BP 2013 Annual Report Download - page 33

Strategic report
BP Annual Report and Form 20-F 2013 29
a Liquids comprise crude oil, condensate, NGLs and bitumen.
b Includes 21 million barrels (14 million barrels at 31 December 2012 and 20 million barrels at
31 December 2011) in respect of the 30% non-controlling interest in BP Trinidad & Tobago LLC.
c BP’s share of reserves of equity-accounted entities in the Upstream segment. During 2013,
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 2,685 billion cubic feet of natural gas (2,890 billion cubic feet at 31 December 2012
and 2,759 billion cubic feet at 31 December 2011) 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 Upstream segment’s total hydrocarbon reserves, on an oil
equivalent basis including equity-accounted entities comprised
11,422mmboe (10,243mmboe for subsidiaries and 1,179mmboe for
equity-accounted entities) at 31 December 2013, a decrease of 2%
(decrease of 2% for subsidiaries and decrease of 8% for equity-
accounted entities) compared with the 31 December 2012 reserves of
11,685mmboe (10,408mmboe for subsidiaries and 1,277mmboe for
equity-accounted entities).
Proved reserves replacement ratio
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 2013 the proved reserves replacement ratio for the
Upstream segment, excluding acquisitions and disposals, was 93% for
subsidiaries and equity-accounted entities, 105% for subsidiaries alone
and 30% for equity-accounted entities alone. For more information on
proved reserves replacement for the group, see page 247.
Developments
The map on page 28 shows our major development areas, which
include Alaska, Angola, Australia, Azerbaijan, Canada, Egypt, the
deepwater Gulf of Mexico and the UK North Sea.
Three major project start-ups were achieved in 2013: Atlantis
North expansion Phase 1 in the Gulf of Mexico; Angola LNG; and North
Rankin Phase 2 in Australia.
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.
• Angola – we had our first LNG cargo in June and at the end of 2013
around 1 million cubic metres of LNG had been produced. The Plutão,
Saturno, Vénus and Marte (PSVM) project reached plateau
production of 150mb/d and the Cravo, Lirio, Orquidea, Violeta (CLOV)
floating production storage and offloading vessel (FPSO) sailed away
from Angola Paenal in January 2014 to start the offshore hook-up and
commissioning campaign.
• Azerbaijan – the Shah Deniz consortium – a seven-member group
led by BP – selected the Trans Adriatic Pipeline to deliver gas
volumes from the Shah Deniz Stage 2 project to customers in
Greece, Italy and southern Europe. In August, 25-year sales
agreements were concluded for over 10bcma of gas, to be produced
from the Shah Deniz field as a result of Stage 2. This adds to existing
agreements to sell 6bcma in Turkey. The final investment decision on
the project was made in December.
• North Sea – we continued to see high levels of activity, including the
ramp-up of major project volumes, a significant level of turnaround
activity, progress in the major redevelopment of the west of Shetland
Schiehallion and Loyal fields, the installation of the platform jackets
on the Clair Ridge project, a major milestone, and the sale of a
number of non-strategic assets.
• Gulf of Mexico – we had 10 rigs operating at the end of the year, the
highest number ever. Atlantis North expansion Phase 1 started up in
April. Following our strategic divestment programme, we now have a
very focused portfolio with growth potential around four operated
and three non-operated hubs.
In April the decision was taken not to move forward with the existing
development plan for the Mad Dog Phase 2 project in the deepwater
Gulf of Mexico, as market conditions and industry cost inflation made
the project less attractive than previously modelled. This decision
resulted in an impairment of $159 million. BP and its co-owners
reviewed alternative development concepts and the current concept
being considered is a single production host designed for future
flexibility in evaluating how best to capture additional potential resource.
Development expenditure of subsidiaries incurred in 2013,
excluding midstream activities, was $13.6 billion (2012 $12.6 billion,
2011 $10.4 billion).
Production
Our oil and natural gas production assets are located onshore and
offshore and include wells, gathering centres, in-field flow lines,
processing facilities, storage facilities, offshore platforms, export systems
(e.g. transit lines), pipelines and LNG plant facilities. The principal areas
of production are Angola, Argentina, Australia, Azerbaijan, Egypt, Trinidad,
the UAE, the UK and the US.
Maximizing value at Mad Dog
We continually review the development concepts of our projects to make sure they maximize
value for shareholders. One example of this is Mad Dog Phase 2 in the Gulf of Mexico. The project
builds on the existing Mad Dog development, which is designed to process 80,000 barrels of oil and
60 million cubic feet of gas per day.
For Phase 2, we originally planned to develop the remaining resource potential of the Mad Dog field
through a large second platform. However, as we progressed the design and reviewed cost
estimates, it became clear that market conditions and industry cost inflation made that selected
concept less attractive than initially modelled.
As part of our commitment to efficient investments, we reviewed alternative lower-cost
development concepts to ensure that we optimize project value and make the best financial
choices. The current concept being considered consists of a subsea development with a single new
production host that has been designed for future flexibility, allowing capture of additional resource
potential.
We continue to review options to further enhance value including simplifying the topsides and
subsea design, optimizing the location and number of wells and evaluating the required time to
achieve first oil production. We expect the revised project to show improved economics compared
with the previous concept.
We select only the best options that maximize value.