BP 2005 Annual Report Download - page 133

Supplementary information on oil and natural gas quantities
BP RESERVES GOVERNANCE
BP manages its hydrocarbon resources in three major categories:
prospect inventory, non-proved resources and proved reserves. When
a discovery is made, volumes transfer from the prospect inventory to
the non-proved resource category. The resources move through
various non-proved resource sub-categories as their technical and
commercial maturity increases through appraisal activity.
Resources in a field will only be categorized as proved reserves
when all the criteria for attribution of proved status have been met,
including an internally imposed requirement for project sanction, or
for sanction expected within six months and, for additional reserves
in existing fields, the requirement that the reserves be included in
the business plan and scheduled for development within three years.
Internal approval and final investment decision are what we refer to
as project sanction.
At the point of sanction, all booked 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. The first PD bookings will 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 to the start of
production. Adjustments may be made to booked reserves owing
to production, reservoir performance, commercial factors, acquisition
and divestment activity and additional reservoir development activity.
BP has an internal process to control the quality of reserve
bookings that forms part of a holistic and integrated system of internal
control. BP’s process to manage reserve bookings has been centrally
controlled for over 15 years and it currently has several key elements.
The first element is the accountabilities of certain officers of the
company, which ensure that there is clear responsibility for review
and, where appropriate, endorsement of changes to reserves
bookings; that the review is independent of the operating business
unit for the integrity and accuracy of the reserve estimates; and that
there are effective controls in the reserve approval process and
verification that the group’s reserve estimates and the related financial
impacts are reported in a timely manner.
The second element is the 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
process exists to review that both technical and commercial criteria
are met prior to the commitment of capital to projects.
The third element is internal audit, whose role includes
systematically examining the effectiveness of the group’s financial
controls designed to assure the reliability of reporting and
safeguarding of assets and examining the group’s compliance with
laws, regulations and internal standards.
The fourth element is a quarterly due diligence review, which is
separate and independent from the operating business units, of
reserves associated with properties where technical, operational or
commercial issues have arisen.
The fifth element is the established criteria whereby reserves above
certain thresholds require central authorization. Furthermore, the
volumes booked under these authorization levels are reviewed on a
periodic basis. The frequency of review is determined according to
field size and ensures that more than 80% of the BP reserves base
undergoes central review every two years and more than 90% is
reviewed every four years.
BP Annual Report and Accounts 2005 131
RESERVES REPORTING
Our proved reserves are associated with both concessions (tax and
royalty arrangements) and production-sharing agreements (PSAs). In a
concession, the consortium of which we are a part is entitled to the
reserves that can be produced over the licence period, which may be
the life of the field. In a PSA, we are entitled to recover volumes that
equate to costs incurred to develop and produce the reserves and an
agreed share of the remaining volumes or the economic equivalent.
As part of our entitlement is driven by the monetary amount of costs
to be recovered, price fluctuations will have an impact on both
production volumes and reserves. Twenty per cent of our proved
reserves are associated with PSAs. The main countries in which we
operate under PSA arrangements are Algeria, Angola, Azerbaijan,
Egypt, Indonesia and Vietnam.
As a UK-registered company, BP estimates its proved reserves
under UK accounting rules for oil and gas companies contained in the
Statement of Recommended Practice, ‘Accounting for Oil and Gas
Exploration, Development, Production and Decommissioning
Activities’ (UK SORP). In estimating its reserves under UK SORP,
BP uses long-term planning prices; these are the long-term price
assumptions on which the group makes decisions to invest in the
development of a field. Using planning prices for estimating proved
reserves removes the impact of the volatility inherent in using year-
end spot prices on our reserve base and on cash flow expectations
over the long term. The group’s planning prices for estimating reserves
through the end of 2005 were $25 per barrel for oil and $4.00 per
mmBtu for natural gas.
In determining ‘reasonable certainty’ for UK SORP purposes,
BP applies a number of additional internally imposed assessment
principles, such as the requirement for internal approval and final
investment decision (which we refer to as project sanction), or for
such project sanction within six months and, for additional reserves
in existing fields, the requirement that the reserves be included in the
business plan and scheduled for development within three years.
On the basis of UK SORP, our total proved reserves for
subsidiaries and equity-accounted entities at the end of 2005 were
18,271mmboe, representing a proved reserve replacement ratio (RRR)
before acquisitions and divestments of 100%, versus 110% in 2004.
Our principal equity-accounted entity is TNK-BP. For subsidiaries only,
the RRR is 71% and, for equity-accounted entities only, the RRR is
160%. The proved reserve replacement ratio (also known as the
production replacement ratio) is the extent to which production is
replaced by proved reserve additions. This ratio is expressed in oil
equivalent terms and includes changes resulting from revisions to
previous estimates, improved recovery, extensions, discoveries and
other additions, excluding the impact of acquisitions and divestments.
Natural gas is converted to oil equivalent at 5.8 billion cubic feet (bcf)
equals 1 million barrels. By their nature, there is always some risk
involved in the ultimate development and production of reserves,
including but not limited to final regulatory approval, the installation of
new or additional infrastructure as well as changes in oil and gas
prices and the continued availability of additional development capital.
The estimated proved oil and natural gas reserves on this basis are
shown on pages 133-134.
The US Securities and Exchange Commission (SEC) rules
for estimating reserves are different in certain respects from
SORP; in particular, the SEC requires the use of year-end prices.