039 | ||||||||||||||||||||||||||
Acquisitions |
| | | 8 | | | | 8 | ||||||||||||||||||||||||||
Transfers |
| | 4,365 | | | | | 4,365 | ||||||||||||||||||||||||||
Deletions |
(20 | ) | (45 | ) | (2,718 | ) | (447 | ) | (474 | ) | (118 | ) | (257 | ) | (4,079 | ) | ||||||||||||||||||
At 31 December 2013 |
3,375 | 3,027 | 187,691 | 48,912 | 3,176 | 13,314 | 9,391 | 268,886 | ||||||||||||||||||||||||||
Depreciation |
||||||||||||||||||||||||||||||||||
At 1 January 2013 |
514 | 1,023 | 87,965 | 18,628 | 2,119 | 8,409 | 4,915 | 123,573 | ||||||||||||||||||||||||||
Exchange adjustments |
(6 | ) | (1 | ) | | (61 | ) | 7 | (28 | ) | (7 | ) | (96 | ) | ||||||||||||||||||||
Charge for the year |
37 | 129 | 10,334 | 1,616 | 278 | 347 | 502 | 13,243 | ||||||||||||||||||||||||||
Impairment losses |
10 | 20 | 611 | 525 | | 160 | 35 | 1,361 | ||||||||||||||||||||||||||
Impairment reversals |
| | (209 | ) | | | (17 | ) | | (226 | ) | |||||||||||||||||||||||
Transfers |
| | 365 | | | | | 365 | ||||||||||||||||||||||||||
Deletions |
(5 | ) | (30 | ) | (2,003 | ) | (330 | ) | (434 | ) | (38 | ) | (184 | ) | (3,024 | ) | ||||||||||||||||||
At 31 December 2013 |
550 | 1,141 | 97,063 | 20,378 | 1,970 | 8,833 | 5,261 | 135,196 | ||||||||||||||||||||||||||
Net book amount at 31 December 2013 |
2,825 | 1,886 | 90,628 | 28,534 | 1,206 | 4,481 | 4,130 | 133,690 | ||||||||||||||||||||||||||
Cost |
||||||||||||||||||||||||||||||||||
At 1 January 2012 |
3,169 | 2,942 | 176,988 | 41,319 | 3,140 | 12,753 | 8,611 | 248,922 | ||||||||||||||||||||||||||
Exchange adjustments |
86 | 14 | | 320 | 28 | 8 | 272 | 728 | ||||||||||||||||||||||||||
Additions |
120 | 387 | 16,303 | 4,481 | 314 | 902 | 533 | 23,040 | ||||||||||||||||||||||||||
Acquisitions |
| | 44 | 2 | | 15 | | 61 | ||||||||||||||||||||||||||
Transfers |
| | 1,306 | | | | | 1,306 | ||||||||||||||||||||||||||
Reclassified as assets held for sale |
| | (19,410 | ) | (143 | ) | | (172 | ) | (2 | ) | (19,727 | ) | |||||||||||||||||||||
Deletions |
(96 | ) | (531 | ) | (3,459 | ) | (779 | ) | (136 | ) | (70 | ) | (355 | ) | (5,426 | ) | ||||||||||||||||||
At 31 December 2012 |
3,279 | 2,812 | 171,772 | 45,200 | 3,346 | 13,436 | 9,059 | 248,904 | ||||||||||||||||||||||||||
Depreciation |
||||||||||||||||||||||||||||||||||
At 1 January 2012 |
511 | 1,411 | 91,994 | 16,915 | 1,940 | 8,149 | 4,571 | 125,491 | ||||||||||||||||||||||||||
Exchange adjustments |
8 | 13 | | 228 | 25 | 6 | 151 | 431 | ||||||||||||||||||||||||||
Charge for the year |
33 | 123 | 9,659 | 1,442 | 289 | 320 | 504 | 12,370 | ||||||||||||||||||||||||||
Impairment losses |
8 | | 2,765 | 493 | | 70 | 7 | 3,343 | ||||||||||||||||||||||||||
Impairment reversals |
| | (221 | ) | | | | (1 | ) | (222 | ) | |||||||||||||||||||||||
Reclassified as assets held for sale |
| | (13,774 | ) | (36 | ) | | (126 | ) | (2 | ) | (13,938 | ) | |||||||||||||||||||||
Deletions |
(46 | ) | (524 | ) | (2,458 | ) | (414 | ) | (135 | ) | (10 | ) | (315 | ) | (3,902 | ) | ||||||||||||||||||
At 31 December 2012 |
514 | 1,023 | 87,965 | 18,628 | 2,119 | 8,409 | 4,915 | 123,573 | ||||||||||||||||||||||||||
Net book amount at 31 December 2012 |
2,765 | 1,789 | 83,807 | 26,572 | 1,227 | 5,027 | 4,144 | 125,331 | ||||||||||||||||||||||||||
Net book amount at 1 January 2012 |
2,658 | 1,531 | 84,994 | 24,404 | 1,200 | 4,604 | 4,040 | 123,431 | ||||||||||||||||||||||||||
Assets held under finance leases at net book amount included above | ||||||||||||||||||||||||||||||||||
At 31 December 2013 |
| 7 | 187 | 265 | | 4 | | 463 | ||||||||||||||||||||||||||
At 31 December 2012 |
| 9 | 157 | 254 | | 9 | | 429 | ||||||||||||||||||||||||||
Assets under construction included above | ||||||||||||||||||||||||||||||||||
At 31 December 2013 |
27,900 | |||||||||||||||||||||||||||||||||
At 31 December 2012 |
29,203 |
160 | BP Annual Report and Form 20-F 2013 |
15. Goodwill and impairment review of goodwill
$ million | ||||||||||
2013 | 2012 | |||||||||
Cost |
||||||||||
At 1 January |
12,804 | 14,041 | ||||||||
Exchange adjustments |
46 | 160 | ||||||||
Acquisitions |
44 | 25 | ||||||||
Reclassified as assets held for sale |
| (1,327 | ) | |||||||
Deletions |
(43 | ) | (95 | ) | ||||||
At 31 December |
12,851 | 12,804 | ||||||||
Impairment losses |
||||||||||
At 1 January |
614 | 1,612 | ||||||||
Impairment losses for the year |
56 | | ||||||||
Reclassified as assets held for sale |
| (977 | ) | |||||||
Deletions |
| (21 | ) | |||||||
At 31 December |
670 | 614 | ||||||||
Net book amount at 31 December |
12,181 | 12,190 | ||||||||
Net book amount at 1 January |
12,190 | 12,429 |
Impairment review of goodwill
$ million | ||||||||||
Goodwill at 31 December | 2013 | 2012 | ||||||||
Upstream |
7,812 | 7,862 | ||||||||
Downstream |
4,277 | 4,168 | ||||||||
Other businesses and corporate |
92 | 160 | ||||||||
12,181 | 12,190 |
Goodwill acquired through business combinations has been allocated to groups of cash-generating units that are expected to benefit from the synergies of the acquisition. For Upstream, goodwill is allocated to all oil and gas assets in aggregate at the segment level. For Downstream, goodwill has been allocated to the Rhine fuels value chain (FVC), Lubricants and Other.
In assessing whether goodwill has been impaired, the carrying amount of the cash-generating unit (CGU) or groups of CGUs (including goodwill) is compared with the recoverable amount of the CGU or groups of CGUs. The recoverable amount is the higher of fair value less costs to sell and value in use. In the absence of readily available information about the fair value of a cash-generating unit, the recoverable amount is deemed to be the value in use for the purposes of performing an impairment test of goodwill, unless this would lead to an impairment loss. If goodwill would be impaired using value in use as the recoverable amount, a fair value less costs to sell assessment would be performed as this may lead to a higher recoverable amount.
The group calculates the value in use using a discounted cash flow model. The future cash flows are adjusted for risks specific to the cash-generating unit and are discounted using a pre-tax discount rate. The discount rate is derived from the groups post-tax weighted average cost of capital and is adjusted where applicable to take into account any specific risks relating to the country where the cash-generating unit is located. The rate to be applied to each country is reassessed each year. Discount rates of 12% and 14% have been used for goodwill impairment calculations performed in 2013 (2012 12% and 14%).
The business segment plans, which are approved on an annual basis by senior management, are the primary source of information for the determination of value in use. They contain forecasts for oil and natural gas production, refinery throughputs, sales volumes for various types of refined products (e.g. gasoline and lubricants), revenues, costs and capital expenditure. As an initial step in the preparation of these plans, various environmental assumptions, such as oil prices, natural gas prices, refining margins, refined product margins and cost inflation rates, are set by senior management. These environmental assumptions take account of existing prices, global supply-demand equilibrium for oil and natural gas, other macroeconomic factors and historical trends and variability.
Upstream
$ million | ||||||||||
2013 | 2012 | |||||||||
Goodwill |
7,812 | 7,862 | ||||||||
Excess of recoverable amount over carrying amount |
6,811 | 25,871 |
The table above shows the carrying amount of the goodwill for the segment and the excess of the recoverable amount, based upon a value in use calculation, over the carrying amount (the headroom).
The value in use is based on the cash flows expected to be generated by the projected oil or natural gas production profiles up to the expected dates of cessation of production of each producing field, based on current estimates of reserves. As the production profile and related cash flows can be estimated from BPs past experience, management believes that the cash flows generated over the estimated life of field is the appropriate basis upon which to assess goodwill and individual assets for impairment. The date of cessation of production depends on the interaction of a number of variables, such as the recoverable quantities of hydrocarbons, the production profile of the hydrocarbons, the cost of the development of the infrastructure necessary to recover the hydrocarbons, the production costs, the contractual duration of the production concession and the selling price of the hydrocarbons produced. As each producing field has specific reservoir characteristics and economic circumstances, the cash flows of the fields are computed using appropriate individual economic models and key assumptions agreed by BPs management. Capital expenditure, operating costs and expected hydrocarbon production profiles up to 2023 are derived from the business segment plan. Estimated production volumes and cash flows up to the date of cessation of production on a field-by-field basis are developed to be consistent with this. The production profiles used are consistent with the reserve volumes approved as part of BPs centrally controlled process for the estimation of proved and probable reserves and total resources.
BP Annual Report and Form 20-F 2013 | 161 |
15. Goodwill and impairment review of goodwill continued
Intangible assets are deemed to have a recoverable amount equal to their carrying amount. Consistent with prior years, the 2013 review for impairment was carried out during the fourth quarter.
The Brent oil price and Henry Hub natural gas price assumptions used in the impairment review of goodwill are shown in the table below.
2013 | ||||||||||||||||||||||||||
2014 | 2015 | 2016 | 2017 | 2018 | 2019 and thereafter |
|||||||||||||||||||||
Brent oil price ($/bbl) |
108 | 102 | 97 | 93 | 90 | 90 | ||||||||||||||||||||
Henry Hub natural gas price ($/mmBtu) |
3.86 | 4.02 | 4.10 | 4.17 | 4.27 | 6.50 | ||||||||||||||||||||
2012 | ||||||||||||||||||||||||||
2013 | 2014 | 2015 | 2016 | 2017 | 2018 and thereafter |
|||||||||||||||||||||
Brent oil price ($/bbl) |
105 | 100 | 96 | 93 | 91 | 90 | ||||||||||||||||||||
Henry Hub natural gas price ($/mmBtu) |
3.96 | 4.25 | 4.42 | 4.61 | 4.82 | 6.50 |
Key assumptions for oil and gas prices for the first five years were derived from forward price curves in the fourth quarter. Prices in 2019 and beyond were determined using long-term views of global supply and demand, building upon past experience of the industry and using information from external sources. These prices were adjusted to arrive at appropriate consistent price assumptions for different qualities of oil and gas, or where appropriate, contracted oil and gas prices were applied.
The key assumptions required for the value-in-use estimation are the oil and natural gas prices, production volumes and the discount rate. The sensitivity of the headroom to changes in the key assumptions was estimated. Due to the non-linear relationship of different variables, the calculations were performed using a number of simplifying assumptions, including assuming a change to the variable being tested only, therefore a detailed calculation at any given price may produce a different result.
It is estimated that if the oil price assumption for all future years was approximately equal to the current assumption for 2019 and beyond, this would cause the recoverable amount to be equal to the carrying amount of goodwill and related non-current assets of the segment. It is estimated that if the price assumption for natural gas was around 24% lower than the current assumption for 2019 and beyond the headroom would be reduced to zero.
Estimated production volumes are based on detailed data for each field and take into account development plans agreed by management as part of the long-term planning process. The average production for the purposes of goodwill impairment testing over the next 15 years is 597mmboe per year (2012 576mmboe per year). It is estimated that if this production volume were to be reduced by around 2% for the whole period, this would cause the recoverable amount to be equal to the carrying amount of goodwill and related non-current assets of the segment.
It is estimated that if the discount rate was approximately 14% for the entire portfolio this would cause the recoverable amount to be equal to the carrying amount of goodwill and related non-current assets of the segment.
Downstream
$ million | ||||||||||||||||||||||||||||||||||
2013 | 2012 | |||||||||||||||||||||||||||||||||
Rhine FVC | Lubricants | Other | Total | Rhine FVC | Lubricants | Other | Total | |||||||||||||||||||||||||||
Goodwill |
643 | 3,518 | 116 | 4,277 | 627 | 3,441 | 100 | 4,168 | ||||||||||||||||||||||||||
Excess of recoverable amount over carrying amount |
2,759 | n/a | n/a | n/a | 2,411 | n/a | n/a | n/a |
Cash flows for each cash-generating unit are derived from the business segment plans, which cover a period of two to five years. To determine the value in use for each of the cash-generating units, cash flows for a period of 10 years are discounted and aggregated with a terminal value.
Rhine FVC
The key assumptions to which the calculation of value in use for the Rhine FVC is most sensitive are refinery gross margins, throughput volumes and discount rate. Gross margin assumptions used in the Rhine FVC plan are consistent with those used to develop the regional Refining Marker Margin (RMM). The average values assigned to the regional RMM and refinery throughput volume over the plan period are $12.35 per barrel and 250mmbbl per year (2012 $12.30 per barrel and 246mmbbl per year). These values reflect past experience and are consistent with external sources. Cash flows beyond the five-year plan period are extrapolated using a nominal 4% growth rate (2012 4%).
No reasonably possible change in the discount rate would cause the Rhine FVC units carrying amount to exceed its recoverable amount. It is estimated that if the refinery margin assumption was $1.9 per barrel lower than the current assumption, the recoverable amount would equal the carrying amount. It is also estimated that if the refinery throughput volume assumption was 32mmbbl per year lower than the current assumption, the recoverable amount would equal the carrying amount.
Lubricants
In certain circumstances IAS 36 allows the use of the most recent detailed calculations of the recoverable amount performed in an earlier period as the basis for the current years goodwill impairment test. The most recent detailed calculation of the Lubricants units recoverable amount was performed in 2009 and this was used as the basis for the tests in 2010-2012 as the criteria of IAS 36 were met in each of those years. IAS 36 does not specify for how many years such an approach is appropriate and management determined that a re-performance of the test was appropriate in 2013 given the passage of time since 2009. There was no significant change in the outcome of this test compared to that in 2009.
The key assumptions to which the calculation of the value in use for the Lubricants unit is most sensitive are operating margins, sales volumes, and discount rate. Operating margin and sales volumes assumptions used in the detailed impairment review of goodwill calculation are consistent with the assumptions used in the Lubricant units business plan and values assigned to these key assumptions reflect past experience. No reasonably possible change in any of these key assumptions would cause the units carrying amount to exceed its recoverable amount. Cash flows beyond the plan period are extrapolated using a 3% growth rate (2009 3%).
162 | BP Annual Report and Form 20-F 2013 |
$ million | ||||||||||||||||||||||||||
2013 | 2012 | |||||||||||||||||||||||||
Exploration and appraisal expenditure |
Other intangibles |
Total | Exploration and appraisal expenditure |
Other intangibles |
Total | |||||||||||||||||||||
Cost |
||||||||||||||||||||||||||
At 1 January |
24,511 | 3,739 | 28,250 | 21,216 | 3,500 | 24,716 | ||||||||||||||||||||
Exchange adjustments |
| (5 | ) | (5 | ) | | 50 | 50 | ||||||||||||||||||
Acquisitions |
| | | (68 | ) | 80 | 12 | |||||||||||||||||||
Additions |
4,464 | 336 | 4,800 | 5,244 | 343 | 5,587 | ||||||||||||||||||||
Transfers |
(4,365 | ) | | (4,365 | ) | (1,306 | ) | | (1,306 | ) | ||||||||||||||||
Reclassified as assets held for sale |
| | | (67 | ) | (26 | ) | (93 | ) | |||||||||||||||||
Deletions |
(2,868 | ) | (134 | ) | (3,002 | ) | (508 | ) | (208 | ) | (716 | ) | ||||||||||||||
At 31 December |
21,742 | 3,936 | 25,678 | 24,511 | 3,739 | 28,250 | ||||||||||||||||||||
Amortization |
||||||||||||||||||||||||||
At 1 January |
1,077 | 2,541 | 3,618 | 783 | 2,280 | 3,063 | ||||||||||||||||||||
Exchange adjustments |
| (2 | ) | (2 | ) | | 25 | 25 | ||||||||||||||||||
Charge for the year |
2,710 | 267 | 2,977 | 745 | 317 | 1,062 | ||||||||||||||||||||
Impairment losses |
253 | 85 | 338 | | 126 | 126 | ||||||||||||||||||||
Impairment reversals |
| | | (42 | ) | | (42 | ) | ||||||||||||||||||
Transfers |
(365 | ) | | (365 | ) | | | | ||||||||||||||||||
Reclassified as assets held for sale |
| | | | (21 | ) | (21 | ) | ||||||||||||||||||
Deletions |
(2,798 | ) | (129 | ) | (2,927 | ) | (409 | ) | (186 | ) | (595 | ) | ||||||||||||||
At 31 December |
877 | 2,762 | 3,639 | 1,077 | 2,541 | 3,618 | ||||||||||||||||||||
Net book amount at 31 December |
20,865 | 1,174 | 22,039 | 23,434 | 1,198 | 24,632 | ||||||||||||||||||||
Net book amount at 1 January |
23,434 | 1,198 | 24,632 | 20,433 | 1,220 | 21,653 |
17. Investments in joint ventures
The significant joint ventures of the BP group at 31 December 2013 are shown in Note 38. Summarized financial information for the groups share of joint ventures is shown below. Balance sheet information shown below excludes data relating to joint ventures classified as assets held for sale as at the end of the period. Income statement information shown below includes data relating to joint ventures reclassified as assets held for sale during the period up until the date of reclassification. The group does not have any individually material joint ventures.
The following table provides aggregated summarized financial information relating to the groups share of joint ventures.
$ million | ||||||||||||||
2013 | 2012 | 2011 | ||||||||||||
Sales and other operating revenues |
12,507 | 12,507 | 11,993 | |||||||||||
Profit before interest and taxation |
1,076 | 778 | 1,315 | |||||||||||
Finance costs |
130 | 113 | 115 | |||||||||||
Profit before taxation |
946 | 665 | 1,200 | |||||||||||
Taxation |
499 | 405 | 433 | |||||||||||
Profit for the year |
447 | 260 | 767 | |||||||||||
Other comprehensive income |
38 | (52 | ) | | ||||||||||
Total comprehensive income |
485 | 208 | 767 | |||||||||||
Non-current assets |
11,576 | 11,147 | ||||||||||||
Current assets |
3,095 | 2,931 | ||||||||||||
Total assets |
14,671 | 14,078 | ||||||||||||
Current liabilities |
2,276 | 2,350 | ||||||||||||
Non-current liabilities |
3,499 | 3,379 | ||||||||||||
Total liabilities |
5,775 | 5,729 | ||||||||||||
8,896 | 8,349 | |||||||||||||
Group investment in joint ventures |
||||||||||||||
Group share of net assets (as above) |
8,896 | 8,349 | ||||||||||||
Loans made by group companies to joint ventures |
303 | 265 | ||||||||||||
9,199 | 8,614 |
BP Annual Report and Form 20-F 2013 | 163 |
17. Investments in joint ventures continued
Transactions between the group and its joint ventures are summarized below.
$ million | ||||||||||||||||||||||||||
Sales to joint ventures | 2013 | 2012 | 2011 | |||||||||||||||||||||||
Product | Sales | Amount receivable at 31 December |
Sales | Amount receivable at 31 December |
Sales | Amount receivable at 31 December |
||||||||||||||||||||
LNG, crude oil and oil products, natural gas, employee services |
4,125 | 342 | 4,272 | 379 | 3,196 | 423 | ||||||||||||||||||||
$ million | ||||||||||||||||||||||||||
Purchases from joint ventures | 2013 | 2012 | 2011 | |||||||||||||||||||||||
Product | Purchases | Amount payable at 31 December |
Purchases | Amount payable at 31 December |
Purchases | Amount payable at 31 December |
||||||||||||||||||||
LNG, crude oil and oil products, natural gas, refinery operating costs, plant processing fees |
503 | 51 | 1,107 | 116 | 1,165 | 62 |
The terms of the outstanding balances receivable from joint ventures are typically 30 to 45 days. The balances are unsecured and will be settled in cash. There are no significant provisions for doubtful debts relating to these balances and no significant expense recognized in the income statement in respect of bad or doubtful debts. Dividends receivable are not included in the table above.
BP has commitments amounting to $21 million (2012 $53 million) in relation to contracts with joint ventures for the purchase of LNG, crude oil and oil products, refinery operating costs and storage and handling services. See Note 36 for further information on capital commitments relating to BPs investments in joint ventures.
The following table provides aggregated financial information for the groups associates as it relates to the amounts recognized in the group income statement and on the group balance sheet.
$ million | ||||||||||||||||||||||||||
Earnings from associates after interest and tax |
Investments in associates |
|||||||||||||||||||||||||
2013 | 2012 | 2011 | 2013 | 2012 | 2011 | |||||||||||||||||||||
Rosneft |
2,058 | | | 13,681 | | | ||||||||||||||||||||
TNK-BP |
| 2,986 | 4,185 | | | 10,013 | ||||||||||||||||||||
Other associates |
684 | 689 | 731 | 2,955 | 2,998 | 3,278 | ||||||||||||||||||||
2,742 | 3,675 | 4,916 | 16,636 | 2,998 | 13,291 |
The associate that is material to the group at 31 December 2013 is Rosneft (2012 TNK-BP). In 2013, BP concluded transactions to sell its 50% interest in TNK-BP to Rosneft and to increase BPs investment in Rosneft. BP and Rosneft announced heads of terms for this transaction on 22 October 2012, after which our investment in TNK-BP was classified as an asset held for sale and therefore equity accounting ceased. See below and Note 6 for further information. Other significant associates of the BP group at 31 December 2013 are shown in Note 38.
At 31 December 2013, and since the transaction described in Note 6 concluded on 21 March 2013, BP owned 19.75% of the voting shares of OJSC Oil Company Rosneft (Rosneft), a Russian oil and gas company. Rosneft shares are listed on the MICEX stock exchange in Moscow and its global depository receipts are listed on the London Stock Exchange. The Russian federal government, through its investment company OJSC Rosneftegaz, owned 69.5% of the voting shares of Rosneft at 31 December 2013.
BP uses the equity method of accounting for its investment in Rosneft because in managements judgement BP has significant influence over Rosneft, see Note 1 Interests in other entities significant estimate or judgement for further information.
164 | BP Annual Report and Form 20-F 2013 |
18. Investments in associates continued
The following table provides summarized financial information at 100% share relating to each of the groups material associates.
$ million | ||||||||||||||
Gross amount | ||||||||||||||
2013 | 2012 | 2011 | ||||||||||||
Rosneft | TNK-BPa | TNK-BP | ||||||||||||
Sales and other operating revenues |
122,866 | 49,350 | 60,200 | |||||||||||
Profit before interest and taxation |
14,106 | 8,810 | 11,984 | |||||||||||
Finance costs |
1,337 | 168 | 264 | |||||||||||
Profit before taxation |
12,769 | 8,642 | 11,720 | |||||||||||
Taxation |
2,137 | 1,958 | 2,666 | |||||||||||
Non-controlling interests |
213 | 712 | 684 | |||||||||||
Profit for the year |
10,419 | 5,972 | 8,370 | |||||||||||
Other comprehensive income |
(441 | ) | 26 | (77 | ) | |||||||||
Total comprehensive income |
9,978 | 5,998 | 8,293 | |||||||||||
Non-current assets |
149,149 | |||||||||||||
Current assets |
48,775 | |||||||||||||
Total assets |
197,924 | |||||||||||||
Current liabilities |
43,175 | |||||||||||||
Non-current liabilities |
83,458 | |||||||||||||
Total liabilities |
126,633 | |||||||||||||
Non-controlling interests |
2,020 | |||||||||||||
69,271 |
a | BP ceased equity accounting for TNK-BP on 22 October 2012. See Note 6 for further information. |
The group received dividends of $456 million from Rosneft in 2013, net of withholding tax (2012 dividends of $709 million from TNK-BP and 2011 dividends of $3,747 million from TNK-BP).
Summarized financial information for the groups share of associates is shown below. Balance sheet information shown below does not include data relating to associates classified as assets held for sale as at the end of the period. Income statement and other comprehensive income information shown below includes data relating to associates classified as assets held for sale during the period prior to their classification as assets held for sale.
$ million | ||||||||||||||||||||||||||||||||||||||
BP share | ||||||||||||||||||||||||||||||||||||||
2013 | 2012 | 2011 | ||||||||||||||||||||||||||||||||||||
Rosnefta | Other | Total | TNK-BPb | Other | Total | TNK-BP | Other | Total | ||||||||||||||||||||||||||||||
Sales and other operating revenues |
24,266 | 7,967 | 32,233 | 24,675 | 11,965 | 36,640 | 30,100 | 12,145 | 42,245 | |||||||||||||||||||||||||||||
Profit before interest and taxation |
2,786 | 908 | 3,694 | 4,405 | 906 | 5,311 | 5,992 | 958 | 6,950 | |||||||||||||||||||||||||||||
Finance costs |
264 | 11 | 275 | 84 | 16 | 100 | 132 | 13 | 145 | |||||||||||||||||||||||||||||
Profit before taxation |
2,522 | 897 | 3,419 | 4,321 | 890 | 5,211 | 5,860 | 945 | 6,805 | |||||||||||||||||||||||||||||
Taxation |
422 | 213 | 635 | 979 | 201 | 1,180 | 1,333 | 214 | 1,547 | |||||||||||||||||||||||||||||
Non-controlling interests |
42 | | 42 | 356 | | 356 | 342 | | 342 | |||||||||||||||||||||||||||||
Profit for the year |
2,058 | 684 | 2,742 | 2,986 | 689 | 3,675 | 4,185 | 731 | 4,916 | |||||||||||||||||||||||||||||
Other comprehensive income |
(87 | ) | 2 | (85 | ) | 13 | (6 | ) | 7 | (39 | ) | | (39 | ) | ||||||||||||||||||||||||
Total comprehensive income |
1,971 | 686 | 2,657 | 2,999 | 683 | 3,682 | 4,146 | 731 | 4,877 | |||||||||||||||||||||||||||||
Non-current assets |
29,457 | 3,148 | 32,605 | | 3,270 | 3,270 | ||||||||||||||||||||||||||||||||
Current assets |
9,633 | 2,477 | 12,110 | | 2,399 | 2,399 | ||||||||||||||||||||||||||||||||
Total assets |
39,090 | 5,625 | 44,715 | | 5,669 | 5,669 | ||||||||||||||||||||||||||||||||
Current liabilities |
8,527 | 2,114 | 10,641 | | 2,126 | 2,126 | ||||||||||||||||||||||||||||||||
Non-current liabilities |
16,483 | 1,053 | 17,536 | | 1,290 | 1,290 | ||||||||||||||||||||||||||||||||
Total liabilities |
25,010 | 3,167 | 28,177 | | 3,416 | 3,416 | ||||||||||||||||||||||||||||||||
Non-controlling interests |
399 | | 399 | | | | ||||||||||||||||||||||||||||||||
13,681 | 2,458 | 16,139 | | 2,253 | 2,253 | |||||||||||||||||||||||||||||||||
Group investment in associates |
||||||||||||||||||||||||||||||||||||||
Group share of net assets (as above) |
13,681 | 2,458 | 16,139 | | 2,253 | 2,253 | ||||||||||||||||||||||||||||||||
Loans made by group companies to associates |
| 497 | 497 | | 745 | 745 | ||||||||||||||||||||||||||||||||
13,681 | 2,955 | 16,636 | | 2,998 | 2,998 |
a | The fair value of BPs 19.75% stake in Rosneft was $15,937 million at 31 December 2013 based on the quoted market share price of $7.62 per share. |
b | BP ceased equity accounting for TNK-BP on 22 October 2012. See Note 6 for further information. |
BP Annual Report and Form 20-F 2013 | 165 |
18. Investments in associates continued
Transactions between the group and its associates are summarized below.
$ million | ||||||||||||||||||||||||||
Sales to associates | 2013 | 2012 | 2011 | |||||||||||||||||||||||
Product | Sales | Amount receivable at 31 December |
Sales | Amount receivable at 31 December |
Sales | Amount receivable at 31 December |
||||||||||||||||||||
LNG, crude oil and oil products, natural gas, employee services |
5,170 | 783 | 3,771 | 401 | 3,855 | 393 | ||||||||||||||||||||
$ million | ||||||||||||||||||||||||||
Purchases from associates | 2013 | 2012 | 2011 | |||||||||||||||||||||||
Product | Purchases | Amount payable at 31 December |
Purchases | Amount payable at 31 December |
Purchases | Amount payable at 31 December |
||||||||||||||||||||
Crude oil and oil products, natural gas, transportation tariff |
21,205 | 3,470 | 9,135 | 932 | 8,159 | 815 |
The terms of the outstanding balances receivable from associates are typically 30 to 45 days. The balances are unsecured and will be settled in cash. There are no significant provisions for doubtful debts relating to these balances and no significant expense recognized in the income statement in respect of bad or doubtful debts. Dividends receivable are not included in the table above.
The majority of the purchases from associates are crude oil and oil products purchased from Rosneft. BP has commitments amounting to $6,077 million (2012 $595 million) in relation to contracts with its associates for the purchase of crude oil and oil products, transportation and storage. See Note 36 for further information on capital commitments relating to BPs investments in associates.
19. Financial instruments and financial risk factors
The accounting classification of each category of financial instruments, and their carrying amounts, are set out below.
$ million | ||||||||||||||||||||||||||||||||||
At 31 December 2013 | Note | Loans and receivables |
Available- for-sale financial |
Held-to- maturity investments |
At fair value through profit or loss |
Derivative hedging instruments |
Financial liabilities |
Total carrying amount |
||||||||||||||||||||||||||
Financial assets |
||||||||||||||||||||||||||||||||||
Other investments equity shares |
20 | | 291 | | | | | 291 | ||||||||||||||||||||||||||
other |
20 | | 1,167 | | 574 | | | 1,741 | ||||||||||||||||||||||||||
Loans |
979 | | | | | | 979 | |||||||||||||||||||||||||||
Trade and other receivables |
22 | 39,630 | | | | | | 39,630 | ||||||||||||||||||||||||||
Derivative financial instruments |
26 | | | | 5,189 | 995 | | 6,184 | ||||||||||||||||||||||||||
Cash and cash equivalents |
23 | 19,153 | 2,267 | 1,100 | | | | 22,520 | ||||||||||||||||||||||||||
Financial liabilities |
||||||||||||||||||||||||||||||||||
Trade and other payables |
25 | | | | | | (48,072 | ) | (48,072 | ) | ||||||||||||||||||||||||
Derivative financial instruments |
26 | | | | (4,159 | ) | (388 | ) | | (4,547 | ) | |||||||||||||||||||||||
Accruals |
| | | | | (9,507 | ) | (9,507 | ) | |||||||||||||||||||||||||
Finance debt |
27 | | | | | | (48,192 | ) | (48,192 | ) | ||||||||||||||||||||||||
59,762 | 3,725 | 1,100 | 1,604 | 607 | (105,771 | ) | (38,973 | ) | ||||||||||||||||||||||||||
At 31 December 2012 | ||||||||||||||||||||||||||||||||||
Financial assets |
||||||||||||||||||||||||||||||||||
Other investments equity shares |
20 | | 1,433 | | | | | 1,433 | ||||||||||||||||||||||||||
other |
20 | | 1,005 | | 585 | | | 1,590 | ||||||||||||||||||||||||||
Loans |
889 | | | | | | 889 | |||||||||||||||||||||||||||
Trade and other receivables |
22 | 35,962 | | | | | | 35,962 | ||||||||||||||||||||||||||
Derivative financial instruments |
26 | | | | 5,342 | 3,459 | | 8,801 | ||||||||||||||||||||||||||
Cash and cash equivalents |
23 | 15,128 | 4,507 | | | | | 19,635 | ||||||||||||||||||||||||||
Financial liabilities |
||||||||||||||||||||||||||||||||||
Trade and other payables |
25 | | | | | | (44,405 | ) | (44,405 | ) | ||||||||||||||||||||||||
Derivative financial instruments |
26 | | | | (5,093 | ) | (288 | ) | | (5,381 | ) | |||||||||||||||||||||||
Accruals |
| | | | | (7,366 | ) | (7,366 | ) | |||||||||||||||||||||||||
Finance debt |
27 | | | | | | (48,168 | ) | (48,168 | ) | ||||||||||||||||||||||||
51,979 | 6,945 | | 834 | 3,171 | (99,939 | ) | (37,010 | ) |
The fair value of finance debt is shown in Note 27. For all other financial instruments, the carrying amount is either the fair value, or approximates the fair value.
Financial risk factors
The group is exposed to a number of different financial risks arising from natural business exposures as well as its use of financial instruments including: market risks relating to commodity prices, foreign currency exchange rates, interest rates and equity prices; credit risk; and liquidity risk.
166 | BP Annual Report and Form 20-F 2013 |
19. Financial instruments and financial risk factors continued
The group financial risk committee (GFRC) advises the group chief financial officer (CFO) who oversees the management of these risks. The GFRC is chaired by the CFO and consists of a group of senior managers including the group treasurer and the heads of the group finance, tax and the integrated supply and trading functions. The purpose of the committee is to advise on financial risks and the appropriate financial risk governance framework for the group. The committee provides assurance to the CFO and the group chief executive (GCE), and via the GCE to the board, that the groups financial risk-taking activity is governed by appropriate policies and procedures and that financial risks are identified, measured and managed in accordance with group policies and group risk appetite.
The groups trading activities in the oil, natural gas and power markets are managed within the integrated supply and trading function, while the activities in the financial markets are managed by the treasury function, working under the compliance and control structure of the integrated supply and trading function. All derivative activity is carried out by specialist teams that have the appropriate skills, experience and supervision. These teams are subject to close financial and management control.
The integrated supply and trading function maintains formal governance processes that provide oversight of market risk associated with trading activity. A policy and risk committee monitors and validates limits and risk exposures, reviews incidents and validates risk-related policies, methodologies and procedures. A commitments committee approves value-at-risk delegations, the trading of new products, instruments and strategies and material commitments.
In addition, the integrated supply and trading function undertakes derivative activity for risk management purposes under a separate control framework as described more fully below.
(a) Market risk
Market risk is the risk or uncertainty arising from possible market price movements and their impact on the future performance of a business. The primary commodity price risks that the group is exposed to include oil, natural gas and power prices that could adversely affect the value of the groups financial assets, liabilities or expected future cash flows. The group enters into derivatives in a well-established entrepreneurial trading operation. In addition, the group has developed a control framework aimed at managing the volatility inherent in certain of its natural business exposures. In accordance with the control framework the group enters into various transactions using derivatives for risk management purposes.
The major components of market risk are commodity price risk, foreign currency exchange risk, interest rate risk and equity price risk, each of which is discussed below.
(i) Commodity price risk
The groups integrated supply and trading function uses conventional financial and commodity instruments and physical cargoes available in the related commodity markets. Oil and natural gas swaps, options and futures are used to mitigate price risk. Power trading is undertaken using a combination of over-the-counter forward contracts and other derivative contracts, including options and futures. This activity is on both a standalone basis and in conjunction with gas derivatives in relation to gas-generated power margin. In addition, NGLs are traded around certain US inventory locations using over-the-counter forward contracts in conjunction with over-the-counter swaps, options and physical inventories.
The group measures market risk exposure arising from its trading positions using value-at-risk techniques. These techniques make a statistical assessment of the market risk arising from possible future changes in market prices over a one-day holding period. The value-at-risk measure is supplemented by stress testing. Value-at-risk limits are in place for each trading activity and for the groups trading activity in total. The board has delegated a limit of $100 million value at risk in support of this trading activity.
In addition, the group has embedded derivatives relating to certain natural gas contracts. The net fair value of these contracts was a liability of $652 million at 31 December 2013 (2012 liability of $1,112 million). For these embedded derivatives the sensitivity of the net fair value to an immediate 10% favourable or adverse change in each key assumption is less than $100 million in each case.
(ii) Foreign currency exchange risk
Where the group enters into foreign currency exchange contracts for entrepreneurial trading purposes the activity is controlled using trading value-at-risk techniques as explained above.
Since BP has global operations, fluctuations in foreign currency exchange rates can have a significant effect on the groups reported results. The effects of most exchange rate fluctuations are absorbed in business operating results through changing cost competitiveness, lags in market adjustment to movements in rates and translation differences accounted for on specific transactions. For this reason, the total effect of exchange rate fluctuations is not identifiable separately in the groups reported results. The main underlying economic currency of the groups cash flows is the US dollar. This is because BPs major product, oil, is priced internationally in US dollars. BPs foreign currency exchange management policy is to limit economic and material transactional exposures arising from currency movements against the US dollar. The group co-ordinates the handling of foreign currency exchange risks centrally, by netting off naturally-occurring opposite exposures wherever possible, and then managing any material residual foreign currency exchange risks.
The group manages these exposures by constantly reviewing the foreign currency economic value at risk and aims to manage such risk to keep the 12-month foreign currency value at risk below $400 million. At no point over the past three years did the value at risk exceed the maximum risk limit. The most significant exposures relate to capital expenditure commitments and other UK and European operational requirements, for which a hedging programme is in place and hedge accounting is claimed as outlined in Note 26.
For highly probable forecast capital expenditures the group locks in the US dollar cost of non-US dollar supplies by using currency forwards and futures. The main exposures are sterling, euro, Norwegian krone, Australian dollar and Korean won. At 31 December 2013 the most significant open contracts in place were for $723 million sterling (2012 $853 million sterling).
For other UK, European and Australian operational requirements the group uses cylinders (purchased call and sold put options) and currency forwards to manage the estimated exposures on a 12-month rolling basis. At 31 December 2013, the open positions relating to cylinders consisted of receive sterling, pay US dollar cylinders for $2,770 million (2012 $2,886 million); receive euro, pay US dollar cylinders for $962 million (2012 $1,636 million); receive Australian dollar, pay US dollar cylinders for $401 million (2012 $522 million).
In addition, most of the groups borrowings are in US dollars or are hedged with respect to the US dollar. At 31 December 2013, the total foreign currency net borrowings not swapped into US dollars amounted to $665 million (2012 $364 million).
(iii) Interest rate risk
Where the group enters into money market contracts for entrepreneurial trading purposes the activity is controlled using value-at-risk techniques as described above.
BP Annual Report and Form 20-F 2013 | 167 |
19. Financial instruments and financial risk factors continued
BP is also exposed to interest rate risk from the possibility that changes in interest rates will affect future cash flows or the fair values of its financial instruments, principally finance debt. While the group issues debt in a variety of currencies based on market opportunities, it uses derivatives to swap the debt to a floating rate exposure, mainly to US dollar floating, but in certain defined circumstances maintains a US dollar fixed rate exposure for a proportion of debt. The proportion of floating rate debt net of interest rate swaps at 31 December 2013 was 65% of total finance debt outstanding (2012 65%). The weighted average interest rate on finance debt at 31 December 2013 was 2% (2012 2%) and the weighted average maturity of fixed rate debt was four years (2012 four years).
The groups earnings are sensitive to changes in interest rates on the floating rate element of the groups finance debt. If the interest rates applicable to floating rate instruments were to have increased by one percentage point on 1 January 2014, it is estimated that the groups finance costs for 2014 would increase by approximately $312 million (2012 $311 million increase in 2013).
(iv) Equity price risk
The group holds equity investments, typically for strategic purposes, that are classified as non-current available-for-sale financial assets and are measured initially at fair value with changes in fair value recognized in other comprehensive income.
At 31 December 2013 the group had no significant exposure to the price of quoted equity instruments. At 31 December 2012, an increase or decrease of 10% in quoted equity prices would have resulted in an immediate credit or charge to other comprehensive income of $1,502 million. At 31 December 2012, 82% of the carrying amount of non-current available-for-sale equity financial assets represented the groups 1.25% stake in Rosneft, thus the groups exposure was concentrated on changes in the share price of this equity in particular. The sensitivity analysis at 31 December 2012 includes the impact of a change in the share price on the valuation of the contracts to acquire Rosneft shares accounted for as cash flow hedge derivatives.
(b) Credit risk
Credit risk is the risk that a customer or counterparty to a financial instrument will fail to perform or fail to pay amounts due causing financial loss to the group and arises from cash and cash equivalents, derivative financial instruments and deposits with financial institutions and principally from credit exposures to customers relating to outstanding receivables. Credit exposure also exists in relation to guarantees issued by group companies under which amounts outstanding at 31 December 2013 were $199 million (2012 $237 million) in respect of liabilities of joint ventures and associates and $305 million (2012 $717 million) in respect of liabilities of other third parties.
The group has a credit policy, approved by the CFO, that is designed to ensure that consistent processes are in place throughout the group to measure and control credit risk. Credit risk is considered as part of the risk-reward balance of doing business. On entering into any business contract the extent to which the arrangement exposes the group to credit risk is considered. Key requirements of the policy include segregation of credit approval authorities from any sales, marketing or trading teams authorized to incur credit risk; the establishment of credit systems and processes to ensure that all counterparty exposure is rated and that all counterparty exposure and limits can be monitored and reported; and the timely identification and reporting of any non-approved credit exposures and credit losses. While each segment of the group is typically responsible for its own credit risk management and reporting consistent with group policy, the treasury function holds group-wide credit risk authority and oversight responsibility for exposure to banks and financial institutions.
The maximum credit exposure associated with financial assets is equal to the carrying amount. The group does not aim to remove credit risk entirely but expects to experience a certain level of credit losses. As at 31 December 2013, the group had in place credit enhancements designed to mitigate approximately $13 billion of credit risk (2012 $12 billion). Reports are regularly prepared and presented to the GFRC that cover the groups overall credit exposure and expected loss trends, exposure by segment, and overall quality of the portfolio.
For the contracts comprising derivative financial instruments in an asset position at 31 December 2013 it is estimated that over 80% (2012 over 70%, excluding the contracts with Rosneft accounted for as derivatives) of the unmitigated credit exposure is to counterparties of investment grade credit quality.
For cash and cash equivalents, the treasury function dynamically manages bank deposit limits to ensure cash is well-diversified and to reduce concentration risks. At 31 December 2013, 92% of the cash and cash equivalents balance was deposited with financial institutions rated at least A- by Standard & Poors and Fitch, and A3 by Moodys. Of the total cash and cash equivalents held at year end, collateral of $5,450 million was held by third-party custodians in tri-partite repurchase agreements, which would only be released to BP in the event of repayment default by the borrower.
Trade and other receivables of the group are analysed in the table below. By comparing the BP credit ratings to the equivalent external credit ratings, it is estimated that approximately 70-80% (2012 approximately 70-80%) of the unmitigated trade receivables portfolio exposure is of investment grade credit quality. Current assets, including trade and other receivables, in Egypt amount to $2.3 billion (see page 241), of which over one third relates to trade receivables which are not impaired but are past the original due date. Management is working with the counterparties to continue to collect these amounts.
$ million | ||||||||||
Trade and other receivables at 31 December | 2013 | 2012 | ||||||||
Neither impaired nor past due |
37,201 | 33,053 | ||||||||
Impaired (net of provision) |
27 | 80 | ||||||||
Not impaired and past due in the following periods |
||||||||||
within 30 days |
1,054 | 1,337 | ||||||||
31 to 60 days |
249 | 286 | ||||||||
61 to 90 days |
216 | 225 | ||||||||
over 90 days |
883 | 981 | ||||||||
39,630 | 35,962 |
Movements in the impairment provision for trade receivables are shown in Note 24.
Financial instruments subject to offsetting, enforceable master netting arrangements and similar agreements
The following table shows the gross amounts of recognized financial assets and liabilities (i.e. before offsetting) and the amounts offset in the balance sheet. Financial assets and liabilities are only offset when the group currently has a legally enforceable right to set off the recognized amounts and the group intends to either settle on a net basis or realize the asset and settle the liability simultaneously. A right of set off is the groups legal right to settle an amount payable to a creditor by applying against it an amount receivable from the same counterparty. The relevant legal jurisdiction and laws applicable to the relationships between the parties need to be considered when assessing whether a current legally enforceable right to set off exists.
168 | BP Annual Report and Form 20-F 2013 |
19. Financial instruments and financial risk factors continued
Furthermore, amounts which cannot be offset under IFRS, but which could be settled net under the terms of master netting agreements if certain conditions arise, and collateral received or pledged, are also shown in the table to show the total net exposure of the group.
$ million | ||||||||||||||||||||||||||
At 31 December 2013 |
Gross |
Amounts |
Net amounts |
Related amounts not set off in the balance sheet |
Net amount |
|||||||||||||||||||||
Master netting arrangements |
Cash (received) pledged |
|||||||||||||||||||||||||
Derivative assets |
7,271 | (1,563 | ) | 5,708 | (344 | ) | (231 | ) | 5,133 | |||||||||||||||||
Derivative liabilities |
(5,457 | ) | 1,563 | (3,894 | ) | 344 | | (3,550 | ) | |||||||||||||||||
Trade receivables |
11,034 | (7,744 | ) | 3,290 | (1,287 | ) | (264 | ) | 1,739 | |||||||||||||||||
Trade payables |
(10,619 | ) | 7,744 | (2,875 | ) | 1,287 | | (1,588 | ) | |||||||||||||||||
At 31 December 2012 | ||||||||||||||||||||||||||
Derivative assets |
9,291 | (1,870 | ) | 7,421 | (754 | ) | (175 | ) | 6,492 | |||||||||||||||||
Derivative liabilities |
(6,117 | ) | 1,870 | (4,247 | ) | 754 | | (3,493 | ) | |||||||||||||||||
Trade receivables |
8,829 | (6,368 | ) | 2,461 | (578 | ) | (176 | ) | 1,707 | |||||||||||||||||
Trade payables |
(9,330 | ) | 6,368 | (2,962 | ) | 578 | | (2,384 | ) |
(c) Liquidity risk
Liquidity risk is the risk that suitable sources of funding for the groups business activities may not be available. The groups liquidity is managed centrally with operating units forecasting their cash and currency requirements to the central treasury function. Unless restricted by local regulations, subsidiaries pool their cash surpluses to treasury, which will then arrange to fund other subsidiaries requirements, or invest any net surplus in the market or arrange for necessary external borrowings, while managing the groups overall net currency positions.
The group has in place a European Debt Issuance Programme (DIP) 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 $13,854 million (2012 $14,043 million). Since 5 February 2013, the group has had a US shelf registration with a limit of $30 billion. This was converted from an unlimited shelf registration following the approval in December 2012 of the settlement with the US Securities and Exchange Commission in respect of Gulf of Mexico oil spill related claims. Amounts drawn down since conversion total $6.9 billion. In addition, the group has an Australian Note Issuance Programme of A$5 billion, and as at 31 December 2013 the amount drawn down was A$800 million (2012 A$500 million).
The groups long-term credit ratings are A (positive outlook) from Standard & Poors, and A2 (stable outlook) from Moodys Investor Services, both remaining unchanged during 2013.
During 2013, $8.6 billion of long-term taxable bonds were issued with terms ranging from 18 months to 10 years. Commercial paper is issued at competitive rates to meet short-term borrowing requirements as and when needed.
As a further liquidity measure, the group continues to maintain suitable levels of cash and cash equivalents, amounting to $22.5 billion at 31 December 2013, primarily invested with highly rated banks or money market funds and readily accessible at immediate and short notice (2012 $19.6 billion). At 31 December 2013, the group had substantial amounts of undrawn borrowing facilities available, consisting of $7,375 million of standby facilities, of which $6,975 million is available to draw and repay until the first half of 2018, and $400 million is available to draw and repay until April 2016. These facilities were renegotiated during 2013 with 26 international banks, and borrowings under them would be at pre-agreed rates.
The group also has committed letter of credit (LC) facilities totalling $7,475 million with a number of banks, allowing LCs to be issued for a maximum one-year duration. There were also uncommitted secured LC facilities in place at 31 December 2013 for $2,410 million, which are secured against inventories or receivables when utilized. The facilities only terminate by either party giving a stipulated termination notice to the other.
The amounts shown for finance debt in the table below include future minimum lease payments with respect to finance leases. The table also shows the timing of cash outflows relating to trade and other payables and accruals.
$ million | ||||||||||||||||||||||||||||||||||
2013 | 2012 | |||||||||||||||||||||||||||||||||
Trade and other payables |
Accruals | Finance debt |
Interest relating to finance debt |
Trade and other payables |
Accruals | Finance debt |
Interest relating to finance debt |
|||||||||||||||||||||||||||
Within one year |
43,790 | 8,960 | 7,381 | 885 | 42,512 | 6,875 | 9,401 | a | 893 | |||||||||||||||||||||||||
1 to 2 years |
1,007 | 207 | 6,630 | 752 | 903 | 136 | 5,906 | 755 | ||||||||||||||||||||||||||
2 to 3 years |
822 | 66 | 6,720 | 621 | 434 | 80 | 5,902 | 634 | ||||||||||||||||||||||||||
3 to 4 years |
761 | 73 | 5,828 | 498 | 373 | 52 | 6,024 | 510 | ||||||||||||||||||||||||||
4 to 5 years |
1,405 | 37 | 5,279 | 388 | 71 | 83 | 5,797 | 388 | ||||||||||||||||||||||||||
5 to 10 years |
207 | 113 | 15,933 | 809 | 79 | 84 | 14,790 | 885 | ||||||||||||||||||||||||||
Over 10 years |
80 | 51 | 421 | 119 | 33 | 56 | 348 | 50 | ||||||||||||||||||||||||||
48,072 | 9,507 | 48,192 | 4,072 | 44,405 | 7,366 | 48,168 | 4,115 |
a | In addition, current finance debt on the group balance sheet at 31 December 2012 included $632 million in respect of cash deposits received for disposals which completed in 2013. |
The group manages liquidity risk associated with derivative contracts, other than derivative hedging instruments, based on the expected maturities of both derivative assets and liabilities as indicated in Note 26. Management does not currently anticipate any cash flows that could be of a significantly different amount, or could occur earlier than the expected maturity analysis provided.
The table below shows cash outflows for derivative hedging instruments based upon contractual payment dates. The amounts reflect the maturity profile of the fair value liability where the instruments will be settled net, and the gross settlement amount where the pay leg of a derivative will be settled separately from the receive leg, as in the case of cross-currency swaps hedging non-US dollar finance debt. The swaps are with high investment-grade counterparties and therefore the settlement-day risk exposure is considered to be negligible. Not shown in the table are the gross
BP Annual Report and Form 20-F 2013 | 169 |
19. Financial instruments and financial risk factors continued
settlement amounts (inflows) for the receive leg of derivatives that are settled separately from the pay leg, which amount to $12,222 million at 31 December 2013 (2012 $8,620 million) to be received on the same day as the related cash outflows.
$ million | ||||||||||
2013 | 2012 | |||||||||
Within one year |
1,095 | 1,356 | ||||||||
1 to 2 years |
293 | 1,107 | ||||||||
2 to 3 years |
2,959 | 295 | ||||||||
3 to 4 years |
2,577 | 1,261 | ||||||||
4 to 5 years |
1,505 | 2,577 | ||||||||
5 to 10 years |
3,835 | 1,903 | ||||||||
12,264 | 8,499 |
$ million | ||||||||||||||||||
2013 | 2012 | |||||||||||||||||
Current | Non-current | Current | Non-current | |||||||||||||||
Equity investments listed |
| 3 | | 1,182 | ||||||||||||||
unlisted |
| 288 | | 251 | ||||||||||||||
Repurchased gas pre-paid bonds |
276 | 408 | 303 | 686 | ||||||||||||||
Contingent consideration |
186 | 292 | | | ||||||||||||||
Other |
5 | 574 | 16 | 585 | ||||||||||||||
467 | 1,565 | 319 | 2,704 |
At 31 December 2012 the groups 1.25% stake in Rosneft was the most significant listed investment, with a fair value of $1,179 million.
