bp201602026k.htm
SECURITIES AND EXCHANGE COMMISSION
 
 
 
Washington, D.C. 20549
 
 
 
 
 
Form 6-K
 
 
 
Report of Foreign Issuer
 
 
 
Pursuant to Rule 13a-16 or 15d-16 of
the Securities Exchange Act of 1934
 
 
 

 
for the period ended February, 2016


BP p.l.c.
(Translation of registrant's name into English)
 
 

1 ST JAMES'S SQUARE, LONDON, SW1Y 4PD, ENGLAND
(Address of principal executive offices)
 
 

Indicate  by check mark  whether the  registrant  files or will file annual
reports under cover Form 20-F or Form 40-F.
 
 
Form 20-F        |X|          Form 40-F
     ---------------               ----------------
 
 

Indicate by check mark whether the registrant by furnishing the information
contained in this Form is also thereby  furnishing  the  information to the
Commission  pursuant to Rule 12g3-2(b) under the Securities Exchange Act of
     1934.
 
 

Yes                            No        |X|
      ---------------           ----------------
 
 

BP p.l.c.
Group results
Fourth quarter and full year 2015
 
Top of page 1
FOR IMMEDIATE RELEASE                                                                                                         London 2 February 2016
 

Fourth
Third
Fourth
          
quarter
quarter
quarter
      
Year
Year
2014
2015
2015
  
$ million
  
2015
2014
(4,407)
46
(3,307)
  
Profit (loss) for the period(a)
  
(6,482)
3,780
3,438
1,188
1,074
  
Inventory holding (gains) losses*, net of tax
  
1,320
4,293
(969)
1,234
(2,233)
  
Replacement cost profit (loss)*
  
(5,162)
8,073
       
Net (favourable) unfavourable impact of
     
       
  non-operating items* and fair value
      
3,208
585
2,429
  
  accounting effects*, net of tax
  
11,067
4,063
2,239
1,819
196
  
Underlying replacement cost profit*
  
5,905
12,136
       
Replacement cost profit (loss)
      
(5.32)
6.73
(12.16)
  
    per ordinary share (cents)
  
(28.18)
43.90
(0.32)
0.40
(0.73)
  
    per ADS (dollars)
  
(1.69)
2.63
       
Underlying replacement cost profit
      
12.28
9.92
1.06
  
    per ordinary share (cents)
  
32.22
66.00
0.74
0.60
0.06
  
    per ADS (dollars)
  
1.93
3.96

·  
BP’s fourth-quarter replacement cost (RC) loss was $2,233 million, compared with a loss of $969 million a year ago. After adjusting for a net charge for non-operating items of $2,617 million and net favourable fair value accounting effects of $188 million (both on a post-tax basis), underlying RC profit for the fourth quarter was $196 million, compared with $2,239 million for the same period in 2014. The net charge for non-operating items mainly relates to impairment charges in the Upstream segment and also reflects $450 million of restructuring charges for the group. The lower underlying result was mainly due to the Upstream segment which reported an underlying replacement cost loss of $728 million for the quarter. Cumulative restructuring charges from the beginning of the fourth quarter 2014 totalled $1.5 billion by the end of 2015. A further $1.0 billion of restructuring charges are expected to be incurred in 2016.

·  
For the full year, RC loss was $5,162 million, compared with a profit of $8,073 million a year ago. After adjusting for a net charge for non-operating items of $11,272 million and net favourable fair value accounting effects of $205 million (both on a post-tax basis), underlying RC profit for the full year was $5,905 million, compared with $12,136 million for the same period in 2014. 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 29.

·  
All amounts relating to the Gulf of Mexico oil spill have been treated as non-operating items, with a net pre-tax charge of $443 million for the fourth quarter and $11,956 million for the full year. For further information on the Gulf of Mexico oil spill and its consequences see page 10 and Note 2 on page 16. See also Legal proceedings on page 33.

·  
Including the impact of the Gulf of Mexico oil spill, net cash provided by operating activities for the fourth quarter and full year was $5.8 billion and $19.1 billion respectively, compared with $7.2 billion and $32.8 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 fourth quarter and full year was $5.9 billion and $20.3 billion respectively, compared with $6.9 billion and $32.8 billion for the same periods in 2014.

·  
Net debt* at 31 December 2015 was $27.2 billion, compared with $22.6 billion a year ago. The net debt ratio* at
 
31 December 2015 was 21.6%, compared with 16.7% a year ago. Net debt and the net debt ratio are non-GAAP measures. See page 25 for more information. We aim to maintain the net debt ratio, with some flexibility, at around 20%. We expect the net debt ratio to be above 20% whilst oil prices remain weak.

· 
The reserves replacement ratio* on a combined basis of subsidiaries and equity-accounted entities was estimated at 61%(b) for the year, excluding the impact of acquisitions and disposals.

·  
BP today announced a quarterly dividend of 10.00 cents per ordinary share ($0.600 per ADS), which is expected to be paid on 24 March 2016. The corresponding amount in sterling will be announced on 14 March 2016. See page 24 for further information.

*
 
For items marked with an asterisk throughout this document, definitions are provided in the Glossary on page 31.
  
(a)
Profit attributable to BP shareholders.
 
  
(b)
Includes estimated reserves data for Rosneft. The reserves replacement ratio will be finalized and reported in BP Annual Report and Form 20-F 2015 which is scheduled to be published in early March 2016.
 
 
  
The commentaries above and following should be read in conjunction with the cautionary statement on page 34.


Top of page 2
Group headlines (continued)
 

·  
Total capital expenditure on an accruals basis for the fourth quarter was $6.1 billion, of which organic capital expenditure* was $5.5 billion, compared with $6.7 billion for the same period in 2014, of which organic capital expenditure was $6.6 billion. For the full year, total capital expenditure on an accruals basis was $19.5 billion, of which organic capital expenditure was $18.7 billion, compared with $23.8 billion for the same period in 2014, of which organic capital expenditure was $22.9 billion. See page 27 for further information. In 2016, we expect organic capital expenditure to be at the lower end of the range of $17-19 billion.

·  
BP has now completed the $10-billion divestment programme that was announced in October 2013. Disposal proceeds were $0.2 billion for the fourth quarter and $2.8 billion for the full year. The full-year amount for disposal proceeds includes amounts received 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 fourth quarter and full year was 12% and 34% respectively, compared with 70% and 26% 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 year was 22%. Adjusting for non-operating items, fair value accounting effects and the North Sea adjustment, the underlying ETR for the fourth quarter and full year was -20% and 31% respectively, compared with 38% and 36% for the same periods in 2014. The underlying ETR for the fourth quarter reflects tax credits associated with losses in the Upstream segment offsetting tax charges arising elsewhere. The full-year underlying ETR is lower than a year ago mainly due to changes in the geographical mix of profits. In the current environment, and with our existing portfolio of assets, the ETR in 2016 is expected to be lower than 2015 due to the anticipated mix of profits moving away from relatively high tax Upstream jurisdictions.

·  
Finance costs and net finance expense relating to pensions and other post-retirement benefits were a charge of $457 million for the fourth quarter, compared with $381 million for the same period in 2014. For the full year, the respective amounts were $1,653 million and $1,462 million.

· 
Reported production for the fourth quarter, including BP’s share of Rosneft’s production, was 3,397 thousand barrels of oil equivalent per day (mboe/d), compared with 3,214mboe/d for the same period in 2014 (see Upstream on page 4 and Rosneft on page 8). Reported production for the full year, including BP’s share of Rosneft’s production, was 3,277mboe/d, compared with 3,151mboe/d in 2014.

·  
The charge for depreciation, depletion and amortization was $15.2 billion in 2015, the same as 2014. In 2016, we expect the charge to be similar to 2015.

·  
Definitive agreements were signed in January 2016 to dissolve BP’s refining joint operation with Rosneft in Germany (see Note 3 for further information).


Top of page 3
 
Analysis of RC profit (loss) before interest and tax
and reconciliation to profit (loss) for the period
 

Fourth
Third
Fourth
          
quarter
quarter
quarter
      
Year
Year
2014
2015
2015
  
$ million
  
2015
2014
       
RC profit (loss) before interest and tax*
      
(3,085)
743
(2,280)
  
    Upstream
  
(937)
8,934
780
2,562
838
  
    Downstream
  
7,111
3,738
451
382
235
  
    Rosneft
  
1,310
2,100
(647)
(378)
(627)
  
    Other businesses and corporate
  
(1,768)
(2,010)
(468)
(311)
(328)
  
    Gulf of Mexico oil spill response(a)
  
(11,709)
(781)
257
67
65
  
    Consolidation adjustment – UPII*
  
(36)
641
(2,712)
3,065
(2,097)
  
RC profit (loss) before interest and tax
  
(6,029)
12,622
       
Finance costs and net finance expense relating
     
(381)
(474)
(457)
  
  to pensions and other post-retirement benefits
  
(1,653)
(1,462)
2,158
(1,347)
304
  
Taxation on a RC basis
  
2,602
(2,864)
(34)
(10)
17
  
Non-controlling interests
  
(82)
(223)
(969)
1,234
(2,233)
  
RC profit (loss) attributable to BP shareholders
  
(5,162)
8,073
(4,985)
(1,726)
(1,546)
  
Inventory holding gains (losses)
 
(1,889)
(6,210)
       
Taxation (charge) credit on inventory holding
     
1,547
538
472
  
  gains and losses
  
569
1,917
       
Profit (loss) for the period attributable to
      
(4,407)
46
(3,307)
  
  BP shareholders
  
(6,482)
3,780

(a)
See Note 2 on page 16 for further information on the accounting for the Gulf of Mexico oil spill response.


Analysis of underlying RC profit before interest and tax
 

Fourth
Third
Fourth
          
quarter
quarter
quarter
      
Year
Year
2014
2015
2015
  
$ million
  
2015
2014
       
Underlying RC profit before interest and tax*
      
2,246
823
(728)
  
    Upstream
  
1,193
15,201
1,213
2,302
1,218
  
    Downstream
  
7,545
4,441
470
382
235
  
    Rosneft
  
1,310
1,875
(120)
(231)
(299)
  
    Other businesses and corporate
  
(1,221)
(1,340)
257
67
65
  
    Consolidation adjustment - UPII
  
(36)
641
4,066
3,343
491
  
Underlying RC profit before interest and tax
  
8,791
20,818
       
Finance costs and net finance expense relating to
      
(372)
(359)
(342)
  
  pensions and other post-retirement benefits
  
(1,406)
(1,424)
(1,421)
(1,155)
30
  
Taxation on an underlying RC basis
  
(1,398)
(7,035)
(34)
(10)
17
  
Non-controlling interests
  
(82)
(223)
2,239
1,819
196
  
Underlying RC profit attributable to BP shareholders
  
5,905
12,136

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.


