bp201502036k.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, 2015


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 2014
 
Top of page 1
FOR IMMEDIATE RELEASE                                         London 3 February 2015
 

Fourth
Third
Fourth
          
quarter
quarter
quarter
      
Year
Year
2013
2014
2014
  
$ million
  
2014
2013
1,042
1,290
(4,407)
  
Profit (loss) for the period(a)
  
3,780
23,451
465
1,095
3,438
  
Inventory holding (gains) losses*, net of tax
  
4,293
230
1,507
2,385
(969)
  
Replacement cost profit (loss)*
  
8,073
23,681
       
Net (favourable) unfavourable impact of non-operating
      
1,302
652
3,208
  
  items* and fair value accounting effects*, net of tax
  
4,063
(10,253)
2,809
3,037
2,239
  
Underlying replacement cost profit*
  
12,136
13,428
       
Replacement cost profit (loss)
      
8.06
12.97
(5.32)
  
    per ordinary share (cents)
  
43.90
125.08
0.48
0.78
(0.32)
  
    per ADS (dollars)
  
2.63
7.50
       
Underlying replacement cost profit
      
15.02
16.51
12.28
  
    per ordinary share (cents)
  
66.00
70.92
0.90
0.99
0.74
  
    per ADS (dollars)
  
3.96
4.26

·  
BP’s fourth-quarter replacement cost (RC) result was a loss of $969 million, compared with a profit of $1,507 million a year ago. After adjusting for a net charge for non-operating items of $3,565 million, mainly relating to impairments in Upstream, reflecting the impact of the lower near-term price environment, revisions to reserves and other factors (see page 4 and Note 3 on page 22), and net favourable fair value accounting effects of $357 million (both on a post-tax basis), underlying RC profit for the fourth quarter 2014 was $2,239 million, compared with $2,809 million for the same period in 2013.

·  
For the full year, RC profit was $8,073 million, compared with $23,681 million a year ago which included a $12.5-billion gain relating to the disposal of our interest in TNK-BP. After adjusting for a net charge for non-operating items of $4,620 million and net favourable fair value accounting effects of $557 million (both on a post-tax basis), underlying RC profit for the full year was $12,136 million, compared with $13,428 million for the same period in 2013. 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 $477 million for the quarter and $819 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 quarter and full year was $7.2 billion and $32.8 billion respectively, compared with $5.4 billion and $21.1 billion for the same periods in 2013. Excluding amounts related to the Gulf of Mexico oil spill, net cash provided by operating activities for the fourth quarter and full year was $6.9 billion and $32.8 billion respectively, compared with $5.3 billion and $21.2 billion respectively for the same periods in 2013.

·  
Net debt at 31 December 2014 was $22.6 billion, compared with $25.2 billion a year ago. The ratio of net debt to net debt plus equity at 31 December 2014 was 16.7%, compared with 16.2% a year ago. We continue to target a net debt ratio in the 10-20% range. Net debt and the ratio of net debt to net debt plus equity are non-GAAP measures. See page 25 for more information.

·  
The reserves replacement ratio* on a combined basis of subsidiaries and equity-accounted entities was estimated at 62%(b) for the year, excluding the impact of acquisitions and disposals.

·  
Total capital expenditure on an accruals basis for the fourth quarter was $6.7 billion, of which organic capital expenditure* was $6.6 billion. For the full year, total capital expenditure on an accruals basis was $23.8 billion, of which organic capital expenditure was $22.9 billion. In 2015, we expect organic capital expenditure to be around $20 billion.

·  
In October 2013, BP announced plans to divest a further $10 billion of assets before the end of 2015, having completed its earlier divestment programme of $38 billion. BP has agreed around $4.7 billion of such further divestments to date. Disposal proceeds received in cash were $1.1 billion for the quarter and $3.5 billion for the full year.

·  
BP today announced a quarterly dividend of 10.00 cents per ordinary share ($0.600 per ADS), which is expected to be paid on 27 March 2015. The corresponding amount in sterling will be announced on 16 March 2015. See page 25 for further information.

*
 
For items marked with an asterisk throughout this document, definitions are provided in the Glossary on page 31.
  
(a)
Profit (loss) attributable to BP shareholders.
 
  
(b)
Includes estimated reserves data from Rosneft. The reserves replacement ratio will be finalized and reported in BP Annual Report and Form 20-F 2014 which is scheduled to be published in early March 2015.
 
 
 
 
  
The commentaries above and following should be read in conjunction with the cautionary statement on page 36.


Top of page 2
Group headlines (continued)
 

·  
The effective tax rate (ETR) on RC profit or loss for the fourth quarter and full year was 70% and 26% respectively, compared with 15% and 21% for the same periods in 2013. Adjusting for non-operating items and fair value accounting effects, the underlying ETR for the fourth quarter and full year was 38% and 36% respectively, compared with 24% and 35% for the same periods in 2013. The underlying ETR was higher for the fourth quarter 2014 mainly due to foreign exchange impacts on deferred tax and a lower level of equity-accounted earnings (which are reported net of tax), compared to the corresponding period in 2013. In the current environment, with our current portfolio of assets, the underlying ETR in 2015 is expected to be lower than 2014.

·  
Finance costs and net finance expense relating to pensions and other post-retirement benefits were a charge of $381 million for the fourth quarter, compared with $378 million for the same period in 2013. For the full year, the respective amounts were $1,462 million and $1,548 million.

·  
BP repurchased 105 million ordinary shares at a cost of $0.7 billion, including fees and stamp duty, during the fourth quarter of 2014. For the full year, BP repurchased 612 million ordinary shares at a cost of $4.8 billion, including fees and stamp duty. The $8-billion share repurchase programme announced on 22 March 2013 was completed in July 2014.

·  
Reported production for the fourth quarter, including BP’s share of Rosneft’s production, was 3,214 thousand barrels of oil equivalent per day (mboe/d), compared with 3,231mboe/d for the same period in 2013 (see Upstream on page 4 and Rosneft on page 8). This reduction reflected the Abu Dhabi onshore concession expiry and divestments, substantially offset by increased production from higher-margin areas and favourable entitlement impacts in our production-sharing agreements (PSAs), resulting from lower oil prices in Upstream and higher production in Rosneft. Reported production for the full year, including BP’s share of Rosneft’s production, was 3,151mboe/d, compared with 3,230mboe/d in 2013 which includes BP’s share of Rosneft and TNK-BP production. This reduction reflected the Abu Dhabi onshore concession expiry and divestments, partially offset by increased production from higher-margin areas and higher production in Rosneft in 2014 compared to the aggregate production in Rosneft and TNK-BP in 2013.

·  
The charge for depreciation, depletion and amortization was $15.2 billion in 2014, compared with $13.5 billion in 2013, reflecting the impact of new major projects coming onstream.  In 2015, we expect a flatter trend relative to 2014.



