TIDMBP.
RNS Number : 2299U
BP PLC
28 July 2015
BP p.l.c. Top of page
Group results 1
Second quarter and half year 2015(a)
FOR IMMEDIATE RELEASE London 28 July 2015
Second First Second First First
quarter quarter quarter half half
2014 2015 2015 $ million 2015 2014
======== ======== ======== ======== ======
3,369 2,602 (5,823) Profit (loss) for the period(b) (3,221) 6,897
Inventory holding (gains) losses*,
(187) (499) (443) net of tax (942) (240)
======== ======== ======== ==================================== ======== ======
3,182 2,103 (6,266) Replacement cost profit (loss)* (4,163) 6,657
Net (favourable) unfavourable
impact
of non-operating items* and fair
value
453 474 7,579 accounting effects*, net of tax 8,053 203
======== ======== ======== ==================================== ======== ======
3,635 2,577 1,313 Underlying replacement cost profit* 3,890 6,860
======== ======== ======== ==================================== ======== ======
Replacement cost profit (loss)
17.25 11.54 (34.25) per ordinary share (cents) (22.77) 36.05
1.03 0.69 (2.05) per ADS (dollars) (1.37) 2.16
Underlying replacement cost profit
19.71 14.14 7.17 per ordinary share (cents) 21.27 37.15
1.18 0.85 0.43 per ADS (dollars) 1.28 2.23
======== ======== ======== ==================================== ======== ======
-- BP's second-quarter replacement cost (RC) loss was $6,266
million, compared with a profit of $3,182 million a year ago. After
adjusting for a net charge for non-operating items of $7,486
million, mainly relating to the recently announced agreements in
principle to settle federal, state and the vast majority of local
government claims arising from the 2010 Deepwater Horizon accident,
and net unfavourable fair value accounting effects of $93 million
(both on a post-tax basis), underlying RC profit for the second
quarter was $1,313 million, compared with $3,635 million for the
same period in 2014. For the half year, RC loss was $4,163 million,
compared with a profit of $6,657 million a year ago. After
adjusting for a net charge for non-operating items of $7,899
million and net unfavourable fair value accounting effects of $154
million (both on a post-tax basis), underlying RC profit for the
half year was $3,890 million, compared with $6,860 million for the
same period in 2014. Non-operating items include a restructuring
charge of $272 million for the quarter and $487 million for the
half year. Restructuring charges are now expected to be around $1.5
billion by the end of 2015 relative to the $1 billion we announced
back in December. RC profit or loss for the group, underlying RC
profit or loss and fair value accounting effects are non-GAAP
measures and further information is provided on pages 3 and 30.
-- On 2 July 2015, BP announced that it has reached agreements
in principle to settle all outstanding federal and state claims and
claims made by more than 400 local government entities arising from
the 2010 Deepwater Horizon oil spill. BP has accepted releases
received from the vast majority of local government entities and
the District Court has ordered BP to commence processing payments
under the releases.
-- The group income statement for the second quarter reflects a
pre-tax charge of $9.8 billion related to the agreements in
principle. All amounts relating to the Gulf of Mexico oil spill
have been treated as non-operating items, with a net pre-tax charge
of $10,755 million for the second quarter and $11,087 million for
the half year ($7,154 million and $7,374 million respectively on a
post-tax basis). For further information on the Gulf of Mexico oil
spill and its consequences see page 10 and Note 2 on page 18. See
also Principal risks and uncertainties on page 34 and Legal
proceedings on page 35.
-- Including the impact of the Gulf of Mexico oil spill, net
cash provided by operating activities for the second quarter and
half year was $6.3 billion and $8.1 billion respectively, compared
with $7.9 billion and $16.1 billion for the same periods in 2014.
Excluding amounts related to the Gulf of Mexico oil spill, net cash
provided by operating activities for the second quarter and half
year was $6.4 billion and $8.9 billion respectively, compared with
$7.6 billion and $16.5 billion for the same periods in 2014.
-- Net debt* at 30 June 2015 was $24.8 billion, compared with
$24.4 billion a year ago. The net debt ratio* at 30 June 2015 was
18.8%, compared with 15.5% a year ago. Net debt and the net debt
ratio are non-GAAP measures. See page 26 for more information.
-- Total capital expenditure on an accruals basis for the second
quarter was $4.7 billion, of which organic capital expenditure* was
$4.5 billion, compared with $5.6 billion for the same period in
2014, almost all of which was organic. For the half year, total
capital expenditure on an accruals basis was $9.1 billion, of which
organic capital expenditure was $8.9 billion, compared with $11.7
billion for the same period in 2014, of which organic capital
expenditure was $11.0 billion. For full year 2015, we now expect
organic capital expenditure to be below $20 billion.
-- BP today announced a quarterly dividend of 10.00 cents per
ordinary share ($0.600 per ADS), which is expected to be paid on 18
September 2015. The corresponding amount in sterling will be
announced on 8 September 2015. See page 25 for further
information.
* For items marked with an asterisk throughout this document, definitions
are provided in the Glossary on page 32.
(a) This results announcement also represents BP's half-yearly financial
report (see page 11).
(b) Profit attributable to BP shareholders.
The commentaries above and following should be read in conjunction
with the cautionary statement on page 38.
--------------------------------------------------------------------------------
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Group headlines (continued)
-- In October 2013, BP announced plans to divest a further $10
billion of assets before the end of 2015, having completed its
earlier divestment programme of $38 billion. Transactions to date
have reached around $7.4 billion. Disposal proceeds were $0.5
billion for the second quarter and $2.3 billion for the half year.
The half-year amount includes proceeds from our Toledo refinery
partner, Husky Energy, in place of capital commitments relating to
the original divestment transaction that have not been subsequently
sanctioned.
-- The effective tax rate (ETR) on RC profit or loss for the
second quarter and half year was 33% and 47% compared with 34% and
32% for the same periods in 2014. Excluding the one-off deferred
tax adjustment in the first quarter 2015 as a result of the
reduction in the UK North Sea supplementary charge, the ETR for the
half year was 35%. Adjusting for non-operating items, fair value
accounting effects and the first-quarter 2015 one-off deferred tax
adjustment, the underlying ETR in the second quarter and half year
was 35% and 28% respectively, compared with 33% for the same
periods in 2014. The underlying ETR for the half year is lower than
a year ago mainly due to changes in the mix of our profits and
certain one-off items, partly offset by foreign exchange effects
from a stronger US dollar.
-- Finance costs and net finance expense relating to pensions
and other post-retirement benefits were a charge of $364 million
for the second quarter, compared with $356 million for the same
period in 2014. For the half year, the respective amounts were $722
million and $723 million.
Top of page 3
Analysis of RC profit (loss) before interest and tax
and reconciliation to profit (loss) for the period
Second First Second First First
quarter quarter quarter half half
2014 2015 2015 $ million 2015 2014
======== ======== ========= ========= ========
RC profit (loss) before interest
and tax*
4,049 372 228 Upstream 600 8,708
933 2,083 1,628 Downstream 3,711 1,727
1,024 183 510 Rosneft 693 1,542
(434) (308) (455) Other businesses and corporate (763) (931)
(251) (323) (10,747) Gulf of Mexico oil spill response(a) (11,070) (280)
(76) (129) (39) Consolidation adjustment - UPII* (168) 14
======== ======== ========= ========================================== ========= ========
RC profit (loss) before interest
5,245 1,878 (8,875) and tax (6,997) 10,780
Finance costs and net finance
expense relating to
pensions and other post-retirement
(356) (358) (364) benefits (722) (723)
(1,643) 632 3,013 Taxation on a RC basis 3,645 (3,245)
(64) (49) (40) Non-controlling interests (89) (155)
======== ======== ========= ========================================== ========= ========
RC profit (loss) attributable
3,182 2,103 (6,266) to BP shareholders (4,163) 6,657
======== ======== ========= ========================================== ========= ========
258 756 627 Inventory holding gains (losses) 1,383 360
Taxation (charge) credit on inventory
holding gains
(71) (257) (184) and losses (441) (120)
======== ======== ========= ========================================== ========= ========
Profit (loss) for the period attributable
to
3,369 2,602 (5,823) BP shareholders (3,221) 6,897
======== ======== ========= ========================================== ========= ========
(a) See Note 2 on page 18 for further information on the accounting
for the Gulf of Mexico oil spill response.
Analysis of underlying RC profit before interest and tax
Second First Second First First
quarter quarter quarter half half
2014 2015 2015 $ million 2015 2014
======== ======== ======== ====== ========
Underlying RC profit before interest
and tax*
4,655 604 494 Upstream 1,098 9,056
733 2,158 1,867 Downstream 4,025 1,744
1,024 183 510 Rosneft 693 1,295
(438) (290) (401) Other businesses and corporate (691) (927)
(76) (129) (39) Consolidation adjustment - UPII (168) 14
======== ======== ======== ===================================== ====== ========
Underlying RC profit before interest
5,898 2,526 2,431 and tax 4,957 11,182
Finance costs and net finance
expense relating to
pensions and other post-retirement
(347) (349) (356) benefits (705) (704)
(1,852) 449 (722) Taxation on an underlying RC basis (273) (3,463)
(64) (49) (40) Non-controlling interests (89) (155)
======== ======== ======== ===================================== ====== ========
Underlying RC profit attributable
3,635 2,577 1,313 to BP shareholders 3,890 6,860
======== ======== ======== ===================================== ====== ========
Reconciliations of underlying RC profit or loss to the nearest
equivalent IFRS measure are provided on page 1 for the group and on
pages 4-9 for the segments.
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Upstream
Second First Second First First
quarter quarter quarter half half
2014 2015 2015 $ million 2015 2014
======== ======== ======== ====== ======
4,048 390 225 Profit before interest and tax 615 8,701
1 (18) 3 Inventory holding (gains) losses* (15) 7
======== ======== ======== ===================================== ====== ======
RC profit before interest and
4,049 372 228 tax 600 8,708
Net (favourable) unfavourable
impact of
non-operating items* and fair
606 232 266 value accounting effects* 498 348
======== ======== ======== ===================================== ====== ======
Underlying RC profit before interest
4,655 604 494 and tax*(a) 1,098 9,056
======== ======== ======== ===================================== ====== ======
(a) See page 5 for a reconciliation to segment RC profit before interest
and tax by region.
Financial results
The replacement cost profit before interest and tax for the
second quarter and half year was $228 million and $600 million
respectively, compared with $4,049 million and $8,708 million for
the same periods in 2014. The second quarter and half year included
a net non-operating charge of $236 million and $478 million
respectively, compared with a net non-operating charge of $516
million and $240 million for the same periods a year ago. Fair
value accounting effects in the second quarter and half year had
unfavourable impacts of $30 million and $20 million respectively,
compared with unfavourable impacts of $90 million and $108 million
in the same periods of 2014.
After adjusting for non-operating items and fair value
accounting effects, the underlying replacement cost profit before
interest and tax for the second quarter and half year was $494
million and $1,098 million respectively, compared with $4,655
million and $9,056 million for the same periods in 2014. The result
for the second quarter reflected significantly lower liquids and
gas realizations and higher exploration write-offs, partly offset
by lower costs including the benefits from simplification and
efficiency activities. In Libya, we recorded exploration write-offs
and other costs totalling $598 million in the quarter. The result
for the first half reflected significantly lower liquids and gas
realizations, and lower gas marketing and trading results, partly
offset by increased production and lower costs. Costs were lower
reflecting benefits from simplification and efficiency activities
and lower exploration write-offs, partly offset by rig cancellation
costs.
Production
Production for the quarter was 2,112mboe/d, 0.3% higher than the
second quarter of 2014. Underlying production* for the quarter
decreased by 1.7%, mainly due to increased seasonal turnaround
activity partly offset by the ramp-up of major projects which
started up in 2014. For the first half, production was 2,209mboe/d,
4.3% higher than in the same period of 2014. First-half underlying
production was 1.0% higher than in 2014.
Key events
In April, BP confirmed the start of oil production from the
Kizomba Satellites Phase-2 development in Block 15, offshore
Angola. This deepwater project is operated by ExxonMobil.
In April, BP signed agreements to become a shareholder in the
Trans Anatolian Natural Gas Pipeline (TANAP), and will hold a 12%
equity share in the project. TANAP is a central part of the
Southern Corridor pipeline system that will transport gas from the
Shah Deniz field in Azerbaijan to markets in Turkey, Greece,
Bulgaria and Italy.
BP signed agreements to purchase a 20% participatory interest in
Taas-Yuryakh Neftegazodobycha, a Rosneft subsidiary which will
further develop the Srednebotuobinskoye oil and gas condensate
field in East Siberia. Related to this, Rosneft and BP will jointly
undertake the exploration of an Area of Mutual Interest in the
region. Rosneft and BP have also agreed to jointly explore two
additional Areas of Mutual Interest in the West Siberian and
Yenisey-Khatanga basins covering a combined area of approximately
260,000km(2) .
Greater Plutonio Phase 3 successfully started up production,
BP's second major project start-up in Angola this year.
In Australia, front-end engineering and design has commenced on
the Browse floating LNG development.
Following Atoll in the first quarter, we made a further gas
discovery at the Nooros prospect, located in the Abu Madi West
concession in the Nile Delta in Egypt, operated by our partner ENI.
BP holds a 25% interest.
This builds on the progress we announced with our first-quarter
results, which comprised the following: the gas discovery in the
North Damietta Offshore Concession in the East Nile Delta in Egypt
at the Atoll-1 Deepwater exploration well; the final agreements for
two West Nile Delta projects Taurus/Libra and Giza/Fayoum/Raven
with an estimated investment of around $12 billion by BP and its
partner; the start of production at the Sunrise Phase 1 in-situ oil
sands project in Alberta, Canada; and the sale of BP's equity in
the Central Area Transmission System (CATS) business in the UK
North Sea to Antin Infrastructure Partners.
Outlook
Looking ahead, we expect third-quarter 2015 reported production
to be broadly flat with the second quarter, primarily reflecting
the continuation of seasonal maintenance activity consistent with
the second-quarter activity levels.
The commentary above contains forward-looking statements and should
be read in conjunction with the cautionary statement on page 38.
