BP in 2014    We have reshaped and repositioned the business for the future, with a clear strategy that has put us on course to grow value for shareholders.								Information about this report
						1		Strategic report
						2		BP at a glance		24		Upstream
						6		Chairman’s letter		29		Downstream
						8		Group chief executive’s letter		33		Rosneft
						10		Our market outlook		35		Other businesses and corporate
						12		Our business model		36		Gulf of Mexico oil spill
						13		Our strategy		39		Corporate responsibility
						18		Our key performance indicators		46		Our management of risk
						20		Our markets in 2014		48		Risk factors
						21		Group performance
						51		Corporate governance
						52		Board of directors		68		Safety, ethics and environment assurance committee
						56		Executive team
						58		Governance overview		69		Gulf of Mexico committee
						59		How the board works		71		Nomination committee
						61		Board effectiveness		71		Chairman’s committee
						62		Shareholder engagement		72		Directors’ remuneration report
						63		International advisory board
						63		Internal control revised guidance for directors (Turnbull)
						64		Audit committee
«  Glossary Words with this symbol « are defined in the glossary on page 252.						89		Financial statements
						94		Consolidated financial statements of the BP group		167		Supplementary information on oil and natural gas (unaudited)
						100		Notes on financial statements
						207		Additional disclosures
						208		Selected financial information		239		Property, plant and equipment
						211		Liquidity and capital resources		239		Related-party transactions
						213		Upstream analysis by region		239		Corporate governance practices
						217		Downstream plant capacity		240		Code of ethics
						219		Oil and gas disclosures for the group		240		Controls and procedures
						225		Environmental expenditure		241		Principal accountants’ fees and services
						225		Regulation of the group’s business
						228		Legal proceedings		241		Directors’ report information
						238		International trade sanctions		241		Disclosures required under Listing Rule 9.8.4.R
						239		Material contracts
										241		Cautionary statement
						243		Shareholder information
						244		Share prices and listings		251		Fees and charges payable by ADSs holders
						244		Dividends
						245		UK foreign exchange controls on dividends		251		Fees and payments made by the Depositary to the issuer
						245		Shareholder taxation information		251		Documents on display
						247		Major shareholders		252		Shareholding administration
						247		Annual general meeting		252		Exhibits
						247		Memorandum and Articles of Association		252		Abbreviations, glossary and trade marks
						250		Purchases of equity securities by the issuer and affiliated purchasers
						256 257		Signatures Cross reference to Form 20-F

 

 

 

 

 

		Strategic report   An overview of the key activities, events and results in 2014, together with commentary on BP’s performance and our priorities as we move forward.						2		BP at a glance
								6		Chairman’s letter
								8		Group chief executive’s letter
								10		Our market outlook
								12		Our business model
								13		Our strategy
										14		Strategy in action
										16		Distinctive capabilities
								18		Our key performance indicators
								20		Our markets in 2014
								21		Group performance
										21		10-point plan performance
										22		Financial and operating performance
								24		Upstream
								29		Downstream
								33		Rosneft
								35		Other businesses and corporate
								36		Gulf of Mexico oil spill
								39		Corporate responsibility
										39		Safety
										42		Environment and society
										44		Employees
								46		Our management of risk
								48		Risk factors
				BP Annual Report and Form 20-F 2014      1

 

 

 

 

 

 

 

Board performance For information about the board and its committees see page 51.    Remuneration For information about our directors’ remuneration see page 72.		Oversight The board has continued to maintain oversight of performance, risk and financial efficiency and kept a constant scrutiny on safety. Each year we review and monitor the group level risks through our own work and our committees, who carry out the majority of the work, leaving the board free to address strategic issues.   There are, however, longer-term issues on which we also have to focus, such as carbon and its role in climate change. It is clear that it is for governments and regulators to set the boundary conditions to address these issues and we will develop our business within their framework. For example, we already factor a price for carbon into our project evaluation. We recognize that we need to play our part in informing this debate and we do this through our projections for future world energy markets in the BP Energy Outlook 2035 . Throughout, we must remain alert to developments that may alter the world in which we operate. The board is recommending that shareholders support the resolution at the annual general meeting seeking greater transparency of reporting in this important area.   Governance and succession The board regularly considers how it operates and the appropriate composition and mix around the board table – both to respond to today’s challenges and BP’s future strategic direction. Antony Burgmans, the current chair of the remuneration committee, will stand down as a director in 2016. In anticipation of his departure, Dame Ann Dowling will take over the chair of that committee during 2015. We have also considered the chairs and membership of all other committees. In 2012, upon Andrew Shilston joining the board and being appointed the senior independent director, we announced that Antony Burgmans would retain a role as an internal sounding board. This role will cease after the annual general meeting. Andrew will join the remuneration and nomination committees.   I would like to welcome Alan Boeckmann who joined the board as a non-executive director in July. Alan brings deep experience of contractor management, procurement and project delivery in our industry following his career in Fluor Corporation. Alan will be joining the remuneration committee after the annual general meeting. Our longest serving director, Iain Conn, left the company in December to become chief executive of Centrica after an almost 30-year career with BP, spanning different businesses and regions. George David will retire from the board at our AGM in April. My fellow directors and I thank both Iain and George for their huge contributions and work on behalf of the board.
q Top: Members of BP’s safety, ethics and environmental assurance committee (SEEAC) in Azerbaijan.   q Bottom: Cynthia Carroll attends a briefing during a visit to Brazil with SEEAC.		I would also like to thank Bob Dudley, his team, my board colleagues and all our employees for all that they have done. Finally, my thanks go to you, our shareholders, for the support you have shown us during the year.
		Carl-Henric Svanberg Chairman 3 March 2015

