BP 2012 Annual Report Download - page 68

Business review: BP in more depth
BP Annual Report and Form 20-F 2012
66
Prior years’ comparative financial information
The replacement cost profit before interest and tax for the year ended
31 December 2011 of $26,366 million 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. In addition, fair value
accounting effects had a favourable impact of $11 million relative to
management’s measure of performance.
The replacement cost profit before interest and tax for the year ended
31 December 2010 of $28,269 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.
After adjusting for non-operating items and fair value accounting effects,
the underlying replacement cost profit in 2011 compared with 2010 was
marginally increased, reflecting higher realizations partially offset by lower
production volumes (including in higher margin areas).
Acquisitions and disposals
During 2012 we undertook a number of disposals. In total, disposal
transactions generated $10.7 billion in proceeds during 2012. With regards
to proved reserves, 441mmboe net were disposed of, all within our
subsidiaries. There were no significant acquisitions in 2012.
Disposals
t On 28 February 2012 BP announced it had agreed terms with LINN
Energy to sell BP’s Hugoton basin assets (including the Jayhawk NGL
plant). Under the agreement LINN Energy agreed to pay BP $1.2 billion
in cash. The sale completed on 30 March 2012.
t On 27 March 2012 BP announced that it had agreed to sell its interests
in all of its operated gas fields in the southern North Sea, including
associated pipeline infrastructure and the Dimlington terminal (including
the integrated Easington terminal) to Perenco UK Ltd for $400 million.
The sale completed in October 2012.
t On 2 April 2012 the sale of the Canadian natural gas liquid business to
Plains Midstream Canada ULC, a wholly owned subsidiary of Plains All
American Pipeline L.P., announced in 2011, was completed.
t On 25 June 2012 BP announced that it had agreed to sell its interests in
the Jonah and Pinedale upstream operation in Wyoming to LINN
Energy for $1.025 billion. The sale completed on 31 July 2012.
t On 26 June 2012 BP announced that it had agreed to sell its non-
operated interests in the Alba and Britannia fields in the UK North Sea to
Mitsui & Co Ltd for $280 million. The sale completed in December 2012.
t On 10 August 2012 BP announced that it had agreed to sell its Sunray
and Hemphill gas processing plants in Texas, together with their
associated gas gathering system, to Eagle Rock Energy Partners for
$228 million. The sale completed on 1 October 2012.
t On 10 September 2012 BP announced that it had agreed to sell its
interests in a number of non-strategic assets in the Gulf of Mexico to
Plains Exploration and Production Company for $5.55 billion. The sale
includes interests in three BP-operated assets: the Marlin hub,
comprised of the Marlin, Dorado and King fields (BP 100%); Horn
Mountain (BP 100%) and Holstein (BP 50%). The deal also includes
BP’s stake in two non-operated assets: Ram Powell (BP 31%) and
Diana Hoover (BP 33.33%). The sale completed on 30 November 2012.
t On 13 September 2012 BP announced that it had agreed to sell its
18.36% non-operated interest in the Draugen field in the Norwegian
Sea to AS Norske Shell for $240 million in cash. The sale completed in
November 2012.
t On 28 November 2012 BP announced that it had agreed to sell a
package of its central North Sea assets to TAQA Bratani Ltd for up to
$1.3 billion (comprising $1.058 billion consideration plus future
payments which, dependent on oil price and production, are expected
to exceed $250 million after tax). This package comprised the non-
operated Braes and Braemar assets, and the operated Harding, Maclure
and Devenick assets. The transaction is subject to third-party and
regulatory approvals.
t On 17 December 2012 BP announced that it had agreed to sell its 50%
non-operated interest in the Sean field in the UK North Sea to SSE PLC
for $288 million in cash. The transaction is subject to third-party and
regulatory approvals.
t On 19 December 2012 BP announced that it had agreed the sale of its
34.3% interest in the Yacheng gas field in the South China Sea to
Kuwait Foreign Petroleum Exploration Company (KUFPEC) for $308
million in cash. The transaction is subject to regulatory, CNOOC and
third-party approvals.
t BP’s 33.3% ownership in the Phu My 3 power business in Vietnam
was originally part of the divestment programme of the integrated gas
business to TNK-BP. However, the Phu My 3 part of the divestment
failed to conclude prior to the expiry of the sale and purchase
agreement, and hence was reclassified from being held for sale into
routine business. BP is open to other future divestment options and is
currently evaluating its position in the business over the medium term.
Exploration
We continually seek access to resources and in 2012 this included Brazil,
where we farmed in to four deepwater concessions covering 2,100km2 on
the Equatorial Margin; Canada, where we were the successful bidder on
four leases, covering almost 14,000km2 offshore Nova Scotia, for which
award is expected to be completed in early 2013; Egypt, where we
farmed in to two blocks covering 1,400km2; deepwater Gulf of Mexico,
where we were assigned 51 leases covering 1,200km2; Namibia, where
we farmed in to five deepwater blocks covering 22,900km2; Uruguay,
where we signed three production sharing agreements (PSAs) for
deepwater exploration blocks covering almost 26,000km2; and the
onshore US, where we signed an agreement to lease 300km2 in the
Utica/Point Pleasant shale formation in Ohio.
Our exploration and appraisal programme is currently active in Algeria,
Angola, Australia, Azerbaijan, Brazil, Canada, Egypt, the deepwater Gulf of
Mexico, Jordan, Namibia, Trinidad, the UK North Sea, Oman and
onshore US.
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 2012 our exploration and appraisal costs, excluding lease acquisitions,
were $4,317 million, compared with $2,398 million in 2011 and $2,706
million in 2010. 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 58% of 2012 exploration and appraisal
costs were directed towards appraisal activity. In 2012, we participated in
177 gross (46.2 net) exploration and appraisal wells in eight countries.
Total exploration expense in 2012 of $1,475 million (2011 $1,520 million
and 2010 $843 million) included the write-off of expenses related to
unsuccessful drilling activities in the UK North Sea ($97 million), Namibia
($64 million) and others ($72 million). It also included $97 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
Reserves booking from new discoveries will depend on the results of
ongoing technical and commercial evaluations, including appraisal drilling.
The Upstream segment’s total hydrocarbon reserves, on an oil equivalent
basis including equity-accounted entities comprised 11,685mmboe
(10,213mmboe for subsidiaries and 1,472mmboe for equity-accounted
entities) at 31 December 2012, a decrease of 10% (decrease of 11% for
subsidiaries and decrease of 3% for equity-accounted entities) compared
with the 31 December 2011 reserves of 12,946mmboe (11,426mmboe
for subsidiaries and 1,520mmboe for equity-accounted entities).
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 2012 the proved reserves replacement ratio for the Upstream
segment, excluding acquisitions and disposals, was 6% for subsidiaries
and equity-accounted entities, –5% for subsidiaries alone and 65% for