Top of page 4
Upstream
 

Fourth
Third
Fourth
          
quarter
quarter
quarter
      
Year
Year
2014
2015
2015
  
$ million
  
2015
2014
(3,165)
716
(2,298)
  
Profit (loss) before interest and tax
  
(967)
8,848
80
27
18
  
Inventory holding (gains) losses*
  
30
86
(3,085)
743
(2,280)
  
RC profit (loss) before interest and tax
  
(937)
8,934
       
Net (favourable) unfavourable impact of
     
       
  non-operating items* and fair value
      
5,331
80
1,552
  
  accounting effects*
  
2,130
6,267
2,246
823
(728)
  
Underlying RC profit (loss) before interest and tax*(a)
  
1,193
15,201

(a)
See page 5 for a reconciliation to segment RC profit before interest and tax by region.

Financial results

The replacement cost result before interest and tax for the fourth quarter and full year was a loss of $2,280 million and $937 million respectively, compared with a loss of $3,085 million and a profit of $8,934 million for the same periods in 2014. The fourth quarter and full year included a net non-operating charge of $1,639 million and $2,235 million respectively, compared with a net non-operating charge of $5,557 million and $6,298 million for the same periods a year ago. The net non-operating charge for the quarter relates mainly to a net impairment charge recorded in relation to a number of assets following a further fall in oil and gas prices in the quarter and changes to other assumptions. See Note 4 Impairment of fixed assets on page 21 for further information. Fair value accounting effects in the fourth quarter and full year had favourable impacts of $87 million and $105 million respectively, compared with favourable impacts of $226 million and $31 million in the same periods of 2014.

After adjusting for non-operating items and fair value accounting effects, the underlying replacement cost result before interest and tax for the fourth quarter and full year was a loss of $728 million and a profit of $1,193 million respectively, compared with a profit of $2,246 million and $15,201 million for the same periods in 2014. The result for the fourth quarter reflected significantly lower liquids and gas realizations and lower gas marketing and trading results partly offset by lower costs, including lower exploration write-offs and benefits from simplification and efficiency activities. The result for the full year reflected significantly lower liquids and gas realizations, rig cancellation charges and lower gas marketing and trading results partly offset by lower costs including benefits from simplification and efficiency activities and lower exploration write-offs, and higher production.

Production

Production for the quarter was 2,369mboe/d, 8.3% higher than the fourth quarter of 2014. Underlying production* for the quarter increased by 1.7%, mainly due to improved operating efficiency, wellwork delivery and major project start-ups partly offset by planned maintenance activity. For the full year, production was 2,258mboe/d, 5.4% higher than in 2014. Underlying production for the full year was flat versus 2014.

Key events

In November, BP signed a Heads of Agreement with the Egyptian Minister of Petroleum regarding the acceleration of the development of the recent Atoll gas discovery. The Atoll discovery (BP 100%) in the North Damietta Offshore Concession in the East Nile Delta, offshore Egypt was announced in March 2015. Development of Atoll will be executed and operated by Pharaonic Petroleum Co. (PhPC), BP’s joint venture with EGAS and Eni. 

Also in November, BP completed a transaction to acquire a 20% participatory interest in Taas-Yuryakh Neftegazodobycha LLC, a Rosneft subsidiary that will further develop the Srednebotuobinskoye oil and gas condensate field in Eastern Siberia.

In December, BP announced the completion of its acquisition of 22.75% in the North Alexandria Concession and 2.75% in the West Mediterranean Deep Water Concession from DEA Deutsche Erdoel AG. The acquisition will bring BP’s working interest in both concessions of the West Nile Delta project in Egypt to 82.75%.

The new Glen Lyon floating production storage and offload (FPSO) vessel has completed sea trials and sailed away from South Korea on 25 December. Glen Lyon is currently in tow to Norway for pre-installation works before travelling to the West of Shetlands for installation and future start of production. The new FPSO is the centrepiece to the Quad 204 project, which is redeveloping the Schiehallion and Loyal fields.

BP’s US Lower 48 Onshore business expanded its San Juan basin operations in December by acquiring all of Devon Energy’s assets in the region. The bulk of the acquired assets, which span northern New Mexico and southern Colorado, consist of Devon’s operated interest in the Northeast Blanco Unit. BP anticipates taking over operations of the unit’s 480 wells spread across 33,000 gross acres at the end of the first quarter of 2016, after receiving required government agency approvals.

Outlook

We expect full-year 2016 underlying production to be broadly flat with 2015. The actual reported outcome will depend on the exact timing of project start-ups, divestments, OPEC quotas and entitlement impacts in our production-sharing agreements*. We expect first-quarter 2016 reported production to be broadly flat with the fourth quarter 2015. Oil prices continue to be challenging in the near term.

The commentary above contains forward-looking statements and should be read in conjunction with the cautionary statement on page 34.



Top of page 5
Upstream
 

Fourth
Third
Fourth
          
quarter
quarter
quarter
      
Year
Year
2014
2015
2015
  
$ million
  
2015
2014
       
Underlying RC profit (loss) before interest and tax
      
1,007
(152)
(852)
  
US
  
(1,615)
4,338
1,239
975
124
  
Non-US
  
2,808
10,863
2,246
823
(728)
      
1,193
15,201
       
Non-operating items
      
(30)
(139)
(260)
  
US
  
(602)
(36)
(5,527)
21
(1,379)
  
Non-US(a)
  
(1,633)
(6,262)
(5,557)
(118)
(1,639)
      
(2,235)
(6,298)
       
Fair value accounting effects
      
152
26
(34)
  
US
  
(66)
23
74
12
121
  
Non-US
  
171
8
226
38
87
      
105
31
       
RC profit (loss) before interest and tax
      
1,129
(265)
(1,146)
  
US
  
(2,283)
4,325
(4,214)
1,008
(1,134)
  
Non-US
  
1,346
4,609
(3,085)
743
(2,280)
      
(937)
8,934
       
Exploration expense
      
426
61
627
  
US(b)
  
960
1,295
1,029
295
296
  
Non-US(a)(c)
  
1,393
2,337
1,455
356
923
      
2,353
3,632
       
Production (net of royalties)(d)
      
       
Liquids* (mb/d)
      
407
390
401
  
US
  
379
411
85
94
131
  
Europe
  
121
94
656
747
795
  
Rest of World
  
732
602
1,149
1,231
1,326
      
1,232
1,106
       
Natural gas (mmcf/d)
      
1,526
1,569
1,547
  
US
  
1,528
1,519
163
232
287
  
Europe
  
266
173
4,332
4,062
4,214
  
Rest of World
  
4,157
4,324
6,021
5,864
6,048
      
5,951
6,016
       
Total hydrocarbons* (mboe/d)
      
670
661
668
  
US
  
643
673
114
135
180
  
Europe
  
167
123
1,403
1,447
1,521
  
Rest of World
  
1,448
1,347
2,187
2,242
2,369
      
2,258
2,143
       
Average realizations(e)
      
69.03
44.01
37.05
  
Total liquids(f) ($/bbl)
  
45.63
87.96
5.54
3.49
3.47
  
Natural gas ($/mcf)
  
3.80
5.70
51.53
33.25
29.54
  
Total hydrocarbons ($/boe)
  
34.78
60.85

(a)
Fourth quarter and full year 2014 include write-offs of $20 million and $395 million respectively relating to Block KG D6 in India. This is classified in the ‘other’ category of non-operating items. In addition, impairment charges of $20 million and $415 million for the same periods were also recorded in relation to this block. See page 28.
(b)
Fourth quarter and full year 2015 include the write-off of costs relating to the Gila discovery in the deepwater Gulf of Mexico. Fourth quarter and full year 2014 include the write-off of costs relating to the Moccasin discovery in the deepwater Gulf of Mexico. Full year 2014 also includes a $544-million write-off relating to the Utica shale acreage in Ohio, following the decision not to proceed with development plans.
(c)
Full year 2015 includes 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. Fourth quarter and full year 2014 include the write-off of $524 million relating to the Bourarhat Sud block licence in the Illizi Basin of Algeria.
(d)
Includes BP’s share of production of equity-accounted entities in the Upstream segment.
(e)
Realizations are based on sales by consolidated subsidiaries only – this excludes equity-accounted entities.
(f)
Includes condensate and bitumen.
 
Because of rounding, some totals may not agree exactly with the sum of their component parts.


Top of page 6
Downstream
 

Fourth
Third
Fourth
          
quarter
quarter
quarter
      
Year
Year
2014
2015
2015
  
$ million
  
2015
2014
(4,064)
875
(644)
  
Profit (loss) before interest and tax
  
5,248
(2,362)
4,844
1,687
1,482
  
Inventory holding (gains) losses*
  
1,863
6,100
780
2,562
838
  
RC profit before interest and tax
  
7,111
3,738
       
Net (favourable) unfavourable impact of
     
       
  non-operating items* and fair value
      
433
(260)
380
  
  accounting effects*
  
434
703
1,213
2,302
1,218
  
Underlying RC profit before interest and tax*(a)
  
7,545
4,441

(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 fourth quarter and full year was $838 million and $7,111 million respectively, compared with $780 million and $3,738 million for the same periods in 2014.  

The 2015 results include a net non-operating charge of $548 million for the fourth quarter and a net non-operating charge of $590 million for the full year, compared with net non-operating charges of $790 million and $1,570 million for the same periods in 2014 (see pages 7 and 28 for further information on non-operating items). Fair value accounting effects had favourable impacts of $168 million for the fourth quarter and $156 million for the full year, compared with favourable impacts of $357 million and $867 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 fourth quarter and full year was $1,218 million and $7,545 million respectively, compared with $1,213 million and $4,441 million for the same periods in 2014. The full-year result is a record for Downstream.

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 $888 million for the fourth quarter and $5,995 million for the full year, compared with $925 million and $3,219 million for the same periods in 2014. The result for the full year reflects a strong refining environment, improved refining margin optimization and operations, and lower costs from simplification and efficiency programmes. The result for the quarter reflects lower costs from simplification and efficiency programmes, offset by a weak supply and trading result.    