 

 

 

Delivery of our 10-point plan For details of our performance against the plan see page 21.    Our strategy For more on our strategic priorities and longer-term objectives see page 13.    Our key performance indicators Find out how we measure our performance on page 18.       q Top: Bob Dudley at the World Petroleum Congress in Moscow.   q Bottom: Bob Dudley congratulates winners at the Helios awards – where teams from across the world are recognized for their contributions to building a safer, stronger BP in line with our values.		We grew our exploration position during the year, with new access in five areas and hydrocarbon discoveries in the Gulf of Mexico, Brazil, the North Sea, Egypt and Angola. We began operating our onshore oil and gas operations in the ‘Lower 48’ states of the US as a separate business in January 2015. In the Downstream, we improved performance from fuels marketing, increased our capacity to refine heavy crude and shale oil in the US, maintained the focus on premium brands and growth markets in lubricants and reviewed the petrochemicals business to increase its earnings potential.   Having completed our $38-billion divestment programme ahead of schedule, we committed to make a further $10 billion of divestments by the end of 2015. By the end of 2014 we had agreed transactions amounting to $4.7 billion.   Distinctive capabilities BP’s distinctive capabilities of advanced technology, proven expertise and strong relationships underpin our progress. We have invested over the years to be a specialist in several key areas of technology. For example, in 2014 we started using robots to test enhanced oil recovery options, helping us reduce time to production.   The expertise of our people is central to our progress so developing our employees in critical areas is an ongoing activity. For example, we run specialist academies dedicated to global wells expertise and safety and operational risk, as well as other areas.   Strong relationships remain vital – with communities, governments, partners, suppliers, staff and shareholders. The rapid progress made on the Southern Corridor project, which will pipe natural gas from the Caspian Sea to markets as far away as Italy, is just one example. With our partners, we have already awarded more than $9 billion of contracts to make, transport and install facilities.   A challenging environment In 2015 we entered a very different landscape from that in which we began last year. The lower oil price presents formidable challenges for the industry. In these volatile times, BP continues to drive capital discipline by constraining the total level of capital spend in any one year, taking account of the opportunities available and the flexibility of our balance sheet.   Meanwhile, we continue to manage issues specific to BP. The legal proceedings in the US associated with the Deepwater Horizon accident and oil spill continue. In the first trial phase the judge issued a finding of gross negligence and wilful misconduct. We strongly disagree with these findings and have appealed. In the second phase the court found no gross negligence in our source control efforts and ruled that 3.19 million barrels of oil were discharged into the Gulf of Mexico. We have also appealed this ruling. The penalty phase trial finished in February, with the ruling to come at a later date. In all of the proceedings, we are seeking fair and just outcomes while protecting the best interests of our shareholders.   Our investment in Rosneft, funded from the proceeds of our sale of TNK-BP in 2013, continues to attract attention. Our approach is to comply with all relevant sanctions and otherwise to maintain our distinctive, long-term investment and relationship with Rosneft in a country that holds some of the world’s largest oil and gas resources. There is strong interdependence between Russia and its trading partners, and I believe that over time such commercial links tend to ease tensions rather than exacerbate them.   The BP of 2015 is a robust and resilient business, a global team that has been through some of the most difficult times an organization can face and emerged stronger, safer and better than before.     Bob Dudley Group chief executive 3 March 2015

 

 

 

 

 

Our strategy

 

Our goal is to be a focused oil and gas company that delivers value over volume.
 An operator commissions a steam system at the Whiting refinery in the US.   { Technical operations onboard our floating production, storage and offloading vessel in Angola.		We prioritize value over volume by actively managing a high-value upstream and downstream portfolio and investing only where we can apply the distinctive strengths, capabilities and technologies we have built up over decades.   Our objective is to create shareholder value by growing sustainable free cash flow « over the long term. Our disciplined approach enables us to grow distributions to our shareholders over time.   We are pursuing our strategy by setting clear priorities, actively managing a quality portfolio and employing our distinctive capabilities.   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 in support of growth in operating cash « from our businesses, disciplined allocation of capital and financial resilience.   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 deep water, giant fields and selected gas value chains. And, in our downstream businesses, we plan to leverage our newly upgraded assets, customer relationships and technology to grow operating cash flow.   Our portfolio of projects and operations is focused where we believe 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 work to develop and maintain strong relationships – with governments, partners, civil society and others – to enhance our operations in almost 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 how we are delivering our strategy on page 14.   Our key performance indicators See how we measure our progress on page 18.   Risks Find out how we manage the risks to our strategy on page 46.