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

Fourth
Third
Fourth
          
quarter
quarter
quarter
      
Year
Year
2013
2014
2014
  
$ million
  
2014
2013
       
RC profit (loss) before interest and tax*
      
2,537
3,311
(3,085)
  
    Upstream
  
8,934
16,657
(360)
1,231
780
  
    Downstream
  
3,738
2,919
–
–
–
  
    TNK-BP(a)
  
–
12,500
1,058
107
451
  
    Rosneft(b)
  
2,100
2,153
(605)
(432)
(647)
  
    Other businesses and corporate
  
(2,010)
(2,319)
(179)
(33)
(468)
  
    Gulf of Mexico oil spill response(c)
  
(781)
(430)
(240)
370
257
  
    Consolidation adjustment – UPII*
  
641
579
2,211
4,554
(2,712)
  
RC profit (loss) before interest and tax
  
12,622
32,059
       
Finance costs and net finance expense relating to
      
(378)
(358)
(381)
  
  pensions and other post-retirement benefits
  
(1,462)
(1,548)
(270)
(1,777)
2,158
  
Taxation on a RC basis
  
(2,864)
(6,523)
(56)
(34)
(34)
  
Non-controlling interests
  
(223)
(307)
1,507
2,385
(969)
  
RC profit (loss) attributable to BP shareholders
  
8,073
23,681
(634)
(1,585)
(4,985)
  
Inventory holding gains (losses)
 
(6,210)
(290)
       
Taxation (charge) credit on inventory holding gains
      
169
490
1,547
  
  and losses
  
1,917
60
1,042
1,290
(4,407)
  
Profit (loss) for the period attributable to BP shareholders
  
3,780
23,451

(a)
BP ceased equity accounting for its share of TNK-BP’s earnings from 22 October 2012. Full year 2013 includes the gain arising on the disposal of BP’s interest in TNK-BP.
(b)
BP’s investment in Rosneft is accounted under the equity method from 21 March 2013. See page 8 for further information.
(c)
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
2013
2014
2014
  
$ million
  
2014
2013
       
Underlying RC profit before interest and tax*
      
3,852
3,899
2,246
  
    Upstream
  
15,201
18,265
70
1,484
1,213
  
    Downstream
  
4,441
3,632
1,087
110
470
  
    Rosneft
  
1,875
2,198
(614)
(293)
(120)
  
    Other businesses and corporate
  
(1,340)
(1,898)
(240)
370
257
  
    Consolidation adjustment - UPII
  
641
579
4,155
5,570
4,066
  
Underlying RC profit before interest and tax
  
20,818
22,776
       
Finance costs and net finance expense relating to
      
(368)
(348)
(372)
  
  pensions and other post-retirement benefits
  
(1,424)
(1,509)
(922)
(2,151)
(1,421)
  
Taxation on an underlying RC basis
  
(7,035)
(7,532)
(56)
(34)
(34)
  
Non-controlling interests
  
(223)
(307)
2,809
3,037
2,239
  
Underlying RC profit attributable to BP shareholders
  
12,136
13,428

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
2013
2014
2014
  
$ million
  
2014
2013
2,540
3,312
(3,165)
  
Profit (loss) before interest and tax
  
8,848
16,661
(3)
(1)
80
  
Inventory holding (gains) losses*
  
86
(4)
2,537
3,311
(3,085)
  
RC profit (loss) before interest and tax
  
8,934
16,657
       
Net (favourable) unfavourable impact of non-operating
      
1,315
588
5,331
  
  items* and fair value accounting effects*
  
6,267
1,608
3,852
3,899
2,246
  
Underlying RC profit before interest and tax*(a)
  
15,201
18,265

(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 $3,085 million and a profit of $8,934 million respectively, compared with a profit of $2,537 million and $16,657 million for the same periods in 2013. The fourth quarter and full year included a net non-operating charge of $5,557 million and $6,298 million respectively. These are primarily related to impairments associated with several assets, mainly in the North Sea and Angola reflecting the impact of the lower near-term price environment, revisions to reserves and other factors (see Note 3 on page 22 for further information). In 2013, the net non-operating charge for the fourth quarter and full year was $1,201 million and $1,364 million, respectively. Fair value accounting effects in the fourth quarter and full year had favourable impacts of $226 million and $31 million respectively, compared with unfavourable impacts of $114 million and $244 million in the same periods of 2013.

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 $2,246 million and $15,201 million respectively, compared with $3,852 million and $18,265 million for the same periods in 2013. The result for the fourth quarter reflected significantly lower liquids realizations, the absence of a one-off benefit to production taxes which occurred in 2013 and higher exploration write-offs, partly offset by lower costs, higher production in higher-margin areas and a benefit from stronger gas marketing and trading activities. The result for the full year reflected lower liquids realizations, higher costs, mainly depreciation, depletion and amortization and exploration write-offs and the absence of one-off benefits which occurred in 2013 related to production taxes and a cost pooling settlement agreement between the owners of the Trans-Alaska Pipeline System (TAPS), partly offset by higher production in higher-margin areas, higher gas realizations and a benefit from stronger gas marketing and trading activities.

Production

Production for the quarter was 2,187mboe/d, 2.6% lower than the fourth quarter of 2013. Underlying production* increased by 2.3%, reflecting growth in production from higher-margin areas. For the full year, reported production was 2,143mboe/d, 5% lower than in 2013. Underlying production for the full year was 2.2% higher than in 2013, also from higher-margin areas.

Key events

In November, BP was awarded two new exploration blocks as a result of the 2013 Egyptian Natural Gas Holding Company (EGAS) bid round: Block 3 – North El Mataria (BP 50%), in the onshore Nile Delta, will be operated by BP; Block 8 – Karawan Offshore (BP 50%) is located in the Mediterranean Sea and will be operated by ENI. BP and its partners have committed to invest a total of $240 million in the blocks over different phases. Also in November, BP completed the sale of its interests and transfer of operatorship in four BP-operated oilfields on the North Slope of Alaska to Hilcorp.

In December, BP announced the start of operations by Husky Energy at the Sunrise Phase 1 in-situ oil sands project in Alberta, Canada (BP 50%), with the start of steam generation. BP also announced the start of production from the Kinnoull field (BP 77.06%) in the central North Sea. The Kinnoull reservoir is tied back to BP’s Andrew platform. These were the final two of seven major project start-ups in 2014. In Azerbaijan, BP and the State Oil Company of the Republic of Azerbaijan (SOCAR) signed a new production-sharing agreement (PSA) to jointly explore for and develop potential resources in the shallow water area around the Absheron Peninsula in the Azerbaijan sector of the Caspian Sea.

After the end of the quarter, BP announced the formation of a new ownership and operating model with Chevron and ConocoPhillips in the deepwater Gulf of Mexico. Under the agreements, BP will sell to Chevron approximately half of its current equity interests in the Gila and Tiber fields. BP, Chevron and ConocoPhillips also have agreed to joint ownership interests in exploration blocks east of Gila known as Gibson. Chevron will operate Tiber, Gila and Gibson, with operatorship transferring after BP finishes drilling appraisal wells at Gila and Tiber.

Outlook

Reported production for the full year 2015 is expected to be higher than 2014. The actual reported outcome will depend on the exact timing of project start-ups, divestments, OPEC quotas and entitlement impacts in our PSAs. We expect full-year underlying production in 2015 to be broadly flat with 2014. We expect first-quarter 2015 reported production to be higher than the fourth quarter, mainly reflecting higher entitlements in PSA regions on the basis of assumed lower oil prices.