BP entered into long-term gas supply contracts which are backed by gas pre-paid bonds. In 2010, BP was unsuccessful in the remarketing of these bonds and repurchased them. The outstanding bonds associated with these long-term gas supply contracts held by BP are recorded within other investments, with the related liability recorded within other payables on the balance sheet. The fair value of the gas pre-paid bonds is the same as the carrying amount, as the bonds are based on floating rate interest with weekly market re-set, and as such are in level 1 of the fair value hierarchy.
At 31 December 2013 the group had contingent consideration receivable in respect of the disposal of the Devenick field, classified as an available-for-sale financial asset.
Other non-current investments at 31 December 2013 include $574 million relating to life insurance policies (2012 $585 million). The life insurance policies have been designated as financial assets at fair value through profit and loss and their valuation methodology is in level 3 of the fair value hierarchy. Fair value losses of $4 million were recognized in the income statement (2012 $70 million gain and 2011 $21 million gain).
$ million | ||||||||||
2013 | 2012 | |||||||||
Crude oil |
10,190 | 9,123 | ||||||||
Natural gas |
235 | 187 | ||||||||
Refined petroleum and petrochemical products |
15,427 | 15,465 | ||||||||
25,852 | 24,775 | |||||||||
Supplies |
2,735 | 2,428 | ||||||||
28,587 | 27,203 | |||||||||
Trading inventories |
644 | 1,000 | ||||||||
29,231 | 28,203 | |||||||||
Cost of inventories expensed in the income statement |
298,351 | 292,774 |
The inventory valuation at 31 December 2013 is stated net of a provision of $322 million (2012 $124 million) to write inventories down to their net realizable value. The net charge to the income statement in the year in respect of inventory net realizable value provisions was $195 million (2012 $28 million credit).
Trading inventories are valued using quoted benchmark bid prices adjusted as appropriate for location and quality differentials. As such they are predominantly categorized within level 2 of the fair value hierarchy.
Inventories with a carrying amount of $227 million (2012 $64 million) have been pledged as security for certain of the groups liabilities at 31 December 2013.
170 | BP Annual Report and Form 20-F 2013 |
22. Trade and other receivables
$ million | ||||||||||||||||||
2013 | 2012 | |||||||||||||||||
Current | Non-current | Current | Non-current | |||||||||||||||
Financial assets |
||||||||||||||||||
Trade receivables |
28,868 | 183 | 26,485 | 151 | ||||||||||||||
Amounts receivable from joint ventures and associates |
1,213 | 47 | 871 | 102 | ||||||||||||||
Other receivables |
6,594 | 2,725 | 5,683 | 2,670 | ||||||||||||||
36,675 | 2,955 | 33,039 | 2,923 | |||||||||||||||
Non-financial assets |
||||||||||||||||||
Gulf of Mexico oil spill trust fund reimbursement asseta |
2,457 | 2,442 | 4,178 | 2,264 | ||||||||||||||
Other receivables |
699 | 588 | 394 | 774 | ||||||||||||||
3,156 | 3,030 | 4,572 | 3,038 | |||||||||||||||
39,831 | 5,985 | 37,611 | 5,961 |
a | See Note 2 for further information. |
Trade and other receivables are predominantly non-interest bearing. See Note 19 for further information.
Receivables with a carrying amount of $236 million (2012 $12 million) have been pledged as security for certain of the groups liabilities at 31 December 2013.
$ million | ||||||||||
2013 | 2012 | |||||||||
Cash at bank and in hand |
6,907 | 5,885 | ||||||||
Term bank deposits |
12,246 | 9,243 | ||||||||
Cash equivalents |
3,367 | 4,507 | ||||||||
22,520 | 19,635 |
Cash and cash equivalents comprise cash in hand; current balances with banks and similar institutions; term deposits of three months or less with banks and similar institutions; money market funds and commercial paper. The carrying amounts of cash at bank and in hand and term bank deposits approximate their fair values. Substantially all of the other cash equivalents are categorized within level 1 of the fair value hierarchy.
Cash and cash equivalents at 31 December 2013 includes $1,626 million (2012 $1,544 million) that is restricted. Included in restricted cash at 31 December 2012 was $709 million relating to the dividend received from TNK-BP in December 2012 which remained restricted until completion of the sale of BPs interest in TNK-BP to Rosneft, which occurred in the first quarter of 2013. See Note 6 for further information. The remaining restricted cash balances relate largely to amounts required to cover initial margin on trading exchanges.
24. Valuation and qualifying accounts
$ million | ||||||||||||||||||||||||||
2013 | 2012 | 2011 | ||||||||||||||||||||||||
Accounts receivable |
Fixed asset investments |
Accounts receivable |
Fixed asset investments |
Accounts receivable |
Fixed asset investments |
|||||||||||||||||||||
At 1 January |
489 | 349 | 332 | 643 | 428 | 540 | ||||||||||||||||||||
Charged to costs and expenses |
82 | 4 | 240 | 196 | 115 | 111 | ||||||||||||||||||||
Charged to other accountsa |
(4 | ) | 4 | 7 | 18 | (16 | ) | (3 | ) | |||||||||||||||||
Deductions |
(224 | ) | (189 | ) | (90 | ) | (508 | ) | (195 | ) | (5 | ) | ||||||||||||||
At 31 December |
343 | 168 | 489 | 349 | 332 | 643 |
a | Principally currency transactions. |
Valuation and qualifying accounts comprise impairment provisions for accounts receivable and fixed asset investments, and are deducted in the balance sheet from the assets to which they apply.
$ million | ||||||||||||||||||
2013 | 2012 | |||||||||||||||||
Current | Non-current | Current | Non-current | |||||||||||||||
Financial liabilities |
||||||||||||||||||
Trade payables |
28,926 | | 29,920 | | ||||||||||||||
Amounts payable to joint ventures and associates |
3,576 | 47 | 1,105 | 102 | ||||||||||||||
Other payables |
11,288 | 4,235 | 11,487 | 1,791 | ||||||||||||||
43,790 | 4,282 | 42,512 | 1,893 | |||||||||||||||
Non-financial liabilities |
||||||||||||||||||
Other payables |
3,369 | 474 | 4,161 | 399 | ||||||||||||||
47,159 | 4,756 | 46,673 | 2,292 |
Trade and other payables are predominantly non-interest bearing. See Note 19 for further information.
BP Annual Report and Form 20-F 2013 | 171 |
26. Derivative financial instruments
In the normal course of business the group enters into derivative financial instruments (derivatives) to manage its normal business exposures in relation to commodity prices, foreign currency exchange rates and interest rates, including management of the balance between floating rate and fixed rate debt, consistent with risk management policies and objectives. An outline of the groups financial risks and the objectives and policies pursued in relation to those risks is set out in Note 19. Additionally, the group has a well-established entrepreneurial trading operation that is undertaken in conjunction with these activities using a similar range of contracts.
The fair values of derivative financial instruments at 31 December are set out below.
$ million | ||||||||||||||||||
2013 | 2012 | |||||||||||||||||
Fair value asset |
Fair value liability |
Fair value asset |
Fair value liability |
|||||||||||||||
Derivatives held for trading |
||||||||||||||||||
Currency derivatives |
192 | (111 | ) | 175 | (189 | ) | ||||||||||||
Oil price derivatives |
810 | (806 | ) | 841 | (707 | ) | ||||||||||||
Natural gas price derivatives |
2,840 | (2,029 | ) | 3,536 | (2,496 | ) | ||||||||||||
Power price derivatives |
871 | (560 | ) | 719 | (589 | ) | ||||||||||||
Other derivatives |
475 | | 71 | | ||||||||||||||
5,188 | (3,506 | ) | 5,342 | (3,981 | ) | |||||||||||||
Embedded derivatives |
||||||||||||||||||
Commodity price contracts |
1 | (653 | ) | | (1,112 | ) | ||||||||||||
1 | (653 | ) | | (1,112 | ) | |||||||||||||
Cash flow hedges |
||||||||||||||||||
Equity price derivatives |
| | 1,339 | | ||||||||||||||
Currency forwards, futures and cylinders |
129 | (30 | ) | 51 | (41 | ) | ||||||||||||
Cross-currency interest rate swaps |
| (69 | ) | 1 | | |||||||||||||
129 | (99 | ) | 1,391 | (41 | ) | |||||||||||||
Fair value hedges |
||||||||||||||||||
Currency forwards, futures and swaps |
340 | (154 | ) | 875 | (247 | ) | ||||||||||||
Interest rate swaps |
526 | (135 | ) | 1,193 | | |||||||||||||
866 | (289 | ) | 2,068 | (247 | ) | |||||||||||||
6,184 | (4,547 | ) | 8,801 | (5,381 | ) | |||||||||||||
Of which current |
2,675 | (2,322 | ) | 4,507 | (2,658 | ) | ||||||||||||
non-current |
3,509 | (2,225 | ) | 4,294 | (2,723 | ) |
Exchange traded derivatives are valued using closing prices provided by the exchange as at the balance sheet date. These derivatives are categorized within level 1 of the fair value hierarchy. Over-the-counter (OTC) financial swaps and physical commodity sale and purchase contracts are generally valued using readily available information in the public markets and quotations provided by brokers and price index developers. These quotes are corroborated with market data and are categorized within level 2 of the fair value hierarchy.
In certain less liquid markets, or for longer-term contracts, forward prices are not as readily available. In these circumstances, OTC financial swaps and physical commodity sale and purchase contracts are valued using internally developed methodologies that consider historical relationships between various commodities, and that result in managements best estimate of fair value. These contracts are categorized within level 3 of the fair value hierarchy.
Financial OTC and physical commodity options are valued using industry standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and contractual prices for the underlying instruments, as well as other relevant economic factors. The degree to which these inputs are observable in the forward markets determines whether the option is categorized within level 2 or level 3 of the fair value hierarchy.
Derivatives held for trading
The group maintains active trading positions in a variety of derivatives. The contracts may be entered into for risk management purposes, to satisfy supply requirements or for entrepreneurial trading. Certain contracts are classified as held for trading, regardless of their original business objective, and are recognized at fair value with changes in fair value recognized in the income statement. Trading activities are undertaken by using a range of contract types in combination to create incremental gains by arbitraging prices between markets, locations and time periods. The net of these exposures is monitored using market value-at-risk techniques as described in Note 19.
172 | BP Annual Report and Form 20-F 2013 |
26. Derivative financial instruments continued
The following tables show further information on the fair value of derivatives and other financial instruments held for trading purposes.
Derivative assets held for trading have the following fair values and maturities.
$ million | ||||||||||||||||||||||||||||||
2013 | ||||||||||||||||||||||||||||||
Less than 1 year |
1-2 years | 2-3 years | 3-4 years | 4-5 years | Over 5 years |
Total | ||||||||||||||||||||||||
Currency derivatives |
143 | | 21 | | | 28 | 192 | |||||||||||||||||||||||
Oil price derivatives |
694 | 78 | 23 | 13 | 2 | | 810 | |||||||||||||||||||||||
Natural gas price derivatives |
1,034 | 526 | 334 | 192 | 154 | 600 | 2,840 | |||||||||||||||||||||||
Power price derivatives |
528 | 202 | 81 | 22 | 8 | 30 | 871 | |||||||||||||||||||||||
Other derivatives |
102 | | 93 | 147 | 66 | 67 | 475 | |||||||||||||||||||||||
2,501 | 806 | 552 | 374 | 230 | 725 | 5,188 | ||||||||||||||||||||||||
$ million | ||||||||||||||||||||||||||||||
2012 | ||||||||||||||||||||||||||||||
Less than 1 year |
1-2 years | 2-3 years | 3-4 years | 4-5 years | Over 5 years |
Total | ||||||||||||||||||||||||
Currency derivatives |
169 | 6 | | | | | 175 | |||||||||||||||||||||||
Oil price derivatives |
656 | 109 | 38 | 21 | 12 | 5 | 841 | |||||||||||||||||||||||
Natural gas price derivatives |
1,532 | 711 | 418 | 259 | 144 | 472 | 3,536 | |||||||||||||||||||||||
Power price derivatives |
327 | 188 | 114 | 62 | 19 | 9 | 719 | |||||||||||||||||||||||
Other derivatives |
71 | | | | | | 71 | |||||||||||||||||||||||
2,755 | 1,014 | 570 | 342 | 175 | 486 | 5,342 |
At 31 December 2013 the group had contingent consideration receivable in respect of a business disposal. The sale agreement contained an embedded derivative the whole agreement has, consequently, been designated at fair value through profit or loss and shown within other derivatives held for trading, and falls within level 3 of the fair value hierarchy. The valuation depends on refinery throughput and future margins. At 31 December 2012, other derivatives related to the anticipated transaction with Rosneft see Cash flow hedges below for further information.
Derivative liabilities held for trading have the following fair values and maturities.
$ million | ||||||||||||||||||||||||||||||
2013 | ||||||||||||||||||||||||||||||
Less than 1 year |
1-2 years | 2-3 years | 3-4 years | 4-5 years | Over 5 years |
Total | ||||||||||||||||||||||||
Currency derivatives |
(111 | ) | | | | | | (111 | ) | |||||||||||||||||||||
Oil price derivatives |
(620 | ) | (100 | ) | (42 | ) | (31 | ) | (13 | ) | | (806 | ) | |||||||||||||||||
Natural gas price derivatives |
(778 | ) | (319 | ) | (157 | ) | (110 | ) | (102 | ) | (563 | ) | (2,029 | ) | ||||||||||||||||
Power price derivatives |
(400 | ) | (99 | ) | (48 | ) | (13 | ) | | | (560 | ) | ||||||||||||||||||
(1,909 | ) | (518 | ) | (247 | ) | (154 | ) | (115 | ) | (563 | ) | (3,506 | ) | |||||||||||||||||
$ million | ||||||||||||||||||||||||||||||
2012 | ||||||||||||||||||||||||||||||
Less than 1 year |
1-2 years | 2-3 years | 3-4 years | 4-5 years | Over 5 years |
Total | ||||||||||||||||||||||||
Currency derivatives |
(189 | ) | | | | | | (189 | ) | |||||||||||||||||||||
Oil price derivatives |
(580 | ) | (77 | ) | (27 | ) | (12 | ) | (8 | ) | (3 | ) | (707 | ) | ||||||||||||||||
Natural gas price derivatives |
(1,199 | ) | (440 | ) | (241 | ) | (135 | ) | (78 | ) | (403 | ) | (2,496 | ) | ||||||||||||||||
Power price derivatives |
(341 | ) | (133 | ) | (59 | ) | (21 | ) | (10 | ) | (25 | ) | (589 | ) | ||||||||||||||||
(2,309 | ) | (650 | ) | (327 | ) | (168 | ) | (96 | ) | (431 | ) | (3,981 | ) |
BP Annual Report and Form 20-F 2013 | 173 |
26. Derivative financial instruments continued
The following table shows the fair value of derivative assets and derivative liabilities held for trading, analysed by maturity period and by methodology of fair value estimation. This information is presented on a gross basis, that is, before netting by counterparty.
$ million | ||||||||||||||||||||||||||||||
2013 | ||||||||||||||||||||||||||||||
Less than 1 year |
1-2 years | 2-3 years | 3-4 years | 4-5 years | Over 5 years |
Total | ||||||||||||||||||||||||
Fair value of derivative assets |
||||||||||||||||||||||||||||||
Level 1 |
100 | | | | | | 100 | |||||||||||||||||||||||
Level 2 |
3,118 | 981 | 399 | 83 | 20 | 30 | 4,631 | |||||||||||||||||||||||
Level 3 |
389 | 183 | 252 | 291 | 210 | 695 | 2,020 | |||||||||||||||||||||||
3,607 | 1,164 | 651 | 374 | 230 | 725 | 6,751 | ||||||||||||||||||||||||
Less: netting by counterparty |
(1,106 | ) | (358 | ) | (99 | ) | | | | (1,563 | ) | |||||||||||||||||||
2,501 | 806 | 552 | 374 | 230 | 725 | 5,188 | ||||||||||||||||||||||||
Fair value of derivative liabilities |
||||||||||||||||||||||||||||||
Level 1 |
(87 | ) | | | | | | (87 | ) | |||||||||||||||||||||
Level 2 |
(2,790 | ) | (733 | ) | (215 | ) | (36 | ) | (15 | ) | (31 | ) | (3,820 | ) | ||||||||||||||||
Level 3 |
(138 | ) | (143 | ) | (131 | ) | (118 | ) | (100 | ) | (532 | ) | (1,162 | ) | ||||||||||||||||
(3,015 | ) | (876 | ) | (346 | ) | (154 | ) | (115 | ) | (563 | ) | (5,069 | ) | |||||||||||||||||
Less: netting by counterparty |
1,106 | 358 | 99 | | | | 1,563 | |||||||||||||||||||||||
(1,909 | ) | (518 | ) | (247 | ) | (154 | ) | (115 | ) | (563 | ) | (3,506 | ) | |||||||||||||||||
Net fair value |
592 | 288 | 305 | 220 | 115 | 162 | 1,682 | |||||||||||||||||||||||
$ million | ||||||||||||||||||||||||||||||
2012 | ||||||||||||||||||||||||||||||
Less than 1 year |
1-2 years | 2-3 years | 3-4 years | 4-5 years | Over 5 years |
Total | ||||||||||||||||||||||||
Fair value of derivative assets |
||||||||||||||||||||||||||||||
Level 1 |
187 | 6 | | | | | 193 | |||||||||||||||||||||||
Level 2 |
3,766 | 1,088 | 520 | 216 | 46 | 10 | 5,646 | |||||||||||||||||||||||
Level 3 |
302 | 184 | 137 | 136 | 136 | 478 | 1,373 | |||||||||||||||||||||||
4,255 | 1,278 | 657 | 352 | 182 | 488 | 7,212 | ||||||||||||||||||||||||
Less: netting by counterparty |
(1,500 | ) | (264 | ) | (87 | ) | (10 | ) | (7 | ) | (2 | ) | (1,870 | ) | ||||||||||||||||
2,755 | 1,014 | 570 | 342 | 175 | 486 | 5,342 | ||||||||||||||||||||||||
Fair value of derivative liabilities |
||||||||||||||||||||||||||||||
Level 1 |
(189 | ) | | | | | | (189 | ) | |||||||||||||||||||||
Level 2 |
(3,476 | ) | (810 | ) | (315 | ) | (78 | ) | (19 | ) | (28 | ) | (4,726 | ) | ||||||||||||||||
Level 3 |
(144 | ) | (104 | ) | (99 | ) | (100 | ) | (84 | ) | (405 | ) | (936 | ) | ||||||||||||||||
(3,809 | ) | (914 | ) | (414 | ) | (178 | ) | (103 | ) | (433 | ) | (5,851 | ) | |||||||||||||||||
Less: netting by counterparty |
1,500 | 264 | 87 | 10 | 7 | 2 | 1,870 | |||||||||||||||||||||||
(2,309 | ) | (650 | ) | (327 | ) | (168 | ) | (96 | ) | (431 | ) | (3,981 | ) | |||||||||||||||||
Net fair value |
446 | 364 | 243 | 174 | 79 | 55 | 1,361 |
Level 3 derivatives
The following table shows the changes during the year in the net fair value of derivatives held for trading purposes within level 3 of the fair value hierarchy.
$ million | ||||||||||||||||||||||
Oil price |
Natural gas price |
Power price |
Other | Total | ||||||||||||||||||
Net fair value of contracts at 1 January 2013 |
105 | 304 | (43 | ) | 71 | 437 | ||||||||||||||||
Gains (losses) recognized in the income statement |
(47 | ) | 62 | 81 | | 96 | ||||||||||||||||
Purchases |
110 | 1 | | | 111 | |||||||||||||||||
New contracts |
| | | 475 | 475 | |||||||||||||||||
Settlements |
(143 | ) | (52 | ) | 10 | (71 | ) | (256 | ) | |||||||||||||
Transfers out of level 3 |
(43 | ) | (1 | ) | 36 | | (8 | ) | ||||||||||||||
Exchange adjustments |
| (1 | ) | 2 | | 1 | ||||||||||||||||
Net fair value of contracts at 31 December 2013 |
(18 | ) | 313 | 86 | 475 | 856 |
174 | BP Annual Report and Form 20-F 2013 |
26. Derivative financial instruments continued
$ million | ||||||||||||||||||||||
Oil price |
Natural gas price |
Power price |
Other | Total | ||||||||||||||||||
Net fair value of contracts at 1 January 2012 |
162 | 408 | 13 | | 583 | |||||||||||||||||
Gains (losses) recognized in the income statement |
30 | 4 | (4 | ) | | 30 | ||||||||||||||||
New contracts |
| | | 71 | 71 | |||||||||||||||||
Settlements |
(87 | ) | (56 | ) | | | (143 | ) | ||||||||||||||
Transfers into level 3 |
| (19 | ) | | | (19 | ) | |||||||||||||||
Transfers out of level 3 |
| (33 | ) | (51 | ) | | (84 | ) | ||||||||||||||
Exchange adjustments |
| | (1 | ) | | (1 | ) | |||||||||||||||
Net fair value of contracts at 31 December 2012 |
105 | 304 | (43 | ) | 71 | 437 |
US natural gas price derivatives are valued using observable market data for maturities up to 60 months in basis locations that trade at a premium or discount to the NYMEX Henry Hub price, and using internally developed price curves based on economic forecasts for periods beyond that time. At 31 December 2013, the US natural gas derivatives in level 3 of the fair value hierarchy had a net fair value of $351 million. Of this amount, $71 million (asset of $598 million and liability of $527 million) depends on level 3 inputs, with the remainder valued using level 2 inputs. The significant unobservable inputs for fair value measurements categorized within level 3 of the fair value hierarchy for the year ended 31 December 2013 are presented below.
Unobservable inputs | Range $/mmBtu |
Weighted average $/mmBtu |
||||||||||
Natural gas price contracts |
Long-dated market price | 3.15-6.71 | 4.63 |
If the natural gas prices after 2018 were 10% higher (lower), this would result in a decrease (increase) in derivative assets of $82 million, and decrease (increase) in derivative liabilities of $78 million, and a net decrease (increase) in profit before tax of $4 million.
Derivative gains and losses
Gains and losses relating to derivative contracts are included within sales and other operating revenues and within purchases in the income statement depending upon the nature of the activity and type of contract involved. The contract types treated in this way include futures, options, swaps and certain forward sales and forward purchases contracts, and relate to both currency and commodity trading activities. Gains or losses arise on contracts entered into for risk management purposes, optimization activity and entrepreneurial trading. They also arise on certain contracts that are for normal procurement or sales activity for the group but that are required to be fair valued under accounting standards. Also included within sales and other operating revenues are gains and losses on inventory held for trading purposes. The total amount relating to all these items (excluding gains and losses on realized physical derivative contracts that have been reflected gross in the income statement within sales and purchases) was a gain of $587 million (2012 $411 million net loss and 2011 $216 million net gaina).
a | The comparative amounts for 2012 and 2011 have been amended and now reflect only the margin on derivative contracts that have been reflected net within the income statement. |
Embedded derivatives
The group is a party to contracts containing embedded derivatives, the majority of which relate to certain natural gas contracts. Prior to the development of an active gas trading market, UK gas contracts were priced using a basket of available price indices, primarily relating to oil products, power and inflation. After the development of an active UK gas market, certain contracts were entered into or renegotiated using pricing formulae not directly related to gas prices, for example, oil product and power prices. In these circumstances, pricing formulae have been determined to be derivatives, embedded within the overall contractual arrangements that are not clearly and closely related to the underlying commodity. The resulting fair value relating to these contracts is recognized on the balance sheet with gains or losses recognized in the income statement.
Key information on the natural gas contracts is given below.
At 31 December | 2013 | 2012 | ||||||
Remaining contract terms |
1 year and 5 months to 4 years and 9 months | 2 years and 5 months to 5 years and 9 months | ||||||
Contractual/notional amount |
153 million therms | 117 million therms |
The commodity price embedded derivatives relate to natural gas contracts and are categorized in levels 2 and 3 of the fair value hierarchy. The contracts in level 2 are valued using inputs that include price curves for each of the different products that are built up from active market pricing data. Where necessary, the price curves are extrapolated to the expiry of the contracts (the last of which is in 2018) using all available external pricing information; additionally, where limited data exists for certain products, prices are interpolated using historic and long-term pricing relationships. These valuations are categorized in level 3. Transfers from level 3 to level 2 occur when the valuation no longer depends significantly on extrapolated or interpolated data. Valuations use observable market data for maturities up to 36 months, and internally developed price curves based on economic forecasts for periods beyond that time.
The following table shows the changes during the year in the net fair value of embedded derivatives, within level 3 of the fair value hierarchy.
$ million | ||||||||||
2013 | 2012 | |||||||||
Commodity price |
Commodity price |
|||||||||
Net fair value of contracts at 1 January |
(1,112 | ) | (1,417 | ) | ||||||
Settlements |
316 | 375 | ||||||||
Gains (losses) recognized in the income statement |
142 | (6 | ) | |||||||
Transfers out of level 3 |
258 | | ||||||||
Exchange adjustments |
17 | (64 | ) | |||||||
Net fair value of contracts at 31 December |
(379 | ) | (1,112 | ) |
BP Annual Report and Form 20-F 2013 | 175 |
26. Derivative financial instruments continued
The fair value gain (loss) on embedded derivatives is shown below.
$ million | ||||||||||||||
2013 | 2012 | 2011 | ||||||||||||
Commodity price embedded derivatives |
459 | 347 | 190 | |||||||||||
Other embedded derivatives |
| | (122 | ) | ||||||||||
Fair value gain (loss) |
459 | 347 | 68 |
Cash flow hedges
At 31 December 2013, the group held currency forwards and futures contracts and cylinders that were being used to hedge the foreign currency risk of highly probable forecast transactions. Note 19 outlines the management of risk aspects for currency risk. For cash flow hedges the group only claims hedge accounting for the intrinsic value on the currency with any fair value attributable to time value taken immediately to the income statement. The pre-tax amount reclassified from equity and recognized in the income statement in production and manufacturing expenses was a loss of $4 million (2012 $62 million loss and 2011 $195 million gain). The amount reclassified from equity and recognized in the carrying amount of non-financial assets was a loss of $17 million (2012 $19 million loss and 2011 $13 million gain). The amounts remaining in equity at 31 December 2013 in relation to these cash flow hedges consist of deferred gains of $85 million maturing in 2014, deferred losses of $23 million maturing in 2015 and deferred gains of $10 million maturing in 2016 and beyond.
At 31 December 2012, BP had entered into three agreements to sell its 50% interest in TNK-BP and acquire 18.5% of Rosneft, as described in Note 6. During the period from signing until completion on 21 March 2013, these agreements represented derivative financial instruments that were required to be measured at fair value. BP designated two of the agreements, for the acquisition of a 5.66% shareholding in Rosneft from Rosneftegaz, and for the acquisition of a 9.80% shareholding from Rosneft, as hedging instruments in a cash flow hedge, and so changes in the fair values of these agreements were recognized in other comprehensive income. The third agreement, under which BP sold its 50% interest in TNK-BP in exchange for cash and a 3.04% shareholding in Rosneft, was also a derivative financial instrument, but its fair value could not be reliably measured. An asset of $1,410 million related to these agreements was recognized on the balance sheet at 31 December 2012, of which $1,339 million related to the fair value of the cash flow hedge derivatives. The derivatives measured at fair value at 31 December 2012 were categorized in level 3 of the fair value hierarchy using inputs that included the quoted Rosneft share price. During 2013, a charge of $2,061 million was recognized in other comprehensive income in relation to these agreements and $4 million was recognized in the income statement. The resulting cumulative charge of $651 million recognized in other comprehensive income would only be recognized in the income statement if the investment in Rosneft were either sold or impaired. The cash flow hedge derivatives were valued using the quoted Rosneft share price at the time the deal completed, of $7.60 per share.
Fair value hedges
At 31 December 2013, the group held interest rate and cross-currency interest rate swap contracts as fair value hedges of the interest rate risk on fixed rate debt issued by the group. The effectiveness of each hedge relationship is quantitatively assessed and demonstrated to continue to be highly effective. The loss on the hedging derivative instruments recognized in the income statement in 2013 was $1,240 million (2012 $536 million gain and 2011 $328 million gain) offset by a gain on the fair value of the finance debt of $1,228 million (2012 $537 million loss and 2011 $327 million loss).
The interest rate and cross-currency interest rate swaps mature within one to 10 years, with an average maturity of four to five years (2012 four to five years) and are used to convert sterling, euro, Swiss franc, Australian dollar, Canadian dollar and Hong Kong dollar denominated borrowings primarily into US dollar floating rate debt. Note 19 outlines the groups approach to interest rate and currency risk management.
$ million | ||||||||||||||||||||||||||
2013 | 2012 | |||||||||||||||||||||||||
Current | Non-current | Total | Current | Non-current | Total | |||||||||||||||||||||
Borrowings |
7,340 | 40,317 | 47,657 | 9,372 | 38,412 | 47,784 | ||||||||||||||||||||
Net obligations under finance leases |
41 | 494 | 535 | 29 | 355 | 384 | ||||||||||||||||||||
7,381 | 40,811 | 48,192 | 9,401 | 38,767 | 48,168 | |||||||||||||||||||||
Disposal deposits |
| | | 632 | | 632 | ||||||||||||||||||||
7,381 | 40,811 | 48,192 | 10,033 | 38,767 | 48,800 |
The main elements of current borrowings are the current portion of long-term borrowings that are due to be repaid in the next 12 months of
$6,230 million (2012 $6,240 million) and issued commercial paper of $1,050 million (2012 $3,028 million). Finance debt does not include accrued interest, which is reported within other payables.
Deposits for disposal transactions of $632 million were included in current finance debt at 31 December 2012. This unsecured debt was extinguished on completion of the transactions in 2013. There were no deposits for disposal transactions included within finance debt at 31 December 2013.
At 31 December 2013, $141 million (2012 $142 million) of finance debt was secured by the pledging of assets. The remainder of finance debt was unsecured.
176 | BP Annual Report and Form 20-F 2013 |
27. Finance debt continued
The following table shows, by major currency, the groups finance debt at 31 December and the weighted average interest rates achieved at those dates through a combination of borrowings and derivative financial instruments entered into to manage interest rate and currency exposures. The disposal deposits noted above are excluded from this analysis.
Fixed rate debt |
Floating rate debt |
Total | ||||||||||||||||||||||||
Weighted average interest rate % |
Weighted average time for which rate is fixed Years |
Amount $ million |
Weighted average interest rate % |
Amount $ million |
Amount $ million |
|||||||||||||||||||||
2013 | ||||||||||||||||||||||||||
US dollar |
3 | 4 | 16,405 | 1 | 29,740 | 46,145 | ||||||||||||||||||||
Euro |
5 | 30 | 157 | 2 | 1,396 | 1,553 | ||||||||||||||||||||
Other currencies |
4 | 7 | 454 | 2 | 40 | 494 | ||||||||||||||||||||
17,016 | 31,176 | 48,192 | ||||||||||||||||||||||||
2012 | ||||||||||||||||||||||||||
US dollar |
3 | 4 | 16,744 | 1 | 26,208 | 42,952 | ||||||||||||||||||||
Euro |
5 | 2 | 20 | 1 | 4,854 | 4,874 | ||||||||||||||||||||
Other currencies |
4 | 11 | 255 | 3 | 87 | 342 | ||||||||||||||||||||
17,019 | 31,149 | 48,168 |
The euro debt not swapped to US dollar is naturally hedged with respect to the foreign currency risk by holding equivalent euro cash and cash equivalent amounts.
Fair values
The estimated fair value of finance debt is shown in the table below together with the carrying amount as reflected in the balance sheet.
Long-term borrowings in the table below include the portion of debt that matures in the 12 months from 31 December 2013, whereas in the balance sheet the amount is reported within current finance debt. The disposal deposits noted above are excluded from this analysis.
The carrying amount of the groups short-term borrowings, comprising mainly commercial paper, approximates their fair value. The fair values of the groups long-term borrowings are principally determined using quoted prices in active markets (and so fall within level 1 of the fair value hierarchy) or, where quoted prices are not available, quoted prices for similar instruments in active markets. The fair value of the groups finance lease obligations is estimated using discounted cash flow analyses based on the groups current incremental borrowing rates for similar types and maturities of borrowing.
$ million | ||||||||||||||||||
2013 | 2012 | |||||||||||||||||
Fair value |
Carrying amount |
Fair value |
Carrying amount |
|||||||||||||||
Short-term borrowings |
1,110 | 1,110 | 3,131 | 3,131 | ||||||||||||||
Long-term borrowings |
47,398 | 46,547 | 45,969 | 44,653 | ||||||||||||||
Net obligations under finance leases |
654 | 535 | 520 | 384 | ||||||||||||||
Total finance debt |
49,162 | 48,192 | 49,620 | 48,168 |
28. Capital disclosures and analysis of changes in net debt
The group defines capital as total equity. The groups approach to managing capital is set out in its financial framework which BP continues to refine to support the pursuit of value growth for shareholders, whilst maintaining a secure financial base. We intend to maintain a net debt ratio within the 10-20% gearing range, and continue to hold a significant liquidity buffer while uncertainties remain.
The group monitors capital on the basis of the net debt ratio, that is, the ratio of net debt to net debt plus equity. Net debt is calculated as gross finance debt, as shown in the balance sheet, plus the fair value of associated derivative financial instruments that are used to hedge foreign exchange and interest rate risks relating to finance debt, for which hedge accounting is applied, less cash and cash equivalents. Net debt and net debt ratio are non-GAAP measures. BP believes these measures provide useful information to investors. Net debt enables investors to see the economic effect of gross debt, related hedges and cash and cash equivalents in total. The net debt ratio enables investors to see how significant net debt is relative to equity from shareholders. The derivatives are reported on the balance sheet within the headings Derivative financial instruments. All components of equity are included in the denominator of the calculation. At 31 December 2013, the net debt ratio was 16.2% (2012 18.7%).
During 2013, the company repurchased 753 million shares for a total amount of $5.5 billion, including fees and stamp duty, as part of its share buyback programme announced on 22 March 2013. During 2012, the company did not repurchase any of its own shares, other than as needed to satisfy the requirements of certain employee share-based payment plans.
$ million | ||||||||||
At 31 December | 2013 | 2012 | ||||||||
Gross debt |
48,192 | 48,800 | ||||||||
Fair value (asset) liability of hedges related to finance debt |
(477 | ) | (1,700 | ) | ||||||
47,715 | 47,100 | |||||||||
Less: cash and cash equivalents |
22,520 | 19,635 | ||||||||
Net debt |
25,195 | 27,465 | ||||||||
Equity |
130,407 | 119,752 | ||||||||
Net debt ratio |
16.2% | 18.7% |
BP Annual Report and Form 20-F 2013 | 177 |
28. Capital disclosures and analysis of changes in net debt continued
An analysis of changes in net debt is provided below.
$ million | ||||||||||||||||||||||||||
2013 | 2012 | |||||||||||||||||||||||||
Movement in net debt | Finance debta | Cash and cash equivalents |
Net debt | Finance debta |
Cash and cash equivalents |
Net debt | ||||||||||||||||||||
At 1 January |
(47,100 | ) | 19,635 | (27,465 | ) | (43,075 | ) | 14,177 | (28,898 | ) | ||||||||||||||||
Exchange adjustments |
(219 | ) | 40 | (179 | ) | (75 | ) | 64 | (11 | ) | ||||||||||||||||
Net cash flow |
(836 | ) | 2,845 | 2,009 | (3,244 | ) | 5,394 | 2,150 | ||||||||||||||||||
Movement in finance debt relating to investing activitiesb |
632 | | 632 | (602 | ) | | (602 | ) | ||||||||||||||||||
Other movements |
(192 | ) | | (192 | ) | (104 | ) | | (104 | ) | ||||||||||||||||
At 31 December |
(47,715 | ) | 22,520 | (25,195 | ) | (47,100 | ) | 19,635 | (27,465 | ) |
a | Including the fair value of associated derivative financial instruments. |
b | See Note 27 for further information. |
$ million | ||||||||||||||||||||||||||||||
Decommissioning | Environmental | Spill response |
Litigation and claims |
Clean Water Act penalties |
Other | Total | ||||||||||||||||||||||||
At 1 January 2013 |
17,374 | 3,631 | 345 | 10,251 | 3,510 | 2,872 | 37,983 | |||||||||||||||||||||||
Exchange adjustments |
(37 | ) | (7 | ) | | 5 | | 14 | (25 | ) | ||||||||||||||||||||
New or increased provisions |
2,092 | 472 | (66 | ) | 2,466 | | 464 | 5,428 | ||||||||||||||||||||||
Derecognition of provisions for items that cannot be reliably estimated |
| | | (379 | ) | | | (379 | ) | |||||||||||||||||||||
Write-back of unused provisions |
(2 | ) | (52 | ) | | (38 | ) | | (210 | ) | (302 | ) | ||||||||||||||||||
Transfer between categories of provision |
| 47 | (47 | ) | | | | | ||||||||||||||||||||||
Unwinding of discount |
110 | 11 | | 10 | | 16 | 147 | |||||||||||||||||||||||
Change in discount rate |
(1,602 | ) | (41 | ) | | (20 | ) | | (13 | ) | (1,676 | ) | ||||||||||||||||||
Utilization |
(500 | ) | (695 | ) | (143 | ) | (3,451 | ) | | (230 | ) | (5,019 | ) | |||||||||||||||||
Reclassified to other payables |
| | | (3,933 | ) | | | (3,933 | ) | |||||||||||||||||||||
Deletions |
(230 | ) | (1 | ) | | | | (33 | ) | (264 | ) | |||||||||||||||||||
At 31 December 2013 |
17,205 | 3,365 | 89 | 4,911 | 3,510 | 2,880 | 31,960 | |||||||||||||||||||||||
Of which current |
866 | 769 | 84 | 2,725 | | 601 | 5,045 | |||||||||||||||||||||||
non-current |
16,339 | 2,596 | 5 | 2,186 | 3,510 | 2,279 | 26,915 | |||||||||||||||||||||||
Of which Gulf of Mexico oil spill |
| 1,590 | 89 | 4,157 | 3,510 | | 9,346 |
Further information on the financial impacts of the Gulf of Mexico oil spill is provided in Note 2.
The group makes full provision for the future cost of decommissioning oil and natural gas wells, facilities and related pipelines on a discounted basis upon installation. The provision for the costs of decommissioning these wells, production facilities and pipelines at the end of their economic lives has been estimated using existing technology, at current prices or future assumptions, depending on the expected timing of the activity, and discounted using a real discount rate of 1% (2012 0.5%). The amount provided in the year for new or increased decommissioning provisions was $2,092 million (2012 $3,766 million). The weighted average period over which these costs are generally expected to be incurred is estimated to be approximately 20 years. While the provision is based on the best estimate of future costs and the economic lives of the facilities and pipelines, there is uncertainty regarding both the amount and timing of these costs.
Provisions for environmental remediation are made when a clean-up is probable and the amount of the obligation can be estimated reliably. Generally, this coincides with commitment to a formal plan of action or, if earlier, on divestment or on closure of inactive sites. The provision for environmental liabilities has been estimated using existing technology, at current prices and discounted using a real discount rate of 1% (2012 0.5%). The weighted average period over which these costs are generally expected to be incurred is estimated to be approximately five years. The extent and cost of future remediation programmes are inherently difficult to estimate; they depend on the scale of any possible contamination, the timing and extent of corrective actions, and also the groups share of the liability.
The litigation category includes provisions for matters related to, for example, commercial disputes, product liability, and allegations of exposures of third parties to toxic substances. Included within the other category at 31 December 2013 are provisions for deferred employee compensation of $602 million (2012 $618 million). These provisions are discounted using either a nominal discount rate of 3.25% (2012 2.5%) or a real discount rate of 1% (2012 0.5%), as appropriate.
30. Pensions and other post-retirement benefits
Most group companies have pension plans, the forms and benefits of which vary with conditions and practices in the countries concerned. Pension benefits may be provided through defined contribution plans (money purchase schemes) or defined benefit plans (final salary and other types of schemes with committed pension payments). For defined contribution plans, retirement benefits are determined by the value of funds arising from contributions paid in respect of each employee. For defined benefit plans, retirement benefits are based on such factors as the employees pensionable salary and length of service. Defined benefit plans may be funded or unfunded. The assets of funded plans are generally held in separately administered trusts.
In particular, the primary pension arrangement in the UK is a funded final salary pension plan under which retired employees draw the majority of their benefit as an annuity. This pension plan is governed by a trustee board composed of four member-nominated and four company-nominated representatives, an independent chairman, an independent director and a chief executive officer appointed by the chairman. The trustee board is required by law to act in the best interests of the plan participants and is responsible for setting certain policies, such as investment policies of the plan.
178 | BP Annual Report and Form 20-F 2013 |
30. Pensions and other post-retirement benefits continued
The UK plan is closed to new joiners but remains open to ongoing accrual for current members. New joiners in the UK are eligible for membership of a defined contribution plan.
In the US, a range of retirement arrangements is provided. This includes a funded final salary pension plan for certain heritage employees and a cash balance arrangement for new joiners. Retired US employees typically take their pension benefit in the form of a lump sum payment. The plans assets are overseen by a fiduciary investment committee composed of seven company employees appointed by the appointing officer, who is the president of BP Corporation North America Inc. The investment committee is required by law to act in the best interests of the plan participants and is responsible for setting certain policies, such as the investment policies, of the plan. US employees are also eligible to participate in a defined contribution (401k) plan in which employee contributions are matched with company contributions.
The level of contributions to funded defined benefit plans is the amount needed to provide adequate funds to meet pension obligations as they fall due. During 2013, contributions of $597 million (2012 $884 million and 2011 $429 million) and $386 million (2012 $153 million and 2011 $777 million) were made to the UK plans and US plans respectively. In addition, contributions of $289 million (2012 $238 million and 2011 $223 million) were made to other funded defined benefit plans. The aggregate level of contributions in 2014 is expected to be approximately $1,250 million, and includes contributions in all countries that we expect to be required to make by law or under contractual agreements as well as an allowance for discretionary funding.
For the primary UK plan there is an agreement between the group and the trustee under which contributions are determined annually based on the funding level of the plan. Under this agreement a proportion of any deficit and the service cost is funded in the following year. Contributions in the US are determined by legislation and are supplemented by discretionary contributions.
Certain group companies, principally in the US, provide post-retirement healthcare and life insurance benefits to retired employees and their dependants. The entitlement to these benefits is usually based on the employee remaining in service until retirement age and completion of a minimum period of service.
The obligation and cost of providing pensions and other post-retirement benefits is assessed annually using the projected unit credit method. The date of the most recent actuarial review was 31 December 2013. The groups principal plans are subject to a formal actuarial valuation every three years in the UK, with valuations being required more frequently in many other countries. The most recent formal actuarial valuation of the UK pension plans was as at 31 December 2011.
The material financial assumptions used to estimate the benefit obligations of the various plans are set out below. The assumptions are reviewed by management at the end of each year, and are used to evaluate accrued pension and other post-retirement benefits at 31 December and pension expense for the following year.
% | ||||||||||||||||||||||||||||||||||||||
Financial assumptions used to determine benefit obligation | 2013 | 2012 | UK 2011 |
2013 | 2012 | US 2011 |
2013 | 2012 | Other 2011 |
|||||||||||||||||||||||||||||
Discount rate for pension plan liabilities |
4.6 | 4.4 | 4.8 | 4.3 | 3.2 | 4.3 | 3.9 | 3.6 | 4.7 | |||||||||||||||||||||||||||||
Discount rate for other post-retirement benefit plan liabilities |
n/a | n/a | n/a | 4.5 | 3.7 | 4.5 | n/a | n/a | n/a | |||||||||||||||||||||||||||||
Rate of increase in salaries |
5.1 | 4.9 | 5.1 | 3.9 | 4.2 | 3.7 | 3.7 | 3.7 | 3.7 | |||||||||||||||||||||||||||||
Rate of increase for pensions in payment |
3.3 | 3.1 | 3.2 | | | | 1.7 | 1.7 | 1.7 | |||||||||||||||||||||||||||||
Rate of increase in deferred pensions |
3.3 | 3.1 | 3.2 | | | | 1.3 | 1.2 | 1.2 | |||||||||||||||||||||||||||||
Inflation for pension plan liabilities |
3.3 | 3.1 | 3.2 | 2.1 | 2.4 | 1.9 | 2.2 | 2.2 | 2.2 | |||||||||||||||||||||||||||||
Financial assumptions used to determine benefit expense | 2013 | 2012 | UK 2011 |
2013 | 2012 | US 2011 |
2013 | 2012 | Other 2011 |
|||||||||||||||||||||||||||||
Discount rate for pension plan service cost |
4.4 | 4.8 | 5.5 | 3.2 | 4.3 | 4.7 | 3.6 | 4.7 | 5.3 | |||||||||||||||||||||||||||||
Discount rate for pension plan other finance expense |
4.4 | 4.8 | 5.5 | 3.2 | 4.3 | 4.7 | 3.6 | 4.7 | 5.3 | |||||||||||||||||||||||||||||
Discount rate for other post-retirement benefit plan service cost |
n/a | n/a | n/a | 3.7 | 4.5 | 5.3 | n/a | n/a | n/a | |||||||||||||||||||||||||||||
Inflation for pension plan service cost |
3.1 | 3.2 | 3.5 | 2.4 | 1.9 | 2.3 | 2.2 | 2.2 | 2.3 |
Our discount rate assumptions are based on third-party AA corporate bond indices and for our largest plans in the UK, US and Germany we use yields that reflect the maturity profile of the expected benefit payments. The inflation rate assumptions for our UK and US plans are based on the difference between the yields on index-linked and fixed-interest long-term government bonds. In other countries we use either this approach, or the central bank inflation target, or advice from the local actuary depending on the information that is available to us. The inflation assumptions are used to determine the rate of increase for pensions in payment and the rate of increase in deferred pensions where there is such an increase.
Our assumptions for the rate of increase in salaries are based on our inflation assumption plus an allowance for expected long-term real salary growth. These include allowance for promotion-related salary growth, of between 0.3% and 1.0% depending on country.
In addition to the financial assumptions, we regularly review the demographic and mortality assumptions. The mortality assumptions reflect best practice in the countries in which we provide pensions, and have been chosen with regard to the latest available published tables adjusted where appropriate to reflect the experience of the group and an extrapolation of past longevity improvements into the future. BPs most substantial pension liabilities are in the UK, the US and Germany where our mortality assumptions are as follows:
Years | ||||||||||||||||||||||||||||||||||||||
Mortality assumptions | 2013 | 2012 | UK 2011 |
2013 | 2012 | US 2011 |
2013 | 2012 |
Germanya 2011 |
|||||||||||||||||||||||||||||
Life expectancy at age 60 for a male currently aged 60 |
27.8 | 27.7 | 27.6 | 24.9 | 24.9 | 24.8 | 23.3 | 23.1 | 23.0 | |||||||||||||||||||||||||||||
Life expectancy at age 60 for a male currently aged 40 |
30.7 | 30.6 | 30.5 | 26.4 | 26.3 | 26.3 | 26.1 | 26.0 | 25.8 | |||||||||||||||||||||||||||||
Life expectancy at age 60 for a female currently aged 60 |
29.5 | 29.4 | 29.3 | 26.5 | 26.4 | 26.4 | 27.8 | 27.7 | 27.5 | |||||||||||||||||||||||||||||
Life expectancy at age 60 for a female currently aged 40 |
32.2 | 32.1 | 32.0 | 27.3 | 27.3 | 27.3 | 30.5 | 30.3 | 30.2 |
a | Minor amendments have been made to comparative amounts. |
BP Annual Report and Form 20-F 2013 | 179 |
30. Pensions and other post-retirement benefits continued
Our assumption for future US healthcare cost trend rate for the first year after the reporting date reflects the rate of actual cost increases seen in recent years. The ultimate trend rate reflects our long-term expectations of the level at which cost inflation will stabilize based on past healthcare cost inflation seen over a longer period of time. The assumed future US healthcare cost trend rate assumptions are as follows:
% | ||||||||||||||
2013 | 2012 | 2011 | ||||||||||||
First years US healthcare cost trend rate |
7.3 | 7.3 | 7.6 | |||||||||||
Ultimate US healthcare cost trend rate |
5.0 | 5.0 | 5.0 | |||||||||||
Year in which ultimate trend rate is reached |
2021 | 2020 | 2020 |
Pension plan assets are generally held in trusts. The primary objective of the trusts is to accumulate pools of assets sufficient to meet the obligations of the various plans. The assets of the trusts are invested in a manner consistent with fiduciary obligations and principles that reflect current practices in portfolio management.
A significant proportion of the assets are held in equities, owing to a higher expected level of return over the long term with an acceptable level of risk. In order to provide reasonable assurance that no single security or type of security has an unwarranted impact on the total portfolio, the investment portfolios are highly diversified.
The current long-term asset allocation policy for the major plans is as follows:
% | ||||||||||||||
Asset category | UK |
US | Other | |||||||||||
Total equity |
70 | 60 | 17-65 | |||||||||||
Bonds/cash |
23 | 40 | 25-78 | |||||||||||
Property/real estate |
7 | | 0-10 |
The groups main pension plans do not invest directly in either securities or property/real estate of the company or of any subsidiary. Some of the groups pension plans use derivative financial instruments as part of their asset mix to manage the level of risk.
For the primary UK pension plan there is an agreement with the trustee to reduce the proportion of plan assets held as equities and increase the proportion held as bonds at certain market trigger points, over time, with a view to better matching the pension liabilities. During 2013 the first trigger point was reached. There is a similar agreement in place in the US where trigger points were reached in 2011 and 2013.
BPs main plans in the UK and US do not currently follow a liability driven investment (LDI) approach, a form of investing designed to match the movement in pension plan assets with the movement in projected benefit obligations over time.
180 | BP Annual Report and Form 20-F 2013 |
30. Pensions and other post-retirement benefits continued
The fair values of the various categories of assets held by the defined benefit plans at 31 December are presented in the table below, including the effects of derivative financial instruments. Movements in the fair value of plan assets during the year are shown in detail in the table on page 182.
