BP 2009 Annual Report Download - page 26

BP Annual Report and Accounts 2009
Business review
The table below presents our average production cost per unit of production.
$ per unit of productiona
Europe North South Africa Asia Australasia Total group
America America average
Rest of
Rest of North Rest of
UK Europe US America Russia Asia
The average production cost per
unit of productiona
2009 12.38 10.72 7.26 14.45 2.20 6.05 – 4.35 1.60 6.39
2008 12.19 8.74 9.02 15.35 2.34 6.72 – 5.24 1.74 7.24
2007 14.00 7.17 9.03 14.04 2.69 6.43 – 3.81 1.75 7.14
aUnits of production are barrels for liquids and thousands of cubic feet for gas. Amounts do not include ad valorem and severance taxes; and are based on production cost of consolidated subsidiaries only,
which excludes equity-accounted entities.
Outlook
Our priorities remain the same – safety, people and performance,
focusing on the delivery of safe, reliable and efficient operations.
In 2010, we aim to use the momentum generated in 2009 to
continue to improve operational, cost and capital efficiency, while
ensuring we maintain our priorities of safe, reliable and efficient
operations. We intend to continue to focus on building personnel and
technological capability for the future. We believe our portfolio of assets
is strong and well positioned to compete and grow in a range of external
conditions. Also in 2010, we intend to create a centralized developments
organization to deliver our major projects. By bringing our project
expertise into one team, we expect to continue our drive for improved
capital efficiency by fully optimizing our project designs and improving
project execution.
Upstream activities
Exploration
The group explores for oil and natural gas under a wide range of
licensing, joint venture and other contractual agreements. We may do
this alone or, more frequently, with partners. BP acts as operator for
many of these ventures.
Our exploration and appraisal costs, excluding lease acquisitions,
in 2009 were $2,805 million, compared with $2,290 million in 2008 and
$1,892 million in 2007. These costs include exploration and appraisal
drilling expenditures, which are capitalized within intangible fixed assets,
and geological and geophysical exploration costs, which are charged to
income as incurred. Approximately 68% of 2009 exploration and appraisal
costs were directed towards appraisal activity. In 2009, we participated in
503 gross (107 net) exploration and appraisal wells in 12 countries.
The principal areas of exploration and appraisal activity were Angola,
Egypt, the deepwater Gulf of Mexico, Libya, the North Sea, Oman
and onshore US.
Total exploration expense in 2009 of $1,116 million (2008
$882 million and 2007 $756 million) included the write-off of expenses
related to unsuccessful drilling activities in the deepwater Gulf of Mexico
($391 million), India ($31 million), Angola ($28 million), Egypt ($27 million),
and others ($31 million).
In most cases, reserves booking from new discoveries will
depend on the results of ongoing technical and commercial evaluations,
including appraisal drilling.
Reserves and 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 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
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 divestment activity and
additional reservoir development activity.
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. Where, on
occasion, the group decides to book proved reserves where
development is scheduled to commence after five years, these proved
reserves will be booked only where they satisfy the SEC’s criteria for
attribution of proved status. There are material volumes of proved
undeveloped reserves in Angola, Trinidad, the US, and Canada which are
part of ongoing development activities for which BP has a historical track
record of completing comparable projects. In all cases, the volumes are
being progressed as part of an adopted development plan which calls for
drilling of wells over an extended period of time given the magnitude of
the development.
In 2009, we converted approximately 2,061mmboe 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 $12,392 million in 2009 ($10,396 million for subsidiaries
and $1,996 million for equity-accounted entities). The major areas
converted in 2009 were Azerbaijan, Indonesia, Russia, Trinidad and
the US.
24