On 15 January 2016 we announced that we had signed definitive agreements to dissolve our German refining joint operation with our partner Rosneft, which will refocus our refining business in the heart of Europe.

Lubricants business

The lubricants business reported an underlying replacement cost profit before interest and tax of $294 million in the fourth quarter and $1,384 million in the full year, compared with $313 million and $1,271 million for the same periods in 2014. The result for the quarter reflects continued strong margins offset by adverse foreign exchange impacts. The result for the full year reflects strong performance in growth markets and premium brands and lower costs from simplification and efficiency programmes. These full-year factors contributed to around a 20% growth in the underlying replacement cost profit before interest and tax, which was partially offset by adverse foreign exchange impacts.

Petrochemicals business

The petrochemicals business reported an underlying replacement cost profit before interest and tax of $36 million in the fourth quarter and $166 million in the full year, compared with a loss of $25 million and a loss of $49 million for the same periods in 2014. The results for the quarter and full year reflect improved operational performance and benefits from our simplification and efficiency programmes leading to lower costs. 

Following a review of our petrochemicals portfolio to refocus our global business for long-term growth, on 6 January 2016 we announced the agreement to sell our Decatur petrochemicals complex in Alabama, US.  

Outlook

Looking ahead, refining margins in the first quarter are expected to be lower than the fourth quarter.


The commentary above contains forward-looking statements and should be read in conjunction with the cautionary statement on page 34.


Top of page 7
Downstream
 

Fourth
Third
Fourth
          
quarter
quarter
quarter
      
Year
Year
2014
2015
2015
  
$ million
  
2015
2014
       
Underlying RC profit before interest and tax -
      
       
  by region
      
338
885
477
  
US
  
2,599
1,684
875
1,417
741
  
Non-US
  
4,946
2,757
1,213
2,302
1,218
      
7,545
4,441
       
Non-operating items
      
(337)
51
(196)
  
US
  
(86)
(339)
(453)
(8)
(352)
  
Non-US
  
(504)
(1,231)
(790)
43
(548)
      
(590)
(1,570)
       
Fair value accounting effects
      
379
153
124
  
US
  
102
914
(22)
64
44
  
Non-US
  
54
(47)
357
217
168
      
156
867
       
RC profit before interest and tax
      
380
1,089
405
  
US
  
2,615
2,259
400
1,473
433
  
Non-US
  
4,496
 
1,479
780
2,562
838
      
7,111
3,738
       
Underlying RC profit (loss) before interest
     
       
  and tax - by business(a)(b)
      
925
1,917
888
  
Fuels
  
5,995
3,219
313
348
294
  
Lubricants
  
1,384
1,271
(25)
37
36
  
Petrochemicals
  
166
(49)
1,213
2,302
1,218
      
7,545
4,441
       
Non-operating items and fair value accounting
      
       
  effects(c)
      
(383)
295
(220)
  
Fuels
  
(137)
(389)
(45)
(25)
(17)
  
Lubricants
  
(143)
136
(5)
(10)
(143)
  
Petrochemicals
  
(154)
(450)
(433)
260
 
(380)
      
(434)
(703)
       
RC profit (loss) before interest and tax(a)(b)
      
542
2,212
668
  
Fuels
  
5,858
2,830
268
323
277
  
Lubricants
  
1,241
1,407
(30)
27
(107)
  
Petrochemicals
  
12
(499)
780
2,562
838
      
7,111
3,738
               
13.0
20.0
13.2
  
BP average refining marker margin (RMM)* ($/bbl)
  
17.0
14.4
       
Refinery throughputs (mb/d)
      
657
681
700
  
US
  
657
642
807
785
776
  
Europe
  
794
782
318
230
238
  
Rest of World
  
254
297
1,782
1,696
1,714
      
1,705
1,721
94.8
94.9
95.5
  
Refining availability* (%)
  
94.7
94.9
       
Marketing sales of refined products (mb/d)
      
1,166
1,121
1,267
  
US
  
1,158
1,166
1,173
1,272
1,188
  
Europe
  
1,199
1,177
534
479
476
  
Rest of World(d)
  
478
529
2,873
2,872
2,931
      
2,835
2,872
2,470
2,781
2,883
  
Trading/supply sales of refined products(d)
  
2,770
2,448
5,343
5,653
5,814
  
Total sales volumes of refined products
  
5,605
5,320
       
Petrochemicals production (kte)
      
872
877
938
  
US
  
3,666
3,844
937
976
727
  
Europe
  
3,527
3,851
1,719
2,004
2,002
  
Rest of World
  
7,567
6,319
3,528
3,857
3,667
      
14,760
14,014

(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.
(d)
Third quarter 2015 includes a minor reclassification between Marketing sales in Rest of World and Trading/supply sales of refined products.


Top of page 8
Rosneft
 

Fourth
Third
Fourth
          
quarter
quarter
quarter
      
Year
Year
2014
2015
2015(a)
  
$ million
  
2015(a)
2014
390
370
189
  
Profit before interest and tax(b)
  
1,314
2,076
61
12
46
  
Inventory holding (gains) losses*
  
(4)
24
451
382
235
  
RC profit before interest and tax
  
1,310
2,100
19
–
–
  
Net charge (credit) for non-operating items*
  
–
(225)
470
382
235
  
Underlying RC profit before interest and tax*
  
1,310
1,875

Replacement cost profit before interest and tax for the fourth quarter and full year was $235 million and $1,310 million respectively, compared with $451 million and $2,100 million for the same periods in 2014.

There were no non-operating items in the fourth quarter and full year 2015, compared with a non-operating charge of $19 million and a gain of $225 million for the same periods in 2014.

After adjusting for non-operating items, the underlying replacement cost profit before interest and tax for the fourth quarter and full year was $235 million and $1,310 million respectively, compared with $470 million and $1,875 million for the same periods in 2014. Compared with the same periods last year, the results for the fourth quarter and full year were primarily affected by lower oil prices, foreign exchange, and comparatively favourable duty lag effects.

See also Group statement of comprehensive income – Share of items relating to equity-accounted entities, net of tax, and footnote (a), on page 12 for other foreign exchange effects.

In June, Rosneft’s Annual General Meeting of Shareholders 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.

Fourth
Third
Fourth
          
quarter
quarter
quarter
      
Year
Year
2014
2015
2015(a)
      
2015(a)
2014
       
Production (net of royalties) (BP share)
      
819
810
811
  
Liquids* (mb/d)
  
813
821
1,203
1,125
1,261
  
Natural gas (mmcf/d)
  
1,195
1,084
1,027
1,003
1,028
  
Total hydrocarbons* (mboe/d)
  
1,019
1,008

(a)
The operational and financial information of the Rosneft segment for the fourth quarter and full year is based on preliminary operational and financial results of Rosneft for the full year ended 31 December 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 before interest and tax for the fourth quarter and full year 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
 

Fourth
Third
Fourth
          
quarter
quarter
quarter
      
Year
Year
2014
2015
2015
  
$ million
  
2015
2014
(647)
(378)
(627)
  
Profit (loss) before interest and tax
  
(1,768)
(2,010)
–
–
–
  
Inventory holding (gains) losses*
  
–
–
(647)
(378)
(627)
  
RC profit (loss) before interest and tax
  
(1,768)
(2,010)
527
147
328
  
Net charge (credit) for non-operating items*
  
547
670
(120)
(231)
(299)
  
Underlying RC profit (loss) before interest and tax*
  
(1,221)
(1,340)
       
Underlying RC profit (loss) before interest and tax
      
(167)
(126)
(107)
  
US
  
(439)
(594)
47
(105)
(192)
  
Non-US
  
(782)
(746)
(120)
(231)
(299)
      
(1,221)
(1,340)
       
Non-operating items
      
(219)
(127)
(296)
  
US
  
(434)
(360)
(308)
(20)
(32)
  
Non-US
  
(113)
(310)
(527)
(147)
(328)
      
(547)
(670)
       
RC profit (loss) before interest and tax
      
(386)
(253)
(403)
  
US
  
(873)
(954)
(261)
(125)
(224)
  
Non-US
  
(895)
(1,056)
(647)
(378)
(627)
      
(1,768)
(2,010)

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 fourth quarter and full year was $627 million and $1,768 million respectively, compared with $647 million and $2,010 million for the same periods in 2014.

The fourth-quarter result included a net non-operating charge of $328 million, primarily relating to impairments, compared with a net charge of $527 million a year ago, which related to restructuring provisions and impairments. For the full year, the net non-operating charge was $547 million, compared with a net charge of $670 million in 2014.

After adjusting for non-operating items, the underlying replacement cost loss before interest and tax for the fourth quarter was $299 million, compared with $120 million for the same period in 2014. The underlying charge in the fourth quarter was higher than 2014 mainly due to a number of one-off credits in the fourth quarter 2014. For the full year, the underlying replacement cost loss before interest and tax was $1,221 million compared with $1,340 million in 2014.

Biofuels

The net ethanol-equivalent production (which includes ethanol and sugar) for the fourth quarter and full year was 189 million litres and 795 million litres respectively, compared with 242 million litres and 653 million litres for the same periods in 2014.

Wind

Net wind generation capacity*(a) was 1,588MW at 31 December 2015, the same as at 31 December 2014. BP’s net share of wind generation for the fourth quarter and full year was 1,253GWh and 4,424GWh respectively, compared with 1,240GWh and 4,617GWh for the same periods in 2014.

Outlook

In 2016, Other businesses and corporate average quarterly charges, excluding non-operating items, are expected to be around $300 million although this will fluctuate from quarter to quarter.

(a)
Capacity figures include 32MW in the Netherlands managed by our Downstream segment.



The commentary above contains forward-looking statements and should be read in conjunction with the cautionary statement on page 34.


Top of page 10
Gulf of Mexico oil spill
 

We announced on 2 July 2015 that BP Exploration & Production Inc. 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 along with more than 400 local government claims. On 5 October 2015, the United States lodged with the district court in MDL 2179 a proposed Consent Decree between the United States, the Gulf states and BP to fully and finally resolve any and all natural resource damages (NRD) claims of the United States, the Gulf states, and their respective natural resource trustees and all Clean Water Act (CWA) penalty claims, and certain other claims of the United States and the Gulf states. A hearing has been scheduled by the court to consider approval of the proposed Consent Decree in March 2016.