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Upstream
Second First Second First First
quarter quarter quarter half half
2014 2015 2015 $ million 2015 2014
======== ======== ======== ====== ======
Underlying RC profit (loss) before
interest and tax
1,419 (545) (66) US (611) 2,150
3,236 1,149 560 Non-US 1,709 6,906
======== ======== ======== =================================== ====== ======
4,655 604 494 1,098 9,056
======== ======== ======== =================================== ====== ======
Non-operating items
(72) (68) (135) US (203) (131)
(444) (174) (101) Non-US (275) (109)
======== ======== ======== =================================== ====== ======
(516) (242) (236) (478) (240)
======== ======== ======== =================================== ====== ======
Fair value accounting effects
(31) (3) (55) US (58) (80)
(59) 13 25 Non-US 38 (28)
======== ======== ======== =================================== ====== ======
(90) 10 (30) (20) (108)
======== ======== ======== =================================== ====== ======
RC profit (loss) before interest
and tax
1,316 (616) (256) US (872) 1,939
2,733 988 484 Non-US 1,472 6,769
======== ======== ======== =================================== ====== ======
4,049 372 228 600 8,708
======== ======== ======== =================================== ====== ======
Exploration expense
68 78 194 US(a) 272 727
321 94 708 Non-US(b) 802 610
======== ======== ======== =================================== ====== ======
389 172 902 1,074 1,337
======== ======== ======== =================================== ====== ======
Production (net of royalties)(c)
Liquids* (mb/d)
429 392 334 US 362 413
92 112 147 Europe 130 99
562 754 631 Rest of World 692 572
======== ======== ======== =================================== ====== ======
1,083 1,258 1,111 1,184 1,084
======== ======== ======== =================================== ====== ======
Natural gas (mmcf/d)
1,525 1,517 1,477 US 1,497 1,502
166 264 281 Europe 273 182
4,244 4,307 4,046 Rest of World 4,176 4,317
======== ======== ======== =================================== ====== ======
5,936 6,088 5,805 5,945 6,001
======== ======== ======== =================================== ====== ======
Total hydrocarbons* (mboe/d)
692 653 588 US 621 672
121 158 196 Europe 177 130
1,293 1,496 1,328 Rest of World 1,412 1,316
======== ======== ======== =================================== ====== ======
2,106 2,307 2,112 2,209 2,118
======== ======== ======== =================================== ====== ======
Average realizations(d)
96.90 46.79 56.69 Total liquids ($/bbl) 51.49 97.03
5.67 4.44 3.80 Natural gas ($/mcf) 4.12 5.94
64.90 37.00 40.04 Total hydrocarbons ($/boe) 38.47 65.53
======== ======== ======== =================================== ====== ======
(a) First half 2014 includes a $521-million write-off relating to the
Utica shale acreage in Ohio, following the decision not to proceed
with development plans.
(b) Second quarter and first half 2015 include a $432-million write-off
in Libya. BP has declared force majeure in Libya and there is significant
uncertainty on when drilling operations might be able to proceed.
(c) Includes BP's share of production of equity-accounted entities in
the Upstream segment.
(d) Based on sales by consolidated subsidiaries only - this excludes
equity-accounted entities.
Because of rounding, some totals may not agree exactly with the sum
of their component parts.
Top of page 6
Downstream
Second First Second First First
quarter quarter quarter half half
2014 2015 2015 $ million 2015 2014
======== ======== ======== ======== ======
1,166 2,783 2,234 Profit before interest and tax 5,017 2,037
(233) (700) (606) Inventory holding (gains) losses* (1,306) (310)
======== ======== ======== ===================================== ======== ======
933 2,083 1,628 RC profit before interest and tax 3,711 1,727
Net (favourable) unfavourable impact
of
non-operating items* and fair
(200) 75 239 value accounting effects* 314 17
======== ======== ======== ===================================== ======== ======
Underlying RC profit before interest
733 2,158 1,867 and tax*(a) 4,025 1,744
======== ======== ======== ===================================== ======== ======
(a) See page 7 for a reconciliation to segment RC profit before interest
and tax by region and by business.
Financial results
The replacement cost profit before interest and tax for the
second quarter and half year was $1,628 million and $3,711 million
respectively, compared with $933 million and $1,727 million for the
same periods in 2014.
The 2015 results include a net non-operating charge of $122
million for the second quarter and $85 million for the half year
mainly reflecting restructuring charges, compared with a net
non-operating gain of $50 million and a net non-operating charge of
$228 million for the same periods in 2014 (see pages 7 and 29 for
further information on non-operating items). Fair value accounting
effects had unfavourable impacts of $117 million for the second
quarter and $229 million for the half year, compared with
favourable impacts of $150 million and $211 million in the same
periods of 2014.
After adjusting for non-operating items and fair value
accounting effects, the underlying replacement cost profit before
interest and tax for the second quarter and half year was $1,867
million and $4,025 million respectively, compared with $733 million
and $1,744 million for the same periods in 2014.
Replacement cost profit before interest and tax for the fuels,
lubricants and petrochemicals businesses is set out on page 7.
Fuels business
The fuels business reported an underlying replacement cost
profit before interest and tax of $1,394 million for the second
quarter and $3,190 million for the half year, compared with $516
million and $1,216 million for the same periods in 2014. The
results for the quarter and half year were driven by improved
refining environment and production mix, partially offset by weaker
North American crude oil differentials. The quarter and half year
also benefited from a higher oil supply and trading contribution,
returning to average levels in the second quarter, as well as lower
costs, including the benefits from our simplification and
efficiency programmes.
During the quarter we completed the cessation of refining
operations at our Bulwer Island facility and we announced, with our
partner, Rosneft, a planned reorganization of our German refining
joint operations. In the first quarter we announced the sale of our
bitumen business in Australia and completed the sale of our
interest in UTA, a European fuel cards business.
Lubricants business
The lubricants business reported an underlying replacement cost
profit before interest and tax of $397 million in the second
quarter and $742 million in the half year, compared with $315
million and $622 million in the same periods last year. The strong
quarterly and half-year performance reflects continued momentum in
growth markets, premium brand performance and benefits from our
simplification and efficiency programmes leading to lower costs.
These benefits were partially offset by adverse foreign exchange
effects.
Petrochemicals business
The petrochemicals business reported an underlying replacement
cost profit before interest and tax of $76 million in the second
quarter and $93 million in the half year, compared with losses of
$98 million and $94 million in the same periods last year. The
improved results reflect stronger operational performance, improved
margins and the benefits of our simplification and efficiency
programmes.
Our new advanced technology purified terephthalic acid (PTA)
plant in Zhuhai, China which will add over one million tonnes of
PTA capacity per year, is now fully commissioned and
operational.
Outlook
Looking forward to the third quarter, we expect reduced refining
margins and lower levels of turnaround activity.
The commentary above contains forward-looking statements and should
be read in conjunction with the cautionary statement on page 38.
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Downstream
Second First Second First First
quarter quarter quarter half half
2014 2015 2015 $ million 2015 2014
======== ======== ======== ====== ======
Underlying RC profit before interest
and tax -
by region
331 661 576 US 1,237 743
402 1,497 1,291 Non-US 2,788 1,001
======== ======== ======== ===================================== ====== ======
733 2,158 1,867 4,025 1,744
======== ======== ======== ===================================== ====== ======
Non-operating items
180 (4) 63 US 59 179
(130) 41 (185) Non-US (144) (407)
======== ======== ======== ===================================== ====== ======
50 37 (122) (85) (228)
======== ======== ======== ===================================== ====== ======
Fair value accounting effects
206 (127) (48) US (175) 297
(56) 15 (69) Non-US (54) (86)
======== ======== ======== ===================================== ====== ======
150 (112) (117) (229) 211
======== ======== ======== ===================================== ====== ======
RC profit before interest and
tax
717 530 591 US 1,121 1,219
216 1,553 1,037 Non-US 2,590 508
======== ======== ======== ===================================== ====== ======
933 2,083 1,628 3,711 1,727
======== ======== ======== ===================================== ====== ======
Underlying RC profit (loss) before
interest
and tax - by business(a)(b)
516 1,796 1,394 Fuels 3,190 1,216
315 345 397 Lubricants 742 622
(98) 17 76 Petrochemicals 93 (94)
======== ======== ======== ===================================== ====== ======
733 2,158 1,867 4,025 1,744
======== ======== ======== ===================================== ====== ======
Non-operating items and fair value
accounting
effects(c)
15 (60) (152) Fuels (212) (202)
186 (14) (87) Lubricants (101) 186
(1) (1) - Petrochemicals (1) (1)
======== ======== ======== ===================================== ====== ======
200 (75) (239) (314) (17)
======== ======== ======== ===================================== ====== ======
RC profit (loss) before interest
and tax(a)(b)
531 1,736 1,242 Fuels 2,978 1,014
501 331 310 Lubricants 641 808
(99) 16 76 Petrochemicals 92 (95)
======== ======== ======== ===================================== ====== ======
933 2,083 1,628 3,711 1,727
======== ======== ======== ===================================== ====== ======
BP average refining marker margin
15.4 15.2 19.4 (RMM)* ($/bbl) 17.3 14.4
======== ======== ======== ===================================== ====== ======
Refinery throughputs (mb/d)
645 623 622 US 623 630
757 805 810 Europe 807 777
250 324 224 Rest of World 274 279
======== ======== ======== ===================================== ====== ======
1,652 1,752 1,656 1,704 1,686
======== ======== ======== ===================================== ====== ======
95.3 94.3 94.0 Refining availability* (%) 94.1 95.1
======== ======== ======== ===================================== ====== ======
Marketing sales of refined products
(mb/d)
1,183 1,098 1,145 US 1,122 1,152
1,154 1,174 1,160 Europe 1,167 1,146
515 607 569 Rest of World 588 530
======== ======== ======== ===================================== ====== ======
2,852 2,879 2,874 2,877 2,828
Trading/supply sales of refined
2,468 2,544 2,649 products 2,597 2,442
======== ======== ======== ===================================== ====== ======
Total sales volumes of refined
5,320 5,423 5,523 products 5,474 5,270
======== ======== ======== ===================================== ====== ======
Petrochemicals production (kte)
969 905 946 US 1,851 2,040
895 972 852 Europe 1,824 1,867
1,501 1,663 1,898 Rest of World 3,561 2,923
======== ======== ======== ===================================== ====== ======
3,365 3,540 3,696 7,236 6,830
======== ======== ======== ===================================== ====== ======
(a) Segment-level overhead expenses are included in the fuels business
result.
(b) BP's share of income from petrochemicals at our Gelsenkirchen and
Mülheim sites in Germany is reported in the fuels business.
(c) For Downstream, fair value accounting effects arise solely in the
fuels business.
Top of page 8
Rosneft
Second First Second First First
quarter quarter quarter half half
2014 2015 2015(a) $ million 2015(a) 2014
======== ======== ======== ======== ======
1,050 221 534 Profit before interest and tax(b) 755 1,599
(26) (38) (24) Inventory holding (gains) losses* (62) (57)
======== ======== ======== ====================================== ======== ======
RC profit before interest and
1,024 183 510 tax 693 1,542
Net charge (credit) for non-operating
- - - items* - (247)
======== ======== ======== ====================================== ======== ======
Underlying RC profit before interest
1,024 183 510 and tax* 693 1,295
======== ======== ======== ====================================== ======== ======
Replacement cost profit before interest and tax for the second
quarter and half year was $510 million and $693 million
respectively, compared with $1,024 million and $1,542 million for
the same periods in 2014.
There were no non-operating items in the second quarter 2015,
half year 2015, or second quarter 2014, and there was a
non-operating gain of $247 million in the first half of 2014.
After adjusting for non-operating items, the underlying
replacement cost profit for the second quarter and half year was
$510 million and $693 million respectively, compared with $1,024
million and $1,295 million for the same periods in 2014. Compared
with the same period last year, the result for the second quarter
was primarily affected by lower oil prices. For the half year, the
result was primarily affected by lower oil prices partly offset by
favourable foreign exchange effects.
See also Group statement of comprehensive income - Share of
items relating to equity-accounted entities, net of tax, and
footnote (a), on page 14 for other foreign exchange effects.
A second BP representative, Guillermo Quintero, president of BP
Energy do Brasil Ltda, was elected to Rosneft's board of directors
at Rosneft's Annual General Meeting of Shareholders (AGM) on 17
June 2015.
Rosneft's AGM also approved the distribution of a dividend of
8.21 roubles per share. We received our share of this dividend in
July 2015, which amounted to $271 million after the deduction of
withholding tax.
Second First Second First First
quarter quarter quarter half half
2014 2015 2015(a) 2015(a) 2014
======== ======== ======== ======== ======
Production (net of royalties) (BP
share)
820 816 815 Liquids* (mb/d) 815 825
1,036 1,225 1,172 Natural gas (mmcf/d) 1,198 1,030
999 1,027 1,017 Total hydrocarbons* (mboe/d) 1,022 1,002
======== ======== ======== ================================== ======== ======
(a) The operational and financial information of the Rosneft segment
for the second quarter and first half is based on preliminary operational
and financial results of Rosneft for the six months ended 30 June
2015. Actual results may differ from these amounts.
(b) The Rosneft segment result includes equity-accounted earnings arising
from BP's 19.75% shareholding in Rosneft as adjusted for the accounting
required under IFRS relating to BP's purchase of its interest in
Rosneft and the amortization of the deferred gain relating to the
disposal of BP's interest in TNK-BP. These adjustments have increased
the reported profit for the second quarter and first half 2015,
as shown in the table above, compared with the equivalent amount
in Russian roubles that we expect Rosneft to report in its own financial
statements under IFRS. BP's share of Rosneft's profit before interest
and tax for each year-to-date period is calculated by translating
the amounts reported in Russian roubles into US dollars using the
average exchange rate for the year to date. BP's share of Rosneft's
earnings after finance costs, taxation and non-controlling interests,
as adjusted, is included in the BP group income statement within
profit before interest and taxation.
Top of page 9
Other businesses and corporate
Second First Second First First
quarter quarter quarter half half
2014 2015 2015 $ million 2015 2014
======== ======== ======== ====== ======
Profit (loss) before interest and
(434) (308) (455) tax (763) (931)
- - - Inventory holding (gains) losses* - -
======== ======== ======== ====================================== ====== ======
RC profit (loss) before interest
(434) (308) (455) and tax (763) (931)
Net charge (credit) for non-operating
(4) 18 54 items* 72 4
======== ======== ======== ====================================== ====== ======
Underlying RC profit (loss) before
(438) (290) (401) interest and tax* (691) (927)
======== ======== ======== ====================================== ====== ======
Underlying RC profit (loss) before
interest and tax
(226) (62) (144) US (206) (325)
(212) (228) (257) Non-US (485) (602)
======== ======== ======== ====================================== ====== ======
(438) (290) (401) (691) (927)
======== ======== ======== ====================================== ====== ======
Non-operating items
4 (1) (10) US (11) 3
- (17) (44) Non-US (61) (7)
======== ======== ======== ====================================== ====== ======
4 (18) (54) (72) (4)
======== ======== ======== ====================================== ====== ======
RC profit (loss) before interest
and tax
(222) (63) (154) US (217) (322)
(212) (245) (301) Non-US (546) (609)
======== ======== ======== ====================================== ====== ======
(434) (308) (455) (763) (931)
======== ======== ======== ====================================== ====== ======
Other businesses and corporate comprises biofuels and wind
businesses, shipping, treasury (which includes interest income on
the group's cash and cash equivalents), and corporate activities
including centralized functions.