$ million | ||||||||||||||||||||||
UK pension plansa |
US pension plansb |
US other post- retirement benefit plans |
Other plans |
Total | ||||||||||||||||||
Fair value of pension plan assets |
||||||||||||||||||||||
At 31 December 2013 |
||||||||||||||||||||||
Listed equities developed markets |
17,341 | 3,260 | | 913 | 21,514 | |||||||||||||||||
emerging markets |
2,290 | 308 | | 84 | 2,682 | |||||||||||||||||
Private equity |
2,907 | 1,432 | | 6 | 4,345 | |||||||||||||||||
Government issued nominal bonds |
549 | 1,259 | | 1,258 | 3,066 | |||||||||||||||||
Index-linked bonds |
787 | | | 69 | 856 | |||||||||||||||||
Corporate bonds |
4,427 | 1,323 | | 982 | 6,732 | |||||||||||||||||
Property |
2,200 | 6 | | 134 | 2,340 | |||||||||||||||||
Cash |
855 | 135 | | 278 | 1,268 | |||||||||||||||||
Other |
160 | 55 | | 113 | 328 | |||||||||||||||||
31,516 | 7,778 | | 3,837 | 43,131 | ||||||||||||||||||
At 31 December 2012 |
||||||||||||||||||||||
Listed equities developed markets |
15,659 | 3,622 | | 844 | 20,125 | |||||||||||||||||
emerging markets |
1,074 | 341 | | 89 | 1,504 | |||||||||||||||||
Private equity |
2,879 | 1,468 | | 7 | 4,354 | |||||||||||||||||
Government issued nominal bonds |
544 | 904 | | 1,042 | 2,490 | |||||||||||||||||
Index-linked bonds |
491 | | | 78 | 569 | |||||||||||||||||
Corporate bonds |
3,850 | 1,255 | | 766 | 5,871 | |||||||||||||||||
Property |
1,783 | 5 | | 139 | 1,927 | |||||||||||||||||
Cash |
1,000 | 86 | 1 | 321 | 1,408 | |||||||||||||||||
Other |
66 | 105 | | 247 | 418 | |||||||||||||||||
27,346 | 7,786 | 1 | 3,533 | 38,666 | ||||||||||||||||||
At 31 December 2011 |
||||||||||||||||||||||
Listed equities developed markets |
13,622 | 3,328 | | 754 | 17,704 | |||||||||||||||||
emerging markets |
890 | 299 | | 69 | 1,258 | |||||||||||||||||
Private equity |
2,690 | 1,407 | | 8 | 4,105 | |||||||||||||||||
Government issued nominal bonds |
513 | 733 | | 993 | 2,239 | |||||||||||||||||
Index-linked bonds |
390 | | | 123 | 513 | |||||||||||||||||
Corporate bonds |
3,238 | 1,289 | | 724 | 5,251 | |||||||||||||||||
Property |
1,710 | 4 | | 117 | 1,831 | |||||||||||||||||
Cash |
470 | 88 | 4 | 326 | 888 | |||||||||||||||||
Other |
64 | 56 | | 172 | 292 | |||||||||||||||||
23,587 | 7,204 | 4 | 3,286 | 34,081 |
a | Bonds held by the UK pension fund are typically denominated in sterling. Property held by the UK pension fund is in the United Kingdom. |
b | Bonds held by the US pension fund are typically denominated in US dollars. |
BP Annual Report and Form 20-F 2013 | 181 |
30. Pensions and other post-retirement benefits continued
$ million | ||||||||||||||||||||||
2013 | ||||||||||||||||||||||
UK pension plans |
US pension plans |
US other post- retirement benefit plans |
Other plans |
Total | ||||||||||||||||||
Analysis of the amount charged to profit before interest and taxation |
||||||||||||||||||||||
Current service costa |
497 | 358 | 49 | 177 | 1,081 | |||||||||||||||||
Past service costb |
(22 | ) | (49 | ) | | 27 | (44 | ) | ||||||||||||||
Settlement |
| | | (1 | ) | (1 | ) | |||||||||||||||
Operating charge relating to defined benefit plans |
475 | 309 | 49 | 203 | 1,036 | |||||||||||||||||
Payments to defined contribution plans |
24 | 223 | | 53 | 300 | |||||||||||||||||
Total operating charge |
499 | 532 | 49 | 256 | 1,336 | |||||||||||||||||
Interest income on plan assets |
(1,139 | ) | (240 | ) | | (130 | ) | (1,509 | ) | |||||||||||||
Interest on plan liabilities |
1,221 | 305 | 101 | 362 | 1,989 | |||||||||||||||||
Other finance expense |
82 | 65 | 101 | 232 | 480 | |||||||||||||||||
Analysis of the amount recognized in other comprehensive income |
||||||||||||||||||||||
Actual asset return less interest income on plan assetsa |
2,671 | 730 | | 114 | 3,515 | |||||||||||||||||
Change in financial assumptions underlying the present value of the plan liabilities |
60 | 1,054 | 106 | 283 | 1,503 | |||||||||||||||||
Change in demographic assumptions underlying the present value of the plan liabilities |
| 14 | | (65 | ) | (51 | ) | |||||||||||||||
Experience gains and losses arising on the plan liabilities |
41 | (205 | ) | (44 | ) | 5 | (203 | ) | ||||||||||||||
Remeasurements recognized in other comprehensive income |
2,772 | 1,593 | 62 | 337 | 4,764 | |||||||||||||||||
Movements in benefit obligation during the year |
||||||||||||||||||||||
Benefit obligation at 1 January |
29,259 | 10,029 | 2,845 | 10,148 | 52,281 | |||||||||||||||||
Exchange adjustments |
705 | | | 132 | 837 | |||||||||||||||||
Operating charge relating to defined benefit plans |
475 | 309 | 49 | 203 | 1,036 | |||||||||||||||||
Interest cost |
1,221 | 305 | 101 | 362 | 1,989 | |||||||||||||||||
Contributions by plan participantsc |
37 | | | 13 | 50 | |||||||||||||||||
Benefit payments (funded plans)d |
(1,087 | ) | (1,364 | ) | (1 | ) | (192 | ) | (2,644 | ) | ||||||||||||
Benefit payments (unfunded plans)d |
(4 | ) | (52 | ) | (233 | ) | (395 | ) | (684 | ) | ||||||||||||
Disposals |
(9 | ) | | (61 | ) | (13 | ) | (83 | ) | |||||||||||||
Remeasurements |
(101 | ) | (863 | ) | (62 | ) | (223 | ) | (1,249 | ) | ||||||||||||
Benefit obligation at 31 Decembera e |
30,496 | 8,364 | 2,638 | 10,035 | 51,533 | |||||||||||||||||
Movements in fair value of plan assets during the year |
||||||||||||||||||||||
Fair value of plan assets at 1 January |
27,346 | 7,786 | 1 | 3,533 | 38,666 | |||||||||||||||||
Exchange adjustments |
822 | | | (37 | ) | 785 | ||||||||||||||||
Interest income on plan assetsa |
1,139 | 240 | | 130 | 1,509 | |||||||||||||||||
Contributions by plan participantsc |
37 | | | 13 | 50 | |||||||||||||||||
Contributions by employers (funded plans) |
597 | 386 | | 289 | 1,272 | |||||||||||||||||
Benefit payments (funded plans)d |
(1,087 | ) | (1,364 | ) | (1 | ) | (192 | ) | (2,644 | ) | ||||||||||||
Disposals |
(9 | ) | | | (13 | ) | (22 | ) | ||||||||||||||
Remeasurementsf |
2,671 | 730 | | 114 | 3,515 | |||||||||||||||||
Fair value of plan assets at 31 December |
31,516 | 7,778 | | 3,837 | 43,131 | |||||||||||||||||
Surplus (deficit) at 31 December |
1,020 | (586 | ) | (2,638 | ) | (6,198 | ) | (8,402 | ) | |||||||||||||
Represented by |
||||||||||||||||||||||
Asset recognized |
1,291 | 6 | | 79 | 1,376 | |||||||||||||||||
Liability recognized |
(271 | ) | (592 | ) | (2,638 | ) | (6,277 | ) | (9,778 | ) | ||||||||||||
1,020 | (586 | ) | (2,638 | ) | (6,198 | ) | (8,402 | ) | ||||||||||||||
The surplus (deficit) may be analysed between funded and unfunded plans as follows |
||||||||||||||||||||||
Funded |
1,285 | (5 | ) | | (320 | ) | 960 | |||||||||||||||
Unfunded |
(265 | ) | (581 | ) | (2,638 | ) | (5,878 | ) | (9,362 | ) | ||||||||||||
1,020 | (586 | ) | (2,638 | ) | (6,198 | ) | (8,402 | ) | ||||||||||||||
The defined benefit obligation may be analysed between funded and unfunded plans as follows |
||||||||||||||||||||||
Funded |
(30,231 | ) | (7,783 | ) | | (4,157 | ) | (42,171 | ) | |||||||||||||
Unfunded |
(265 | ) | (581 | ) | (2,638 | ) | (5,878 | ) | (9,362 | ) | ||||||||||||
(30,496 | ) | (8,364 | ) | (2,638 | ) | (10,035 | ) | (51,533 | ) |
a | The costs of managing the plans investments are treated as being part of the return on plan assets, the costs of administering our pension plan benefits are generally included in current service cost and the costs of administering our other post-retirement benefit plans are included in the benefit obligation. |
b | Past service costs include a credit of $73 million as the result of a curtailment in the pension arrangements of a number of employees in the UK and US following divestment transactions. A charge of $29 million for special termination benefits represents the increased liability arising as a result of early retirements occurring as part of restructuring programmes. |
c | Most of the contributions made by plan participants into UK pension plans were made under salary sacrifice. |
d | The benefit payments amount shown above comprises $3,269 million benefits plus $59 million of plan expenses incurred in the administration of the benefit. |
e | The benefit obligation for other plans includes $4,874 million for the German plan, which is largely unfunded. |
f | The actual return on plan assets is made up of the sum of the interest income on plan assets and the remeasurment of plan assets as disclosed above. |
182 | BP Annual Report and Form 20-F 2013 |
30. Pensions and other post-retirement benefits continued
$ million | ||||||||||||||||||||||
2012 | ||||||||||||||||||||||
UK pension plans |
US pension plans |
US other post- retirement benefit plans |
Other plans |
Total | ||||||||||||||||||
Analysis of the amount charged to profit before interest and taxation |
||||||||||||||||||||||
Current service costa |
477 | 328 | 51 | 151 | 1,007 | |||||||||||||||||
Past service costb |
(1 | ) | 20 | | 82 | 101 | ||||||||||||||||
Settlement |
| | | 1 | 1 | |||||||||||||||||
Operating charge relating to defined benefit plans |
476 | 348 | 51 | 234 | 1,109 | |||||||||||||||||
Payments to defined contribution plans |
14 | 223 | | 44 | 281 | |||||||||||||||||
Total operating charge |
490 | 571 | 51 | 278 | 1,390 | |||||||||||||||||
Interest income on plan assets |
(1,146 | ) | (304 | ) | | (154 | ) | (1,604 | ) | |||||||||||||
Interest on plan liabilities |
1,249 | 382 | 134 | 405 | 2,170 | |||||||||||||||||
Other finance expense |
103 | 78 | 134 | 251 | 566 | |||||||||||||||||
Analysis of the amount recognized in other comprehensive income |
||||||||||||||||||||||
Actual asset return less interest income on plan assetsa |
1,523 | 718 | | 173 | 2,414 | |||||||||||||||||
Change in financial assumptions underlying the present value of the plan liabilities |
(1,446 | ) | (1,427 | ) | 187 | (1,093 | ) | (3,779 | ) | |||||||||||||
Change in demographic assumptions underlying the present value of the plan liabilities |
| | 52 | (37 | ) | 15 | ||||||||||||||||
Experience gains and losses arising on the plan liabilities |
(116 | ) | 68 | (48 | ) | (126 | ) | (222 | ) | |||||||||||||
Remeasurements recognized in other comprehensive income |
(39 | ) | (641 | ) | 191 | (1,083 | ) | (1,572 | ) | |||||||||||||
Movements in benefit obligation during the year |
||||||||||||||||||||||
Benefit obligation at 1 January |
25,675 | 8,617 | 3,061 | 8,801 | 46,154 | |||||||||||||||||
Exchange adjustments |
1,313 | | | 254 | 1,567 | |||||||||||||||||
Operating charge relating to defined benefit plans |
476 | 348 | 51 | 234 | 1,109 | |||||||||||||||||
Interest cost |
1,249 | 382 | 134 | 405 | 2,170 | |||||||||||||||||
Contributions by plan participantsc |
39 | | | 14 | 53 | |||||||||||||||||
Benefit payments (funded plans)d |
(1,038 | ) | (593 | ) | (3 | ) | (230 | ) | (1,864 | ) | ||||||||||||
Benefit payments (unfunded plans)d |
(7 | ) | (84 | ) | (207 | ) | (394 | ) | (692 | ) | ||||||||||||
Disposals |
(10 | ) | | | (192 | ) | (202 | ) | ||||||||||||||
Remeasurements |
1,562 | 1,359 | (191 | ) | 1,256 | 3,986 | ||||||||||||||||
Benefit obligation at 31 Decembera e |
29,259 | 10,029 | 2,845 | 10,148 | 52,281 | |||||||||||||||||
Movements in fair value of plan assets during the year |
||||||||||||||||||||||
Fair value of plan assets at 1 January |
23,587 | 7,204 | 4 | 3,286 | 34,081 | |||||||||||||||||
Exchange adjustments |
1,215 | | | 88 | 1,303 | |||||||||||||||||
Interest income on plan assetsa |
1,146 | 304 | | 154 | 1,604 | |||||||||||||||||
Contributions by plan participantsc |
39 | | | 14 | 53 | |||||||||||||||||
Contributions by employers (funded plans) |
884 | 153 | | 238 | 1,275 | |||||||||||||||||
Benefit payments (funded plans)d |
(1,038 | ) | (593 | ) | (3 | ) | (230 | ) | (1,864 | ) | ||||||||||||
Disposals |
(10 | ) | | | (190 | ) | (200 | ) | ||||||||||||||
Remeasurementsf |
1,523 | 718 | | 173 | 2,414 | |||||||||||||||||
Fair value of plan assets at 31 December |
27,346 | 7,786 | 1 | 3,533 | 38,666 | |||||||||||||||||
Deficit at 31 December |
(1,913 | ) | (2,243 | ) | (2,844 | ) | (6,615 | ) | (13,615 | ) | ||||||||||||
Represented by |
||||||||||||||||||||||
Asset recognized |
| | | 12 | 12 | |||||||||||||||||
Liability recognized |
(1,913 | ) | (2,243 | ) | (2,844 | ) | (6,627 | ) | (13,627 | ) | ||||||||||||
(1,913 | ) | (2,243 | ) | (2,844 | ) | (6,615 | ) | (13,615 | ) | |||||||||||||
The surplus (deficit) may be analysed between funded and unfunded plans as follows |
||||||||||||||||||||||
Funded |
(1,688 | ) | (1,599 | ) | (43 | ) | (539 | ) | (3,869 | ) | ||||||||||||
Unfunded |
(225 | ) | (644 | ) | (2,801 | ) | (6,076 | ) | (9,746 | ) | ||||||||||||
(1,913 | ) | (2,243 | ) | (2,844 | ) | (6,615 | ) | (13,615 | ) | |||||||||||||
The defined benefit obligation may be analysed between funded and unfunded plans as follows |
||||||||||||||||||||||
Funded |
(29,034 | ) | (9,385 | ) | (44 | ) | (4,072 | ) | (42,535 | ) | ||||||||||||
Unfunded |
(225 | ) | (644 | ) | (2,801 | ) | (6,076 | ) | (9,746 | ) | ||||||||||||
(29,259 | ) | (10,029 | ) | (2,845 | ) | (10,148 | ) | (52,281 | ) |
a | The costs of managing the plans investments are treated as being part of the return on plan assets, the costs of administering our pension plan benefits are generally included in current service cost and the costs of administering our other post-retirement benefit plans are included in the benefit obligation. |
b | Past service costs are charges for special termination benefits representing the increased liability arising as a result of early retirements occurring as part of restructuring programmes. |
c | Most of the contributions made by plan participants into UK pension plans were made under salary sacrifice. |
d | The benefit payments amount shown above comprises $2,501 million benefits plus $55 million of plan expenses incurred in the administration of the benefit. |
e | The benefit obligation for other plans includes $4,783 million for the German plan, which is largely unfunded. |
f | The actual return on plan assets is made up of the sum of the interest income on plan assets and the remeasurement of plan assets as disclosed above. |
BP Annual Report and Form 20-F 2013 | 183 |
30. Pensions and other post-retirement benefits continued
$ million | ||||||||||||||||||||||
2011 | ||||||||||||||||||||||
UK pension |
US pension plans |
US other post- retirement benefit plans |
Other plans |
Total | ||||||||||||||||||
Analysis of the amount charged to profit before interest and taxation |
||||||||||||||||||||||
Current service costa |
383 | 280 | 53 | 135 | 851 | |||||||||||||||||
Past service cost |
3 | 184 | | 43 | 230 | |||||||||||||||||
Settlement |
| | | 4 | 4 | |||||||||||||||||
Operating charge relating to defined benefit plans |
386 | 464 | 53 | 182 | 1,085 | |||||||||||||||||
Payments to defined contribution plans |
5 | 199 | | 41 | 245 | |||||||||||||||||
Total operating charge |
391 | 663 | 53 | 223 | 1,330 | |||||||||||||||||
Analysis of the amount credited (charged) to other finance expense |
||||||||||||||||||||||
Interest income on plan assets |
(1,361 | ) | (304 | ) | | (178 | ) | (1,843 | ) | |||||||||||||
Interest on plan liabilities |
1,263 | 369 | 163 | 448 | 2,243 | |||||||||||||||||
Other finance (income) expense |
(98 | ) | 65 | 163 | 270 | 400 | ||||||||||||||||
Analysis of the amount recognized in other comprehensive income |
||||||||||||||||||||||
Actual asset return less interest income on plan assetsa |
(1,552 | ) | 224 | (1 | ) | (54 | ) | (1,383 | ) | |||||||||||||
Change in financial assumptions underlying the present value of the plan liabilities |
(2,251 | ) | (468 | ) | (63 | ) | (636 | ) | (3,418 | ) | ||||||||||||
Change in demographic assumptions underlying the present value of the plan liabilities |
(429 | ) | (44 | ) | 102 | (6 | ) | (377 | ) | |||||||||||||
Experience gains and losses arising on the plan liabilities |
(84 | ) | (102 | ) | 89 | (26 | ) | (123 | ) | |||||||||||||
Remeasurements recognized in other comprehensive income |
(4,316 | ) | (390 | ) | 127 | (722 | ) | (5,301 | ) |
a | The costs of managing the plans investments are treated as being part of the return on plan assets, the costs of administering our pension plan benefits are generally included in current service cost and the costs of administering our other post-retirement benefit plans are included in the benefit obligation. |
At 31 December 2013, reimbursement balances due from or to other companies in respect of pensions amounted to $399 million reimbursement assets (2012 $381 million) and $15 million reimbursement liabilities (2012 $15 million). These balances are not included as part of the pension surpluses and deficits, but are reflected within other receivables and other payables in the group balance sheet.
Sensitivity analysis
The discount rate, inflation, salary growth, US healthcare cost trend rate and the mortality assumptions all have a significant effect on the amounts reported. A one-percentage point change, in isolation, in certain assumptions as at 31 December 2013 for the groups plans would have had the effects shown in the table below. The effects shown for the expense in 2014 comprise the total of current service cost and net finance income or expense.
$ million | ||||||||||
One percentage point | ||||||||||
Increase | Decrease | |||||||||
Discount ratea |
||||||||||
Effect on pension and other post-retirement benefit expense in 2014 |
(474 | ) | 481 | |||||||
Effect on pension and other post-retirement benefit obligation at 31 December 2013 |
(6,918 | ) | 9,059 | |||||||
Inflation rate |
||||||||||
Effect on pension and other post-retirement benefit expense in 2014 |
521 | (397 | ) | |||||||
Effect on pension and other post-retirement benefit obligation at 31 December 2013 |
7,120 | (5,658 | ) | |||||||
Salary growth |
||||||||||
Effect on pension and other post-retirement benefit expense in 2014 |
142 | (123 | ) | |||||||
Effect on pension and other post-retirement benefit obligation at 31 December 2013 |
1,300 | (1,158 | ) | |||||||
US healthcare cost trend rate |
||||||||||
Effect on US other post-retirement benefit expense in 2014 |
16 | (13 | ) | |||||||
Effect on US other post-retirement obligation at 31 December 2013 |
278 | (233 | ) |
a | The amounts presented reflect that the discount rate is used to determine the asset interest income as well as the interest cost on the obligation. |
One additional year of longevity in the mortality assumptions would have the effects shown in the table below. The effect shown for the expense in 2014 comprises the total of current service cost and net finance income or expense.
$ million | ||||||||||||||||||
UK pension |
US pension |
US other post- retirement benefit plans |
German pension plans |
|||||||||||||||
One additional years longevity |
||||||||||||||||||
Effect on pension and other post-retirement benefit expense in 2014 |
52 | 5 | 3 | 9 | ||||||||||||||
Effect on pension and other post-retirement benefit obligation at 31 December 2013 |
927 | 95 | 46 | 213 |
184 | BP Annual Report and Form 20-F 2013 |
30. Pensions and other post-retirement benefits continued
Estimated future benefit payments and the weighted average duration of defined benefit obligations
The expected benefit payments, which reflect expected future service, as appropriate, but exclude plan expenses, up until 2023 and the weighted average duration of the defined benefit obligations at the end of the reporting period are as follows:
$ million | ||||||||||||||||||||||
Estimated future benefit payments | UK pension plans |
US pension plans |
US other post- retirement benefit plans |
Other plans | Total | |||||||||||||||||
2014 |
1,153 | 690 | 174 | 596 | 2,613 | |||||||||||||||||
2015 |
1,201 | 715 | 177 | 585 | 2,678 | |||||||||||||||||
2016 |
1,265 | 726 | 178 | 582 | 2,751 | |||||||||||||||||
2017 |
1,281 | 733 | 178 | 570 | 2,762 | |||||||||||||||||
2018 |
1,361 | 735 | 178 | 560 | 2,834 | |||||||||||||||||
2019-2023 |
7,282 | 3,533 | 874 | 2,651 | 14,340 | |||||||||||||||||
years | ||||||||||||||||||||||
Weighted average duration |
17.6 | 8.3 | 10.5 | 13.2 |
The allotted, called up and fully paid share capital at 31 December was as follows:
2013 | 2012 | 2011 | ||||||||||||||||||||||||
Issued | Shares thousand |
$ million | Shares thousand |
$ million | Shares thousand |
$ million | ||||||||||||||||||||
8% cumulative first preference shares of £1 eacha |
7,233 | 12 | 7,233 | 12 | 7,233 | 12 | ||||||||||||||||||||
9% cumulative second preference shares of £1 eacha |
5,473 | 9 | 5,473 | 9 | 5,473 | 9 | ||||||||||||||||||||
21 | 21 | 21 | ||||||||||||||||||||||||
Ordinary shares of 25 cents each |
||||||||||||||||||||||||||
At 1 January |
20,959,159 | 5,240 | 20,813,410 | 5,203 | 20,647,160 | 5,162 | ||||||||||||||||||||
Issue of new shares for the scrip dividend programme |
202,124 | 51 | 138,406 | 35 | 165,601 | 41 | ||||||||||||||||||||
Issue of new shares for employee share-based payment plansb |
18,203 | 5 | 7,343 | 2 | 649 | | ||||||||||||||||||||
Repurchase of ordinary share capitalc |
(752,854 | ) | (188 | ) | | | | | ||||||||||||||||||
At 31 December |
20,426,632 | 5,108 | 20,959,159 | 5,240 | 20,813,410 | 5,203 | ||||||||||||||||||||
5,129 | 5,261 | 5,224 |
a | The nominal amount of 8% cumulative first preference shares and 9% cumulative second preference shares that can be in issue at any time shall not exceed £10,000,000 for each class of preference shares. |
b | The nominal value of new shares issued for the employee share plans in 2011 amounted to $162,000. Consideration received relating to the issue of new shares for employee share plans amounted to $116 million (2012 $47 million and 2011 $4 million). |
c | Purchased for a total consideration of $5,493 million, including transaction costs of $30 million. All shares purchased were for cancellation. The repurchased shares represented 3.6% of ordinary share capital. |
Voting on substantive resolutions tabled at a general meeting is on a poll. On a poll, shareholders present in person or by proxy have two votes for every £5 in nominal amount of the first and second preference shares held and one vote for every ordinary share held. On a show-of-hands vote on other resolutions (procedural matters) at a general meeting, shareholders present in person or by proxy have one vote each.
In the event of the winding up of the company, preference shareholders would be entitled to a sum equal to the capital paid up on the preference shares, plus an amount in respect of accrued and unpaid dividends and a premium equal to the higher of (i) 10% of the capital paid up on the preference shares and (ii) the excess of the average market price of such shares on the London Stock Exchange during the previous six months over par value.
During 2013 the company repurchased 753 million ordinary shares at a cost of $5,463 million as part of the share repurchase programme announced on 22 March 2013. The number of shares in issue is reduced when shares are repurchased, but is not reduced in respect of the year-end commitment to repurchase shares subsequent to the end of the year, for which an amount of $1,430 million has been accrued at 31 December 2013 (2012 nil).
Treasury shares
2013 | 2012 | 2011 | ||||||||||||||||||||||||
Shares thousand |
Nominal value $ million |
Shares thousand |
Nominal value $ million |
Shares thousand |
Nominal value $ million |
|||||||||||||||||||||
At 1 January |
1,823,408 | 455 | 1,837,508 | 459 | 1,850,699 | 462 | ||||||||||||||||||||
Shares re-issued for employee share-based payment plans |
(35,469 | ) | (8 | ) | (14,100 | ) | (4 | ) | (13,191 | ) | (3 | ) | ||||||||||||||
At 31 December |
1,787,939 | 447 | 1,823,408 | 455 | 1,837,508 | 459 |
For each year presented, the balance at 1 January represents the maximum number of shares held in treasury during the year, representing 8.7% (2012 8.8% and 2011 9.0%) of the called-up ordinary share capital of the company.
During 2013, the movement in treasury shares represented less than 0.2% (2012 less than 0.1% and 2011 less than 0.1%) of the ordinary share capital of the company.
BP Annual Report and Form 20-F 2013 | 185 |
Share capital |
Share premium account |
Capital redemption reserve |
Merger reserve |
Total share capital and capital reserves |
||||||||||||||||||
At 1 January 2013 |
5,261 | 9,974 | 1,072 | 27,206 | 43,513 | |||||||||||||||||
Profit for the year |
| | | | | |||||||||||||||||
Items that may be reclassified subsequently to profit or loss |
||||||||||||||||||||||
Currency translation differences (including recycling) |
| | | | | |||||||||||||||||
Available-for-sale investments (including recycling) |
| | | | | |||||||||||||||||
Cash flow hedges (including recycling) |
| | | | | |||||||||||||||||
Share of items relating to equity-accounted entities, net of tax |
| | | | | |||||||||||||||||
Other |
| | | | | |||||||||||||||||
Items that will not be reclassified to profit or loss |
||||||||||||||||||||||
Remeasurements of the net pension and other post-retirement benefit liability or asset |
| | | | | |||||||||||||||||
Share of items relating to equity-accounted entities, net of tax |
| | | | | |||||||||||||||||
Total comprehensive income |
| | | | | |||||||||||||||||
Dividends |
51 | (51 | ) | | | | ||||||||||||||||
Repurchases of ordinary share capital |
(188 | ) | | 188 | | | ||||||||||||||||
Share-based payments, net of taxa |
5 | 138 | | | 143 | |||||||||||||||||
Share of equity-accounted entities changes in equity, net of tax |
| | | | | |||||||||||||||||
Transactions involving non-controlling interests |
| | | | | |||||||||||||||||
At 31 December 2013 |
5,129 | 10,061 | 1,260 | 27,206 | 43,656 | |||||||||||||||||
Share capital |
Share premium account |
Capital redemption reserve |
Merger reserve |
Total share capital and capital reserves |
||||||||||||||||||
At 1 January 2012 |
5,224 | 9,952 | 1,072 | 27,206 | 43,454 | |||||||||||||||||
Profit for the year |
| | | | | |||||||||||||||||
Items that may be reclassified subsequently to profit or loss |
||||||||||||||||||||||
Currency translation differences (including recycling) |
| | | | | |||||||||||||||||
Available-for-sale investments (including recycling) |
| | | | | |||||||||||||||||
Cash flow hedges (including recycling) |
| | | | | |||||||||||||||||
Share of items relating to equity-accounted entities, net of tax |
| | | | | |||||||||||||||||
Other |
| | | | | |||||||||||||||||
Items that will not be reclassified to profit or loss |
||||||||||||||||||||||
Remeasurements of the net pension and other post-retirement benefit liability or asset |
| | | | | |||||||||||||||||
Share of items relating to equity-accounted entities, net of tax |
| | | | | |||||||||||||||||
Total comprehensive income |
| | | | | |||||||||||||||||
Dividends |
35 | (35 | ) | | | | ||||||||||||||||
Share-based payments, net of taxa |
2 | 57 | | | 59 | |||||||||||||||||
Transactions involving non-controlling interests |
| | | | | |||||||||||||||||
At 31 December 2012 |
5,261 | 9,974 | 1,072 | 27,206 | 43,513 | |||||||||||||||||
Share capital |
Share premium account |
Capital redemption reserve |
Merger reserve |
Total share capital and capital reserves |
||||||||||||||||||
At 1 January 2011 |
5,183 | 9,987 | 1,072 | 27,206 | 43,448 | |||||||||||||||||
Profit for the year |
| | | | | |||||||||||||||||
Items that may be reclassified subsequently to profit or loss |
||||||||||||||||||||||
Currency translation differences (including recycling) |
| | | | | |||||||||||||||||
Available-for-sale investments (including recycling) |
| | | | | |||||||||||||||||
Cash flow hedges (including recycling) |
| | | | | |||||||||||||||||
Share of items relating to equity-accounted entities, net of tax |
| | | | | |||||||||||||||||
Items that will not be reclassified to profit or loss |
||||||||||||||||||||||
Remeasurements of the net pension and other post-retirement benefit liability or asset |
| | | | | |||||||||||||||||
Total comprehensive income |
| | | | | |||||||||||||||||
Dividends |
41 | (41 | ) | | | | ||||||||||||||||
Share-based payments, net of taxa |
| 6 | | | 6 | |||||||||||||||||
Transactions involving non-controlling interests |
| | | | | |||||||||||||||||
At 31 December 2011 |
5,224 | 9,952 | 1,072 | 27,206 | 43,454 |
a | Includes new share issues and movements in own shares and treasury shares where these relate to employee share-based payment plans. |
186 | BP Annual Report and Form 20-F 2013 |
$ million | ||||||||||||||||||||||||||||||||||||||||||||||||
Own shares |
Treasury shares |
Total own shares and treasury shares |
Foreign currency translation reserve |
Available- for-sale investments |
Cash flow hedges |
Total fair value reserves |
Share- based payment reserve |
Profit and loss account |
BP shareholders equity |
Non- controlling interests |
Total equity |
|||||||||||||||||||||||||||||||||||||
(280 | ) | (20,774 | ) | (21,054 | ) | 5,128 | 685 | 1,090 | 1,775 | 1,608 | 87,576 | 118,546 | 1,206 | 119,752 | ||||||||||||||||||||||||||||||||||
| | | | | | | | 23,451 | 23,451 | 307 | 23,758 | |||||||||||||||||||||||||||||||||||||
| | | (1,603 | ) | | | | | | (1,603 | ) | (15 | ) | (1,618 | ) | |||||||||||||||||||||||||||||||||
| | | | (685 | ) | | (685 | ) | | | (685 | ) | | (685 | ) | |||||||||||||||||||||||||||||||||
| | | | | (1,785 | ) | (1,785 | ) | | | (1,785 | ) | | (1,785 | ) | |||||||||||||||||||||||||||||||||
| | | | | | | | (24 | ) | (24 | ) | | (24 | ) | ||||||||||||||||||||||||||||||||||
| | | | | | | | (25 | ) | (25 | ) | | (25 | ) | ||||||||||||||||||||||||||||||||||
| | | | | | | | 3,243 | 3,243 | | 3,243 | |||||||||||||||||||||||||||||||||||||
| | | | | | | | 2 | 2 | | 2 | |||||||||||||||||||||||||||||||||||||
| | | (1,603 | ) | (685 | ) | (1,785 | ) | (2,470 | ) | | 26,647 | 22,574 | 292 | 22,866 | |||||||||||||||||||||||||||||||||
| | | | | | | | (5,441 | ) | (5,441 | ) | (469 | ) | (5,910 | ) | |||||||||||||||||||||||||||||||||
| | | | | | | | (6,923 | ) | (6,923 | ) | | (6,923 | ) | ||||||||||||||||||||||||||||||||||
(321 | ) | 404 | 83 | | | | | 97 | 150 | 473 | | 473 | ||||||||||||||||||||||||||||||||||||
| | | | | | | | 73 | 73 | | 73 | |||||||||||||||||||||||||||||||||||||
| | | | | | | | | | 76 | 76 | |||||||||||||||||||||||||||||||||||||
(601 | ) | (20,370 | ) | (20,971 | ) | 3,525 | | (695 | ) | (695 | ) | 1,705 | 102,082 | 129,302 | 1,105 | 130,407 | ||||||||||||||||||||||||||||||||
Own shares |
Treasury shares |
Total own shares and treasury shares |
Foreign currency translation reserve |
Available- for-sale investments |
Cash flow hedges |
Total fair value reserves |
Share- based payment reserve |
Profit and loss account |
BP shareholders equity |
Non- controlling interests |
Total equity |
|||||||||||||||||||||||||||||||||||||
(388 | ) | (20,935 | ) | (21,323 | ) | 4,509 | 389 | (122 | ) | 267 | 1,582 | 83,079 | 111,568 | 1,017 | 112,585 | |||||||||||||||||||||||||||||||||
| | | | | | | | 11,017 | 11,017 | 234 | 11,251 | |||||||||||||||||||||||||||||||||||||
| | | 619 | | (5 | ) | (5 | ) | | | 614 | 2 | 616 | |||||||||||||||||||||||||||||||||||
| | | | 296 | | 296 | | | 296 | | 296 | |||||||||||||||||||||||||||||||||||||
| | | | | 1,217 | 1,217 | | | 1,217 | | 1,217 | |||||||||||||||||||||||||||||||||||||
| | | | | | | | (39 | ) | (39 | ) | | (39 | ) | ||||||||||||||||||||||||||||||||||
| | | | | | | | 23 | 23 | | 23 | |||||||||||||||||||||||||||||||||||||
| | | | | | | | (1,134 | ) | (1,134 | ) | 2 | (1,132 | ) | ||||||||||||||||||||||||||||||||||
| | | | | | | | (6 | ) | (6 | ) | | (6 | ) | ||||||||||||||||||||||||||||||||||
| | | 619 | 296 | 1,212 | 1,508 | | 9,861 | 11,988 | 238 | 12,226 | |||||||||||||||||||||||||||||||||||||
| | | | | | | | (5,294 | ) | (5,294 | ) | (82 | ) | (5,376 | ) | |||||||||||||||||||||||||||||||||
108 | 161 | 269 | | | | | 26 | (70 | ) | 284 | | 284 | ||||||||||||||||||||||||||||||||||||
| | | | | | | | | | 33 | 33 | |||||||||||||||||||||||||||||||||||||
(280 | ) | (20,774 | ) | (21,054 | ) | 5,128 | 685 | 1,090 | 1,775 | 1,608 | 87,576 | 118,546 | 1,206 | 119,752 | ||||||||||||||||||||||||||||||||||
Own shares |
Treasury shares |
Total own shares and treasury shares |
Foreign currency translation reserve |
Available- for-sale investments |
Cash flow hedges |
Total fair value reserves |
Share- based payment reserve |
Profit and loss account |
BP shareholders equity |
Non- controlling interests |
Total equity |
|||||||||||||||||||||||||||||||||||||
(126 | ) | (21,085 | ) | (21,211 | ) | 5,036 | 463 | 6 | 469 | 1,586 | 65,754 | 95,082 | 904 | 95,986 | ||||||||||||||||||||||||||||||||||
| | | | | | | | 25,212 | 25,212 | 397 | 25,609 | |||||||||||||||||||||||||||||||||||||
| | | (527 | ) | | (1 | ) | (1 | ) | | | (528 | ) | (10 | ) | (538 | ) | |||||||||||||||||||||||||||||||
| | | | (74 | ) | | (74 | ) | | | (74 | ) | | (74 | ) | |||||||||||||||||||||||||||||||||
| | | | | (127 | ) | (127 | ) | | | (127 | ) | | (127 | ) | |||||||||||||||||||||||||||||||||
| | | | | | | | (39 | ) | (39 | ) | | (39 | ) | ||||||||||||||||||||||||||||||||||
| | | | | | | | (3,831 | ) | (3,831 | ) | (3 | ) | (3,834 | ) | |||||||||||||||||||||||||||||||||
| | | (527 | ) | (74 | ) | (128 | ) | (202 | ) | | 21,342 | 20,613 | 384 | 20,997 | |||||||||||||||||||||||||||||||||
| | | | | | | | (4,072 | ) | (4,072 | ) | (245 | ) | (4,317 | ) | |||||||||||||||||||||||||||||||||
(262 | ) | 150 | (112 | ) | | | | | (4 | ) | 102 | (8 | ) | | (8 | ) | ||||||||||||||||||||||||||||||||
| | | | | | | | (47 | ) | (47 | ) | (26 | ) | (73 | ) | |||||||||||||||||||||||||||||||||
(388 | ) | (20,935 | ) | (21,323 | ) | 4,509 | 389 | (122 | ) | 267 | 1,582 | 83,079 | 111,568 | 1,017 | 112,585 |
BP Annual Report and Form 20-F 2013 | 187 |
32. Capital and reserves continued
Share capital
The balance on the share capital account represents the aggregate nominal value of all ordinary and preference shares in issue, including treasury shares.
Share premium account
The balance on the share premium account represents the amounts received in excess of the nominal value of the ordinary and preference shares.
Capital redemption reserve
The balance on the capital redemption reserve represents the aggregate nominal value of all the ordinary shares repurchased and cancelled.
Merger reserve
The balance on the merger reserve represents the fair value of the consideration given in excess of the nominal value of the ordinary shares issued in an acquisition made by the issue of shares.
Own shares
Own shares represent BP shares held in Employee Share Ownership Plans (ESOPs) to meet the future requirements of the employee share-based payment plans. The ESOPs have waived their rights to dividends on shares held for future awards and are funded by the group. Until such time as the companys own shares held by the ESOPs vest unconditionally to employees, the amount paid for those shares is shown as a reduction in shareholders equity. Assets and liabilities of the ESOPs are recognized as assets and liabilities of the group.
At 31 December 2013, the ESOPs held 32,748,354 shares (2012 22,428,179 shares and 2011 27,784,503 shares) for potential future awards, which had a market value of $253 million (2012 $154 million and 2011 $197 million). At 31 December 2013, a further 12,856,914 ordinary share equivalents (2012 18,673,926 ordinary share equivalents) were held by the group in the form of ADSs to meet the requirements of employee share-based payment plans in the US.
Treasury shares
Treasury shares represent BP shares repurchased and available for re-issue.
Foreign currency translation reserve
The foreign currency translation reserve records exchange differences arising from the translation of the financial statements of foreign operations. Upon disposal of foreign operations, the related accumulated exchange differences are recycled to the income statement.
Available-for-sale investments
This reserve records the changes in fair value of available-for-sale investments except for impairment losses, foreign exchange gains or losses, or changes arising from revised estimates of future cash flows. On disposal or impairment of the investments, the cumulative changes in fair value are recycled to the income statement.
Cash flow hedges
This reserve records the portion of the gain or loss on a hedging instrument in a cash flow hedge that is determined to be an effective hedge. For further information see Note 1.
Share-based payment reserve
This reserve represents cumulative amounts charged to profit in respect of employee share-based payment plans where the scheme has not yet been settled by means of an award of shares to an individual.
Profit and loss account
The balance held on this reserve is the accumulated retained profits of the group.
188 | BP Annual Report and Form 20-F 2013 |
32. Capital and reserves continued
The pre-tax amounts of each component of other comprehensive income, and the related amounts of tax, are shown in the table below.
$ million | ||||||||||||||
2013 | ||||||||||||||
Pre-tax | Tax | Net of tax | ||||||||||||
Items that may be reclassified subsequently to profit or loss |
||||||||||||||
Currency translation differences (including recycling) |
(1,586 | ) | (32 | ) | (1,618 | ) | ||||||||
Available-for-sale investments (including recycling) |
(695 | ) | 10 | (685 | ) | |||||||||
Cash flow hedges (including recycling) |
(1,979 | ) | 194 | (1,785 | ) | |||||||||
Share of items relating to equity-accounted entities, net of tax |
(24 | ) | | (24 | ) | |||||||||
Other |
| (25 | ) | (25 | ) | |||||||||
Items that will not be reclassified to profit or loss |
||||||||||||||
Remeasurements of the net pension and other post-retirement benefit liability or asset |
4,764 | (1,521 | ) | 3,243 | ||||||||||
Share of items relating to equity-accounted entities, net of tax |
2 | | 2 | |||||||||||
Other comprehensive income |
482 | (1,374 | ) | (892 | ) | |||||||||
$ million | ||||||||||||||
2012 | ||||||||||||||
Pre-tax | Tax | Net of tax | ||||||||||||
Items that may be reclassified subsequently to profit or loss |
||||||||||||||
Currency translation differences (including recycling) |
470 | 146 | 616 | |||||||||||
Available-for-sale investments (including recycling) |
305 | (9 | ) | 296 | ||||||||||
Cash flow hedges (including recycling) |
1,547 | (330 | ) | 1,217 | ||||||||||
Share of items relating to equity-accounted entities, net of tax |
(39 | ) | | (39 | ) | |||||||||
Other |
| 23 | 23 | |||||||||||
Items that will not be reclassified to profit or loss |
||||||||||||||
Remeasurements of the net pension and other post-retirement benefit liability or asset |
(1,572 | ) | 440 | (1,132 | ) | |||||||||
Share of items relating to equity-accounted entities, net of tax |
(6 | ) | | (6 | ) | |||||||||
Other comprehensive income |
705 | 270 | 975 | |||||||||||
$ million | ||||||||||||||
2011 | ||||||||||||||
Pre-tax | Tax | Net of tax | ||||||||||||
Items that may be reclassified subsequently to profit or loss |
||||||||||||||
Currency translation differences (including recycling) |
(524 | ) | (14 | ) | (538 | ) | ||||||||
Available-for-sale investments (including recycling) |
(74 | ) | | (74 | ) | |||||||||
Cash flow hedges (including recycling) |
(164 | ) | 37 | (127 | ) | |||||||||
Share of items relating to equity-accounted entities, net of tax |
(39 | ) | | (39 | ) | |||||||||
Items that will not be reclassified to profit or loss |
||||||||||||||
Remeasurements of the net pension and other post-retirement benefit liability or asset |
(5,301 | ) | 1,467 | (3,834 | ) | |||||||||
Other comprehensive income |
(6,102 | ) | 1,490 | (4,612 | ) |
33. Employee costs and numbers
$ million | ||||||||||||||
Employee costs | 2013 | 2012 | 2011 | |||||||||||
Wages and salariesa b |
10,161 | 9,910 | 9,333 | |||||||||||
Social security costs |
958 | 908 | 854 | |||||||||||
Share-based paymentsc |
719 | 674 | 584 | |||||||||||
Pension and other post-retirement benefit costs |
1,816 | 1,956 | 1,730 | |||||||||||
13,654 | 13,448 | 12,501 | ||||||||||||
Number of employees at 31 Decemberd | 2013 | 2012 | 2011 | |||||||||||
Upstream |
24,700 | 24,200 | 22,400 | |||||||||||
Downstreame |
48,000 | 51,800 | 51,500 | |||||||||||
Other businesses and corporatef |
11,100 | 10,300 | 10,100 | |||||||||||
Gulf Coast Restoration Organization |
100 | 100 | 100 | |||||||||||
83,900 | 86,400 | 84,100 | ||||||||||||
By geographical area |
||||||||||||||
US |
19,600 | 23,400 | 22,900 | |||||||||||
Non-USe |
64,300 | 63,000 | 61,200 | |||||||||||
83,900 | 86,400 | 84,100 |
BP Annual Report and Form 20-F 2013 | 189 |
33. Employee costs and numbers continued
2013 | 2012 | 2011 | ||||||||||||||||||||||||||||||||||||
Average number of employeesd | US | Non-US | Total | US | Non-US | Total | US | Non-US | Total | |||||||||||||||||||||||||||||
Upstream |
9,400 | 15,100 | 24,500 | 9,300 | 14,100 | 23,400 | 8,500 | 13,400 | 21,900 | |||||||||||||||||||||||||||||
Downstream |
9,300 | 39,800 | 49,100 | 12,000 | 39,900 | 51,900 | 12,300 | 39,700 | 52,000 | |||||||||||||||||||||||||||||
Other businesses and corporate |
1,900 | 9,000 | 10,900 | 1,900 | 8,700 | 10,600 | 1,700 | 6,500 | 8,200 | |||||||||||||||||||||||||||||
Gulf Coast Restoration Organization |
100 | | 100 | 100 | | 100 | 100 | | 100 | |||||||||||||||||||||||||||||
20,700 | 63,900 | 84,600 | 23,300 | 62,700 | 86,000 | 22,600 | 59,600 | 82,200 |
a | Includes termination payments of $212 million (2012 $77 million and 2011 $126 million). |
b | Wages and salaries for 2012 and 2011 have been amended. |
c | The group provides certain employees with shares and share options as part of their remuneration packages. The majority of these share-based payment arrangements are equity-settled. |
d | Reported to the nearest 100. |
e | Includes 14,100 (2012 14,700 and 2011 14,600) service station staff. |
f | Includes 4,300 (2012 3,600 and 2011 4,000) agricultural, operational and seasonal workers in Brazil. |
34. Remuneration of directors and senior management
Remuneration of directors
$ million | ||||||||||||||
2013 | 2012 | 2011 | ||||||||||||
Total for all directors |
||||||||||||||
Emoluments |
16 | 12 | 10 | |||||||||||
Gains made on exercise of share options |
| | | |||||||||||
Amounts awarded under incentive schemes |
2 | 3 | 1 | |||||||||||
Total |
18 | 15 | 11 |
Emoluments
These amounts comprise fees and benefits paid to the non-executive chairman and the non-executive directors and, for executive directors, salary and benefits earned during the relevant financial year, plus cash bonuses awarded for the year. There was no compensation for loss of office in 2013 (2012 nil and 2011 nil).
Pension contributions
During 2013 two executive directors participated in a non-contributory pension scheme established for UK employees. Two US executive directors participated in the US BP Retirement Accumulation Plan during 2013.
Office facilities for former chairmen and deputy chairmen
It is customary for the company to make available to former chairmen and deputy chairmen, who were previously employed executives, the use of office and basic secretarial facilities following their retirement. The cost involved in doing so is not significant.
Further information
Full details of individual directors remuneration are given in the Directors remuneration report on page 81.
Remuneration of directors and senior management
$ million | ||||||||||||||
Total for all senior management | 2013 | 2012a | 2011a | |||||||||||
Total for all senior management |
||||||||||||||
Short-term employee benefits |
36 | 29 | 34 | |||||||||||
Pensions and other post-retirement benefits |
3 | 3 | 3 | |||||||||||
Share-based payments |
43 | 37 | 28 | |||||||||||
Total |
82 | 69 | 65 |
a | Prior year comparatives have been amended to include the portion of bonuses that were deferred and will be settled in shares in the future. |
Senior management, in addition to executive and non-executive directors, includes other senior managers who are members of the executive management team.
Short-term employee benefits
In addition to fees and benefits paid to the non-executive chairman and non-executive directors, these amounts comprise, for executive directors and senior managers, salary and benefits earned during the year, plus cash bonuses awarded for the year. Deferred annual bonus awards, to be settled in shares, are included in share-based payments. Short-term employee benefits includes compensation for loss of office of $3 million (2012 nil and 2011 $9 million).
Pensions and other post-retirement benefits
The amounts represent the estimated cost to the group of providing defined benefit pensions and other post-retirement benefits to senior management in respect of the current year of service measured in accordance with IAS 19 Employee Benefits.
Share-based payments
This is the cost to the group of senior managements participation in share-based payment plans, as measured by the fair value of options and shares granted accounted for in accordance with IFRS 2 Share-based Payments. The main plans in which senior management have participated are the EDIP, DAB, ACBD, SVP and RSP.
190 | BP Annual Report and Form 20-F 2013 |
Contingent liabilities related to the Gulf of Mexico oil spill
Details of contingent liabilities related to the Gulf of Mexico oil spill are set out in Note 2.
Contingent liabilities not related to the Gulf of Mexico oil spill
There were contingent liabilities at 31 December 2013 in respect of guarantees and indemnities entered into as part of the ordinary course of the groups business. No material losses are likely to arise from such contingent liabilities. Further information is included in Note 19.
Lawsuits arising out of the Exxon Valdez oil spill in Prince William Sound, Alaska, in March 1989 were filed against Exxon (now ExxonMobil), Alyeska Pipeline Service Company (Alyeska), which operates the oil terminal at Valdez, and the other oil companies that own Alyeska. Alyeska initially responded to the spill until the response was taken over by Exxon. BP owns a 46.9% interest (reduced during 2001 from 50% by a sale of 3.1% to Phillips) in Alyeska through a subsidiary of BP America Inc. and briefly indirectly owned a further 20% interest in Alyeska following BPs combination with Atlantic Richfield Company (Atlantic Richfield). Alyeska and its owners have settled all the claims against them under these lawsuits. Exxon has indicated that it may file a claim for contribution against Alyeska for a portion of the costs and damages that Exxon has incurred. BP will defend any such claims vigorously. It is not possible to estimate any financial effect.
In the normal course of the groups business, legal proceedings are pending or may be brought against BP group entities arising out of current and past operations, including matters related to commercial disputes, product liability, antitrust, commodities trading, premises-liability claims, consumer protection, general environmental claims and allegations of exposures of third parties to toxic substances, such as lead pigment in paint, asbestos and other chemicals. BP believes that the impact of these legal proceedings on the groups results of operations, liquidity or financial position will not be material.
With respect to lead pigment in paint in particular, Atlantic Richfield, a subsidiary of BP, has been named as a co-defendant in numerous lawsuits brought in the US alleging injury to persons and property. Although it is not possible to predict the outcome of the legal proceedings, Atlantic Richfield believes it has valid defences that render the incurrence of a liability remote; however, the amounts claimed and the costs of implementing the remedies sought in the various cases could be substantial. The majority of the lawsuits have been abandoned or dismissed against Atlantic Richfield. No lawsuit against Atlantic Richfield has been settled nor has Atlantic Richfield been subject to a final adverse judgment in any proceeding. Atlantic Richfield intends to defend such actions vigorously.
The group files tax returns in many jurisdictions throughout the world. Various tax authorities are currently examining the groups tax returns. Tax returns contain matters that could be subject to differing interpretations of applicable tax laws and regulations and the resolution of tax positions through negotiations with relevant tax authorities, or through litigation, can take several years to complete. While it is difficult to predict the ultimate outcome in some cases, the group does not anticipate that there will be any material impact upon the groups results of operations, financial position or liquidity.
The group is subject to numerous national and local environmental laws and regulations concerning its products, operations and other activities. These laws and regulations may require the group to take future action to remediate the effects on the environment of prior disposal or release of chemicals or petroleum substances by the group or other parties. Such contingencies may exist for various sites including refineries, chemical plants, oil fields, service stations, terminals and waste disposal sites. In addition, the group may have obligations relating to prior asset sales or closed facilities. The ultimate requirement for remediation and its cost are inherently difficult to estimate. However, the estimated cost of known environmental obligations has been provided in these accounts in accordance with the groups accounting policies. While the amounts of future costs that are not provided for could be significant and could be material to the groups results of operations in the period in which they are recognized, it is not possible to estimate the amounts involved. BP does not expect these costs to have a material effect on the groups financial position or liquidity.
The group also has obligations to decommission oil and natural gas production facilities and related pipelines. Provision is made for the estimated costs of these activities, however there is uncertainty regarding both the amount and timing of these costs, given the long-term nature of these obligations. BP believes that the impact of any reasonably foreseeable changes to these provisions on the groups results of operations, financial position or liquidity will not be material. If oil and natural gas production facilities and pipelines are sold to third parties and the subsequent owner is unable to meet their decommissioning obligations, judgement must be used to determine whether BP is then responsible for decommissioning, and if so the extent of that responsibility.
The group generally restricts its purchase of insurance to situations where this is required for legal or contractual reasons. This is because external insurance is not considered an economic means of financing losses for the group. Losses will therefore be borne as they arise rather than being spread over time through insurance premiums with attendant transaction costs. The position is reviewed periodically.
Authorized future capital expenditure for property, plant and equipment by group companies for which contracts had been signed at 31 December 2013 amounted to $13,705 million (2012 $14,894 million). BPs share of capital commitments of joint ventures amounted to $317 million (2012 $293 million).
BP Annual Report and Form 20-F 2013 | 191 |
$ million | ||||||||||||||
Fees EY | 2013 | 2012 | 2011 | |||||||||||
The audit of the company annual accountsa |
26 | 26 | 26 | |||||||||||
The audit of accounts of any subsidiaries of the company |
13 | 13 | 15 | |||||||||||
Total audit |
39 | 39 | 41 | |||||||||||
Audit-related assurance servicesb |
8 | 7 | 6 | |||||||||||
Total audit and audit-related assurance services |
47 | 46 | 47 | |||||||||||
Taxation compliance services |
1 | 2 | 1 | |||||||||||
Taxation advisory services |
1 | 2 | 1 | |||||||||||
Services relating to corporate finance transactions |
2 | 2 | 4 | |||||||||||
Other assurance services |
1 | 1 | 1 | |||||||||||
Total non-audit or non-audit-related assurance services |
5 | 7 | 7 | |||||||||||
Services relating to BP pension plansc |
1 | 1 | 1 | |||||||||||
53 | 54 | 55 |
a | Fees in respect of the audit of the accounts of BP p.l.c. including the groups consolidated financial statements. |
b | Includes interim reviews and reporting on internal financial controls and non-statutory audit services. |
c | The pension plan services include tax compliance services of $240,000 (2012 $50,000 and 2011 $108,000). |
2013 includes $3 million of additional fees for 2012, and 2012 includes $2 million of additional fees for 2011. Auditors remuneration is included in the income statement within distribution and administration expenses.
The tax services relate to income tax and indirect tax compliance, employee tax services and tax advisory services.
The audit committee has established pre-approval policies and procedures for the engagement of Ernst & Young to render audit and certain assurance and tax services. The audit fees payable to Ernst & Young are reviewed by the audit committee in the context of other global companies for cost-effectiveness. Ernst & Young performed further assurance and tax services that were not prohibited by regulatory or other professional requirements and were pre-approved by the committee. Ernst & Young is engaged for these services when its expertise and experience of BP are important. Most of this work is of an audit nature. Tax services were awarded either through a full competitive tender process or following an assessment of the expertise of Ernst & Young compared with that of other potential service providers. These services are for a fixed term.