For further details see Note 2 on page 16.

Financial update

The replacement cost loss before interest and tax for the fourth quarter and full year was $328 million and $11,709 million respectively, compared with $468 million and $781 million for the same periods last year. The fourth-quarter loss reflects additional business economic loss claims under the Plaintiffs’ Steering Committee settlements and the ongoing costs of the Gulf Coast Restoration Organization, partially offset by adjustments to provisions due to discounting effects. The loss for the full year also includes amounts provided for the agreements described above, and additional increases in the provision for business economic loss claims, associated claims administration costs and other items. The cumulative pre-tax charge recognized to date amounts to $55.5 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 16. These could have a material impact on our consolidated financial position, results and cash flows.


Top of page 11
 
Financial statements
 

Group income statement

Fourth
Third
Fourth
          
quarter
quarter
quarter
      
Year
Year
2014
2015
2015
  
$ million
  
2015
2014
               
73,997
56,152
49,172
  
Sales and other operating revenues (Note 6)(a)
  
222,894
353,568
181
327
(615)
  
Earnings from joint ventures – after interest and tax
  
(28)
570
519
504
303
  
Earnings from associates – after interest and tax
  
1,839
2,802
238
151
145
  
Interest and other income
  
611
843
161
167
228
  
Gains on sale of businesses and fixed assets
  
666
895
75,096
57,301
49,233
  
Total revenues and other income
  
225,982
358,678
60,411
42,485
36,893
  
Purchases(a)
  
164,790
281,907
7,002
6,407
6,448
  
Production and manufacturing expenses(b)
  
37,040
27,375
412
238
263
  
Production and similar taxes (Note 7)
  
1,036
2,958
3,866
3,737
3,881
  
Depreciation, depletion and amortization
  
15,219
15,163
       
Impairment and losses on sale of businesses and
      
6,768
40
1,386
  
  fixed assets (Note 4)
  
1,909
8,965
1,455
356
923
  
Exploration expense
 
2,353
3,632
2,879
2,699
3,082
  
Distribution and administration expenses
  
11,553
12,266
(7,697)
1,339
(3,643)
  
Profit (loss) before interest and taxation
 
(7,918)
6,412
299
398
379
  
Finance costs(b)
  
1,347
1,148
       
Net finance expense relating to pensions and other
      
82
76
78
  
  post-retirement benefits
  
306
314
(8,078)
865
(4,100)
  
Profit (loss) before taxation
 
(9,571)
4,950
(3,705)
809
(776)
  
Taxation(b)
  
(3,171)
947
(4,373)
56
(3,324)
  
Profit (loss) for the period
  
(6,400)
4,003
       
Attributable to
      
(4,407)
46
(3,307)
  
  BP shareholders
  
(6,482)
3,780
34
10
(17)
  
  Non-controlling interests
  
82
223
(4,373)
56
(3,324)
      
(6,400)
4,003
               
       
Earnings per share (Note 8)
      
       
Profit (loss) for the period attributable to
     
       
  BP shareholders
      
       
  Per ordinary share (cents)
      
(24.18)
0.25
(18.01)
  
    Basic
  
(35.39)
20.55
(24.18)
0.25
(18.01)
  
    Diluted
  
(35.39)
20.42
       
  Per ADS (dollars)
     
(1.45)
0.02
(1.08)
  
    Basic
  
(2.12)
1.23
(1.45)
0.02
(1.08)
  
    Diluted
  
(2.12)
1.23

(a)
Amounts reported in the prior quarters of 2015 for Sales and other operating revenues and Purchases have been amended, with no effect on profit for the period. See Note 6 for further information.
(b)
See Note 2 for information on the impact of the Gulf of Mexico oil spill on these income statement line items.


Top of page 12
Financial statements (continued)
 

Group statement of comprehensive income

Fourth
Third
Fourth
          
quarter
quarter
quarter
      
Year
Year
2014
2015
2015
  
$ million
  
2015
2014
               
(4,373)
56
(3,324)
  
Profit (loss) for the period
  
(6,400)
4,003
       
Other comprehensive income
     
       
Items that may be reclassified subsequently to
     
       
  profit or loss
      
(3,496)
(2,247)
(958)
  
  Currency translation differences
  
(4,119)
(6,838)
       
  Exchange gains (losses) on translation of foreign
     
       
    operations reclassified to gain or loss on sale of
     
54
7
–
  
    business and fixed assets
  
23
51
–
–
–
  
  Available-for-sale investments
  
1
–
(111)
(70)
(24)
  
  Cash flow hedges marked to market
  
(178)
(155)
       
  Cash flow hedges reclassified to the
      
17
65
29
  
    income statement
  
249
(73)
–
7
6
  
  Cash flow hedges reclassified to the balance sheet
  
22
(11)
       
  Share of items relating to equity-accounted
     
(2,418)
(830)
(233)
  
    entities, net of tax(a)
  
(814)
(2,584)
151
268
(43)
  
  Income tax relating to items that may be reclassified
  
257
147
(5,803)
(2,800)
(1,223)
      
(4,559)
(9,463)
       
Items that will not be reclassified to profit or loss
      
       
  Remeasurements of the net pension and other
     
(2,825)
(551)
2,570
  
    post-retirement benefit liability or asset
  
4,139
(4,590)
       
  Share of items relating to equity-accounted
     
(1)
(1)
–
  
    entities, net of tax
  
(1)
4
       
  Income tax relating to items that will not be
      
856
80
(881)
  
    reclassified
  
(1,397)
1,334
(1,970)
(472)
1,689
      
2,741
(3,252)
(7,773)
(3,272)
466
  
Other comprehensive income
 
(1,818)
(12,715)
(12,146)
(3,216)
(2,858)
  
Total comprehensive income
  
(8,218)
(8,712)
       
Attributable to
      
(12,155)
(3,204)
(2,836)
  
  BP shareholders
  
(8,259)
(8,903)
9
(12)
(22)
  
  Non-controlling interests
  
41
191
(12,146)
(3,216)
(2,858)
      
(8,218)
(8,712)

(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 13
 
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
 
(8,259)
41
(8,218)
Dividends
  
(6,659)
(91)
(6,750)
Share-based payments, net of tax
  
656
–
656
Share of equity-accounted entities’ changes in equity,
        
  net of tax
  
40
–
40
Transactions involving non-controlling interests
  
(3)
20
17
At 31 December 2015
  
97,216
1,171
98,387
         
   
BP
    
   
shareholders’
Non-controlling
Total
$ million
  
equity
interests
equity
         
At 1 January 2014
  
129,302
1,105
130,407
         
Total comprehensive income
  
(8,903)
191
(8,712)
Dividends
  
(5,850)
(255)
(6,105)
Repurchases of ordinary share capital
  
(3,366)
–
(3,366)
Share-based payments, net of tax
  
185
–
185
Share of equity-accounted entities’ changes in equity,
        
  net of tax
  
73
–
73
Transactions involving non-controlling interests
  
–
160
160
At 31 December 2014
  
111,441
1,201
112,642


Top of page 14
 
Financial statements (continued)
 

Group balance sheet

   
31 December
31 December
$ million
  
2015
2014
Non-current assets
      
Property, plant and equipment
  
129,758
130,692
Goodwill
  
11,627
11,868
Intangible assets
  
18,660
20,907
Investments in joint ventures
  
8,412
8,753
Investments in associates
  
9,422
10,403
Other investments
  
1,002
1,228
Fixed assets
  
178,881
183,851
Loans
  
529
659
Trade and other receivables
  
2,216
4,787
Derivative financial instruments
  
4,409
4,442
Prepayments
  
1,003
964
Deferred tax assets
  
1,545
2,309
Defined benefit pension plan surpluses
  
2,647
31
   
191,230
197,043
Current assets
      
Loans
  
272
333
Inventories
  
14,142
18,373
Trade and other receivables
  
22,323
31,038
Derivative financial instruments
  
4,242
5,165
Prepayments
 
1,838
1,424
Current tax receivable
  
599
837
Other investments
  
219
329
Cash and cash equivalents
  
26,389
29,763
   
70,024
87,262
Assets classified as held for sale (Note 3)
  
578
–
   
70,602
87,262
Total assets
  
261,832
284,305
Current liabilities
      
Trade and other payables
  
31,949
40,118
Derivative financial instruments
  
3,239
3,689
Accruals
 
6,261
7,102
Finance debt
  
6,944
6,877
Current tax payable
  
1,080
2,011
Provisions
  
5,154
3,818
   
54,627
63,615
Liabilities directly associated with assets classified as held for sale (Note 3)
  
97
–
   
54,724
63,615
Non-current liabilities
      
Other payables
  
2,910
3,587
Derivative financial instruments
  
4,283
3,199
Accruals
  
890
861
Finance debt
  
46,224
45,977
Deferred tax liabilities
  
9,599
13,893
Provisions
  
35,960
29,080
Defined benefit pension plan and other post-retirement benefit plan deficits
  
8,855
11,451
   
108,721
108,048
Total liabilities
  
163,445
171,663
Net assets
  
98,387
112,642
Equity
      
BP shareholders’ equity
  
97,216
111,441
Non-controlling interests
  
1,171
1,201
   
98,387
112,642


Top of page 15
Financial statements (continued)
 

Condensed group cash flow statement

Fourth
Third
Fourth
          
quarter
quarter
quarter
      
Year
Year
2014
2015
2015
  
$ million
  
2015
2014
       
Operating activities
      
(8,078)
865
(4,100)
  
Profit (loss) before taxation
  
(9,571)
4,950
       
Adjustments to reconcile profit (loss) before taxation
     
       
  to net cash provided by operating activities
      
       
  Depreciation, depletion and amortization and
     
5,215
3,971
4,578
  
    exploration expenditure written off
  
17,048
18,192
       
  Impairment and (gain) loss on sale of businesses
      
6,607
(127)
1,158
  
    and fixed assets
  
1,243
8,070
       
  Earnings from equity-accounted entities, less
     
(224)
(295)
1,028
  
    dividends received
  
(197)
(1,461)
       
  Net charge for interest and other finance expense,
      
49
196
164
  
    less net interest paid
  
502
330
(58)
137
167
  
  Share-based payments
  
321
379
       
  Net operating charge for pensions and other post-
      
       
    retirement benefits, less contributions and benefit
      
(664)
(41)
(464)
  
    payments for unfunded plans
  
(592)
(963)
551
113
591
  
  Net charge for provisions, less payments
  
11,792
1,119
       
  Movements in inventories and other current and
      
4,842
1,231
2,978
  
   non-current assets and liabilities
  
843
6,925
(993)
(867)
(294)
  