The commentary above contains forward-looking statements and should be read in conjunction with the cautionary statement on page 36.


Top of page 5
Upstream
 

Fourth
Third
Fourth
          
quarter
quarter
quarter
      
Year
Year
2013
2014
2014
  
$ million
  
2014
2013
       
Underlying RC profit before interest and tax(a)
      
1,050
1,181
1,007
  
US
  
4,338
3,836
2,802
2,718
1,239
  
Non-US
  
10,863
14,429
3,852
3,899
2,246
      
15,201
18,265
       
Non-operating items(b)
      
(3)
125
(30)
  
US
  
(36)
58
(1,198)
(626)
(5,527)
  
Non-US(c)(d)
  
(6,262)
(1,422)
(1,201)
(501)
(5,557)
      
(6,298)
(1,364)
       
Fair value accounting effects
      
(112)
(49)
152
  
US
  
23
(269)
(2)
(38)
74
  
Non-US
  
8
25
(114)
(87)
226
      
31
(244)
       
RC profit (loss) before interest and tax(a)
      
935
1,257
1,129
  
US
  
4,325
3,625
1,602
2,054
(4,214)
  
Non-US
  
4,609
13,032
2,537
3,311
(3,085)
      
8,934
16,657
       
Exploration expense
      
126
142
426
  
US(e)
  
1,295
438
2,048
698
1,029
  
Non-US(c)(d)(f)
  
2,337
3,003
2,174
840
1,455
      
3,632
3,441
       
Production (net of royalties)(g)
      
       
Liquids* (mb/d)
      
392
410
407
  
US
  
411
363
97
91
85
  
Europe
  
94
96
712
605
656
  
Rest of World
  
602
718
1,201
1,106
1,149
      
1,106
1,176
       
Natural gas (mmcf/d)
      
1,507
1,546
1,526
  
US
  
1,519
1,539
190
164
163
  
Europe
  
173
237
4,360
4,328
4,332
  
Rest of World
  
4,324
4,483
6,057
6,038
6,021
      
6,016
6,259
       
Total hydrocarbons* (mboe/d)
      
652
676
670
  
US
  
673
628
130
119
114
  
Europe
  
123
137
1,464
1,352
1,403
  
Rest of World
  
1,347
1,491
2,246
2,147
2,187
      
2,143
2,256
       
Average realizations(h)
      
98.26
91.42
69.03
  
Total liquids ($/bbl)
  
87.96
99.24
5.49
5.40
5.54
  
Natural gas ($/mcf)
  
5.70
5.35
65.04
61.61
51.53
  
Total hydrocarbons ($/boe)
  
60.85
63.58

(a)
A minor amendment has been made to the analysis by region for the comparative periods in 2013.
(b)
See Note 3 for more information on impairment losses in the fourth quarter and full year 2014.
(c)
Third quarter, fourth quarter and full year 2014 include write-offs of $375 million, $20 million and $395 million respectively relating to Block KG D6 in India. This is classified in the ‘other’ category of non-operating items (see page 28). In addition, impairment charges of $395 million, $20 million and $415 million for the same periods were also recorded in relation to this block.
(d)
Fourth quarter and full year 2013 include an $845-million write-off relating to the value ascribed to block BM-CAL-13 offshore Brazil as part of the accounting for the acquisition of upstream assets from Devon Energy in 2011 and $216 million of costs relating to the Pitanga exploration well, which was drilled in this block and did not encounter commercial quantities of oil or gas. The $845-million write-off has been classified in the ‘other’ category of non-operating items (see page 28).
(e)
Fourth quarter and full year 2014 include the write-off of costs relating to the Moccasin discovery in the deepwater Gulf of Mexico. Following on from the decision to create a separate BP business around our US lower 48 onshore oil and gas activities, and as a consequence of disappointing appraisal results, we have decided not to proceed with development plans in the Utica shale. Third quarter and full year 2014 include write-offs of $23 million and $544 million respectively, relating to the Utica acreage.
(f)
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. Fourth quarter and full year 2013 include the write-off of costs relating to the Risha concession in Jordan.
(g)
Includes BP’s share of production of equity-accounted entities in the Upstream segment.
(h)
Based on sales by consolidated subsidiaries only – this excludes equity-accounted entities.
 
Because of rounding, some totals may not agree exactly with the sum of their component parts.


Top of page 6
 
Downstream
 

Fourth
Third
Fourth
          
quarter
quarter
quarter
      
Year
Year
2013
2014
2014
  
$ million
  
2014
2013
(840)
(335)
(4,064)
  
Profit (loss) before interest and tax
  
(2,362)
2,725
480
1,566
4,844
  
Inventory holding (gains) losses*
  
6,100
194
(360)
1,231
780
  
RC profit (loss) before interest and tax
  
3,738
2,919
       
Net (favourable) unfavourable impact of non-operating
      
430
253
433
  
  items* and fair value accounting effects*
  
703
713
70
1,484
1,213
  
Underlying RC profit before interest and tax*(a)
  
4,441
3,632

(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 $780 million and $3,738 million respectively, compared with a replacement cost loss before interest and tax of $360 million and a replacement cost profit before interest and tax of $2,919 million for the same periods in 2013.

The 2014 results included net non-operating charges of $790 million for the fourth quarter and $1,570 million for the full year, compared with net non-operating charges of $74 million and $535 million for the same periods a year ago (see pages 7 and 28 for further information on non-operating items). The fourth-quarter non-operating charges are mainly related to impairment losses in our fuels business and costs associated with our restructuring programme and charges for the full year are mainly related to impairment losses in our fuels and petrochemicals businesses. Fair value accounting effects had favourable impacts of $357 million for the fourth quarter and $867 million for the full year, compared with unfavourable impacts of $356 million for the fourth quarter and $178 million for the full year in 2013.
 
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 $1,213 million and $4,441 million respectively, compared with $70 million and $3,632 million a year ago with the increase in profits mainly arising in the fuels business.

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 $925 million for the fourth quarter and $3,219 million for the full year, compared with an underlying replacement cost loss before interest and tax of $204 million and an underlying replacement cost profit before interest and tax of $2,230 million for the same periods in 2013. Relative to the same period in 2013, despite an overall weaker refining environment which was primarily due to falling crude price differentials in the US, the result for the quarter benefited from an improved fuels marketing performance, increased heavy crude processing in the US, lower turnaround activity and an improved contribution from supply and trading. The stronger full-year result was also impacted by the weaker refining environment which was more than offset by higher fuels marketing performance, increased heavy crude processing and increased production, mainly associated with the ramp-up of operations at our Whiting refinery following the completion of the modernization project.    

Lubricants business

The lubricants business reported an underlying replacement cost profit before interest and tax of $313 million in the fourth quarter and $1,271 million for the full year, compared with $230 million and $1,272 million in the same periods last year. The fourth-quarter result reflects continued margin improvement in growth markets and benefits, in comparison with the same period in 2013, from the absence of restructuring charges which were recorded in the same period in 2013. These factors were partially offset by adverse foreign exchange impacts. Similarly the full-year result benefited from improved margin across the portfolio, contributing to a 6% improvement in the result which, however, was offset by adverse foreign exchange translation impacts.

