BP 2011 Annual Report Download - page 92

90 BP Annual Report and Form 20-F 2011
Business review
Licence expiry
The Abu Dhabi onshore concession expires in January 2014 with a
consequent reduction in production of approximately 140mb/d. The group
holds no other licences due to expire within the next three years that
would have a significant impact on BP’s reserves or production.
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 re-categorized 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 four 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,
acquisition and disposal activity 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 re-categorized 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. The group will only book
proved reserves where development is scheduled to commence after 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 2011, BP had material volumes of proved
undeveloped reserves held for more than five years in Trinidad, as well as
non-material volumes in Australia, Azerbaijan, Norway, 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.
BP has a three year average track record (since the adoption of
the modernised rules for reporting) of converting 20% of our proved
undeveloped reserves (excluding disposals) to proved developed reserves.
This equates to a turnover time of five years. We expect the turnover time
to remain at or below five years and anticipate no increase in the volume of
proved undeveloped reserves held for more than five years.
In 2011, we converted 1,062mmboe of proved undeveloped
reserves to proved developed reserves through ongoing investment in
our upstream development activities. Total development expenditure in
Exploration and Production, excluding midstream activities, was $13,329
million in 2011 ($10,194 million for subsidiaries and $3,135 million for
equity-accounted entities). The major areas converted in 2011 were
Argentina, Indonesia, Russia, Trinidad and the US. Revisions of previous
estimates for proved undeveloped reserves are due to the impact of
year-end price (net of 1%) and changes relating to field performance or
well results (99%). The table below describes the changes to our proved
undeveloped reserves position through the year.
volumes in mmboe
Proved undeveloped reserves at 1 January 2011 7,899
Revisions of previous estimates 693
Improved recovery 522
Discoveries and extensions 92
Purchases 77
Sales (302)
Total in year proved undeveloped reserves changes 8,981
Progressed to proved developed reserves (1,062)
Proved undeveloped reserves at 31 December 2011 7,919
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; and (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 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.
• Internal audit, whose role is to consider whether the group’s system
of internal control is adequately designed and operating effectively to
respond appropriately to the risks that are significant to BP.
• Approval hierarchy, whereby proved reserves changes above certain
threshold volumes require central authorization and periodic reviews. The
frequency of review is determined according to field size and ensures
that more than 80% of the BP proved reserves base undergoes central
review every two years, and more than 90% is reviewed centrally every
four years.