Under SEC regulations, the remuneration of the auditor of $53 million (2012 $54 million and 2011 $55 million) is required to be presented as follows: audit $39 million (2012 $39 million and 2011 $41 million); other audit-related services $8 million (2012 $7 million and 2011 $6 million); tax $2 million (2012 $4 million and 2011 $2 million); and all other fees $4 million (2012 $4 million and 2011 $6 million).
192 | BP Annual Report and Form 20-F 2013 |
38. Subsidiaries, joint arrangements and associates
The more important subsidiaries, joint arrangements and associates of the group at 31 December 2013 and the group percentage of ordinary share capital or joint arrangement interest (to nearest whole number) are set out below. Those held directly by the parent company are marked with an asterisk (*), the percentage owned being that of the group unless otherwise indicated. The group has interests in a number of joint arrangements, but none of these is individually material to the group. A complete list of investments in subsidiaries, joint arrangements and associates will be attached to the parent companys annual return made to the Registrar of Companies.
Subsidiaries | % | Country of incorporation |
Principal activities | |||||||||||
International |
||||||||||||||
*BP Corporate Holdings |
100 | England & Wales | Investment holding | |||||||||||
BP Exploration Operating Company |
100 | England & Wales | Exploration and production | |||||||||||
*BP Global Investments |
100 | England & Wales | Investment holding | |||||||||||
*BP International |
100 | England & Wales | Integrated oil operations | |||||||||||
BP Oil International |
100 | England & Wales | Integrated oil operations | |||||||||||
*Burmah Castrol |
100 | Scotland | Lubricants | |||||||||||
Algeria |
||||||||||||||
BP Amoco Exploration (In Amenas) |
100 | Scotland | Exploration and production | |||||||||||
Angola |
||||||||||||||
BP Exploration (Angola) |
100 | England & Wales | Exploration and production | |||||||||||
Australia |
||||||||||||||
BP Australia Capital Markets |
100 | Australia | Finance | |||||||||||
BP Finance Australia |
100 | Australia | Finance | |||||||||||
Azerbaijan |
||||||||||||||
BP Exploration (Caspian Sea) |
100 | England & Wales | Exploration and production | |||||||||||
Brazil |
||||||||||||||
BP Energy do Brazil |
100 | Brazil | Exploration and production | |||||||||||
India |
||||||||||||||
BP Exploration (Alpha) |
100 | England & Wales | Exploration and production | |||||||||||
New Zealand |
||||||||||||||
BP Oil New Zealand |
100 | New Zealand | Marketing | |||||||||||
Norway |
||||||||||||||
BP Norge |
100 | Norway | Exploration and production | |||||||||||
UK |
||||||||||||||
BP Capital Markets |
100 | England & Wales | Finance | |||||||||||
US |
||||||||||||||
*BP Holdings North America |
100 | England & Wales | Investment holding | |||||||||||
Atlantic Richfield Company |
100 | US |
Exploration and production, refining and marketing pipelines and petrochemicals
| |||||||||||
BP America |
100 | US | ||||||||||||
BP America Production Company |
100 | US | ||||||||||||
BP Company North America |
100 | US | ||||||||||||
BP Corporation North America |
100 | US | ||||||||||||
BP Exploration & Production |
100 | US | ||||||||||||
BP Exploration (Alaska) |
100 | US | ||||||||||||
BP Products North America |
100 | US | ||||||||||||
Standard Oil Company |
100 | US | ||||||||||||
BP Capital Markets America |
100 | US | Finance |
Associates | % | Country of incorporation |
Principal activities | |||||||||||
Russia |
||||||||||||||
Rosneft |
20 | Russia | Integrated oil operations |
BP Annual Report and Form 20-F 2013 | 193 |
39. Condensed consolidating information on certain US subsidiaries
BP p.l.c. fully and unconditionally guarantees the payment obligations of its 100%-owned subsidiary BP Exploration (Alaska) Inc. under the BP Prudhoe Bay Royalty Trust. The following financial information for BP p.l.c., BP Exploration (Alaska) Inc. and all other subsidiaries on a condensed consolidating basis is intended to provide investors with meaningful and comparable financial information about BP p.l.c. and its subsidiary issuers of registered securities and is provided pursuant to Rule 3-10 of Regulation S-X in lieu of the separate financial statements of each subsidiary issuer of public debt securities. Investments include the investments in subsidiaries recorded under the equity method for the purposes of the condensed consolidating financial information. Equity accounted income of subsidiaries is the groups share of profit related to such investments. The eliminations and reclassifications column includes the necessary amounts to eliminate the intercompany balances and transactions between BP p.l.c., BP Exploration (Alaska) Inc. and other subsidiaries. The financial information presented in the following tables for BP Exploration (Alaska) Inc. for all years includes equity income arising from subsidiaries of BP Exploration (Alaska) Inc. some of which operate outside of Alaska and excludes the BP groups midstream operations in Alaska that are reported through different legal entities and that are included within the other subsidiaries column in these tables. BP p.l.c. also fully and unconditionally guarantees securities issued by BP Capital Markets p.l.c. and BP Capital Markets America Inc. These companies are 100%- owned finance subsidiaries of BP p.l.c.
Income statement
$ million | ||||||||||||||||||||||
For the year ended 31 December | 2013 | |||||||||||||||||||||
Issuer | Guarantor | |||||||||||||||||||||
BP Exploration (Alaska) Inc. |
BP p.l.c. | Other subsidiaries |
Eliminations and reclassifications |
BP group | ||||||||||||||||||
Sales and other operating revenues |
5,397 | | 379,136 | (5,397 | ) | 379,136 | ||||||||||||||||
Earnings from joint ventures after interest and tax |
| | 447 | | 447 | |||||||||||||||||
Earnings from associates after interest and tax |
| | 2,742 | | 2,742 | |||||||||||||||||
Equity-accounted income of subsidiaries after interest and tax |
| 24,693 | | (24,693 | ) | | ||||||||||||||||
Interest and other income |
7 | 118 | 841 | (189 | ) | 777 | ||||||||||||||||
Gains on sale of businesses and fixed assets |
| | 13,115 | | 13,115 | |||||||||||||||||
Total revenues and other income |
5,404 | 24,811 | 396,281 | (30,279 | ) | 396,217 | ||||||||||||||||
Purchases |
861 | | 302,887 | (5,397 | ) | 298,351 | ||||||||||||||||
Production and manufacturing expenses |
1,473 | | 26,054 | | 27,527 | |||||||||||||||||
Production and similar taxes |
1,010 | | 6,037 | | 7,047 | |||||||||||||||||
Depreciation, depletion and amortization |
616 | | 12,894 | | 13,510 | |||||||||||||||||
Impairment and losses on sale of businesses and fixed assets |
(68 | ) | | 2,029 | | 1,961 | ||||||||||||||||
Exploration expense |
| | 3,441 | | 3,441 | |||||||||||||||||
Distribution and administration expenses |
108 | 1,234 | 11,728 | | 13,070 | |||||||||||||||||
Fair value gain on embedded derivatives |
| | (459 | ) | | (459 | ) | |||||||||||||||
Profit before interest and taxation |
1,404 | 23,577 | 31,670 | (24,882 | ) | 31,769 | ||||||||||||||||
Finance costs |
42 | 43 | 1,172 | (189 | ) | 1,068 | ||||||||||||||||
Net finance (income) expense relating to pensions and other post-retirement benefits |
| 81 | 399 | | 480 | |||||||||||||||||
Profit before taxation |
1,362 | 23,453 | 30,099 | (24,693 | ) | 30,221 | ||||||||||||||||
Taxation |
522 | 2 | 5,939 | | 6,463 | |||||||||||||||||
Profit for the year |
840 | 23,451 | 24,160 | (24,693 | ) | 23,758 | ||||||||||||||||
Attributable to |
||||||||||||||||||||||
BP shareholders |
840 | 23,451 | 23,853 | (24,693 | ) | 23,451 | ||||||||||||||||
Non-controlling interests |
| | 307 | | 307 | |||||||||||||||||
840 | 23,451 | 24,160 | (24,693 | ) | 23,758 |
Statement of comprehensive income
$ million | ||||||||||||||||||||||
For the year ended 31 December | 2013 | |||||||||||||||||||||
Issuer | Guarantor | |||||||||||||||||||||
BP Exploration (Alaska) Inc. |
BP p.l.c. | Other subsidiaries |
Eliminations and reclassifications |
BP group | ||||||||||||||||||
Profit for the year |
840 | 23,451 | 24,160 | (24,693 | ) | 23,758 | ||||||||||||||||
Other comprehensive income |
| 2,819 | (3,711 | ) | | (892 | ) | |||||||||||||||
Total comprehensive income |
840 | 26,270 | 20,449 | (24,693 | ) | 22,866 | ||||||||||||||||
Attributable to |
||||||||||||||||||||||
BP shareholders |
840 | 26,270 | 20,157 | (24,693 | ) | 22,574 | ||||||||||||||||
Non-controlling interests |
| | 292 | | 292 | |||||||||||||||||
840 | 26,270 | 20,449 | (24,693 | ) | 22,866 |
194 | BP Annual Report and Form 20-F 2013 |
39. Condensed consolidating information on certain US subsidiaries continued
Income statement continued
$ million | ||||||||||||||||||||||
For the year ended 31 December | 2012 | |||||||||||||||||||||
Issuer | Guarantor | |||||||||||||||||||||
BP Exploration (Alaska) Inc. |
BP p.l.c. | Other subsidiaries |
Eliminations and reclassifications |
BP group | ||||||||||||||||||
Sales and other operating revenues |
5,501 | | 375,765 | (5,501 | ) | 375,765 | ||||||||||||||||
Earnings from joint ventures after interest and tax |
| | 260 | | 260 | |||||||||||||||||
Earnings from associates after interest and tax |
| | 3,675 | | 3,675 | |||||||||||||||||
Equity-accounted income of subsidiaries after interest and tax |
(59 | ) | 12,649 | | (12,590 | ) | | |||||||||||||||
Interest and other income |
12 | 187 | 1,764 | (286 | ) | 1,677 | ||||||||||||||||
Gains on sale of businesses and fixed assets |
3,580 | | 6,697 | (3,580 | ) | 6,697 | ||||||||||||||||
Total revenues and other income |
9,034 | 12,836 | 388,161 | (21,957 | ) | 388,074 | ||||||||||||||||
Purchases |
777 | | 297,498 | (5,501 | ) | 292,774 | ||||||||||||||||
Production and manufacturing expenses |
1,475 | | 32,451 | | 33,926 | |||||||||||||||||
Production and similar taxes |
1,374 | | 6,784 | | 8,158 | |||||||||||||||||
Depreciation, depletion and amortization |
457 | | 12,230 | | 12,687 | |||||||||||||||||
Impairment and losses on sale of businesses and fixed assets |
957 | | 5,318 | | 6,275 | |||||||||||||||||
Exploration expense |
| | 1,475 | | 1,475 | |||||||||||||||||
Distribution and administration expenses |
35 | 1,766 | 11,641 | (85 | ) | 13,357 | ||||||||||||||||
Fair value gain on embedded derivatives |
| | (347 | ) | | (347 | ) | |||||||||||||||
Profit before interest and taxation |
3,959 | 11,070 | 21,111 | (16,371 | ) | 19,769 | ||||||||||||||||
Finance costs |
48 | 43 | 1,182 | (201 | ) | 1,072 | ||||||||||||||||
Net finance expense relating to pensions and other post-retirement benefits |
| 103 | 463 | | 566 | |||||||||||||||||
Profit before taxation |
3,911 | 10,924 | 19,466 | (16,170 | ) | 18,131 | ||||||||||||||||
Taxation |
203 | (93 | ) | 6,770 | | 6,880 | ||||||||||||||||
Profit for the year |
3,708 | 11,017 | 12,696 | (16,170 | ) | 11,251 | ||||||||||||||||
Attributable to |
||||||||||||||||||||||
BP shareholders |
3,708 | 11,017 | 12,462 | (16,170 | ) | 11,017 | ||||||||||||||||
Non-controlling interests |
| | 234 | | 234 | |||||||||||||||||
3,708 | 11,017 | 12,696 | (16,170 | ) | 11,251 |
Statement of comprehensive income continued
$ million | ||||||||||||||||||||||
For the year ended 31 December | 2012 | |||||||||||||||||||||
Issuer | Guarantor | |||||||||||||||||||||
BP Exploration (Alaska) Inc. |
BP p.l.c. | Other subsidiaries |
Eliminations and reclassifications |
BP group | ||||||||||||||||||
Profit for the year |
3,708 | 11,017 | 12,696 | (16,170 | ) | 11,251 | ||||||||||||||||
Other comprehensive income |
| (232 | ) | 1,207 | | 975 | ||||||||||||||||
Total comprehensive income |
3,708 | 10,785 | 13,903 | (16,170 | ) | 12,226 | ||||||||||||||||
Attributable to |
||||||||||||||||||||||
BP shareholders |
3,708 | 10,785 | 13,665 | (16,170 | ) | 11,988 | ||||||||||||||||
Non-controlling interests |
| | 238 | | 238 | |||||||||||||||||
3,708 | 10,785 | 13,903 | (16,170 | ) | 12,226 |
BP Annual Report and Form 20-F 2013 | 195 |
39. Condensed consolidating information on certain US subsidiaries continued
Income statement continued
$ million | ||||||||||||||||||||||
For the year ended 31 December | 2011 | |||||||||||||||||||||
Issuer | Guarantor | |||||||||||||||||||||
BP Exploration (Alaska) Inc. |
BP p.l.c. | Other subsidiaries |
Eliminations and reclassifications |
BP group | ||||||||||||||||||
Sales and other operating revenues |
6,159 | | 375,713 | (6,159 | ) | 375,713 | ||||||||||||||||
Earnings from joint ventures after interest and tax |
| | 767 | | 767 | |||||||||||||||||
Earnings from associates after interest and tax |
| | 4,916 | | 4,916 | |||||||||||||||||
Equity-accounted income of subsidiaries after interest and tax |
313 | 26,019 | | (26,332 | ) | | ||||||||||||||||
Interest and other income |
10 | 242 | 756 | (320 | ) | 688 | ||||||||||||||||
Gains on sale of businesses and fixed assets |
| 1 | 4,131 | | 4,132 | |||||||||||||||||
Total revenues and other income |
6,482 | 26,262 | 386,283 | (32,811 | ) | 386,216 | ||||||||||||||||
Purchases |
978 | | 290,314 | (6,159 | ) | 285,133 | ||||||||||||||||
Production and manufacturing expenses |
1,280 | | 22,883 | | 24,163 | |||||||||||||||||
Production and similar taxes |
1,684 | | 6,596 | | 8,280 | |||||||||||||||||
Depreciation, depletion and amortization |
335 | | 11,022 | | 11,357 | |||||||||||||||||
Impairment and losses on sale of businesses and fixed assets |
| | 2,058 | | 2,058 | |||||||||||||||||
Exploration expense |
4 | | 1,516 | | 1,520 | |||||||||||||||||
Distribution and administration expenses |
27 | 1,048 | 12,992 | (109 | ) | 13,958 | ||||||||||||||||
Fair value gain on embedded derivatives |
| | (68 | ) | | (68 | ) | |||||||||||||||
Profit before interest and taxation |
2,174 | 25,214 | 38,970 | (26,543 | ) | 39,815 | ||||||||||||||||
Finance costs |
32 | 47 | 1,319 | (211 | ) | 1,187 | ||||||||||||||||
Net finance (income) expense relating to pensions and other post-retirement benefits |
| (94 | ) | 494 | | 400 | ||||||||||||||||
Profit before taxation |
2,142 | 25,261 | 37,157 | (26,332 | ) | 38,228 | ||||||||||||||||
Taxation |
729 | 49 | 11,841 | | 12,619 | |||||||||||||||||
Profit for the year |
1,413 | 25,212 | 25,316 | (26,332 | ) | 25,609 | ||||||||||||||||
Attributable to |
||||||||||||||||||||||
BP shareholders |
1,413 | 25,212 | 24,919 | (26,332 | ) | 25,212 | ||||||||||||||||
Non-controlling interests |
| | 397 | | 397 | |||||||||||||||||
1,413 | 25,212 | 25,316 | (26,332 | ) | 25,609 |
Statement of comprehensive income continued
$ million | ||||||||||||||||||||||
For the year ended 31 December | 2011 | |||||||||||||||||||||
Issuer | Guarantor | |||||||||||||||||||||
BP Exploration (Alaska) Inc. |
BP p.l.c. | Other subsidiaries |
Eliminations and reclassifications |
BP group | ||||||||||||||||||
Profit for the year |
1,413 | 25,212 | 25,316 | (26,332 | ) | 25,609 | ||||||||||||||||
Other comprehensive income |
| (3,674 | ) | (938 | ) | | (4,612 | ) | ||||||||||||||
Total comprehensive income |
1,413 | 21,538 | 24,378 | (26,332 | ) | 20,997 | ||||||||||||||||
Attributable to |
||||||||||||||||||||||
BP shareholders |
1,413 | 21,538 | 23,994 | (26,332 | ) | 20,613 | ||||||||||||||||
Non-controlling interests |
| | 384 | | 384 | |||||||||||||||||
1,413 | 21,538 | 24,378 | (26,332 | ) | 20,997 |
196 | BP Annual Report and Form 20-F 2013 |
39. Condensed consolidating information on certain US subsidiaries continued
Balance sheet
$ million | ||||||||||||||||||||||
At 31 December | 2013 | |||||||||||||||||||||
Issuer | Guarantor | |||||||||||||||||||||
BP Exploration (Alaska) Inc. |
BP p.l.c. | Other subsidiaries |
Eliminations and reclassifications |
BP group | ||||||||||||||||||
Non-current assets |
||||||||||||||||||||||
Property, plant and equipment |
8,546 | | 125,144 | | 133,690 | |||||||||||||||||
Goodwill |
| | 12,181 | | 12,181 | |||||||||||||||||
Intangible assets |
417 | | 21,622 | | 22,039 | |||||||||||||||||
Investments in joint ventures |
| | 9,199 | | 9,199 | |||||||||||||||||
Investments in associates |
| 2 | 16,634 | | 16,636 | |||||||||||||||||
Other investments |
| | 1,565 | | 1,565 | |||||||||||||||||
Subsidiaries equity-accounted basis |
| 142,143 | | (142,143 | ) | | ||||||||||||||||
Fixed assets |
8,963 | 142,145 | 186,345 | (142,143 | ) | 195,310 | ||||||||||||||||
Loans |
| | 5,356 | (4,593 | ) | 763 | ||||||||||||||||
Trade and other receivables |
| | 5,985 | | 5,985 | |||||||||||||||||
Derivative financial instruments |
| | 3,509 | | 3,509 | |||||||||||||||||
Prepayments |
22 | | 900 | | 922 | |||||||||||||||||
Deferred tax assets |
| | 985 | | 985 | |||||||||||||||||
Defined benefit pension plan surpluses |
| 1,020 | 356 | | 1,376 | |||||||||||||||||
8,985 | 143,165 | 203,436 | (146,736 | ) | 208,850 | |||||||||||||||||
Current assets |
||||||||||||||||||||||
Loans |
| | 216 | | 216 | |||||||||||||||||
Inventories |
152 | | 29,079 | | 29,231 | |||||||||||||||||
Trade and other receivables |
9,593 | 21,550 | 42,363 | (33,675 | ) | 39,831 | ||||||||||||||||
Derivative financial instruments |
| | 2,675 | | 2,675 | |||||||||||||||||
Prepayments |
18 | | 1,370 | | 1,388 | |||||||||||||||||
Current tax receivable |
| | 512 | | 512 | |||||||||||||||||
Other investments |
| | 467 | | 467 | |||||||||||||||||
Cash and cash equivalents |
| 6 | 22,514 | | 22,520 | |||||||||||||||||
9,763 | 21,556 | 99,196 | (33,675 | ) | 96,840 | |||||||||||||||||
Assets classified as held for sale |
| | | | | |||||||||||||||||
9,763 | 21,556 | 99,196 | (33,675 | ) | 96,840 | |||||||||||||||||
Total assets |
18,748 | 164,721 | 302,632 | (180,411 | ) | 305,690 | ||||||||||||||||
Current liabilities |
||||||||||||||||||||||
Trade and other payables |
889 | 2,727 | 77,218 | (33,675 | ) | 47,159 | ||||||||||||||||
Derivative financial instruments |
| | 2,322 | | 2,322 | |||||||||||||||||
Accruals |
171 | 1,540 | 7,249 | | 8,960 | |||||||||||||||||
Finance debt |
| | 7,381 | | 7,381 | |||||||||||||||||
Current tax payable |
166 | | 1,779 | | 1,945 | |||||||||||||||||
Provisions |
1 | | 5,044 | | 5,045 | |||||||||||||||||
1,227 | 4,267 | 100,993 | (33,675 | ) | 72,812 | |||||||||||||||||
Liabilities directly associated with assets classified as held for sale |
| | | | | |||||||||||||||||
1,227 | 4,267 | 100,993 | (33,675 | ) | 72,812 | |||||||||||||||||
Non-current liabilities |
||||||||||||||||||||||
Other payables |
9 | 4,584 | 4,756 | (4,593 | ) | 4,756 | ||||||||||||||||
Derivative financial instruments |
| | 2,225 | | 2,225 | |||||||||||||||||
Accruals |
| 58 | 489 | | 547 | |||||||||||||||||
Finance debt |
| | 40,811 | | 40,811 | |||||||||||||||||
Deferred tax liabilities |
1,659 | | 15,780 | | 17,439 | |||||||||||||||||
Provisions |
1,942 | | 24,973 | | 26,915 | |||||||||||||||||
Defined benefit pension plan and other post-retirement benefit plan deficits |
| | 9,778 | | 9,778 | |||||||||||||||||
3,610 | 4,642 | 98,812 | (4,593 | ) | 102,471 | |||||||||||||||||
Total liabilities |
4,837 | 8,909 | 199,805 | (38,268 | ) | 175,283 | ||||||||||||||||
Net assets |
13,911 | 155,812 | 102,827 | (142,143 | ) | 130,407 | ||||||||||||||||
Equity |
||||||||||||||||||||||
BP shareholders equity |
13,911 | 155,812 | 101,722 | (142,143 | ) | 129,302 | ||||||||||||||||
Non-controlling interests |
| | 1,105 | | 1,105 | |||||||||||||||||
13,911 | 155,812 | 102,827 | (142,143 | ) | 130,407 |
BP Annual Report and Form 20-F 2013 | 197 |
39. Condensed consolidating information on certain US subsidiaries continued
Balance sheet continued
$ million | ||||||||||||||||||||||
At 31 December | 2012 | |||||||||||||||||||||
Issuer | Guarantor | |||||||||||||||||||||
BP Exploration (Alaska) Inc. |
BP p.l.c. | Other subsidiaries |
Eliminations and reclassifications |
BP group | ||||||||||||||||||
Non-current assets |
||||||||||||||||||||||
Property, plant and equipment |
8,343 | | 116,988 | | 125,331 | |||||||||||||||||
Goodwill |
| | 12,190 | | 12,190 | |||||||||||||||||
Intangible assets |
379 | | 24,253 | | 24,632 | |||||||||||||||||
Investments in joint ventures |
| | 8,614 | | 8,614 | |||||||||||||||||
Investments in associates |
| 2 | 2,996 | | 2,998 | |||||||||||||||||
Other investments |
| | 2,704 | | 2,704 | |||||||||||||||||
Subsidiaries equity-accounted basis |
| 136,553 | | (136,553 | ) | | ||||||||||||||||
Fixed assets |
8,722 | 136,555 | 167,745 | (136,553 | ) | 176,469 | ||||||||||||||||
Loans |
| | 4,924 | (4,282 | ) | 642 | ||||||||||||||||
Trade and other receivables |
| | 5,961 | | 5,961 | |||||||||||||||||
Derivative financial instruments |
| | 4,294 | | 4,294 | |||||||||||||||||
Prepayments |
34 | | 796 | | 830 | |||||||||||||||||
Deferred tax assets |
| | 874 | | 874 | |||||||||||||||||
Defined benefit pension plan surpluses |
| | 12 | | 12 | |||||||||||||||||
8,756 | 136,555 | 184,606 | (140,835 | ) | 189,082 | |||||||||||||||||
Current assets |
||||||||||||||||||||||
Loans |
| | 247 | | 247 | |||||||||||||||||
Inventories |
174 | | 28,029 | | 28,203 | |||||||||||||||||
Trade and other receivables |
11,835 | 17,496 | 43,008 | (34,728 | ) | 37,611 | ||||||||||||||||
Derivative financial instruments |
| | 4,507 | | 4,507 | |||||||||||||||||
Prepayments |
15 | | 1,076 | | 1,091 | |||||||||||||||||
Current tax receivable |
| | 456 | | 456 | |||||||||||||||||
Other investments |
| | 319 | | 319 | |||||||||||||||||
Cash and cash equivalents |
| 9 | 19,626 | | 19,635 | |||||||||||||||||
12,024 | 17,505 | 97,268 | (34,728 | ) | 92,069 | |||||||||||||||||
Assets classified as held for sale |
| | 19,315 | | 19,315 | |||||||||||||||||
12,024 | 17,505 | 116,583 | (34,728 | ) | 111,384 | |||||||||||||||||
Total assets |
20,780 | 154,060 | 301,189 | (175,563 | ) | 300,466 | ||||||||||||||||
Current liabilities |
||||||||||||||||||||||
Trade and other payables |
3,914 | 2,577 | 74,910 | (34,728 | ) | 46,673 | ||||||||||||||||
Derivative financial instruments |
| | 2,658 | | 2,658 | |||||||||||||||||
Accruals |
140 | 27 | 6,708 | | 6,875 | |||||||||||||||||
Finance debt |
| | 10,033 | | 10,033 | |||||||||||||||||
Current tax payable |
145 | | 2,358 | | 2,503 | |||||||||||||||||
Provisions |
1 | | 7,586 | | 7,587 | |||||||||||||||||
4,200 | 2,604 | 104,253 | (34,728 | ) | 76,329 | |||||||||||||||||
Liabilities directly associated with assets classified as held for sale |
| | 846 | | 846 | |||||||||||||||||
4,200 | 2,604 | 105,099 | (34,728 | ) | 77,175 | |||||||||||||||||
Non-current liabilities |
||||||||||||||||||||||
Other payables |
8 | 4,449 | 2,117 | (4,282 | ) | 2,292 | ||||||||||||||||
Derivative financial instruments |
| | 2,723 | | 2,723 | |||||||||||||||||
Accruals |
| 38 | 453 | | 491 | |||||||||||||||||
Finance debt |
| | 38,767 | | 38,767 | |||||||||||||||||
Deferred tax liabilities |
1,654 | | 13,589 | | 15,243 | |||||||||||||||||
Provisions |
1,887 | | 28,509 | | 30,396 | |||||||||||||||||
Defined benefit pension plan and other post-retirement benefit plan deficits |
| 1,913 | 11,714 | | 13,627 | |||||||||||||||||
3,549 | 6,400 | 97,872 | (4,282 | ) | 103,539 | |||||||||||||||||
Total liabilities |
7,749 | 9,004 | 202,971 | (39,010 | ) | 180,714 | ||||||||||||||||
Net assets |
13,031 | 145,056 | 98,218 | (136,553 | ) | 119,752 | ||||||||||||||||
Equity |
||||||||||||||||||||||
BP shareholders equity |
13,031 | 145,056 | 97,012 | (136,553 | ) | 118,546 | ||||||||||||||||
Non-controlling interests |
| | 1,206 | | 1,206 | |||||||||||||||||
13,031 | 145,056 | 98,218 | (136,553 | ) | 119,752 |
198 | BP Annual Report and Form 20-F 2013 |
39. Condensed consolidating information on certain US subsidiaries continued
Cash flow statement
$ million | ||||||||||||||||||||||
For the year ended 31 December | 2013 | |||||||||||||||||||||
Issuer | Guarantor | |||||||||||||||||||||
BP Exploration (Alaska) Inc. |
BP p.l.c. | Other subsidiaries |
Eliminations and reclassifications |
BP group | ||||||||||||||||||
Net cash provided by operating activities |
746 | 11,488 | 25,094 | (16,228 | ) | 21,100 | ||||||||||||||||
Net cash used in investing activities |
(746 | ) | (690 | ) | (6,419 | ) | | (7,855 | ) | |||||||||||||
Net cash used in financing activities |
| (10,801 | ) | (15,827 | ) | 16,228 | (10,400 | ) | ||||||||||||||
Currency translation differences relating to cash and cash equivalents |
| | 40 | | 40 | |||||||||||||||||
Increase (decrease) in cash and cash equivalents |
| (3 | ) | 2,888 | | 2,885 | ||||||||||||||||
Cash and cash equivalents at beginning of year |
| 9 | 19,626 | | 19,635 | |||||||||||||||||
Cash and cash equivalents at end of year |
| 6 | 22,514 | | 22,520 |
$ million | ||||||||||||||||||||||
For the year ended 31 December | 2012 | |||||||||||||||||||||
Issuer | Guarantor | |||||||||||||||||||||
BP Exploration (Alaska) Inc. |
BP p.l.c. | Other subsidiaries |
Eliminations and reclassifications |
BP group | ||||||||||||||||||
Net cash provided by operating activities |
681 | 12,381 | 20,932 | (13,515 | ) | 20,479 | ||||||||||||||||
Net cash used in investing activities |
(680 | ) | (7,060 | ) | (5,335 | ) | | (13,075 | ) | |||||||||||||
Net cash used in financing activities |
| (5,312 | ) | (10,213 | ) | 13,515 | (2,010 | ) | ||||||||||||||
Currency translation differences relating to cash and cash equivalents |
| | 64 | | 64 | |||||||||||||||||
Increase in cash and cash equivalents |
1 | 9 | 5,448 | | 5,458 | |||||||||||||||||
Cash and cash equivalents at beginning of year |
(1 | ) | | 14,178 | | 14,177 | ||||||||||||||||
Cash and cash equivalents at end of year |
| 9 | 19,626 | | 19,635 |
$ million | ||||||||||||||||||||||
For the year ended 31 December | 2011 | |||||||||||||||||||||
Issuer | Guarantor | |||||||||||||||||||||
BP Exploration (Alaska) Inc. |
BP p.l.c. | Other subsidiaries |
Eliminations and reclassifications |
BP group | ||||||||||||||||||
Net cash provided by operating activities |
661 | 8,321 | 25,178 | (11,942 | ) | 22,218 | ||||||||||||||||
Net cash used in investing activities |
(661 | ) | (3,710 | ) | (22,382 | ) | | (26,753 | ) | |||||||||||||
Net cash (used in) provided by financing activities |
| (4,615 | ) | (6,850 | ) | 11,942 | 477 | |||||||||||||||
Currency translation differences relating to cash and cash equivalents |
| | (493 | ) | | (493 | ) | |||||||||||||||
Decrease in cash and cash equivalents |
| (4 | ) | (4,547 | ) | | (4,551 | ) | ||||||||||||||
Cash and cash equivalents at beginning of year |
(1 | ) | 4 | 18,725 | | 18,728 | ||||||||||||||||
Cash and cash equivalents at end of year |
(1 | ) | | 14,178 | | 14,177 |
BP Annual Report and Form 20-F 2013 | 199 |
Supplementary information on oil and natural gas (unaudited)
2013 reserves and production information for equity-accounted entities includes BPs share of TNK-BP from 1 January to 20 March, and Rosneft for the period 21 March to 31 December. For the period 22 October 2012 to 31 December 2012, and throughout all of 2013, financial information for equity-accounted entities does not include any information for TNK-BP, as equity accounting ceased on 22 October 2012. Comparative information for 2012 and 2011 has been restated to reflect the adoption of IFRS 11 Joint Arrangements. For further information see Financial statements Note 1.
The regional analysis presented below is on a continent basis, with separate disclosure for countries that contain 15% or more of the total proved reserves (for subsidiaries plus equity-accounted entities), in accordance with SEC and FASB requirements.
Oil and gas reserves certain definitions
Unless the context indicates otherwise, the following terms have the meanings shown below:
Proved oil and gas reserves
Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.
(i) | The area of the reservoir considered as proved includes: |
(A) | The area identified by drilling and limited by fluid contacts, if any; and |
(B) | Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data. |
(ii) | In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty. |
(iii) | Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty. |
(iv) | Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: |
(A) | Successful testing by a pilot project in an area of the reservoir with properties no more favourable than in the reservoir as a whole, the operation of an installed programme in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or programme was based; and |
(B) | The project has been approved for development by all necessary parties and entities, including governmental entities. |
(v) | Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. |
Undeveloped oil and gas reserves
Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.
(i) | Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. |
(ii) | Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time. |
(iii) | Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty. |
Developed oil and gas reserves
Developed oil and gas reserves are reserves of any category that can be expected to be recovered:
(i) | Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and |
(ii) | Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well. |
For details on BPs proved reserves and production compliance and governance processes, see page 245.
200 | BP Annual Report and Form 20-F 2013 |
Oil and natural gas exploration and production activities
$ million | ||||||||||||||||||||||||||||||||||||||||||
2013 | ||||||||||||||||||||||||||||||||||||||||||
Europe |
North America |
South America |
Africa |
Asia |
Australasia |
Total | ||||||||||||||||||||||||||||||||||||
UK | Rest of Europe |
US | Rest of North America |
Russia | Rest of Asia |
|||||||||||||||||||||||||||||||||||||
Subsidiariesa |
||||||||||||||||||||||||||||||||||||||||||
Capitalized costs at 31 Decemberb |
||||||||||||||||||||||||||||||||||||||||||
Gross capitalized costs |
||||||||||||||||||||||||||||||||||||||||||
Proved properties |
29,314 | 10,040 | 75,313 | 2,501 | 8,809 | 35,720 | | 20,726 | 4,681 | 187,104 | ||||||||||||||||||||||||||||||||
Unproved properties |
316 | 195 | 6,816 | 2,408 | 3,366 | 5,079 | | 2,756 | 805 | 21,741 | ||||||||||||||||||||||||||||||||
29,630 | 10,235 | 82,129 | 4,909 | 12,175 | 40,799 | | 23,482 | 5,486 | 208,845 | |||||||||||||||||||||||||||||||||
Accumulated depreciation |
18,707 | 3,650 | 38,236 | 193 | 5,063 | 20,082 | | 10,069 | 1,962 | 97,962 | ||||||||||||||||||||||||||||||||
Net capitalized costs |
10,923 | 6,585 | 43,893 | 4,716 | 7,112 | 20,717 | | 13,413 | 3,524 | 110,883 | ||||||||||||||||||||||||||||||||
Costs incurred for the year ended 31 Decemberb |
|
|||||||||||||||||||||||||||||||||||||||||
Acquisition of properties |
||||||||||||||||||||||||||||||||||||||||||
Proved |
| | 1 | | 7 | | | | | 8 | ||||||||||||||||||||||||||||||||
Unproved |
| | 158 | | 284 | 30 | | 7 | | 479 | ||||||||||||||||||||||||||||||||
| | 159 | | 291 | 30 | | 7 | | 487 | |||||||||||||||||||||||||||||||||
Exploration and appraisal costsc |
178 | 14 | 1,291 | 194 | 951 | 883 | | 1,090 | 210 | 4,811 | ||||||||||||||||||||||||||||||||
Development |
1,942 | 455 | 4,877 | 569 | 683 | 2,755 | | 2,082 | 189 | 13,552 | ||||||||||||||||||||||||||||||||
Total costs |
2,120 | 469 | 6,327 | 763 | 1,925 | 3,668 | | 3,179 | 399 | 18,850 | ||||||||||||||||||||||||||||||||
Results of operations for the year ended 31 December |
|
|||||||||||||||||||||||||||||||||||||||||
Sales and other operating revenuesd |
||||||||||||||||||||||||||||||||||||||||||
Third parties |
1,129 | 183 | 934 | 5 | 2,413 | 3,195 | | 1,005 | 1,784 | 10,648 | ||||||||||||||||||||||||||||||||
Sales between businesses |
1,661 | 1,280 | 14,047 | 12 | 1,154 | 6,518 | | 11,432 | 941 | 37,045 | ||||||||||||||||||||||||||||||||
2,790 | 1,463 | 14,981 | 17 | 3,567 | 9,713 | | 12,437 | 2,725 | 47,693 | |||||||||||||||||||||||||||||||||
Exploration expenditure |
280 | 17 | 437 | 28 | 1,477 | 387 | | 768 | 47 | 3,441 | ||||||||||||||||||||||||||||||||
Production costs |
1,102 | 430 | 3,691 | 42 | 892 | 1,623 | | 1,091 | 187 | 9,058 | ||||||||||||||||||||||||||||||||
Production taxes |
(35 | ) | | 1,112 | | 184 | | | 5,660 | 126 | 7,047 | |||||||||||||||||||||||||||||||
Other costs (income)e |
(1,731 | ) | 86 | 3,241 | 55 | 322 | 89 | 65 | 84 | 351 | 2,562 | |||||||||||||||||||||||||||||||
Depreciation, depletion and amortization |
504 | 490 | 3,268 | | 559 | 3,132 | | 2,174 | 207 | 10,334 | ||||||||||||||||||||||||||||||||
Impairments and (gains) losses on sale of businesses and fixed assets |
118 | 15 | (80 | ) | | 129 | 29 | | (16 | ) | 230 | 425 | ||||||||||||||||||||||||||||||
238 | 1,038 | 11,669 | 125 | 3,563 | 5,260 | 65 | 9,761 | 1,148 | 32,867 | |||||||||||||||||||||||||||||||||
Profit (loss) before taxationf |
2,552 | 425 | 3,312 | (108 | ) | 4 | 4,453 | (65 | ) | 2,676 | 1,577 | 14,826 | ||||||||||||||||||||||||||||||
Allocable taxes |
554 | 475 | 1,204 | (26 | ) | 642 | 1,925 | (2 | ) | 682 | 641 | 6,095 | ||||||||||||||||||||||||||||||
Results of operations |
1,998 | (50 | ) | 2,108 | (82 | ) | (638 | ) | 2,528 | (63 | ) | 1,994 | 936 | 8,731 | ||||||||||||||||||||||||||||
Upstream, Rosneft and TNK-BP segments replacement cost profit before interest and tax |
| |||||||||||||||||||||||||||||||||||||||||
Exploration and production activities subsidiaries (as above) |
2,552 | 425 | 3,312 | (108 | ) | 4 | 4,453 | (65 | ) | 2,676 | 1,577 | 14,826 | ||||||||||||||||||||||||||||||
Midstream activities subsidiariesg |
244 | (40 | ) | 296 | (14 | ) | 153 | (154 | ) | (4 | ) | (29 | ) | 347 | 799 | |||||||||||||||||||||||||||
TNK-BP gain on sale |
| | | | | | 12,500 | | | 12,500 | ||||||||||||||||||||||||||||||||
Equity-accounted entitiesh |
| 28 | 17 | | 405 | 24 | 2,158 | 553 | | 3,185 | ||||||||||||||||||||||||||||||||
Total replacement cost profit before interest and tax |
2,796 | 413 | 3,625 | (122 | ) | 562 | 4,323 | 14,589 | 3,200 | 1,924 | 31,310 |
a | These tables contain information relating to oil and natural gas exploration and production activities of subsidiaries, which includes our share of oil and natural gas exploration and production activities of joint operations. They do not include any costs relating to the Gulf of Mexico oil spill. Midstream activities relating to the management and ownership of crude oil and natural gas pipelines, processing and export terminals and LNG processing facilities and transportation are excluded. In addition, our midstream activities of marketing and trading of natural gas, power and NGLs in the US, Canada, UK and Europe are excluded. The most significant midstream pipeline interests include the Trans-Alaska Pipeline System, the Forties Pipeline System, the Central Area Transmission System pipeline, the South Caucasus Pipeline and the Baku-Tbilisi-Ceyhan pipeline. Major LNG activities are located in Trinidad, Indonesia, Australia and Angola. |
b | Decommissioning assets are included in capitalized costs at 31 December but are excluded from costs incurred for the year. |
c | Includes exploration and appraisal drilling expenditures, which are capitalized within intangible assets, and geological and geophysical exploration costs, which are charged to income as incurred. |
d | Presented net of transportation costs, purchases and sales taxes. |
e | Includes property taxes, other government take and the fair value gain on embedded derivatives of $459 million. The UK region includes a $1,055 million gain offset by corresponding charges primarily in the US, relating to the group self-insurance programme. |
f | Excludes the unwinding of the discount on provisions and payables amounting to $141 million which is included in finance costs in the group income statement. |
g | Midstream and other activities excludes inventory holding gains and losses. |
h | The profits of equity-accounted entities are included after interest and tax. |
BP Annual Report and Form 20-F 2013 | 201 |
Oil and natural gas exploration and production activities continued
$ million | ||||||||||||||||||||||||||||||||||||||||||
2013 | ||||||||||||||||||||||||||||||||||||||||||
Europe |
North America |
South America |
Africa |
Asia |
Australasia |
Total | ||||||||||||||||||||||||||||||||||||
UK | Rest of Europe |
US | Rest of North America |
Russiaa | Rest of Asia |
|||||||||||||||||||||||||||||||||||||
Equity-accounted entities (BP share)b |
||||||||||||||||||||||||||||||||||||||||||
Capitalized costs at 31 Decemberc |
||||||||||||||||||||||||||||||||||||||||||
Gross capitalized costs |
||||||||||||||||||||||||||||||||||||||||||
Proved properties |
| | | | 7,648 | | 18,942 | 4,239 | | 30,829 | ||||||||||||||||||||||||||||||||
Unproved properties |
| | | | 29 | | 638 | 21 | | 688 | ||||||||||||||||||||||||||||||||
| | | | 7,677 | | 19,580 | 4,260 | | 31,517 | |||||||||||||||||||||||||||||||||
Accumulated depreciation |
| | | | 3,282 | | 1,077 | 4,061 | | 8,420 | ||||||||||||||||||||||||||||||||
Net capitalized costs |
| | | | 4,395 | | 18,503 | 199 | | 23,097 | ||||||||||||||||||||||||||||||||
Costs incurred for the year ended 31 Decemberd |
|
|||||||||||||||||||||||||||||||||||||||||
Acquisition of properties |
||||||||||||||||||||||||||||||||||||||||||
Proved |
| | | | | | 1,816 | | | 1,816 | ||||||||||||||||||||||||||||||||
Unproved |
| | | | | | 657 | | | 657 | ||||||||||||||||||||||||||||||||
| | | | | | 2,473 | | | 2,473 | |||||||||||||||||||||||||||||||||
Exploration and appraisal costse |
| | | | 8 | | 133 | 12 | | 153 | ||||||||||||||||||||||||||||||||
Development |
| | | | 714 | | 1,860 | 538 | | 3,112 | ||||||||||||||||||||||||||||||||
Total costs |
| | | | 722 | | 4,466 | 550 | | 5,738 | ||||||||||||||||||||||||||||||||
Results of operations for the year ended 31 December |
|
|||||||||||||||||||||||||||||||||||||||||
Sales and other operating revenuesf |
||||||||||||||||||||||||||||||||||||||||||
Third parties |
| | | | 2,294 | | 435 | 4,770 | | 7,499 | ||||||||||||||||||||||||||||||||
Sales between businesses |
| | | | | | 9,679 | 14 | | 9,693 | ||||||||||||||||||||||||||||||||
| | | | 2,294 | | 10,114 | 4,784 | | 17,192 | |||||||||||||||||||||||||||||||||
Exploration expenditure |
| | | | | | 126 | 1 | | 127 | ||||||||||||||||||||||||||||||||
Production costs |
| | | | 586 | | 1,177 | 404 | | 2,167 | ||||||||||||||||||||||||||||||||
Production taxes |
| | | | 630 | | 4,511 | 3,645 | | 8,786 | ||||||||||||||||||||||||||||||||
Other costs (income) |
| | | | 6 | | 94 | (1 | ) | | 99 | |||||||||||||||||||||||||||||||
Depreciation, depletion and amortization |
| | | | 317 | | 1,232 | 544 | | 2,093 | ||||||||||||||||||||||||||||||||
Impairments and losses on sale of |
||||||||||||||||||||||||||||||||||||||||||
businesses and fixed assets |
| | | | | | 37 | | | 37 | ||||||||||||||||||||||||||||||||
| | | | 1,539 | | 7,177 | 4,593 | | 13,309 | |||||||||||||||||||||||||||||||||
Profit (loss) before taxation |
| | | | 755 | | 2,937 | 191 | | 3,883 | ||||||||||||||||||||||||||||||||
Allocable taxes |
| | | | 460 | | 367 | 40 | | 867 | ||||||||||||||||||||||||||||||||
Results of operations |
| | | | 295 | | 2,570 | 151 | | 3,016 | ||||||||||||||||||||||||||||||||
Exploration and production activities equity-accounted entities after tax (as above) |
| | | | 295 | | 2,570 | 151 | | 3,016 | ||||||||||||||||||||||||||||||||
Midstream and other activities after taxg |
| 28 | 17 | | 110 | 24 | (412 | ) | 402 | | 169 | |||||||||||||||||||||||||||||||
Total replacement cost profit after interest and tax |
| 28 | 17 | | 405 | 24 | 2,158 | 553 | | 3,185 |
a | Amounts reported for Russia in this table include BPs share of Rosnefts worldwide activities, including insignificant amounts outside Russia. |
b | These tables contain information relating to oil and natural gas exploration and production activities of equity-accounted entities. They do not include amounts relating to assets held for sale. Midstream activities relating to the management and ownership of crude oil and natural gas pipelines, processing and export terminals and LNG processing facilities and transportation as well as downstream activities of TNK-BP and Rosneft are excluded. The amounts reported for equity-accounted entities exclude the corresponding amounts for their equity-accounted entities. |
c | Decommissioning assets are included in capitalized costs at 31 December but are excluded from costs incurred for the year. |
d | The amounts shown reflect BPs share of equity-accounted entities costs incurred, and not the costs incurred by BP in acquiring an interest in equity-accounted entities. |
e | Includes exploration and appraisal drilling expenditures, which are capitalized within intangible assets, and geological and geophysical exploration costs, which are charged to income as incurred. |
f | Presented net of transportation costs and sales taxes. |
g | Includes interest, non-controlling interest and the net results of equity-accounted entities, and excludes inventory holding gains and losses. |
202 | BP Annual Report and Form 20-F 2013 |
Oil and natural gas exploration and production activities continued
$ million | ||||||||||||||||||||||||||||||||||||||||||
2012 | ||||||||||||||||||||||||||||||||||||||||||
Europe |
North America |
South America |
Africa |
Asia |
Australasia |
Total | ||||||||||||||||||||||||||||||||||||
UK | Rest of Europe |
US | Rest of North America |
Russia | Rest of Asia |
|||||||||||||||||||||||||||||||||||||
Subsidiariesa |
||||||||||||||||||||||||||||||||||||||||||
Capitalized costs at 31 Decemberb j |
||||||||||||||||||||||||||||||||||||||||||
Gross capitalized costs |
||||||||||||||||||||||||||||||||||||||||||
Proved properties |
28,370 | 9,421 | 70,133 | 1,928 | 8,153 | 32,755 | | 16,757 | 3,676 | 171,193 | ||||||||||||||||||||||||||||||||
Unproved properties |
400 | 199 | 7,084 | 2,244 | 3,590 | 4,524 | | 4,920 | 1,540 | 24,501 | ||||||||||||||||||||||||||||||||
28,770 | 9,620 | 77,217 | 4,172 | 11,743 | 37,279 | | 21,677 | 5,216 | 195,694 | |||||||||||||||||||||||||||||||||
Accumulated depreciation |
19,002 | 3,161 | 35,459 | 197 | 4,444 | 16,901 | | 8,360 | 1,517 | 89,041 | ||||||||||||||||||||||||||||||||
Net capitalized costs |
9,768 | 6,459 | 41,758 | 3,975 | 7,299 | 20,378 | | 13,317 | 3,699 | 106,653 | ||||||||||||||||||||||||||||||||
Costs incurred for the year ended 31 Decemberb |
|
|||||||||||||||||||||||||||||||||||||||||
Acquisition of propertiesc k |
||||||||||||||||||||||||||||||||||||||||||
Proved |
| | 256 | | 51 | | | | | 307 | ||||||||||||||||||||||||||||||||
Unproved |
| | 1,111 | | 27 | 239 | | (68 | ) | | 1,309 | |||||||||||||||||||||||||||||||
| | 1,367 | | 78 | 239 | | (68 | ) | | 1,616 | ||||||||||||||||||||||||||||||||
Exploration and appraisal costsd |
173 | 47 | 1,069 | 230 | 758 | 1,024 | | 814 | 241 | 4,356 | ||||||||||||||||||||||||||||||||
Development |
1,907 | 784 | 3,866 | 611 | 581 | 2,992 | | 1,591 | 221 | 12,553 | ||||||||||||||||||||||||||||||||
Total costs |
2,080 | 831 | 6,302 | 841 | 1,417 | 4,255 | | 2,337 | 462 | 18,525 | ||||||||||||||||||||||||||||||||
Results of operations for the year ended 31 December |
|
|||||||||||||||||||||||||||||||||||||||||
Sales and other operating revenuese |
||||||||||||||||||||||||||||||||||||||||||
Third parties |
1,595 | 76 | 453 | 10 | 2,026 | 3,424 | | 1,299 | 1,749 | 10,632 | ||||||||||||||||||||||||||||||||
Sales between businesses |
2,975 | 783 | 15,713 | 10 | 984 | 5,633 | | 11,345 | 915 | 38,358 | ||||||||||||||||||||||||||||||||
4,570 | 859 | 16,166 | 20 | 3,010 | 9,057 | | 12,644 | 2,664 | 48,990 | |||||||||||||||||||||||||||||||||
Exploration expenditure |
105 | 29 | 649 | 4 | 120 | 310 | | 126 | 132 | 1,475 | ||||||||||||||||||||||||||||||||
Production costs |
1,310 | 348 | 3,854 | 71 | 812 | 1,323 | | 1,076 | 191 | 8,985 | ||||||||||||||||||||||||||||||||
Production taxes |
92 | | 1,472 | | 162 | | | 6,291 | 141 | 8,158 | ||||||||||||||||||||||||||||||||
Other costs (income)f |
(1,474 | ) | 78 | 3,505 | 63 | 109 | 221 | (330 | ) | 84 | 264 | 2,520 | ||||||||||||||||||||||||||||||
Depreciation, depletion and amortization |
1,102 | 145 | 3,187 | 10 | 606 | 2,281 | | 2,116 | 211 | 9,658 | ||||||||||||||||||||||||||||||||
Impairments and (gains) losses on sale of businesses and fixed assets |
373 | 83 | (3,576 | ) | 98 | 6 | 24 | | (2 | ) | (5 | ) | (2,999 | ) | ||||||||||||||||||||||||||||
1,508 | 683 | 9,091 | 246 | 1,815 | 4,159 | (330 | ) | 9,691 | 934 | 27,797 | ||||||||||||||||||||||||||||||||
Profit (loss) before taxationg |
3,062 | 176 | 7,075 | (226 | ) | 1,195 | 4,898 | 330 | 2,953 | 1,730 | 21,193 | |||||||||||||||||||||||||||||||
Allocable taxes |
1,121 | (313 | ) | 2,762 | (67 | ) | 804 | 2,371 | (13 | ) | 663 | 755 | 8,083 | |||||||||||||||||||||||||||||
Results of operations |
1,941 | 489 | 4,313 | (159 | ) | 391 | 2,527 | 343 | 2,290 | 975 | 13,110 | |||||||||||||||||||||||||||||||
Upstream segment and TNK-BP segment replacement cost profit before interest and tax |
| |||||||||||||||||||||||||||||||||||||||||
Exploration and production activities subsidiaries (as above) |
3,062 | 176 | 7,075 | (226 | ) | 1,195 | 4,898 | 330 | 2,953 | 1,730 | 21,193 | |||||||||||||||||||||||||||||||
Midstream activities subsidiariesh |
(250 | ) | (114 | ) | (173 | ) | 774 | 163 | (46 | ) | 11 | 32 | 370 | 767 | ||||||||||||||||||||||||||||
