BP Annual Report and Form 20-F 2011 - Company Reporting

Business reviewin 2011, compared with 2010, primarily reflected higher oil and gasrealizations, partly offset by lower production. The increase in 2010,compared with 2009, primarily reflected higher oil and gas realizations,partly offset by lower production.The replacement cost profit before interest and tax for 2011 was$30,500 million, compared with $30,886 million for the previous year. 2011included net non-operating gains of $1,130 million, primarily a result ofgains on disposals being partly offset by impairments, a charge associatedwith the termination of our agreement to sell our 60% interest in PanAmerican Energy LLC (PAE) to Bridas Corporation and other non-operatingitems. (See page 58 for further information on non-operating items.) Inaddition, fair value accounting effects had a favourable impact of $11million relative to management’s measure of performance. (See page 58for further information on fair value accounting effects.)The primary additional factors contributing to the 1% decrease inreplacement cost profit before interest and tax were higher realizationspartially offset by lower production volumes (including in higher marginareas), rig standby costs in the Gulf of Mexico, higher costs related toturnarounds, certain one-off costs and higher exploration write-offs.Total capital expenditure including acquisitions and asset exchangesin 2011 was $25.5 billion (2010 $17.8 billion and 2009 $14.9 billion). (Seepage 83 for further information on acquisitions.)Development expenditure of subsidiaries incurred in 2011,excluding midstream activities, was $10.2 billion, compared with $9.7billion in 2010 and $10.4 billion in 2009.Provisions for decommissioning increased from $10.5 billion at theend of 2010 to $17.2 billion at the end of 2011. The increase reflects highercost estimates, which are in part driven by new requirements in the Gulf ofMexico. Decommissioning costs are initially capitalized within fixed assetsand are subsequently depreciated as part of the asset.Prior years’ comparative financial informationThe replacement cost profit before interest and tax for the year ended31 December 2010 of $30,886 million included net non-operating gains of$3,199 million, comprised primarily of gains on disposals that completedduring the year partly offset by impairment charges and fair value losseson embedded derivatives. In addition, fair value accounting effects had anunfavourable impact of $3 million relative to management’s measure ofperformance.The replacement cost profit before interest and tax for the yearended 31 December 2009 of $24,800 million included a net credit for nonoperatingitems of $2,265 million, with the most significant items beinggains on the sale of operations (primarily from the disposal of our 46%stake in LukArco, the sale of our 49.9% interest in Kazakhstan PipelineVentures LLC and the sale of BP West Java Limited in Indonesia) and fairvalue gains on embedded derivatives. In addition, fair value accountingeffects had a favourable impact of $919 million relative to management’smeasure of performance.The primary additional factor contributing to the 25% increase inthe replacement cost profit before interest and tax for the year ended31 December 2010 compared with the year ended 31 December 2009 werehigher realizations, lower depreciation and higher earnings from equityaccountedentities, partly offset by lower production, a significantly lowercontribution from gas marketing and trading and higher production taxes.OutlookIn 2012, we will continue to drive operational risk reduction through thenew Exploration and Production segment structure, supported by theS&OR function. Our divisions will work to manage risk and deliver commonstandards, driving functional excellence across the lifecycle of exploration,development and production, while continuing to focus on building ourtechnical capability for the future. We believe that our portfolio of assetsremains well positioned to compete and grow value in a range of externalconditions and we continue to increase both investment and operating cash.We expect production in 2012 to be broadly flat, normalizing for divestmentsand price effects, and excluding TNK-BP. This is the net effect of growthfrom new projects and new production from India and Brazil being offset bynormal base decline. In 2012, we intend to drill 12 exploration wells, startup six major projects, and increase our activity in the Gulf of Mexico to eightoperational