Petrochemicals business

The petrochemicals business reported an underlying replacement cost loss before interest and tax of $25 million in the fourth quarter and $49 million in the full year, compared with an underlying replacement cost profit before interest and tax of $44 million and $130 million respectively in the same periods last year. The decrease in the fourth quarter and full year reflects a continuation of the weak margin environment, particularly in the Asian aromatics sector, and unplanned operational events.

Outlook

Looking to 2015, at this point, we anticipate a weaker refining environment due to narrowing crude differentials in the low crude price environment. We expect the financial impact of refinery turnarounds to be at similar levels as 2014 and the petrochemicals margin environment to gradually improve.

The commentary above contains forward-looking statements and should be read in conjunction with the cautionary statement on page 36.


Top of page 7
Downstream
 

Fourth
Third
Fourth
          
quarter
quarter
quarter
      
Year
Year
2013
2014
2014
  
$ million
  
2014
2013
       
Underlying RC profit (loss) before interest and tax - 
      
       
  by region
      
(162)
603
338
  
US
  
1,684
1,123
232
881
875
  
Non-US
  
2,757
2,509
70
1,484
1,213
      
4,441
3,632
       
Non-operating items
      
(20)
(181)
(337)
  
US
  
(339)
(154)
(54)
(371)
(453)
  
Non-US
  
(1,231)
(381)
(74)
(552)
(790)
      
(1,570)
(535)
       
Fair value accounting effects
      
(446)
238
379
  
US
  
914
(211)
90
61
(22)
  
Non-US
  
(47)
33
(356)
299
357
      
867
(178)
       
RC profit (loss) before interest and tax
      
(628)
660
380
  
US
  
2,259
758
268
571
400
  
Non-US
  
1,479
2,161
(360)
1,231
780
      
3,738
2,919
       
Underlying RC profit (loss) before interest and tax - 
      
       
  by business(a)(b)
      
(204)
1,078
925
  
Fuels
  
3,219
2,230
230
336
313
  
Lubricants
  
1,271
1,272
44
70
(25)
  
Petrochemicals
  
(49)
130
70
1,484
1,213
      
4,441
3,632
       
Non-operating items and fair value accounting
      
       
  effects(c)
      
(430)
196
(383)
  
Fuels
  
(389)
(712)
–
(5)
(45)
  
Lubricants
  
136
2
–
(444)
(5)
  
Petrochemicals
  
(450)
(3)
(430)
(253)
(433)
      
(703)
(713)
       
RC profit (loss) before interest and tax(a)(b)
      
(634)
1,274
542
  
Fuels
  
2,830
1,518
230
331
268
  
Lubricants
  
1,407
1,274
44
(374)
(30)
  
Petrochemicals
  
(499)
127
(360)
1,231
780
      
3,738
2,919
               
11.0
15.6
13.0
  
BP average refining marker margin (RMM)* ($/bbl)
  
14.4
15.4
       
Refinery throughputs (mb/d)
      
641
651
657
  
US
  
642
726
742
766
807
  
Europe
  
782
766
312
312
318
  
Rest of World
  
297
299
1,695
1,729
1,782
      
1,721
1,791
95.6
94.8
94.8
  
Refining availability* (%)
  
94.9
95.3
       
Marketing sales of refined products (mb/d)
      
1,179
1,197
1,166
  
US
  
1,166
1,282
1,189
1,240
1,173
  
Europe
  
1,177
1,237
603
522
534
  
Rest of World
  
529
565
2,971
2,959
2,873
      
2,872
3,084
2,504
2,439
2,470
  
Trading/supply sales of refined products
  
2,448
2,485
5,475
5,398
5,343
  
Total sales volumes of refined products
  
5,320
5,569
       
Petrochemicals production (kte)
      
993
932
872
  
US
  
3,844
4,264
952
1,048
937
  
Europe
  
3,851
3,779
1,426
1,676
1,719
  
Rest of World
  
6,319
5,900
3,371
3,656
3,528
      
14,014
13,943

(a)
Segment-level overhead expenses are included in the fuels business result.
(b)
BP’s share of income from petrochemicals at our Gelsenkirchen and Mülheim sites in Germany is reported in the fuels business.
(c)
For Downstream, fair value accounting effects arise solely in the fuels business.


Top of page 8
Rosneft
 

Fourth
Third
Fourth
          
quarter
quarter
quarter
      
Year
Year
2013
2014
2014(a)
  
$ million
  
2014(a)
2013
901
87
390
  
Profit before interest and tax(b)(c)
  
2,076
2,053
157
20
61
  
Inventory holding (gains) losses*
  
24
100
1,058
107
451
  
RC profit before interest and tax
  
2,100
2,153
29
3
19
  
Net charge (credit) for non-operating items*
  
(225)
45
1,087
110
470
  
Underlying RC profit before interest and tax*
  
1,875
2,198

Replacement cost profit before interest and tax for the fourth quarter and full year was $451 million and $2,100 million respectively, compared with $1,058 million and $2,153 million for the same periods in 2013.

The 2014 results included a non-operating charge of $19 million for the fourth quarter and a gain of $225 million for the full year relating to Rosneft’s sale of its interest in the Yugragazpererabotka joint venture, compared with a non-operating charge of $29 million and $45 million for the same periods in 2013.

After adjusting for non-operating items, the underlying replacement cost profit for the fourth quarter and full year was $470 million and $1,875 million respectively, compared with $1,087 million and $2,198 million for the same periods in 2013. Compared with 2013, the results for both periods were affected by an unfavourable duty lag effect, lower oil prices and other items, partially offset by certain foreign exchange effects which had a favourable impact on the result. 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.

On 27 June 2014, Rosneft’s Annual General Meeting of Shareholders approved the distribution of a dividend of 12.85 roubles per share. We received our share of this dividend in July 2014, which amounted to $693 million after the deduction of withholding tax.

See also Other matters on page 35 for information on sanctions.

Fourth
Third
Fourth
          
quarter
quarter
quarter
      
Year
Year
2013
2014
2014(a)
      
2014(a)
2013(d)
       
Production (net of royalties) (BP share)
      
833
817
819
  
Liquids* (mb/d)
  
821
650
884
1,073
1,203
  
Natural gas (mmcf/d)
  
1,084
617
985
1,002
1,027
  
Total hydrocarbons* (mboe/d)
  
1,008
756

(a)
The operational and financial information of the Rosneft segment for the fourth quarter and full year 2014 is based on preliminary operational and financial results of Rosneft for the three months ended 31 December 2014. 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. 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.
(c)
Third quarter and full year 2014 include $25 million of foreign exchange losses arising on the dividend received ($5 million loss in the full year 2013).
(d)
Full year 2013 reflects production for the period 21 March – 31 December averaged over the full year.
   