Equity-accounted entitiesi |
| 35 | 16 | | 160 | 48 | 3,005 | 640 | | 3,904 | ||||||||||||||||||||||||||||||||
Total replacement cost profit before interest and tax |
2,812 | 97 | 6,918 | 548 | 1,518 | 4,900 | 3,346 | 3,625 | 2,100 | 25,864 |
a | These tables contain information relating to oil and natural gas exploration and production activities of subsidiaries. They do not include any costs relating to the Gulf of Mexico oil spill or assets held for sale. Midstream activities relating to the management and ownership of crude oil and natural gas pipelines, processing and export terminals and LNG processing facilities and transportation are excluded. In addition, our midstream activities of marketing and trading of natural gas, power and NGLs in the US, Canada, UK and Europe are excluded. The most significant midstream pipeline interests include the Trans-Alaska Pipeline System, the Forties Pipeline System, the Central Area Transmission System pipeline, the South Caucasus Pipeline and the Baku-Tbilisi-Ceyhan pipeline. Major LNG activities are located in Trinidad, Indonesia and Australia and BP is also investing in the LNG business in Angola. |
b | Decommissioning assets are included in capitalized costs at 31 December but are excluded from costs incurred for the year. |
c | Includes costs capitalized as a result of asset exchanges. |
d | Includes exploration and appraisal drilling expenditures, which are capitalized within intangible assets, and geological and geophysical exploration costs, which are charged to income as incurred. |
e | Presented net of transportation costs, purchases and sales taxes. |
f | Includes property taxes, other government take and the fair value gain on embedded derivatives of $347 million. The UK region includes a $1,161 million gain offset by corresponding charges primarily in the US, relating to the group self-insurance programme. The Russia region, for which equity accounting ceased on 22 October 2012, includes a net non-operating gain of $351 million including dividend income of $709 million partly offset by a settlement charge of $325 million. |
g | Excludes the unwinding of the discount on provisions and payables amounting to $173 million which is included in finance costs in the group income statement. |
h | Midstream and other activities exclude inventory holding gains and losses. |
i | The profits of equity-accounted entities are included after interest and tax and the results exclude balances associated with assets held for sale. |
j | Excludes balances associated with assets held for sale. |
k | Excludes goodwill associated with business combinations. |
BP Annual Report and Form 20-F 2013 | 203 |
Oil and natural gas exploration and production activities continued
$ million | ||||||||||||||||||||||||||||||||||||||||||
2012 | ||||||||||||||||||||||||||||||||||||||||||
Europe |
North
America |
South
America |
Africa |
Asia |
Australasia |
Total | ||||||||||||||||||||||||||||||||||||
UK | Rest of Europe |
US | Rest of North America |
Russiaa | Rest of Asia |
|||||||||||||||||||||||||||||||||||||
Equity-accounted entities (BP share)b |
||||||||||||||||||||||||||||||||||||||||||
Capitalized costs at 31 Decemberc |
||||||||||||||||||||||||||||||||||||||||||
Gross capitalized costs |
||||||||||||||||||||||||||||||||||||||||||
Proved properties |
| | | | 6,958 | | | 4,036 | | 10,994 | ||||||||||||||||||||||||||||||||
Unproved properties |
| | | | 21 | | | 16 | | 37 | ||||||||||||||||||||||||||||||||
| | | | 6,979 | | | 4,052 | | 11,031 | |||||||||||||||||||||||||||||||||
Accumulated depreciation |
| | | | 2,965 | | | 3,648 | | 6,613 | ||||||||||||||||||||||||||||||||
Net capitalized costs |
| | | | 4,014 | | | 404 | | 4,418 | ||||||||||||||||||||||||||||||||
Costs incurred for the year ended 31 Decemberc |
|
|||||||||||||||||||||||||||||||||||||||||
Acquisition of propertiesd |
||||||||||||||||||||||||||||||||||||||||||
Proved |
| | | | | | 4 | | | 4 | ||||||||||||||||||||||||||||||||
Unproved |
| | | | 439 | | 15 | | | 454 | ||||||||||||||||||||||||||||||||
| | | | 439 | | 19 | | | 458 | |||||||||||||||||||||||||||||||||
Exploration and appraisal costse |
| | | | 31 | | 195 | 7 | | 233 | ||||||||||||||||||||||||||||||||
Development |
| | | | 599 | | 1,560 | 556 | | 2,715 | ||||||||||||||||||||||||||||||||
Total costs |
| | | | 1,069 | | 1,774 | 563 | | 3,406 | ||||||||||||||||||||||||||||||||
Results of operations for the year ended 31 December |
|
|||||||||||||||||||||||||||||||||||||||||
Sales and other operating revenuesf |
||||||||||||||||||||||||||||||||||||||||||
Third parties |
| | | | 2,267 | | 6,472 | 4,245 | | 12,984 | ||||||||||||||||||||||||||||||||
Sales between businesses |
| | | | | | 3,639 | 21 | | 3,660 | ||||||||||||||||||||||||||||||||
| | | | 2,267 | | 10,111 | 4,266 | | 16,644 | |||||||||||||||||||||||||||||||||
Exploration expenditure |
| | | | 31 | | 93 | 1 | | 125 | ||||||||||||||||||||||||||||||||
Production costs |
| | | | 555 | | 1,605 | 295 | | 2,455 | ||||||||||||||||||||||||||||||||
Production taxes |
| | | | 959 | | 4,400 | 3,245 | | 8,604 | ||||||||||||||||||||||||||||||||
Other costs (income) |
| | | | (11 | ) | | (24 | ) | (2 | ) | | (37 | ) | ||||||||||||||||||||||||||||
Depreciation, depletion and amortization |
| | | | 328 | | 786 | 538 | | 1,652 | ||||||||||||||||||||||||||||||||
Impairments and losses on sale of businesses and fixed assets |
| | | | | | (27 | ) | | | (27 | ) | ||||||||||||||||||||||||||||||
| | | | 1,862 | | 6,833 | 4,077 | | 12,772 | |||||||||||||||||||||||||||||||||
Profit (loss) before taxation |
| | | | 405 | | 3,278 | 189 | | 3,872 | ||||||||||||||||||||||||||||||||
Allocable taxes |
| | | | 294 | | 536 | 54 | | 884 | ||||||||||||||||||||||||||||||||
Results of operations |
| | | | 111 | | 2,742 | 135 | | 2,988 | ||||||||||||||||||||||||||||||||
Exploration and production activities equity-accounted entities after tax (as above) |
| | | | 111 | | 2,742 | 135 | | 2,988 | ||||||||||||||||||||||||||||||||
Midstream and other activities after taxg |
| 35 | 16 | | 49 | 48 | 263 | 505 | | 916 | ||||||||||||||||||||||||||||||||
Total replacement cost profit after interest and tax |
| 35 | 16 | | 160 | 48 | 3,005 | 640 | | 3,904 |
a | The Russia region includes BPs equity-accounted share of TNK-BPs earnings. For 2012, equity-accounted earnings are included until 21 October 2012 only, after which our investment was classified as an asset held for sale and therefore equity accounting ceased. The amounts shown exclude BPs share of costs incurred and results of operations for the period 22 October to 31 December 2012. |
b | These tables contain information relating to oil and natural gas exploration and production activities of equity-accounted entities. They do not include amounts relating to assets held for sale. Midstream activities relating to the management and ownership of crude oil and natural gas pipelines, processing and export terminals and LNG processing facilities and transportation as well as downstream activities of TNK-BP are excluded. The amounts reported for equity-accounted entities exclude the corresponding amounts for their equity-accounted entities. |
c | Decommissioning assets are included in capitalized costs at 31 December but are excluded from costs incurred for the year. Capitalized costs exclude balances associated with assets held for sale. |
d | Includes costs capitalized as a result of asset exchanges. |
e | Includes exploration and appraisal drilling expenditures, which are capitalized within intangible assets, and geological and geophysical exploration costs, which are charged to income as incurred. |
f | Presented net of transportation costs and sales taxes. |
g | Includes interest, non-controlling interest and the net results of equity-accounted entities, and excludes inventory holding gains and losses. |
204 | BP Annual Report and Form 20-F 2013 |
Oil and natural gas exploration and production activities continued
$ million | ||||||||||||||||||||||||||||||||||||||||||
2011 | ||||||||||||||||||||||||||||||||||||||||||
Europe |
North America |
South
|
Africa |
Asia |
Australasia |
Total | ||||||||||||||||||||||||||||||||||||
UK |
Rest of |
US | Rest of North America |
Russia | Rest of Asia |
|||||||||||||||||||||||||||||||||||||
Subsidiariesa |
||||||||||||||||||||||||||||||||||||||||||
Capitalized costs at 31 Decemberb j |
|
|||||||||||||||||||||||||||||||||||||||||
Gross capitalized costs |
||||||||||||||||||||||||||||||||||||||||||
Proved properties |
37,491 | 8,994 | 73,626 | 1,296 | 7,471 | 29,358 | | 14,833 | 3,370 | 176,439 | ||||||||||||||||||||||||||||||||
Unproved properties |
368 | 180 | 6,198 | 2,017 | 2,986 | 3,689 | | 4,495 | 1,279 | 21,212 | ||||||||||||||||||||||||||||||||
37,859 | 9,174 | 79,824 | 3,313 | 10,457 | 33,047 | | 19,328 | 4,649 | 197,651 | |||||||||||||||||||||||||||||||||
Accumulated depreciation |
26,953 | 3,715 | 36,009 | 139 | 3,839 | 14,595 | | 6,235 | 1,294 | 92,779 | ||||||||||||||||||||||||||||||||
Net capitalized costs |
10,906 | 5,459 | 43,815 | 3,174 | 6,618 | 18,452 | | 13,093 | 3,355 | 104,872 | ||||||||||||||||||||||||||||||||
Costs incurred for the year ended 31 Decemberb j |
|
|||||||||||||||||||||||||||||||||||||||||
Acquisition of propertiesc k |
||||||||||||||||||||||||||||||||||||||||||
Proved |
| | 1,178 | 8 | 237 | | | 1,733 | | 3,156 | ||||||||||||||||||||||||||||||||
Unproved |
| 1 | 418 | | 2,592 | 679 | | 3,008 | | 6,698 | ||||||||||||||||||||||||||||||||
| 1 | 1,596 | 8 | 2,829 | 679 | | 4,741 | | 9,854 | |||||||||||||||||||||||||||||||||
Exploration and appraisal costsd |
211 | 1 | 566 | 132 | 271 | 490 | 6 | 511 | 225 | 2,413 | ||||||||||||||||||||||||||||||||
Development |
1,361 | 889 | 3,016 | 227 | 405 | 2,933 | | 1,340 | 251 | 10,422 | ||||||||||||||||||||||||||||||||
Total costs |
1,572 | 891 | 5,178 | 367 | 3,505 | 4,102 | 6 | 6,592 | 476 | 22,689 | ||||||||||||||||||||||||||||||||
Results of operations for the year ended 31 December |
|
|||||||||||||||||||||||||||||||||||||||||
Sales and other operating revenuese |
||||||||||||||||||||||||||||||||||||||||||
Third parties |
1,997 | | 751 | 25 | 2,263 | 3,353 | | 1,450 | 1,611 | 11,450 | ||||||||||||||||||||||||||||||||
Sales between businesses |
3,495 | 1,273 | 19,089 | 20 | 1,409 | 4,858 | | 10,811 | 967 | 41,922 | ||||||||||||||||||||||||||||||||
5,492 | 1,273 | 19,840 | 45 | 3,672 | 8,211 | | 12,261 | 2,578 | 53,372 | |||||||||||||||||||||||||||||||||
Exploration expenditure |
37 | 1 | 1,065 | 9 | 35 | 163 | 6 | 134 | 70 | 1,520 | ||||||||||||||||||||||||||||||||
Production costs |
1,372 | 230 | 3,402 | 66 | 503 | 1,146 | 4 | 787 | 194 | 7,704 | ||||||||||||||||||||||||||||||||
Production taxes |
72 | | 1,854 | | 278 | | | 5,956 | 147 | 8,307 | ||||||||||||||||||||||||||||||||
Other costs (income)f |
(1,357 | ) | 101 | 4,688 | 62 | 935 | 215 | 72 | 118 | 257 | 5,091 | |||||||||||||||||||||||||||||||
Depreciation, depletion and amortization |
874 | 199 | 2,980 | 6 | 523 | 1,668 | | 1,692 | 172 | 8,114 | ||||||||||||||||||||||||||||||||
Impairments and (gains) losses on sale of businesses and fixed assets |
26 | (64 | ) | (492 | ) | 15 | (1,085 | ) | 18 | (1 | ) | (537 | ) | | (2,120 | ) | ||||||||||||||||||||||||||
1,024 | 467 | 13,497 | 158 | 1,189 | 3,210 | 81 | 8,150 | 840 | 28,616 | |||||||||||||||||||||||||||||||||
Profit (loss) before taxationg |
4,468 | 806 | 6,343 | (113 | ) | 2,483 | 5,001 | (81 | ) | 4,111 | 1,738 | 24,756 | ||||||||||||||||||||||||||||||
Allocable taxes |
2,483 | 384 | 2,152 | (159 | ) | 1,205 | 2,184 | (21 | ) | 1,001 | 677 | 9,906 | ||||||||||||||||||||||||||||||
Results of operations |
1,985 | 422 | 4,191 | 46 | 1,278 | 2,817 | (60 | ) | 3,110 | 1,061 | 14,850 | |||||||||||||||||||||||||||||||
Upstream segment and TNK-BP segment replacement cost profit before interest and tax |
| |||||||||||||||||||||||||||||||||||||||||
Exploration and production activities subsidiaries (as above) |
4,468 | 806 | 6,343 | (113 | ) | 2,483 | 5,001 | (81 | ) | 4,111 | 1,738 | 24,756 | ||||||||||||||||||||||||||||||
Midstream activities subsidiariesh |
(118 | ) | 29 | (157 | ) | 299 | 78 | (4 | ) | (1 | ) | 42 | 284 | 452 | ||||||||||||||||||||||||||||
Equity-accounted entitiesi |
| 12 | 10 | | 525 | 69 | 4,095 | 573 | | 5,284 | ||||||||||||||||||||||||||||||||
Total replacement cost profit before interest and tax |
4,350 | 847 | 6,196 | 186 | 3,086 | 5,066 | 4,013 | 4,726 | 2,022 | 30,492 |
a | These tables contain information relating to oil and natural gas exploration and production activities of subsidiaries. They do not include any costs relating to the Gulf of Mexico oil spill. Midstream activities relating to the management and ownership of crude oil and natural gas pipelines, processing and export terminals and LNG processing facilities and transportation are excluded. In addition, our midstream activities of marketing and trading of natural gas, power and NGLs in the US, Canada, UK and Europe are excluded. The most significant midstream pipeline interests include the Trans-Alaska Pipeline System, the Forties Pipeline System, the Central Area Transmission System pipeline, the South Caucasus Pipeline and the Baku-Tbilisi-Ceyhan pipeline. Major LNG activities are located in Trinidad, Indonesia and Australia and BP is also investing in the LNG business in Angola. |
b | Decommissioning assets are included in capitalized costs at 31 December but are excluded from costs incurred for the year. |
c | Includes costs capitalized as a result of asset exchanges. |
d | Includes exploration and appraisal drilling expenditures, which are capitalized within intangible assets, and geological and geophysical exploration costs, which are charged to income as incurred. |
e | Presented net of transportation costs, purchases and sales taxes. |
f | Includes property taxes, other government take and the fair value gain on embedded derivatives of $191 million. The UK region includes a $1,442 million gain offset by corresponding charges primarily in the US, relating to the group self-insurance programme. The South America region includes a charge of $700 million associated with the termination of the agreement to sell our 60% interest in Pan American Energy LLC to Bridas Corporation. |
g | Excludes the unwinding of the discount on provisions and payables amounting to $267 million which is included in finance costs in the group income statement. |
h | Midstream activities exclude inventory holding gains and losses. |
i | The profits of equity-accounted entities are included after interest and tax. |
j | Excludes balances associated with assets held for sale. |
k | Excludes goodwill associated with business combinations. |
BP Annual Report and Form 20-F 2013 | 205 |
Oil and natural gas exploration and production activities continued
$ million |
||||||||||||||||||||||||||||||||||||||||||
2011 | ||||||||||||||||||||||||||||||||||||||||||
Europe |
North America |
South America |
Africa |
Asia |
Australasia |
Total | ||||||||||||||||||||||||||||||||||||
UK | Rest of Europe |
US | Rest of North America |
Russia | Rest of Asia |
|||||||||||||||||||||||||||||||||||||
Equity-accounted entities (BP share)a |
||||||||||||||||||||||||||||||||||||||||||
Capitalized costs at 31 Decemberb |
||||||||||||||||||||||||||||||||||||||||||
Gross capitalized costs |
||||||||||||||||||||||||||||||||||||||||||
Proved properties |
| | | | 6,562 | | 16,214 | 3,571 | | 26,347 | ||||||||||||||||||||||||||||||||
Unproved properties |
| | | | 19 | | 652 | 9 | | 680 | ||||||||||||||||||||||||||||||||
| | | | 6,581 | | 16,866 | 3,580 | | 27,027 | |||||||||||||||||||||||||||||||||
Accumulated depreciation |
| | | | 2,644 | | 6,978 | 3,017 | | 12,639 | ||||||||||||||||||||||||||||||||
Net capitalized costs |
| | | | 3,937 | | 9,888 | 563 | | 14,388 | ||||||||||||||||||||||||||||||||
Costs incurred for the year ended 31 Decemberb |
|
|||||||||||||||||||||||||||||||||||||||||
Acquisition of propertiesc |
||||||||||||||||||||||||||||||||||||||||||
Proved |
| | | | | | | 46 | | 46 | ||||||||||||||||||||||||||||||||
Unproved |
| | | | 6 | | 37 | | | 43 | ||||||||||||||||||||||||||||||||
| | | | 6 | | 37 | 46 | | 89 | |||||||||||||||||||||||||||||||||
Exploration and appraisal costsd |
| | | | 2 | | 167 | 9 | | 178 | ||||||||||||||||||||||||||||||||
Development |
| | | | 587 | | 1,862 | 435 | | 2,884 | ||||||||||||||||||||||||||||||||
Total costs |
| | | | 595 | | 2,066 | 490 | | 3,151 | ||||||||||||||||||||||||||||||||
Results of operations for the year ended 31 December |
|
|||||||||||||||||||||||||||||||||||||||||
Sales and other operating revenuese |
||||||||||||||||||||||||||||||||||||||||||
Third parties |
| | | | 2,381 | | 7,380 | 3,828 | | 13,589 | ||||||||||||||||||||||||||||||||
Sales between businesses |
| | | | | | 5,149 | 23 | | 5,172 | ||||||||||||||||||||||||||||||||
| | | | 2,381 | | 12,529 | 3,851 | | 18,761 | |||||||||||||||||||||||||||||||||
Exploration expenditure |
| | | | 10 | | 72 | 1 | | 83 | ||||||||||||||||||||||||||||||||
Production costs |
| | | | 459 | | 1,846 | 212 | | 2,517 | ||||||||||||||||||||||||||||||||
Production taxes |
| | | | 1,098 | | 5,000 | 3,125 | | 9,223 | ||||||||||||||||||||||||||||||||
Other costs (income) |
| | | | (239 | ) | | 2 | (1 | ) | | (238 | ) | |||||||||||||||||||||||||||||
Depreciation, depletion and amortization |
| | | | 329 | | 988 | 431 | | 1,748 | ||||||||||||||||||||||||||||||||
Impairments and (gains) losses on sale of businesses and fixed assets |
| | | | | | | | | | ||||||||||||||||||||||||||||||||
| | | | 1,657 | | 7,908 | 3,768 | | 13,333 | |||||||||||||||||||||||||||||||||
Profit (loss) before taxation |
| | | | 724 | | 4,621 | 83 | | 5,428 | ||||||||||||||||||||||||||||||||
Allocable taxes |
| | | | 294 | | 806 | 19 | | 1,119 | ||||||||||||||||||||||||||||||||
Results of operations |
| | | | 430 | | 3,815 | 64 | | 4,309 | ||||||||||||||||||||||||||||||||
Exploration and production activities equity-accounted entities after tax (as above) |
| | | | 430 | | 3,815 | 64 | | 4,309 | ||||||||||||||||||||||||||||||||
Midstream and other activities after taxf |
| 12 | 10 | | 95 | 69 | 280 | 509 | | 975 | ||||||||||||||||||||||||||||||||
Total replacement cost profit after interest and tax |
| 12 | 10 | | 525 | 69 | 4,095 | 573 | | 5,284 |
a | These tables contain information relating to oil and natural gas exploration and production activities of equity-accounted entities. They do not include amounts relating to assets held for sale. Midstream activities relating to the management and ownership of crude oil and natural gas pipelines, processing and export terminals and LNG processing facilities and transportation as well as downstream activities of TNK-BP are excluded. The amounts reported for equity-accounted entities exclude the corresponding amounts for their equity-accounted entities. |
b | Decommissioning assets are included in capitalized costs at 31 December but are excluded from costs incurred for the year. |
c | Includes costs capitalized as a result of asset exchanges. |
d | Includes exploration and appraisal drilling expenditures, which are capitalized within intangible assets, and geological and geophysical exploration costs, which are charged to income as incurred. |
e | Presented net of transportation costs and sales taxes. |
f | Includes interest, non-controlling interest and the net results of equity-accounted entities, and excludes inventory holding gains and losses |
206 | BP Annual Report and Form 20-F 2013 |
Movements in estimated net proved reserves
million barrels | ||||||||||||||||||||||||||||||||||||||||||
Crude oila | 2013 | |||||||||||||||||||||||||||||||||||||||||
Europe |
North America |
South America |
Africa |
Asia |
Australasia |
Total | ||||||||||||||||||||||||||||||||||||
UK | Rest of Europe |
USb | Rest of North America |
Russia | Rest of Asia |
|||||||||||||||||||||||||||||||||||||
Subsidiaries |
||||||||||||||||||||||||||||||||||||||||||
At 1 January 2013 |
||||||||||||||||||||||||||||||||||||||||||
Developed |
242 | 170 | 1,443 | | 22 | 312 | | 268 | 52 | 2,509 | ||||||||||||||||||||||||||||||||
Undeveloped |
431 | 79 | 989 | | 32 | 255 | | 137 | 45 | 1,968 | ||||||||||||||||||||||||||||||||
673 | 249 | 2,432 | | 54 | 567 | | 405 | 97 | 4,477 | |||||||||||||||||||||||||||||||||
Changes attributable to |
||||||||||||||||||||||||||||||||||||||||||
Revisions of previous estimates |
(78 | ) | (19 | ) | (141 | ) | | 30 | 26 | | 65 | (12 | ) | (129 | ) | |||||||||||||||||||||||||||
Improved recovery |
12 | | 52 | | 1 | 2 | | 65 | | 132 | ||||||||||||||||||||||||||||||||
Purchases of reserves-in-place |
| | | | | | | | | | ||||||||||||||||||||||||||||||||
Discoveries and extensions |
| | 4 | | | | | 39 | 3 | 46 | ||||||||||||||||||||||||||||||||
Productionc |
(22 | ) | (12 | ) | (132 | ) | | (11 | ) | (80 | ) | | (52 | ) | (9 | ) | (318 | ) | ||||||||||||||||||||||||
Sales of reserves-in-place |
(36 | ) | | (11 | ) | | | | | | | (47 | ) | |||||||||||||||||||||||||||||
(124 | ) | (31 | ) | (228 | ) | | 20 | (52 | ) | | 117 | (18 | ) | (316 | ) | |||||||||||||||||||||||||||
At 31 December 2013d |
||||||||||||||||||||||||||||||||||||||||||
Developed |
169 | 163 | 1,297 | | 29 | 320 | | 320 | 57 | 2,355 | ||||||||||||||||||||||||||||||||
Undeveloped |
380 | 55 | 907 | | 45 | 195 | | 202 | 22 | 1,806 | ||||||||||||||||||||||||||||||||
549 | 218 | 2,204 | | 74 | 515 | | 522 | 79 | 4,161 | |||||||||||||||||||||||||||||||||
Equity-accounted entities (BP share)e |
||||||||||||||||||||||||||||||||||||||||||
At 1 January 2013 |
||||||||||||||||||||||||||||||||||||||||||
Developed |
| | | | 339 | 12 | 2,492 | 198 | | 3,041 | ||||||||||||||||||||||||||||||||
Undeveloped |
| | | | 351 | 11 | 1,962 | 13 | | 2,337 | ||||||||||||||||||||||||||||||||
| | | | 690 | 23 | 4,454 | 211 | | 5,378 | |||||||||||||||||||||||||||||||||
Changes attributable to |
||||||||||||||||||||||||||||||||||||||||||
Revisions of previous estimates |
| | | 1 | (21 | ) | (3 | ) | 384 | 1 | | 362 | ||||||||||||||||||||||||||||||
Improved recovery |
| | | | 27 | | | | | 27 | ||||||||||||||||||||||||||||||||
Purchases of reserves-in-place |
| | | | 34 | | 4,579 | | | 4,613 | ||||||||||||||||||||||||||||||||
Discoveries and extensions |
| | | | 12 | | 228 | | | 240 | ||||||||||||||||||||||||||||||||
Production |
| | | | (27 | ) | | (303 | ) | (85 | ) | | (415 | ) | ||||||||||||||||||||||||||||
Sales of reserves-in-place |
| | | | (85 | ) | | (4,399 | ) | | | (4,484 | ) | |||||||||||||||||||||||||||||
| | | 1 | (60 | ) | (3 | ) | 489 | (84 | ) | | 343 | ||||||||||||||||||||||||||||||
At 31 December 2013f g |
||||||||||||||||||||||||||||||||||||||||||
Developed |
| | | | 316 | 10 | 3,064 | 120 | | 3,510 | ||||||||||||||||||||||||||||||||
Undeveloped |
| | | 1 | 314 | 10 | 1,879 | 7 | | 2,211 | ||||||||||||||||||||||||||||||||
| | | 1 | 630 | 20 | 4,943 | 127 | | 5,721 | |||||||||||||||||||||||||||||||||
Total subsidiaries and equity-accounted entities (BP share) |
|
|||||||||||||||||||||||||||||||||||||||||
At 1 January 2013 |
||||||||||||||||||||||||||||||||||||||||||
Developed |
242 | 170 | 1,443 | | 361 | 324 | 2,492 | 466 | 52 | 5,550 | ||||||||||||||||||||||||||||||||
Undeveloped |
431 | 79 | 989 | | 383 | 266 | 1,962 | 150 | 45 | 4,305 | ||||||||||||||||||||||||||||||||
673 | 249 | 2,432 | | 744 | 590 | 4,454 | 616 | 97 | 9,855 | |||||||||||||||||||||||||||||||||
At 31 December 2013 |
||||||||||||||||||||||||||||||||||||||||||
Developed |
169 | 163 | 1,297 | | 345 | 330 | 3,064 | 440 | 57 | 5,865 | ||||||||||||||||||||||||||||||||
Undeveloped |
380 | 55 | 907 | 1 | 359 | 205 | 1,879 | 209 | 22 | 4,017 | ||||||||||||||||||||||||||||||||
549 | 218 | 2,204 | 1 | 704 | 535 | 4,943 | 649 | 79 | 9,882 |
a | Crude oil includes NGLs and condensate. Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting and sales arrangements independently. |
b | Proved reserves in the Prudhoe Bay field in Alaska include an estimated 72 million barrels upon which a net profits royalty will be payable over the life of the field under the terms of the BP Prudhoe Bay Royalty Trust. |
c | Excludes NGLs from processing plants in which an interest is held of 5,500 barrels per day. |
d | Includes 551 million barrels of NGLs. Also includes 21 million barrels of crude oil in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC. |
e | Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities. |
f | Includes 131 million barrels of NGLs. Also includes 23 million barrels of crude oil in respect of the 0.47% non-controlling interest in Rosneft. |
g | Total proved liquid reserves held as part of our equity interest in Rosneft is 4,975 million barrels, comprising less than 1 mmboe in Vietnam and Canada, 32 million barrels in Venezuela and 4,943 million barrels in Russia. |
BP Annual Report and Form 20-F 2013 | 207 |
Movements in estimated net proved reserves continued
billion cubic feet | ||||||||||||||||||||||||||||||||||||||||||
Natural gasa |
2013 | |||||||||||||||||||||||||||||||||||||||||
Europe |
North America |
South America |
Africa |
Asia |
Australasia |
Total | ||||||||||||||||||||||||||||||||||||
UK | Rest of Europe |
US | Rest of North America |
Russia | Rest of Asia |
|||||||||||||||||||||||||||||||||||||
Subsidiaries |
||||||||||||||||||||||||||||||||||||||||||
At 1 January 2013 |
||||||||||||||||||||||||||||||||||||||||||
Developed |
1,038 | 340 | 8,245 | 4 | 3,588 | 1,139 | | 926 | 3,282 | 18,562 | ||||||||||||||||||||||||||||||||
Undeveloped |
666 | 141 | 2,986 | | 6,250 | 1,923 | | 413 | 2,323 | 14,702 | ||||||||||||||||||||||||||||||||
1,704 | 481 | 11,231 | 4 | 9,838 | 3,062 | | 1,339 | 5,605 | 33,264 | |||||||||||||||||||||||||||||||||
Changes attributable to |
||||||||||||||||||||||||||||||||||||||||||
Revisions of previous estimates |
(62 | ) | (47 | ) | (1,166 | ) | 10 | 62 | (138 | ) | | 2,148 | (140 | ) | 667 | |||||||||||||||||||||||||||
Improved recovery |
49 | | 630 | | 144 | 28 | | 94 | | 945 | ||||||||||||||||||||||||||||||||
Purchases of reserves-in-place |
9 | | | | | | | | | 9 | ||||||||||||||||||||||||||||||||
Discoveries and extensions |
| | 39 | | | 55 | | 1,875 | 511 | 2,480 | ||||||||||||||||||||||||||||||||
Productionb |
(66 | ) | (31 | ) | (635 | ) | (4 | ) | (819 | ) | (239 | ) | | (199 | ) | (289 | ) | (2,282 | ) | |||||||||||||||||||||||
Sales of reserves-in-place |
(677 | ) | | (152 | ) | | | | | (67 | ) | | (896 | ) | ||||||||||||||||||||||||||||
(747 | ) | (78 | ) | (1,284 | ) | 6 | (613 | ) | (294 | ) | | 3,851 | 82 | 923 | ||||||||||||||||||||||||||||
At 31 December 2013c |
||||||||||||||||||||||||||||||||||||||||||
Developed |
643 | 364 | 7,122 | 10 | 3,109 | 961 | | 1,519 | 3,932 | 17,660 | ||||||||||||||||||||||||||||||||
Undeveloped |
314 | 39 | 2,825 | | 6,116 | 1,807 | | 3,671 | 1,755 | 16,527 | ||||||||||||||||||||||||||||||||
957 | 403 | 9,947 | 10 | 9,225 | 2,768 | | 5,190 | 5,687 | 34,187 | |||||||||||||||||||||||||||||||||
Equity-accounted entities (BP share)d |
||||||||||||||||||||||||||||||||||||||||||
At 1 January 2013 |
||||||||||||||||||||||||||||||||||||||||||
Developed |
| | | | 1,276 | 175 | 2,617 | 128 | | 4,196 | ||||||||||||||||||||||||||||||||
Undeveloped |
| | | | 904 | 164 | 1,759 | 18 | | 2,845 | ||||||||||||||||||||||||||||||||
| | | | 2,180 | 339 | 4,376 | 146 | | 7,041 | |||||||||||||||||||||||||||||||||
Changes attributable to |
||||||||||||||||||||||||||||||||||||||||||
Revisions of previous estimates |
| | | 1 | 3 | 29 | 685 | 1 | | 719 | ||||||||||||||||||||||||||||||||
Improved recovery |
| | | | 64 | | | 3 | | 67 | ||||||||||||||||||||||||||||||||
Purchases of reserves-in-place |
| | | | 14 | | 8,871 | 33 | | 8,918 | ||||||||||||||||||||||||||||||||
Discoveries and extensions |
| | | | 51 | | 254 | | | 305 | ||||||||||||||||||||||||||||||||
Productionb |
| | | | (163 | ) | (3 | ) | (292 | ) | (23 | ) | | (481 | ) | |||||||||||||||||||||||||||
Sales of reserves-in-place |
| | | | (38 | ) | | (4,669 | ) | (74 | ) | | (4,781 | ) | ||||||||||||||||||||||||||||
| | | 1 | (69 | ) | 26 | 4,849 | (60 | ) | | 4,747 | |||||||||||||||||||||||||||||||
At 31 December 2013e f |
||||||||||||||||||||||||||||||||||||||||||
Developed |
| | | | 1,364 | 230 | 4,171 | 72 | | 5,837 | ||||||||||||||||||||||||||||||||
Undeveloped |
| | | 1 | 747 | 135 | 5,054 | 14 | | 5,951 | ||||||||||||||||||||||||||||||||
| | | 1 | 2,111 | 365 | 9,225 | 86 | | 11,788 | |||||||||||||||||||||||||||||||||
Total subsidiaries and equity-accounted entities (BP share) |
|
|||||||||||||||||||||||||||||||||||||||||
At 1 January 2013 |
||||||||||||||||||||||||||||||||||||||||||
Developed |
1,038 | 340 | 8,245 | 4 | 4,864 | 1,314 | 2,617 | 1,054 | 3,282 | 22,758 | ||||||||||||||||||||||||||||||||
Undeveloped |
666 | 141 | 2,986 | | 7,154 | 2,087 | 1,759 | 431 | 2,323 | 17,547 | ||||||||||||||||||||||||||||||||
1,704 | 481 | 11,231 | 4 | 12,018 | 3,401 | 4,376 | 1,485 | 5,605 | 40,305 | |||||||||||||||||||||||||||||||||
At 31 December 2013 |
||||||||||||||||||||||||||||||||||||||||||
Developed |
643 | 364 | 7,122 | 10 | 4,473 | 1,191 | 4,171 | 1,591 | 3,932 | 23,497 | ||||||||||||||||||||||||||||||||
Undeveloped |
314 | 39 | 2,825 | 1 | 6,863 | 1,942 | 5,054 | 3,685 | 1,755 | 22,478 | ||||||||||||||||||||||||||||||||
957 | 403 | 9,947 | 11 | 11,336 | 3,133 | 9,225 | 5,276 | 5,687 | 45,975 |
a | Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting and sales arrangements independently. |
b | Includes 180 billion cubic feet of natural gas consumed in operations, 149 billion cubic feet in subsidiaries, 31 billion cubic feet in equity-accounted entities. |
c | Includes 2,685 billion cubic feet of natural gas in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC. |
d | Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities. |
e | Includes 41 billion cubic feet of natural gas in respect of the 0.44% non-controlling interest in Rosneft. |
f | Total proved gas reserves held as part of our equity interest in Rosneft is 9,271 billion cubic feet, comprising 1 billion cubic feet in Canada, 14 billion cubic feet in Venezuela, 31 billion cubic feet in Vietnam and 9,225 billion cubic feet in Russia. |
208 | BP Annual Report and Form 20-F 2013 |
Movements in estimated net proved reserves continued
million barrels | ||||||||||
Bitumena | 2013 | |||||||||
|
Rest of North America |
|
Total | |||||||
Subsidiaries |
||||||||||
At 1 January 2013 |
||||||||||
Developed |
| | ||||||||
Undeveloped |
195 | 195 | ||||||||
195 | 195 | |||||||||
Changes attributable to |
||||||||||
Revisions of previous estimates |
(7 | ) | (7 | ) | ||||||
Improved recovery |
| | ||||||||
Purchases of reserves-in-place |
| | ||||||||
Discoveries and extensions |
| | ||||||||
Production |
| | ||||||||
Sales of reserves-in-place |
| | ||||||||
(7 | ) | (7 | ) | |||||||
At 31 December 2013 |
||||||||||
Developed |
| | ||||||||
Undeveloped |
188 | 188 | ||||||||
188 | 188 |
a | Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting and sales arrangements independently. |
BP Annual Report and Form 20-F 2013 | 209 |
Movements in estimated net proved reserves continued
million barrels of oil equivalentb |
||||||||||||||||||||||||||||||||||||||||||
Total hydrocarbonsa | 2013 | |||||||||||||||||||||||||||||||||||||||||
Europe |
North America |
South America |
Africa |
Asia |
Australasia |
Total | ||||||||||||||||||||||||||||||||||||
UK | Rest of Europe |
USc | Rest of North America |
Russia | Rest of Asia |
|||||||||||||||||||||||||||||||||||||
Subsidiaries |
|
|||||||||||||||||||||||||||||||||||||||||
At 1 January 2013 |
||||||||||||||||||||||||||||||||||||||||||
Developed |
421 | 229 | 2,865 | 1 | 640 | 508 | | 427 | 618 | 5,709 | ||||||||||||||||||||||||||||||||
Undeveloped |
546 | 103 | 1,504 | 195 | 1,110 | 587 | | 209 | 445 | 4,699 | ||||||||||||||||||||||||||||||||
967 | 332 | 4,369 | 196 | 1,750 | 1,095 | | 636 | 1,063 | 10,408 | |||||||||||||||||||||||||||||||||
Changes attributable to |
||||||||||||||||||||||||||||||||||||||||||
Revisions of previous estimates |
(89 | ) | (27 | ) | (342 | ) | (5 | ) | 41 | 3 | | 435 | (36 | ) | (20 | ) | ||||||||||||||||||||||||||
Improved recovery |
20 | | 161 | | 25 | 7 | | 81 | | 294 | ||||||||||||||||||||||||||||||||
Purchases of reserves-in-place |
2 | | | | | | | | | 2 | ||||||||||||||||||||||||||||||||
Discoveries and extensions |
| | 10 | | | 9 | | 363 | 91 | 473 | ||||||||||||||||||||||||||||||||
Productiond e |
(34 | ) | (18 | ) | (241 | ) | (1 | ) | (152 | ) | (121 | ) | | (86 | ) | (59 | ) | (712 | ) | |||||||||||||||||||||||
Sales of reserves-in-place |
(152 | ) | | (38 | ) | | | | | (12 | ) | | (202 | ) | ||||||||||||||||||||||||||||
(253 | ) | (45 | ) | (450 | ) | (6 | ) | (86 | ) | (102 | ) | | 781 | (4 | ) | (165 | ) | |||||||||||||||||||||||||
At 31 December 2013f |
||||||||||||||||||||||||||||||||||||||||||
Developed |
280 | 225 | 2,525 | 2 | 564 | 486 | | 582 | 735 | 5,399 | ||||||||||||||||||||||||||||||||
Undeveloped |
434 | 62 | 1,394 | 188 | 1,100 | 507 | | 835 | 324 | 4,844 | ||||||||||||||||||||||||||||||||
714 | 287 | 3,919 | 190 | 1,664 | 993 | | 1,417 | 1,059 | 10,243 | |||||||||||||||||||||||||||||||||
Equity-accounted entities (BP share)g |
|
|||||||||||||||||||||||||||||||||||||||||
At 1 January 2013 |
||||||||||||||||||||||||||||||||||||||||||
Developed |
| | | | 559 | 43 | 2,943 | 220 | | 3,765 | ||||||||||||||||||||||||||||||||
Undeveloped |
| | | | 508 | 39 | 2,265 | 15 | | 2,827 | ||||||||||||||||||||||||||||||||
| | | | 1,067 | 82 | 5,208 | 235 | | 6,592 | |||||||||||||||||||||||||||||||||
Changes attributable to |
||||||||||||||||||||||||||||||||||||||||||
Revisions of previous estimates |
| | | 1 | (20 | ) | 2 | 502 | 1 | | 486 | |||||||||||||||||||||||||||||||
Improved recovery |
| | | | 38 | | | 1 | | 39 | ||||||||||||||||||||||||||||||||
Purchases of reserves-in-place |
| | | | 36 | | 6,108 | 6 | | 6,150 | ||||||||||||||||||||||||||||||||
Discoveries and extensions |
| | | | 20 | | 272 | | | 292 | ||||||||||||||||||||||||||||||||
Productione |
| | | | (55 | ) | (1 | ) | (353 | ) | (88 | ) | | (497 | ) | |||||||||||||||||||||||||||
Sales of reserves-in-place |
| | | | (92 | ) | | (5,204 | ) | (13 | ) | | (5,309 | ) | ||||||||||||||||||||||||||||
| | | 1 | (73 | ) | 1 | 1,325 | (93 | ) | | 1,161 | |||||||||||||||||||||||||||||||
At 31 December 2013h i |
||||||||||||||||||||||||||||||||||||||||||
Developed |
| | | | 552 | 50 | 3,782 | 133 | | 4,517 | ||||||||||||||||||||||||||||||||
Undeveloped |
| | | 1 | 442 | 33 | 2,751 | 9 | | 3,236 | ||||||||||||||||||||||||||||||||
| | | 1 | 994 | 83 | 6,533 | 142 | | 7,753 | |||||||||||||||||||||||||||||||||
Total subsidiaries and equity-accounted entities (BP share) |
|
|||||||||||||||||||||||||||||||||||||||||
At 1 January 2013 |
||||||||||||||||||||||||||||||||||||||||||
Developed |
421 | 229 | 2,865 | 1 | 1,199 | 551 | 2,943 | 647 | 618 | 9,474 | ||||||||||||||||||||||||||||||||
Undeveloped |
546 | 103 | 1,504 | 195 | 1,618 | 626 | 2,265 | 224 | 445 | 7,526 | ||||||||||||||||||||||||||||||||
967 | 332 | 4,369 | 196 | 2,817 | 1,177 | 5,208 | 871 | 1,063 | 17,000 | |||||||||||||||||||||||||||||||||
At 31 December 2013 |
||||||||||||||||||||||||||||||||||||||||||
Developed |
280 | 225 | 2,525 | 2 | 1,116 | 536 | 3,782 | 715 | 735 | 9,916 | ||||||||||||||||||||||||||||||||
Undeveloped |
434 | 62 | 1,394 | 189 | 1,542 | 540 | 2,751 | 844 | 324 | 8,080 | ||||||||||||||||||||||||||||||||
714 | 287 | 3,919 | 191 | 2,658 | 1,076 | 6,533 | 1,559 | 1,059 | 17,996 |
a | Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting and sales arrangements independently. |
b | 5.8 billion cubic feet of natural gas = 1 million barrels of oil equivalent. |
c | Proved reserves in the Prudhoe Bay field in Alaska include an estimated 72 million barrels of oil equivalent upon which a net profits royalty will be payable, over the life of the field under the terms of the BP Prudhoe Bay Royalty Trust. |
d | Excludes NGLs from processing plants in which an interest is held of 5,500 barrels of oil equivalent per day. |
e | Includes 31 million barrels of oil equivalent of natural gas consumed in operations, 26 million barrels of oil equivalent in subsidiaries, 5 million barrels of oil equivalent in equity-accounted entities. |
f | Includes 551 million barrels of NGLs. Also includes 484 million barrels of oil equivalent in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC. |
g | Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities. |
h | Includes 131 million barrels of NGLs. Also includes 30 million barrels of oil equivalent in respect of the non-controlling interest in Rosneft. |
i | Total proved reserves held as part of our equity interest in Rosneft is 6,574 million barrels of oil equivalent, comprising 1 million barrels of oil equivalent in Canada, 34 million barrels of oil equivalent in Venezuela, 5 million barrels of oil equivalent in Vietnam and 6,533 million barrels of oil equivalent in Russia. |
210 | BP Annual Report and Form 20-F 2013 |
Movements in estimated net proved reserves continued
million barrels | ||||||||||||||||||||||||||||||||||||||||||
Crude oila | 2012 | |||||||||||||||||||||||||||||||||||||||||
Europe |
North America |
South America |
Africa |
Asia |
Australasia |
Total |
||||||||||||||||||||||||||||||||||||
UK | Rest of Europe |
USb | Rest of North America |
Russia | Rest of Asia |
|||||||||||||||||||||||||||||||||||||
Subsidiaries |
| |||||||||||||||||||||||||||||||||||||||||
At 1 January 2012 |
||||||||||||||||||||||||||||||||||||||||||
Developed |
288 | 69 | 1,685 | | 27 | 311 | | 177 | 59 | 2,616 | ||||||||||||||||||||||||||||||||
Undeveloped |
445 | 230 | 1,173 | | 48 | 315 | | 279 | 47 | 2,537 | ||||||||||||||||||||||||||||||||
733 | 299 | 2,858 | | 75 | 626 | | 456 | 106 | 5,153 | |||||||||||||||||||||||||||||||||
Changes attributable to |
||||||||||||||||||||||||||||||||||||||||||
Revisions of previous estimates |
(30 | ) | (25 | ) | (280 | ) | | (11 | ) | (1 | ) | | (2 | ) | | (349 | ) | |||||||||||||||||||||||||
Improved recovery |
3 | | 140 | | | 13 | | 2 | | 158 | ||||||||||||||||||||||||||||||||
Purchases of reserves-in-place |
4 | | 21 | | | | | | | 25 | ||||||||||||||||||||||||||||||||
Discoveries and extensions |
| 1 | 23 | | | 2 | | | | 26 | ||||||||||||||||||||||||||||||||
Productionc |
(31 | ) | (8 | ) | (142 | ) | | (10 | ) | (73 | ) | | (51 | ) | (9 | ) | (324 | ) | ||||||||||||||||||||||||
Sales of reserves-in-place |
(6 | ) | (18 | ) | (188 | ) | | | | | | | (212 | ) | ||||||||||||||||||||||||||||
(60 | ) | (50 | ) | (426 | ) | | (21 | ) | (59 | ) | | (51 | ) | (9 | ) | (676 | ) | |||||||||||||||||||||||||
At 31 December 2012d h |
||||||||||||||||||||||||||||||||||||||||||
Developed |
242 | 170 | 1,443 | | 22 | 312 | | 268 | 52 | 2,509 | ||||||||||||||||||||||||||||||||
Undeveloped |
431 | 79 | 989 | | 32 | 255 | | 137 | 45 | 1,968 | ||||||||||||||||||||||||||||||||
673 | 249 | 2,432 | | 54 | 567 | | 405 | 97 | 4,477 | |||||||||||||||||||||||||||||||||
Equity-accounted entities (BP share)e |
| |||||||||||||||||||||||||||||||||||||||||
At 1 January 2012 |
||||||||||||||||||||||||||||||||||||||||||
Developed |
| | | | 349 | | 2,596 | 256 | | 3,201 | ||||||||||||||||||||||||||||||||
Undeveloped |
| | | | 348 | 14 | 1,613 | 58 | | 2,033 | ||||||||||||||||||||||||||||||||
| | | | 697 | 14 | 4,209 | 314 | | 5,234 | |||||||||||||||||||||||||||||||||
Changes attributable to |
||||||||||||||||||||||||||||||||||||||||||
Revisions of previous estimates |
| | | | (2 | ) | 9 | 462 | (23 | ) | | 446 | ||||||||||||||||||||||||||||||
Improved recovery |
| | | | 24 | | 47 | | | 71 | ||||||||||||||||||||||||||||||||
Purchases of reserves-in-place |
| | | | | | | | | | ||||||||||||||||||||||||||||||||
Discoveries and extensions |
| | | | | | 67 | | | 67 | ||||||||||||||||||||||||||||||||
Production |
| | | | (29 | ) | | (316 | ) | (80 | ) | | (425 | ) | ||||||||||||||||||||||||||||
Sales of reserves-in-place |
| | | | | | (15 | ) | | | (15 | ) | ||||||||||||||||||||||||||||||
| | | | (7 | ) | 9 | 245 | (103 | ) | | 144 | |||||||||||||||||||||||||||||||
At 31 December 2012f g i |
||||||||||||||||||||||||||||||||||||||||||
Developed |
| | | | 339 | 12 | 2,492 | 198 | | 3,041 | ||||||||||||||||||||||||||||||||
Undeveloped |
| | | | 351 | 11 | 1,962 | 13 | | 2,337 | ||||||||||||||||||||||||||||||||
| | | | 690 | 23 | 4,454 | 211 | | 5,378 | |||||||||||||||||||||||||||||||||
Total subsidiaries and equity-accounted entities (BP share) |
| |||||||||||||||||||||||||||||||||||||||||
At 1 January 2012 |
||||||||||||||||||||||||||||||||||||||||||
Developed |
288 | 69 | 1,685 | | 376 | 311 | 2,596 | 433 | 59 | 5,817 | ||||||||||||||||||||||||||||||||
Undeveloped |
445 | 230 | 1,173 | | 396 | 329 | 1,613 | 337 | 47 | 4,570 | ||||||||||||||||||||||||||||||||
733 | 299 | 2,858 | | 772 | 640 | 4,209 | 770 | 106 | 10,387 | |||||||||||||||||||||||||||||||||
At 31 December 2012 |
||||||||||||||||||||||||||||||||||||||||||
Developed |
242 | 170 | 1,443 | | 361 | 324 | 2,492 | 466 | 52 | 5,550 | ||||||||||||||||||||||||||||||||
Undeveloped |
431 | 79 | 989 | | 383 | 266 | 1,962 | 150 | 45 | 4,305 | ||||||||||||||||||||||||||||||||
673 | 249 | 2,432 | | 744 | 590 | 4,454 | 616 | 97 | 9,855 |
a | Crude oil includes NGLs and condensate. Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting and sales arrangements independently. |
b | Proved reserves in the Prudhoe Bay field in Alaska include an estimated 76 million barrels upon which a net profits royalty will be payable over the life of the field under the terms of the BP Prudhoe Bay Royalty Trust. |
c | Excludes NGLs from processing plants in which an interest is held of 13,500 barrels per day. |
d | Includes 591 million barrels of NGLs. Also includes 14 million barrels of crude oil in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC. |
e | Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities. |
f | Includes 103 million barrels of NGLs. Also includes 328 million barrels of crude oil in respect of the 7.35% non-controlling interest in TNK-BP. |
g | Total proved liquid reserves held as part of our equity interest in TNK-BP is 4,540 million barrels, comprising 87 million barrels in Venezuela and 4,454 million barrels in Russia. |
h | Includes assets held for sale of 39 million barrels. |
i | Includes assets held for sale of 4,540 million barrels. |
BP Annual Report and Form 20-F 2013 | 211 |
Movements in estimated net proved reserves continued
billion cubic feet |
||||||||||||||||||||||||||||||||||||||||||
Natural gasa | 2012 | |||||||||||||||||||||||||||||||||||||||||
Europe |
North America |
South
America |
Africa |
Asia |
Australasia |
Total | ||||||||||||||||||||||||||||||||||||
UK | Rest of Europe |
US | Rest of North America |
Russia | Rest of Asia |
|||||||||||||||||||||||||||||||||||||
Subsidiaries |
| |||||||||||||||||||||||||||||||||||||||||
At 1 January 2012 |
||||||||||||||||||||||||||||||||||||||||||
Developed |
1,411 | 43 | 9,721 | 28 | 2,869 | 1,224 | | 1,034 | 3,570 | 19,900 | ||||||||||||||||||||||||||||||||
Undeveloped |
909 | 450 | 3,831 | | 6,529 | 2,033 | | 364 | 2,365 | 16,481 | ||||||||||||||||||||||||||||||||
2,320 | 493 | 13,552 | 28 | 9,398 | 3,257 | | 1,398 | 5,935 | 36,381 | |||||||||||||||||||||||||||||||||
Changes attributable to |
||||||||||||||||||||||||||||||||||||||||||
Revisions of previous estimates |
(18 | ) | (13 | ) | (1,853 | ) | (19 | ) | (116 | ) | (14 | ) | | 38 | (41 | ) | (2,036 | ) | ||||||||||||||||||||||||
Improved recovery |
95 | | 885 | | 756 | 69 | | 156 | | 1,961 | ||||||||||||||||||||||||||||||||
Purchases of reserves-in-place |
17 | (1 | ) | 232 | | | | | | | 248 | |||||||||||||||||||||||||||||||
Discoveries and extensions |
| 7 | 225 | | 598 | 1 | | | | 831 | ||||||||||||||||||||||||||||||||
Productionb |
(164 | ) | (5 | ) | (661 | ) | (5 | ) | (775 | ) | (251 | ) | | (253 | ) | (289 | ) | (2,403 | ) | |||||||||||||||||||||||
Sales of reserves-in-place |
(546 | ) | | (1,149 | ) | | (23 | ) | | | | | (1,718 | ) | ||||||||||||||||||||||||||||
(616 | ) | (12 | ) | (2,321 | ) | (24 | ) | 440 | (195 | ) | | (59 | ) | (330 | ) | (3,117 | ) | |||||||||||||||||||||||||
At 31 December 2012c g |
||||||||||||||||||||||||||||||||||||||||||
Developed |
1,038 | 340 | 8,245 | 4 | 3,588 | 1,139 | | 926 | 3,282 | 18,562 | ||||||||||||||||||||||||||||||||
Undeveloped |
666 | 141 | 2,986 | | 6,250 | 1,923 | | 413 | 2,323 | 14,702 | ||||||||||||||||||||||||||||||||
1,704 | 481 | 11,231 | 4 | 9,838 | 3,062 | | 1,339 | 5,605 | 33,264 | |||||||||||||||||||||||||||||||||
Equity-accounted entities (BP share)d |
| |||||||||||||||||||||||||||||||||||||||||
At 1 January 2012 |
||||||||||||||||||||||||||||||||||||||||||
Developed |
| | | | 1,144 | | 2,119 | 104 | | 3,367 | ||||||||||||||||||||||||||||||||
Undeveloped |
| | | | 1,006 | 195 | 659 | 51 | | 1,911 | ||||||||||||||||||||||||||||||||
| | | | 2,150 | 195 | 2,778 | 155 | | 5,278 | |||||||||||||||||||||||||||||||||
Changes attributable to |
||||||||||||||||||||||||||||||||||||||||||
Revisions of previous estimates |
| | | | 86 | 144 | 569 | 25 | | 824 | ||||||||||||||||||||||||||||||||
Improved recovery |
