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

Business reviewLicence expiryThe Abu Dhabi onshore concession expires in January 2014 with aconsequent reduction in production of approximately 140mb/d. The groupholds no other licences due to expire within the next three years thatwould have a significant impact on BP’s reserves or production.Resource progressionBP manages its hydrocarbon resources in three major categories: prospectinventory, contingent resources and proved reserves. When a discoveryis made, volumes usually transfer from the prospect inventory to thecontingent resources category. The contingent resources move throughvarious sub-categories as their technical and commercial maturity increasesthrough appraisal activity.At the point of final investment decision, most proved reserves willbe categorized as proved undeveloped (PUD). Volumes will subsequentlybe re-categorized from PUD to proved developed (PD) as a consequenceof development activity. When part of a well’s proved reserves dependson a later phase of activity, only that portion of proved reserves associatedwith existing, available facilities and infrastructure moves to PD. The firstPD bookings will typically occur at the point of first oil or gas production.Major development projects typically take one to four years from the timeof initial booking of proved reserves to the start of production. Changes toproved reserves bookings may be made due to analysis of new or existingdata concerning production, reservoir performance, commercial factors,acquisition and disposal activity and additional reservoir developmentactivity.Volumes can also be added or removed from our portfolio throughacquisition or divestment of properties and projects. When we disposeof an interest in a property or project, the volumes associated with ouradopted plan of development for which we have a final investmentdecision will be removed from our proved reserves upon completion.When we acquire an interest in a property or project, the volumesassociated with the existing development and any committed projectswill be added to our proved reserves if BP has made a final investmentdecision and they satisfy the SEC’s criteria for attribution of proved status.Following the acquisition, additional volumes may be progressed to provedreserves from contingent.Contingent resources in a field will only be re-categorized as provedreserves when all the criteria for attribution of proved status have been metand the proved reserves are included in the business plan and scheduledfor development, typically within five years. The group will only bookproved reserves where development is scheduled to commence after fiveyears, if these proved reserves satisfy the SEC’s criteria for attribution ofproved status and BP management has reasonable certainty that theseproved reserves will be produced.At the end of 2011, BP had material volumes of provedundeveloped reserves held for more than five years in Trinidad, as well asnon-material volumes in Australia, Azerbaijan, Norway, the UK and the US,that are part of ongoing development activities for which BP has a historicaltrack record of completing comparable projects in these countries.The volumes are being progressed as part of an adopted developmentplan where there are physical limits to the development timing suchas infrastructure limitations, contractual limits including gas deliverycommitments, late life compression and the complex nature of working inremote locations.BP has a three year average track record (since the adoption ofthe modernised rules for reporting) of converting 20% of our provedundeveloped reserves (excluding disposals) to proved developed reserves.This equates to a turnover time of five years. We expect the turnover timeto remain at or below five years and anticipate no increase in the volume ofproved undeveloped reserves held for more than five years.In 2011, we converted 1,062mmboe of proved undevelopedreserves to proved developed reserves through ongoing investment inour upstream development activities. Total development expenditure inExploration and Production, excluding midstream activities, was $13,329million in 2011 ($10,194 million for subsidiaries and $3,135 million forequity-accounted entities). The major areas converted in 2011 wereArgentina, Indonesia, Russia, Trinidad and the US. Revisions of previousestimates for proved undeveloped reserves are due to the impact ofyear-end price (net of 1%) and changes relating to field performance orwell results (99%). The table below describes the changes to our provedundeveloped reserves position through the year.volumes in mmboeProved undeveloped reserves at 1 January 2011 7,899Revisions of previous estimates 693Improved recovery 522Discoveries and extensions 92Purchases 77Sales (302)Total in year proved undeveloped reserves changes 8,981Progressed to proved developed reserves (1,062)Proved undeveloped reserves at 31 December 2011 7,919BP bases its proved reserves estimates on the requirement of reasonablecertainty with rigorous technical and commercial assessments based onconventional industry practice. BP only applies technologies that have beenfield tested and have been demonstrated to provide reasonably certainresults with consistency and repeatability in the formation being evaluatedor in an analogous formation. BP applies high-resolution seismic data forthe identification of reservoir extent and fluid contacts only where there isan overwhelming track record of success in its local application. In certaindeepwater fields BP has booked proved reserves before production flowtests are conducted, in part because of the significant safety, cost andenvironmental implications of conducting these tests. The industry hasmade substantial technological improvements in understanding, measuringand delineating reservoir properties without the need for flow tests. Todetermine reasonable certainty of commercial recovery, BP employs ageneral method of reserves assessment that relies on the integration ofthree types of data: (1) well data used to assess the local characteristicsand conditions of reservoirs and fluids; (2) field scale seismic data toallow the interpolation and extrapolation of these characteristics outsidethe immediate area of the local well control; and (3) data from relevantanalogous fields. Well data includes appraisal wells or sidetrack holes, fulllogging suites, core data and fluid samples. BP considers the integrationof this data in certain cases to be superior to a flow test in providingunderstanding of overall reservoir performance. The collection of datafrom logs, cores, wireline formation testers, pressures and fluid samplescalibrated to each other and to the seismic data can allow reservoirproperties to be determined over a greater volume than the localizedvolume of investigation associated with a short-term flow test. There isa strong track record of proved reserves recorded using these methods,validated by actual production levels.GovernanceBP’s centrally controlled process for proved reserves estimation approvalforms part of a holistic and integrated system of internal control. It consistsof the following elements:• Accountabilities of certain officers of the group to ensure that there isreview and approval of proved reserves bookings independent of theoperating business and that there are effective controls in the approvalprocess and verification that the proved reserves estimates and therelated financial impacts are reported in a timely manner.• Capital allocation processes, whereby delegated authority is exercisedto commit to capital projects that are consistent with the delivery of thegroup’s business plan. A formal review process exists to ensure thatboth technical and commercial criteria are met prior to the commitmentof capital to projects.• Internal audit, whose role is to consider whether the group’s systemof internal control is adequately designed and operating effectively torespond appropriately to the risks that are significant to BP.• Approval hierarchy, whereby proved reserves changes above certainthreshold volumes require central authorization and periodic reviews. Thefrequency of review is determined according to field size and ensuresthat more than 80% of the BP proved reserves base undergoes centralreview every two years, and more than 90% is reviewed centrally everyfour years.90 BP Annual Report and Form 20-F 2011