Top of page 9
Other businesses and corporate
 

Fourth
Third
Fourth
          
quarter
quarter
quarter
      
Year
Year
2013
2014
2014
  
$ million
  
2014
2013
(605)
(432)
(647)
  
Profit (loss) before interest and tax
  
(2,010)
(2,319)
–
–
–
  
Inventory holding (gains) losses*
  
–
–
(605)
(432)
(647)
  
RC profit (loss) before interest and tax
  
(2,010)
(2,319)
(9)
139
527
  
Net charge (credit) for non-operating items*
  
670
421
(614)
(293)
(120)
  
Underlying RC profit (loss) before interest and tax*
  
(1,340)
(1,898)
       
Underlying RC profit (loss) before interest and tax
      
(228)
(102)
(167)
  
US
  
(594)
(800)
(386)
(191)
47
  
Non-US
  
(746)
(1,098)
(614)
(293)
(120)
      
(1,340)
(1,898)
       
Non-operating items
      
(14)
(144)
(219)
  
US
  
(360)
(449)
23
5
(308)
  
Non-US
  
(310)
28
9
(139)
(527)
      
(670)
(421)
       
RC profit (loss) before interest and tax
      
(242)
(246)
(386)
  
US
  
(954)
(1,249)
(363)
(186)
(261)
  
Non-US
  
(1,056)
(1,070)
(605)
(432)
(647)
      
(2,010)
(2,319)

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 $647 million and $2,010 million respectively, compared with $605 million and $2,319 million for the same periods in 2013.

The fourth-quarter result included a net non-operating charge of $527 million, primarily relating to restructuring provisions and impairments, compared with a net credit of $9 million a year ago. For the full year, the net non-operating charge was $670 million, compared with a net charge of $421 million in 2013.

After adjusting for non-operating items, the underlying replacement cost loss before interest and tax for the fourth quarter was $120 million, compared with $614 million for the same period in 2013. For the full year, the underlying replacement cost loss before interest and tax was $1,340 million compared with $1,898 million in 2013. The underlying charge in the fourth quarter and full year 2014 was lower than 2013 resulting from improved business performances and a number of one-off credits.

Biofuels
The net ethanol-equivalent production (which includes ethanol and sugar) for the fourth quarter and full year was 242 million litres and 653 million litres respectively, compared with 140 million litres and 521 million litres for the same periods in 2013.

Wind
Net wind generation capacity*(a) was 1,588MW at 31 December 2014, compared with 1,590MW at 31 December 2013. BP’s net share of wind generation for the fourth quarter and full year was 1,240GWh and 4,617GWh respectively, compared with 1,203GWh and 4,203GWh for the same periods in 2013.

Outlook
In 2015, Other businesses and corporate average quarterly charges, excluding non-operating items, are expected to be around $400 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 36.



Top of page 10
Gulf of Mexico oil spill
 

Financial update

The replacement cost loss before interest and tax for the fourth quarter and full year was $468 million and $781 million respectively, compared with $179 million and $430 million for the same periods last year. The fourth-quarter charge reflects an increased provision for litigation costs, additional business economic loss claims and the ongoing costs of the Gulf Coast Restoration Organization. The cumulative pre-tax charge recognized to date amounts to $43.5 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 all the obligations relating to the incident are subject to significant uncertainty and the ultimate exposure and cost to BP will be dependent on many factors, as discussed under Provisions and contingent liabilities in Note 2 on page 18. These could have a material impact on our consolidated financial position, results and cash flows.


Trust update

As previously disclosed in our third-quarter results announcement, the cumulative charges to be paid from the Trust, and the associated reimbursement asset recognized, had reached $20 billion. Subsequent additional costs are being charged to the income statement as incurred. In the fourth quarter this included a $235-million charge for additional business economic loss claims under the Plaintiffs’ Steering Committee settlement. See Note 2 on page 16 and Legal proceedings on page 33 for further details.

During the fourth quarter, $1.0 billion was paid out of the Deepwater Horizon Oil Spill Trust (the Trust) and qualified settlement funds (QSFs), including $419 million for claims payments, administrative costs of the Deepwater Horizon Court Supervised Settlement Program (DHCSSP) and other resolved items, and $581 million for natural resource damage early restoration projects and assessment. At 31 December 2014, the aggregate cash balances in the Trust and the QSFs amounted to $5.1 billion, including $1.1 billion remaining in the seafood compensation fund which is yet to be distributed, and $0.4 billion held for natural resource damage early restoration projects.


Legal proceedings

The federal district court in New Orleans (the District Court) issued its ruling on Phase 1 in the Trial of Liability, Limitation, Exoneration and Fault Allocation in MDL 2179 (the Trial) on 4 September 2014. It found that BP Exploration & Production Inc. (BPXP), BP America Production Company (BPAPC) and various other parties are each liable under general maritime law for the blowout, explosion and oil spill from the Macondo well. With respect to the United States’ claim against BPXP under the Clean Water Act, the District Court found that the discharge of oil was the result of BPXP’s gross negligence and wilful misconduct and that BPXP is therefore subject to enhanced civil penalties, which may be up to $4,300 per barrel of oil discharged into the Gulf of Mexico.

BPXP and BPAPC have filed a notice of appeal of the Phase 1 ruling to the United States Court of Appeals for the Fifth Circuit (the Fifth Circuit).

The District Court issued its ruling on Phase 2 of the Trial on 15 January 2015, finding that 3.19 million barrels of oil were discharged into the Gulf of Mexico and therefore subject to a Clean Water Act penalty. In addition, the District Court found that BP was not grossly negligent in its source control efforts.

The penalty phase of the Trial began on 20 January 2015 and is scheduled to last three weeks. In this phase, the District Court will determine the amount of civil penalties owed to the United States under the Clean Water Act based on the court’s rulings (or ultimate determinations on appeal) in Phases 1 and 2, and the application of the penalty factors under the Clean Water Act.

With regard to the Plaintiffs’ Steering Committee (PSC) settlement, on 24 September 2014, the District Court denied BP’s motion to order the return of excessive payments made by the DHCSSP under the matching policy in effect before the District Court’s December 2013 ruling requiring a claimant’s revenue to be matched with variable expenses. BP has appealed this decision to the Fifth Circuit.

In March 2014, the Fifth Circuit affirmed the District Court’s ruling that the Economic and Property Damages Settlement Agreement (EPD Settlement Agreement) contained no causation requirement beyond the revenue and related tests set out in an exhibit to that agreement. The District Court dissolved the injunction that had halted the processing and payment of business economic loss claims and instructed the claims administrator to resume the processing and payment of claims. In August 2014, BP petitioned for review by the US Supreme Court of the Fifth Circuit’s decisions relating to compensation of claims for losses with no apparent connection to the Deepwater Horizon spill. On 8 December 2014, the US Supreme Court declined to review BP’s petition. As a result, the final deadline for filing claims under the EPD Settlement Agreement (other than those that fall under the Seafood Compensation Program) is 8 June 2015.

For further details, see Legal proceedings on page 33.