| | | | 110 | | | 1 | | 111 | ||||||||||||||||||||||||||||||||
Purchases of reserves-in-place |
| | | | | | | | | | ||||||||||||||||||||||||||||||||
Discoveries and extensions |
| | | | 3 | | 1,310 | | | 1,313 | ||||||||||||||||||||||||||||||||
Productionb |
| | | | (169 | ) | | (280 | ) | (35 | ) | | (484 | ) | ||||||||||||||||||||||||||||
Sales of reserves-in-place |
| | | | | | (1 | ) | | | (1 | ) | ||||||||||||||||||||||||||||||
| | | | 30 | 144 | 1,598 | (9 | ) | | 1,763 | ||||||||||||||||||||||||||||||||
At 31 December 2012e f h |
||||||||||||||||||||||||||||||||||||||||||
Developed |
| | | | 1,276 | 175 | 2,617 | 128 | | 4,196 | ||||||||||||||||||||||||||||||||
Undeveloped |
| | | | 904 | 164 | 1,759 | 18 | | 2,845 | ||||||||||||||||||||||||||||||||
| | | | 2,180 | 339 | 4,376 | 146 | | 7,041 | |||||||||||||||||||||||||||||||||
Total subsidiaries and equity-accounted entities (BP share) |
| |||||||||||||||||||||||||||||||||||||||||
At 1 January 2012 |
||||||||||||||||||||||||||||||||||||||||||
Developed |
1,411 | 43 | 9,721 | 28 | 4,013 | 1,224 | 2,119 | 1,138 | 3,570 | 23,267 | ||||||||||||||||||||||||||||||||
Undeveloped |
909 | 450 | 3,831 | | 7,535 | 2,228 | 659 | 415 | 2,365 | 18,392 | ||||||||||||||||||||||||||||||||
2,320 | 493 | 13,552 | 28 | 11,548 | 3,452 | 2,778 | 1,553 | 5,935 | 41,659 | |||||||||||||||||||||||||||||||||
At 31 December 2012 |
||||||||||||||||||||||||||||||||||||||||||
Developed |
1,038 | 340 | 8,245 | 4 | 4,864 | 1,314 | 2,617 | 1,054 | 3,282 | 22,758 | ||||||||||||||||||||||||||||||||
Undeveloped |
666 | 141 | 2,986 | | 7,154 | 2,087 | 1,759 | 431 | 2,323 | 17,547 | ||||||||||||||||||||||||||||||||
1,704 | 481 | 11,231 | 4 | 12,018 | 3,401 | 4,376 | 1,485 | 5,605 | 40,305 |
a | Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting and sales arrangements independently. |
b | Includes 190 billion cubic feet of natural gas consumed in operations, 145 billion cubic feet in subsidiaries, 45 billion cubic feet in equity-accounted entities and excludes 9 billion cubic feet of produced non-hydrocarbon components that meet regulatory requirements for sales. |
c | Includes 2,890 billion cubic feet of natural gas in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC. |
d | Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities. |
e | Includes 270 billion cubic feet of natural gas in respect of the 6.17% non-controlling interest in TNK-BP. |
f | Total proved gas reserves held as part of our equity interest in TNK-BP is 4,492 billion cubic feet, comprising 38 billion cubic feet in Venezuela, 78 billion cubic feet in Vietnam and 4,376 billion cubic feet in Russia. |
g | Includes assets held for sale of 590 billion cubic feet. |
h | Includes assets held for sale of 4,492 billion cubic feet. |
212 | BP Annual Report and Form 20-F 2013 |
Movements in estimated net proved reserves continued
million barrels | ||||||||||
Bitumena | 2012 | |||||||||
|
Rest of North America |
|
Total | |||||||
Subsidiaries |
||||||||||
At 1 January 2012 |
||||||||||
Developed |
| | ||||||||
Undeveloped |
178 | 178 | ||||||||
178 | 178 | |||||||||
Changes attributable to |
||||||||||
Revisions of previous estimates |
17 | 17 | ||||||||
Improved recovery |
| | ||||||||
Purchases of reserves-in-place |
| | ||||||||
Discoveries and extensions |
| | ||||||||
Production |
| | ||||||||
Sales of reserves-in-place |
| | ||||||||
17 | 17 | |||||||||
At 31 December 2012 |
||||||||||
Developed |
| | ||||||||
Undeveloped |
195 | 195 | ||||||||
195 | 195 |
a | Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting and sales arrangements independently. |
BP Annual Report and Form 20-F 2013 | 213 |
Movements in estimated net proved reserves continued
million barrels of oil equivalentb | ||||||||||||||||||||||||||||||||||||||||||
Total hydrocarbonsa | 2012 | |||||||||||||||||||||||||||||||||||||||||
Europe |
North America |
South
America |
Africa |
Asia | Australasia | Total | ||||||||||||||||||||||||||||||||||||
UK | Rest of Europe |
USc | Rest of North America |
Russia | Rest of Asia |
|||||||||||||||||||||||||||||||||||||
Subsidiaries |
| |||||||||||||||||||||||||||||||||||||||||
At 1 January 2012 |
||||||||||||||||||||||||||||||||||||||||||
Developed |
531 | 76 | 3,362 | 5 | 522 | 522 | | 355 | 675 | 6,048 | ||||||||||||||||||||||||||||||||
Undeveloped |
602 | 308 | 1,833 | 178 | 1,173 | 665 | | 342 | 455 | 5,556 | ||||||||||||||||||||||||||||||||
1,133 | 384 | 5,195 | 183 | 1,695 | 1,187 | | 697 | 1,130 | 11,604 | |||||||||||||||||||||||||||||||||
Changes attributable to |
||||||||||||||||||||||||||||||||||||||||||
Revisions of previous estimates |
(33 | ) | (27 | ) | (600 | ) | 14 | (31 | ) | (3 | ) | | 5 | (8 | ) | (683 | ) | |||||||||||||||||||||||||
Improved recovery |
19 | | 293 | | 130 | 25 | | 29 | | 496 | ||||||||||||||||||||||||||||||||
Purchases of reserves-in-place |
7 | | 61 | | | | | | | 68 | ||||||||||||||||||||||||||||||||
Discoveries and extensions |
| 2 | 62 | | 103 | 2 | | | | 169 | ||||||||||||||||||||||||||||||||
Productiond e |
(59 | ) | (9 | ) | (256 | ) | (1 | ) | (143 | ) | (116 | ) | | (95 | ) | (59 | ) | (738 | ) | |||||||||||||||||||||||
Sales of reserves-in-place |
(100 | ) | (18 | ) | (386 | ) | | (4 | ) | | | | | (508 | ) | |||||||||||||||||||||||||||
(166 | ) | (52 | ) | (826 | ) | 13 | 55 | (92 | ) | | (61 | ) | (67 | ) | (1,196 | ) | ||||||||||||||||||||||||||
At 31 December 2012f j |
||||||||||||||||||||||||||||||||||||||||||
Developed |
421 | 229 | 2,865 | 1 | 640 | 508 | | 427 | 618 | 5,709 | ||||||||||||||||||||||||||||||||
Undeveloped |
546 | 103 | 1,504 | 195 | 1,110 | 587 | | 209 | 445 | 4,699 | ||||||||||||||||||||||||||||||||
967 | 332 | 4,369 | 196 | 1,750 | 1,095 | | 636 | 1,063 | 10,408 | |||||||||||||||||||||||||||||||||
Equity-accounted entities (BP share)g |
| |||||||||||||||||||||||||||||||||||||||||
At 1 January 2012 |
||||||||||||||||||||||||||||||||||||||||||
Developed |
| | | | 546 | | 2,961 | 274 | | 3,781 | ||||||||||||||||||||||||||||||||
Undeveloped |
| | | | 522 | 48 | 1,727 | 66 | | 2,363 | ||||||||||||||||||||||||||||||||
| | | | 1,068 | 48 | 4,688 | 340 | | 6,144 | |||||||||||||||||||||||||||||||||
Changes attributable to |
||||||||||||||||||||||||||||||||||||||||||
Revisions of previous estimates |
| | | | 13 | 34 | 560 | (19 | ) | | 588 | |||||||||||||||||||||||||||||||
Improved recovery |
| | | | 43 | | 47 | | | 90 | ||||||||||||||||||||||||||||||||
Purchases of reserves-in-place |
| | | | | | | | | | ||||||||||||||||||||||||||||||||
Discoveries and extensions |
| | | | 1 | | 292 | | | 293 | ||||||||||||||||||||||||||||||||
Productiond e |
| | | | (58 | ) | | (364 | ) | (86 | ) | | (508 | ) | ||||||||||||||||||||||||||||
Sales of reserves-in-place |
| | | | | | (15 | ) | | | (15 | ) | ||||||||||||||||||||||||||||||
| | | | (1 | ) | 34 | 520 | (105 | ) | | 448 | |||||||||||||||||||||||||||||||
At 31 December 2012h i k |
||||||||||||||||||||||||||||||||||||||||||
Developed |
| | | | 559 | 43 | 2,943 | 220 | | 3,765 | ||||||||||||||||||||||||||||||||
Undeveloped |
| | | | 508 | 39 | 2,265 | 15 | | 2,827 | ||||||||||||||||||||||||||||||||
| | | | 1,067 | 82 | 5,208 | 235 | | 6,592 | |||||||||||||||||||||||||||||||||
Total subsidiaries and equity-accounted entities (BP share) |
| |||||||||||||||||||||||||||||||||||||||||
At 1 January 2012 |
||||||||||||||||||||||||||||||||||||||||||
Developed |
531 | 76 | 3,362 | 5 | 1,068 | 522 | 2,961 | 629 | 675 | 9,829 | ||||||||||||||||||||||||||||||||
Undeveloped |
602 | 308 | 1,833 | 178 | 1,695 | 713 | 1,727 | 408 | 455 | 7,919 | ||||||||||||||||||||||||||||||||
1,133 | 384 | 5,195 | 183 | 2,763 | 1,235 | 4,688 | 1,037 | 1,130 | 17,748 | |||||||||||||||||||||||||||||||||
At 31 December 2012 |
||||||||||||||||||||||||||||||||||||||||||
Developed |
421 | 229 | 2,865 | 1 | 1,199 | 551 | 2,943 | 647 | 618 | 9,474 | ||||||||||||||||||||||||||||||||
Undeveloped |
546 | 103 | 1,504 | 195 | 1,618 | 626 | 2,265 | 224 | 445 | 7,526 | ||||||||||||||||||||||||||||||||
967 | 332 | 4,369 | 196 | 2,817 | 1,177 | 5,208 | 871 | 1,063 | 17,000 |
a | Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting and sales arrangements independently. |
b | 5.8 billion cubic feet of natural gas = 1 million barrels of oil equivalent. |
c | Proved reserves in the Prudhoe Bay field in Alaska include an estimated 76 million barrels of oil equivalent upon which a net profits royalty will be payable, over the life of the field under the terms of the BP Prudhoe Bay Royalty Trust. |
d | Excludes NGLs from processing plants in which an interest is held of 13,500 barrels of oil equivalent per day. |
e | Includes 33 million barrels of oil equivalent of natural gas consumed in operations, 25 million barrels of oil equivalent in subsidiaries, 8 million barrels of oil equivalent in equity-accounted entities and excludes 2 million barrels of oil equivalent of produced non-hydrocarbon components that meet regulatory requirements for sales. |
f | Includes 591 million barrels of NGLs. Also includes 512 million barrels of oil equivalent in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC. |
g | Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities. |
h | Includes 103 million barrels of NGLs. Also includes 374 million barrels of oil equivalent in respect of the non-controlling interest in TNK-BP. |
i | Total proved reserves held as part of our equity interest in TNK-BP is 5,315 million barrels of oil equivalent, comprising 93 million barrels of oil equivalent in Venezuela, 14 million barrels of oil equivalent in Vietnam and 5,208 million barrels of oil equivalent in Russia. |
j | Includes assets held for sale of 140 million barrels of oil equivalent. |
k | Includes assets held for sale of 5,315 million barrels of oil equivalent. |
214 | BP Annual Report and Form 20-F 2013 |
Movements in estimated net proved reserves continued
million barrels | ||||||||||||||||||||||||||||||||||||||||||
Crude oila | 2011 | |||||||||||||||||||||||||||||||||||||||||
Europe |
North America |
South America |
Africa |
Asia | Australasia | Total | ||||||||||||||||||||||||||||||||||||
UK | Rest of Europe |
USb | Rest of North America |
Russia | Rest of Asia |
|||||||||||||||||||||||||||||||||||||
Subsidiaries |
| |||||||||||||||||||||||||||||||||||||||||
At 1 January 2011 |
||||||||||||||||||||||||||||||||||||||||||
Developed |
364 | 77 | 1,729 | | 44 | 371 | | 269 | 48 | 2,902 | ||||||||||||||||||||||||||||||||
Undeveloped |
431 | 221 | 1,190 | | 58 | 374 | | 325 | 58 | 2,657 | ||||||||||||||||||||||||||||||||
795 | 298 | 2,919 | | 102 | 745 | | 594 | 106 | 5,559 | |||||||||||||||||||||||||||||||||
Changes attributable to |
||||||||||||||||||||||||||||||||||||||||||
Revisions of previous estimates |
(1 | ) | 5 | 27 | | 6 | (68 | ) | | (131 | ) | 3 | (159 | ) | ||||||||||||||||||||||||||||
Improved recovery |
14 | 8 | 97 | | 1 | 10 | | 70 | 6 | 206 | ||||||||||||||||||||||||||||||||
Purchases of reserves-in-place |
| | 10 | | 7 | | | 4 | | 21 | ||||||||||||||||||||||||||||||||
Discoveries and extensions |
| | 1 | | 1 | 19 | | | | 21 | ||||||||||||||||||||||||||||||||
Productionc |
(41 | ) | (12 | ) | (162 | ) | | (13 | ) | (68 | ) | | (50 | ) | (9 | ) | (355 | ) | ||||||||||||||||||||||||
Sales of reserves-in-place |
(34 | ) | | (34 | ) | | (29 | ) | (12 | ) | | (31 | ) | | (140 | ) | ||||||||||||||||||||||||||
(62 | ) | 1 | (61 | ) | | (27 | ) | (119 | ) | | (138 | ) | | (406 | ) | |||||||||||||||||||||||||||
At 31 December 2011d |
||||||||||||||||||||||||||||||||||||||||||
Developed |
288 | 69 | 1,685 | | 27 | 311 | | 177 | 59 | 2,616 | ||||||||||||||||||||||||||||||||
Undeveloped |
445 | 230 | 1,173 | | 48 | 315 | | 279 | 47 | 2,537 | ||||||||||||||||||||||||||||||||
733 | 299 | 2,858 | | 75 | 626 | | 456 | 106 | 5,153 | |||||||||||||||||||||||||||||||||
Equity-accounted entities (BP share)e |
| |||||||||||||||||||||||||||||||||||||||||
At 1 January 2011 |
||||||||||||||||||||||||||||||||||||||||||
Developed |
| | | | 408 | | 2,388 | 370 | | 3,166 | ||||||||||||||||||||||||||||||||
Undeveloped |
| | | | 407 | 12 | 1,362 | 24 | | 1,805 | ||||||||||||||||||||||||||||||||
| | | | 815 | 12 | 3,750 | 394 | | 4,971 | |||||||||||||||||||||||||||||||||
Changes attributable to |
||||||||||||||||||||||||||||||||||||||||||
Revisions of previous estimates |
| | | | (12 | ) | 2 | 677 | (5 | ) | | 662 | ||||||||||||||||||||||||||||||
Improved recovery |
| | | | 70 | | 73 | | | 143 | ||||||||||||||||||||||||||||||||
Purchases of reserves-in-place |
| | | | 98 | | | 1 | | 99 | ||||||||||||||||||||||||||||||||
Discoveries and extensions |
| | | | | | 25 | | | 25 | ||||||||||||||||||||||||||||||||
Production |
| | | | (30 | ) | | (316 | ) | (76 | ) | | (422 | ) | ||||||||||||||||||||||||||||
Sales of reserves-in-place |
| | | | (244 | ) | | | | | (244 | ) | ||||||||||||||||||||||||||||||
| | | | (118 | ) | 2 | 459 | (80 | ) | | 263 | |||||||||||||||||||||||||||||||
At 31 December 2011f g |
||||||||||||||||||||||||||||||||||||||||||
Developed |
| | | | 349 | | 2,596 | 256 | | 3,201 | ||||||||||||||||||||||||||||||||
Undeveloped |
| | | | 348 | 14 | 1,613 | 58 | | 2,033 | ||||||||||||||||||||||||||||||||
| | | | 697 | 14 | 4,209 | 314 | | 5,234 | |||||||||||||||||||||||||||||||||
Total subsidiaries and equity-accounted entities (BP share) |
| |||||||||||||||||||||||||||||||||||||||||
At 1 January 2011 |
||||||||||||||||||||||||||||||||||||||||||
Developed |
364 | 77 | 1,729 | | 452 | 371 | 2,388 | 639 | 48 | 6,068 | ||||||||||||||||||||||||||||||||
Undeveloped |
431 | 221 | 1,190 | | 465 | 386 | 1,362 | 349 | 58 | 4,462 | ||||||||||||||||||||||||||||||||
795 | 298 | 2,919 | | 917 | 757 | 3,750 | 988 | 106 | 10,530 | |||||||||||||||||||||||||||||||||
At 31 December 2011 |
||||||||||||||||||||||||||||||||||||||||||
Developed |
288 | 69 | 1,685 | | 376 | 311 | 2,596 | 433 | 59 | 5,817 | ||||||||||||||||||||||||||||||||
Undeveloped |
445 | 230 | 1,173 | | 396 | 329 | 1,613 | 337 | 47 | 4,570 | ||||||||||||||||||||||||||||||||
733 | 299 | 2,858 | | 772 | 640 | 4,209 | 770 | 106 | 10,387 |
a | Crude oil includes NGLs and condensate. Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting and sales arrangements independently. |
b | Proved reserves in the Prudhoe Bay field in Alaska include an estimated 82 million barrels upon which a net profits royalty will be payable over the life of the field under the terms of the BP Prudhoe Bay Royalty Trust. |
c | Excludes NGLs from processing plants in which an interest is held of 28 thousand barrels per day. |
d | Includes 616 million barrels of NGLs. Also includes 20 million barrels of crude oil in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC. |
e | Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities. |
f | Includes 19 million barrels of NGLs. Also includes 310 million barrels of crude oil in respect of the 7.37% non-controlling interest in TNK-BP. |
g | Total proved liquid reserves held as part of our equity interest in TNK-BP is 4,305 million barrels, comprising 95 million barrels in Venezuela, one million barrels in Vietnam and 4,209 million barrels in Russia. In 2011, BP aligned its reporting with TNK-BP by moving to a life of field reporting basis. Reasonable certainty of licence renewals is demonstrated by evidence of Russian subsoil law, track record of renewals within the industry and track record of success in obtaining renewals by TNK-BP. This has resulted in an increase in proved liquid reserves of 221 million barrels. |
BP Annual Report and Form 20-F 2013 | 215 |
Movements in estimated net proved reserves continued
billion cubic feet |
||||||||||||||||||||||||||||||||||||||||||
Natural gasa |
2011 | |||||||||||||||||||||||||||||||||||||||||
Europe |
North America |
South America |
Africa |
Asia | Australasia | Total | ||||||||||||||||||||||||||||||||||||
UK | Rest of Europe |
US |
Rest of North America |
Russia | Rest of Asia |
|||||||||||||||||||||||||||||||||||||
Subsidiaries |
| |||||||||||||||||||||||||||||||||||||||||
At 1 January 2011 |
||||||||||||||||||||||||||||||||||||||||||
Developed |
1,416 | 40 | 9,495 | 58 | 3,575 | 1,329 | | 1,290 | 3,563 | 20,766 | ||||||||||||||||||||||||||||||||
Undeveloped |
829 | 430 | 4,248 | | 6,575 | 2,351 | | 268 | 2,342 | 17,043 | ||||||||||||||||||||||||||||||||
2,245 | 470 | 13,743 | 58 | 10,150 | 3,680 | | 1,558 | 5,905 | 37,809 | |||||||||||||||||||||||||||||||||
Changes attributable to |
||||||||||||||||||||||||||||||||||||||||||
Revisions of previous estimates |
169 | 30 | | (9 | ) | 202 | (206 | ) | | 69 | 299 | 554 | ||||||||||||||||||||||||||||||
Improved recovery |
56 | 1 | 597 | | 84 | 15 | | 28 | 22 | 803 | ||||||||||||||||||||||||||||||||
Purchases of reserves-in-place |
8 | | 93 | 7 | | | | 310 | | 418 | ||||||||||||||||||||||||||||||||
Discoveries and extensions |
| | 219 | | 47 | | | | | 266 | ||||||||||||||||||||||||||||||||
Productionb |
(146 | ) | (8 | ) | (737 | ) | (5 | ) | (811 | ) | (232 | ) | | (244 | ) | (291 | ) | (2,474 | ) | |||||||||||||||||||||||
Sales of reserves-in-place |
(12 | ) | | (363 | ) | (23 | ) | (274 | ) | | | (323 | ) | | (995 | ) | ||||||||||||||||||||||||||
75 | 23 | (191 | ) | (30 | ) | (752 | ) | (423 | ) | | (160 | ) | 30 | (1,428 | ) | |||||||||||||||||||||||||||
At 31 December 2011c |
||||||||||||||||||||||||||||||||||||||||||
Developed |
1,411 | 43 | 9,721 | 28 | 2,869 | 1,224 | | 1,034 | 3,570 | 19,900 | ||||||||||||||||||||||||||||||||
Undeveloped |
909 | 450 | 3,831 | | 6,529 | 2,033 | | 364 | 2,365 | 16,481 | ||||||||||||||||||||||||||||||||
2,320 | 493 | 13,552 | 28 | 9,398 | 3,257 | | 1,398 | 5,935 | 36,381 | |||||||||||||||||||||||||||||||||
Equity-accounted entities (BP share)d |
| |||||||||||||||||||||||||||||||||||||||||
At 1 January 2011 |
||||||||||||||||||||||||||||||||||||||||||
Developed |
| | | | 1,075 | | 1,900 | 71 | | 3,046 | ||||||||||||||||||||||||||||||||
Undeveloped |
| | | | 1,192 | 175 | 459 | 19 | | 1,845 | ||||||||||||||||||||||||||||||||
| | | | 2,267 | 175 | 2,359 | 90 | | 4,891 | |||||||||||||||||||||||||||||||||
Changes attributable to |
||||||||||||||||||||||||||||||||||||||||||
Revisions of previous estimates |
| | | | (75 | ) | 20 | 683 | (3 | ) | | 625 | ||||||||||||||||||||||||||||||
Improved recovery |
| | | | 190 | | | 12 | | 202 | ||||||||||||||||||||||||||||||||
Purchases of reserves-in-place |
| | | | 31 | | | 76 | | 107 | ||||||||||||||||||||||||||||||||
Discoveries and extensions |
| | | | | | | | | | ||||||||||||||||||||||||||||||||
Productionb |
| | | | (167 | ) | | (264 | ) | (20 | ) | | (451 | ) | ||||||||||||||||||||||||||||
Sales of reserves-in-place |
| | | | (96 | ) | | | | | (96 | ) | ||||||||||||||||||||||||||||||
| | | | (117 | ) | 20 | 419 | 65 | | 387 | ||||||||||||||||||||||||||||||||
At 31 December 2011e f |
||||||||||||||||||||||||||||||||||||||||||
Developed |
| | | | 1,144 | | 2,119 | 104 | | 3,367 | ||||||||||||||||||||||||||||||||
Undeveloped |
| | | | 1,006 | 195 | 659 | 51 | | 1,911 | ||||||||||||||||||||||||||||||||
| | | | 2,150 | 195 | 2,778 | 155 | | 5,278 | |||||||||||||||||||||||||||||||||
Total subsidiaries and equity-accounted entities (BP share) |
| |||||||||||||||||||||||||||||||||||||||||
At 1 January 2011 |
||||||||||||||||||||||||||||||||||||||||||
Developed |
1,416 | 40 | 9,495 | 58 | 4,650 | 1,329 | 1,900 | 1,361 | 3,563 | 23,812 | ||||||||||||||||||||||||||||||||
Undeveloped |
829 | 430 | 4,248 | | 7,767 | 2,526 | 459 | 287 | 2,342 | 18,888 | ||||||||||||||||||||||||||||||||
2,245 | 470 | 13,743 | 58 | 12,417 | 3,855 | 2,359 | 1,648 | 5,905 | 42,700 | |||||||||||||||||||||||||||||||||
At 31 December 2011 |
||||||||||||||||||||||||||||||||||||||||||
Developed |
1,411 | 43 | 9,721 | 28 | 4,013 | 1,224 | 2,119 | 1,138 | 3,570 | 23,267 | ||||||||||||||||||||||||||||||||
Undeveloped |
909 | 450 | 3,831 | | 7,535 | 2,228 | 659 | 415 | 2,365 | 18,392 | ||||||||||||||||||||||||||||||||
2,320 | 493 | 13,552 | 28 | 11,548 | 3,452 | 2,778 | 1,553 | 5,935 | 41,659 |
a | Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting and sales arrangements independently. |
b | Includes 196 billion cubic feet of natural gas consumed in operations,155 billion cubic feet in subsidiaries, 41 billion cubic feet in equity-accounted entities and excludes 14 billion cubic feet of produced non-hydrocarbon components which meet regulatory requirements for sales. |
c | Includes 2,759 billion cubic feet of natural gas in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC. |
d | Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities. |
e | Includes 174 billion cubic feet of natural gas in respect of the 6.27% non-controlling interest in TNK-BP. |
f | Total proved gas reserves held as part of our equity interest in TNK-BP is 2,881 billion cubic feet, comprising 30 billion cubic feet in Venezuela, 73 billion cubic feet in Vietnam and 2,778 billion cubic feet in Russia. In 2011, BP aligned its reporting with TNK-BP by moving to a life of field reporting basis. Reasonable certainty of licence renewals is demonstrated by evidence of Russian subsoil law, track record of renewals within the industry and track record of success in obtaining renewals by TNK-BP. This has resulted in an increase in proved gas reserves of 185 billion cubic feet. |
216 | BP Annual Report and Form 20-F 2013 |
Movements in estimated net proved reserves continued
million barrels | ||||||||||
Bitumena | 2011 | |||||||||
|
Rest of North America |
|
Total | |||||||
Subsidiaries |
||||||||||
At 1 January 2011 |
||||||||||
Developed |
| | ||||||||
Undeveloped |
179 | 179 | ||||||||
179 | 179 | |||||||||
Changes attributable to |
||||||||||
Revisions of previous estimates |
(1 | ) | (1 | ) | ||||||
Improved recovery |
| | ||||||||
Purchases of reserves-in-place |
| | ||||||||
Discoveries and extensions |
| | ||||||||
Production |
| | ||||||||
Sales of reserves-in-place |
| | ||||||||
(1 | ) | (1 | ) | |||||||
At 31 December 2011 |
||||||||||
Developed |
| | ||||||||
Undeveloped |
178 | 178 | ||||||||
178 | 178 |
a | Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting and sales arrangements independently. |
BP Annual Report and Form 20-F 2013 | 217 |
Movements in estimated net proved reserves continued
million barrels of oil equivalentb | ||||||||||||||||||||||||||||||||||||||||||
Total hydrocarbonsa | 2011 | |||||||||||||||||||||||||||||||||||||||||
Europe |
North America |
South America |
Africa |
Asia | Australasia | Total | ||||||||||||||||||||||||||||||||||||
UK | Rest of Europe |
USc | Rest of North America |
Russia | Rest of Asia |
|||||||||||||||||||||||||||||||||||||
Subsidiaries |
||||||||||||||||||||||||||||||||||||||||||
At 1 January 2011 |
||||||||||||||||||||||||||||||||||||||||||
Developed |
608 | 84 | 3,366 | 10 | 660 | 600 | | 491 | 662 | 6,481 | ||||||||||||||||||||||||||||||||
Undeveloped |
574 | 295 | 1,923 | 179 | 1,192 | 779 | | 371 | 462 | 5,775 | ||||||||||||||||||||||||||||||||
1,182 | 379 | 5,289 | 189 | 1,852 | 1,379 | | 862 | 1,124 | 12,256 | |||||||||||||||||||||||||||||||||
Changes attributable to |
||||||||||||||||||||||||||||||||||||||||||
Revisions of previous estimates |
28 | 10 | 27 | (3 | ) | 41 | (103 | ) | | (119 | ) | 55 | (64 | ) | ||||||||||||||||||||||||||||
Improved recovery |
24 | 8 | 200 | | 15 | 12 | | 75 | 10 | 344 | ||||||||||||||||||||||||||||||||
Purchases of reserves-in-place |
1 | | 26 | 2 | 7 | | | 58 | | 94 | ||||||||||||||||||||||||||||||||
Discoveries and extensions |
| | 39 | | 9 | 19 | | | | 67 | ||||||||||||||||||||||||||||||||
Productiond e |
(66 | ) | (13 | ) | (289 | ) | (1 | ) | (153 | ) | (108 | ) | | (92 | ) | (59 | ) | (781 | ) | |||||||||||||||||||||||
Sales of reserves-in-place |
(36 | ) | | (97 | ) | (4 | ) | (76 | ) | (12 | ) | | (87 | ) | | (312 | ) | |||||||||||||||||||||||||
(49 | ) | 5 | (94 | ) | (6 | ) | (157 | ) | (192 | ) | | (165 | ) | 6 | (652 | ) | ||||||||||||||||||||||||||
At 31 December 2011f |
||||||||||||||||||||||||||||||||||||||||||
Developed |
531 | 76 | 3,362 | 5 | 522 | 522 | | 355 | 675 | 6,048 | ||||||||||||||||||||||||||||||||
Undeveloped |
602 | 308 | 1,833 | 178 | 1,173 | 665 | | 342 | 455 | 5,556 | ||||||||||||||||||||||||||||||||
1,133 | 384 | 5,195 | 183 | 1,695 | 1,187 | | 697 | 1,130 | 11,604 | |||||||||||||||||||||||||||||||||
Equity-accounted entities (BP share)g |
|
|||||||||||||||||||||||||||||||||||||||||
At 1 January 2011 |
||||||||||||||||||||||||||||||||||||||||||
Developed |
| | | | 593 | | 2,716 | 382 | | 3,691 | ||||||||||||||||||||||||||||||||
Undeveloped |
| | | | 613 | 43 | 1,441 | 27 | | 2,124 | ||||||||||||||||||||||||||||||||
| | | | 1,206 | 43 | 4,157 | 409 | | 5,815 | |||||||||||||||||||||||||||||||||
Changes attributable to |
||||||||||||||||||||||||||||||||||||||||||
Revisions of previous estimates |
| | | | (25 | ) | 5 | 795 | (5 | ) | | 770 | ||||||||||||||||||||||||||||||
Improved recovery |
| | | | 103 | | 73 | 2 | | 178 | ||||||||||||||||||||||||||||||||
Purchases of reserves-in-place |
| | | | 103 | | | 14 | | 117 | ||||||||||||||||||||||||||||||||
Discoveries and extensions |
| | | | | | 25 | | | 25 | ||||||||||||||||||||||||||||||||
Productiond e |
| | | | (59 | ) | | (362 | ) | (80 | ) | | (501 | ) | ||||||||||||||||||||||||||||
Sales of reserves-in-place |
| | | | (260 | ) | | | | | (260 | ) | ||||||||||||||||||||||||||||||
| | | | (138 | ) | 5 | 531 | (69 | ) | | 329 | |||||||||||||||||||||||||||||||
At 31 December 2011h i |
||||||||||||||||||||||||||||||||||||||||||
Developed |
| | | | 546 | | 2,961 | 274 | | 3,781 | ||||||||||||||||||||||||||||||||
Undeveloped |
| | | | 522 | 48 | 1,727 | 66 | | 2,363 | ||||||||||||||||||||||||||||||||
| | | | 1,068 | 48 | 4,688 | 340 | | 6,144 | |||||||||||||||||||||||||||||||||
Total subsidiaries and equity-accounted entities (BP share) |
|
|||||||||||||||||||||||||||||||||||||||||
At 1 January 2011 |
||||||||||||||||||||||||||||||||||||||||||
Developed |
608 | 84 | 3,366 | 10 | 1,253 | 600 | 2,716 | 873 | 662 | 10,172 | ||||||||||||||||||||||||||||||||
Undeveloped |
574 | 295 | 1,923 | 179 | 1,805 | 822 | 1,441 | 398 | 462 | 7,899 | ||||||||||||||||||||||||||||||||
1,182 | 379 | 5,289 | 189 | 3,058 | 1,422 | 4,157 | 1,271 | 1,124 | 18,071 | |||||||||||||||||||||||||||||||||
At 31 December 2011 |
||||||||||||||||||||||||||||||||||||||||||
Developed |
531 | 76 | 3,362 | 5 | 1,068 | 522 | 2,961 | 629 | 675 | 9,829 | ||||||||||||||||||||||||||||||||
Undeveloped |
602 | 308 | 1,833 | 178 | 1,695 | 713 | 1,727 | 408 | 455 | 7,919 | ||||||||||||||||||||||||||||||||
1,133 | 384 | 5,195 | 183 | 2,763 | 1,235 | 4,688 | 1,037 | 1,130 | 17,748 |
a | Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting and sales arrangements independently. |
b | 5.8 billion cubic feet of natural gas = 1 million barrels of oil equivalent. |
c | Proved reserves in the Prudhoe Bay field in Alaska include an estimated 82 million barrels of oil equivalent upon which a net profits royalty will be payable over the life of the field under the terms of the BP Prudhoe Bay Royalty Trust. |
d | Excludes NGLs from processing plants in which an interest is held of 28 thousand barrels of oil equivalent a day. |
e | Includes 34 million barrels of oil equivalent of natural gas consumed in operations, 27 million barrels of oil equivalent in subsidiaries, seven million barrels of oil equivalent in equity-accounted entities and excludes two million barrels of oil equivalent of produced non-hydrocarbon components which meet regulatory requirements for sales. |
f | Includes 616 million barrels of NGLs. Also includes 496 million barrels of oil equivalent in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC. |
g | Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities. |
h | Includes 19 million barrels of NGLs. Also includes 340 million barrels of oil equivalent in respect of the non-controlling interest in TNK-BP. |
i | Total proved reserves held as part of our equity interest in TNK-BP is 4,802 million barrels of oil equivalent, comprising 100 million barrels of oil equivalent in Venezuela, 14 million barrels of oil equivalent in Vietnam and 4,688 million barrels of oil equivalent in Russia. In 2011, BP aligned its reporting with TNK-BP by moving to a life of field reporting basis. Reasonable certainty of licence renewals is demonstrated by evidence of Russian subsoil law, track record of renewals within the industry and track record of success in obtaining renewals by TNK-BP. This has resulted in an increase in proved reserves of 253 million barrels of oil equivalent. |
218 | BP Annual Report and Form 20-F 2013 |
Standardized measure of discounted future net cash flows and changes therein relating to proved oil and gas reserves
The following tables set out the standardized measure of discounted future net cash flows, and changes therein, relating to crude oil and natural gas production from the groups estimated proved reserves. This information is prepared in compliance with FASB Oil and Gas Disclosures requirements.
Future net cash flows have been prepared on the basis of certain assumptions which may or may not be realized. These include the timing of future production, the estimation of crude oil and natural gas reserves and the application of average crude oil and natural gas prices and exchange rates from the previous 12 months. Furthermore, both proved reserves estimates and production forecasts are subject to revision as further technical information becomes available and economic conditions change. BP cautions against relying on the information presented because of the highly arbitrary nature of the assumptions on which it is based and its lack of comparability with the historical cost information presented in the financial statements.
$ million | ||||||||||||||||||||||||||||||||||||||||||
2013 | ||||||||||||||||||||||||||||||||||||||||||
Europe |
North America |
South America |
Africa |
Asia | Australasia | Total | ||||||||||||||||||||||||||||||||||||
UK | Rest of Europe |
US | Rest of North America |
Russia | Rest of Asia |
|||||||||||||||||||||||||||||||||||||
At 31 December 2013 |
||||||||||||||||||||||||||||||||||||||||||
Subsidiaries |
||||||||||||||||||||||||||||||||||||||||||
Future cash inflowsa |
66,200 | 26,300 | 234,500 | 9,400 | 40,000 | 67,500 | | 89,000 | 57,600 | 590,500 | ||||||||||||||||||||||||||||||||
Future production costb |
21,900 | 11,200 | 99,000 | 4,600 | 11,600 | 17,800 | | 35,000 | 20,000 | 221,100 | ||||||||||||||||||||||||||||||||
Future development costb |
6,500 | 2,000 | 27,700 | 2,000 | 7,600 | 10,900 | | 23,700 | 6,900 | 87,300 | ||||||||||||||||||||||||||||||||
Future taxationc |
23,900 | 8,000 | 37,000 | 400 | 11,100 | 14,300 | | 6,200 | 8,100 | 109,000 | ||||||||||||||||||||||||||||||||
Future net cash flows |
13,900 | 5,100 | 70,800 | 2,400 | 9,700 | 24,500 | | 24,100 | 22,600 | 173,100 | ||||||||||||||||||||||||||||||||
10% annual discountd |
6,800 | 2,200 | 34,300 | 1,900 | 4,200 | 9,300 | | 13,300 | 12,800 | 84,800 | ||||||||||||||||||||||||||||||||
Standardized measure of discounted future net cash flowse |
7,100 | 2,900 | 36,500 | 500 | 5,500 | 15,200 | | 10,800 | 9,800 | 88,300 | ||||||||||||||||||||||||||||||||
Equity-accounted entities (BP share)f |
| |||||||||||||||||||||||||||||||||||||||||
Future cash inflowsa |
| | | | 45,800 | | 255,600 | 14,300 | | 315,700 | ||||||||||||||||||||||||||||||||
Future production costb |
| | | | 22,500 | | 139,000 | 11,800 | | 173,300 | ||||||||||||||||||||||||||||||||
Future development costb |
| | | | 6,000 | | 19,700 | 2,100 | | 27,800 | ||||||||||||||||||||||||||||||||
Future taxationc |
| | | | 5,900 | | 15,200 | 100 | | 21,200 | ||||||||||||||||||||||||||||||||
Future net cash flows |
| | | | 11,400 | | 81,700 | 300 | | 93,400 | ||||||||||||||||||||||||||||||||
10% annual discountd |
| | | | 6,900 | | 48,700 | 100 | | 55,700 | ||||||||||||||||||||||||||||||||
Standardized measure of discounted future net cash flowsg h |
| | | | 4,500 | | 33,000 | 200 | | 37,700 | ||||||||||||||||||||||||||||||||
Total subsidiaries and equity-accounted entities |
| |||||||||||||||||||||||||||||||||||||||||
Standardized measure of discounted future net cash flows |
7,100 | 2,900 | 36,500 | 500 | 10,000 | 15,200 | 33,000 | 11,000 | 9,800 | 126,000 |
The following are the principal sources of change in the standardized measure of discounted future net cash flows:
$ million | ||||||||||||||
Subsidiaries |
Equity-accounted entities (BP share) |
Total subsidiaries and entities |
||||||||||||
Sales and transfers of oil and gas produced, net of production costs |
(30,600 | ) | (7,900 | ) | (38,500 | ) | ||||||||
Development costs for the current year as estimated in previous year |
14,000 | 3,200 | 17,200 | |||||||||||
Extensions, discoveries and improved recovery, less related costs |
1,900 | 2,000 | 3,900 | |||||||||||
Net changes in prices and production cost |
(1,800 | ) | (100 | ) | (1,900 | ) | ||||||||
Revisions of previous reserves estimates |
(3,100 | ) | (400 | ) | (3,500 | ) | ||||||||
Net change in taxation |
12,900 | 3,400 | 16,300 | |||||||||||
Future development costs |
(4,100 | ) | (2,100 | ) | (6,200 | ) | ||||||||
Net change in purchase and sales of reserves-in-place |
(3,500 | ) | 9,000 | 5,500 | ||||||||||
Addition of 10% annual discount |
9,300 | 2,800 | 12,100 | |||||||||||
Total change in the standardized measure during the yeari |
(5,000 | ) | 9,900 | 4,900 |
a | The marker prices used were Brent $108.02/bbl, Henry Hub $3.66/mmBtu. |
b | Production costs, which include production taxes, and development costs relating to future production of proved reserves are based on the continuation of existing economic conditions. Future decommissioning costs are included. |
c | Taxation is computed using appropriate year-end statutory corporate income tax rates. |
d | Future net cash flows from oil and natural gas production are discounted at 10% regardless of the group assessment of the risk associated with its producing activities. |
e | Non-controlling interest in BP Trinidad and Tobago LLC amounted to $1,700 million. |
f | The standardized measure of discounted future net cash flows of equity-accounted entities includes standardized measure of discounted future net cash flows of equity-accounted investments of those entities. |
g | Non-controlling interest in Rosneft amounted to $200 million in Russia. |
h | No equity-accounted future cash flows in Africa because proved reserves are received as a result of contractual arrangements, with no associated costs. |
i | Total change in the standardized measure during the year includes the effect of exchange rate movements. |
BP Annual Report and Form 20-F 2013 | 219 |
Standardized measure of discounted future net cash flows and changes therein relating to proved oil and gas reserve continued
$ million | ||||||||||||||||||||||||||||||||||||||||||
2012 | ||||||||||||||||||||||||||||||||||||||||||
Europe |
North America |
South America |
Africa |
Asia | Australasia | Total | ||||||||||||||||||||||||||||||||||||
UK | Rest of Europe |
US | Rest of North |
Russia | Rest of Asia |
|||||||||||||||||||||||||||||||||||||
At 31 December 2012 |
||||||||||||||||||||||||||||||||||||||||||
Subsidiaries |
||||||||||||||||||||||||||||||||||||||||||
Future cash inflowsa |
88,000 | 30,800 | 261,100 | 9,500 | 30,400 | 75,800 | | 54,200 | 54,300 | 604,100 | ||||||||||||||||||||||||||||||||
Future production costb |
24,600 | 10,400 | 117,000 | 4,600 | 10,700 | 17,200 | | 14,000 | 19,000 | 217,500 | ||||||||||||||||||||||||||||||||
Future development costb |
7,400 | 2,400 | 29,600 | 2,400 | 7,700 | 13,000 | | 10,900 | 3,700 | 77,100 | ||||||||||||||||||||||||||||||||
Future taxationc |
35,200 | 11,700 | 40,700 | 400 | 6,300 | 17,500 | | 6,900 | 8,400 | 127,100 | ||||||||||||||||||||||||||||||||
Future net cash flows |
20,800 | 6,300 | 73,800 | 2,100 | 5,700 | 28,100 | | 22,400 | 23,200 | 182,400 | ||||||||||||||||||||||||||||||||
10% annual discountd |
10,900 | 2,400 | 40,100 | 2,000 | 2,700 | 10,900 | | 8,300 | 11,800 | 89,100 | ||||||||||||||||||||||||||||||||
Standardized measure of discounted future net cash flowse |
9,900 | 3,900 | 33,700 | 100 | 3,000 | 17,200 | | 14,100 | 11,400 | 93,300 | ||||||||||||||||||||||||||||||||
Equity-accounted entities (BP share)f |
| |||||||||||||||||||||||||||||||||||||||||
Future cash inflowsa |
| | | | 49,400 | | 203,600 | 24,400 | | 277,400 | ||||||||||||||||||||||||||||||||
Future production costb |
| | | | 24,800 | | 133,400 | 21,000 | | 179,200 | ||||||||||||||||||||||||||||||||
Future development costb |
| | | | 5,500 | | 16,600 | 1,900 | | 24,000 | ||||||||||||||||||||||||||||||||
Future taxationc |
| | | | 6,600 | | 10,100 | 200 | | 16,900 | ||||||||||||||||||||||||||||||||
Future net cash flows |
| | | | 12,500 | | 43,500 | 1,300 | | 57,300 | ||||||||||||||||||||||||||||||||
10% annual discountd |
| | | | 7,600 | | 21,600 | 300 | | 29,500 | ||||||||||||||||||||||||||||||||
Standardized measure of discounted future net cash flowsg h |
| | | | 4,900 | | 21,900 | 1,000 | | 27,800 | ||||||||||||||||||||||||||||||||
Total subsidiaries and equity-accounted entities |
| |||||||||||||||||||||||||||||||||||||||||
Standardized measure of discounted future net cash flowsi |
9,900 | 3,900 | 33,700 | 100 | 7,900 | 17,200 | 21,900 | 15,100 | 11,400 | 121,100 |
The following are the principal sources of change in the standardized measure of discounted future net cash flows:
$ million | ||||||||||||||
Subsidiaries |
Equity-accounted entities (BP share) |
Total subsidiaries and equity-accounted entities |
||||||||||||
Sales and transfers of oil and gas produced, net of production costs |
(34,600 | ) | (8,300 | ) | (42,900 | ) | ||||||||
Development costs for the current year as estimated in previous year |
14,400 | 3,100 | 17,500 | |||||||||||
Extensions, discoveries and improved recovery, less related costs |
8,000 | 1,200 | 9,200 | |||||||||||
Net changes in prices and production cost |
(15,300 | ) | 2,900 | (12,400 | ) | |||||||||
Revisions of previous reserves estimates |
(16,000 | ) | (1,000 | ) | (17,000 | ) | ||||||||
Net change in taxation |
23,200 | 300 | 23,500 | |||||||||||
Future development costs |
(7,700 | ) | (500 | ) | (8,200 | ) | ||||||||
Net change in purchase and sales of reserves-in-place |
(6,800 | ) | (100 | ) | (6,900 | ) | ||||||||
Addition of 10% annual discount |
11,600 | 2,800 | 14,400 | |||||||||||
Total change in the standardized measure during the yearj |
(23,200 | ) | 400 | (22,800 | ) |
a | The marker prices used were Brent $111.13/bbl, Henry Hub $2.75/mmBtu. |
b | Production costs, which include production taxes, and development costs relating to future production of proved reserves are based on the continuation of existing economic conditions. Future decommissioning costs are included. |
c | Taxation is computed using appropriate year-end statutory corporate income tax rates. |
d | Future net cash flows from oil and natural gas production are discounted at 10% regardless of the group assessment of the risk associated with its producing activities. |
e | Non-controlling interest in BP Trinidad and Tobago LLC amounted to $900 million. |
f | The standardized measure of discounted future net cash flows of equity-accounted entities includes standardized measure of discounted future net cash flows of equity-accounted investments of those entities. |
g | Non-controlling interest in TNK-BP amounted to $1,600 million in Russia. |
h | No equity-accounted future cash flows in Africa because proved reserves are received as a result of contractual arrangements, with no associated costs. |
i | Includes future net cash flows for assets held for sale at 31 December 2012. |
j | Total change in the standardized measure during the year includes the effect of exchange rate movements. |
220 | BP Annual Report and Form 20-F 2013 |
Standardized measure of discounted future net cash flows and changes therein relating to proved oil and gas reserve continued
$ million |
||||||||||||||||||||||||||||||||||||||||||
2011 | ||||||||||||||||||||||||||||||||||||||||||
Europe |
North America |
South
America |
Africa |
Asia |
Australasia |
Total | ||||||||||||||||||||||||||||||||||||
UK | Rest of Europe |
US | Rest of North America |
Russia | Rest of Asia |
|||||||||||||||||||||||||||||||||||||
At 31 December 2011 |
||||||||||||||||||||||||||||||||||||||||||
Subsidiaries |
|
|||||||||||||||||||||||||||||||||||||||||
Future cash inflowsa |
97,900 | 36,400 | 332,900 | 9,200 | 39,100 | 82,100 | | 59,200 | 53,900 | 710,700 | ||||||||||||||||||||||||||||||||
Future production costb |
30,500 | 10,900 | 140,700 | 3,200 | 10,500 | 16,800 | | 16,000 | 15,600 | 244,200 | ||||||||||||||||||||||||||||||||
Future development costb |
8,500 | 2,700 | 32,300 | 1,900 | 7,600 | 13,200 | | 9,600 | 3,200 | 79,000 | ||||||||||||||||||||||||||||||||
Future taxationc |
37,100 | 15,200 | 57,000 | 900 | 11,400 | 19,800 | | 8,100 | 9,000 | 158,500 | ||||||||||||||||||||||||||||||||
Future net cash flows |
21,800 | 7,600 | 102,900 | 3,200 | 9,600 | 32,300 | | 25,500 | 26,100 | 229,000 | ||||||||||||||||||||||||||||||||
10% annual discountd |
11,200 | 3,100 | 55,500 | 2,800 | 4,100 | 12,500 | | 9,800 | 13,500 | 112,500 | ||||||||||||||||||||||||||||||||
Standardized measure of discounted future net cash flowse |
10,600 | 4,500 | 47,400 | 400 | 5,500 | 19,800 | | 15,700 | 12,600 | 116,500 | ||||||||||||||||||||||||||||||||
Equity-accounted entities (BP share)f |
|
|||||||||||||||||||||||||||||||||||||||||
Future cash inflowsa |
| | | | 46,700 | | 188,900 | 34,200 | | 269,800 | ||||||||||||||||||||||||||||||||
Future production costb |
| | | | 21,500 | | 123,800 | 30,100 | | 175,400 | ||||||||||||||||||||||||||||||||
Future development costb |
| | | | 5,000 | | 15,600 | 2,400 | | 23,000 | ||||||||||||||||||||||||||||||||
Future taxationc |
| | | | 5,900 | | 9,600 | 200 | | 15,700 | ||||||||||||||||||||||||||||||||
Future net cash flows |
| | | | 14,300 | | 39,900 | 1,500 | | 55,700 | ||||||||||||||||||||||||||||||||
10% annual discountd |
| | | | 8,700 | | 19,000 | 600 | | 28,300 | ||||||||||||||||||||||||||||||||
Standardized measure of discounted future net cash flowsg h |
| | | | 5,600 | | 20,900 | 900 | | 27,400 | ||||||||||||||||||||||||||||||||
Total subsidiaries and equity-accounted entities |
|
|||||||||||||||||||||||||||||||||||||||||
Standardized measure of discounted future net cash flows |
10,600 | 4,500 | 47,400 | 400 | 11,100 | 19,800 | 20,900 | 16,600 | 12,600 | 143,900 |
The following are the principal sources of change in the standardized measure of discounted future net cash flows:
$ million | ||||||||||||||
Subsidiaries | Equity-accounted entities (BP share) |
Total subsidiaries and entities |
||||||||||||
Sales and transfers of oil and gas produced, net of production costs |
(30,900 | ) | (5,700 | ) | (36,600 | ) | ||||||||
Development costs for the current year as estimated in previous year |
13,200 | 2,500 | 15,700 | |||||||||||
Extensions, discoveries and improved recovery, less related costs |
6,600 | 2,800 | 9,400 | |||||||||||
Net changes in prices and production cost |
75,100 | 15,700 | 90,800 | |||||||||||
Revisions of previous reserves estimates |
(21,900 | ) | 2,000 | (19,900 | ) | |||||||||
Net change in taxation |
(18,200 | ) | (1,400 | ) | (19,600 | ) | ||||||||
Future development costs |
(11,000 | ) | (2,500 | ) | (13,500 | ) | ||||||||
Net change in purchase and sales of reserves-in-place |
(6,500 | ) | (2,700 | ) | (9,200 | ) | ||||||||
Addition of 10% annual discount |
10,000 | 1,500 | 11,500 | |||||||||||
Total change in the standardized measure during the yeari |
16,400 | 12,200 | 28,600 |
a | The marker prices used were Brent $110.96/bbl, Henry Hub $4.12/mmBtu. |
b | Production costs, which include production taxes, and development costs relating to future production of proved reserves are based on the continuation of existing economic conditions. Future decommissioning costs are included. |
c | Taxation is computed using appropriate year-end statutory corporate income tax rates. |
d | Future net cash flows from oil and natural gas production are discounted at 10% regardless of the group assessment of the risk associated with its producing activities. |
e | Non-controlling interest in BP Trinidad and Tobago LLC amounted to $1,600 million. |
f | The standardized measure of discounted future net cash flows of equity-accounted entities includes standardized measure of discounted future net cash flows of equity-accounted investments of those entities. |
g | Non-controlling interest in TNK-BP amounted to $1,600 million in Russia. |
h | No equity-accounted future cash flows in Africa because proved reserves are received as a result of contractual arrangements, with no associated costs. |
i | Total change in the standardized measure during the year includes the effect of exchange rate movements. |
BP Annual Report and Form 20-F 2013 | 221 |
Operational and statistical information
The following tables present operational and statistical information related to production, drilling, productive wells and acreage. Figures include amounts attributable to assets held for sale.