  Income taxes paid
  
(2,256)
(4,787)
7,247
5,183
5,806
  
Net cash provided by operating activities
  
19,133
32,754
       
Investing activities
      
(5,900)
(4,357)
(5,126)
  
Capital expenditure
  
(18,648)
(22,546)
(118)
33
(10)
  
Acquisitions, net of cash acquired
  
23
(131)
(65)
(55)
(87)
  
Investment in joint ventures
  
(265)
(179)
(128)
(119)
(888)
  
Investment in associates
  
(1,312)
(336)
224
88
17
  
Proceeds from disposal of fixed assets
  
1,066
1,820
       
Proceeds from disposal of businesses, net of
     
880
200
215
  
  cash disposed
  
1,726
1,671
48
61
1
  
Proceeds from loan repayments
  
110
127
(5,059)
(4,149)
(5,878)
  
Net cash used in investing activities
  
(17,300)
(19,574)
       
Financing activities
      
(793)
–
–
  
Net repurchase of shares
  
–
(4,589)
2,779
117
185
  
Proceeds from long-term financing
  
8,173
12,394
(2,937)
(18)
(3,559)
  
Repayments of long-term financing
  
(6,426)
(6,282)
(186)
(115)
(124)
  
Net increase (decrease) in short-term debt
  
473
(693)
9
–
(5)
  
Net increase (decrease) in non-controlling interests
 
  
(5)
9
(1,729)
(1,718)
(1,541)
  
Dividends paid
– BP shareholders
  
(6,659)
(5,850)
(40)
(29)
(20)
    
– non-controlling interests
 
(91)
(255)
(2,897)
(1,763)
(5,064)
  
Net cash provided by (used in) financing activities
  
(4,535)
(5,266)
       
Currency translation differences relating to cash
     
(257)
(158)
(177)
  
  and cash equivalents
  
(672)
(671)
(966)
(887)
(5,313)
  
Increase (decrease) in cash and cash equivalents
  
(3,374)
7,243
30,729
32,589
31,702
  
Cash and cash equivalents at beginning of period
  
29,763
22,520
29,763
31,702
26,389
  
Cash and cash equivalents at end of period
  
26,389
29,763


Top of page 16
 
Financial statements (continued)
 

Notes

1.       Basis of preparation

The results for the interim periods and for the year ended 31 December 2015 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.

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.

In BP Annual Report and Form 20-F 2014 we disclosed a significant estimate or judgement relating to the recoverability of asset carrying values, including the discount rates applied to estimates of future cash flows to determine the recoverable amount of assets when performing impairment tests. During the fourth quarter 2015 the discount rates used by the group in assessments of impairment were reviewed. The post-tax discount rate applied to cash flow analyses used to calculate fair value less costs of disposal in the fourth quarter was 7%. For value-in-use calculations, the pre-tax discount rate applied in the fourth quarter was 11%. For both calculations a premium of 2% continues to be added for assets located in higher risk countries. The group’s assumptions for long-term oil and gas prices were also revised downwards slightly for impairment tests in which the recoverable amount of Upstream assets is determined on the basis of fair value less costs of disposal. Impairment tests continue to utilize market-based forward prices for the first five years. Further details will be provided in BP Annual Report and Form 20-F 2015 which is expected to be published in early March 2016.


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 33 of this report.

The group income statement includes a pre-tax charge of $443 million for the fourth quarter and $11,956 million for the full year in relation to the Gulf of Mexico oil spill. The fourth-quarter charge reflects additional business economic loss claims under the Plaintiffs’ Steering Committee (PSC) settlement, finance costs and the ongoing costs of the Gulf Coast Restoration Organization, partially offset by adjustments to provisions due to discounting effects. The cumulative pre-tax income statement charge since the incident, in April 2010, amounts to $55,451 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 to settle all federal and state claims and claims made by more than 400 local government entities were 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 resolution to BP’s satisfaction of the economic loss, property damage and other claims with more than 400 local government entities. The proposed Consent Decree between the United States, the Gulf states and BP was available for public comment until early December 2015 and is subject to final court approval. The Consent Decree and Settlement Agreement with the five Gulf states are conditional upon each other and neither will become effective unless there is final court approval of the Consent Decree; a hearing has been scheduled by the court to consider approval of the proposed Consent Decree in March 2016. During the third quarter 2015, the Settlement Agreement with the five Gulf states was executed. BP has accepted releases received from the vast majority of local government entities and payments required under those releases were made during the third quarter. For more information on the proposed Consent Decree and Settlement Agreement see Legal proceedings on pages 32-34 of BP Third Quarter and nine months results 2015.

The agreements described above (the Agreements) 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 relating to the incident not covered by the Agreements. The total amounts


Top of page 17
Financial statements (continued)
 

Notes

2.       Gulf of Mexico oil spill (continued)

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.

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.

 
Fourth
Third
Fourth
          
 
quarter
quarter
quarter
      
Year
Year
 
2014
2015
2015
  
$ million
  
2015
2014
         
Income statement
      
 
468
311
328
  
Production and manufacturing expenses
  
11,709
781
 
(468)
(311)
(328)
  
Profit (loss) before interest and taxation
  
(11,709)
(781)
 
9
115
115
  
Finance costs
  
247
38
 
(477)
(426)
(443)
  
Profit (loss) before taxation
  
(11,956)
(819)
 
163
(87)
(134)
  
Taxation
  
3,492
262
 
(314)
(513)
(577)
  
Profit (loss) for the period
  
(8,464)
(557)


     
31 December
31 December
 
$ million
  
2015
2014
 
Balance sheet
      
 
Current assets
      
 
  Trade and other receivables
  
686
1,154
 
Current liabilities
      
 
  Trade and other payables
  
(693)
(655)
 
  Accruals
  
(40)
–
 
  Provisions
  
(3,076)
(1,702)
 
Net current assets (liabilities)
  
(3,123)
(1,203)
 
Non-current assets
      
 
  Trade and other receivables
  
–
2,701
 
Non-current liabilities
     
 
  Other payables
  
(2,057)
(2,412)
 
  Accruals
  
(186)
(169)
 
  Provisions
  
(13,431)
(6,903)
 
  Deferred tax
 
5,200
1,723
 
Net non-current assets (liabilities)
  
(10,474)
(5,060)
 
Net assets (liabilities)
  
(13,597)
(6,263)


 
Fourth
Third
Fourth
          
 
quarter
quarter
quarter
      
Year
Year
 
2014
2015
2015
  
$ million
  
2015
2014
         
Cash flow statement - Operating activities
      
 
(477)
(426)
(443)
  
Profit (loss) before taxation
  
(11,956)
(819)
         
Adjustments to reconcile profit (loss) before
      
         
  taxation to net cash provided by
      
         
  operating activities
      
         
Net charge for interest and other finance
      
 
9
115
115
  
  expense, less net interest paid
  
247
38
 
334
235
227
  
Net charge for provisions, less payments
  
11,296
939
         
Movements in inventories and other current
      
 
3
(135)
(36)
  
  and non-current assets and liabilities
  
(732)
(1,454)
 
(131)
(211)
(137)
  
Pre-tax cash flows
  
(1,145)
(1,296)

Net cash from operating activities relating to the Gulf of Mexico oil spill, on a post-tax basis, amounted to an outflow of $137 million and an outflow of $1,130 million in the fourth quarter and full year of 2015 respectively. For the same periods in 2014, the amounts were an inflow of $304 million and an outflow of $9 million respectively.


Top of page 18
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 31 December 2015, $686 million of the provisions and payables are eligible to be paid from the Trust. The reimbursement asset is recorded within Trade and other receivables on the balance sheet, all of which is classified as current, as payment of all amounts covered by the remaining reimbursement asset may be requested during 2016. During 2015, $3,022 million of provisions and $147 million of payables were paid from the Trust.

At 31 December 2015, the remaining cash in the Trust not allocated for specific purposes was $25 million. This unallocated amount was exhausted in January 2016 and BP commenced paying claims and other costs not covered by the specific-purpose cash balances. The total cash remaining in the Trust and associated qualifying settlement funds, amounting to $1.4 billion, includes $0.7 billion in the seafood compensation fund, $0.2 billion held for natural resource damage early restoration projects and $0.5 billion held in relation to certain other specified costs under the PSC settlement.

(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 fourth quarter and full year are presented in the table below.

         
Litigation
Clean
 
         
and
Water Act
  
 
$ million 
  
Environmental
claims
penalties
Total
 
At 1 October 2015
  
6,004
6,644
4,179
16,827
 
Net increase (decrease) in provision
  
(9)
575
–
566
 
Unwinding of discount
  
47
25
34
106
 
Change in discount rate
  
(115)
(59)
(84)
(258)
 
Utilization
– paid by BP
  
(1)
(80)
–
(81)
 
               
– paid by the trust fund
  
(7)
(646)
–
(653)
 
At 31 December 2015
  
5,919
6,459
4,129
16,507
 
Of which
– current
  
227
2,849
–
3,076
 
               
– non-current
  
5,692
3,610
4,129
13,431

         
Litigation
Clean
  
         
and
Water Act
  
       
Environmental
claims
penalties
Total
 
$ million 
          
 
At 1 January 2015
  
1,141
3,954
3,510
8,605
 
Net increase (decrease) in provision
 
5,393
5,832
661
11,886
 
Unwinding of discount
  
94
50
68
212
 
Change in discount rate
  
(149)
(74)
(110)
(333)
 
Reclassified to other payables
  
(459)
(125)
–
(584)
 
Utilization
– paid by BP
  
(23)
(234)
–
(257)
   
– paid by the trust fund
  
(78)
(2,944)
–
(3,022)
 
At 31 December 2015
  
5,919
6,459
4,129
16,507


Top of page 19
Financial statements (continued)
 

Notes

2.       Gulf of Mexico oil spill (continued)

Environmental
The environmental provision includes amounts payable for natural resource damage costs under the proposed Consent Decree. 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. Amounts payable under the $1-billion early restoration framework agreement with natural resource trustees for the US and five Gulf states, that are not yet allocated to specific projects, 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 provided under the Agreements in relation to state claims that have not yet been paid. 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 2012 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 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 revised 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. Only a small proportion of claim determinations have been made under some of the specialized frameworks that have been put in place for particular industries, namely construction, agriculture, professional services and education, and so determinations to date may not be representative of the total population of claims. In addition, although some pre-determination data has been provided to BP, detailed data on the majority of pre-determination claims is not available due to a court order to protect claimant confidentiality. Therefore there is an insufficient level of detail to enable a complete or clear understanding of the composition of the underlying claims population.