Financial results
The replacement cost loss before interest and tax for the second
quarter and half year was $455 million and $763 million
respectively, compared with $434 million and $931 million for the
same periods in 2014.
The second-quarter result included a net non-operating charge of
$54 million, compared with a net non-operating gain of $4 million a
year ago. For the half year, the net non-operating charge was $72
million, compared with a net non-operating charge of $4 million a
year ago.
After adjusting for non-operating items, the underlying
replacement cost loss before interest and tax for the second
quarter and half year was $401 million and $691 million
respectively, compared with $438 million and $927 million for the
same periods in 2014. The 2015 results reflected improved business
performance and lower corporate and functional costs, partly offset
by adverse foreign exchange impacts.
Biofuels
The net ethanol-equivalent production (which includes ethanol
and sugar) for the second quarter was 247 million litres, compared
with 113 million litres for the same period in 2014, as there was
no production in the second quarter of 2014 at one of our mills in
Brazil due to an expansion project.
Wind
Net wind generation capacity*(a) was 1,588MW at 30 June 2015,
compared with 1,590MW at 30 June 2014. BP's net share of wind
generation for the second quarter and half year was 1,150GWh and
2,277GWh respectively, compared with 1,248GWh and 2,540GWh for the
same periods in 2014.
(a) Capacity figures include 32MW in the Netherlands managed by our Downstream
segment.
Top of page 10
Gulf of Mexico oil spill
We announced on 2 July 2015 that BP Exploration & Production
Inc. has reached agreements in principle with the US federal
government and five Gulf states to settle all outstanding federal
and state claims arising from the Deepwater Horizon oil spill. The
agreement with the Gulf states also provides for the settlement of
claims made by more than 400 local government entities. The
agreements in principle are subject to execution of definitive
agreements, including a Consent Decree with the United States and
Gulf states with respect to the Clean Water Act and natural
resource damage claims. The definitive agreements will only become
effective if there is final court approval of the Consent Decree.
We expect that the definitive agreement with the Gulf states will
be executed and that the court will approve the Consent Decree. BP
advised the Court that it is satisfied with and has accepted
releases received from the vast majority of local government
entities. Accordingly, on 27 July, the District Court ordered BP to
commence processing payments required under the releases and that
such payments be made within 30 days of the Court's order.
The agreements in principle do not cover claims relating to the
2012 class action settlements with the Plaintiffs' Steering
Committee, including business economic loss claims; private claims
from other litigants not included within the class action
settlements; or private securities litigation in MDL 2185.
For further details see Note 2 on page 18 and Legal proceedings
on page 35.
Financial update
The replacement cost loss before interest and tax for the second
quarter and half year was $10,747 million and $11,070 million
respectively, compared with $251 million and $280 million for the
same periods last year. The second-quarter loss reflects a $9.8
billion charge associated with the government settlements mentioned
above, additional claims administration costs and business economic
loss claims under the Plaintiffs' Steering Committee settlement,
and adjustments to other provisions, as well as the ongoing costs
of the Gulf Coast Restoration Organization. The cumulative pre-tax
charge recognized to date amounts to $54.6 billion.
The cumulative income statement charge does not include amounts
for obligations that BP currently considers are not possible to
measure reliably. The total amounts that will ultimately be paid by
BP in relation to the incident will be dependent on many factors,
as discussed under Provisions and contingent liabilities in Note 2
on page 20. These could have a material impact on our consolidated
financial position, results and cash flows.
Top of page 11
Half-yearly financial report
This results announcement also represents BP's half-yearly
financial report for the purposes of the Disclosure and
Transparency Rules made by the UK Financial Conduct Authority. In
this context: (i) the condensed set of financial statements can be
found on pages 13-27; (ii) pages 1-10, and 28-38 comprise the
interim management report; and (iii) the directors' responsibility
statement and auditors' independent review report can be found on
pages 11-12.
Statement of directors' responsibilities
The directors confirm that, to the best of their knowledge, the
condensed set of financial statements on pages 13-27 has been
prepared in accordance with IAS 34 'Interim Financial Reporting',
and that the interim management report on pages 1-10 and 28-38
includes a fair review of the information required by the
Disclosure and Transparency Rules.
The directors of BP p.l.c. are listed on pages 52-55 of BP
Annual Report and Form 20-F 2014, with the exception of George
David who retired at the 2015 Annual General Meeting and Paula
Rosput Reynolds and Sir John Sawers who joined the board on 14 May
2015.
By order of the board
Bob Dudley Brian Gilvary
Group Chief Executive Chief Financial Officer
27 July 2015 27 July 2015
Top of page 12
Independent review report to BP p.l.c.
We have been engaged by the company to review the condensed set
of financial statements in the half-yearly financial report for the
six months ended 30 June 2015 which comprises the group income
statement, group statement of comprehensive income, group statement
of changes in equity, group balance sheet, condensed group cash
flow statement, and Notes 1 to 10. We have read the other
information contained in the half-yearly financial report and
considered whether it contains any apparent misstatements or
material inconsistencies with the information in the condensed set
of financial statements.
This report is made solely to the company in accordance with
guidance contained in International Standard on Review Engagements
(UK and Ireland) 2410, 'Review of Interim Financial Information
Performed by the Independent Auditor of the Entity' issued by the
Auditing Practices Board for use in the United Kingdom (ISRE 2410).
To the fullest extent permitted by law, we do not accept or assume
responsibility to anyone other than the company, for our work, for
this report, or for the conclusions we have formed.
Directors' responsibilities
The half-yearly financial report is the responsibility of, and
has been approved by, the directors. The directors are responsible
for preparing the half-yearly financial report in accordance with
the Disclosure and Transparency Rules of the United Kingdom's
Financial Conduct Authority.
As disclosed in Note 1, the annual financial statements of the
group are prepared in accordance with International Financial
Reporting Standards (IFRS) as issued by the International
Accounting Standards Board (IASB) and IFRS as adopted by the
European Union (EU). The condensed set of financial statements
included in this half-yearly financial report has been prepared in
accordance with International Accounting Standard 34, 'Interim
Financial Reporting', as issued by the IASB and as adopted by the
EU.
Our responsibility
Our responsibility is to express to the company a conclusion on
the condensed set of financial statements in the half-yearly
financial report based on our review.
Scope of review
We conducted our review in accordance with ISRE 2410. A review
of interim financial information consists of making enquiries,
primarily of persons responsible for financial and accounting
matters, and applying analytical and other review procedures. A
review is substantially less in scope than an audit conducted in
accordance with International Standards on Auditing (UK and
Ireland) and consequently does not enable us to obtain assurance
that we would become aware of all significant matters that might be
identified in an audit. Accordingly, we do not express an audit
opinion.
Conclusion
Based on our review, nothing has come to our attention that
causes us to believe that the condensed set of financial statements
in the half-yearly financial report for the six months ended 30
June 2015 is not prepared, in all material respects, in accordance
with International Accounting Standard 34 as issued by the IASB and
as adopted by the EU and the Disclosure and Transparency Rules of
the United Kingdom's Financial Conduct Authority.
Ernst & Young LLP
London
27 July 2015
The maintenance and integrity of the BP p.l.c. website are the
responsibility of the directors; the review work carried out by the
auditors does not involve consideration of these matters and,
accordingly, the auditors accept no responsibility for any changes
that may have occurred to the financial information since it was
initially presented on the website.
Legislation in the United Kingdom governing the preparation and
dissemination of financial statements may differ from legislation
in other jurisdictions.
Top of page 13
Financial statements
Group income statement
Second First Second First First
quarter quarter quarter half half
2014 2015 2015 $ million 2015 2014
======== ======== ======== ======== ========
Sales and other operating revenues
93,957 54,196 60,646 (Note 4) 114,842 185,667
Earnings from joint ventures -
155 104 156 after interest and tax 260 270
Earnings from associates - after
1,228 362 670 interest and tax 1,032 2,011
157 120 195 Interest and other income 315 488
Gains on sale of businesses and
330 138 133 fixed assets 271 379
======== ======== ======== ========================================== ======== ========
95,827 54,920 61,800 Total revenues and other income 116,720 188,815
74,536 37,936 44,748 Purchases 82,684 146,004
6,980 7,000 17,185 Production and manufacturing expenses 24,185 13,811
Production and similar taxes (Note
816 362 173 5) 535 1,802
3,751 3,836 3,765 Depreciation, depletion and amortization 7,601 7,341
Impairment and losses on sale of
businesses and
774 197 286 fixed assets 483 1,200
389 172 902 Exploration expense 1,074 1,337
Distribution and administration
3,078 2,783 2,989 expenses 5,772 6,180
Profit (loss) before interest and
5,503 2,634 (8,248) taxation (5,614) 11,140
277 281 289 Finance costs 570 564
Net finance expense relating to
pensions and other
79 77 75 post-retirement benefits 152 159
======== ======== ======== ========================================== ======== ========
5,147 2,276 (8,612) Profit (loss) before taxation (6,336) 10,417
1,714 (375) (2,829) Taxation (3,204) 3,365
======== ======== ======== ========================================== ======== ========
3,433 2,651 (5,783) Profit (loss) for the period (3,132) 7,052
======== ======== ======== ========================================== ======== ========
Attributable to
3,369 2,602 (5,823) BP shareholders (3,221) 6,897
64 49 40 Non-controlling interests 89 155
======== ======== ======== ========================================== ======== ========
3,433 2,651 (5,783) (3,132) 7,052
======== ======== ======== ========================================== ======== ========
Earnings per share (Note 6)
Profit (loss) for the period attributable
to BP shareholders
Per ordinary share (cents)
18.26 14.28 (31.83) Basic (17.62) 37.35
18.15 14.21 (31.83) Diluted (17.62) 37.11
Per ADS (dollars)
1.10 0.86 (1.91) Basic (1.06) 2.24
1.09 0.85 (1.91) Diluted (1.06) 2.23
======== ======== ======== ========================================== ======== ========
Top of page 14
Financial statements (continued)
Group statement of comprehensive income
Second First Second First First
quarter quarter quarter half half
2014 2015 2015 $ million 2015 2014
======== ======== ======== ======== ======
3,433 2,651 (5,783) Profit (loss) for the period (3,132) 7,052
======== ======== ======== ============================================= ======== ======
Other comprehensive income
Items that may be reclassified
subsequently to profit
or loss
1,005 (1,612) 698 Currency translation differences (914) 92
Exchange gains (losses) on translation
of foreign
operations reclassified to gain
or loss on sale of
- - 16 business and fixed assets 16 -
Available-for-sale investments
2 - 1 marked to market 1 (1)
Available-for-sale investments
reclassified to the
1 - - income statement - 1
77 (212) 128 Cash flow hedges marked to market (84) 100
Cash flow hedges reclassified
to the
(49) 74 81 income statement 155 (69)
Cash flow hedges reclassified
(2) 5 4 to the balance sheet 9 (3)
Share of items relating to equity-accounted
entities,
51 (80) 329 net of tax(a) 249 (22)
Income tax relating to items
9 124 (92) that may be reclassified 32 9
======== ======== ======== ============================================= ======== ======
1,094 (1,701) 1,165 (536) 107
======== ======== ======== ============================================= ======== ======
Items that will not be reclassified
to profit or loss
Remeasurements of the net pension
and other post-
retirement benefit liability
222 (568) 2,688 or asset 2,120 (714)
Share of items relating to equity-accounted
entities,
- - - net of tax - 5
Income tax relating to items
that will not
(73) 158 (754) be reclassified (596) 221
======== ======== ======== ============================================= ======== ======
149 (410) 1,934 1,524 (488)
======== ======== ======== ============================================= ======== ======
1,243 (2,111) 3,099 Other comprehensive income 988 (381)
======== ======== ======== ============================================= ======== ======
4,676 540 (2,684) Total comprehensive income (2,144) 6,671
======== ======== ======== ============================================= ======== ======
Attributable to
4,606 513 (2,732) BP shareholders (2,219) 6,509
70 27 48 Non-controlling interests 75 162
======== ======== ======== ============================================= ======== ======
4,676 540 (2,684) (2,144) 6,671
======== ======== ======== ============================================= ======== ======
(a) Includes the effects of hedge accounting adopted by Rosneft from
1 October 2014 in relation to a portion of future export revenue
denominated in US dollars. For further information see BP Annual
Report and Form 20-F 2014 - Financial statements - Note 15.