Crude oil and natural gas production
The following table shows crude oil and natural gas production for the years ended 31 December 2013, 2012 and 2011.
Production for the yeara
Europe |
North America |
South
America |
Africa |
Asia |
Australasia |
Total | ||||||||||||||||||||||||||||||||||||
UK | Rest of Europe |
US | Rest of North America |
Russia | Rest of Asia |
|||||||||||||||||||||||||||||||||||||
Subsidiaries |
||||||||||||||||||||||||||||||||||||||||||
Crude oilb | thousand barrels per day |
|||||||||||||||||||||||||||||||||||||||||
2013 |
61 | 34 | 363 | | 30 | 225 | | 141 | 25 | 879 | ||||||||||||||||||||||||||||||||
2012 |
86 | 23 | 390 | 1 | 28 | 202 | | 139 | 27 | 896 | ||||||||||||||||||||||||||||||||
2011 |
113 | 32 | 453 | 2 | 39 | 190 | | 138 | 25 | 992 | ||||||||||||||||||||||||||||||||
Natural gasc | million cubic feet per day |
|||||||||||||||||||||||||||||||||||||||||
2013 |
157 | 80 | 1,539 | 11 | 2,221 | 561 | | 494 | 780 | 5,845 | ||||||||||||||||||||||||||||||||
2012 |
414 | 8 | 1,651 | 13 | 2,097 | 590 | | 633 | 787 | 6,193 | ||||||||||||||||||||||||||||||||
2011 |
355 | 13 | 1,843 | 14 | 2,197 | 558 | | 618 | 795 | 6,393 | ||||||||||||||||||||||||||||||||
Equity-accounted entities(BP share) |
|
|||||||||||||||||||||||||||||||||||||||||
Crude oilb | thousand barrels per day |
|||||||||||||||||||||||||||||||||||||||||
2013 |
| | | | 73 | | 829 | 232 | | 1,134 | ||||||||||||||||||||||||||||||||
2012 |
| | | | 80 | | 863 | 217 | | 1,160 | ||||||||||||||||||||||||||||||||
2011 |
| | | | 90 | | 865 | 210 | | 1,165 | ||||||||||||||||||||||||||||||||
Natural gasc | million cubic feet per day |
|||||||||||||||||||||||||||||||||||||||||
2013 |
| | | | 386 | 8 | 780 | 41 | | 1,216 | ||||||||||||||||||||||||||||||||
2012 |
| | | | 394 | | 734 | 72 | | 1,200 | ||||||||||||||||||||||||||||||||
2011 |
| | | | 392 | | 699 | 34 | | 1,125 |
a | Production excludes royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting and sales arrangements independently. |
b | Crude oil includes natural gas liquids and condensate. |
c | Natural gas production excludes gas consumed in operations. |
Because of rounding, some totals may not exactly agree with the sum of their component parts.
Productive oil and gas wells and acreage
The following tables show the number of gross and net productive oil and natural gas wells and total gross and net developed and undeveloped oil and natural gas acreage in which the group and its equity-accounted entities had interests as at 31 December 2013. A gross well or acre is one in which a whole or fractional working interest is owned, while the number of net wells or acres is the sum of the whole or fractional working interests in gross wells or acres. Productive wells are producing wells and wells capable of production. Developed acreage is the acreage within the boundary of a field, on which development wells have been drilled, which could produce the reserves; while undeveloped acres are those on which wells have not been drilled or completed to a point that would permit the production of commercial quantities, whether or not such acres contain proved reserves.
Europe |
North America |
South
America |
Africa |
Asia |
Australasia |
Total | ||||||||||||||||||||||||||||||||||||||||
UK | Rest of Europe |
US | Rest of North America |
Russia | Rest of Asia |
|||||||||||||||||||||||||||||||||||||||||
Number of productive wells at 31 December 2013 |
|
|||||||||||||||||||||||||||||||||||||||||||||
Oil wellsa |
gross | 115 | 63 | 2,456 | 55 | 4,681 | 608 | 41,541 | 2,166 | 13 | 51,698 | |||||||||||||||||||||||||||||||||||
net | 71 | 25 | 975 | 28 | 2,583 | 441 | 7,779 | 439 | 2 | 12,343 | ||||||||||||||||||||||||||||||||||||
Gas wellsb |
gross | 68 | 6 | 21,445 | 364 | 688 | 135 | 72 | 761 | 74 | 23,613 | |||||||||||||||||||||||||||||||||||
net | 29 | 1 | 9,367 | 179 | 239 | 52 | 14 | 280 | 14 | 10,175 | ||||||||||||||||||||||||||||||||||||
Oil and natural gas acreage at 31 December 2013 |
|
Thousands of acres | ||||||||||||||||||||||||||||||||||||||||||||
Developed |
gross | 128 | 39 | 6,340 | 223 | 1,634 | 621 | 4,380 | 1,982 | 162 | 15,509 | |||||||||||||||||||||||||||||||||||
net | 71 | 16 | 3,334 | 109 | 453 | 221 | 831 | 355 | 35 | 5,425 | ||||||||||||||||||||||||||||||||||||
Undevelopedc |
gross | 1,118 | 1,196 | 6,669 | 9,710 | 29,100 | 26,538 | 257,896 | 20,141 | 16,021 | 368,389 | |||||||||||||||||||||||||||||||||||
net | 672 | 403 | 4,585 | 7,638 | 12,943 | 17,142 | 50,285 | 7,258 | 11,254 | 112,180 |
a | Includes approximately 7,639 gross (1,491 net) multiple completion wells (more than one formation producing into the same well bore). |
b | Includes approximately 2,859 gross (1,350 net) multiple completion wells. If one of the multiple completions in a well is an oil completion, the well is classified as an oil well. |
c | Undeveloped acreage includes leases and concessions. |
222 | BP Annual Report and Form 20-F 2013 |
Operational and statistical information continued
Net oil and gas wells completed or abandoned
The following table shows the number of net productive and dry exploratory and development oil and natural gas wells completed or abandoned in the years indicated by the group and its equity-accounted entities. Productive wells include wells in which hydrocarbons were encountered and the drilling or completion of which, in the case of exploratory wells, has been suspended pending further drilling or evaluation. A dry well is one found to be incapable of producing hydrocarbons in sufficient quantities to justify completion.
Europe |
North America |
South
America |
Africa |
Asia |
Australasia |
Total | ||||||||||||||||||||||||||||||||||||
UK | Rest of Europe |
US | Rest of North America |
Russiae | Rest of Asia |
|||||||||||||||||||||||||||||||||||||
2013 |
||||||||||||||||||||||||||||||||||||||||||
Exploratory |
||||||||||||||||||||||||||||||||||||||||||
Productive |
1.0 | | 12.7 | | 4.5 | 1.5 | 4.0 | 3.5 | | 27.2 | ||||||||||||||||||||||||||||||||
Dry |
| | 1.1 | | 1.4 | 0.6 | | 0.9 | 0.5 | 4.5 | ||||||||||||||||||||||||||||||||
Development |
||||||||||||||||||||||||||||||||||||||||||
Productive |
1.0 | 1.2 | 285.7 | | 94.6 | 12.6 | 395.0 | 58.0 | 0.2 | 848.3 | ||||||||||||||||||||||||||||||||
Dry |
| 0.2 | 0.4 | | 2.7 | 0.2 | | 0.7 | 0.4 | 4.6 | ||||||||||||||||||||||||||||||||
2012 |
||||||||||||||||||||||||||||||||||||||||||
Exploratory |
||||||||||||||||||||||||||||||||||||||||||
Productive |
| 0.3 | 17.1 | | 5.8 | 2.3 | 14.7 | | | 40.2 | ||||||||||||||||||||||||||||||||
Dry |
0.2 | | 0.6 | | 1.0 | 0.5 | 5.0 | | | 7.3 | ||||||||||||||||||||||||||||||||
Development |
||||||||||||||||||||||||||||||||||||||||||
Productive |
1.6 | | 317.8 | | 78.9 | 17.7 | 552.5 | 43.1 | | 1,011.6 | ||||||||||||||||||||||||||||||||
Dry |
| | | | | 1.0 | | 9.5 | | 10.5 | ||||||||||||||||||||||||||||||||
2011 |
||||||||||||||||||||||||||||||||||||||||||
Exploratory |
||||||||||||||||||||||||||||||||||||||||||
Productive |
0.4 | | 34.1 | | 4.4 | 2.1 | 16.7 | 1.0 | 0.2 | 58.9 | ||||||||||||||||||||||||||||||||
Dry |
| | 2.1 | | 0.2 | | 7.2 | 0.3 | 0.3 | 10.1 | ||||||||||||||||||||||||||||||||
Development |
||||||||||||||||||||||||||||||||||||||||||
Productive |
1.7 | | 199.4 | | 101.3 | 16.0 | 582.0 | 45.1 | | 945.5 | ||||||||||||||||||||||||||||||||
Dry |
| | 0.2 | | 3.0 | 2.7 | | 0.4 | | 6.3 | ||||||||||||||||||||||||||||||||
e Information for 2011 and 2012 includes BPs share of TNK-BP which was sold to Rosneft on 21 March 2013. |
| |||||||||||||||||||||||||||||||||||||||||
Drilling and production activities in progress The following table shows the number of exploratory and development oil and natural gas wells in the process of being drilled by the group and its equity-accounted entities as of 31 December 2013. Suspended development wells and long-term suspended exploratory wells are also included in the table.
|
| |||||||||||||||||||||||||||||||||||||||||
Europe |
North America |
South
America |
Africa |
Asia |
Australasia |
Total | ||||||||||||||||||||||||||||||||||||
UK | Rest of Europe |
US | Rest of North America |
Russia | Rest of Asia |
|||||||||||||||||||||||||||||||||||||
At 31 December 2013 |
||||||||||||||||||||||||||||||||||||||||||
Exploratory |
||||||||||||||||||||||||||||||||||||||||||
Gross |
2.0 | | 32.0 | 3.0 | 6.0 | 10.0 | | 4.0 | | 57.0 | ||||||||||||||||||||||||||||||||
Net |
0.8 | | 9.2 | 1.5 | 2.2 | 5.2 | | 0.8 | | 19.7 | ||||||||||||||||||||||||||||||||
Development |
||||||||||||||||||||||||||||||||||||||||||
Gross |
6.0 | 3.0 | 780.0 | 55.0 | 33.0 | 20.0 | 100.0 | 58.0 | 10.0 | 1,065.0 | ||||||||||||||||||||||||||||||||
Net |
4.0 | 1.1 | 169.1 | 27.5 | 16.6 | 6.1 | 19.8 | 20.7 | 1.4 | 266.3 |
BP Annual Report and Form 20-F 2013 | 223 |
Pages 224-234 have been removed as they do not form part of
the BPs Annual Report on Form 20-F as filed with the SEC.
224 | BP Annual Report and Form 20-F 2013 |
BP Annual Report and Form 20-F 2013 | 235 |
Selected financial information
This information, insofar as it relates to 2013, has been extracted or derived from the audited consolidated financial statements of the BP group presented on page 115. Note 1 to the financial statements includes details on the basis of preparation of these financial statements. The selected information should be read in conjunction with the audited financial statements and related notes elsewhere herein. Comparative financial information for 2009-12 has been restated to reflect the adoption of amendments to IAS 19 Employee Benefits. Financial information for 2011 and 2012 has also been restated to reflect the adoption of IFRS 11 Joint Arrangements. For further information see Financial statements Note 1.
$ million except per share amounts |
||||||||||||||||||||||
2013 | 2012 | 2011 | 2010 | 2009 | ||||||||||||||||||
Income statement data |
||||||||||||||||||||||
Sales and other operating revenues |
379,136 | 375,765 | 375,713 | 297,107 | 239,272 | |||||||||||||||||
Underlying replacement cost profit before interest and taxationa |
22,776 | 26,454 | 33,601 | 31,704 | 22,673 | |||||||||||||||||
Net favourable (unfavourable) impact of non-operating items and fair value accounting effectsa |
9,283 | (6,091 | ) | 3,580 | (37,190 | ) | (169 | ) | ||||||||||||||
Replacement cost profit (loss) before interest and taxationa |
32,059 | 20,363 | 37,181 | (5,486 | ) | 22,504 | ||||||||||||||||
Inventory holding gains (losses)b |
(290 | ) | (594 | ) | 2,634 | 1,784 | 3,922 | |||||||||||||||
Profit (loss) before interest and taxation |
31,769 | 19,769 | 39,815 | (3,702 | ) | 26,426 | ||||||||||||||||
Finance costs and net finance expense relating to pensions and other post-retirement benefits |
(1,548 | ) | (1,638 | ) | (1,587 | ) | (1,605 | ) | (1,609 | ) | ||||||||||||
Taxation |
(6,463 | ) | (6,880 | ) | (12,619 | ) | 1,638 | (8,273 | ) | |||||||||||||
Profit (loss) for the year |
23,758 | 11,251 | 25,609 | (3,669 | ) | 16,544 | ||||||||||||||||
Profit (loss) for the year attributable to BP shareholders |
23,451 | 11,017 | 25,212 | (4,064 | ) | 16,363 | ||||||||||||||||
Inventory holding (gains) lossesb, net of taxation |
230 | 411 | (1,800 | ) | (1,195 | ) | (2,623 | ) | ||||||||||||||
Replacement cost profit (loss) for the year attributable to BP shareholdersa |
23,681 | 11,428 | 23,412 | (5,259 | ) | 13,740 | ||||||||||||||||
Non-operating items and fair value accounting effectsa, net of taxation |
(10,253 | ) | 5,643 | (2,242 | ) | 25,436 | 622 | |||||||||||||||
Underlying replacement cost profit for the year attributable to BP shareholdersa |
13,428 | 17,071 | 21,170 | 20,177 | 14,362 | |||||||||||||||||
Per ordinary share cents |
||||||||||||||||||||||
Profit (loss) for the year attributable to BP shareholders |
||||||||||||||||||||||
Basic |
123.87 | 57.89 | 133.35 | (21.64 | ) | 87.34 | ||||||||||||||||
Diluted |
123.12 | 57.50 | 131.74 | (21.64 | ) | 86.40 | ||||||||||||||||
Replacement cost profit (loss) for the year attributable to BP shareholders |
125.08 | 60.05 | 123.83 | (28.01 | ) | 73.34 | ||||||||||||||||
Underlying replacement cost profit for the year attributable to BP shareholders |
70.92 | 89.70 | 111.97 | 107.39 | 76.66 | |||||||||||||||||
Dividends paid per share cents |
36.50 | 33.00 | 28.00 | 14.00 | 56.00 | |||||||||||||||||
pence |
23.399 | 20.852 | 17.404 | 8.679 | 36.417 | |||||||||||||||||
Capital expenditure and acquisitionsc |
36,612 | 25,204 | 31,959 | 23,016 | 20,309 | |||||||||||||||||
Acquisitions and asset exchanges |
71 | 200 | 11,283 | 3,406 | 308 | |||||||||||||||||
Organic capital expenditured |
24,600 | 23,950 | 19,580 | 18,218 | 20,001 | |||||||||||||||||
Balance sheet data (at 31 December) |
||||||||||||||||||||||
Total assets |
305,690 | 300,466 | 292,907 | 272,262 | 235,968 | |||||||||||||||||
Net assets |
130,407 | 119,752 | 112,585 | 95,891 | 102,113 | |||||||||||||||||
Share capital |
5,129 | 5,261 | 5,224 | 5,183 | 5,179 | |||||||||||||||||
BP shareholders equity |
129,302 | 118,546 | 111,568 | 94,987 | 101,613 | |||||||||||||||||
Finance debt due after more than one year |
40,811 | 38,767 | 35,169 | 30,710 | 25,518 | |||||||||||||||||
Net debt to net debt plus equitye |
16.2% | 18.7% | 20.4% | 21.2% | 20.4% | |||||||||||||||||
Ordinary share dataf |
|
Shares million |
| |||||||||||||||||||
Basic weighted average number of shares |
18,931 | 19,028 | 18,905 | 18,786 | 18,732 | |||||||||||||||||
Diluted weighted average number of shares |
19,046 | 19,158 | 19,136 | 18,998 | 18,936 |
a | RC profit or loss for the group, underlying RC profit or loss and fair value accounting effects are not recognized GAAP measures. For further information, see pages 237 and 238 and Certain definitions on page 269. |
b | See Certain definitions and also see Financial statements Note 7 for an analysis of inventory holding gains and losses by segment. |
c | Includes asset exchanges. All capital expenditure and acquisitions during the past five years have been financed from cash flow from operations, disposal proceeds and external financing. |
d | Organic capital expenditure excludes acquisitions and asset exchanges, and: in 2013 $11,941 million relating to our investment in Rosneft; in 2012 $1,054 million associated with deepening our US natural gas and North Sea asset bases; in 2011 $1,096 million associated with deepening our US natural gas bases; in 2010 $900 million relating to the formation of a partnership with Value Creation Inc. to develop the Terre de Grace oil sands acreage and $492 million for the purchase of additional interests in the Valhall and Hod fields in the North Sea. |
e | Net debt and the ratio of net debt to net debt plus equity are not recognized GAAP measures. We believe these numbers are useful information to investors. Further information on net debt is given in Financial statements Note 28. |
f | The number of ordinary shares shown has been used to calculate the per share amounts. |
236 | BP Annual Report and Form 20-F 2013 |
Non-operating items
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. They are items that management considers not to be part of underlying business operations and are disclosed in order to enable investors to understand better and evaluate the groups reported financial performance. An analysis of non-operating items is shown in the table below.
$ million | ||||||||||||||
2013 | 2012 | 2011 | ||||||||||||
Upstream |
||||||||||||||
Impairment and gain (loss) on sale of businesses and fixed assets |
(802 | ) | 3,638 | 2,131 | ||||||||||
Environmental and other provisions |
(20 | ) | (48 | ) | (27 | ) | ||||||||
Restructuring, integration and rationalization costs |
| | | |||||||||||
Fair value gain (loss) on embedded derivatives |
459 | 347 | 191 | |||||||||||
Othera |
(1,001 | ) | (748 | ) | (1,165 | ) | ||||||||
(1,364 | ) | 3,189 | 1,130 | |||||||||||
Downstream |
||||||||||||||
Impairment and gain (loss) on sale of businesses and fixed assets |
(348 | ) | (2,934 | ) | (332 | ) | ||||||||
Environmental and other provisions |
(134 | ) | (171 | ) | (221 | ) | ||||||||
Restructuring, integration and rationalization costs |
(15 | ) | (32 | ) | (4 | ) | ||||||||
Fair value gain (loss) on embedded derivatives |
| | | |||||||||||
Other |
(38 | ) | (35 | ) | (45 | ) | ||||||||
(535 | ) | (3,172 | ) | (602 | ) | |||||||||
TNK-BP |
||||||||||||||
Impairment and gain (loss) on sale of businesses and fixed assets |
12,500 | (55 | ) | | ||||||||||
Environmental and other provisions |
| (83 | ) | | ||||||||||
Restructuring, integration and rationalization costs |
| | | |||||||||||
Fair value gain (loss) on embedded derivatives |
| | | |||||||||||
Otherb |
| 384 | | |||||||||||
12,500 | 246 | | ||||||||||||
Rosneft |
||||||||||||||
Impairment and gain (loss) on sale of businesses and fixed assets |
(35 | ) | | | ||||||||||
Environmental and other provisions |
(10 | ) | | | ||||||||||
Restructuring, integration and rationalization costs |
| | | |||||||||||
Fair value gain (loss) on embedded derivatives |
| | | |||||||||||
Other |
| | | |||||||||||
(45 | ) | | | |||||||||||
Other businesses and corporate |
||||||||||||||
Impairment and gain (loss) on sale of businesses and fixed assets |
(196 | ) | (282 | ) | 275 | |||||||||
Environmental and other provisions |
(241 | ) | (261 | ) | (220 | ) | ||||||||
Restructuring, integration and rationalization costs |
(3 | ) | (15 | ) | (39 | ) | ||||||||
Fair value gain (loss) on embedded derivativesc |
| | (123 | ) | ||||||||||
Otherd |
19 | (240 | ) | (715 | ) | |||||||||
(421 | ) | (798 | ) | (822 | ) | |||||||||
Gulf of Mexico oil spill response |
(430 | ) | (4,995 | ) | 3,800 | |||||||||
Total before interest and taxation |
9,705 | (5,530 | ) | 3,506 | ||||||||||
Finance costse |
(39 | ) | (19 | ) | (58 | ) | ||||||||
Taxation credit (charge)f |
867 | 251 | (1,253 | ) | ||||||||||
Total after taxation |
10,533 | (5,298 | ) | 2,195 |
a | 2013 included $845 million relating to the value ascribed to block BM-CAL-13 offshore Brazil, following the acquisition of upstream assets from Devon Energy in 2011, which was written off as a result of the Pitanga exploration well not encountering commercial quantities of oil or gas. 2012 included a charge of $370 million relating to onerous gas marketing and trading contracts and $308 million relating to exploration expense associated with our US natural gas assets (2011 $395 million). 2011 included a charge of $700 million associated with the termination of the agreement to sell our 60% interest in Pan American Energy LLC to Bridas Corporation. |
b | 2012 included dividend income from TNK-BP of $709 million and a charge of $325 million to settle disputes with AAR. |
c | Relates to an embedded derivative arising from a financing arrangement. |
d | 2012 included charges of $244 million relating to our exit from the solar business (2011 $717 million). |
e | Finance costs relate to the Gulf of Mexico oil spill. See Financial statements Note 2 for further details. |
f | For the Gulf of Mexico oil spill and certain impairment losses, disposal gains and fair value gains and losses on embedded derivatives, tax is based on statutory rates, except for non-deductible items. For other items reported for consolidated subsidiaries, tax is calculated using the groups discrete quarterly effective tax rate (adjusted for the items noted above, equity-accounted earnings and certain deferred tax adjustments relating to changes in UK taxation). Non-operating items reported within the equity-accounted earnings of TNK-BP and Rosneft are reported net of tax. |
BP Annual Report and Form 20-F 2013 | 237 |
Non-GAAP information on fair value accounting effects
The impacts of fair value accounting effects, relative to managements internal measure of performance, and a reconciliation to GAAP information is also set out below. Further information on fair value accounting effects is provided on page 269.
$ million | ||||||||||||||
2013 | 2012 | 2011 | ||||||||||||
Upstream |
||||||||||||||
Unrecognized gains (losses) brought forward from previous period |
(404 | ) | (538 | ) | (527 | ) | ||||||||
Unrecognized (gains) losses carried forward |
160 | 404 | 538 | |||||||||||
Favourable (unfavourable) impact relative to managements measure of performance |
(244 | ) | (134 | ) | 11 | |||||||||
Downstreama |
||||||||||||||
Unrecognized gains (losses) brought forward from previous period |
501 | 74 | 137 | |||||||||||
Unrecognized (gains) losses carried forward |
(679 | ) | (501 | ) | (74 | ) | ||||||||
Favourable (unfavourable) impact relative to managements measure of performance |
(178 | ) | (427 | ) | 63 | |||||||||
(422 | ) | (561 | ) | 74 | ||||||||||
Taxation credit (charge)b |
142 | 216 | (27 | ) | ||||||||||
(280 | ) | (345 | ) | 47 | ||||||||||
By region |
||||||||||||||
Upstream |
||||||||||||||
US |
(269 | ) | (67 | ) | 15 | |||||||||
Non-US |
25 | (67 | ) | (4 | ) | |||||||||
(244 | ) | (134 | ) | 11 | ||||||||||
Downstreama |
||||||||||||||
US |
(211 | ) | (441 | ) | | |||||||||
Non-US |
33 | 14 | 63 | |||||||||||
(178 | ) | (427 | ) | 63 |
a | Fair value accounting effects arise solely in the fuels business. |
b | Tax is calculated using the groups discrete quarterly effective tax rate (adjusted for the Gulf of Mexico oil spill, equity-accounted earnings, certain impairment losses, disposal gains and fair value gains and losses on embedded derivatives and certain deferred tax adjustments relating to changes in UK taxation). |
Reconciliation of non-GAAP information
$ million | ||||||||||||||
2013 | 2012 | 2011 | ||||||||||||
Upstream |
||||||||||||||
Replacement cost profit before interest and tax adjusted for fair value accounting effects |
16,901 | 22,625 | 26,347 | |||||||||||
Impact of fair value accounting effects |
(244 | ) | (134 | ) | 11 | |||||||||
Replacement cost profit before interest and tax |
16,657 | 22,491 | 26,358 | |||||||||||
Downstream |
||||||||||||||
Replacement cost profit before interest and tax adjusted for fair value accounting effects |
3,097 | 3,291 | 5,407 | |||||||||||
Impact of fair value accounting effects |
(178 | ) | (427 | ) | 63 | |||||||||
Replacement cost profit before interest and tax |
2,919 | 2,864 | 5,470 | |||||||||||
Total group |
||||||||||||||
Profit before interest and tax adjusted for fair value accounting effects |
32,191 | 20,330 | 39,741 | |||||||||||
Impact of fair value accounting effects |
(422 | ) | (561 | ) | 74 | |||||||||
Profit before interest and tax |
31,769 | 19,769 | 39,815 |
238 | BP Annual Report and Form 20-F 2013 |
BP Annual Report and Form 20-F 2013 | 239 |
240 | BP Annual Report and Form 20-F 2013 |
BP Annual Report and Form 20-F 2013 | 241 |
242 | BP Annual Report and Form 20-F 2013 |
Downstream plant capacity
The following table summarizes the BP groups interests in refineries and average daily crude distillation capacities as at 31 December 2013.
thousand barrels per day | ||||||||||||||||||
Crude distillation capacitiesa | ||||||||||||||||||
Geographical area | Refinery | Fuels value chain | Group interestb % |
Total | BP share |
|||||||||||||
US |
||||||||||||||||||
Washington |
Cherry Point | US North West | 100.0 | 234 | 234 | |||||||||||||
Indiana |
Whiting | US East of Rockies | 100.0 | 428 | 428 | |||||||||||||
Ohio |
Toledo | US East of Rockies | 50.0 | 160 | 80 | |||||||||||||
822 | 742 | |||||||||||||||||
Europe |
||||||||||||||||||
Germany |
Bayernoilc | Rhine | 22.5 | 217 | 49 | |||||||||||||
Gelsenkirchen | Rhine | 50.0 | 265 | 132 | ||||||||||||||
Karlsruhec | Rhine | 12.0 | 322 | 39 | ||||||||||||||
Lingen | Rhine | 100.0 | 95 | 95 | ||||||||||||||
Schwedtc | Rhine | 18.8 | 239 | 45 | ||||||||||||||
Netherlands |
Rotterdam | Rhine | 100.0 | 377 | 377 | |||||||||||||
Spain |
Castellón | Iberia | 100.0 | 110 | 110 | |||||||||||||
1,625 | 847 | |||||||||||||||||
Rest of world |
||||||||||||||||||
Australia |
Bulwer | Australia New Zealand | 100.0 | 102 | 102 | |||||||||||||
Kwinana | Australia New Zealand | 100.0 | 146 | 146 | ||||||||||||||
New Zealand |
Whangareic | Australia New Zealand | 23.7 | 118 | 28 | |||||||||||||
South Africa |
Durbanc | Southern Africa | 50.0 | 180 | 90 | |||||||||||||
546 | 366 | |||||||||||||||||
Total BP share of capacity at 31 December 2013 |
1,955 |
a | Crude distillation capacity is gross rated capacity, which is defined as the highest average sustained unit rate for a consecutive 30-day period. |
b | BP share of equity, which is not necessarily the same as BP share of processing entitlements. |
c | Indicates refineries not operated by BP. |
BP Annual Report and Form 20-F 2013 | 243 |
Petrochemicals production capacitya b
The following table summarizes the BP groups share of petrochemicals production capacities as at 31 December 2013.
Geographical area | Site | Product | Group interest % |
BP share of capacity thousand tonnes per annumc |
||||||||||
US |
||||||||||||||
Cooper River | Purified terephthalic acid (PTA) | 100.0 | 1,300 | |||||||||||
Decaturd | PTA | 100.0 | 1,000 | |||||||||||
Paraxylene (PX) |
100.0 | 1,100 | ||||||||||||
Texas City | Acetic acid | 100.0 | e | 600 | e | |||||||||
PX |
100.0 | 1,300 | ||||||||||||
Metaxylene |
100.0 | 100 | ||||||||||||
5,400 | ||||||||||||||
Europe |
||||||||||||||
UK |
Hulld | Acetic acid | 100.0 | 500 | ||||||||||
Acetic anhydride |
100.0 | 200 | ||||||||||||
Belgium |
Geel | PTA | 100.0 | 1,300 | ||||||||||
PX |
100.0 | 700 | ||||||||||||
Germany |
Gelsenkirchenf | Olefins and derivatives | 50.0 to 61.0 | 1,800 | b g | |||||||||
Mülheimf | Solvents | 50.0 | 100 | b | ||||||||||
4,600 | ||||||||||||||
Rest of world |
||||||||||||||
China |
Caojing | Olefins and derivatives | 50.0 | 3,300 | b | |||||||||
Chongqing | Acetic acid | 51.0 | 200 | b | ||||||||||
Esters |
51.0 | 100 | b | |||||||||||
Nanjing | Acetic acid | 50.0 | 300 | b | ||||||||||
Zhuhai | PTA | 85.0 | 1,800 | h | ||||||||||
Indonesia |
Merak | PTA | 50.0 | 300 | b | |||||||||
South Korea |
Ulsan | Acetic acid | 51.0 | 300 | b | |||||||||
Vinyl acetate monomer |
34.0 | 100 | b | |||||||||||
Malaysia |
Kertih | Acetic acid | 70.0 | 400 | b | |||||||||
Taiwan |
Kaohsiung | PTA | 61.4 | 900 | b | |||||||||
Taichung | PTA | 61.4 | 500 | b | ||||||||||
Mai Liao | Acetic acid | 50.0 | 200 | b | ||||||||||
8,400 | ||||||||||||||
Total BP share of capacity at 31 December 2013 |
18,400 |
a | Petrochemicals production capacity is the proven maximum sustainable daily rate (MSDR) multiplied by the number of days in the respective period, where MSDR is the highest average daily rate ever achieved over a sustained period. |
b | Includes BP share of equity-accounted entities, as indicated. |
c | Capacities are shown to the nearest hundred thousand tonnes per annum. |
d | These sites have capacity under 100,000 tonnes per annum for a speciality product (e.g. naphthalene dicarboxylate and ethylidene diacetate). |
e | Group interest is quoted at 100%, reflecting the capacity entitlement, which is marketed by BP. |
f | Due to the integrated nature of these plants with our Gelsenkirchen refinery, the income and expenditure of these plants is managed and reported through the fuels business. |
g | Group interest varies by product. |
h | BP Zhuhai Chemical Company Ltd is a subsidiary of BP, the capacity of which is shown above at 100%. |
244 | BP Annual Report and Form 20-F 2013 |
BP Annual Report and Form 20-F 2013 | 245 |
246 | BP Annual Report and Form 20-F 2013 |
BPs net production by major field liquids
thousand barrels per day |
||||||||||||||||
BP net share of productiona |
||||||||||||||||
Field or area | 2013 | 2012 | 2011 | |||||||||||||
Subsidiaries UKb |
ETAPc | 22 | 11 | 22 | ||||||||||||
Foinaven (BP-operated) | 17 | 14 | 26 | |||||||||||||
Other | 22 | 61 | 65 | |||||||||||||
Total UK |
61 | 86 | 113 | |||||||||||||
Norwayb |
Various | 34 | 23 | 32 | ||||||||||||
Total Rest of Europe |
34 | 23 | 32 | |||||||||||||
Total Europe | 96 | 109 | 145 | |||||||||||||
Alaskab |
Greater Prudhoe Bay (BP-operated) | 73 | 77 | 78 | ||||||||||||
Kuparuk | 36 | 36 | 39 | |||||||||||||
Milne Point (BP-operated) | 16 | 15 | 19 | |||||||||||||
Other | 12 | 11 | 17 | |||||||||||||
Total Alaska |
137 | 139 | 153 | |||||||||||||
Lower 48 onshoreb |
Various | 56 | 60 | 69 | ||||||||||||
Gulf of Mexico deepwaterb |
Great White | 23 | 19 | 9 | ||||||||||||
Thunder Horse (BP-operated) | 27 | 49 | 77 | |||||||||||||
Atlantis (BP-operated) | 40 | 23 | 34 | |||||||||||||
Mad Dog (BP-operated) | 18 | 9 | 8 | |||||||||||||
Mars | 14 | 15 | 19 | |||||||||||||
Na Kika (BP-operated) | 28 | 21 | 14 | |||||||||||||
Horn Mountain (BP-operated) | | 6 | 8 | |||||||||||||
King (BP-operated) | | 14 | 15 | |||||||||||||
Other | 20 | 35 | 47 | |||||||||||||
Total Gulf of Mexico deepwater |
170 | 191 | 231 | |||||||||||||
Total US |
363 | 390 | 453 | |||||||||||||
Canadab |
Various (BP-operated) | | 1 | 2 | ||||||||||||
Total Rest of North America |
| 1 | 2 | |||||||||||||
Total North America | 363 | 391 | 455 |
BP Annual Report and Form 20-F 2013 | 247 |
BPs net production by major field liquids continued
thousand barrels per day |
||||||||||||||||
BP net share of productiona |
||||||||||||||||
Field or area | 2013 | 2012 | 2011 | |||||||||||||
Subsidiaries Colombiab |
Various (BP-operated) | | | 1 | ||||||||||||
Trinidad & Tobago |
Various (BP-operated) | 23 | 21 | 31 | ||||||||||||
Brazilb |
Polvo | 7 | 7 | 7 | ||||||||||||
Total South America | 30 | 28 | 39 | |||||||||||||
Angola |
Greater Plutonio (BP-operated) | 59 | 59 | 51 | ||||||||||||
Kizomba C Dev | 9 | 9 | 21 | |||||||||||||
Dalia | 11 | 11 | 12 | |||||||||||||
Girassol FPSO | 11 | 11 | 12 | |||||||||||||
Pazflor | 32 | 29 | 5 | |||||||||||||
PSVM | 24 | 1 | | |||||||||||||
Other | 34 | 29 | 22 | |||||||||||||
Total Angola |
180 | 149 | 123 | |||||||||||||
Egypt |
Gupco | 29 | 32 | 34 | ||||||||||||
Other | 9 | 9 | 11 | |||||||||||||
Total Egypt |
38 | 41 | 45 | |||||||||||||
Algeriab |
Various | 7 | 12 | 22 | ||||||||||||
Total Africa | 225 | 202 | 190 | |||||||||||||
Azerbaijanb |
Azeri-Chirag-Gunashli (BP-operated) | 83 | 82 | 86 | ||||||||||||
Other | 13 | 10 | 8 | |||||||||||||
Total Azerbaijan |
96 | 92 | 94 | |||||||||||||
Western Indonesia |
Various | 1 | 1 | 2 | ||||||||||||
Iraq |
Rumaila | 39 | 39 | 31 | ||||||||||||
Other |
Various | 5 | 7 | 11 | ||||||||||||
Total Rest of Asiab |
141 | 139 | 138 | |||||||||||||
Total Asia | 141 | 139 | 138 | |||||||||||||
Australia |
Various | 23 | 24 | 23 | ||||||||||||
Other |
Various | 2 | 3 | 2 | ||||||||||||
Total Australasia | 25 | 27 | 25 | |||||||||||||
Total subsidiariesd | 879 | 896 | 992 | |||||||||||||
Equity-accounted entities (BP share) |
||||||||||||||||
TNK-BP (Russia, Venezuela, Vietnam)b e |
Various | 187 | 877 | 871 | ||||||||||||
Rosneft (Russia, Canada, Venezuela, Vietnam)b f |
Various | 650 | | | ||||||||||||
Abu Dhabig |
Various | 231 | 216 | 209 | ||||||||||||
Argentina |
Various | 63 | 65 | 74 | ||||||||||||
Bolivia |
Various | 2 | 1 | | ||||||||||||
Venezuelab |
Various | | | 10 | ||||||||||||
Other |
Various | 1 | 1 | 1 | ||||||||||||
Total equity-accounted entities | 1,134 | 1,160 | 1,165 | |||||||||||||
Total subsidiaries and equity-accounted entities | 2,013 | 2,056 | 2,157 |
a | Production excludes royalties due to others whether payable in cash or in kind where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting and sales arrangements independently. |
b | In 2013, BP divested its interests in TNK-BP, its interests in the Harding, Devenick, Maclure, Braes and Braemar fields in the North Sea and its interests in the US onshore Moxa upstream operation in Wyoming. It also acquired an interest in Rosneft. In 2012, BP divested its interests in the Gulf of Mexico Marlin, Dorado, King, Horn Mountain, Holstein, Ram Powell and Diana Hoover assets, a portion of its interest in the Gulf of Mexico Mad Dog asset, its interests in the US onshore Jonah and Pinedale upstream operation in Wyoming, and associated gas gathering system, its interests in the Canadian natural gas liquid business, its interests in the Alba and Britannia fields in the UK North Sea, its interests in the Draugen field in the Norwegian Sea, and TNK-BP disposed of its interests in OJSC Novosibirskneftegaz, with interests in Novosibirsk region, Omsk region, and Irkutsk region, and its interests in OJSC Severnoeneftegaz, with interests in Novosibirsk region. BP also increased its interest in the US onshore Eagle Ford Shale in south Texas, its interests in certain UK North Sea assets, and in certain US Alaska assets. In 2011, BP sold its holdings in Venezuela and Vietnam to TNK-BP. It also made acquisitions in India through a joint arrangement with Reliance, Brazil and additional volumes in the Gulf of Mexico and UK North Sea. BP divested its holdings in Pompano along with other interests in the Gulf of Mexico, Tuscaloosa and interests in South Texas in the US onshore, a portion of our interest in the Azeri-Chirag-Gunashli development in Azerbaijan, Wytch Farm in the UK, our interests in the REB field in Algeria, and the remainder of our interests in Colombia and Pakistan. |
c | Volumes relate to six BP-operated fields within ETAP. BP has no interests in the remaining three ETAP fields, which are operated by Shell. |
d | Includes 5.5 net mboe/d of NGLs from processing plants in which BP has an interest (2012 13.5mboe/d and 2011 28mboe/d). |
e | Estimated production for 2013 represents BPs share of TNK-BPs estimated production from 1 January to 20 March, averaged over the full year. |
f | 2013 reflects production for the period 21 March to 31 December, averaged over the full year. |
g | In 2013 BP held interests, through associates, in onshore and offshore concessions in Abu Dhabi, of which the onshore concession expired in 2014 and the offshore concession expires in 2018. |
Because of rounding, some totals may not agree exactly with the sum of their component parts.
248 | BP Annual Report and Form 20-F 2013 |
BPs net production by major field natural gas
million cubic feet per day |
||||||||||||||||
BP net share of productiona |
||||||||||||||||
Field or area | 2013 | 2012 | 2011 | |||||||||||||
Subsidiaries UKb |
Bruce/Rhum (BP-operated) | 25 | 15 | 20 | ||||||||||||
Other | 132 | 399 | 335 | |||||||||||||
Total UK |
157 | 414 | 355 | |||||||||||||
Norway |
Various | 80 | 8 | 13 | ||||||||||||
Total Rest of Europe |
80 | 8 | 13 | |||||||||||||
Total Europe | 237 | 422 | 368 | |||||||||||||
Lower 48 onshoreb |
San Juan (BP-operated) | 529 | 561 | 603 | ||||||||||||
Jonah (BP-operated) | | 69 | 145 | |||||||||||||
Anadarko | 129 | 142 | 141 | |||||||||||||
Arkoma Central | 107 | 118 | 136 | |||||||||||||
Wamsutter (BP-operated) | 159 | 141 | 122 | |||||||||||||
Arkoma East | 115 | 112 | 115 | |||||||||||||
Arkoma West | 110 | 98 | 109 | |||||||||||||
Other | 255 | 258 | 274 | |||||||||||||
Total Lower 48 onshore |
1,404 | 1,499 | 1,645 | |||||||||||||
Gulf of Mexico deepwaterb |
Various | 114 | 134 | 176 | ||||||||||||
Alaska |
Various | 21 | 18 | 22 | ||||||||||||
Total US |
1,539 | 1,651 | 1,843 | |||||||||||||
Canadab |
Various | 11 | 13 | 14 | ||||||||||||
Total Rest of North America |
11 | 13 | 14 | |||||||||||||
Total North America | 1,551 | 1,664 | 1,857 | |||||||||||||
Trinidad & Tobago |
Mango (BP-operated) | 119 | 181 | 308 | ||||||||||||
Cashima/NEQB (BP-operated) | 138 | 305 | 570 | |||||||||||||
Kapok (BP-operated) | 358 | 360 | 464 | |||||||||||||
Cannonball (BP-operated) | 27 | 56 | 99 | |||||||||||||
Amherstia (BP-operated) | 257 | 324 | 296 | |||||||||||||
Serrette (BP-operated) | 527 | 367 | 35 | |||||||||||||
Savonette (BP-operated) | 545 | 320 | 327 | |||||||||||||
Immortelle (BP-operated) | 200 | 95 | 68 | |||||||||||||
Other (BP-operated) | 50 | 89 | 26 | |||||||||||||
Total Trinidad |
2,221 | 2,097 | 2,193 | |||||||||||||
Colombiab |
Various | | | 4 | ||||||||||||
Total South America | 2,221 | 2,097 | 2,197 | |||||||||||||
Egypt |
Temsah | 30 | 34 | 74 | ||||||||||||
Hapy (BP-operated) | 72 | 88 | 99 | |||||||||||||
Taurt (BP-operated) | 50 | 67 | 61 | |||||||||||||
Denis | 99 | 138 | 77 | |||||||||||||
Other | 193 | 143 | 133 | |||||||||||||
Total Egypt |
444 | 470 | 444 | |||||||||||||
Algeria |
Various | 117 | 120 | 114 | ||||||||||||
Total Africa | 561 | 590 | 558 | |||||||||||||
Pakistanb |
Various (BP-operated) | | | 73 | ||||||||||||
Azerbaijan |
Various (BP-operated) | 203 | 158 | 140 | ||||||||||||
Western Indonesia |
Sanga-Sanga | 55 | 59 | 59 | ||||||||||||
Indiab |
D1 D3 | 117 | 253 | 121 | ||||||||||||
D26 |
38 | 59 | 25 | |||||||||||||
Other | 1 | 1 | | |||||||||||||
Total India |
156 | 313 | 146 | |||||||||||||
Vietnamb |
Various (BP-operated) | | | 69 | ||||||||||||
Chinab |
Yacheng | 34 | 54 | 70 | ||||||||||||
Oman |
22 | 14 | 20 | |||||||||||||
Sharjah |
Various (BP-operated) | 25 | 35 | 41 | ||||||||||||
Total Rest of Asia |
494 | 633 | 618 | |||||||||||||
Total Asia | 494 | 633 | 618 |
BP Annual Report and Form 20-F 2013 | 249 |
BPs net production by major field natural gas continued
million cubic feet per day |
||||||||||||||||
BP net share of productiona |
||||||||||||||||
Field or area | 2013 | 2012 | 2011 | |||||||||||||
Subsidiaries Australia |
Perseus/Athena | 139 | 141 | 170 | ||||||||||||
Goodwyn |
57 | 73 | 72 | |||||||||||||
Angel |
89 | 110 | 126 | |||||||||||||
Other | 146 | 111 | 87 | |||||||||||||
Total Australia |
431 | 435 | 455 | |||||||||||||
Eastern Indonesia |
Tangguh (BP-operated) | 349 | 352 | 340 | ||||||||||||
Total Australasia | 780 | 787 | 795 | |||||||||||||
Total subsidiariesc | 5,845 | 6,193 | 6,393 | |||||||||||||
Equity-accounted entities (BP share) |
||||||||||||||||
TNK-BP (Russia, Venezuela, Vietnam)b d |
Various | 184 | 785 | 710 | ||||||||||||
Rosneft (Russia, Canada, Venezuela, Vietnam)b e |
Various | 617 | | | ||||||||||||
Angola |
ALNG | 8 | | | ||||||||||||
Argentina |
Various | 329 | 355 | 371 | ||||||||||||
Bolivia |
Various | 55 | 34 | 14 | ||||||||||||
Venezuelab |
Various | | | 4 | ||||||||||||
Western Indonesia |
Various | 22 | 26 | 26 | ||||||||||||
Total equity-accounted entitiesc | 1,216 | 1,200 | 1,125 | |||||||||||||
Total subsidiaries and equity-accounted entities | 7,060 | 7,393 | 7,518 |
a | Production excludes royalties due to others whether payable in cash or in kind where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting and sales arrangements independently. |
b | In 2013, BP divested its interests in TNK-BP, its interests in the Harding, Devenick, Maclure, Braes, Braemar and Sean fields in the North Sea, its interests in the US onshore Moxa upstream operation in Wyoming and its interests in the Yacheng gas field in the South China Sea. It also acquired an interest in Rosneft. In 2012, BP divested its interests in the US Hugoton basin including the Jayhawk NGL plant, its interests in the Gulf of Mexico Marlin, Dorado, King, Horn Mountain, Holstein, Ram Powell and Diana Hoover assets, a portion of its interest in the Gulf of Mexico Mad Dog asset, its interests in the US onshore Jonah and Pinedale upstream operation in Wyoming, its interests in the Sunray and Hemphill gas processing plants in Texas, and associated gas gathering system, its interests in the UK North Sea southern gas fields including associated pipeline infrastructure and the Dimlington terminal (including the integrated Easington terminal), and its interests in the Alba and Britannia fields in the UK North Sea. BP also increased its interest in the US onshore Eagle Ford Shale in South Texas, and its interests in certain UK North Sea assets. In 2011, BP sold its holdings in Venezuela and Vietnam to TNK-BP. It also made acquisitions in India through a joint operation with Reliance, in the Eagle Ford shale in North America and additional volumes in the Gulf of Mexico. BP divested its holdings in Pompano along with other interests in the Gulf of Mexico, Tuscaloosa and interests in south Texas in the US onshore, Wytch Farm in the UK, minor volumes in Canada and the remainder of our interests in Colombia and Pakistan. |
c | Natural gas production volumes exclude gas consumed in operations within the lease boundaries of the producing field, but the related reserves are included in the groups reserves. |
d | Estimated production for 2013 represents BPs share of TNK-BPs estimated production from 1 January to 20 March, averaged over the full year. |
e | 2013 reflects production for the period 21 March to 31 December, averaged over the full year. |
Because of rounding, some totals may not agree exactly with the sum of their component parts.
250 | BP Annual Report and Form 20-F 2013 |
The following tables provide additional data and disclosures in relation to our oil and gas operations.
Average sales price per unit of productiona
$ per unit of production | ||||||||||||||||||||||||||||||||||||||||||
Europe |
North America |
South America |
Africa |
Asia |
Australasia |
Total group average |
||||||||||||||||||||||||||||||||||||
UK | Rest of Europe |
US | Rest of North America |
Russiab | Rest of Asia |
|||||||||||||||||||||||||||||||||||||
Subsidiaries |
||||||||||||||||||||||||||||||||||||||||||
2013 |
||||||||||||||||||||||||||||||||||||||||||
Liquidsc |
105.86 | 102.72 | 91.88 | | 87.16 | 104.27 | | 108.24 | 100.41 | 99.24 | ||||||||||||||||||||||||||||||||
Gas |
9.43 | 10.18 | 3.07 | | 4.66 | 5.75 | | 4.99 | 10.55 | 5.35 | ||||||||||||||||||||||||||||||||
2012 |
||||||||||||||||||||||||||||||||||||||||||
Liquidsc |
109.64 | 106.93 | 96.35 | | 84.53 | 106.39 | | 109.69 | 103.12 | 102.10 | ||||||||||||||||||||||||||||||||
Gas |
8.62 | 9.43 | 2.32 | | 3.53 | 6.05 | | 5.08 | 10.08 | 4.75 | ||||||||||||||||||||||||||||||||
2011 |
||||||||||||||||||||||||||||||||||||||||||
Liquidsc |
106.89 | 107.83 | 96.34 | | 86.60 | 104.37 | | 111.10 | 101.22 | 101.29 | ||||||||||||||||||||||||||||||||
Gas |
7.91 | 13.15 | 3.34 | | 3.60 | 5.24 | | 4.73 | 9.13 | 4.69 | ||||||||||||||||||||||||||||||||
Equity-accounted entitiesd |
||||||||||||||||||||||||||||||||||||||||||
2013 |
||||||||||||||||||||||||||||||||||||||||||
Liquidsc |
| | | | 75.45 | | 95.28 | 11.58 | | 63.65 | ||||||||||||||||||||||||||||||||
Gas |
| | | | 4.05 | | 2.47 | 13.21 | | 3.26 | ||||||||||||||||||||||||||||||||
2012 |
||||||||||||||||||||||||||||||||||||||||||
Liquidsc |
| | | | 79.08 | | 83.85 | 10.15 | | 69.41 | ||||||||||||||||||||||||||||||||
Gas |
| | | | 2.35 | | 2.35 | 5.08 | | 2.52 | ||||||||||||||||||||||||||||||||
2011 |
||||||||||||||||||||||||||||||||||||||||||
Liquidsc |
| | | | 73.51 | | 84.39 | 8.11 | | 71.35 | ||||||||||||||||||||||||||||||||
Gas |
| | | | 2.31 | | 2.23 | 12.21 | | 2.40 |
a | Units of production are barrels for liquids and thousands of cubic feet for gas. Realizations include transfers between businesses. |
b | Amounts reported for Russia in 2013 include BPs share of Rosnefts worldwide activities, including insignificant amounts outside Russia. |
c | Crude oil, condensate and natural gas liquids. |
d | It is common for equity-accounted entities agreements to include pricing clauses that require selling a significant portion of the entitled production to local governments or markets at discounted prices. |
Average production cost per unit of productiona
$ per unit of production | ||||||||||||||||||||||||||||||||||||||||||
Europe |
North America |
South America |
Africa |
Asia |
Australasia |
Total group average |
||||||||||||||||||||||||||||||||||||
UK | Rest of Europe |
US | Rest of North America |
Russiab | Rest of Asia |
|||||||||||||||||||||||||||||||||||||
Subsidiaries |
||||||||||||||||||||||||||||||||||||||||||
2013 |
34.10 | 24.48 | 16.11 | | 5.92 | 13.84 | | 13.20 | 3.21 | 13.16 | ||||||||||||||||||||||||||||||||
2012 |
22.77 | 39.10 | 15.60 | | 5.69 | 11.89 | | 11.85 | 3.23 | 12.50 | ||||||||||||||||||||||||||||||||
2011 |
21.59 | 18.23 | 12.09 | | 3.20 | 10.82 | | 8.65 | 3.05 | 10.08 | ||||||||||||||||||||||||||||||||
Equity-accounted entities |
||||||||||||||||||||||||||||||||||||||||||
2013 |
| | | | 12.16 | | 4.36 | 4.19 | | 5.28 | ||||||||||||||||||||||||||||||||
2012 |
| | | | 11.33 | | 5.72 | 2.88 | | 5.76 | ||||||||||||||||||||||||||||||||
2011 |
| | | | 9.04 | | 5.68 | 2.70 | | 5.58 |
a | Units of production are barrels for liquids and thousands of cubic feet for gas. Amounts do not include ad valorem and severance taxes. |
b | Amounts reported for Russia in 2013 include BPs share of Rosnefts worldwide activities, including insignificant amounts outside Russia. |
BP Annual Report and Form 20-F 2013 | 251 |
The following table summarizes the groups principal contractual obligations at 31 December 2013, distinguishing between those for which a liability is recognized on the balance sheet and those for which no liability is recognized. Further information on borrowings is given in Financial statements Note 27 and more information on operating leases is given in Financial statements Note 9.