There is insufficient 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 $12.4 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 $402 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 $12.4 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 20
Financial statements (continued)
 

Notes

2.       Gulf of Mexico oil spill (continued)

There continues to be a high level of uncertainty with regards to the amounts that ultimately will be paid in relation to current claims as described above and the outcomes of any further litigation including by parties excluded from, or parties who opted out of, the PSC settlement. 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 relation to state 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. The vast majority of local government entities who filed claims have issued releases, which were accepted by BP; amounts due under those releases were paid during the third quarter of 2015.

Clean Water Act penalties
A provision has been recognized for penalties under Section 311 of the Clean Water Act, as determined in the Agreements. The amount is payable in instalments over 15 years, commencing one year after the court approves the Consent Decree. 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 $566 million and $11,886 million was recognized for the fourth quarter and full year respectively. The fourth-quarter net increase arises primarily due to an increase in the litigation and claims provision for business economic loss claims. The remainder of the income statement charge mainly relates to finance costs, offset by adjustments to provisions due to discounting effects. The net increase for the full year also includes amounts provided for the Agreements, and additional increases in the litigation and claims provision for business economic loss claims, associated claims administration costs and other items. The following table shows an analysis of the income statement charge.

     
Fourth
  
Cumulative
     
quarter
Year
since the
 
$ million 
  
2015
2015
incident
 
Environmental costs
  
(124)
5,303
8,526
 
Spill response costs
  
–
–
14,304
 
Litigation and claims costs
  
516
5,758
32,538
 
Clean Water Act penalties – amount provided
  
(84)
551
4,061
 
Other costs charged directly to the income statement
  
20
97
1,354
 
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
  
328
11,709
54,973
 
Finance costs
– related to the trust funds
  
–
–
137
   
– not related to the trust funds
  
115
247
341
 
Loss before taxation
  
443
11,956
55,451

Further information on provisions is provided in BP Annual Report and Form 20-F 2014 – Financial statements – Note 2.


Top of page 21
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, except for claims covered by the Agreements.

·  
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, 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 government entity claims. See additional information on the Agreements above.

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.       Non-current assets held for sale

On 15 January 2016 BP and Rosneft announced that they had signed definitive agreements to dissolve the German refining joint operation Ruhr Oel GmbH (ROG). The restructuring, which is expected to be completed in 2016, will result in Rosneft taking ownership of ROG’s interests in the Bayernoil, MiRO Karlsruhe and PCK Schwedt refineries. In exchange, BP will take sole ownership of the Gelsenkirchen refinery and the solvent production facility DHC Solvent Chemie. Assets and associated liabilities relating to BP’s share of ROG’s interests in the Bayernoil, MiRO Karlsruhe and PCK Schwedt refineries have been classified as held for sale in the group balance sheet at 31 December 2015.


4.       Impairment of fixed assets

The net impairment loss for the fourth quarter and full year is $2,014 million and $2,357 million respectively. Of this total amount, $1,303 million and $1,646 million respectively is included within the line item in the income statement for Impairment and losses on sale of businesses and fixed assets. The remaining $711 million in the fourth quarter and full year relates to BP’s share of impairment charges recognized by equity-accounted entities included in the income statement line item Earnings from joint ventures – after interest and tax.

The fourth-quarter net impairment loss comprised $1,579 million in Upstream, $156 million in Downstream, and $279 million in Other businesses and corporate. The full-year net impairment loss comprised $1,960 million in Upstream, $87 million in Downstream, and $310 million in Other businesses and corporate.

The net impairment loss in Upstream, including BP’s share of impairment charges recognized by equity-accounted entities, comprised impairment losses of $2,572 million and $3,040 million for the fourth quarter and full year respectively, and impairment reversals of $993 million and $1,080 million for the same periods. Impairment losses have been recorded in a number of regions with the largest charge arising in Angola, a significant element of which relates to the Angola LNG plant. Impairment losses also included charges in relation to assets in the North Sea but these were more than offset by impairment reversals in relation to other assets in the region.

The impairment losses primarily arose as a result of a lower price environment, technical reserves revisions, and increases in decommissioning cost estimates for certain assets. The impairment reversals arose mainly as a result of decreases in cost estimates and a reduction in the discount rate applied, offsetting the impact of lower prices.


Top of page 22
Financial statements (continued)
 

Notes

5.        Analysis of replacement cost profit (loss) before interest and tax and reconciliation
           to profit (loss) before taxation

 
Fourth
Third
Fourth
          
 
quarter
quarter
quarter
      
Year
Year
 
2014
2015
2015
  
$ million
  
2015
2014
 
(3,085)
743
(2,280)
  
Upstream
  
(937)
8,934
 
780
2,562
838
  
Downstream
  
7,111
3,738
 
451
382
235
  
Rosneft
  
1,310
2,100
 
(647)
(378)
(627)
  
Other businesses and corporate
  
(1,768)
(2,010)
 
(2,501)
3,309
(1,834)
      
5,716
12,762
 
(468)
(311)
(328)
  
Gulf of Mexico oil spill response
  
(11,709)
(781)
 
257
67
65
  
Consolidation adjustment – UPII*
  
(36)
641
 
(2,712)
3,065
(2,097)
  
RC profit (loss) before interest and tax
  
(6,029)
12,622
         
Inventory holding gains (losses)*
      
 
(80)
(27)
(18)
  
  Upstream
  
(30)
(86)
 
(4,844)
(1,687)
(1,482)
  
  Downstream
  
(1,863)
(6,100)
 
(61)
(12)
(46)
  
  Rosneft (net of tax)
  
4
(24)
 
(7,697)
1,339
(3,643)
  
Profit (loss) before interest and tax
  
(7,918)
6,412
 
299
398
379
  
Finance costs
  
1,347
1,148
         
Net finance expense relating to pensions
     
 
82
76
78
  
  and other post-retirement benefits
  
306
314
 
(8,078)
865
(4,100)
  
Profit (loss) before taxation
  
(9,571)
4,950
                 
         
RC profit (loss) before interest and tax*
      
 
683
324
(1,429)
  
US
  
(12,243)
5,251
 
(3,395)
2,741
(668)
  
Non-US
  
6,214
7,371
 
(2,712)
3,065
(2,097)
      
(6,029)
12,622


Top of page 23
 
Financial statements (continued)
 

Notes

6.        Sales and other operating revenues

 
Fourth
Third
Fourth
          
 
quarter
quarter
quarter
      
Year
Year
 
2014
2015
2015
  
$ million
  
2015
2014
         
By segment
      
 
15,800
10,357
10,212
  
Upstream
  
43,235
65,424
 
65,249
50,921
43,463
  
Downstream(a)
  
200,569
323,486
 
616
552
556
  
Other businesses and corporate
  
2,048
1,989
 
81,665
61,830
54,231
      
245,852
390,899
                 
         
Less: sales and other operating revenues
      
         
  between segments
      
 
8,270
5,809
4,987
  
Upstream
  
21,949
36,643
 
(814)
(377)
(133)
  
Downstream
  
68
(173)
 
212
246
205
  
Other businesses and corporate
  
941
861
 
7,668
5,678
5,059
      
22,958
37,331
                 
         
Third party sales and other operating revenues
      
 
7,530
4,548
5,225
  
Upstream
  
21,286
28,781
 
66,063
51,298
43,596
  
Downstream(a)
  
200,501
323,659
 
404
306
351
  
Other businesses and corporate
  
1,107
1,128
 
73,997
56,152
49,172
  
Total sales and other operating revenues
  
222,894
353,568
                 
         
By geographical area
      
 
27,300
20,680
16,936
  
US
  
78,281
132,310
 
51,933
39,200
34,773
  
Non-US(a)
  
158,519
251,943
 
79,233
59,880
51,709
      
236,800
384,253
         
Less: sales and other operating revenues
      
 
5,236
3,728
2,537
  
  between areas
  
13,906
30,685
 
73,997
56,152
49,172
      
222,894
353,568

(a)
Amounts reported in the prior quarters of 2015 for Downstream and Total sales and other operating revenues have been amended. Amended Total sales and other operating revenues are $55,519 million for the first quarter 2015, $62,051 million for the second quarter 2015 and $56,152 million for the third quarter 2015. The previously reported amounts for Total sales and other operating revenues were $54,196 million, $60,646 million and $54,730 million respectively. Purchases have been amended by the same amounts and therefore there is no impact on reported profit.


 
7.      Production and similar taxes

 
Fourth
Third
Fourth
          
 
quarter
quarter
quarter
      
Year
Year
 
2014
2015
2015
  
$ million
  
2015
2014
 
56
30
118
  
US
  
215
690
 
356
208
145
  
Non-US
  
821
2,268
 
412
238
263
      
1,036
2,958


 
8.        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 24
 
Financial statements (continued)
 

Notes

 
8.        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.

 
Fourth
Third
Fourth
          
 
quarter
quarter
quarter
      
Year
Year
 
2014
2015
2015
  
$ million
  
2015
2014
         
Results for the period
      
         
Profit (loss) for the period attributable
     
 
(4,407)
46
(3,307)
  
  to BP shareholders
  
(6,482)
3,780
 
1
–
1
  
Less: preference dividend
  
2
2
         
Profit (loss) attributable to BP
     
 
(4,408)
46
(3,308)
  
  ordinary shareholders
  
(6,484)
3,778
                 
         
Number of shares (thousand)(a)(b)
      
         
Basic weighted average number  
      
 
18,232,147
18,329,701
18,369,064
  
  of shares outstanding
  
18,323,646
18,385,458
 
3,038,691
3,054,950
3,061,510
  
ADS equivalent
  
3,053,941
3,064,243
                 
         
Weighted average number of
     
         
  shares outstanding used to
     
 
18,232,147
18,371,656
18,369,064
  
  calculate diluted earnings per share
  
18,323,646
18,497,294
 
3,038,691
3,061,942
3,061,510
  
ADS equivalent
  
3,053,941
3,082,882
                 
 
18,199,882
18,349,963
18,412,392
  
Shares in issue at period-end
  
18,412,392
18,199,882
 
3,033,313
3,058,327
3,068,732
  
ADS equivalent
  
3,068,732
3,033,313

(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.


