BP 2011 Annual Report Download - page 84

82 BP Annual Report and Form 20-F 2011
Business review
in 2011, compared with 2010, primarily reflected higher oil and gas
realizations, partly offset by lower production. The increase in 2010,
compared with 2009, primarily reflected higher oil and gas realizations,
partly offset by lower production.
The replacement cost profit before interest and tax for 2011 was
$30,500 million, compared with $30,886 million for the previous year. 2011
included net non-operating gains of $1,130 million, primarily a result of
gains on disposals being partly offset by impairments, a charge associated
with the termination of our agreement to sell our 60% interest in Pan
American Energy LLC (PAE) to Bridas Corporation and other non-operating
items. (See page 58 for further information on non-operating items.) In
addition, fair value accounting effects had a favourable impact of $11
million relative to management’s measure of performance. (See page 58
for further information on fair value accounting effects.)
The primary additional factors contributing to the 1% decrease in
replacement cost profit before interest and tax were higher realizations
partially offset by lower production volumes (including in higher margin
areas), rig standby costs in the Gulf of Mexico, higher costs related to
turnarounds, certain one-off costs and higher exploration write-offs.
Total capital expenditure including acquisitions and asset exchanges
in 2011 was $25.5 billion (2010 $17.8 billion and 2009 $14.9 billion). (See
page 83 for further information on acquisitions.)
Development expenditure of subsidiaries incurred in 2011,
excluding midstream activities, was $10.2 billion, compared with $9.7
billion in 2010 and $10.4 billion in 2009.
Provisions for decommissioning increased from $10.5 billion at the
end of 2010 to $17.2 billion at the end of 2011. The increase reflects higher
cost estimates, which are in part driven by new requirements in the Gulf of
Mexico. Decommissioning costs are initially capitalized within fixed assets
and are subsequently depreciated as part of the asset.
Prior years’ comparative financial information
The replacement cost profit before interest and tax for the year ended
31 December 2010 of $30,886 million included net non-operating gains of
$3,199 million, comprised primarily of gains on disposals that completed
during the year partly offset by impairment charges and fair value losses
on embedded derivatives. In addition, fair value accounting effects had an
unfavourable impact of $3 million relative to management’s measure of
performance.
The replacement cost profit before interest and tax for the year
ended 31 December 2009 of $24,800 million included a net credit for non-
operating items of $2,265 million, with the most significant items being
gains on the sale of operations (primarily from the disposal of our 46%
stake in LukArco, the sale of our 49.9% interest in Kazakhstan Pipeline
Ventures LLC and the sale of BP West Java Limited in Indonesia) and fair
value gains on embedded derivatives. In addition, fair value accounting
effects had a favourable impact of $919 million relative to management’s
measure of performance.
The primary additional factor contributing to the 25% increase in
the replacement cost profit before interest and tax for the year ended
31 December 2010 compared with the year ended 31 December 2009 were
higher realizations, lower depreciation and higher earnings from equity-
accounted entities, partly offset by lower production, a significantly lower
contribution from gas marketing and trading and higher production taxes.
Outlook
In 2012, we will continue to drive operational risk reduction through the
new Exploration and Production segment structure, supported by the
S&OR function. Our divisions will work to manage risk and deliver common
standards, driving functional excellence across the lifecycle of exploration,
development and production, while continuing to focus on building our
technical capability for the future. We believe that our portfolio of assets
remains well positioned to compete and grow value in a range of external
conditions and we continue to increase both investment and operating cash.
We expect production in 2012 to be broadly flat, normalizing for divestments
and price effects, and excluding TNK-BP. This is the net effect of growth
from new projects and new production from India and Brazil being offset by
normal base decline. In 2012, we intend to drill 12 exploration wells, start
up six major projects, and increase our activity in the Gulf of Mexico to eight
operational rigs, subject to approvals by US regulators.
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.