 

 

How we deliver

How we measure

Strategy in action in 2014

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.

Running reliably Running operations safely is Air BP’s first priority. See page 40.

28 tier 1 process safety events.

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, gearing, total shareholder return, underlying replacement cost profit per ordinary share.

Increasing value An alternative solution to increase long-term value. See page 21.

$32.8bn 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.

Unlocking hidden resources Using our advanced technology and exploration experience to access gas in Oman. See page 27.

7 major project start-ups in Upstream.

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.

Extending the life of the North Sea Our latest discovery demonstrates the basin’s ongoing potential. See page 28.

63 % reserves replacement ratio. a

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 years to come.

Production.

Committing to the future Increasing production in the Gulf of Mexico. See page 25.

3.2 million barrels of oil equivalent per day. a

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.

Driving success Our retail partnership with Marks & Spencer is driving sales growth. See page 31.

94.9 % refining availability.

 

 

Creating shareholder value by generating sustainable free cash flow

 

 

 

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 aim to form enduring partnerships in the countries in which we operate, building strong relationships with governments, customers, partners, suppliers and communities to create mutual advantage. Co-operation helps unlock resources found in challenging locations and transforms them into products for our customers.		Our talented people help to drive our business forward. They apply their diverse skills and expertise to deliver complex projects across all areas of our business.

^a On a combined basis of subsidiaries « and equity-accounted entities.

 

 

 

 

 

 

Group performance

A summary of our group financial and operating performance.

 

 

10-point plan performance

In 2014 we completed our three-year 10-point plan, established in 2011, to help stabilize BP and restore trust and value in response to the tragic Deepwater Horizon accident in 2010. Here we report on our performance in delivering the plan over the period.

 

		Relentless focus on safety
		We reduced tier 1 process safety events « and loss of primary containment (LOPC) by 62% and 21% respectively over the plan period. However, in 2014 there were eight more tier 1 events and 25 more LOPC incidents than 2013. Safety remains our primary focus and we continue to focus our efforts on it.
		Play to our strengths
		We accessed almost 158,000 km 2 exploration acres, made 13 new discoveries and drilled a total of 44 exploration wells (2014 18).
		Stronger and more focused
		We have reshaped our portfolio to have a set of high-value deepwater assets, gas value chains, giant fields, and a high-quality downstream business. We sold around half of our upstream installations and pipelines, and one third of our wells – while retaining roughly 90% of our proved reserves and production.
		Simpler and more standardized
		We implemented standardized global systems and processes and established global functional organizations to conduct all BP-operated drilling and wells activity and manage the development of our major projects « .
		More visibility and transparency to value
		We provide downstream results by fuels, petrochemicals and lubricants, and report earnings from Rosneft as a separate operating segment.

		Active portfolio management
		We completed our $38-billion divestment programme ahead of schedule and plan for a further $10 billion of divestments before the end of 2015, with $4.7 billion of sales already agreed.
		New upstream projects onstream with unit cash margins « double the 2011 average
		We started up 15 major upstream projects, of which 13 are in the four higher-margin areas (Angola, Azerbaijan, Gulf of Mexico and North Sea). Average forecast unit cash margins (2014-23) for the 15 projects at $100/bbl oil price were more than double the 2011 upstream segment average.
		Generate around 50% more in operating cash flow « by 2014 versus 2011 a
		We reported $32.8 billion of operating cash flow in 2014 (averaged oil price of $98.95/bbl, averaged Henry Hub gas price of $4.43/mmBtu) – exceeding our target of around 50% increase on 2011.
		Half of incremental operating cash for reinvestment – half for other purposes including distributions
		The dividend paid in 2014 increased by 39% since 2011, and we carried out $10.3 billion of share buybacks since March 2013, when a share repurchase programme was announced.
		Strong balance sheet
		Our gearing « stayed within our target range of 10-20%, decreasing from 20.4% in 2011 to 16.7% at the end of 2014.