 
9.       Dividends

Dividends payable

BP today announced an interim dividend of 10.00 cents per ordinary share which is expected to be paid on 24 March 2016 to shareholders and American Depositary Share (ADS) holders on the register on 12 February 2016. The corresponding amount in sterling is due to be announced on 14 March 2016, calculated based on the average of the market exchange rates for the four dealing days commencing on 8 March 2016. 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 fourth-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

 
Fourth
Third
Fourth
          
 
quarter
quarter
quarter
      
Year
Year
 
2014
2015
2015
      
2015
2014
         
Dividends paid per ordinary share
      
 
10.000
10.000
10.000
  
  cents
  
40.000
39.000
 
6.377
6.549
6.634
  
  pence
  
26.383
23.850
 
60.00
60.00
60.00
  
Dividends paid per ADS (cents)
  
240.00
234.00
         
Scrip dividends
     
 
13.7
18.5
49.7
  
Number of shares issued (millions)
  
102.8
165.6
 
95
110
289
  
Value of shares issued ($ million)
  
642
1,318


Top of page 25
 
Financial statements (continued)
 

Notes

 
10.      Net debt*

Net debt ratio*

 
Fourth
Third
Fourth
          
 
quarter
quarter
quarter
      
Year
Year
 
2014
2015
2015
  
$ million
  
2015
2014
 
52,854
57,405
53,168
  
Gross debt
  
53,168
52,854
         
Fair value (asset) liability of hedges related
      
 
(445)
(57)
379
  
  to finance debt(a)
  
379
(445)
 
52,409
57,348
53,547
      
53,547
52,409
 
29,763
31,702
26,389
  
Less: cash and cash equivalents
  
26,389
29,763
 
22,646
25,646
27,158
  
Net debt
  
27,158
22,646
 
112,642
102,599
98,387
  
Equity
  
98,387
112,642
 
16.7%
20.0%
21.6%
  
Net debt ratio
  
21.6%
16.7%

Analysis of changes in net debt

 
Fourth
Third
Fourth
          
 
quarter
quarter
quarter
      
Year
Year
 
2014
2015
2015
  
$ million
  
2015
2014
         
Opening balance
      
 
53,610
57,104
57,405
  
Finance debt
  
52,854
48,192
         
Fair value (asset) liability of hedges
      
 
(434)
315
(57)
  
  related to finance debt(a)
  
(445)
(477)
 
30,729
32,589
31,702
  
Less: cash and cash equivalents
  
29,763
22,520
 
22,447
24,830
25,646
  
Opening net debt
  
22,646
25,195
         
Closing balance
      
 
52,854
57,405
53,168
  
Finance debt
  
53,168
52,854
         
Fair value (asset) liability of hedges
     
 
(445)
(57)
379
  
  related to finance debt(a)
  
379
(445)
 
29,763
31,702
26,389
  
Less: cash and cash equivalents
  
26,389
29,763
 
22,646
25,646
27,158
  
Closing net debt
  
27,158
22,646
 
(199)
(816)
(1,512)
  
Decrease (increase) in net debt
  
(4,512)
2,549
         
Movement in cash and cash equivalents
      
 
(709)
(729)
(5,136)
  
  (excluding exchange adjustments)
  
(2,702)
7,914
         
Net cash outflow (inflow) from financing
      
 
344
16
3,498
  
  (excluding share capital and dividends)
  
(2,220)
(5,419)
 
(3)
40
(33)
  
Other movements
  
17
(435)
         
Movement in net debt before
     
 
(368)
(673)
(1,671)
  
  exchange effects
  
(4,905)
2,060
 
169
(143)
159
  
Exchange adjustments
  
393
489
 
(199)
(816)
(1,512)
  
Decrease (increase) in net debt
  
(4,512)
2,549

(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 $1,617 million (third quarter 2015 liability of $1,349 million and fourth quarter 2014 liability of $774 million) are not included in the calculation of net debt shown above as hedge accounting was not applied for these instruments.


 
11.    Inventory valuation

A provision of $1,295 million was held at 31 December 2015 ($722 million at 30 September 2015 and $2,879 million at 31 December 2014) to write inventories down to their net realizable value. The net movement charged to the income statement during the fourth quarter 2015 was $583 million (third quarter 2015 was a charge of $144 million and fourth quarter 2014 was a charge of $1,924 million).


Top of page 26
 
Financial statements (continued)
 

Notes

 
12.    Statutory accounts

The financial information shown in this publication, which was approved by the Board of Directors on 1 February 2016, is unaudited and does not constitute statutory financial statements. Audited financial information is expected to be published in BP Annual Report and Form 20-F 2015 in early March 2016 and delivered to the Registrar of Companies in due course. 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 did not contain a statement under section 498(2) or section 498(3) of the UK Companies Act 2006. 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 auditors on BP Annual Report and Form 20-F 2015, due to be published in early March 2016, is not expected to contain an emphasis of matter paragraph.


Top of page 27
 
Additional information
 

Capital expenditure and acquisitions

Fourth
Third
Fourth
          
quarter
quarter
quarter
      
Year
Year
2014
2015
2015
  
$ million
  
2015
2014
       
By segment
      
       
Upstream
      
1,560
1,121
1,313
  
US
  
4,560
6,203
3,546
2,673
3,841
  
Non-US
  
12,522
13,569
5,106
3,794
5,154
      
17,082
19,772
       
Downstream
      
265
143
224
  
US
  
702
942
984
269
633
  
Non-US
  
1,407
2,164
1,249
412
857
      
2,109
3,106
       
Other businesses and corporate
      
38
11
37
  
US
  
70
82
341
53
90
  
Non-US
  
270
821
379
64
127
      
340
903
6,734
4,270
6,138
      
19,531
23,781
       
By geographical area
      
1,863
1,275
1,574
  
US
  
5,332
7,227
4,871
2,995
4,564
  
Non-US
  
14,199
16,554
6,734
4,270
6,138
      
19,531
23,781
       
Included above:
      
150
(16)
22
  
Acquisitions and asset exchanges
  
49
420
27
–
584
  
Other inorganic capital expenditure
  
734
469

Capital expenditure shown in the table above is presented on an accruals basis.


Top of page 28
Additional information (continued)
 

Non-operating items*

Fourth
Third
Fourth
          
quarter
quarter
quarter
      
Year
Year
2014
2015
2015
  
$ million
  
2015
2014
       
Upstream
      
       
Impairment and gain (loss) on sale of businesses
     
(5,685)
(44)
(853)
  
  and fixed assets(a)(b)
  
(1,204)
(6,576)
(1)
(35)
–
  
Environmental and other provisions
  
(24)
(60)
(100)
(92)
(70)
  
Restructuring, integration and rationalization costs
  
(410)
(100)
187
40
18
  
Fair value gain (loss) on embedded derivatives
  
120
430
42
13
(734)
  
Other(b)(c)
  
(717)
8
(5,557)
(118)
(1,639)
      
(2,235)
(6,298)
       
Downstream
      
       
Impairment and gain (loss) on sale of businesses
     
(614)
182
(185)
  
  and fixed assets(a)
  
131
(1,190)
(5)
(92)
(9)
  
Environmental and other provisions
  
(108)
(133)
(158)
(46)
(351)
  
Restructuring, integration and rationalization costs
  
(607)
(165)
–
–
–
  
Fair value gain (loss) on embedded derivatives
  
–
–
(13)
(1)
(3)
  
Other
  
(6)
(82)
(790)
43
(548)
      
(590)
(1,570)
       
Rosneft
      
       
Impairment and gain (loss) on sale of businesses
      
(19)
–
–
  
  and fixed assets
  
–
225
–
–
–
  
Environmental and other provisions
  
–
–
–
–
–
  
Restructuring, integration and rationalization costs
  
–
–
–
–
–
  
Fair value gain (loss) on embedded derivatives
  
–
–
–
–
–
  
Other
  
–
–
(19)
–
–
      
–
225
       
Other businesses and corporate
      
       
Impairment and gain (loss) on sale of businesses
     
(308)
(11)
(120)
  
  and fixed assets(a)
  
(170)
(304)
(35)
(123)
(24)
  
Environmental and other provisions
  
(151)
(180)
(175)
(13)
(29)
  
Restructuring, integration and rationalization costs
  
(71)
(176)
–
–
–
  
Fair value gain (loss) on embedded derivatives
  
–
–
(9)
–
(155)
  
Other(c)
  
(155)
(10)
(527)
(147)
(328)
      
(547)
(670)
(468)
(311)
(328)
  
Gulf of Mexico oil spill response
  
(11,709)
(781)
(7,361)
(533)
(2,843)
  
Total before interest and taxation
  
(15,081)
(9,094)
(9)
(115)
(115)
  
Finance costs(d)
  
(247)
(38)
(7,370)
(648)
(2,958)
  
Total before taxation
  
(15,328)
(9,132)
3,805
(108)
341
  
Taxation credit (charge)
  
4,056
4,512
(3,565)
(756)
(2,617)
  
Total after taxation for period
  
(11,272)
(4,620)

(a)
See Note 4 for further information on impairment charges and reversals.
(b)
Fourth quarter and full year 2014 include impairment charges of $20 million and $415 million respectively and write-offs of $20 million and $395 million respectively in the ‘other’ non-operating item category relating to Block KG D6 in India.
(c)
Fourth quarter and full year 2015 principally relates to BP’s share of impairment losses recognized by equity-accounted entities.
(d)
Finance costs relate to the Gulf of Mexico oil spill. See Note 2 for further details.


Top of page 29
 
Additional information (continued)
 

Non-GAAP information on fair value accounting effects

Fourth
Third
Fourth
          
quarter
quarter
quarter
      
Year
Year
2014
2015
2015
  
$ million
  
2015
2014
       
Favourable (unfavourable) impact relative to
     
       
  management’s measure of performance
      
226
38
87
  
Upstream
  
105
31
357
217
168
  
Downstream
  
156
867
583
255
255
      
261
898
(226)
(84)
(67)
  
Taxation credit (charge)
  
(56)
(341)
357
171
188
      
205
557

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.