Top of page 15
Financial statements (continued)
Group statement of changes in equity
BP
shareholders' Non-controlling Total
$ million equity interests equity
============== ================ ========
At 1 January 2015 111,441 1,201 112,642
============================================== ============== ================ ========
Total comprehensive income (2,219) 75 (2,144)
Dividends (3,400) (42) (3,442)
Share-based payments, net of tax 300 - 300
Share of equity-accounted entities' changes
in equity, net of tax (3) - (3)
Transactions involving non-controlling
interests - (2) (2)
============================================== ============== ================ ========
At 30 June 2015 106,119 1,232 107,351
============================================== ============== ================ ========
BP
shareholders' Non-controlling Total
$ million equity interests equity
============== ================ ========
At 1 January 2014 129,302 1,105 130,407
============================================== ============== ================ ========
Total comprehensive income 6,509 162 6,671
Dividends (2,999) (153) (3,152)
Repurchases of ordinary share capital (1,527) - (1,527)
Share-based payments, net of tax 576 - 576
Transactions involving non-controlling
interests - 3 3
============================================== ============== ================ ========
At 30 June 2014 131,861 1,117 132,978
============================================== ============== ================ ========
Top of page 16
Financial statements (continued)
Group balance sheet
30 June 31 December
$ million 2015 2014
======== ============
Non-current assets
Property, plant and equipment 130,659 130,692
Goodwill 11,837 11,868
Intangible assets 19,411 20,907
Investments in joint ventures 9,037 8,753
Investments in associates 11,340 10,403
Other investments 1,108 1,228
========================================================= ======== ============
Fixed assets 183,392 183,851
Loans 584 659
Trade and other receivables 2,310 4,787
Derivative financial instruments 3,965 4,442
Prepayments 999 964
Deferred tax assets 2,011 2,309
Defined benefit pension plan surpluses 1,223 31
========================================================= ======== ============
194,484 197,043
======== ============
Current assets
Loans 325 333
Inventories 20,034 18,373
Trade and other receivables 31,476 31,038
Derivative financial instruments 3,599 5,165
Prepayments 1,899 1,424
Current tax receivable 731 837
Other investments 294 329
Cash and cash equivalents 32,589 29,763
========================================================= ======== ============
90,947 87,262
Total assets 285,431 284,305
========================================================= ======== ============
Current liabilities
Trade and other payables 40,077 40,118
Derivative financial instruments 2,863 3,689
Accruals 5,770 7,102
Finance debt 9,110 6,877
Current tax payable 1,881 2,011
Provisions 5,666 3,818
========================================================= ======== ============
65,367 63,615
Non-current liabilities
Other payables 2,942 3,587
Derivative financial instruments 3,847 3,199
Accruals 937 861
Finance debt 47,994 45,977
Deferred tax liabilities 9,975 13,893
Provisions 37,039 29,080
Defined benefit pension plan and other post-retirement
benefit plan deficits 9,979 11,451
========================================================= ======== ============
112,713 108,048
======== ============
Total liabilities 178,080 171,663
========================================================= ======== ============
Net assets 107,351 112,642
========================================================= ======== ============
Equity
BP shareholders' equity 106,119 111,441
Non-controlling interests 1,232 1,201
========================================================= ======== ============
107,351 112,642
======== ============
Top of page 17
Financial statements (continued)
Condensed group cash flow statement
Second First Second First First
quarter quarter quarter half half
2014 2015 2015 $ million 2015 2014
======== ======== ======== ======== =========
Operating activities
5,147 2,276 (8,612) Profit (loss) before taxation (6,336) 10,417
Adjustments to reconcile profit
(loss) before
taxation to net cash provided
by operating activities
Depreciation, depletion and amortization
and
exploration expenditure written
3,953 3,928 4,571 off 8,499 8,375
Impairment and (gain) loss on
sale of businesses
444 59 153 and fixed assets 212 821
Earnings from equity-accounted
entities, less
(1,080) (276) (654) dividends received (930) (1,764)
Net charge for interest and other
finance expense,
(3) 129 13 less net interest paid 142 167
178 (238) 255 Share-based payments 17 284
Net operating charge for pensions
and other post-
retirement benefits, less contributions
and benefit
(105) (57) (30) payments for unfunded plans (87) (207)
Net charge for provisions, less
56 388 10,700 payments 11,088 (137)
Movements in inventories and other
current and
654 (3,858) 492 non-current assets and liabilities (3,366) 339
(1,367) (493) (602) Income taxes paid (1,095) (2,187)
======== ======== ======== ============================================= ======== =========
Net cash provided by operating
7,877 1,858 6,286 activities 8,144 16,108
======== ======== ======== ============================================= ======== =========
Investing activities
(5,499) (4,636) (4,529) Capital expenditure (9,165) (11,390)
- - - Acquisitions, net of cash acquired - (10)
(3) (69) (54) Investment in joint ventures (123) (36)
(47) (87) (218) Investment in associates (305) (135)
Proceeds from disposal of fixed
227 653 308 assets 961 1,205
Proceeds from disposal of businesses,
net of
571 1,087 224 cash disposed 1,311 597
53 3 45 Proceeds from loan repayments 48 70
======== ======== ======== ============================================= ======== =========
(4,698) (3,049) (4,224) Net cash used in investing activities (7,273) (9,699)
======== ======== ======== ============================================= ======== =========
Financing activities
(447) - - Net repurchase of shares - (2,173)
856 7,788 83 Proceeds from long-term financing 7,871 6,835
(1,720) (2,307) (542) Repayments of long-term financing (2,849) (2,957)
Net increase (decrease) in short-term
(57) 725 (13) debt 712 20
Dividends
(1,572) (1,709) (1,691) paid - BP shareholders (3,400) (2,999)
(140) (12) (30) - non-controlling interests (42) (153)
======== ======== ======== ============ =============================== ======== =========
Net cash provided by (used in)
(3,080) 4,485 (2,193) financing activities 2,292 (1,427)
======== ======== ======== ============================================= ======== =========
Currency translation differences
relating to cash and
49 (623) 286 cash equivalents (337) 4
======== ======== ======== ============================================= ======== =========
Increase (decrease) in cash and
148 2,671 155 cash equivalents 2,826 4,986
======== ======== ======== ============================================= ======== =========
Cash and cash equivalents at beginning
27,358 29,763 32,434 of period 29,763 22,520
Cash and cash equivalents at end
27,506 32,434 32,589 of period 32,589 27,506
======== ======== ======== ============================================= ======== =========
Top of page 18
Financial statements (continued)
Notes
1. Basis of preparation
The interim financial information included in this report has
been prepared in accordance with IAS 34 'Interim Financial
Reporting'.
The results for the interim periods are unaudited and, in the
opinion of management, include all adjustments necessary for a fair
presentation of the results for each period. All such adjustments
are of a normal recurring nature. This report should be read in
conjunction with the consolidated financial statements and related
notes for the year ended 31 December 2014 included in the BP Annual
Report and Form 20-F 2014.
The directors have made an assessment of the group's ability to
continue as a going concern and consider it appropriate to adopt
the going concern basis of accounting in preparing these interim
financial statements.
BP prepares its consolidated financial statements included
within BP Annual Report and Form 20-F on the basis of International
Financial Reporting Standards (IFRS) as issued by the International
Accounting Standards Board (IASB), IFRS as adopted by the European
Union (EU) and in accordance with the provisions of the UK
Companies Act 2006. IFRS as adopted by the EU differs in certain
respects from IFRS as issued by the IASB. The differences have no
impact on the group's consolidated financial statements for the
periods presented.
The financial information presented herein has been prepared in
accordance with the accounting policies expected to be used in
preparing BP Annual Report and Form 20-F 2015, which do not differ
significantly from those used in BP Annual Report and Form 20-F
2014.
2. Gulf of Mexico oil spill
(a) Overview
As a consequence of the Gulf of Mexico oil spill, BP continues
to incur various costs and has also recognized liabilities for
future costs. The information presented in this note should be read
in conjunction with BP Annual Report and Form 20-F 2014 - Financial
statements - Note 2 and Legal proceedings on page 228 and on page
35 of this report.
The group income statement includes a pre-tax charge of $10,755
million for the second quarter and $11,087 million for the first
half of 2015 in relation to the Gulf of Mexico oil spill. The
second-quarter charge includes additional amounts provided for the
Clean Water Act penalty, natural resource damages and state and
local government claims following the 2 July 2015 agreements in
principle to settle all federal and state claims and claims made by
more than 400 local government entities arising from the oil spill
(the Agreements in Principle). The second-quarter charge also
reflects additional business economic loss claims and claims
administration costs under the Plaintiffs' Steering Committee (PSC)
settlement and the ongoing costs of the Gulf Coast Restoration
Organization. The cumulative pre-tax income statement charge since
the incident, in April 2010, amounts to $54,582 million.
The cumulative income statement charge does not include amounts
for obligations that BP considers are not possible, at this time,
to measure reliably. For further information, see Provisions and
contingent liabilities below.
The Agreements in Principle signed on 2 July 2015 are subject to
execution of definitive agreements including a Consent Decree with
the United States and Gulf states with respect to the Clean Water
Act penalty and natural resource damages and other claims, a
settlement agreement with five Gulf states with respect to state
claims for economic loss, property damage and other claims, and
release agreements for economic loss, property damage and other
claims with local government entities. The state and local
government claims cover economic loss, property damage, business
interruption, breach of contract, loss of royalties, lost tourism,
lost revenue, lost taxes, operating or other costs, losses or
damages arising under the Oil Pollution Act of 1990 and other
legislation. The Consent Decree will be subject to public comment
and final court approval. The Consent Decree and settlement
agreement with the Gulf states are conditional upon each other and
neither will become effective unless there is final court approval
of the Consent Decree and local government entities execute
releases to BP's satisfaction. We expect that the definitive
agreement with the Gulf states will be executed and that the court
will approve the Consent Decree. BP advised the Court that it is
satisfied with and has accepted releases received from the vast
majority of local government entities. Accordingly, on 27 July, the
District Court ordered BP to commence processing payments required
under the releases and that such payments be made within 30 days of
the Court's order. As part of the Agreements in Principle, BP
agreed to pay up to $1 billion to resolve claims made by local
government entities. For more information on the Agreements in
Principle see Legal proceedings on page 35.
The Agreements in Principle described above significantly reduce
the uncertainties faced by BP following the Gulf of Mexico oil
spill in 2010. There continues to be uncertainty regarding the
outcome or resolution of current or future litigation and the
extent and timing of costs and liabilities relating to the incident
not covered by the Agreements in Principle. The total amounts that
will ultimately be paid by BP in relation to the incident will be
dependent on many factors, as discussed under Provisions and
contingent liabilities below, including in relation to any new
information or future developments. These uncertainties could have
a material impact on our consolidated financial position, results
and cash flows.
Top of page 19
Financial statements (continued)
Notes
2. Gulf of Mexico oil spill (continued)
The amounts set out below reflect the impacts on the financial
statements of the Gulf of Mexico oil spill for the periods
presented. The income statement, balance sheet and cash flow
statement impacts are included within the relevant line items in
those statements as set out below.
Second First Second First First
quarter quarter quarter half half
2014 2015 2015 $ million 2015 2014
======== ======== ========= ========= ======
Income statement
Production and manufacturing
251 323 10,747 expenses 11,070 280
======== ======== ========= ============================== ========= ======
Profit (loss) before interest
(251) (323) (10,747) and taxation (11,070) (280)
9 9 8 Finance costs 17 19
======== ======== ========= ============================== ========= ======
(260) (332) (10,755) Profit (loss) before taxation (11,087) (299)
44 112 3,601 Taxation 3,713 54
======== ======== ========= ============================== ========= ======
(216) (220) (7,154) Profit (loss) for the period (7,374) (245)
======== ======== ========= ============================== ========= ======
30 June 31 December
$ million 2015 2014
========= ============
Balance sheet
Current assets
Trade and other receivables 2,638 1,154
Current liabilities
Trade and other payables (817) (655)
Accruals (40) -
Provisions (3,569) (1,702)
======================================= ========= ============
Net current assets (liabilities) (1,788) (1,203)
======================================= ========= ============
Non-current assets
Trade and other receivables 203 2,701
Non-current liabilities
Other payables (2,077) (2,412)
Accruals (190) (169)
Provisions (14,424) (6,903)
Deferred tax 5,436 1,723
======================================= ========= ============
Net non-current assets (liabilities) (11,052) (5,060)
======================================= ========= ============
Net assets (liabilities) (12,840) (6,263)
======================================= ========= ============
Second First Second First First
quarter quarter quarter half half
2014 2015 2015 $ million 2015 2014
======== ======== ========= ========= ======
Cash flow statement - Operating
activities
(260) (332) (10,755) Profit (loss) before taxation (11,087) (299)
Adjustments to reconcile profit
(loss) before
taxation to net cash provided
by
operating activities
Net charge for interest and
other finance
expense, less net interest
9 9 8 paid 17 19
Net charge for provisions,
116 227 10,607 less payments 10,834 19
Movements in inventories and
other current
and non-current assets and
(33) (595) 34 liabilities (561) (611)
======== ======== ========= ================================ ========= ======
(168) (691) (106) Pre-tax cash flows (797) (872)
======== ======== ========= ================================ ========= ======
Net cash from operating activities relating to the Gulf of
Mexico oil spill, on a post-tax basis, amounted to an outflow of
$106 million and outflow of $797 million in the second quarter and
first half of 2015 respectively. For the same periods in 2014, the
amounts were an inflow of $229 million and an outflow of $355
million respectively.
Top of page 20
Financial statements (continued)
Notes
2. Gulf of Mexico oil spill (continued)
Trust fund
BP established the Deepwater Horizon Oil Spill Trust (the
Trust), funded in the amount of $20 billion, to satisfy legitimate
individual and business claims, state and local government claims
resolved by BP, final judgments and settlements, state and local
response costs, and natural resource damages and related costs.
Fines and penalties are not covered by the trust fund.
The funding of the Trust was completed in 2012. The obligation
to fund the $20-billion trust fund, adjusted to take account of the
time value of money, was recognized in full in 2010 and charged to
the income statement. An asset has been recognized representing
BP's right to receive reimbursement from the trust fund. This is
the portion of the estimated future expenditure provided for that
will be settled by payments from the trust fund. During 2014,
cumulative charges to be paid by the Trust reached $20 billion.
Subsequent additional costs, over and above those provided within
the $20 billion, are expensed to the income statement as
incurred.
At 30 June 2015, $2,841 million of the provisions and payables
are eligible to be paid from the Trust. The reimbursement asset is
recorded within other receivables on the balance sheet, of which
$2,638 million is classified as current and $203 million as
non-current. During the second quarter of 2015, $523 million of
provisions and $19 million of payables were paid from the
Trust.
At 30 June 2015, the aggregate cash balances in the Trust and
the associated qualifying settlement funds amounted to $3.7
billion, including $0.8 billion remaining in the seafood
compensation fund which has yet to be distributed and $0.4 billion
held for natural resource damage early restoration projects. When
the cash balances in the trust fund are exhausted, payments in
respect of legitimate claims and other costs will be made directly
by BP.
(b) Provisions and contingent liabilities
BP has recorded certain provisions and disclosed certain
contingent liabilities as a consequence of the Gulf of Mexico oil
spill. These are described below and in more detail in BP Annual
Report and Form 20-F 2014 - Financial statements - Note 2.
Provisions
BP has recorded provisions relating to the Gulf of Mexico oil
spill in relation to environmental expenditure, litigation and
claims, and Clean Water Act penalties. Movements in each class of
provision during the second quarter and first half are presented in
the table below.
Litigation Clean
and Water Act
$ million Environmental claims penalties Total
============== =========== ========== =======
At 1 April 2015 760 3,764 3,510 8,034
Net increase in provision 5,443 4,520 700 10,663
Reclassified to other payables - (125) - (125)
Utilization - paid by BP (3) (53) - (56)
- paid by the trust
fund (15) (508) - (523)
===================== ============== =========== ========== =======
At 30 June 2015 6,185 7,598 4,210 17,993
=================================== ============== =========== ========== =======
Of which - current 399 3,170 - 3,569
- non-current 5,786 4,428 4,210 14,424
===================== ============== =========== ========== =======
Litigation Clean
and Water Act
Environmental claims penalties Total
============== =========== ========== =======
$ million
At 1 January 2015 1,141 3,954 3,510 8,605
Net increase in provision 5,444 4,814 700 10,958
Unwinding of discount 1 - - 1
Reclassified to other payables (329) (125) - (454)
Utilization - paid by BP (22) (102) - (124)
- paid by the trust
fund (50) (943) - (993)
============== =========================== ============== =========== ========== =======
At 30 June 2015 6,185 7,598 4,210 17,993
======================================= ============== =========== ========== =======
Top of page 21
Financial statements (continued)
Notes
2. Gulf of Mexico oil spill (continued)
Provisions recorded include $18.7 billion, plus interest and
adjusted to take account of the time value of money, in relation to
the Agreements in Principle. In addition, $0.4 billion has been
provided in relation to natural resource damage assessment costs
under the Agreements in Principle. After taking account of amounts
previously provided for, the net increase in provisions as a result
of the settlement amounted to $9.8 billion.