 

 

 

 

 

a

Assumed an oil price of $100/bbl and a Henry Hub gas price of $5/mmBtu in 2014. 2011 excluded BP’s share of TNK-BP dividends; 2014 included BP’s share of Rosneft dividends. The projection included the impact of payments in respect of federal criminal and securities claims with the US government and SEC where settlements have already been reached, but does not reflect any cash flows relating to other liabilities, contingent liabilities, settlements or contingent assets arising from the Gulf of Mexico oil spill.

 

 

 

Financial and operating performance

 

											$ million
			2014				2013				2012
Profit before interest and taxation			6,412				31,769				19,769
Finance costs and net finance expense relating to pensions and other post-retirement benefits			(1,462	)			(1,548	)			(1,638	)
Taxation			(947	)			(6,463	)			(6,880	)
Non-controlling interests			(223	)			(307	)			(234	)
Profit for the year a			3,780				23,451				11,017
Inventory holding (gains) losses « , net of tax			4,293				230				411
Replacement cost profit «			8,073				23,681				11,428
Net charge (credit) for non-operating items « , net of tax			4,620				(10,533	)			5,298
Net (favourable) unfavourable impact of fair value accounting effects « , net of tax			(557	)			280				345
Underlying replacement cost profit «			12,136				13,428				17,071
Capital expenditure and acquisitions, on accrual basis			23,781				36,612				25,204

 

a	Profit attributable to BP shareholders.

 

Profit for the year ended 31 December 2014 decreased by $19.7 billion compared with 2013. Excluding inventory holding losses, replacement cost (RC) profit also decreased by $15.6 billion compared with 2013. Both results in 2013 included a $12.5 -billion non-operating gain relating to the disposal of our interest in TNK-BP.

After adjusting for a net charge for non-operating items, which mainly related to impairments and further charges associated with the Gulf of Mexico oil spill; and net favourable fair value accounting effects, underlying RC profit for the year ended 31 December 2014 was down by $1.3 billion compared with 2013. The reduction was mainly due to a lower profit in Upstream, partially offset by improved earnings from Downstream.

Profit for the year ended 31 December 2013 increased by $12.4 billion compared with 2012. Excluding inventory holding losses, RC profit also increased by $12.2 billion compared with 2012. The increase in both results was due to a $12.5 -billion gain of disposal of our interest in TNK-BP.

After adjusting for a net credit for non-operating items, which mainly related to the gain on disposal of our interest in TNK-BP and was partially offset by an $845-million write-off and impairments in Upstream and further charges associated with the Gulf of Mexico oil spill; and net unfavourable fair value accounting effects, underlying RC profit for the year ended 31 December 2013 was down by $3.6 billion compared with 2012. This was impacted by the absence of equity-accounted earnings from TNK-BP and lower earnings from both Downstream and Upstream, partially offset by the equity-accounted earnings from Rosneft from 21 March 2013 (when sale and purchase agreements with Rosneft and Rosneftegaz completed).

For the year ended 31 December 2012 profit was $11.0 billion, RC profit was $11.4 billion and underlying RC profit was $17.1 billion. There was a net post-tax charge of $5.3 billion for non-operating items, which included a $5-billion pre-tax charge relating to the Gulf of Mexico.

More information on non-operating items, and fair value accounting effects, can be found on page 209. See Gulf of Mexico oil spill on page 36 and Financial statements – Note 2 for further information on the impact of the Gulf of Mexico oil spill on BP’s financial results.

 

Taxation

The charge for corporate income taxes in 2014 was lower than 2013. The effective tax rate (ETR) was 19% in 2014 (2013 21%, 2012 38%). The low ETR in 2014 reflects the impairment charges on which tax credits arise in relatively high tax rate jurisdictions. The lower ETR in 2013 compared with 2012 primarily reflects the gain on disposal of TNK-BP in 2013 for which there was no corresponding tax charge. The underlying ETR (which excludes non-operating items and fair value accounting effects) on RC profit was 36% in 2014 (2013 35%, 2012 30%).

In the current environment, with our current portfolio of assets, the underlying ETR on RC profit for 2015 is expected to be lower than 2014.

Cash flow and net debt information

 

											$ million
			2014				2013				2012
Net cash provided by operating activities			32,754				21,100				20,479
Net cash used in investing activities			(19,574	)			(7,855	)			(13,075	)
Net cash used in financing activities			(5,266	)			(10,400	)			(2,010	)
Currency translation differences relating to cash and cash equivalents			(671	)			40				64
Increase in cash and cash equivalents			7,243				2,885				5,458
Cash and cash equivalents at beginning of year			22,520				19,635				14,177
Cash and cash equivalents at end of year			29,763				22,520				19,635
Gross debt			52,854				48,192				48,800
Net debt «			22,646				25,195				27,465
Gross debt to gross debt-plus-equity			31.9%				27.0%				29.0%
Net debt to net debt-plus-equity «			16.7%				16.2%				18.7%

Net cash provided by operating activities

Net cash provided by operating activities for the year ended 31 December 2014 increased by $11.7 billion compared with 2013. Excluding the impacts of the Gulf of Mexico oil spill, net cash provided by operating activities was $32.8 billion for 2014, an increase of $11.6 billion compared with 2013. Profit before taxation was lower but this was partially offset by movements in the adjustments for non-cash items, including depreciation, depletion and amortization, impairments and gains and losses on sale of businesses and fixed assets. Furthermore, 2013 was impacted by an adverse movement in working capital and 2014 was favourably impacted.

