BP 2013 Annual Report Download - page 249

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 PUD 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 resources.
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 2013 BP had material volumes of proved undeveloped
reserves held for more than five years in Trinidad and the Gulf of Mexico.
These are part of ongoing development activities for which BP has a
historical track record of completing comparable projects in these
countries. We have no proved undeveloped reserves held for more than
five years in our onshore US developments.
In each case 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 19% of
our proved undeveloped reserves (accounting for 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 2013 we progressed 985mmboe of proved undeveloped reserves
(532mmboe for our subsidiaries alone) to proved developed reserves
through ongoing investment in our subsidiaries’ and equity-accounted
entities’ upstream development activities. Total development
expenditure in Upstream, excluding midstream activities, was
$16,664 million in 2013 ($13,552 million for subsidiaries and
$3,112 million for equity-accounted entities). The major areas with
progressed volumes in 2013 were Angola, Australia, Azerbaijan, Iraq,
Norway, Russia, Trinidad and the US. Revisions of previous estimates for
proved undeveloped reserves are due to changes relating to field
performance or well results. The following tables describe the changes to
our proved undeveloped reserves position through the year for our
subsidiaries and equity-accounted entities and for our subsidiaries alone.
Subsidiaries and equity-accounted assets volumes in mmboe
Proved undeveloped reserves at 1 January 2013 7,526
Revisions of previous estimates 466
Improved recovery 333
Discoveries and extensions 765
Purchases 2,447
Sales (2,472)
Total in year proved undeveloped reserves changes 9,065
Progressed to proved developed reserves (985)
Proved undeveloped reserves at 31 December 2013 8,080
Subsidiaries only volumes in mmboe
Proved undeveloped reserves at 1 January 2013 4,699
Revisions of previous estimates (20)
Improved recovery 294
Discoveries and extensions 473
Purchases –
Sales (70)
Total in year proved undeveloped reserves changes 5,376
Progressed to proved developed reserves (532)
Proved undeveloped reserves at 31 December 2013 4,844
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. 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:
• 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.
• Capital allocation processes, whereby delegated authority is exercised
to commit to capital projects that are consistent with the delivery of
Additional disclosures
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