Environmental
The environmental provision includes amounts payable for natural
resource damage costs under one of the Agreements in Principle
referred to above. These amounts are payable in instalments over 16
years commencing one year after the court approves the Consent
Decree; the majority of the unpaid balance of this natural resource
damages settlement accrues interest at a fixed rate. The remaining
amounts payable under the $1-billion early restoration framework
agreement with natural resource trustees for the US and five Gulf
states are also included in environmental provisions.
Litigation and claims
The litigation and claims provision includes amounts that can be
estimated reliably for the future cost of settling claims by
individuals and businesses for damage to real or personal property,
lost profits or impairment of earning capacity and loss of
subsistence use of natural resources (Individual and Business
Claims), and amounts agreed under the Agreements in Principle in
relation to state claims and amounts in respect of local government
claims. Claims administration costs and legal costs have also been
provided for. Amounts that cannot be measured reliably and which
have therefore not been provided for are described under Contingent
liabilities below.
Litigation and claims - PSC settlement
BP has provided for its best estimate of the cost associated
with the PSC settlement agreements with the exception of the cost
of business economic loss claims, except where an eligibility
notice has been issued and is not subject to appeal by BP within
the claims facility. See BP Annual Report and Form 20-F 2014 -
Financial statements - Note 2 and Legal proceedings on pages
228-237 and page 35 of this report for further details on the
settlements with the PSC and related matters.
Management believes that no reliable estimate can currently be
made of any business economic loss claims not yet processed or
processed but not yet paid, except where an eligibility notice has
been issued and is not subject to appeal by BP within the claims
facility.
The submission deadline for business economic loss claims passed
on 8 June 2015; no further claims may be submitted. A significant
number of business economic loss claims have been received but have
not yet been processed and it is not possible to quantify the total
value of the claims.
A revised policy for the matching of revenue and expenses for
business economic loss claims was introduced in May 2014 and, of
the claims assessable under the new policy, the majority have not
yet been determined at this time. Uncertainties regarding the
proper application of the revised policy to particular claims and
categories of claims continue to arise as the claims administrator
has applied the revised policy. There have been no, or only a small
number of, claim determinations made under some of the specialized
frameworks that have been put in place for particular industries
and so determinations to date may not be representative of the
total population of claims. In addition, while detailed data on
pre-determination claims is not available due to a court order to
protect claimant confidentiality, aggregated pre-determination data
has recently been provided. While this data does provide some
insights, it is not at a sufficient level of detail to review claim
demographics or identify potential populations for each category of
claims.
There is limited data available to build up a track record of
claims determinations under the policies and protocols that are now
being applied following resolution of the matching and causation
issues. We are unable to reliably estimate future trends of the
number and proportion of claims that will be determined to be
eligible, nor can we reliably estimate the value of such claims. A
provision for such business economic loss claims will be
established when these uncertainties are resolved and a reliable
estimate can be made of the liability.
The current estimate for the total cost of those elements of the
PSC settlement that BP considers can be reliably estimated,
including amounts already paid, is $11.3 billion. The Deepwater
Horizon Court Supervised Settlement Program (DHCSSP) has issued
eligibility notices, many of which are disputed by BP, in respect
of business economic loss claims of approximately $415 million
which have not been provided for. The total cost of the PSC
settlement is likely to be significantly higher than the amount
recognized to date of $11.3 billion because the current estimate
does not reflect business economic loss claims not yet processed or
processed but not yet paid, except where an eligibility notice has
been issued and is not subject to appeal by BP within the claims
facility.
Top of page 22
Financial statements (continued)
Notes
2. Gulf of Mexico oil spill (continued)
There continues to be a high level of uncertainty in relation to
the amounts that ultimately will be paid in relation to current
claims as described above and in Legal proceedings on page 35 and
the outcomes of any further litigation including by parties
excluded from, or parties who opted out of, the PSC settlement, as
well as uncertainty arising from the PSC's appeal to the Fifth
Circuit of the District Court's 31 March 2015 decision to deny its
motion seeking to alter or amend the revised matching policy for
business economic loss claims. There is also uncertainty as to the
cost of administering the claims process under the DHCSSP and in
relation to future legal costs. The timing of payment of provisions
related to the PSC settlement is dependent upon ongoing claims
facility activity and is therefore also uncertain.
Litigation and claims - other claims
The provision recognized for litigation and claims includes
amounts agreed under the Agreements in Principle in relation to
state claims and amounts in respect of local government claims. The
amount provided in respect of state claims is payable over 18 years
from the date the court approves the Consent Decree, of which $1
billion is due following the court approval of the Consent Decree.
BP advised the Court that it is satisfied with and has accepted
releases received from the vast majority of local government
entities. Accordingly, on 27 July, the District Court ordered BP to
commence processing payments required under the releases and that
such payments be made within 30 days of the Court's order. As part
of the Agreements in Principle, BP agreed to pay up to $1 billion
to resolve claims made by local government entities.
See Legal proceedings on page 35 for further details.
Clean Water Act penalties
A provision has been recognized for penalties under Section 311
of the Clean Water Act, as agreed in the Agreements in Principle.
The penalty is payable in instalments over 15 years, commencing one
year after the court approves the Consent Decree and execution of
the associated agreements. The unpaid balance of this penalty
accrues interest at a fixed rate.
Provision movements and analysis of income statement charge
A net increase in provisions of $10,663 million and $10,958
million was recognized for the second quarter and half year
respectively. The second-quarter net increase arises primarily due
to increases in provisions of $9.8 billion in relation to the
Agreements in Principle. The remainder of the income statement
charge relates to net increases in the litigation and claims
provision for business economic loss claims, associated claims
administration costs and other items. The net increase for the
first half also includes additional increases in business economic
loss claim provisions arising in the first quarter. The following
table shows an analysis of the income statement charge.
Second First Cumulative
quarter half since
the
$ million 2015 2015 incident
======= ===========
Environmental costs 5,502 5,503 8,726
Spill response costs - - 14,304
Litigation and claims costs 4,520 4,814 31,594
Clean Water Act penalties - amount provided 700 700 4,210
Other costs charged directly to the income
statement 25 53 1,310
Recoveries credited to the income statement - - (5,681)
Charge (credit) related to the trust
fund - - (137)
Other costs of the trust fund - - 8
================================================ ======== ======= ===========
Loss before interest and taxation 10,747 11,070 54,334
Finance
costs - related to the trust funds - - 137
- not related to the trust
funds 8 17 111
==================================== ======== ======= ===========
Loss before taxation 10,755 11,087 54,582
================================================ ======== ======= ===========
Further information on provisions is provided in BP Annual
Report and Form 20-F 2014 - Financial statements - Note 2.
Top of page 23
Financial statements (continued)
Notes
2. Gulf of Mexico oil spill (continued)
Contingent liabilities
BP currently considers that it is not possible to measure
reliably other obligations arising from the incident,
including:
-- Claims asserted in civil litigation, including any further
litigation by parties excluded from, or parties who opted out of,
the PSC settlement, including as set out in Legal proceedings on
pages 228-237 of BP Annual Report and Form 20-F 2014 and page 35 of
this report, except for claims covered by the Agreements in
Principle.
-- The cost of business economic loss claims under the PSC
settlement not yet processed or processed but not yet paid (except
where an eligibility notice has been issued and is not subject to
appeal by BP within the claims facility).
-- Any obligation that may arise from securities-related litigation.
-- Any obligation in relation to other potential private or
non-US government litigation or claims (except for those items
provided for as described above under Provisions).
It is not practicable to estimate the magnitude or possible
timing of payment of these contingent liabilities.
As a result of the Agreements in Principle, contingent
liabilities are no longer disclosed in relation to Clean Water Act
penalties, natural resource damages and state claims and the vast
majority of local claims. See additional information on the
Agreements in Principle above and in Legal proceedings on page
35.
The magnitude and timing of all possible obligations in relation
to the Gulf of Mexico oil spill continue to be subject to
uncertainty.
See also BP Annual Report and Form 20-F 2014 - Financial
statements - Note 2.
3. Analysis of replacement cost profit (loss) before interest and tax and reconciliation
to profit (loss) before taxation
Second First Second First First
quarter quarter quarter half half
2014 2015 2015 $ million 2015 2014
======== ======== ========= ========= =======
4,049 372 228 Upstream 600 8,708
933 2,083 1,628 Downstream 3,711 1,727
1,024 183 510 Rosneft 693 1,542
(434) (308) (455) Other businesses and corporate (763) (931)
======== ======== ========= ================================== ========= =======
5,572 2,330 1,911 4,241 11,046
(251) (323) (10,747) Gulf of Mexico oil spill response (11,070) (280)
Consolidation adjustment -
(76) (129) (39) UPII* (168) 14
======== ======== ========= ================================== ========= =======
RC profit (loss) before interest
5,245 1,878 (8,875) and tax (6,997) 10,780
Inventory holding gains (losses)*
(1) 18 (3) Upstream 15 (7)
233 700 606 Downstream 1,306 310
26 38 24 Rosneft (net of tax) 62 57
======== ======== ========= ================================== ========= =======
Profit (loss) before interest
5,503 2,634 (8,248) and tax (5,614) 11,140
277 281 289 Finance costs 570 564
Net finance expense relating
to pensions
and other post-retirement
79 77 75 benefits 152 159
======== ======== ========= ================================== ========= =======
5,147 2,276 (8,612) Profit (loss) before taxation (6,336) 10,417
======== ======== ========= ================================== ========= =======
RC profit (loss) before interest
and tax*
1,643 (497) (10,641) US (11,138) 2,768
3,602 2,375 1,766 Non-US 4,141 8,012
======== ======== ========= ================================== ========= =======
5,245 1,878 (8,875) (6,997) 10,780
======== ======== ========= ================================== ========= =======
Top of page 24
Financial statements (continued)
Notes
4. Sales and other operating revenues
Second First Second First First
quarter quarter quarter half half
2014 2015 2015 $ million 2015 2014
======== ======== ======== ======== ========
By segment
16,739 11,630 11,036 Upstream 22,666 33,745
86,871 48,125 55,332 Downstream 103,457 171,169
412 428 512 Other businesses and corporate 940 843
======== ======== ======== ================================ ======== ========
104,022 60,183 66,880 127,063 205,757
======== ======== ======== ================================ ======== ========
Less: sales and other operating
revenues
between segments
9,729 5,563 5,590 Upstream 11,153 18,946
152 176 402 Downstream 578 714
184 248 242 Other businesses and corporate 490 430
======== ======== ======== ================================ ======== ========
10,065 5,987 6,234 12,221 20,090
======== ======== ======== ================================ ======== ========
Third party sales and other
operating revenues
7,010 6,067 5,446 Upstream 11,513 14,799
86,719 47,949 54,930 Downstream 102,879 170,455
228 180 270 Other businesses and corporate 450 413
======== ======== ======== ================================ ======== ========
Total third party sales and
other operating
93,957 54,196 60,646 revenues 114,842 185,667
======== ======== ======== ================================ ======== ========
By geographical area
35,507 18,841 21,824 US 40,665 70,332
67,303 38,688 43,130 Non-US 81,818 133,608
======== ======== ======== ================================ ======== ========
102,810 57,529 64,954 122,483 203,940
Less: sales and other operating
revenues
8,853 3,333 4,308 between areas 7,641 18,273
======== ======== ======== ================================ ======== ========
93,957 54,196 60,646 114,842 185,667
======== ======== ======== ================================ ======== ========
5. Production and similar taxes
Second First Second First First
quarter quarter quarter half half
2014 2015 2015 $ million 2015 2014
======== ======== ======== ====== ======
215 34 33 US 67 494
601 328 140 Non-US 468 1,308
======== ======== ======== ========== ====== ======
816 362 173 535 1,802
======== ======== ======== ========== ====== ======
6. Earnings per share and shares in issue
Basic earnings per ordinary share (EpS) amounts are calculated
by dividing the profit for the period attributable to ordinary
shareholders by the weighted average number of ordinary shares
outstanding during the period.
The calculation of EpS is performed separately for each discrete
quarterly period, and for the year-to-date period. As a result, the
sum of the discrete quarterly EpS amounts in any particular
year-to-date period may not be equal to the EpS amount for the
year-to-date period.
Top of page 25
Financial statements (continued)
Notes
6. Earnings per share and shares in issue (continued)
For the diluted EpS calculation the weighted average number of
shares outstanding during the period is adjusted for the number of
shares that are potentially issuable in connection with employee
share-based payment plans using the treasury stock method.
Second First Second First First
quarter quarter quarter half half
2014 2015 2015 $ million 2015 2014
=========== =========== =========== =========== ===========
Results for the period
Profit (loss) for the
period attributable
3,369 2,602 (5,823) to BP shareholders (3,221) 6,897
1 - 1 Less: preference dividend 1 1
=========== =========== =========== ================================== =========== ===========
Profit (loss) attributable
to BP
3,368 2,602 (5,824) ordinary shareholders (3,222) 6,896
=========== =========== =========== ================================== =========== ===========
Number of shares (thousand)(a)(b)
Basic weighted average
number of
18,440,909 18,220,486 18,299,877 shares outstanding 18,287,176 18,460,787
3,073,484 3,036,747 3,049,979 ADS equivalent 3,047,862 3,076,797
=========== =========== =========== ================================== =========== ===========
Weighted average number
of shares
outstanding used to
calculate
diluted earnings per
18,556,789 18,309,730 18,299,877 share 18,287,176 18,580,165
3,092,798 3,051,621 3,049,979 ADS equivalent 3,047,862 3,096,694
=========== =========== =========== ================================== =========== ===========
18,435,266 18,249,422 18,318,924 Shares in issue at period-end 18,318,924 18,435,266
3,072,544 3,041,570 3,053,154 ADS equivalent 3,053,154 3,072,544
=========== =========== =========== ================================== =========== ===========
(a) Excludes treasury shares and includes certain shares that will
be issued in the future under employee share-based payment
plans.
(b) If the inclusion of potentially issuable shares would decrease
loss per share, the potentially issuable shares are excluded
from the weighted average number of shares outstanding used
to calculate diluted earnings per share.