The increase in 2013 compared with 2012 primarily benefited from the reduction of $2.3 billion in the cash outflow in respect of the Gulf of Mexico oil spill. Excluding the impacts of the Gulf of Mexico oil spill, net cash provided by operating activities was $21.2 billion for 2013, compared with $22.9 billion for 2012, a decrease of $1.7 billion. The decrease was mainly due to an increase in working capital requirements of $3.9 billion, which was partially offset by a reduction in income tax paid.

Net cash used in investing activities

Net cash used in investing activities for the year ended 31 December 2014 increased by $11.7 billion compared with 2013. The increase reflected a decrease in disposal proceeds of $18.5 billion, partly offset by a $4.9 -billion decrease in our investments in equity-accounted entities, mainly relating to the completion of the sale of our interest in TNK-BP and subsequent investment in Rosneft in 2013. There was also a decrease in our other capital expenditure excluding acquisitions of $2.0 billion.

 

 

The decrease in 2013 compared with 2012 reflected an increase in disposal proceeds of $10.4 billion, partly offset by an increase in our investments in equity-accounted entities, mainly relating to the completion of the sale of our interest in TNK-BP and subsequent investment in Rosneft. There was also an increase in our other capital expenditure excluding acquisitions of $1.3 billion.

There were no significant acquisitions in 2014, 2013 and 2012.

The group has had significant levels of capital investment for many years. Cash flow in respect of capital investment, excluding acquisitions, was $23.1 billion in 2014 (2013 $30 billion and 2012 $24.8 billion). Sources of funding are fungible, but the majority of the group’s funding requirements for new investment come from cash generated by existing operations.

We expect capital expenditure, excluding acquisitions and asset exchanges, to be around $20 billion in 2015.

Total cash disposal proceeds received during 2014 were $3.5 billion (2013 $22 billion, 2012 $11.6 billion). In 2013 this included $16.7 billion for the disposal of BP’s interest in TNK-BP and in 2012 it included $5.6 billion for the disposal of BP’s interests in the Marlin hub, Horn Mountain, Holstein, Ram Powell and Diana Hoover fields in the Gulf of Mexico. See Financial statements – Note 3 for more information on disposals.

Net cash used in financing activities

Net cash used in financing activities for the year ended 31 December 2014 decreased by $5.1 billion compared with 2013. The decrease primarily reflected higher net proceeds of $3.3 billion from long-term financing and a decrease in the net repayment of short-term debt of $1.3 billion. The $8-billion share repurchase programme was completed in July 2014.

The increase in 2013 compared with 2012 primarily reflected the buyback of shares of $5.5 billion, as part of our $8-billion share repurchase programme, lower net proceeds of $1.1 billion from long-term financing and an increase in the net repayment of short-term debt of $1.4 billion.

Total dividends paid in 2014 were 39 cents per share, up 6.8% compared with 2013 on a dollar basis and 1.9% in sterling terms. This equated to a total cash distribution to shareholders of $5.9 billion during the year (2013 $5.4 billion, 2012 $5.3 billion).

Net debt

Net debt at the end of 2014 decreased by $2.5 billion from the 2013 year-end position. The ratio of net debt to net debt plus equity at the end of 2014 increased by 0.5%.

The total cash and cash equivalents at the end of 2014 were $7.2 billion higher than 2013.

We will continue to target our net debt ratio in the 10-20% range while uncertainties remain. Net debt and the ratio of net debt to net debt plus equity are non-GAAP measures. See Financial statements – Note 25 for further information on net debt.

For information on financing the group’s activities, see Financial statements – Note 27 and Liquidity and capital resources on page 211.

Group reserves and production

Total hydrocarbon proved reserves at 31 December 2014, on an oil equivalent basis including equity-accounted entities, decreased by 3% (decrease of 5% for subsidiaries and increase of 1% for equity-accounted entities) compared with 31 December 2013. Natural gas represented about 44% of these reserves (58% for subsidiaries and 27% for equity-accounted entities). The change includes a net decrease from acquisitions and disposals of 39mmboe (all within our subsidiaries). Acquisition activity in our subsidiaries occurred in Azerbaijan, the US and the UK, and divestment activity in our subsidiaries occurred in the US and Brazil.

