BP 2014 Annual Report Download - page 31

In January 2015, we received formal licences for El Matariya and Karawan
concessions in Egypt after ratification and finalization of the agreements.
During the year we participated in five discoveries that are potentially
commercial including: one in Egypt with the BG-operated Notus well in the
El Burg concession; one in the pre-salt play of Angola with the Orca well in
Block 20, operated by Cobalt International Energy; one at Xerelete in Brazil’s
Campos basin, operated by Total; one at Vorlich in the North Sea, which
spans the GDF-SUEZ-operated block 30/1f and the BP-operated block 30/1c;
and Guadalupe in the deepwater Gulf of Mexico, operated by Chevron.
Exploration and appraisal costs
Excluding lease acquisitions, the costs for exploration and appraisal costs
were $2,911 million (2013 $4,811 million, 2012 $4,356 million). 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 31% of exploration and appraisal costs were directed
towards appraisal activity. We participated in 67 gross (32.75 net)
exploration and appraisal wells in 10 countries.
Exploration expense
Total exploration expense of $3,632 million (2013 $3,441 million, 2012 $1,475
million) included the write-off of expenses related to unsuccessful drilling
activities or lease expiration in the Lower 48 ($665 million), Algeria ($524
million), India ($139 million), the Gulf of Mexico ($500 million), Brazil ($368
million), China ($112 million), Angola ($110 million), Morocco ($83 million) and
others ($133 million). In addition, $395 million was written off KG D6 in India as
a result of uncertainty in the future long-term gas price outlook (see page 216).
Upstream reserves
Estimated net proved reservesa (net of royalties)
2014 2013 2012
Liquids million barrels
Crude oilb
Subsidiaries 3,582 3,798 4,082
Equity-accounted entitiesc702 729 813
4,283 4,527 4,895
Natural gas liquids
Subsidiaries 510 551 591
Equity-accounted entitiesc16 16 25
526 567 616
Total liquids
Subsidiariesd4,092 4,349 4,672
Equity-accounted entitiesc717 745 838
4,809 5,094 5,510
Natural gas billion cubic feet
Subsidiariese 32,496 34,187 33,264
Equity-accounted entitiesc 2,373 2,517 2,549
34,869 36,704 35,813
Total hydrocarbons million barrels of oil equivalent
Subsidiaries 9,694 10,243 10,408
Equity-accounted entitiesc1,126 1,179 1,277
10,821 11,422 11,685
a Because of rounding, some totals may not agree exactly with the sum of their component parts.
b Includes condensate and bitumen.
c BP’s share of reserves of equity-accounted entities in the Upstream segment. During 2014,
upstream operations in Abu Dhabi, Argentina and Bolivia, as well as some of our operations in
Angola and Indonesia, were conducted through equity-accounted entities.
d Includes 21 million barrels (21 million barrels at 31 December 2013 and 14 million barrels at
31 December 2012) in respect of the 30% non-controlling interest in BP Trinidad & Tobago LLC.
e Includes 2,519 billion cubic feet of natural gas (2,685 billion cubic feet at 31 December 2013 and
2,890 billion cubic feet at 31 December 2012) in respect of the 30% non-controlling interest in BP
Trinidad & Tobago LLC.
Reserves booking
Reserves booking from new discoveries will depend on the results of
ongoing technical and commercial evaluations, including appraisal drilling.
The segment’s total hydrocarbon reserves on an oil equivalent basis,
including equity-accounted entities at 31 December 2014, decreased by
5% (5% for subsidiaries and 4% for equity-accounted entities) compared
with reserves at 31 December 2013.
Proved reserves replacement ratio★
The proved reserves replacement ratio for the Upstream segment in 2014,
excluding acquisitions and disposals, was 31% for subsidiaries and
equity-accounted entities (2013 93%), 29% for subsidiaries alone (2013
105%) and 43% for equity-accounted entities alone (2013 30%). For more
information on proved reserves replacement for the group see page 219.
Developments
The map on page 26 shows our major development areas. We achieved
seven major project start-ups in 2014: the Chirag oil project in Azerbaijan;
Na Kika Phase 3, Mars B and Atlantis North expansion Phase 2 in the Gulf
of Mexico; CLOV in Angola; Kinnoull in the North Sea and Sunrise in
Canada. In addition to starting up major projects, we made good progress
in the four areas we believe most likely to provide us with higher-value
barrels – Angola, Azerbaijan, the North Sea and the Gulf of Mexico.
t Angola – we had an oil and gas discovery, Orca, in the pre-salt play of
Angola in Block 20 (BP 30%), operated by Cobalt International Energy,
Inc. and the CLOV project reached plateau production of 160mboe/d.
t "[FSCBJKBOo the Shah Deniz and South Caucasus Pipeline consortia
awarded further key contracts for the development of the Shah Deniz
Stage 2 and South Caucasus Pipeline expansion projects. The BP-
operated Azerbaijan International Operating Company celebrated the
20th anniversary of the Azeri-Chirag-Gunashli PSA.
t /PSUI4FBo we continued to see high levels of activity, including a new
discovery, Vorlich, in the central North Sea (see page 28); progress in the
major redevelopment of the west of Shetland Schiehallion and Loyal fields;
and the restart of operations at the Rhum field. BP has been granted
seven awards in the UK government’s 28th licensing round. The blocks
are located in three of our core areas: to the north of our Magnus field,
next to Vorlich, and west of our Kinnoull development. The government is
still to award some blocks in this round. These blocks are undergoing
environmental assessment.
Unlocking hidden resources
Accessing gas resources locked in hot sandstone almost three miles
below the earth’s surface is a task that our advanced technology and
exploration experience has made possible.
Faced with the particular challenge of Oman’s remote desert, we used
our expertise to safely and successfully complete one of our largest ever
3D seismic surveys across the Khazzan field, an area the size of Greater
London. To unlock this huge resource, we used the technical knowledge
we gained from accessing the tight gas★ that is common in our US
Lower 48 onshore business.
We proved our approach by conducting an extended well test –
producing gas from four appraisal wells and acquiring a surveillance
programme that significantly helped our understanding of the reservoir
and enabled us to proceed with a field development plan. By the end of
2014, we had three rigs in operation and large-scale construction under
way to build the central processing facility, roads and well pads, as well as
workforce accommodation and facilities.
Khazzan represents the first phase in developing one of the largest
known tight gas accumulations in the Middle East. It has the potential
to be a major new source of gas supply for Oman over many decades.
We seek efficient ways to deliver projects on time and on budget.
★ Defined on page 252. BP Annual Report and Form 20-F 2014 27
Strategic report