7. Dividends
Dividends payable
BP today announced an interim dividend of 10.00 cents per
ordinary share which is expected to be paid on 18 September 2015 to
shareholders and American Depositary Share (ADS) holders on the
register on 7 August 2015. The corresponding amount in sterling is
due to be announced on 8 September 2015, calculated based on the
average of the market exchange rates for the four dealing days
commencing on 2 September 2015. Holders of ADSs are expected to
receive $0.600 per ADS (less applicable fees). A scrip dividend
alternative is available, allowing shareholders to elect to receive
their dividend in the form of new ordinary shares and ADS holders
in the form of new ADSs. Details of the second-quarter dividend and
timetable are available at bp.com/dividends and details of the
scrip dividend programme are available at bp.com/scrip.
Dividends paid
Second First Second First First
quarter quarter quarter half half
2014 2015 2015 2015 2014
======== ======== ======== ======= =======
Dividends paid per ordinary
share
9.750 10.000 10.000 cents 20.000 19.250
5.807 6.670 6.530 pence 13.200 11.514
58.50 60.00 60.00 Dividends paid per ADS (cents) 120.00 115.50
======== ======== ======== =================================== ======= =======
Scrip dividends
26.5 15.7 18.9 Number of shares issued (millions) 34.6 66.7
Value of shares issued ($
225 109 134 million) 243 551
======== ======== ======== =================================== ======= =======
Top of page 26
Financial statements (continued)
Notes
8. Net debt*
Net debt ratio*
Second First Second First First
quarter quarter quarter half half
2014 2015 2015 $ million 2015 2014
======== ======== ======== ======== ========
52,906 57,731 57,104 Gross debt 57,104 52,906
Fair value (asset) liability
of hedges related
(1,001) (174) 315 to finance debt(a) 315 (1,001)
======== ======== ======== ================================ ======== ========
51,905 57,557 57,419 57,419 51,905
27,506 32,434 32,589 Less: cash and cash equivalents 32,589 27,506
======== ======== ======== ================================ ======== ========
24,399 25,123 24,830 Net debt 24,830 24,399
======== ======== ======== ================================ ======== ========
132,978 111,509 107,351 Equity 107,351 132,978
15.5% 18.4% 18.8% Net debt ratio 18.8% 15.5%
======== ======== ======== ================================ ======== ========
Analysis of changes in net debt
Second First Second First First
quarter quarter quarter half half
2014 2015 2015 $ million 2015 2014
======== ======== ======== ======== ========
Opening balance
53,249 52,854 57,731 Finance debt 52,854 48,192
Fair value (asset) liability
of hedges
(633) (445) (174) related to finance debt(a) (445) (477)
27,358 29,763 32,434 Less: cash and cash equivalents 29,763 22,520
======== ======== ======== ================================== ======== ========
25,258 22,646 25,123 Opening net debt 22,646 25,195
======== ======== ======== ================================== ======== ========
Closing balance
52,906 57,731 57,104 Finance debt 57,104 52,906
Fair value (asset) liability
of hedges
(1,001) (174) 315 related to finance debt(a) 315 (1,001)
27,506 32,434 32,589 Less: cash and cash equivalents 32,589 27,506
======== ======== ======== ================================== ======== ========
24,399 25,123 24,830 Closing net debt 24,830 24,399
======== ======== ======== ================================== ======== ========
Decrease (increase) in net
859 (2,477) 293 debt (2,184) 796
======== ======== ======== ================================== ======== ========
Movement in cash and cash
equivalents
99 3,294 (131) (excluding exchange adjustments) 3,163 4,982
Net cash outflow (inflow)
from financing
(excluding share capital
921 (6,206) 472 and dividends) (5,734) (3,898)
(276) 11 (1) Other movements 10 (394)
======== ======== ======== ================================== ======== ========
Movement in net debt before
744 (2,901) 340 exchange effects (2,561) 690
115 424 (47) Exchange adjustments 377 106
======== ======== ======== ================================== ======== ========
Decrease (increase) in net
859 (2,477) 293 debt (2,184) 796
======== ======== ======== ================================== ======== ========
(a) Derivative financial instruments entered into for the purpose
of managing interest rate and foreign currency exchange risk
associated with net debt with a fair value liability position
of $1,357 million (first quarter 2015 liability of $1,650 million
and second quarter 2014 asset of $1 million) are not included
in the calculation of net debt shown above as hedge accounting
was not applied for these instruments.
9. Inventory valuation
A provision of $590 million was held at 30 June 2015 ($797
million at 31 March 2015 and $468 million at 30 June 2014) to write
inventories down to their net realizable value. The net movement
credited to the income statement during the second quarter 2015 was
$210 million (first quarter 2015 was a credit of $2,024 million and
second quarter 2014 was a charge of $59 million).
Top of page 27
Financial statements (continued)
Notes
10. Statutory accounts
The financial information shown in this publication, which was
approved by the Board of Directors on 27 July 2015, is unaudited
and does not constitute statutory financial statements. BP Annual
Report and Form 20-F 2014 has been filed with the Registrar of
Companies in England and Wales. The report of the auditor on those
accounts was unqualified and contained an emphasis of matter
paragraph relating to significant uncertainty over provisions and
contingencies related to the Gulf of Mexico oil spill. The report
of the auditor on those accounts did not contain a statement under
section 498(2) or section 498(3) of the UK Companies Act 2006.
Top of page 28
Additional information
Capital expenditure and acquisitions
Second First Second First First
quarter quarter quarter half half
2014 2015 2015 $ million 2015 2014
======== ======== ======== ====== =======
By segment
Upstream
1,435 1,135 991 US 2,126 3,133
3,351 2,896 3,112 Non-US(a)(b) 6,008 7,050
======== ======== ======== ========================================== ====== =======
4,786 4,031 4,103 8,134 10,183
======== ======== ======== ========================================== ====== =======
Downstream
232 145 190 US 335 438
378 199 306 Non-US 505 722
======== ======== ======== ========================================== ====== =======
610 344 496 840 1,160
======== ======== ======== ========================================== ====== =======
Other businesses and corporate
13 16 6 US 22 16
204 74 53 Non-US 127 339
======== ======== ======== ========================================== ====== =======
217 90 59 149 355
======== ======== ======== ========================================== ====== =======
5,613 4,465 4,658 9,123 11,698
======== ======== ======== ========================================== ====== =======
By geographical area
1,680 1,296 1,187 US 2,483 3,587
3,933 3,169 3,471 Non-US(a)(b) 6,640 8,111
======== ======== ======== ========================================== ====== =======
5,613 4,465 4,658 9,123 11,698
======== ======== ======== ========================================== ====== =======
Included above:
10 28 15 Acquisitions and asset exchanges 43 246
- - 150 Other inorganic capital expenditure(a)(b) 150 442
======== ======== ======== ========================================== ====== =======
(a) First half 2014 includes $442 million relating to the purchase of
additional 3.3% equity in Shah Deniz, Azerbaijan and the South Caucasus
Pipeline.
(b) Second quarter and first half 2015 includes a $150-million deposit
paid relating to the agreed purchase of a 20% participatory interest
in Taas-Yuryakh Neftegazodobycha, a Rosneft subsidiary.
Capital expenditure shown in the table above is presented on an
accruals basis.
Top of page 29
Additional information (continued)
Non-operating items*
Second First Second First First
quarter quarter quarter half half
2014 2015 2015 $ million 2015 2014
======== ======== ========= ========= ======
Upstream
Impairment and gain (loss) on
sale of businesses and
(527) (113) (194) fixed assets (307) (643)
- 11 - Environmental and other provisions 11 -
Restructuring, integration and
- (181) (67) rationalization costs (248) -
Fair value gain (loss) on embedded
32 41 21 derivatives 62 130
(21) - 4 Other 4 273
======== ======== ========= =================================== ========= ======
(516) (242) (236) (478) (240)
======== ======== ========= =================================== ========= ======
Downstream
Impairment and gain (loss) on
sale of businesses and
79 66 68 fixed assets 134 (176)
- - (7) Environmental and other provisions (7) -
Restructuring, integration and
(1) (28) (182) rationalization costs (210) (2)
- - - Fair value gain (loss) on embedded - -
derivatives
(28) (1) (1) Other (2) (50)
======== ======== ========= =================================== ========= ======
50 37 (122) (85) (228)
======== ======== ========= =================================== ========= ======
Rosneft
Impairment and gain (loss) on
sale of businesses and
- - - fixed assets - 247
- - - Environmental and other provisions - -
- - - Restructuring, integration and - -
rationalization costs
- - - Fair value gain (loss) on embedded - -
derivatives
- - - Other - -
======== ======== ========= =================================== ========= ======
- - - - 247
======== ======== ========= =================================== ========= ======
Other businesses and corporate
Impairment and gain (loss) on
sale of businesses and
4 (12) (27) fixed assets (39) (2)
- - (4) Environmental and other provisions (4) -
Restructuring, integration and
- (6) (23) rationalization costs (29) (1)
- - - Fair value gain (loss) on embedded - -
derivatives
- - - Other - (1)
======== ======== ========= =================================== ========= ======
4 (18) (54) (72) (4)
======== ======== ========= =================================== ========= ======
(251) (323) (10,747) Gulf of Mexico oil spill response (11,070) (280)
======== ======== ========= =================================== ========= ======
(713) (546) (11,159) Total before interest and taxation (11,705) (505)
(9) (9) (8) Finance costs(a) (17) (19)
======== ======== ========= =================================== ========= ======
(722) (555) (11,167) Total before taxation (11,722) (524)
241 142 3,681 Taxation credit (charge) 3,823 267
======== ======== ========= =================================== ========= ======
(481) (413) (7,486) Total after taxation for period (7,899) (257)
======== ======== ========= =================================== ========= ======
(a) Finance costs relate to the Gulf of Mexico oil spill. See Note 2
for further details.
Top of page 30
Additional information (continued)
Non-GAAP information on fair value accounting effects
Second First Second First First
quarter quarter quarter half half
2014 2015 2015 $ million 2015 2014
======== ======== ======== ====== ======
Favourable (unfavourable) impact
relative to
management's measure of performance
(90) 10 (30) Upstream (20) (108)
150 (112) (117) Downstream (229) 211
======== ======== ======== ===================================== ====== ======
60 (102) (147) (249) 103
(32) 41 54 Taxation credit (charge) 95 (49)
======== ======== ======== ===================================== ====== ======
28 (61) (93) (154) 54
======== ======== ======== ===================================== ====== ======
BP uses derivative instruments to manage the economic exposure
relating to inventories above normal operating requirements of
crude oil, natural gas and petroleum products. Under IFRS, these
inventories are recorded at historical cost. The related derivative
instruments, however, are required to be recorded at fair value
with gains and losses recognized in income because hedge accounting
is either not permitted or not followed, principally due to the
impracticality of effectiveness testing requirements. Therefore,
measurement differences in relation to recognition of gains and
losses occur. Gains and losses on these inventories are not
recognized until the commodity is sold in a subsequent accounting
period. Gains and losses on the related derivative commodity
contracts are recognized in the income statement, from the time the
derivative commodity contract is entered into, on a fair value
basis using forward prices consistent with the contract
maturity.
BP enters into commodity contracts to meet certain business
requirements, such as the purchase of crude for a refinery or the
sale of BP's gas production. Under IFRS these contracts are treated
as derivatives and are required to be fair valued when they are
managed as part of a larger portfolio of similar transactions.
Gains and losses arising are recognized in the income statement
from the time the derivative commodity contract is entered
into.
IFRS requires that inventory held for trading is recorded at its
fair value using period-end spot prices whereas any related
derivative commodity instruments are required to be recorded at
values based on forward prices consistent with the contract
maturity. Depending on market conditions, these forward prices can
be either higher or lower than spot prices resulting in measurement
differences.
BP enters into contracts for pipelines and storage capacity, oil
and gas processing and liquefied natural gas (LNG) that, under
IFRS, are recorded on an accruals basis. These contracts are
risk-managed using a variety of derivative instruments, which are
fair valued under IFRS. This results in measurement differences in
relation to recognition of gains and losses.
The way that BP manages the economic exposures described above,
and measures performance internally, differs from the way these
activities are measured under IFRS. BP calculates this difference
for consolidated entities by comparing the IFRS result with
management's internal measure of performance. Under management's
internal measure of performance the inventory and capacity
contracts in question are valued based on fair value using relevant
forward prices prevailing at the end of the period, the fair values
of certain derivative instruments used to risk manage LNG and oil
and gas processing contracts are deferred to match with the
underlying exposure and the commodity contracts for business
requirements are accounted for on an accruals basis. We believe
that disclosing management's estimate of this difference provides
useful information for investors because it enables investors to
see the economic effect of these activities as a whole. The impacts
of fair value accounting effects, relative to management's internal
measure of performance, are shown in the table above. A
reconciliation to GAAP information is set out below.
Second First Second First First
quarter quarter quarter half half
2014 2015 2015 $ million 2015 2014
======== ======== ======== ======== =======
Upstream
Replacement cost profit before
interest and tax
adjusted for fair value accounting
4,139 362 258 effects 620 8,816
Impact of fair value accounting
(90) 10 (30) effects (20) (108)
======== ======== ======== ==================================== ======== =======
Replacement cost profit before
4,049 372 228 interest and tax 600 8,708
======== ======== ======== ==================================== ======== =======
Downstream
Replacement cost profit before
interest and tax
adjusted for fair value accounting
783 2,195 1,745 effects 3,940 1,516
Impact of fair value accounting
150 (112) (117) effects (229) 211
======== ======== ======== ==================================== ======== =======
Replacement cost profit before
933 2,083 1,628 interest and tax 3,711 1,727
======== ======== ======== ==================================== ======== =======
Total group
Profit (loss) before interest
and tax adjusted for
5,443 2,736 (8,101) fair value accounting effects (5,365) 11,037
Impact of fair value accounting
60 (102) (147) effects (249) 103
======== ======== ======== ==================================== ======== =======
Profit (loss) before interest
5,503 2,634 (8,248) and tax (5,614) 11,140
======== ======== ======== ==================================== ======== =======
Top of page 31
Additional information (continued)
Realizations and marker prices
Second First Second First First
quarter quarter quarter half half
2014 2015 2015 2015 2014
======== ======== ======== ====== =======
Average realizations(a)
Liquids* ($/bbl)
89.61 46.24 50.97 US 48.53 89.71
101.43 52.28 57.42 Europe 55.25 102.88
103.37 46.13 60.78 Rest of World 52.63 103.04
96.90 46.79 56.69 BP Average 51.49 97.03
======== ======== ======== ================================== ====== =======
Natural gas ($/mcf)
3.86 2.39 2.15 US 2.27 4.23
8.07 7.32 9.16 Europe 8.27 8.99
6.31 5.05 4.05 Rest of World 4.57 6.47
5.67 4.44 3.80 BP Average 4.12 5.94
======== ======== ======== ================================== ====== =======
Total hydrocarbons* ($/boe)
63.83 33.20 34.93 US 34.04 64.74
88.22 49.35 56.35 Europe 53.28 90.61
62.89 37.41 39.93 Rest of World 38.58 62.83
64.90 37.00 40.04 BP Average 38.47 65.53
======== ======== ======== ================================== ====== =======
Average oil marker prices ($/bbl)
109.67 53.94 61.88 Brent 57.84 108.93
103.05 48.49 57.85 West Texas Intermediate 53.25 100.90
82.66 36.69 49.56 Western Canadian Select 43.12 79.86
108.05 51.95 62.65 Alaska North Slope 57.39 106.91
100.70 49.15 59.57 Mars 54.44 100.76
107.30 52.59 61.21 Urals (NWE - cif) 56.83 106.76
======== ======== ======== ================================== ====== =======
Average natural gas marker prices
4.68 2.99 2.65 Henry Hub gas price ($/mmBtu)(b) 2.82 4.81
UK Gas - National Balancing Point
44.81 47.90 44.63 (p/therm) 46.29 52.67
======== ======== ======== ================================== ====== =======
(a) Based on sales of consolidated subsidiaries only - this excludes
equity-accounted entities.