Top of page 11
Financial statements
 

Group income statement

Fourth
Third
Fourth
          
quarter
quarter
quarter
      
Year
Year
2013
2014
2014
  
$ million
  
2014
2013
               
93,717
93,904
73,997
  
Sales and other operating revenues (Note 5)
  
353,568
379,136
101
119
181
  
Earnings from joint ventures – after interest and tax
  
570
447
1,000
272
519
  
Earnings from associates – after interest and tax
  
2,802
2,742
235
117
238
  
Interest and other income
  
843
777
43
355
161
  
Gains on sale of businesses and fixed assets
  
895
13,115
95,096
94,767
75,096
  
Total revenues and other income
  
358,678
396,217
74,960
75,492
60,411
  
Purchases
  
281,907
298,351
7,257
6,562
7,002
  
Production and manufacturing expenses
  
27,375
27,527
1,491
744
412
  
Production and similar taxes (Note 6)
  
2,958
7,047
3,736
3,956
3,866
  
Depreciation, depletion and amortization
  
15,163
13,510
       
Impairment and losses on sale of businesses and
      
474
997
6,768
  
  fixed assets (Note 3)
  
8,965
1,961
2,174
840
1,455
  
Exploration expense
 
3,632
3,441
3,482
3,320
3,066
  
Distribution and administration expenses
  
12,696
13,070
(55)
(113)
(187)
  
Fair value gain on embedded derivatives
  
(430)
(459)
1,577
2,969
(7,697)
  
Profit (loss) before interest and taxation
 
6,412
31,769
255
285
299
  
Finance costs
  
1,148
1,068
       
Net finance expense relating to pensions and other
      
123
73
82
  
  post-retirement benefits
  
314
480
1,199
2,611
(8,078)
  
Profit (loss) before taxation
 
4,950
30,221
101
1,287
(3,705)
  
Taxation
  
947
6,463
1,098
1,324
(4,373)
  
Profit (loss) for the period
  
4,003
23,758
       
Attributable to
      
1,042
1,290
(4,407)
  
  BP shareholders
  
3,780
23,451
56
34
34
  
  Non-controlling interests
  
223
307
1,098
1,324
(4,373)
      
4,003
23,758
               
       
Earnings per share (Note 7)
      
       
Profit (loss) for the period attributable to BP shareholders
      
       
  Per ordinary share (cents)
      
5.57
7.01
(24.18)
  
    Basic
  
20.55
123.87
5.54
6.97
(24.18)
  
    Diluted
  
20.42
123.12
       
  Per ADS (dollars)
     
0.33
0.42
(1.45)
  
    Basic
  
1.23
7.43
0.33
0.42
(1.45)
  
    Diluted
  
1.23
7.39


Top of page 12
Financial statements (continued)
 

Group statement of comprehensive income

Fourth
Third
Fourth
          
quarter
quarter
quarter
      
Year
Year
2013
2014
2014
  
$ million
  
2014
2013
               
1,098
1,324
(4,373)
  
Profit (loss) for the period
  
4,003
23,758
       
Other comprehensive income
     
       
Items that may be reclassified subsequently to profit
      
       
  or loss
      
(177)
(3,434)
(3,496)
  
  Currency translation differences(a)
  
(6,838)
(1,608)
       
  Exchange gains (losses) on translation of foreign
     
       
    operations reclassified to gain or loss on sale of
     
13
(3)
54
  
    business and fixed assets
  
51
22
–
–
–
  
  Available-for-sale investments marked to market
  
(1)
(172)
       
  Available-for-sale investments reclassified to the
      
–
–
–
  
    income statement
  
1
(523)
62
(144)
(111)
  
  Cash flow hedges marked to market(b)
  
(155)
(2,000)
3
(21)
17
  
  Cash flow hedges reclassified to the income statement
  
(73)
4
(8)
(8)
–
  
  Cash flow hedges reclassified to the balance sheet
  
(11)
17
       
  Share of items relating to equity-accounted entities,
      
–
(144)
(2,418)
  
    net of tax(a)
  
(2,584)
(24)
(23)
(13)
151
  
  Income tax relating to items that may be reclassified
  
147
147
(130)
(3,767)
(5,803)
      
(9,463)
(4,137)
       
Items that will not be reclassified to profit or loss
      
       
  Remeasurements of the net pension and other post-
      
2,298
(1,051)
(2,825)
  
    retirement benefit liability or asset
  
(4,590)
4,764
       
  Share of items relating to equity-accounted entities,
      
2
–
(1)
  
    net of tax
  
4
2
(676)
257
856
  
  Income tax relating to items that will not be reclassified
  
1,334
(1,521)
1,624
(794)
(1,970)
      
(3,252)
3,245
1,494
(4,561)
(7,773)
  
Other comprehensive income
 
(12,715)
(892)
2,592
(3,237)
(12,146)
  
Total comprehensive income
  
(8,712)
22,866
       
Attributable to
      
2,533
(3,257)
(12,155)
  
  BP shareholders
  
(8,903)
22,574
59
20
9
  
  Non-controlling interests
  
191
292
2,592
(3,237)
(12,146)
      
(8,712)
22,866

(a)
Fourth quarter and full year 2014 are principally affected by a weakening of the rouble compared to the US dollar.
(b)
Full year 2013 includes $2,061 million loss relating to the contracts to acquire Rosneft shares.


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 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
         
   
BP
    
   
shareholders’
Non-controlling
Total
$ million
  
equity
interests
equity
         
At 1 January 2013
  
118,546
1,206
119,752
         
Total comprehensive income
  
22,574
292
22,866
Dividends
  
(5,441)
(469)
(5,910)
Repurchases of ordinary share capital
  
(6,923)
–
(6,923)
Share-based payments, net of tax
  
473
–
473
Share of equity-accounted entities’ changes in equity, net of tax
  
73
–
73
Transactions involving non-controlling interests
  
–
76
76
At 31 December 2013
  
129,302
1,105
130,407


Top of page 14
Financial statements (continued)
 

Group balance sheet

   
31 December
31 December
$ million
  
2014
2013
Non-current assets
      
Property, plant and equipment
  
130,692
133,690
Goodwill
  
11,868
12,181
Intangible assets
  
20,907
22,039
Investments in joint ventures
  
8,753
9,199
Investments in associates
  
10,403
16,636
Other investments
  
1,228
1,565
Fixed assets
  
183,851
195,310
Loans
  
659
763
Trade and other receivables
  
4,787
5,985
Derivative financial instruments
  
4,442
3,509
Prepayments
  
964
922
Deferred tax assets
  
2,309
985
Defined benefit pension plan surpluses
  
31
1,376
   
197,043
208,850
Current assets
      
Loans
  
333
216
Inventories
  
18,373
29,231
Trade and other receivables
  
31,038
39,831
Derivative financial instruments
  
5,165
2,675
Prepayments
 
1,424
1,388
Current tax receivable
  
837
512
Other investments
  
329
467
Cash and cash equivalents
  
29,763
22,520
   
87,262
96,840
Total assets
  
284,305
305,690
Current liabilities
      
Trade and other payables
  
40,118
47,159
Derivative financial instruments
  
3,689
2,322
Accruals
 
7,102
8,960
Finance debt
  
6,877
7,381
Current tax payable
  
2,011
1,945
Provisions
  
3,818
5,045
   
63,615
72,812
Non-current liabilities
      
Other payables
  
3,587
4,756
Derivative financial instruments
  
3,199
2,225
Accruals
  
861
547
Finance debt
  
45,977
40,811
Deferred tax liabilities
  
13,893
17,439
Provisions
  
29,080
26,915
Defined benefit pension plan and other post-retirement benefit plan deficits
  