Our total hydrocarbon production for the group was 2% lower compared with 2013. The decrease comprised a 1% increase (7% increase for liquids and 4% decrease for gas) for subsidiaries and a 7% decrease (13% decrease for liquids and 25% increase for gas) for equity-accounted entities.

For more information on reserves and production, see Oil and gas disclosures for the group on page 219.

 

			2014				2013				2012
Estimated net proved reserves a (net of royalties)
Liquids «			million barrels
Crude oil b
Subsidiaries «			3,582				3,798				4,082
Equity-accounted entities c			5,663				5,589				5,275
			9,244				9,387				9,357
Natural gas liquids
Subsidiaries			510				551				591
Equity-accounted entities c			62				131				103
			572				682				693
Total liquids
Subsidiaries			4,092				4,349				4,672
Equity-accounted entities c			5,725				5,721				5,378
			9,817				10,070				10,050
Natural gas			billion cubic feet
Subsidiaries			32,496				34,187				33,264
Equity-accounted entities c			12,200				11,788				7,041
			44,695				45,975				40,305
Total hydrocarbons «			million barrels of oil equivalent
Subsidiaries			9,694				10,243				10,408
Equity-accounted entities c			7,828				7,753				6,592
			17,523				17,996				17,000
Production a (net of royalties)
Liquids			thousand barrels per day
Crude oil d
Subsidiaries			844				789				795
Equity-accounted entities e			979				1,120				1,137
			1,823				1,909				1,932
Natural gas liquids
Subsidiaries			91				86				96
Equity-accounted entities e			12				19				27
			103				105				123
Total liquids f
Subsidiaries			936				874				891
Equity-accounted entities e			991				1,139				1,164
			1,927				2,013				2,056
Natural gas			million cubic feet per day
Subsidiaries			5,585				5,845				6,193
Equity-accounted entities e			1,515				1,216				1,200
			7,100				7,060				7,393
Total hydrocarbons f			thousand barrels of oil equivalent per day
Subsidiaries			1,898				1,882				1,959
Equity-accounted entities e			1,253				1,348				1,372
			3,151				3,230				3,331

 

a	Because of rounding, some totals may not agree exactly with the sum of their component parts.

b	Includes condensate and bitumen.

c	Includes BP’s share of Rosneft (2014 and 2013) and TNK-BP reserves (2012). See Rosneft on page 33 and Supplementary information on oil and natural gas on page 167 for further information.

d	Includes condensate.

e	Includes BP’s share of Rosneft (2014 and 2013) and TNK-BP production (2013 and 2012). See Rosneft on page 33 and Oil and gas disclosures for the group on page 219 for further information.

f	A minor amendment has been made to the split between subsidiaries and equity-accounted entities for the comparative periods.

 

 

 

Upstream

We continued to actively manage our portfolio to play to our strengths, divesting non-core assets and finding alternative ways to create long-term value.

 

 

~

An operator works the controls at the Rumaila oilfield in Iraq. The field extends 50 miles from end to end.

 

 

 

 

 

 

 

 

 

Sea and Angola reflecting the impact of the lower near-term price environment, revisions to reserves and increases in expected decommissioning cost estimates. This also included a charge to write down the value ascribed to block KG D6 in India as part of the acquisition of upstream interests from Reliance Industries in 2011. The charge arises as a result of uncertainty in the future long-term gas price outlook, following the introduction of a new formula for Indian gas prices, although we do see the commencement of a transition to market-based pricing as a positive step. We expect further clarity on the new pricing policy and the premiums for future developments to emerge in due course. Fair value accounting effects had a favourable impact of $31 million relative to management’s view of performance.

The 2013 result included a net non-operating charge of $1,364 million, which included an $845-million write-off attributable to block BM-CAL-13 offshore Brazil as a result of the Pitanga exploration well not encountering commercial quantities of oil or gas, and had an unfavourable impact of $244 million from fair value accounting effects. The 2012 result included net non-operating gains of $3,189 million, primarily as a result of gains on disposals being partly offset by impairment charges. In addition, fair value accounting effects had an unfavourable impact of $134 million.

After adjusting for non-operating items and fair value accounting effects, the decrease in the underlying RC profit before interest and tax compared with 2013 reflected lower liquids realizations, higher costs, mainly depreciation, depletion and amortization and exploration write-offs and the absence of one-off benefits which occurred in 2013 (see below). This was partly offset by higher production in higher-margin areas, higher gas realizations and a benefit from stronger gas marketing and trading activities.

Compared with 2012 the 2013 result reflected lower production due to divestments, lower liquids realizations and higher costs, including exploration write-offs and higher depreciation, depletion and amortization, partly offset by an increase in underlying volumes, a benefit from stronger gas marketing and trading activities, one-off benefits related to production taxes and a cost pooling settlement agreement between the owners of the Trans-Alaska Pipeline System (TAPS), and higher gas realizations.