(b) Henry Hub First of Month Index.
Exchange rates
Second First Second First First
quarter quarter quarter half half
2014 2015 2015 2015 2014
======== ======== ======== ====== ======
1.68 1.51 1.53 $/GBP average rate for the period 1.52 1.67
1.70 1.48 1.57 $/GBP period-end rate 1.57 1.70
1.37 1.12 1.11 $/EUR average rate for the period 1.12 1.37
1.36 1.08 1.11 $/EUR period-end rate 1.11 1.36
Rouble/$ average rate for the
34.96 63.03 52.68 period 57.94 35.02
33.73 57.79 55.42 Rouble/$ period-end rate 55.42 33.73
======== ======== ======== ================================== ====== ======
Top of page 32
Glossary
Consolidation adjustment - UPII is unrealized profit in
inventory arising on inter-segment transactions.
Fair value accounting effects are non-GAAP adjustments to our
IFRS profit (loss) relating to certain physical inventories,
pipelines and storage capacity. Management uses a fair-value basis
to value these items which, under IFRS, are accounted for on an
accruals basis with the exception of trading inventories, which are
valued using spot prices. The adjustments have the effect of
aligning the valuation basis of the physical positions with that of
any associated derivative instruments, which are required to be
fair valued under IFRS, in order to provide a more representative
view of the ultimate economic value. Further information and a
reconciliation to GAAP information is provided on page 30.
Hydrocarbons - Liquids and natural gas. Natural gas is converted
to oil equivalent at 5.8 billion cubic feet = 1 million
barrels.
Inventory holding gains and losses represent the difference
between the cost of sales calculated using the replacement cost of
inventory and the cost of sales calculated on the first-in
first-out (FIFO) method after adjusting for any changes in
provisions where the net realizable value of the inventory is lower
than its cost. Under the FIFO method, which we use for IFRS
reporting, the cost of inventory charged to the income statement is
based on its historical cost of purchase or manufacture, rather
than its replacement cost. In volatile energy markets, this can
have a significant distorting effect on reported income. The
amounts disclosed represent the difference between the charge to
the income statement for inventory on a FIFO basis (after adjusting
for any related movements in net realizable value provisions) and
the charge that would have arisen based on the replacement cost of
inventory. For this purpose, the replacement cost of inventory is
calculated using data from each operation's production and
manufacturing system, either on a monthly basis, or separately for
each transaction where the system allows this approach. The amounts
disclosed are not separately reflected in the financial statements
as a gain or loss. No adjustment is made in respect of the cost of
inventories held as part of a trading position and certain other
temporary inventory positions. See Replacement cost (RC) profit or
loss definition below.
Liquids comprises crude oil, condensate and natural gas
liquids.
Net debt and net debt ratio are non-GAAP measures. Net debt is
calculated as gross finance debt, as shown in the balance sheet,
plus the fair value of associated derivative financial instruments
that are used to hedge foreign currency exchange and interest rate
risks relating to finance debt, for which hedge accounting is
applied, less cash and cash equivalents. The net debt ratio is
defined as the ratio of net debt to the total of net debt plus
shareholders' equity. All components of equity are included in the
denominator of the calculation. BP believes these measures provide
useful information to investors. Net debt enables investors to see
the economic effect of gross debt, related hedges and cash and cash
equivalents in total. The net debt ratio enables investors to see
how significant net debt is relative to equity from shareholders.
The derivatives are reported on the balance sheet within the
headings 'Derivative financial instruments'.
Net wind generation capacity is the sum of the rated capacities
of the assets/turbines that have entered into commercial operation,
including BP's share of equity-accounted entities. The gross data
is the equivalent capacity on a gross-JV basis, which includes 100%
of the capacity of equity-accounted entities where BP has partial
ownership.
Non-operating items are charges and credits included in the
financial statements that BP discloses separately because it
considers such disclosures to be meaningful and relevant to
investors. They are items that management considers not to be part
of underlying business operations and are disclosed in order to
enable investors better to understand and evaluate the group's
reported financial performance. Non-operating items within
equity-accounted earnings are reported net of incremental income
tax reported by the equity-accounted entity. An analysis of
non-operating items by region is shown on pages 5, 7 and 9, and by
segment and type is shown on page 29.
Organic capital expenditure excludes acquisitions, asset
exchanges, and other inorganic capital expenditure. An analysis of
capital expenditure by segment and region is shown on page 28.
Production-sharing agreement (PSA) is an arrangement through
which an oil company bears the risks and costs of exploration,
development and production. In return, if exploration is
successful, the oil company receives entitlement to variable
physical volumes of hydrocarbons, representing recovery of the
costs incurred and a stipulated share of the production remaining
after such cost recovery.
Realizations are the result of dividing revenue generated from
hydrocarbon sales, excluding revenue generated from purchases made
for resale and royalty volumes, by revenue generating hydrocarbon
production volumes. Revenue generating hydrocarbon production
reflects the BP share of production as adjusted for any production
which does not generate revenue. Adjustments may include losses due
to shrinkage, amounts consumed during processing, and contractual
or regulatory host committed volumes such as royalties.
Refining availability represents Solomon Associates' operational
availability, which is defined as the percentage of the year that a
unit is available for processing after subtracting the annualized
time lost due to turnaround activity and all planned mechanical,
process and regulatory downtime.
The Refining marker margin (RMM) is the average of regional
indicator margins weighted for BP's crude refining capacity in each
region. Each regional marker margin is based on product yields and
a marker crude oil deemed appropriate for the region. The regional
indicator margins may not be representative of the margins achieved
by BP in any period because of BP's particular refinery
configurations and crude and product slate.
Top of page 33
Glossary (continued)
Replacement cost (RC) profit or loss reflects the replacement
cost of inventories sold in the period and is arrived at by
excluding inventory holding gains and losses from profit or loss.
RC profit or loss is the measure of profit or loss that is required
to be disclosed for each operating segment under International
Financial Reporting Standards (IFRS). RC profit or loss for the
group is not a recognized GAAP measure. Management believes this
measure is useful to illustrate to investors the fact that crude
oil and product prices can vary significantly from period to period
and that the impact on our reported result under IFRS can be
significant. Inventory holding gains and losses vary from period to
period due to changes in prices as well as changes in underlying
inventory levels. In order for investors to understand the
operating performance of the group excluding the impact of price
changes on the replacement of inventories, and to make comparisons
of operating performance between reporting periods, BP's management
believes it is helpful to disclose this measure.
Underlying production is production after adjusting for
divestments and entitlement impacts in our production-sharing
agreements.
Underlying RC profit or loss is RC profit or loss after
adjusting for non-operating items and fair value accounting
effects. Underlying RC profit or loss and fair value accounting
effects are not recognized GAAP measures. See pages 29 and 30 for
additional information on the non-operating items and fair value
accounting effects that are used to arrive at underlying RC profit
or loss in order to enable a full understanding of the events and
their financial impact.
BP believes that underlying RC profit or loss is a useful
measure for investors because it is a measure closely tracked by
management to evaluate BP's operating performance and to make
financial, strategic and operating decisions and because it may
help investors to understand and evaluate, in the same manner as
management, the underlying trends in BP's operational performance
on a comparable basis, period on period, by adjusting for the
effects of these non-operating items and fair value accounting
effects. The nearest equivalent measure on an IFRS basis for the
group is profit or loss for the year attributable to BP
shareholders. The nearest equivalent measure on an IFRS basis for
segments is RC profit or loss before interest and taxation.
Top of page 34
Principal risks and uncertainties
The principal risks and uncertainties affecting BP are described
in the Risk factors section of BP Annual Report and Form 20-F 2014
(pages 48-50) and are summarized below. Other than the developments
referred to under the heading Gulf of Mexico oil spill, below,
there are no material changes in those risk factors for the
remaining six months of the financial year.
The risks summarized below, separately or in combination, could
have a material adverse effect on the implementation of our
strategy, our business, financial performance, results of
operations, cash flows, liquidity, prospects, shareholder value and
returns and reputation.
Gulf of Mexico oil spill
-- On 2 July 2015 BP Exploration & Production Inc. signed
agreements in principle to settle all federal and state claims, and
claims made by more than 400 local government entities, arising
from the oil spill. These agreements are subject to the execution
of definitive agreements and court approval of the Consent Decree
relating to such settlement. For further details, including items
not covered by the agreements in principle, see Legal proceedings
(Agreements in principle) on page 35. There continues to be
uncertainty regarding the extent and timing of the remaining costs
and liabilities relating to the 2010 Gulf of Mexico oil spill not
covered by the agreements in principle.
Strategic and commercial risks
-- Prices and markets - our financial performance is subject to
fluctuating prices of oil, gas, refined products, exchange rate
fluctuations and the general macroeconomic outlook.
-- Access, renewal and reserves progression - our inability to
access, renew and progress upstream resources in a timely manner
could adversely affect our long-term replacement of reserves.
-- Major project delivery - failure to invest in the best
opportunities or deliver major projects successfully could
adversely affect our financial performance.
-- Geopolitical - we are exposed to a range of political
developments and consequent changes to the operating and regulatory
environment.
-- Rosneft investment - our investment in Rosneft may be
impacted by events in or relating to Russia.
-- Liquidity, financial capacity and financial, including
credit, exposure - failure to work within our financial framework
could impact our ability to operate and result in financial
loss.
-- Joint arrangements and contractors - we may have limited
control over the standards, operations and compliance of our
partners, contractors and sub-contractors.
-- Digital infrastructure and cybersecurity - breach of our
digital security or failure of our digital infrastructure could
damage our operations and our reputation.
-- Climate change and carbon pricing - public policies could
increase costs and reduce future revenue and strategic growth
opportunities.
-- Competition - inability to remain efficient, innovate and
retain an appropriately skilled workforce could negatively impact
delivery of our strategy in a highly competitive market.
-- Crisis management and business continuity - potential
disruption to our business and operations could occur if we do not
address an incident effectively.
-- Insurance - our insurance strategy could expose the group to material uninsured losses.
Safety and operational risks
-- Process safety, personal safety, and environmental risks - we
are exposed to a wide range of health, safety, security and
environmental risks that could result in regulatory action, legal
liability, increased costs, damage to our reputation and
potentially denial of our licence to operate.
-- Drilling and production - challenging operational
environments and other uncertainties can impact drilling and
production activities.
-- Security - hostile acts against our staff and activities
could cause harm to people and disrupt our operations.
-- Product quality - supplying customers with off-specification
products could damage our reputation, lead to regulatory action and
legal liability, and potentially impact our financial
performance.
Compliance and control risks
-- US government settlements - our settlements with legal and
regulatory bodies in the US announced in November 2012 in respect
of certain charges related to the Gulf of Mexico oil spill may
expose us to further penalties, liabilities and private litigation
or could result in suspension or debarment of certain BP
entities.
-- Regulation - changes in the regulatory and legislative
environment could increase the cost of compliance, affect our
provisions and limit our access to new exploration
opportunities.
-- Ethical misconduct and non-compliance - ethical misconduct or
breaches of applicable laws by our businesses or our employees
could damage our reputation, and could result in litigation,
regulatory action and penalties.
-- Treasury and trading activities - ineffective oversight of
treasury and trading activities could lead to business disruption,
financial loss, regulatory intervention or damage to our
reputation.
-- Reporting - failure to accurately report our data could lead
to regulatory action, legal liability and reputational damage.
Top of page 35
Legal proceedings
The following discussion sets out the material developments in
the group's material legal proceedings during the half year 2015.
For a full discussion of the group's material legal proceedings,
see pages 228-238 of BP Annual Report and Form 20-F 2014.
Matters relating to the Deepwater Horizon accident and oil spill
(the Incident)
Agreements in principle
On 2 July 2015, BP announced that BP Exploration &
Production Inc. (BPXP) has executed agreements in principle with
the United States federal government and five Gulf Coast states to
settle all federal and state claims arising from the Incident. The
agreement with the states of Alabama, Florida, Louisiana,
Mississippi and Texas also provides for the settlement of claims
made by more than 400 local government entities.
The principal payments are as follows:
-- BPXP is to pay the United States a civil penalty of $5.5
billion under the Clean Water Act (CWA) - payable over 15
years.
-- BPXP will pay $7.1 billion to the United States and the five
Gulf states over 15 years for natural resource damages (NRD). This
is in addition to the $1 billion already committed for early
restoration. BPXP will also set aside an additional amount of $232
million to be added to the NRD interest payment at the end of the
payment period to cover any further natural resource damages that
are unknown at the time of the agreement.
-- A total of $4.9 billion will be paid over 18 years to settle
economic and other claims made by the five Gulf states.
-- Up to $1 billion will be paid to resolve claims made by local government entities.
NRD and CWA payments are scheduled to start 12 months after the
agreements become final. Total payments for NRD, CWA and State
claims will be made at a rate of around $1.1 billion a year for the
majority of the payment period.
The agreements in principle are subject to execution of
definitive agreements. These will comprise a Consent Decree with
the United States and Gulf states with respect to the civil penalty
and natural resource damages, a settlement agreement with the five
Gulf states with respect to State and local claims for economic and
property losses, and release agreements with local government
entities.