$ million | ||||||||||||||||||||||||||||||
Payments due by period | ||||||||||||||||||||||||||||||
Expected payments by period under contractual obligations | Total | 2014 | 2015 | 2016 | 2017 | 2018 | 2019 and thereafter |
|||||||||||||||||||||||
Balance sheet obligations |
||||||||||||||||||||||||||||||
Borrowingsa |
51,393 | 8,186 | 7,307 | 7,275 | 6,263 | 5,607 | 16,755 | |||||||||||||||||||||||
Finance lease future minimum lease paymentsb |
871 | 80 | 75 | 66 | 63 | 60 | 527 | |||||||||||||||||||||||
Decommissioning liabilitiesc |
20,850 | 988 | 731 | 699 | 568 | 865 | 16,999 | |||||||||||||||||||||||
Environmental liabilitiesc |
3,546 | 861 | 1,277 | 281 | 267 | 186 | 674 | |||||||||||||||||||||||
Pensions and other post-retirement benefitsd |
24,145 | 1,916 | 1,904 | 1,894 | 1,633 | 1,325 | 15,473 | |||||||||||||||||||||||
100,805 | 12,031 | 11,294 | 10,215 | 8,794 | 8,043 | 50,428 | ||||||||||||||||||||||||
Off-balance sheet obligations |
||||||||||||||||||||||||||||||
Operating lease future minimum lease paymentse |
19,186 | 5,188 | 3,790 | 2,871 | 2,117 | 1,630 | 3,590 | |||||||||||||||||||||||
Unconditional purchase obligationsf |
232,757 | 116,856 | 25,387 | 16,193 | 12,275 | 10,687 | 51,359 | |||||||||||||||||||||||
251,943 | 122,044 | 29,177 | 19,064 | 14,392 | 12,317 | 54,949 | ||||||||||||||||||||||||
Total |
352,748 | 134,075 | 40,471 | 29,279 | 23,186 | 20,360 | 105,377 |
a | Expected payments include interest totalling $3,736 million ($846 million in 2014, $717 million in 2015, $588 million in 2016, $468 million in 2017, $360 million in 2018 and $757 million thereafter). |
252 | BP Annual Report and Form 20-F 2013 |
b | Expected payments include interest totalling $336 million ($39 million in 2014, $35 million in 2015, $33 million in 2016, $30 million in 2017, $28 million in 2018 and $171 million thereafter). |
c | The amounts are undiscounted. Environmental liabilities include those relating to the Gulf of Mexico oil spill, including liabilities for spill response costs. |
d | Represents the expected future contributions to funded pension plans and payments by the group for unfunded pension plans and the expected future payments for other post-retirement benefits. |
e | The future minimum lease payments are before deducting related rental income from operating sub-leases. In the case of an operating lease entered into solely by BP as the operator of a joint operation, the amounts shown in the table represent the net future minimum lease payments, after deducting amounts reimbursed, or to be reimbursed, by joint operation partners. Where BP is not the operator of a joint operation BPs share of the future minimum lease payments are included in the amounts shown, whether BP has co-signed the lease or not. Where operating lease costs are incurred in relation to the hire of equipment used in connection with a capital project, some or all of the cost may be capitalized as part of the capital cost of the project. |
f | Represents any agreement to purchase goods or services that is enforceable and legally binding and that specifies all significant terms. The amounts shown include arrangements to secure long-term access to supplies of crude oil, natural gas, feedstocks and pipeline systems. In addition, the amounts shown for 2014 include purchase commitments existing at 31 December 2013 entered into principally to meet the groups short-term manufacturing and marketing requirements. The price risk associated with these crude oil, natural gas and power contracts is discussed in Financial statements Note 19. |
The following table summarizes the nature of the groups unconditional purchase obligations.
$ million | ||||||||||||||||||||||||||||||
Payments due by period | ||||||||||||||||||||||||||||||
Unconditional purchase obligations | Total | 2014 | 2015 | 2016 | 2017 | 2018 | 2019 and thereafter |
|||||||||||||||||||||||
Crude oil and oil products |
133,774 | 84,558 | 13,854 | 9,026 | 6,533 | 5,281 | 14,522 | |||||||||||||||||||||||
Natural gas |
37,005 | 23,417 | 5,612 | 2,751 | 1,768 | 1,309 | 2,148 | |||||||||||||||||||||||
Chemicals and other refinery feedstocks |
17,005 | 3,976 | 3,190 | 2,590 | 2,306 | 2,248 | 2,695 | |||||||||||||||||||||||
Power |
3,208 | 2,067 | 794 | 250 | 97 | | | |||||||||||||||||||||||
Utilities |
796 | 200 | 168 | 108 | 83 | 73 | 164 | |||||||||||||||||||||||
Transportation |
22,727 | 1,589 | 1,084 | 965 | 1,041 | 1,031 | 17,017 | |||||||||||||||||||||||
Use of facilities and services |
18,242 | 1,049 | 685 | 503 | 447 | 745 | 14,813 | |||||||||||||||||||||||
Total |
232,757 | 116,856 | 25,387 | 16,193 | 12,275 | 10,687 | 51,359 |
The information above 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 the cautionary statement on page 271 and Risk factors on page 51, 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.
BP Annual Report and Form 20-F 2013 | 253 |
254 | BP Annual Report and Form 20-F 2013 |
BP Annual Report and Form 20-F 2013 | 255 |
256 | BP Annual Report and Form 20-F 2013 |
BP Annual Report and Form 20-F 2013 | 257 |
258 | BP Annual Report and Form 20-F 2013 |
BP Annual Report and Form 20-F 2013 | 259 |
260 | BP Annual Report and Form 20-F 2013 |
BP Annual Report and Form 20-F 2013 | 261 |
262 | BP Annual Report and Form 20-F 2013 |
BP Annual Report and Form 20-F 2013 | 263 |
264 | BP Annual Report and Form 20-F 2013 |
BP Annual Report and Form 20-F 2013 | 265 |
266 | BP Annual Report and Form 20-F 2013 |
BP Annual Report and Form 20-F 2013 | 267 |
268 | BP Annual Report and Form 20-F 2013 |
BP Annual Report and Form 20-F 2013 | 269 |
270 | BP Annual Report and Form 20-F 2013 |
BP Annual Report and Form 20-F 2013 | 271 |
272 | BP Annual Report and Form 20-F 2013 |
BP Annual Report and Form 20-F 2013 | 273 |
Pence | Dollars | |||||||||||||||||
Ordinary shares | American depositary sharesa | |||||||||||||||||
High | Low | High | Low | |||||||||||||||
Year ended 31 December |
||||||||||||||||||
2009 |
613.40 | 400.00 | 60.00 | 33.70 | ||||||||||||||
2010 |
658.20 | 296.00 | 62.38 | 26.75 | ||||||||||||||
2011 |
514.90 | 361.25 | 49.50 | 33.62 | ||||||||||||||
2012 |
512.00 | 388.56 | 48.34 | 36.25 | ||||||||||||||
2013 |
494.20 | 426.50 | 48.65 | 39.99 | ||||||||||||||
Year ended 31 December |
||||||||||||||||||
2012: First quarter |
512.00 | 455.05 | 48.34 | 42.53 | ||||||||||||||
Second quarter |
475.47 | 388.56 | 45.60 | 36.25 | ||||||||||||||
Third quarter |
456.00 | 415.60 | 44.16 | 39.13 | ||||||||||||||
Fourth quarter |
464.71 | 416.35 | 43.90 | 39.58 | ||||||||||||||
2013: First quarter |
482.33 | 426.50 | 45.45 | 39.99 | ||||||||||||||
Second quarter |
485.43 | 437.25 | 44.27 | 40.12 | ||||||||||||||
Third quarter |
477.53 | 430.30 | 43.75 | 40.51 | ||||||||||||||
Fourth quarter |
494.20 | 426.55 | 48.65 | 41.30 | ||||||||||||||
2014: First quarter (to 18 February) |
499.90 | 463.80 | 49.63 | 45.83 | ||||||||||||||
Month of |
||||||||||||||||||
September 2013 |
458.28 | 430.85 | 42.86 | 41.08 | ||||||||||||||
October 2013 |
491.27 | 426.55 | 46.65 | 41.30 | ||||||||||||||
November 2013 |
494.20 | 474.10 | 48.03 | 45.72 | ||||||||||||||
December 2013 |
491.26 | 464.15 | 48.65 | 45.30 | ||||||||||||||
January 2014 |
499.90 | 470.15 | 49.20 | 46.62 | ||||||||||||||
February 2014 (to 18 February) |
495.85 | 463.80 | 49.63 | 45.83 |
a | One ADS is equivalent to six 25 cent ordinary shares. |
Source: | Thomson Reuters Datastream. |
274 | BP Annual Report and Form 20-F 2013 |
BP Annual Report and Form 20-F 2013 | 275 |
276 | BP Annual Report and Form 20-F 2013 |
BP Annual Report and Form 20-F 2013 | 277 |
Purchases of equity securities by the issuer and affiliated purchasers
On 22 March 2013 BP announced the start of a share repurchase, or buyback, programme (the buyback programme). The buyback programme is expected to return up to $8 billion to BP shareholders. As at 18 February 2014 the total number of ordinary shares repurchased under the buyback programme since 22 March 2013 was 947,930,354 at a cost of $7,065 million including transaction costs. The following table provides details of this share repurchase activity under the buyback programme as well as details of ordinary share purchases made by the Employee Share Ownership Plans (ESOPs) and other purchases of ordinary shares and ADSs made to satisfy the requirements of certain employee share-based payment plans.
|
Total number of shares purchased |
a |
|
Average price paid per share $ |
|
|
Number of
shares by ESOPs or for |
|
|
Number of shares part of publicly announced programmes |
c |
|
Maximum approximate dollar value of shares that may yet be purchased under the programme $ million |
| ||||||||
2013 |
||||||||||||||||||||||
January |
| | | | | |||||||||||||||||
February |
| | | | | |||||||||||||||||
March 22 March 28 |
21,400,000 | 7.04 | | 21,400,000 | 7,849 | |||||||||||||||||
April 2 April 30 |
102,573,190 | 6.94 | 1,800,000 | 100,773,190 | 7,150 | |||||||||||||||||
May 1 May 31 |
91,671,000 | 7.25 | | 91,671,000 | 6,485 | |||||||||||||||||
June 3 June 28 |
74,649,000 | 7.14 | | 74,649,000 | 5,952 | |||||||||||||||||
July 1 July 31 |
66,536,585 | 7.07 | | 66,536,585 | 5,482 | |||||||||||||||||
August 1 August 31 |
57,395,332 | 6.90 | 10,245,332 | 47,150,000 | 5,155 | |||||||||||||||||
September 2 September 30 |
64,540,000 | 7.08 | 1,860,000 | 62,680,000 | 4,711 | |||||||||||||||||
October 1 October 31 |
92,100,761 | 7.22 | 1,020,000 | 91,080,761 | 4,053 | |||||||||||||||||
November 1 November 29 |
129,680,000 | 7.87 | | 129,680,000 | 3,032 | |||||||||||||||||
December 2 December 31 |
99,933,273 | 7.83 | 32,700,000 | 67,233,273 | 2,507 | |||||||||||||||||
2014 |
||||||||||||||||||||||
January 2 January 31 |
162,240,000 | 8.09 | | 162,240,000 | 1,194 | |||||||||||||||||
February 3 to February 18 |
34,836,545 | 7.92 | 2,000,000 | 32,836,545 | 934 |
a | All share purchases were of ordinary shares of 25 cents each and/or ADSs (each representing six ordinary shares) and were on/open market transactions. |
b | Transactions represent the purchase of ordinary shares by ESOPs and other purchases of ordinary shares and ADSs made to satisfy requirements of certain employee share-based payment plans. |
c | At the AGMs on 12 April 2012 and 11 April 2013, authorization was given in each case to repurchase up to 1.9 billion ordinary shares in the period to the next AGM in 2013 and 2014, respectively or 12 July 2013 and 11 July 2014, respectively, being the latest dates by which an AGM must be held for the relevant year. This authorization is renewed annually at the AGM. All shares were purchased for cancellation to reduce BPs issued share capital. The total number of ordinary shares purchased during 2013 under the buyback programme was 752,853,809 at a cost of $5,493 million (including transaction costs) representing 4.04% of BPs issued share capital excluding shares held in treasury on 31 December 2013. |
Fees and charges payable by ADSs holders
The Depositary collects fees for delivery and surrender of ADSs directly from investors depositing shares or surrendering ADSs for the purpose of withdrawal or from intermediaries acting for them. The Depositary collects fees for making distributions to investors by deducting those fees from the amounts distributed or by selling a portion of the distributable property to pay the fees.
The charges of the Depositary payable by investors are as follows:
Type of service | Depositary actions | Fee | ||||||
Depositing or substituting the underlying shares | Issuance of ADSs against the deposit of shares, including deposits and issuances in respect of: Share distributions, stock splits, rights, merger. Exchange of securities or other transactions or event or other distribution affecting the ADSs or deposited securities. |
$5.00 per 100 ADSs (or portion thereof) evidenced by the new ADSs delivered. | ||||||
Selling or exercising rights | Distribution or sale of securities, the fee being in an amount equal to the fee for the execution and delivery of ADSs that would have been charged as a result of the deposit of such securities. | $5.00 per 100 ADSs (or portion thereof). | ||||||
Withdrawing an underlying share | Acceptance of ADSs surrendered for withdrawal of deposited securities. | $5.00 for each 100 ADSs (or portion thereof) evidenced by the ADSs surrendered. | ||||||
Expenses of the Depositary | Expenses incurred on behalf of holders in connection with: Stock transfer or other taxes and governmental charges. Cable, telex, electronic and facsimile transmission, delivery. Transfer or registration fees, if applicable, for the registration of transfers of underlying shares. Expenses of the Depositary in connection with the conversion of foreign currency into US dollars (which are paid out of such foreign currency). |
Expenses payable at the sole discretion of the Depositary by billing holders or by deducting charges from one or more cash dividends or other cash distributions. |
278 | BP Annual Report and Form 20-F 2013 |
BP Annual Report and Form 20-F 2013 | 279 |
The Directors report on pages 59-80, 109-114, 116, 200-223 and 235-280 was approved by the board and signed on its behalf by David J Jackson, Company Secretary on 6 March 2014.
BP p.l.c.
Registered in England and Wales No. 102498
280 | BP Annual Report and Form 20-F 2013 |
Signatures
The registrant hereby certifies that it meets all of the requirements for filing on Form 20-F and that it has duly caused and authorized the undersigned to sign this annual report on its behalf.
BP p.l.c.
(Registrant)
/s/ David J Jackson
Company Secretary
6 March 2014
BP Annual Report and Form 20-F 2013 | 281 |
Page | ||||||||
Item 1. |
Identity of Directors, Senior Management and Advisors | n/a | ||||||
Item 2. |
Offer Statistics and Expected Timetable | n/a | ||||||
Item 3. |
Key Information | |||||||
A. |
Selected financial data | 236 | ||||||
B. |
Capitalization and indebtedness | n/a | ||||||
C. |
Reasons for the offer and use of proceeds | n/a | ||||||
D. |
Risk factors | 51-55 | ||||||
Item 4. |
Information on the Company | |||||||
A. |
History and development of the company | ii, 2-40, 56-58, 236, 239-243 | ||||||
B. |
Business overview | 2-5, 10-19, 23-58, 149-154, 239-257, 269-271 | ||||||
C. |
Organizational structure | 193 | ||||||
D. |
Property, plants and equipment | 25-37, 191, 222-223, 239-251, 268 | ||||||
Item 4A. |
Unresolved Staff Comments | None | ||||||
Item 5. |
Operating and Financial Review and Prospects | |||||||
A. |
Operating results | |
23-25, 27-28, 31-33, 36-37, 40, 56-58,
126, 252 |
| ||||
B. |
Liquidity and capital resources | |
56-58, 75, 132-133, 161, 166-170, 172-176, 191 |
| ||||
C. |
Research and development, patent and licenses | 16-17, 35, 37, 154 | ||||||
D. |
Trend information | 10-11, 22-37 | ||||||
E. |
Off-balance sheet arrangements | 57, 252-253 | ||||||
F. |
Tabular disclosure of contractual commitments | 57, 252-253 | ||||||
G. |
Safe harbor | n/a | ||||||
Item 6. |
Directors, Senior Management and Employees | |||||||
A. |
Directors and senior management | 60-68 | ||||||
B. |
Compensation | 82-108, 158, 178-181, 190 | ||||||
C. |
Board practices | 61-65, 71, 74-80, 90, 105, 108 | ||||||
D. |
Employees | 47-48, 189-190 | ||||||
E. |
Share ownership | 48, 91, 93-95, 189-190 | ||||||
Item 7. |
Major Shareholders and Related Party Transactions | |||||||
A. |
Major shareholders | 277 | ||||||
B. |
Related party transactions | 163-166, 268 | ||||||
C. |
Interests of experts and counsel | n/a | ||||||
Item 8. |
Financial Information | |||||||
A. |
Consolidated statements and other financial information | 56, 120-199, 257-268, 274-275 | ||||||
B. |
Significant changes | None | ||||||
Item 9. |
The Offer and Listing | |||||||
A. |
Offer and listing details | 274 | ||||||
B. |
Plan of distribution | n/a | ||||||
C. |
Markets | 274 | ||||||
D. |
Selling shareholders | n/a | ||||||
E. |
Dilution | n/a | ||||||
F. |
Expenses of the issue | n/a | ||||||
Item 10. |
Additional Information | |||||||
A. |
Share capital | n/a | ||||||
B. |
Memorandum and articles of association | 112-114 | ||||||
C. |
Material contracts | 268 | ||||||
D. |
Exchange controls | 275 | ||||||
E. |
Taxation | 275-276 | ||||||
F. |
Dividends and paying agents | n/a | ||||||
G. |
Statements by experts | n/a | ||||||
H. |
Documents on display | 279 | ||||||
I. |
Subsidiary information | 193 | ||||||
Item 11. |
Quantitative and Qualitative Disclosures about Market Risk | 166-170, 172-176 | ||||||
Item 12. |
Description of securities other than equity securities | |||||||
A. |
Debt Securities | n/a | ||||||
B. |
Warrants and Rights | n/a | ||||||
C. |
Other Securities | n/a | ||||||
D. |
American Depositary Shares | 278-279 | ||||||
Item 13. |
Defaults, Dividend Arrearages and Delinquencies | None | ||||||
Item 14. |
Material Modifications to the Rights of Security Holders and Use of Proceeds | None | ||||||
Item 15. |
Controls and Procedures | 111, 121 | ||||||
Item 16A. |
Audit Committee Financial Expert | 74 | ||||||
Item 16B. |
Code of Ethics | 111 | ||||||
Item 16C. |
Principal Accountant Fees and Services | 111, 192 | ||||||
Item 16D. |
Exemptions from the Listing Standards for Audit Committees | n/a | ||||||
Item 16E. |
Purchases of Equity Securities by the Issuer and Affiliated Purchasers | 278 | ||||||
Item 16F. |
Change in Registrants Certifying Accountant | None | ||||||
Item 16G. |
Corporate governance | 110-111 | ||||||
Item 17. |
Financial Statements | n/a | ||||||
Item 18. |
Financial Statements | 120-199 | ||||||
Item 19. |
Exhibits | 269 |
282 | BP Annual Report and Form 20-F 2013 |
BPs corporate reporting suite includes information about our
financial and operating performance, sustainability performance
and also on global energy trends and projections.
Annual Report and Form 20-F 2013 Details of our financial and operating performance in print or online. Published in March. bp.com/annualreport |
Strategic Report 2013 A summary of our financial and operating performance in print or online. Published in March. bp.com/annualreport |
Energy Outlook 2035 Projections for world energy markets, considering the potential evolution of global economy, population, policy and technology. Published in January. bp.com/energyoutlook | ||||||||
Sustainability Review 2013 A summary of our sustainability reporting with additional information online. Published in March. bp.com/sustainability |
Financial and Operating Information 2009-2013 Five-year financial and operating data in PDF or Excel format. Published in April. bp.com/financialandoperating |
Statistical Review of World Energy 2014 An objective review of key global energy trends. Published in June. bp.com/statisticalreview |
You can order BPs printed publications free of charge from: |
US and Canada Precision IR Toll-free: +1 888 301 2505 Fax: +1 804 327 7549 bpreports@precisionir.com
UK and rest of world BP Distribution Services Tel: +44 (0)870 241 3269 Fax: +44 (0)870 240 5753 bpdistributionservices@bp.com |
Feedback Your feedback is important to us. You can email the corporate reporting team at corporatereporting@bp.com
or provide your feedback online at bp.com/annualreportfeedback |
You can also telephone +44 (0)20 7496 4000
or write to: Corporate reporting BP p.l.c. 1 St Jamess Square London SW1Y 4PD UK |
Acknowledgements | Paper | © BP p.l.c. 2014 | ||||
Design Typesetting Printing |
Salterbaxter RR Donnelley Pureprint Group Limited, UK, ISO 14001, FSC® certified and CarbonNeutral® |
This document is printed on Oxygen paper and board. Oxygen is made using 100% recycled pulp, a large percentage of which is de-inked. It is manufactured at a mill with ISO 9001 and 14001 accreditation and is FSC® (Forest Stewardship Council) certified. This document has been printed using vegetable inks.
Printed in the UK by Pureprint Group using their alcofree and pureprint printing technology. |
||||
Photography | Shahin Abasaliyev, Pankaj Anand, Moritz Brilo, Jon Challicom, Stuart Conway, Richard Davies, Joshua Drake, Rocky Kneten, Simon Kreitem, Kate Kunz, Andy McAuslan, Marc Morrison, Aaron Tait, Bob Wheeler |
Exhibit 4.3
THIS AGREEMENT is made on 25th February 2014
BETWEEN:
(1) | BP CORPORATION NORTH AMERICA INC. an Illinois corporation of 4101 Winfield Road, Warrenville, Illinois 60555 (the Company); and |
(2) | BP plc a company incorporated in England and Wales of 1 St Jamess Square, London, SW1Y 4PD (the Parent). |
WHEREAS the Company has agreed that it will supply to the Parent assistance by seconding its employee ROBERT W DUDLEY (the Secondee) to the Company in accordance with the terms and conditions of an agreement dated 15th April 2009, (Agreement) under the terms of which the secondment would be for a period of three years from the date of the Agreement. By a further agreement dated 26 March 2012, the parties extended the term of the secondment by a further two years and now wish to extend this term by a further five years and have agreed with terms set out below.
NOW IT IS HEREBY AGREED AS FOLLOWS:
1. | Clause 1.2 of the Agreement shall be deleted and replaced with the following: |
Subject to any earlier termination in accordance with Clause 7 below, the secondment shall be for a period of five years from 15th April 2014. Prior to the expiration of the five year period the Parent may, upon giving written notice to the Company, extend the secondment in which case the secondment shall continue in accordance with the terms and conditions of this Agreement.
2. | This Agreement shall take effect on 15th April 2014. All other terms and conditions of the Agreement shall continue in full force and effect. |
IN WITNESS WHEREOF this agreement has been executed by the parties hereto and is hereby delivered on the date first above written.
SIGNED by Steven L. Bray |
) | /s/ Steven L. Bray | ||||
for and on behalf of |
) | |||||
BP CORPORATION NORTH AMERICA INC |
) | |||||
in the presence of: /s/ Mary Jane Stricker |
) | |||||
SIGNED by Jens Bertelsen |
) | /s/ Jens Bertelsen | ||||
for and on behalf of |
) | |||||
BP p.l.c. |
) | |||||
in the presence of: /s/ Mary Jane Stricker |
) |
Exhibit 7
Computation of ratio of earnings to fixed charges (unaudited)
$ million, except ratios | ||||||||||||||||||||
2013 | 2012 | 2011 | 2010 | 2009 | ||||||||||||||||
Earnings available for fixed charges: |
||||||||||||||||||||
Pre-tax income (loss) from continuing operations before adjustment for income or loss from joint ventures and associates (a) (b) |
27,032 | 14,196 | 32,545 | (10,064 | ) | 20,916 | ||||||||||||||
Fixed charges |
3,021 | 2,971 | 2,808 | 2,944 | 2,279 | |||||||||||||||
Amortization of capitalized interest |
226 | 145 | 44 | 212 | 252 | |||||||||||||||
Distributed income of joint ventures and associates |
1,391 | 1,763 | 5,040 | 3,277 | 3,003 | |||||||||||||||
Interest capitalized |
(238 | ) | (390 | ) | (349 | ) | (254 | ) | (188 | ) | ||||||||||
Preference dividend requirements, gross of tax |
(2 | ) | (3 | ) | (3 | ) | (2 | ) | (3 | ) | ||||||||||
Income of non-controlling interests not inccuring fixed charges |
| | | (9 | ) | (1 | ) | |||||||||||||
|
|
|
|
|
|
|
|
|
|
|||||||||||
Total earnings available for fixed charges |
31,430 | 18,682 | 40,085 | (3,896 | ) | 26,258 | ||||||||||||||
|
|
|
|
|
|
|
|
|
|
|||||||||||
Fixed charges: |
||||||||||||||||||||
Interest expensed |
844 | 844 | 802 | 701 | 718 | |||||||||||||||
Interest capitalized |
238 | 390 | 349 | 254 | 188 | |||||||||||||||
Rental expense representative of interest |
1,937 | 1,734 | 1,654 | 1,987 | 1,370 | |||||||||||||||
Preference dividend requirements, gross of tax |
2 | 3 | 3 | 2 | 3 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|||||||||||
Total fixed charges |
3,021 | 2,971 | 2,808 | 2,944 | 2,279 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|||||||||||
Ratio of earnings to fixed charges |
10.4 | 6.3 | 14.3 | | 11.5 | |||||||||||||||
Deficiency of earnings to fixed charges |
| | | (6,840 | ) | |
(a) | 2013 includes a pre-tax charge of $469 million (2012 $5,014 million pre-tax charge, 2011 $3,742 million pre-tax credit and 2010 $40,935 million pre-tax charge) relating to the Gulf of Mexico oil spill. |
(b) | 2012 includes $709 million of dividends received from TNK-BP. |
Exhibit 12
EXHIBIT 12
Rule 13a14(a) Certificates
I, Robert Dudley, certify that:
1. I have reviewed this annual report on Form 20-F of BP p.l.c.;
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the company as of, and for, the periods presented in this report;
4. The companys other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the company and have:
(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the company, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
(c) Evaluated the effectiveness of the companys disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
(d) Disclosed in this report any change in the companys internal control over financial reporting that occurred during the period covered by the annual report that has materially affected, or is reasonably likely to materially affect, the companys internal control over financial reporting; and
5. The companys other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the companys auditors and the audit committee of the companys board of directors (or persons performing the equivalent functions):
(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the companys ability to record, process, summarize and report financial information; and
(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the companys internal control over financial reporting.
Date: 6 March 2014 |
/s/ Robert Dudley | |
Robert Dudley | ||
Group Chief Executive |
I, Brian Gilvary, certify that:
1. I have reviewed this annual report on Form 20-F of BP p.l.c.;
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the company as of, and for, the periods presented in this report;
4. The companys other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the company and have:
(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the company, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
(c) Evaluated the effectiveness of the companys disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
(d) Disclosed in this report any change in the companys internal control over financial reporting that occurred during the period covered by the annual report that has materially affected, or is reasonably likely to materially affect, the companys internal control over financial reporting; and
5. The companys other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the companys auditors and the audit committee of the companys board of directors (or persons performing the equivalent functions):
(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the companys ability to record, process, summarize and report financial information; and
(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the companys internal control over financial reporting.
Date: 6 March 2014 |
/s/ Brian Gilvary | |
Brian Gilvary | ||
Chief Financial Officer |
EXHIBIT 13
Rule 13a 14(b) Certificates
Certification
Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
(Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code)
Pursuant to section 906 of the Sarbanes-Oxley Act of 2002 (subsections (a) and (b) of section 1350, chapter 63 of title 18, United States Code), the undersigned officer of BP p.l.c., a company incorporated under the laws of England and Wales (the company), hereby certifies, to such officers knowledge, that:
The Annual Report on Form 20-F for the year ended December 31, 2013 (the Report) of the company fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934 and information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the company.
Date: 6 March 2014
/s/ Robert Dudley |
Robert Dudley |
Group Chief Executive |
The foregoing certification is being furnished solely pursuant to section 906 of the Sarbanes-Oxley Act of 2002 (subsections (a) and (b) of section 1350, chapter 63 of title 18, United States Code) and is not being filed as part of the Report or as a separate disclosure document.
A signed original of this written statement required by Section 906 has been provided to the company and will be retained by the company and furnished to the Securities and Exchange Commission or its staff upon request.
Certification
Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
(Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code)
Pursuant to section 906 of the Sarbanes-Oxley Act of 2002 (subsections (a) and (b) of section 1350, chapter 63 of title 18, United States Code), the undersigned officer of BP p.l.c., a company incorporated under the laws of England and Wales (the company), hereby certifies, to such officers knowledge, that:
The Annual Report on Form 20-F for the year ended December 31, 2013 (the Report) of the company fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934 and information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the company.
Dated: 6 March 2014
/s/ Brian Gilvary |
Brian Gilvary |
Chief Financial Officer |
The foregoing certification is being furnished solely pursuant to section 906 of the Sarbanes-Oxley Act of 2002 (subsections (a) and (b) of section 1350, chapter 63 of title 18, United States Code) and is not being filed as part of the Report or as a separate disclosure document.
A signed original of this written statement required by Section 906 has been provided to the company and will be retained by the company and furnished to the Securities and Exchange Commission or its staff upon request.
Exhibit 15.1
DEGOLYER AND MACNAUGHTON
5001 SPRING VALLEY ROAD
SUITE 800 EAST
DALLAS, TEXAS 75244
March 6, 2014
BP p.l.c.
1 St. James Square
London, SW1Y 4PD
Ladies and Gentlemen:
We hereby consent to the reference to DeGolyer and MacNaughton contained in the section entitled Oil and gas disclosures for the group of the Annual Report and Form 20-F for the year ended December 31, 2013, of BP p.l.c. (the Form 20-F), as set forth under the heading Compliance, page 246, to the inclusion of our third-party report dated January 26, 2014, concerning our estimates of the net proved crude oil, condensate, natural gas liquids, and natural gas reserves, as of December 31, 2013, of certain properties owned by OAO NK Rosneft (Third-Party Report), which is included as an exhibit to the Form 20-F, and to the incorporation by reference of the reference to DeGolyer and MacNaughton in the Form 20-F and of the Third Party Report in the following Registration Statements:
Registration Statement on Form F-3 (File Nos. 333-179953 and 333-179953-01) of BP p.l.c. and BP Capital Markets p.l.c.; and
Registration Statements on Form S-8 (File Nos. 333-149778, 333-79399, 333-67206, 333-103924, 333-123482, 333-123483, 333-131583, 333-146868, 333-146870, 333-146873, 333-131584, 333-132619, 333-173136, 333-177423, 333-179406, 333-186463, and 333-186462) of BP p.l.c.
Very truly yours, |
/s/ DeGolyer and MacNaughton |
DeGOLYER and MacNAUGHTON |
Texas Registered Engineering Firm F-716 |
Exhibit 15.2
DEGOLYER AND MACNAUGHTON
5001 SPRING VALLEY ROAD
SUITE 800 EAST
DALLAS, TEXAS 75244
January 26, 2014
BP Russian Investments Limited
Chertsey Road
Sunbury on Thames, Middlesex, TW16 7BP
Ladies and Gentlemen:
Pursuant to the request of OAO NK Rosneft (Rosneft), we have estimated the net proved crude oil, condensate, natural gas liquids (NGL), and natural gas reserves, as of December 31, 2013, of certain properties owned by Rosneft. This evaluation was completed on January 13, 2014. At the request of BP Russian Investments Limited (BP), a wholly-owned subsidiary of BP p.l.c., this report was prepared in accordance with guidelines specified in Item 1202(a)(8) of Regulation SK and is to be used for inclusion in certain United States Securities and Exchange Commission (SEC) filings by BP p.l.c. The properties evaluated consist of working interests located in the Russian Federation, Algeria, Canada, Venezuela, and Vietnam. Rosneft has represented that it owns an interest in certain fields located in the Russian Federation either directly or through various subsidiary enterprises. Rosneft has represented that all fields are held at 100 percent by the respective subsidiary enterprise. Rosneft has represented that its ownership in all the subsidiary enterprises ranges between 16.67 and 100 percent.
Also included in this report are interests held through 3 production sharing agreements (PSA) and 10 joint ventures (JV). As represented by Rosneft, the PSA holdings include projects in Russia, Algeria, and Vietnam. The JV holdings include five in Russia, four in Venezuela, and one in Canada.
These subsidiary enterprises, the Rosneft direct holdings in the Russian Federation (including those in the Chechen Republic), the Russian PSA, the Algerian PSA, the Vietnam PSA, the Russian JVs, the Venezuela JVs, and the Canadian JV are collectively referred to hereinafter as Rosneft Holdings. BP has represented that it owns a 19.75-percent interest in Rosneft Holdings.
Rosneft has represented that these properties account for 100 percent of Rosnefts net proved reserves as of December 31, 2013. The net proved reserves estimates prepared by us have been prepared in accordance with the reserves definitions of Rules 410(a) (1)(32) of Regulation SX of the SEC.
Certain properties in which Rosneft has an interest are subject to the terms of various PSAs. The terms of these PSAs generally allow for working interest participants to be reimbursed for portions of capital costs and operating expenses and to share in the profits. The reimbursements and profit proceeds are converted to a barrel of oil equivalent or standard cubic foot of gas equivalent by dividing by product prices to determine the entitlement reserves. These entitlement reserves are equivalent in principle to net reserves and are used to calculate an equivalent net share, termed an entitlement interest. In this report, Rosneft net reserves or interest for certain properties subject to these PSAs is the entitlement based on Rosnefts working interest. For the Algerian PSA, the proved reserves were estimated to be zero.
The estimated reserves and associated values are reported herein at 100 percent for those subsidiaries of which Rosneft has majority control, either through direct ownership or through voting rights. The estimated reserves and values for those subsidiaries which Rosneft does not control are reported at Rosnefts ownership interest. All of the fields evaluated are located in the Russian Federation, Algeria, Canada, Venezuela, or Vietnam.
1
DEGOLYER AND MACNAUGHTON
Rosneft has represented that the Russian Law on Subsoil provides for the extension of production licenses at the request of the license holder if there exists economic reserves upon the expiration of the primary term, provided the license holder is in material compliance with the terms of the existing license. We understand that the principal requirements for license extension are that the license holder complies with the material terms of the license and that mineral extraction has not been completed. As in the past, Rosneft is required to submit to the appropriate government agency for approval, prior to production, individual field development plans based on the economic life of the field and not based on the term of the associated license. Rosneft has represented that upon completion of the primary term of its current licenses, each of the subsidiary enterprises intends to continue to extend these licenses until the end of the economic life of the associated fields, and that they intend to proceed accordingly with development and operation of these fields. Based on these representations we have included as proved reserves those volumes that are estimated to be economically producible from the fields evaluated after the expiration of the primary term of their licenses.
Reserves included herein are expressed as net reserves owned or controlled by Rosneft (Rosneft net). Gross reserves are defined as the total estimated petroleum to be produced from these properties after December 31, 2013. Net reserves are defined as that portion of the gross reserves attributable to the interests owned by Rosneft after deducting all interests owned by others. For the PSAs, these reserves are expressed in terms of the barrel equivalent of the cost recovery and profit share (entitlement) after deducting interests owned by others.
Estimates of oil, condensate, NGL, and gas reserves should be regarded only as estimates that may change as further production history and additional information become available. Not only are such reserves estimates based on that information which is currently available, but such estimates are also subject to the uncertainties inherent in the application of judgmental factors in interpreting such information.
Data used in our estimates were obtained from Rosneft and public sources. In the preparation of this report we have relied, without independent verification, upon such information furnished by Rosneft with respect to ownership, production, current costs of operation and development, current prices for production, agreements relating to current and future operations and sale of production, and various other information and data that were accepted as represented. A field examination of the properties was not considered necessary for the purposes of this report.
Methodology and Procedures
Estimates of reserves were prepared by the use of appropriate geologic, petroleum engineering, and evaluation principles and techniques that are in accordance with practices generally recognized by the petroleum industry as presented in the publication of the Society of Petroleum Engineers entitled Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (Revision as of February 19, 2007). The method or combination of methods used in the analysis of each reservoir was tempered by experience with similar reservoirs, stage of development, quality and completeness of basic data, and production history.
The volumetric method was used to estimate the original oil in place (OOIP) and the original gas in place (OGIP). Structure and isopach maps were constructed to estimate reservoir volume. Electrical logs, radioactivity logs, core analyses, and other available data were used to prepare these maps as well as to estimate representative values for porosity and water saturation.
Estimates of ultimate recovery were obtained after applying recovery factors to OOIP or OGIP. These recovery factors were based on consideration of the type of energy inherent in the reservoirs, analyses of the petroleum, the structural positions of the properties, and the production histories. In certain cases, recovery factors were estimated by analogy with similar wells or reservoirs for which more complete data were available.
2
DEGOLYER AND MACNAUGHTON
For the Vietnam fields, a Rosneft-supplied reservoir simulation model was reviewed and used to estimate recovery factors. In this case, an analysis of reservoir performance, including production rate, wellhead pressure, and gas-condensate ratio behavior, was used in the estimation of reserves.
For depletion-type reservoirs or those whose performance disclosed a reliable decline in producing-rate trends or other diagnostic characteristics, reserves were estimated by the application of appropriate decline curves. In the analyses of production-decline curves, reserves were estimated only to the limits of economic production or to the limit of the production licenses as appropriate.
Gas reserves estimated herein are reported as fuel-gas, sales-gas, and marketable-gas volumes. Fuel gas is either that portion of the total volume of gas to be produced from the reservoirs used in the operation of the field, or in certain cases it represents the estimated volume of gas utilized in existing and future power-generation plants. Rosneft provided information about currently operating and future plants, including schedule of operation, plant inlet rates, fields associated with each plant, and pertinent economic parameters. Sales gas is defined as the total volume of gas to be produced from the reservoirs, measured at the point of delivery, available for sales, after deductions for various losses and usage. Sales gas is made up of associated gas, including gas-cap and solution gas, from certain oil fields and nonassociated gas from certain oil fields and the gas fields. Marketable gas is defined as the sum of fuel gas and sales gas. Gas reserves estimated herein are expressed at a temperature base of 20 degrees Centigrade (°C) and 1 atmosphere. Estimates of gas reserves are expressed herein in millions of cubic feet (106ft3).
The fuel gas quantities included as a portion of Rosnefts marketable gas reserves are as follows, expressed in millions of cubic feet (106ft3):
Fuel Gas Portion of Marketable Gas Reserves |
||||
Net (106ft3) |
||||
Proved |
||||
Developed |
1,468,089 | |||
Undeveloped |
350,639 | |||
|
|
|||
Total Proved |
1,818,728 |
Definition of Reserves
Petroleum reserves estimated by us and included in this report are classified as proved. Only proved reserves have been evaluated for this report. Reserves classifications used by us in this report are in accordance with the reserves definitions of Rules 410(a) (1)(32) of Regulation SX of the SEC. Reserves are judged to be economically producible in future years from known reservoirs under existing economic and operating conditions and assuming continuation of current regulatory practices using conventional production methods and equipment. In the analyses of production-decline curves, reserves were estimated only to the limit of economic rates of production under existing economic and operating conditions using prices and costs consistent with the effective date of this report, including consideration of changes in existing prices provided only by contractual arrangements but not including escalations based upon future conditions. The petroleum reserves are classified as follows:
Proved oil and gas reservesProved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically produciblefrom a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulationsprior to the time at which contracts providing the right to
3
DEGOLYER AND MACNAUGHTON
operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.
(i) The area of the reservoir considered as proved includes:
(A) The area identified by drilling and limited by fluid contacts, if any, and (B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.
(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.
(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.
(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:
(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (B) The project has been approved for development by all necessary parties and entities, including governmental entities.
(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.
Developed oil and gas reservesDeveloped oil and gas reserves are reserves of any category that can be expected to be recovered:
(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and
(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.
Undeveloped oil and gas reservesUndeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.
(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.
(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time.
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DEGOLYER AND MACNAUGHTON
(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in [section 210.410 (a) Definitions], or by other evidence using reliable technology establishing reasonable certainty.
Our estimates of Rosnefts net proved reserves attributable to the reviewed properties are based on the definitions of proved reserves of the SEC and are as follows, expressed in thousands of barrels (Mbbl) and millions of cubic feet (MMcf):
Rosneft Net Reserves | ||||||||||||||||||
Rosneft Holdings |
Reserves Classification |
Oil and Condensate (103bbl) |
NGL (103bbl) |
Marketable Gas (106ft3) |
Sales Gas (106ft3) |
|||||||||||||
Russia |
Proved Developed | 15,032,246 | 477,687 | 21,118,125 | 19,650,607 | |||||||||||||
Proved Undeveloped |
9,409,796 | 105,726 | 25,588,824 | 25,239,562 | ||||||||||||||
|
|
|
|
|
|
|
|
|||||||||||
Total Proved |
24,442,042 | 583,413 | 46,706,849 | 44,890,169 | ||||||||||||||
Algeria |
Proved Developed | 0 | 0 | 0 | 0 | |||||||||||||
Proved Undeveloped |
0 | 0 | 0 | 0 | ||||||||||||||
|
|
|
|
|
|
|
|
|||||||||||
Total Proved |
0 | 0 | 0 | 0 | ||||||||||||||
Canada |
Proved Developed | 795 | 178 | 1,236 | 1,201 | |||||||||||||
Proved Undeveloped |
2,294 | 559 | 3,920 | 3,673 | ||||||||||||||
|
|
|
|
|
|
|
|
|||||||||||
Total Proved |
3,089 | 737 | 5,156 | 4,874 | ||||||||||||||
Venezuela |
Proved Developed | 58,686 | 0 | 26,327 | 25,691 | |||||||||||||
Proved Undeveloped |
101,991 | 0 | 46,260 | 45,130 | ||||||||||||||
|
|
|
|
|
|
|
|
|||||||||||
Total Proved |
160,677 | 0 | 72,587 | 70,821 | ||||||||||||||
Vietnam |
Proved Developed | 798 | 0 | 156,197 | 156,197 | |||||||||||||
Proved Undeveloped |
0 | 0 | 0 | 0 | ||||||||||||||
|
|
|
|
|
|
|
|
|||||||||||
Total Proved |
798 | 0 | 156,197 | 156,197 | ||||||||||||||
Total |
Proved Developed | 15,092,525 | 477,865 | 21,301,785 | 19,833,696 | |||||||||||||
Proved Undeveloped |
9,514,081 | 106,285 | 25,639,004 | 25,288,365 | ||||||||||||||
|
|
|
|
|
|
|
|
|||||||||||
Total Proved |
24,606,606 | 584,150 | 46,940,789 | 45,122,061 |
Note: | Rosneft has represented that it controls the management of certain of the Rosneft Holdings in Russia through various subsidiary enterprises. For those Rosneft Holdings controlled by Rosneft, 100 percent of the reserves are reported herein as Rosneft Net Reserves and include those reserves not directly owned by Rosneft. |
In our opinion, the information relating to estimated proved reserves of oil, condensate, natural gas liquids, and gas contained in this report has been prepared in accordance with Paragraphs 932-235-50-4 and 932-235-50-6 through 932-235-50-9 of the Accounting Standards Update 932-235-50, Extractive IndustriesOil and Gas (Topic 932): Oil and Gas Reserve Estimation and Disclosures (January 2010) of the Financial Accounting Standards Board and Rules 410(a) (1)(32) of Regulation SX and Rules 302(b), 1201, 1202(a) (1), (2), (3), (4), (8), and 1203(a) of Regulation SK of the Securities and Exchange Commission.
In connection with the Financial Accounting Standards Board and the Securities and Exchange Commission standards and regulations, it should be noted that (i) estimates of the proved developed and proved undeveloped reserves are not presented at the beginning of the year, (ii) certain proved undeveloped reserves are scheduled for
5
DEGOLYER AND MACNAUGHTON
development more than 5 years in the future, and (iii) certain economically producible quantities of reserves beyond the primary term of the current production licenses have been classified as proved reserves in this report based on Rosnefts representation that each of the subsidiary enterprises discussed therein has the ability to and intends to extend the applicable current production licenses to the end of the economic life of the associated fields and that Rosneft believes with reasonable certainty that the inclusion of the reserves and revenue under extended license terms is consistent with SEC regulations. We believe it is reasonable therefore to include these quantities as SEC proved reserves for the reasons discussed herein.
To the extent the above-enumerated rules, regulations, and statements require determinations of an accounting or legal nature, we, as engineers, are necessarily unable to express an opinion as to whether the above-described information is in accordance therewith or sufficient therefor.
We are not in a position to offer an opinion on the duration of the subsidiary enterprises production licenses under the Russian Law on Subsoil, but, in light of the above, believe Rosnefts view on the probability of license extensions to be reasonable although such view may not be confirmed by the SEC. We believe it is reasonable therefore to include these quantities as SEC proved reserves.
Rosneft has represented to us that the Russian Law on Subsoil requires that an operator develop a field according to a development plan that has been submitted to and approved by the appropriate government authority. Once approved, failure to follow the development plan is a violation of the Russian Law on Subsoil and may result in the cancellation of the operators production license for the field. Since the implementation of the approved development plan, including that portion that may occur more than 5 years in the future, is a requirement for maintaining the production license, we have included in certain of our estimates of SEC proved reserves those quantities associated with development activities that are part of the approved development plan and scheduled more than 5 years in the future. We believe that since they must be developed to prevent the loss of licenses that there is reasonable certainty that the reserves will be developed. We believe it is reasonable therefore to include these quantities as SEC proved reserves. Rosneft has represented to us that the development plans provided to us are in accordance with the approved development plans. We cannot render an opinion regarding the actual possibility that a license will be terminated for failure to follow approved development plans nor an opinion on how many companies have lost their licenses for not following approved development plans.
6
DEGOLYER AND MACNAUGHTON
Our estimates of Rosnefts net proved reserves attributable to the reviewed properties, adjusted for BPs ownership interest of 19.75 percent, are as follows, expressed in thousands of barrels (Mbbl) and millions of cubic feet (MMcf):
Rosneft Net Reserves Adjusted for BP 19.75 Percent Share |
||||||||||||||||||
Rosneft Holdings |
Reserves Classification | Oil and Condensate (103bbl) |
NGL (103bbl) |
Marketable Gas (106ft3) |
Sales Gas (106ft3) |
|||||||||||||
Russia |
Proved Developed | 2,968,869 | 94,343 | 4,170,810 | 3,880,995 | |||||||||||||
Proved Undeveloped | 1,858,435 | 20,881 | 5,053,793 | 4,984,813 | ||||||||||||||
|
|
|
|
|
|
|
|
|||||||||||
Total Proved | 4,827,304 | 115,224 | 9,224,603 | 8,865,808 | ||||||||||||||
Algeria |
Proved Developed | 0 | 0 | 0 | 0 | |||||||||||||
Proved Undeveloped | 0 | 0 | 0 | 0 | ||||||||||||||
|
|
|
|
|
|
|
|
|||||||||||
Total Proved | 0 | 0 | 0 | 0 | ||||||||||||||
Canada |
Proved Developed | 157 | 35 | 244 | 237 | |||||||||||||
Proved Undeveloped | 453 | 110 | 774 | 725 | ||||||||||||||
|
|
|
|
|
|
|
|
|||||||||||
Total Proved | 610 | 145 | 1,018 | 962 | ||||||||||||||
Venezuela |
Proved Developed | 11,590 | 0 | 5,200 | 5,074 | |||||||||||||
Proved Undeveloped | 20,143 | 0 | 9,136 | 8,913 | ||||||||||||||
|
|
|
|
|
|
|
|
|||||||||||
Total Proved | 31,733 | 0 | 14,336 | 13,987 | ||||||||||||||
Vietnam |
Proved Developed | 158 | 0 | 30,849 | 30,849 | |||||||||||||
Proved Undeveloped | 0 | 0 | 0 | 0 | ||||||||||||||
|
|
|
|
|
|
|
|
|||||||||||
Total Proved | 158 | 0 | 30,849 | 30,849 | ||||||||||||||
Total |
Proved Developed | 2,980,774 | 94,378 | 4,207,103 | 3,917,155 | |||||||||||||
Proved Undeveloped | 1,879,031 | 20,991 | 5,063,703 | 4,994,451 | ||||||||||||||
|
|
|
|
|
|
|
|
|||||||||||
Total Proved | 4,859,805 | 115,369 | 9,270,806 | 8,911,606 |
Primary Economic Assumptions
The following economic assumptions were used for estimating existing and future prices and costs, expressed in United States dollars (U.S.$):
Oil and Condensate Prices
Rosneft has represented that the oil and condensate prices were based on a reference price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period, unless prices are defined by contractual arrangements. For the Rosneft holdings in the Russian Federation (including those in both the Chechen Republic and the Russian PSA), the volume-weighted average oil and condensate prices over the life of the properties was U.S.$47.34 per barrel and U.S.$48.47 per barrel, respectively. For the JV holding in Canada, Rosneft supplied differentials to an Edmonton Light Oil reference price of U.S.$91.39 per barrel and the prices were held constant thereafter. The average oil price over the life of the properties in the Canadian JV was
7
DEGOLYER AND MACNAUGHTON
U.S.$87.48 per barrel. For the JV holdings in Venezuela, Rosneft has represented that the oil reference price of U.S.$108.66 per barrel was used. Rosneft provided differentials to the reference price for each of the Venezuelan fields. Prices were held constant. The volume-weighted average price for the Venezuelan holdings was U.S.$93.77 per barrel. For the PSA holdings in Vietnam, Rosneft has represented that the condensate reference price of U.S.$108.66 per barrel was used. The realized price of the condensate for the Vietnam holdings was U.S.$104.10 per barrel.
NGL Prices
Rosneft has represented that the NGL prices were based on a reference price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period, unless prices are defined by contractual arrangements. For the Rosneft holdings in the Russian Federation (including those in both the Chechen Republic), the volume-weighted average NGL price over the life of the properties was U.S.$9.92 per barrel. For the JV holding in Canada, Rosneft supplied differentials to the NGL reference price average of U.S.$39.63 per barrel and the prices were held constant thereafter. The average NGL price over the life of the Canadian properties was U.S.$32.47 per barrel.
Gas Prices
Rosneft has represented that the gas prices were based on a reference price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period, unless prices are defined by contractual arrangements. For the Rosneft holdings in the Russian Federation (including those in both the Chechen Republic and the Russian PSA), the volume-weighted average price over the life of the properties was U.S.$2.38 per thousand cubic feet (Mcf). For the JV holding in Canada, Rosneft supplied differentials to an Alberta Export Canadian metering outlet (AECO) reference price of U.S.$3.12 per Mcf and the prices were held constant thereafter. The average gas price over the life of the properties in the Canadian JV was U.S.$2.93 per Mcf. For the Petromonagas field in Venezuela, Rosneft supplied a domestic gas reference price of U.S.$0.26 per Mcf, which was held constant for the life of the property. For the PSA holdings in Vietnam, Rosneft has represented that sales gas is priced according to terms of a Gas Sales Agreement and the average price is U.S.$2.86 per Mcf, held constant for the life of the properties.
Operating Expenses and Capital Costs
Operating expenses and capital costs, based on information provided by Rosneft, were used in estimating future values required to operate the fields. In certain cases, future costs, either higher or lower than current values, were used because of anticipated changes in operating conditions. These costs were not escalated for inflation.
Estimates of oil, condensate, natural gas liquids, and gas reserves should be regarded only as estimates that may change as further production history and additional information become available. Not only are such reserves estimates based on that information which is currently available, but such estimates are also subject to the uncertainties inherent in the application of judgmental factors in interpreting such information.
While the oil and gas industry may be subject to regulatory changes from time to time that could affect an industry participants ability to recover its oil and gas reserves, we are not aware of any such governmental actions which would restrict the recovery of the December 31, 2013, estimated oil and gas volumes. The reserves estimated in this report can be produced under current regulatory guidelines.
8
DEGOLYER AND MACNAUGHTON
DeGolyer and MacNaughton is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world since 1936. DeGolyer and MacNaughton does not have any financial interest, including stock ownership, in Rosneft or BP. Our fees were not contingent on the results of our evaluation. This letter report has been prepared at the request of BP. DeGolyer and MacNaughton has used all methods and procedures as it considered necessary under the circumstances to prepare this report. All assumptions, data, procedures, and methods used to prepare this report are considered by DeGolyer and MacNaughton to be appropriate for the purpose served by this report.
Submitted, | ||
/s/ DeGolyer and MacNaughton | ||
DeGOLYER and MacNAUGHTON | ||
Texas Registered Engineering Firm F-716 | ||
/s/ Gary L. McKenzie, P.E. | ||
Gary L. McKenzie, P.E. | ||
[SEAL] | Senior Vice President | |
DeGolyer and MacNaughton |
9
DEGOLYER AND MACNAUGHTON
CERTIFICATE of QUALIFICATION
I, Gary L. McKenzie, Petroleum Engineer with DeGolyer and MacNaughton, 5001 Spring Valley Road, Suite 800 East, Dallas, Texas, 75244 U.S.A., hereby certify:
1. That I am a Senior Vice President with DeGolyer and MacNaughton, which company did prepare the letter report addressed to BP dated January 26, 2014, and that I, as Senior Vice President, was responsible for the preparation of this report.
2. That I attended the U.S. Military Academy at West Point, and that I graduated with a Bachelor of Science degree in 1976; that I am a Registered Professional Engineer in the State of Texas; that I am a member of the International Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers; and that I have in excess of 32 years of experience in oil and gas reservoir studies and reserves evaluations.
/s/ Gary L. McKenzie, P.E. | ||
Gary L. McKenzie, P.E. | ||
[SEAL] | Senior Vice President | |
DeGolyer and MacNaughton |
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