Fourth
Third
Fourth
          
quarter
quarter
quarter
      
Year
Year
2014
2015
2015
  
$ million
  
2015
2014
       
Upstream
      
       
Replacement cost profit before interest and tax
      
(3,311)
705
(2,367)
  
  adjusted for fair value accounting effects
  
(1,042)
8,903
226
38
87
  
Impact of fair value accounting effects
  
105
31
(3,085)
743
(2,280)
  
Replacement cost profit (loss) before interest and tax
  
(937)
8,934
       
Downstream
      
       
Replacement cost profit before interest and tax
      
423
2,345
670
  
  adjusted for fair value accounting effects
  
6,955
2,871
357
217
168
  
Impact of fair value accounting effects
  
156
867
780
2,562
838
  
Replacement cost profit before interest and tax
  
7,111
3,738
       
Total group
      
       
Profit (loss) before interest and tax adjusted for
     
(8,280)
1,084
(3,898)
  
  fair value accounting effects
  
(8,179)
5,514
583
255
255
  
Impact of fair value accounting effects
  
261
898
(7,697)
1,339
(3,643)
  
Profit (loss) before interest and tax
  
(7,918)
6,412


Top of page 30
Additional information (continued)
 

Realizations and marker prices

Fourth
Third
Fourth
          
quarter
quarter
quarter
      
Year
Year
2014
2015
2015
      
2015
2014
       
Average realizations(a)
      
       
Liquids* ($/bbl)
      
71.41
46.22
37.42
  
US
  
44.94
84.24
71.10
47.68
40.49
  
Europe
  
49.71
93.84
66.61
41.80
36.10
  
Rest of World
  
45.22
90.19
69.03
44.01
37.05
  
BP Average
  
45.63
87.96
       
Natural gas ($/mcf)
      
3.30
2.18
1.71
  
US
  
2.10
3.80
8.19
6.44
6.08
  
Europe
  
7.27
8.18
6.33
3.88
4.00
  
Rest of World
  
4.25
6.35
5.54
3.49
3.47
  
BP Average
  
3.80
5.70
       
Total hydrocarbons* ($/boe)
      
51.92
32.85
26.70
  
US
  
31.80
60.37
65.35
44.76
39.03
  
Europe
  
47.64
82.63
49.88
32.05
29.70
  
Rest of World
  
34.57
58.61
51.53
33.25
29.54
  
BP Average
  
34.78
60.85
       
Average oil marker prices ($/bbl)
      
76.58
50.47
43.76
  
Brent
  
52.39
98.95
73.62
46.45
42.07
  
West Texas Intermediate
  
48.71
93.28
57.78
31.93
29.11
  
Western Canadian Select
  
36.83
73.83
74.66
51.52
43.62
  
Alaska North Slope
 
52.44
97.52
72.69
45.34
38.79
  
Mars
  
48.19
92.93
75.19
49.19
41.42
  
Urals (NWE – cif)
  
50.97
97.23
       
Average natural gas marker prices
      
4.04
2.77
2.27
  
Henry Hub gas price ($/mmBtu)(b)
  
2.67
4.43
52.83
41.48
36.64
  
UK Gas – National Balancing Point (p/therm)
  
42.61
50.01

(a)
Based on sales of consolidated subsidiaries only – this excludes equity-accounted entities.
(b)
Henry Hub First of Month Index.


Exchange rates

Fourth
Third
Fourth
          
quarter
quarter
quarter
      
Year
Year
2014
2015
2015
      
2015
2014
1.58
1.55
1.52
  
$/£ average rate for the period
  
1.53
1.65
1.56
1.51
1.48
  
$/£ period-end rate
  
1.48
1.56
               
1.25
1.11
1.09
  
$/€ average rate for the period
  
1.11
1.33
1.22
1.12
1.09
  
$/€ period-end rate
  
1.09
1.22
               
47.71
63.08
65.88
  
Rouble/$ average rate for the period
  
61.25
38.52
55.65
65.63
73.17
  
Rouble/$ period-end rate
  
73.17
55.65


Top of page 31
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 29.

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 – Liquids for Upstream and Rosneft comprises crude oil, condensate and natural gas liquids. For Upstream, liquids also includes bitumen.

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 28.

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 27.

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.


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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.

Reserves replacement ratio is the extent to which the year’s production has been replaced by proved reserves added to our reserve base. The ratio is expressed in oil-equivalent terms and includes changes resulting from discoveries, improved recovery and extensions and revisions to previous estimates, but excludes changes resulting from acquisitions and disposals.

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 28 and 29 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.


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Legal proceedings
 

The following discussion sets out the material developments in the group’s material legal proceedings during the recent period. For a full discussion of the group’s material legal proceedings, see pages 228-238 of BP Annual Report and Form 20-F 2014, pages 35 to 37 of BP Second quarter and half year results 2015 and pages 32-34 of BP Third quarter and nine months results 2015.

Matters relating to the Deepwater Horizon accident and oil spill (the Incident)

Oil Pollution Act (OPA) Test Case Proceedings Seven OPA test cases before the federal district court in New Orleans will address certain OPA liability questions focusing on, among other issues, whether plaintiffs’ alleged losses tied to the 2010 federal government moratoria on deepwater drilling and federal permit delays are compensable. In December 2015, BP filed a motion to dismiss plaintiffs’ claims arising from the moratoria or permit process, and plaintiffs filed a motion asking the court to prevent BP from arguing that government action and/or inaction following the oil spill is a “superseding” cause with respect to some or all of the damages that plaintiffs claim. The motions are fully briefed, but the court has not yet issued a ruling.

Plaintiffs’ Steering Committee (PSC) settlements – Economic and Property Damages Settlement Agreement The economic and property damages claims process is under court supervision through the settlement claims process established by the Economic and Property Damages Settlement, which resolves certain economic and property damage claims arising from the Incident. On 23 April 2015, the PSC appealed the Fifth Circuit’s denial of the PSC’s motion seeking to alter or amend a revised policy addressing the matching of revenue and expenses for business economic loss claims. On 18 December 2015, the PSC and BP entered into a joint stipulation to stay this appeal pending resolution of certain issues in the federal district court in New Orleans. On 8 January 2016, the Fifth Circuit granted the joint stipulation and stayed the appeal for 120 days.

Non-US government lawsuits On 30 November 2015, the US Supreme Court denied the petition for certiorari filed by three Mexican states bordering the Gulf of Mexico against several BP entities alleging the Incident harmed their tourism, fishing and commercial shipping industries.

On 18 October 2012, before a Mexican Federal District Court located in Mexico City, a class action complaint was filed against BP Exploration & Production Inc., BP America Production Company and other BP subsidiaries. The plaintiffs, consisting of fishermen and other groups, are seeking, among other things, compensatory damages for the class members who allegedly suffered economic losses, as well as an order requiring BP to remediate environmental damage resulting from the Incident, to provide funding for the preservation of the environment and to conduct environmental impact studies in the Gulf of Mexico for the next 10 years. After initial dismissal of the action, it was reported in December 2015 that the action was reinstated after appeal, although BP has not been formally served with the action.

Securities Class Action On 20 May 2014, the court denied plaintiffs’ motion to certify a proposed class of ADS purchasers before the Deepwater Horizon explosion (from 8 November 2007 to 20 April 2010) and granted plaintiffs’ motions to certify a class of post-explosion ADS purchasers from 26 April 2010 to 28 May 2010 and to amend their complaint to add one additional alleged misstatement. The parties appealed the district court’s class certification decisions and on 8 September 2015, the Fifth Circuit affirmed both of the district court’s decisions. On 26 October 2015, the Fifth Circuit denied the pre-explosion ADS purchasers’ motion for rehearing en banc. On 25 January 2016, the pre-explosion ADS purchasers filed in the Supreme Court a petition for a writ of certiorari seeking review of the Fifth Circuit’s decision. The trial of the securities fraud claims of the class of post explosion ADS purchasers has been scheduled to commence on 5 July 2016.

Employee Retirement Income Security Act (ERISA) Following an earlier dismissal by the federal district court in Houston in the ERISA case related to BP share funds in several employee benefit savings plans, plaintiffs filed an amended complaint on 12 February 2015. On 30 October 2015, the district court granted defendants’ partial motion to dismiss, dismissing some of the claims in the amended complaint.

Other legal proceedings

Prudhoe Bay leak In March and August 2006, oil leaked from transit pipelines operated by BP Exploration (Alaska) Inc. at the Prudhoe Bay unit on the North Slope of Alaska. On 12 May 2008, a BP p.l.c. shareholder filed a consolidated complaint alleging violations of federal securities law on behalf of a putative class of BP p.l.c. shareholders, based on alleged misrepresentations concerning the integrity of the Prudhoe Bay pipeline before its shutdown on 6 August 2006. On 7 December 2015, the complaint was dismissed with prejudice. On 5 January 2016, plaintiffs filed a notice of appeal of that decision to the Ninth Circuit Court of Appeals.

EC investigation On 7 December 2015, the European Commission confirmed that it had dropped BP from its investigation regarding anticompetitive practices in connection with oil price reporting practices and the reference price assessment process.


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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 operations 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, expectations regarding 2016 restructuring charges, organic capital expenditure, effective tax rate and depreciation, depletion and amortization charges; expectations regarding future net debt ratio; the expected quarterly dividend payment and timing of such payment; expectations regarding future oil prices; plans and expectations regarding Upstream activities in Egypt, Eastern Siberia and in the Lower 48; expectations regarding Upstream 2016 underlying production and first-quarter 2016 reported production, Downstream first-quarter 2016 refining margins and Other businesses and corporate 2016 quarterly charges; plans and expectations regarding Downstream activities in Europe; expectations with respect to the proposed Consent Decree and Settlement Agreement, including final court approval and timing thereof and the total amounts that will ultimately be paid by BP in relation to the incident; and certain statements regarding the legal and trial proceedings, court decisions, claims, penalties, potential investigations and civil actions by regulators, government entities and/or other entities or parties and 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 under “Principal risks and uncertainties” in our Form 6-K for the period ended 30 June 2015 and under “Risk factors” in BP Annual Report and Form 20-F 2014 as filed with the US Securities and Exchange Commission.



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 SIGNATURES

 
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
 
 

 
 
 
BP p.l.c.
(Registrant)
 
 

Dated: 02 February 2016
 
/s/ J. BERTELSEN
...............................
J. BERTELSEN
Deputy Secretary