In 2011, our exploration and appraisal costs, excluding lease
acquisitions, were $2,398 million, compared with $2,706 million in 2010
and $2,805 million in 2009. These costs included exploration and appraisal
drilling expenditures, which were capitalized within intangible fixed assets,
and geological and geophysical exploration costs, which were charged to
income as incurred. Approximately 76% of 2011 exploration and appraisal
costs were directed towards appraisal activity. In 2011, we participated in
308 gross (73.33 net) exploration and appraisal wells in nine countries. The
principal areas of exploration and appraisal activity were Angola, Australia,
Azerbaijan, Brazil, Canada, Egypt, the deepwater Gulf of Mexico, the UK
North Sea, Oman and onshore US.
Total exploration expense in 2011 of $1,520 million (2010 $843
million and 2009 $1,116 million) included the write-off of expenses related
to unsuccessful drilling activities in the deepwater Gulf of Mexico ($284
million), Asia Pacific ($61 million) and others ($5 million). It also included
$14 million related to decommissioning of idle infrastructure, as required by
the Bureau of Ocean Energy Management Regulation and Enforcement’s
Notice of Lessees 2010 G05 issued in October 2010.
Reserves booking from new discoveries will depend on the results
of ongoing technical and commercial evaluations, including appraisal drilling.
Proved reserves replacement
Total hydrocarbon proved reserves, on an oil equivalent basis including
equity-accounted entities, comprised 17,748mmboe (11,426mmboe
for subsidiaries and 6,322mmboe for equity-accounted entities) at
31 December 2011, a decrease of 2% (decrease of 5% for subsidiaries
and increase of 5% for equity-accounted entities) compared with the
31 December 2010 reserves of 18,071mmboe (12,077mmboe for
subsidiaries and 5,994mmboe for equity-accounted entities). Natural
gas represented about 40% (55% for subsidiaries and 14% for equity-
accounted entities) of these reserves. The change includes a net decrease
from acquisitions and disposals of 361mmboe (218mmboe net decrease
for subsidiaries and 143mmboe net decrease for equity-accounted
entities). Acquisitions occurred in Brazil, Canada, India, the UK, the US,
Venezuela and Vietnam. Divestments occurred in Algeria, Azerbaijan,
Canada, Colombia, Pakistan, Trinidad, the US, the UK, Venezuela and
Vietnam.
The proved reserves replacement ratio is the extent to which
production is replaced by proved reserves additions. This ratio is expressed
in oil equivalent terms and includes changes resulting from revisions to
previous estimates, improved recovery and extensions and discoveries.
For 2011, the proved reserves replacement ratio excluding acquisitions and
disposals was 103% (106% in 2010 and 129% in 2009) for subsidiaries
and equity-accounted entities, 45% for subsidiaries alone and 194% for
equity-accounted entities alone. The 2011 reserves additions for TNK-BP
include the effect of moving from life-of-licence measurement to life-of-
field measurement, reflecting TNK-BP’s track record of successful licence
renewal. Excluding this effect, our 2011 reserves replacement ratio
excluding acquisitions and disposals would have been 83%.
In 2011, net additions to the group’s proved reserves (excluding
production and sales and purchases of reserves-in-place) amounted to
1,320mmboe (348mmboe for subsidiaries and 972mmboe for equity-
accounted entities), through revisions to previous estimates, improved
recovery from, and extensions to, existing fields and discoveries of new
fields. Of our subsidiary reserves additions through improved recovery
from, and extensions to, existing fields and discoveries of new fields,
approximately 26% were associated with new projects and were proved
undeveloped reserves additions. The remaining additions were in existing
developments where they represented a mixture of proved developed and
proved undeveloped reserves. Volumes added in 2011 principally relied
on the application of conventional technologies. The principal reserves
additions in our subsidiaries were in the US (San Juan North, Mad Dog,
Ursa, Prudhoe Bay, Hawkville), Trinidad (Cashima, Juniper) and Indonesia
(Tangguh). The principal reserves additions in our equity-accounted entities