rigs, subject to approvals by US regulators.Upstream activitiesExplorationThe group explores for oil and natural gas under a wide range of licensing,joint venture and other contractual agreements. We may do this aloneor, more frequently, with partners. BP acts as operator for many of theseventures.In 2011, our exploration and appraisal costs, excluding leaseacquisitions, were $2,398 million, compared with $2,706 million in 2010and $2,805 million in 2009. These costs included exploration and appraisaldrilling expenditures, which were capitalized within intangible fixed assets,and geological and geophysical exploration costs, which were charged toincome as incurred. Approximately 76% of 2011 exploration and appraisalcosts were directed towards appraisal activity. In 2011, we participated in308 gross (73.33 net) exploration and appraisal wells in nine countries. Theprincipal areas of exploration and appraisal activity were Angola, Australia,Azerbaijan, Brazil, Canada, Egypt, the deepwater Gulf of Mexico, the UKNorth Sea, Oman and onshore US.Total exploration expense in 2011 of $1,520 million (2010 $843million and 2009 $1,116 million) included the write-off of expenses relatedto unsuccessful drilling activities in the deepwater Gulf of Mexico ($284million), Asia Pacific ($61 million) and others ($5 million). It also included$14 million related to decommissioning of idle infrastructure, as required bythe Bureau of Ocean Energy Management Regulation and Enforcement’sNotice of Lessees 2010 G05 issued in October 2010.Reserves booking from new discoveries will depend on the resultsof ongoing technical and commercial evaluations, including appraisal drilling.Proved reserves replacementTotal hydrocarbon proved reserves, on an oil equivalent basis includingequity-accounted entities, comprised 17,748mmboe (11,426mmboefor subsidiaries and 6,322mmboe for equity-accounted entities) at31 December 2011, a decrease of 2% (decrease of 5% for subsidiariesand increase of 5% for equity-accounted entities) compared with the31 December 2010 reserves of 18,071mmboe (12,077mmboe forsubsidiaries and 5,994mmboe for equity-accounted entities). Naturalgas represented about 40% (55% for subsidiaries and 14% for equityaccountedentities) of these reserves. The change includes a net decreasefrom acquisitions and disposals of 361mmboe (218mmboe net decreasefor subsidiaries and 143mmboe net decrease for equity-accountedentities). Acquisitions occurred in Brazil, Canada, India, the UK, the US,Venezuela and Vietnam. Divestments occurred in Algeria, Azerbaijan,Canada, Colombia, Pakistan, Trinidad, the US, the UK, Venezuela andVietnam.The proved reserves replacement ratio is the extent to whichproduction is replaced by proved reserves additions. This ratio is expressedin oil equivalent terms and includes changes resulting from revisions toprevious estimates, improved recovery and extensions and discoveries.For 2011, the proved reserves replacement ratio excluding acquisitions anddisposals was 103% (106% in 2010 and 129% in 2009) for subsidiariesand equity-accounted entities, 45% for subsidiaries alone and 194% forequity-accounted entities alone. The 2011 reserves additions for TNK-BPinclude the effect of moving from life-of-licence measurement to life-offieldmeasurement, reflecting TNK-BP’s track record of successful licencerenewal. Excluding this effect, our 2011 reserves replacement ratioexcluding acquisitions and disposals would have been 83%.In 2011, net additions to the group’s proved reserves (excludingproduction and sales and purchases of reserves-in-place) amounted to1,320mmboe (348mmboe for subsidiaries and 972mmboe for equityaccountedentities), through revisions to previous estimates, improvedrecovery from, and extensions to, existing fields and discoveries of newfields. Of our subsidiary reserves additions through improved recoveryfrom, and extensions to, existing fields and discoveries of new fields,approximately 26% were associated with new projects and were provedundeveloped reserves additions. The remaining additions were in existingdevelopments where they represented a mixture of proved developed andproved undeveloped reserves. Volumes added in 2011 principally reliedon the application of conventional technologies. The principal reservesadditions in our subsidiaries were in the US (San Juan North, Mad Dog,Ursa, Prudhoe Bay, Hawkville), Trinidad (Cashima, Juniper) and Indonesia(Tangguh). The principal reserves additions in our equity-accounted entities82 BP Annual Report and Form 20-F 2011