11,451
9,778
   
108,048
102,471
Total liabilities
  
171,663
175,283
Net assets
  
112,642
130,407
Equity
      
BP shareholders’ equity
  
111,441
129,302
Non-controlling interests
  
1,201
1,105
   
112,642
130,407


Top of page 15
Financial statements (continued)
 

Condensed group cash flow statement

Fourth
Third
Fourth
          
quarter
quarter
quarter
      
Year
Year
2013
2014
2014
  
$ million
  
2014
2013
       
Operating activities
      
1,199
2,611
(8,078)
  
Profit (loss) before taxation
  
4,950
30,221
       
Adjustments to reconcile profit (loss) before taxation to
     
       
  net cash provided by operating activities
      
       
  Depreciation, depletion and amortization and
     
5,633
4,602
5,215
  
    exploration expenditure written off
  
18,192
16,220
       
  Impairment and (gain) loss on sale of businesses and
      
431
642
6,607
  
    fixed assets
  
8,070
(11,154)
       
  Earnings from equity-accounted entities, less
     
(855)
527
(224)
  
    dividends received
  
(1,461)
(1,798)
       
  Net charge for interest and other finance expense,
      
(40)
114
49
  
    less net interest paid
  
330
323
(77)
153
(58)
  
  Share-based payments
  
379
297
       
  Net operating charge for pensions and other post-
      
       
    retirement benefits, less contributions and benefit
      
(483)
(92)
(664)
  
    payments for unfunded plans
  
(963)
(920)
(84)
705
551
  
  Net charge for provisions, less payments
  
1,119
1,061
       
  Movements in inventories and other current and
      
1,110
1,744
4,842
  
   non-current assets and liabilities(a)
  
6,925
(6,843)
(1,420)
(1,607)
(993)
  
  Income taxes paid
  
(4,787)
(6,307)
5,414
9,399
7,247
  
Net cash provided by operating activities
  
32,754
21,100
       
Investing activities
      
(6,798)
(5,256)
(5,900)
  
Capital expenditure
  
(22,546)
(24,520)
(67)
(3)
(118)
  
Acquisitions, net of cash acquired
  
(131)
(67)
(299)
(78)
(65)
  
Investment in joint ventures
  
(179)
(451)
(39)
(73)
(128)
  
Investment in associates
  
(336)
(4,994)
372
391
224
  
Proceeds from disposal of fixed assets
  
1,820
18,115
       
Proceeds from disposal of businesses, net of
     
5
194
880
  
  cash disposed
  
1,671
3,884
52
9
48
  
Proceeds from loan repayments
  
127
178
(6,774)
(4,816)
(5,059)
  
Net cash provided by (used in) investing activities
  
(19,574)
(7,855)
       
Financing activities
      
(2,265)
(1,623)
(793)
  
Net issue (repurchase) of shares
  
(4,589)
(5,358)
2,467
2,780
2,779
  
Proceeds from long-term financing
  
12,394
8,814
(4,212)
(388)
(2,937)
  
Repayments of long-term financing
  
(6,282)
(5,959)
(268)
(527)
(186)
  
Net increase (decrease) in short-term debt
  
(693)
(2,019)
3
–
9
  
Net increase (decrease) in non-controlling interests
  
9
32
(1,174)
(1,122)
(1,729)
  
Dividends paid
– BP shareholders
  
(5,850)
(5,441)
(213)
(62)
(40)
    
– non-controlling interests
 
(255)
(469)
(5,662)
(942)
(2,897)
  
Net cash provided by (used in) financing activities
  
(5,266)
(10,400)
       
Currency translation differences relating to cash and
      
43
(418)
(257)
  
  cash equivalents
  
(671)
40
(6,979)
3,223
(966)
  
Increase (decrease) in cash and cash equivalents
  
7,243
2,885
29,499
27,506
30,729
  
Cash and cash equivalents at beginning of period
  
22,520
19,635
22,520
30,729
29,763
  
Cash and cash equivalents at end of period
  
29,763
22,520

(a)
Includes

482
1,560
4,904
  
Inventory holding losses
  
6,157
190
(55)
(113)
(187)
  
Fair value gain on embedded derivatives
  
(430)
(459)
(33)
(846)
3
  
Movements related to the Gulf of Mexico oil spill response
  
(1,454)
(2,099)

 
Inventory holding losses and fair value gains on embedded derivatives are also included within profit (loss) before taxation. See Note 2 for further information on the cash flow impacts of the Gulf of Mexico oil spill.


 
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 2014 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 2013 included in BP Annual Report and Form 20-F 2013.

After making enquiries, the directors have a reasonable expectation that the group has adequate resources to continue in operational existence for the foreseeable future. Accordingly, the directors continue to adopt the going concern basis of accounting in preparing the financial statements. The directors draw attention to Note 2 on pages 16-22 which describes the uncertainties surrounding the amounts and timings of liabilities arising from the Gulf of Mexico oil spill. It is likely that the independent auditor’s report in BP Annual Report and Form 20-F 2014 will contain an emphasis of matter paragraph in relation to this matter.

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; however, 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 2014, which do not differ significantly from those used in BP Annual Report and Form 20-F 2013.

In BP Annual Report and Form 20-F 2013 we disclosed a significant estimate or judgement in relation to the provision for penalties under the US Clean Water Act arising from the Gulf of Mexico oil spill, which had been estimated based on the assumption that BP did not act with gross negligence or engage in wilful misconduct. However, in September 2014 the district court ruled that the discharge of oil was the result of BP’s gross negligence and wilful misconduct. No adjustment has been made to the provision and a contingent liability has been disclosed in relation to the potential for a higher penalty due to this ruling. See Note 2 for further information.

In BP Annual Report and Form 20-F 2013 we disclosed a significant estimate or judgement in relation to exploration and appraisal expenditure which is capitalized and is subject to regular technical, commercial and management review on at least an annual basis to confirm the continued intent to develop, or otherwise extract value from, the discovery. Under IFRS 6 ‘Exploration for and Evaluation of Mineral Resources’, one of the facts and circumstances which indicates that an entity should test such assets for impairment is that the period for which the entity has a right to explore in the specific area has expired during the period or will expire in the near future, and is not expected to be renewed.

BP has leases in the Gulf of Mexico making up a prospect, some with terms which were scheduled to expire at the end of 2013 and some with terms which were scheduled to expire at the end of 2014. A significant proportion of our capitalized exploration and appraisal costs in the Gulf of Mexico relate to this prospect. This prospect requires the development of subsea technology to ensure that the hydrocarbons can be extracted safely. BP is in negotiation with the US Bureau of Safety and Environmental Enforcement in relation to seeking extension of these leases so that the discovered hydrocarbons can be developed. BP remains committed to developing this prospect and expects that the leases will be renewed and, therefore, continues to carry the capitalized costs on its balance sheet. See also Notes 10 and 16 in BP Annual Report and Form 20-F 2013 – Financial statements.


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 2013 – Financial statements – Note 2 and Legal proceedings on page 257 and on page 33 of this report.