Total capital expenditure including acquisitions and asset exchanges in 2014 was higher compared with 2013. This included $469 million in 2014 relating to the purchase of an additional 3.3% equity in Shah Deniz, Azerbaijan and the South Caucasus Pipeline.

In total, disposal transactions generated $2.5 billion in proceeds during

2014, with a corresponding reduction in net proved reserves of 114mmboe, all within our subsidiaries.

The major disposal transactions during 2014 were the farm-out of a 40% stake in block 61 in the Khazzan field, Oman, to government owned Makarim Gas Development LLC, for $545 million; the sale of our interests in four BP-operated oilfields on the North Slope of Alaska to Hilcorp, including all of BP’s interests in the Endicott and Northstar oilfields and a 50% interest in each of the Milne Point field and the Liberty prospect, together with BP’s interests in the oil and gas pipelines associated with these fields for $1.25 billion plus an additional carry of up to $250 million, if the Liberty field is developed; and the sale of our interests in the Panhandle West and Texas Hugoton gas fields to Pantera Acquisition Group, LLC for $390 million. Sales transactions are typically subject to post-closing adjustments and future payments depending on oil price and production. More information on disposals is provided in Upstream analysis by region on page 213 and Financial statements – Note 3.

Provisions for decommissioning increased from $17.2 billion at the end of 2013 to $18.7 billion at the end of 2014. The increase primarily reflects updated estimates of the cost of future decommissioning, additions and a change in discount rate, partially offset by utilization of provisions, exchange revaluation and impacts of divestments. Decommissioning costs are initially capitalized within fixed assets and are subsequently depreciated as part of the asset.

Exploration

The group explores for oil and natural gas under a wide range of licensing, joint arrangement « and other contractual agreements. We may do this alone or, more frequently, with partners.

New access in 2014

We gained access to new potential resources covering more than 47,000km ² in five countries (Australia, Greenland, UK (North Sea), the US (Gulf of Mexico) and Morocco, which received final government approval in April 2014). In December, we signed a new PSA with the State Oil Company of the Republic of Azerbaijan to jointly explore for and develop potential prospects in the shallow water area around the Absheron Peninsula in the Azerbaijan sector of the Caspian Sea. This is pending final ratification by the government. Additionally, Rosneft and BP signed a heads of agreement in May 2014 relating to a long-term project for the exploration and potential development of the Domanik formations in the Volga-Urals region of Russia.

 

In January 2015, we received formal licences for El Matariya and Karawan concessions in Egypt after ratification and finalization of the agreements.

During the year we participated in five discoveries that are potentially commercial including: one in Egypt with the BG-operated Notus well in the El Burg concession; one in the pre-salt play of Angola with the Orca well in Block 20, operated by Cobalt International Energy; one at Xerelete in Brazil’s Campos basin, operated by Total; one at Vorlich in the North Sea, which spans the GDF-SUEZ-operated block 30/1f and the BP-operated block 30/1c; and Guadalupe in the deepwater Gulf of Mexico, operated by Chevron.

Exploration and appraisal costs

Excluding lease acquisitions, the costs for exploration and appraisal costs were $2,911 million (2013 $4,811 million, 2012 $4,356 million). These costs included exploration and appraisal drilling expenditures, which were capitalized within intangible fixed assets, and geological and geophysical exploration costs, which were charged to income as incurred. Approximately 31% of exploration and appraisal costs were directed towards appraisal activity. We participated in 67 gross (32.75 net) exploration and appraisal wells in 10 countries.

Exploration expense

Total exploration expense of $3,632 million (2013 $3,441 million, 2012 $1,475 million) included the write-off of expenses related to unsuccessful drilling activities or lease expiration in the Lower 48 ($665 million), Algeria ($524 million), India ($139 million), the Gulf of Mexico ($500 million), Brazil ($368 million), China ($112 million), Angola ($110 million), Morocco ($83 million) and others ($133 million). In addition, $395 million was written off KG D6 in India as a result of uncertainty in the future long-term gas price outlook (see page 216).

Upstream reserves

Estimated net proved reserves ^a (net of royalties)

 

			2014				2013				2012
Liquids			million barrels
Crude oil b
Subsidiaries «			3,582				3,798				4,082
Equity-accounted entities c			702				729				813
			4,283				4,527				4,895
Natural gas liquids
Subsidiaries			510				551				591
Equity-accounted entities c			16				16				25
			526				567				616
Total liquids
Subsidiaries d			4,092				4,349				4,672
Equity-accounted entities c			717				745				838
			4,809				5,094				5,510
Natural gas			billion cubic feet
Subsidiaries e			32,496				34,187				33,264
Equity-accounted entities c			2,373				2,517				2,549
			34,869				36,704				35,813
Total hydrocarbons			million barrels of oil equivalent
Subsidiaries			9,694				10,243				10,408
Equity-accounted entities c			1,126				1,179				1,277
			10,821				11,422				11,685