The Consent Decree will be subject to public comment and final
court approval. The Consent Decree and settlement agreement with
the Gulf states are conditional upon each other and neither will
become effective unless (1) there is final court approval of the
Consent Decree and (2) local government entities execute releases
to BP's satisfaction. BP advised the Court that it is satisfied
with and has accepted releases received from the vast majority of
local government entities. Accordingly, on 27 July, the District
Court ordered BP to commence processing payments required under the
releases and that such payments be made within 30 days of the
Court's order. The agreements in principle do not cover the
remaining costs of the 2012 class action settlements with the
Plaintiffs' Steering Committee for economic and property damage and
medical claims. They do not cover claims by individuals and
businesses that opted out of the 2012 settlements and/or whose
claims were excluded from them, including claims for recovery of
losses allegedly resulting from the 2010 federal deepwater drilling
moratoria and/or the related permitting processes. The agreements
in principle also do not resolve private securities litigation
pending in MDL 2185.
Interest will accrue at a fixed rate on the unpaid balance of
the civil penalty and NRD payments, compounded annually and payable
in years 15 (CWA) and 16 (NRD). To address possible natural
resource damages unknown at the time of the settlement, beginning
10 years after the settlement, the federal government and the Gulf
states may request accelerated payment of accrued but unpaid
interest on the NRD payments.
Parent company guarantees for these payments will be provided by
BP Corporation North America Inc. as the primary guarantor and BP
p.l.c. as the secondary guarantor.
The federal government and the Gulf states may jointly elect to
accelerate the civil penalty and NRD payments in the event of a
change of control or insolvency of BP p.l.c.
In addition to these agreed settlement payments, BPXP has also
agreed to pay $350 million to cover outstanding NRD assessment
costs and $250 million to cover the full settlement of outstanding
response costs, claims related to the False Claims Act and
royalties owed for the Macondo well. These additional payments will
be paid over nine years, beginning in 2015.
Federal multi-district litigation proceeding in New Orleans (MDL
2179) and related matters
US Department of Justice (DoJ) Action - Liability under Section
311(b)(7)(A) of the Clean Water Act. As previously disclosed, in
February 2012, the federal district court in New Orleans (the
District Court) held that the subsurface discharge which occurred
during the Incident was from the Macondo well, rather than from the
Deepwater Horizon vessel, and that BPXP and Anadarko Petroleum
Company (Anadarko), and not Transocean Ltd. (Transocean), were
liable for civil penalties under the Clean Water Act as owners of
the well. On 27 June 2015, the US Supreme Court denied BPXP's and
Anadarko's petitions for certiorari seeking review of the US Court
of Appeals for the Fifth Circuit (the Fifth Circuit)'s order
denying a rehearing of BPXP's and Anadarko's appeal.
Top of page 36
Legal proceedings (continued)
Trial Phases. As previously disclosed, on 4 September 2014, the
District Court issued its ruling for Phase 1 of the trial in MDL
2179. BPXP and BP America Production Company (BPAPC) and other
parties filed notices of appeal of the Phase 1 ruling to the Fifth
Circuit. On 16 July 2015 the United States, with the consent of the
other parties, filed a motion to hold the Phase 1 appeal in
abeyance while the parties work towards finalizing the settlements
under the 2 July 2015 agreements in principle. This motion was
granted by the Fifth Circuit on 22 July 2015.
On 15 January 2015, the District Court issued its ruling for
Phase 2 of MDL 2179. The District Court found that 3.19 million
barrels of oil were discharged into the Gulf of Mexico and are
therefore subject to a Clean Water Act penalty and that BP was not
grossly negligent in its source control efforts. On 28 May 2015,
both BPXP and the United States voluntarily dismissed the appeals
of the Phase 2 ruling that they had made to the Fifth Circuit
(without prejudice to their rights to appeal after the decision in
the penalty phase). Other parties have also appealed the Phase 2
ruling but at the parties' request the Fifth Circuit has ordered
that the appeal be held in abeyance until resolution of the Phase 1
appeal.
Trial in the penalty phase of MDL 2179 (the Penalty Phase)
concluded on 2 February 2015. The Penalty Phase involved
consideration of the amount of CWA civil penalties owed to the
United States. Post-trial briefing concluded on 24 April 2015.
As discussed above, on 2 July 2015, BP announced an agreement in
principle with the United States to settle the United States'
claims against BPXP for CWA penalties.
Plaintiffs' Steering Committee (PSC) Settlements - Deepwater
Horizon Court Supervised Settlement Program (DHCSSP) and
interpretation of the Economic and Property Damages (EPD)
Settlement Agreement. On 24 December 2013, the District Court
issued a ruling that, amongst other things, directed the claims
administrator, in administering business economic loss claims, to
match revenue with corresponding variable expenses. On 13 March
2014, the claims administrator issued a revised matching policy
reflecting this order, which was approved by the District Court.
The PSC filed a motion on 27 May 2014 seeking to alter or amend the
revised policy. This motion was denied by the District Court on 31
March 2015 and, on 23 April 2015, the PSC appealed this decision to
the Fifth Circuit.
On 6 March 2015, BP gave notice that it was not proceeding with
the appeal against the decision of the District Court in November
2014 denying BP's motion seeking an order removing Patrick Juneau
from his role as claims administrator and settlement trustee for
the EPD settlement.
On 8 May 2015, the Fifth Circuit upheld three awards to
non-profit entities issued under the EPD Settlement, each of which
was premised on an official policy that typically treated grant
monies and contributions to non-profit entities as revenue for
purposes of the settlement agreement's calculations. BP argued that
this policy was inconsistent with the language of the settlement
agreement and would place the agreement in violation of United
States law, but the Fifth Circuit upheld the policy and determined
that the District Court did not otherwise abuse its discretion in
denying review of the three awards.
The deadline for filing all claims under the EPD Settlement
other than those that fall into the Seafood Compensation Program
was 8 June 2015.
For information about BP's current estimate of the total cost of
the PSC settlements, see Note 2 on page 18.
Medical Benefits Class Action Settlement (Medical Settlement).
The deadline for submitting claims under the Medical Settlement
Agreement (MSA) for Specified Physical Conditions (SPCs) and under
the Periodic Medical Consultation Program (PMCP) was 12 February
2015. There was an increased volume of SPC and PMCP claims filings
at and around the bar date. The total number of claims estimated by
the MSA claims administrator is approximately 37,000. To date,
approximately 2,000 SPC claims, totalling approximately $5 million,
have been approved for compensation. In addition, approximately
11,200 claimants have been determined eligible for the PMCP. Given
the District Court's decision to classify all physical conditions
first diagnosed after 16 April 2012 as Later-Manifested Physical
Conditions (LMPC), class members must pursue compensation for LMPCs
by submitting a Notice of Intent to Sue (NOIS) under the Back-End
Litigation Option (BELO). As of 9 July 2015, 19 compliant NOISs
have been received by the MSA claims administrator, four of which
have resulted in pending BELO lawsuits. On 27 April 2015, the
District Court issued an order allowing for jury trials for certain
medical settlement claims for BELO plaintiffs.
State and local civil claims, including under the Oil Pollution
Act of 1990 (OPA 90) - State of Alabama Damages Case Proceedings.
On 19 April 2013, the State of Alabama filed an action against BP
alleging general maritime law claims of negligence, gross
negligence, and wilful misconduct; claims under OPA 90 seeking
damages for removal costs, natural resource damages, property
damage, lost tax and other revenue and damages for providing
increased public services during or after removal activities; and
various state law claims. On 14 February 2014, BP moved to strike
the State of Alabama's jury trial demand as to its claim for
compensatory damages under OPA 90. On 30 March 2015, the District
Court denied BP's motion and on 29 April 2015 the District Court
denied BP's motion to certify the ruling for appeal to the Fifth
Circuit. On 16 March 2015 the District Court issued an amended
scheduling order for the State of Alabama's claims against BP and
other parties under which the pre-trial matters will be concluded
in April 2016. On 2 July 2015, however, the court suspended all
discovery obligations and court-scheduled events in the Alabama
action in view of the 2 July 2015 agreements in principle between
BPXP and the United States and five Gulf states.
Top of page 37
Legal proceedings (continued)
Halliburton and Transocean Settlements. On 20 May 2015, BP and
Transocean, and BP and Halliburton Energy Services Inc.
(Halliburton), entered into confidential settlement agreements to
resolve the final remaining disputes between these parties stemming
from the Incident.
Under the agreement with Transocean, BPXP and BPAPC agreed to
indemnify Transocean for compensatory damages (including natural
resource damages), to pay Transocean $125 million in compensation
for incurred legal fees, and discontinue attempts to recover as an
additional insured under Transocean's liability policies.
Transocean will indemnify BPXP and BPAPC for the personal and
bodily injury claims of Transocean employees, as well as for claims
relating to any future cleanup or removal of diesel or other
pollutants stored on the Deepwater Horizon. Finally, BPXP and
BPAPC, and Transocean will mutually release all claims between the
companies.
BPXP's agreement with Halliburton resolves the remaining claims
between the two companies and includes indemnities and the
dismissal of all claims against each other.
Non-US government lawsuits. On 1 May 2015, the Fifth Circuit
affirmed the District Court's 12 September 2013 judgment dismissing
with prejudice the claims brought in September 2010 by three
Mexican states bordering the Gulf of Mexico against several BP
entities.
MDL 2185 and other securities-related litigation
Canadian Class Action. On 26 March 2015, the Supreme Court of
Canada dismissed the plaintiff's appeal to the August 2014 decision
by the Ontario Court of Appeal which held that claims made on
behalf of Canadian residents who purchased BP ordinary shares and
ADSs on exchanges outside of Canada should be litigated in those
countries, and that only claims asserted on behalf of Canadian
residents who purchased ADSs on the Toronto Stock Exchange could be
litigated in Canada. On 27 March 2015, the plaintiff filed a
complaint in Texas federal court asserting claims under Canadian
law against BP on behalf of a class of Canadian residents who
allegedly suffered losses because of their purchase of BP ADSs on
the New York Stock Exchange. That action has been transferred to
the judge presiding over MDL 2185, and on 16 June 2015, BP moved to
dismiss the action.
Other legal proceedings
Scharfstein v. BP West Coast Products, LLC. A purported class
action lawsuit was filed against BP West Coast Products, LLC in
Oregon State Court under the Oregon Unlawful Trade Practices Act on
behalf of customers who used a debit card at ARCO gasoline stations
in Oregon during the period 1 January 2011 to 30 August 2013,
alleging that ARCO's Oregon sites failed to provide sufficient
notice of the 35 cents per transaction debit card fee. After a jury
trial and subsequent hearing, in 2014 the jury rendered a verdict
against BP and determined that statutory damages of $200 per class
member should be awarded. A post-trial claims process in late 2014
identified approximately 1.7 million class members, subject to
final determination. BP intends to appeal. No provision has been
made for damages arising out of this class action.
Top of page 38
Cautionary statement
Cautionary statement regarding forward-looking statements: The
discussion in this results announcement contains certain forecasts,
projections and forward-looking statements - that is, statements
related to future, not past events - with respect to the financial
condition, results of operation and businesses of BP and certain of
the plans and objectives of BP with respect to these items. These
statements may generally, but not always, be identified by the use
of words such as 'will', 'expects', 'is expected to', 'aims',
'should', 'may', 'objective', 'is likely to', 'intends',
'believes', 'anticipates', 'plans', 'we see' or similar
expressions. In particular, among other statements, plans regarding
the divestment of $10 billion in assets by the end of 2015;
expectations regarding restructuring charges; the expected
quarterly dividend payment and timing of such payment; expectations
regarding organic capital expenditure for full year 2015; plans and
expectations regarding future development and exploration in
Siberia; plans regarding TANAP and BP's interest therein; plans and
expectations regarding Upstream projects announced with BP's
first-quarter results; expectations regarding drilling operations
in Libya; expectations regarding the level of reported production
for third quarter 2015; expectations regarding third quarter
refining margins and level of turnaround activity; expectations
regarding the new plant in Zhuhai, China; expectations regarding
Rosneft reporting; expectations with respect to finalizing the
definitive agreements, including the Consent Decree with the United
States and the Gulf states, timing of and expectations regarding
court approval, the timing of payments under the agreement and
financial impact of the settlement on BP and certain statements
regarding the legal and trial proceedings, court decisions, claims,
penalties and civil actions by government entities and/or other
entities or parties, the risks associated with such proceedings;
are all forward looking in nature. By their nature, forward-looking
statements involve risk and uncertainty because they relate to
events and depend on circumstances that will or may occur in the
future and are outside the control of BP. Actual results may differ
materially from those expressed in such statements, depending on a
variety of factors, including: the specific factors identified in
the discussions accompanying such forward-looking statements; the
receipt of relevant third party and/or regulatory approvals; the
timing and level of maintenance and/or turnaround activity; the
timing and volume of refinery additions and outages; the timing of
bringing new fields onstream; the timing, quantum and nature of
certain divestments; future levels of industry product supply,
demand and pricing, including supply growth in North America; OPEC
quota restrictions; PSA effects; operational and safety problems;
potential lapses in product quality; economic and financial market
conditions generally or in various countries and regions; political
stability and economic growth in relevant areas of the world;
changes in laws and governmental regulations; regulatory or legal
actions including the types of enforcement action pursued and the
nature of remedies sought or imposed; the actions of prosecutors,
regulatory authorities and courts; the timing and amount of future
payments relating to the Gulf of Mexico oil spill; exchange rate
fluctuations; development and use of new technology; recruitment
and retention of a skilled workforce; the success or otherwise of
partnering; the actions of competitors, trading partners,
contractors, subcontractors, creditors, rating agencies and others;
our access to future credit resources; business disruption and
crisis management; the impact on our reputation of ethical
misconduct and non-compliance with regulatory obligations; trading
losses; major uninsured losses; decisions by Rosneft's management
and board of directors; the actions of contractors; natural
disasters and adverse weather conditions; changes in public
expectations and other changes to business conditions; wars and
acts of terrorism; cyber-attacks or sabotage; and other factors
discussed elsewhere in this report, including under "Principal
risks and uncertainties", and under "Risk factors" in BP Annual
Report and Form 20-F 2014 as filed with the US Securities and
Exchange Commission.
Notice to investors: BP has received written comments from the
US Securities and Exchange Commission regarding its Form 20-F for
the fiscal year ended 31 December 2014 in a letter dated 22 May
2015.
Contacts
London United States
Press Office David Nicholas Scott Dean
+44 (0)20 7496 4708 +1 630 420 4990
Investor Relations Jessica Mitchell Craig Marshall
bp.com/investors +44 (0)20 7496 4962 +1 281 366 3123
This information is provided by RNS
The company news service from the London Stock Exchange
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