BP 2012 Annual Report Download - page 86

Business review: BP in more depth
BP Annual Report and Form 20-F 2012
84
Oil and gas disclosures for the group
Resource progression
BP manages its hydrocarbon resources in three major categories:
prospect inventory, contingent resources and proved reserves. When a
discovery is made, volumes usually transfer from the prospect inventory
to the contingent resources category. The contingent resources move
through various sub-categories as their technical and commercial maturity
increases through appraisal activity.
At the point of final investment decision, most proved reserves will be
categorized as proved undeveloped (PUD). Volumes will subsequently be
recategorized from PUD to proved developed (PD) as a consequence of
development activity. When part of a well’s proved reserves depends on a
later phase of activity, only that portion of proved reserves associated with
existing, available facilities and infrastructure moves to PD. The first PD
bookings will typically occur at the point of first oil or gas production.
Major development projects typically take one to five years from the time
of initial booking of proved reserves to the start of production. Changes
to proved reserves bookings may be made due to analysis of new or
existing data concerning production, reservoir performance, commercial
factors and additional reservoir development activity.
Volumes can also be added or removed from our portfolio through
acquisition or divestment of properties and projects. When we dispose
of an interest in a property or project, the volumes associated with our
adopted plan of development for which we have a final investment
decision will be removed from our proved reserves upon completion.
When we acquire an interest in a property or project, the volumes
associated with the existing development and any committed projects
will be added to our proved reserves if BP has made a final investment
decision and they satisfy the SEC’s criteria for attribution of proved status.
Following the acquisition, additional volumes may be progressed to
proved reserves from contingent.
Contingent resources in a field will only be recategorized as proved
reserves when all the criteria for attribution of proved status have been
met and the proved reserves are included in the business plan and
scheduled for development, typically within five years. BP will only book
proved reserves where development is scheduled to commence after
more than five years, if these proved reserves satisfy the SEC’s criteria for
attribution of proved status and BP management has reasonable certainty
that these proved reserves will be produced.
At the end of 2012, BP had material volumes of proved undeveloped
reserves held for more than five years in Trinidad, as well as non-material
volumes in Angola, Australia, Azerbaijan, Russia, the UK and the US, that
are part of ongoing development activities for which BP has a historical
track record of completing comparable projects in these countries.
The volumes are being progressed as part of an adopted development
plan where there are physical limits to the development timing such as
infrastructure limitations, contractual limits including gas delivery
commitments, late life compression and the complex nature of working
in remote locations.
Over the past five years, BP has annually progressed on average about
20% of our proved undeveloped reserves (excluding disposals) to proved
developed reserves. This equates to a turnover time of about five years.
We expect the turnover time to remain at or below five years and
anticipate the volume of proved undeveloped reserves held for more than
five years to remain about the same.
In 2012 we progressed 1,279mmboe of proved undeveloped reserves
(780mmboe for our subsidiaries alone) to proved developed reserves
through ongoing investment in our upstream development activities. Total
development expenditure in Upstream, excluding midstream activities,
was $15,247 million in 2012 ($11,964 million for subsidiaries and
$3,283 million for equity-accounted entities). The major areas with
progressed volumes in 2012 were Angola, Azerbaijan, Iraq, Norway,
Russia, Trinidad and the US. Revisions of previous estimates for proved
undeveloped reserves are due to the impact of year-end price (net
reduction of 33%) and changes relating to field performance or well
results (67%). The following tables describe the changes to our proved
undeveloped reserves position through the year for our subsidiaries and
equity-accounted assets and for our subsidiaries alone.
Subsidiaries and equity-accounted assets volumes in mmboe
Proved undeveloped reserves at 1 January 2012 7,919
Revisions of previous estimates (95)
Improved recovery 586
Discoveries and extensions 462
Purchases 49
Sales (116)
Total in year proved undeveloped reserves changes 8,805
Progressed to proved developed reserves (1,279)
Proved undeveloped reserves at 31 December 2012 7,526
Subsidiaries only volumes in mmboe
Proved undeveloped reserves at 1 January 2012 5,378
Revisions of previous estimates (700)
Improved recovery 496
Discoveries and extensions 169
Purchases 49
Sales (108)
Total in year proved undeveloped reserves changes 5,284
Progressed to proved developed reserves (780)
Proved undeveloped reserves at 31 December 2012 4,504
BP bases its proved reserves estimates on the requirement of reasonable
certainty with rigorous technical and commercial assessments based on
conventional industry practice. BP only applies technologies that have been
field tested and have been demonstrated to provide reasonably certain
results with consistency and repeatability in the formation being evaluated or
in an analogous formation. BP applies high-resolution seismic data for the
identification of reservoir extent and fluid contacts only where there is an
overwhelming track record of success in its local application. In certain
deepwater fields BP has booked proved reserves before production flow
tests are conducted, in part because of the significant safety, cost and
environmental implications of conducting these tests. The industry has made
substantial technological improvements in understanding, measuring and
delineating reservoir properties without the need for flow tests. To determine
reasonable certainty of commercial recovery, BP employs a general method
of reserves assessment that relies on the integration of three types of data:
1. Well data used to assess the local characteristics and conditions of
reservoirs and fluids.
2. Field scale seismic data to allow the interpolation and extrapolation of
these characteristics outside the immediate area of the local well control.
3. Data from relevant analogous fields. Well data includes appraisal wells or
sidetrack holes, full logging suites, core data and fluid samples. BP
considers the integration of this data in certain cases to be superior to a
flow test in providing understanding of overall reservoir performance. The
collection of data from logs, cores, wireline formation testers, pressures
and fluid samples calibrated to each other and to the seismic data can allow
reservoir properties to be determined over a greater volume than the
localized volume of investigation associated with a short-term flow test.
There is a strong track record of proved reserves recorded using these
methods, validated by actual production levels.
Governance
BP’s centrally controlled process for proved reserves estimation approval
forms part of a holistic and integrated system of internal control. It
consists of the following elements:
t Accountabilities of certain officers of the group to ensure that there is
review and approval of proved reserves bookings independent of the
operating business and that there are effective controls in the approval
process and verification that the proved reserves estimates and the
related financial impacts are reported in a timely manner.
t Capital allocation processes, whereby delegated authority is exercised
to commit to capital projects that are consistent with the delivery of the
group’s business plan. A formal review process exists to ensure that
both technical and commercial criteria are met prior to the commitment
of capital to projects.