 

a	Because of rounding, some totals may not agree exactly with the sum of their component parts.

b	Includes condensate and bitumen.

c	BP’s share of reserves of equity-accounted entities in the Upstream segment. During 2014, upstream operations in Abu Dhabi, Argentina and Bolivia, as well as some of our operations in Angola and Indonesia, were conducted through equity-accounted entities.

d	Includes 21 million barrels (21 million barrels at 31 December 2013 and 14 million barrels at 31 December 2012) in respect of the 30% non-controlling interest in BP Trinidad & Tobago LLC.

e	Includes 2,519 billion cubic feet of natural gas (2,685 billion cubic feet at 31 December 2013 and 2,890 billion cubic feet at 31 December 2012) in respect of the 30% non-controlling interest in BP Trinidad & Tobago LLC.

Reserves booking

Reserves booking from new discoveries will depend on the results of ongoing technical and commercial evaluations, including appraisal drilling. The segment’s total hydrocarbon reserves on an oil equivalent basis, including equity-accounted entities at 31 December 2014, decreased by 5% (5% for subsidiaries and 4% for equity-accounted entities) compared with reserves at 31 December 2013.

Proved reserves replacement ratio «

The proved reserves replacement ratio for the Upstream segment in 2014, excluding acquisitions and disposals, was 31% for subsidiaries and equity-accounted entities (2013 93%), 29% for subsidiaries alone (2013 105%) and 43% for equity-accounted entities alone (2013 30%). For more information on proved reserves replacement for the group see page 219.

Developments

The map on page 26 shows our major development areas. We achieved seven major project start-ups in 2014: the Chirag oil project in Azerbaijan; Na Kika Phase 3, Mars B and Atlantis North expansion Phase 2 in the Gulf of Mexico; CLOV in Angola; Kinnoull in the North Sea and Sunrise in Canada. In addition to starting up major projects, we made good progress in the four areas we believe most likely to provide us with higher-value barrels – Angola, Azerbaijan, the North Sea and the Gulf of Mexico.

 

•

Angola – we had an oil and gas discovery, Orca, in the pre-salt play of Angola in Block 20 (BP 30%), operated by Cobalt International Energy, Inc. and the CLOV project reached plateau production of 160mboe/d.

 

•

Azerbaijan – the Shah Deniz and South Caucasus Pipeline consortia awarded further key contracts for the development of the Shah Deniz Stage 2 and South Caucasus Pipeline expansion projects. The BP-operated Azerbaijan International Operating Company celebrated the 20th anniversary of the Azeri-Chirag-Gunashli PSA.

 

•

North Sea – we continued to see high levels of activity, including a new discovery, Vorlich, in the central North Sea (see page 28); progress in the major redevelopment of the west of Shetland Schiehallion and Loyal fields; and the restart of operations at the Rhum field. BP has been granted seven awards in the UK government’s 28th licensing round. The blocks are located in three of our core areas: to the north of our Magnus field, next to Vorlich, and west of our Kinnoull development. The government is still to award some blocks in this round. These blocks are undergoing environmental assessment.

 

 

 

•

Gulf of Mexico – we made a new discovery – Guadalupe – and were awarded 51 blocks in the March and August Gulf of Mexico lease sales. At the end of the year we had 10 rigs operating. Following our strategic divestment programme, we now have a focused portfolio with growth potential around four operated and three non-operated hubs.

Development expenditure of subsidiaries incurred in 2014, excluding midstream activities, was $15.1 billion (2013 $13.6 billion, 2012 $12.6 billion).

Production

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

Production (net of royalties) ^a

 

			2014				2013				2012
Liquids			thousand barrels per day
Crude oil
Subsidiaries			844				789				795
Equity-accounted entities			163				294				281
			1,007				1,083				1,076
Natural gas liquids
Subsidiaries			91				86				96
Equity-accounted entities			7				8				7
			99				94				103
Total liquids b
Subsidiaries			936				874				891
Equity-accounted entities			170				302				288
			1,106				1,176				1,179
Natural gas			million cubic feet per day
Subsidiaries			5,585				5,845				6,193
Equity-accounted entities			431				415				416
			6,016				6,259				6,609
Total hydrocarbons b			thousand barrels of oil equivalent per day
Subsidiaries			1,898				1,882				1,959
Equity-accounted entities			245				374				360
			2,143				2,256				2,319

 

a	Includes BP’s share of production of equity-accounted entities in the Upstream segment. Because of rounding, some totals may not agree exactly with the sum of their component parts.

b	A minor amendment has been made to the split between subsidiaries and equity-accounted entities for the comparative periods.