BP 2007 Annual Report Download - page 23

– In 2007, we spent more than $250 million (BP net) in Alaska on a
programme to upgrade or replace pipelines, increase inspection and
corrosion monitoring, carry out preventative maintenance and repairs,
expand capacity, and improve the efficiency of major facilities in all
BP-operated fields.
– We have also made progress on the replacement of sections of oil
transit lines in the Prudhoe Bay field, which for these transit lines has
included adding pipeline pigging facilities to clean and inspect
pipelines, direct corrosion inhibitor injection, new leak detection and
corrosion monitoring systems. We aim to complete this activity in
2008.
– On 16 February 2007, BP temporarily shut down its Northstar
production facility for 18 days to repair welds in the low pressure gas
piping system. The facility was restarted on 6 March. The full-year
impact of the production disruption resulting from this shutdown was
more than offset by the beneficial impacts of an earlier-than-planned
restart of the Milne Point K Pad pipeline replacement and strong
reservoir performance throughout 2007 at Prudhoe Bay and Kuparuk.
– On 25 October 2007, BP Exploration Alaska (BPXA) entered into a plea
agreement with the US Department of Justice (DOJ), which ended
both federal and state government criminal investigations of BPXA on
matters related to the March and August 2006 oil transit line spills in
Alaska. On 29 November 2007, in accordance with the agreement,
BPXA pleaded guilty to a misdemeanour violation of the US Federal
Water Pollution Control Act. BPXA paid a $12 million (gross) fine and
is subject to one-to-three years probation. BPXA also paid restitution
of $4 million (gross) to the State of Alaska and paid another $4 million
(gross) to the National Fish and Wildlife Foundation for Arctic
environmental research. The DOJ and the State of Alaska have agreed
not to bring any further criminal charges against BPXA in connection
with the March and August 2006 spills.
– On 2 June 2007, the Alaska Gasline Inducement Act (AGIA) was
passed into law. AGIA sets out the terms and conditions for
application for the exclusive right to build a natural gas pipeline to
transport North Slope gas to market. BP stated publicly that it cannot
submit a conforming bid under AGIA because of, in its view,
unresolved risks and uncertainties related to project costs, fiscal terms
and pipeline tariffs. BP continues to develop and assess options for
commercializing the major undeveloped gas resources on Alaska’s
North Slope.
– On 16 November 2007, the Alaska State Legislature passed a new
petroleum production tax law, which replaced the Petroleum
Production Tax legislation enacted in 2006. The new legislation
increases production taxes and is effective retrospectively from 1 July
2007. The key terms of the new production tax law include a base oil
tax rate of 25% on net profits, with progressive increases expected in
the oil tax rate as the net margin increases above $30/bbl. The new
production tax law will be governed by regulations to be defined and
promulgated in 2008 by the Alaska State Department of Revenue.
– On 26 December 2007, the Alaska Superior Court issued a ruling
reversing the 2006 decision by the Department of Natural Resources
(DNR) to terminate the Point Thomson Unit and remanded the matter
to the DNR to provide the leaseholders their constitutional due
process rights, including the right to a hearing. Although the judge’s
decision found that the DNR’s rejection of the latest plan of
development (POD) was supported by substantial evidence, the ruling
reinstated the leaseholders’ interests in the Point Thomson leases and
unit, and instructed the DNR to consider ‘good and diligent oil and
gas . . . production practices’ in shaping an appropriate remedy for the
rejected POD. The DNR is expected to call a hearing during the first
quarter of 2008.
– On 3 October 2007, the Endicott field achieved its 20th year of
production. Since start-up in 1987, Endicott has produced 500mmboe.
During 2007, Endicott commenced a technology trial programme that
is expected to progress BP’s LoSal
2
Enhanced Oil Recovery process
from technology development to technology deployment. LoSal
2
is a
patented technology that utililizes geochemically specific waters to
attack the larger remaining residual oils present after conventional
waterflooding. To gain partner approval for a full-field deployment, an
interwell programme has been started at Endicott. Results from this
programme are expected in the second half of 2008 and are expected
to lead to a full-field project commitment in 2009. The LoSal
2
technology has implications for many fields beyond BP’s Alaska
portfolio and the work at Endicott and in Alaska will be extrapolated to
BP’s global portfolio.
– On 3 January 2008, the US Minerals Management Service approved
BP’s development and production plan for the Liberty field. During
2007, $25 million was spent on pre-project planning for Liberty,
including engineering, environmental studies and permit applications.
Development plans for Liberty, which lies offshore to the east of the
Endicott field, include ultra-extended reach wells to be drilled from
pads at Endicott and processing Liberty oil production through existing
Endicott facilities.
United Kingdom
We are the largest producer of oil, second largest producer of gas and
the largest overall producer of hydrocarbons in the UK. In 2007, total
liquids production was 201mb/d, a 20% decrease on 2006, and gas
production was 768mmcf/d, an 18% decrease on 2006. This decrease in
production was driven by natural decline and the unplanned shutdown of
the Central Area Transmission System (CATS) pipeline. Our activities in
the North Sea are focused on safe operations, efficient delivery of
production and midstream operations, in-field drilling and selected new
field developments. Our development expenditure (excluding midstream)
in the UK was $804 million in 2007, compared with $794 million in 2006
and $790 million in 2005.
Significant events in 2007 were:
– During the second quarter, we announced the decision not to proceed
with the decarbonized fuel DF1 project in Scotland. This project was
being led by BP, in partnership with Scottish and Southern Energy,
and would have produced hydrogen as a ‘decarbonized’ fuel for use in
power generation, with the carbon dioxide (CO
2
) gases being exported
to the Miller oil reservoir in the North Sea for increased oil recovery
and ultimate storage. Significant investment had been made in front-
end engineering and design activity. Development of the project was
originally planned to begin at the end of 2006 and required UK
government support. In May, the UK government announced that it
would not decide which carbon capture storage project to support
until 2008 at the earliest. The timing of this decision did not fit with
the DF1 project timeline, which was constrained by the maturity of
the Miller oil field, and therefore the decision was taken not to
proceed. The Miller field, which began production in 1992, has now
ceased production and decommissioning activity is in the planning
stage.
– We sanctioned the Dimlington Onshore Compression and Terminals
Integration project, a $250-million investment in new gas compression
facilities at the BP-operated Dimlington Terminal, which receives gas
from fields in the southern North Sea. This new equipment is
expected to reduce pipeline pressure between the offshore fields and
the terminal, allowing the gas fields to increase production. BP
expects remaining recoverable reserves in the West Sole and
Amethyst fields to increase by around 30% as a result of this project.
– In October, we announced changes to the structure of the North Sea
operations that are intended to simplify the organization and improve
the efficiency of work processes in response to the challenges of the
increasingly mature North Sea, where declining production and rapidly-
rising costs have created business conditions that are not sustainable
in the long term. The new structure will mean fewer organizational
units and reduced management layers. This will allow consolidation of
onshore non-technical support activities, leading to economies of scale
and reduced complexity.
Rest of Europe
Development expenditure (excluding midstream) in the Rest of Europe
was $443 million, compared with $214 million in 2006 and $188 million
in 2005.
BP ANNUAL REPORT AND ACCOUNTS 2007 21