The group income statement includes a pre-tax charge of $477 million for the fourth quarter and $819 million for the full year in relation to the Gulf of Mexico oil spill. The fourth-quarter charge reflects an increased provision for litigation costs, additional business economic loss claims and the ongoing costs of the Gulf Coast Restoration Organization. The cumulative pre-tax income statement charge since the incident, in April 2010, amounts to $43,495 million.


Top of page 17
Financial statements (continued)
 

Notes

2.       Gulf of Mexico oil spill (continued)

The cumulative income statement charge does not include amounts for obligations that BP currently considers are not possible to measure reliably. For further information, including developments in relation to the interpretation of business economic loss claims under the Plaintiffs’ Steering Committee (PSC) settlement, see Provisions below.

The total amounts that will ultimately be paid by BP in relation to all the obligations relating to the incident are subject to significant uncertainty and the ultimate exposure and cost to BP 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 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
 
2013
2014
2014
  
$ million
  
2014
2013
         
Income statement
      
 
179
33
468
  
Production and manufacturing expenses
  
781
430
 
(179)
(33)
(468)
  
Profit (loss) before interest and taxation
  
(781)
(430)
 
10
10
9
  
Finance costs
  
38
39
 
(189)
(43)
(477)
  
Profit (loss) before taxation
  
(819)
(469)
 
80
45
163
  
Taxation
  
262
73
 
(109)
2
(314)
  
Profit (loss) for the period
  
(557)
(396)


 
$ million
  
31 December 2014
31 December 2013
 
Balance sheet
      
 
Current assets
      
 
  Trade and other receivables
  
1,154
2,457
 
Current liabilities
      
 
  Trade and other payables
  
(655)
(1,030)
 
  Provisions
  
(1,702)
(2,951)
 
Net current assets (liabilities)
  
(1,203)
(1,524)
 
Non-current assets
      
 
  Other receivables
  
2,701
2,442
 
Non-current liabilities
     
 
  Other payables
  
(2,412)
(2,986)
 
  Accruals
  
(169)
–
 
  Provisions
  
(6,903)
(6,395)
 
  Deferred tax
 
1,723
2,748
 
Net non-current assets (liabilities)
  
(5,060)
(4,191)
 
Net assets (liabilities)
  
(6,263)
(5,715)


 
Fourth
Third
Fourth
          
 
quarter
quarter
quarter
      
Year
Year
 
2013
2014
2014
  
$ million
  
2014
2013
         
Cash flow statement - Operating activities
      
 
(189)
(43)
(477)
  
Profit (loss) before taxation
  
(819)
(469)
         
Adjustments to reconcile profit (loss) before
      
         
  taxation to net cash provided by
      
         
  operating activities
      
         
Net charge for interest and other finance
      
 
10
10
9
  
  expense, less net interest paid
  
38
39
 
11
586
334
  
Net charge for provisions, less payments
  
939
1,129
         
Movements in inventories and other current
      
 
(33)
(846)
3
  
  and non-current assets and liabilities
  
(1,454)
(2,099)
 
(201)
(293)
(131)
  
Pre-tax cash flows
  
(1,296)
(1,400)


Top of page 18
Financial statements (continued)
 

Notes

2.       Gulf of Mexico oil spill (continued)

Net cash from operating activities relating to the Gulf of Mexico oil spill, on a post-tax basis, amounted to an inflow of $304 million and outflow of $9 million in the fourth quarter and full year of 2014 respectively. For the same periods in 2013, the amounts were an inflow of $120 million and an outflow of $73 million respectively.

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.

The table below shows movements in the reimbursement asset during the period to 31 December 2014. At 31 December 2014, $3,855 million of the provisions and payables are eligible to be paid from the Trust. The reimbursement asset is recorded within other receivables on the balance sheet apportioned between current and non-current elements.

       
Fourth
  
       
quarter
Year
 
$ million
  
2014
2014
 
Opening balance
  
4,855
4,899
 
Net increase in provision for items covered by the trust fund
  
–
662
 
Amounts paid directly by the trust fund
  
(1,000)
(1,706)
 
At 31 December 2014
  
3,855
3,855
 
Of which
– current
  
1,154
1,154
   
– non-current
  
2,701
2,701

During the third quarter, cumulative charges to be paid by the Trust reached $20 billion. Subsequent additional costs, over and above those provided within the $20 billion, are being expensed to the income statement as incurred.

As at 31 December 2014, the aggregate cash balances in the Trust and the associated qualifying settlement funds amounted to $5.1 billion, including $1.1 billion remaining in the seafood compensation fund which has yet to be distributed and $0.4 billion held for natural resource damage early restoration. When the cash balances in the trust fund are exhausted, payments in respect of legitimate claims and other costs will be made directly by BP.

(b) Provisions and contingent liabilities

BP has recorded certain provisions and disclosed certain contingent liabilities as a consequence of the Gulf of Mexico oil spill. These are described below and in more detail in BP Annual Report and Form 20-F 2013 – 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 tables below.

         
Litigation
Clean
 
         
and
Water Act
  
 
$ million 
  
Environmental
claims
penalties
Total
 
At 1 October 2014
  
1,740
4,020
3,510
9,270
 
Net increase in provision
  
–
435
–
435
 
Change in discount rate
  
2
–
–
2
 
Unwinding of discount
  
1
–
–
1
 
Utilization
– paid by BP
  
(21)
(82)
–
(103)
 
               
– paid by the trust fund
  
(581)
(419)
–
(1,000)
 
At 31 December 2014
  
1,141
3,954
3,510
8,605
 
Of which
– current
  
528
1,174
–
1,702
 
               
– non-current
  
613
2,780
3,510
6,903


Top of page 19
Financial statements (continued)
 

Notes

2.       Gulf of Mexico oil spill (continued)

         
Litigation
Clean
  
         
and
Water Act
  
       
Environmental
claims
penalties
Total
 
$ million 
          
 
At 1 January 2014
  
1,679
4,157
3,510
9,346
 
Net increase in provision
 
190
1,137
–
1,327
 
Change in discount rate
  
2
–
–
2
 
Unwinding of discount
  
1
–
–
1
 
Utilization
– paid by BP
  
(83)
(307)
–
(390)
   
– paid by the trust fund
  
(648)
(1,033)
–
(1,681)
 
At 31 December 2014
  
1,141
3,954
3,510
8,605

Environmental
The environmental provision includes amounts for BP’s commitment to fund the Gulf of Mexico Research Initiative, estimated natural resource damage assessment costs and early natural resource damage restoration projects under the $1-billion framework agreement with natural resource trustees for the US and five Gulf coast states. In October 2014, phase three of the natural resource damage early restoration projects was formally approved (comprising $627 million of approved project spend, of which $563 million has been paid) under the framework agreement. Until the size, location and duration of the impact is assessed, it is not possible to estimate reliably the amounts or timing of any further natural resource damages claims, therefore no additional amounts have been provided for these items and they are disclosed as a contingent liability.

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 claims by state and local government entities for removal costs, damage to real or personal property, loss of government revenue and increased public services costs under the Oil Pollution Act of 1990 and other legislation (State and Local Claims), except as described under Contingent liabilities below. Claims administration costs, legal and litigation costs have also been provided for.

BP has provided for its best estimate of the cost associated with the PSC settlement agreements with the exception of the cost of business economic loss claims, except where an eligibility notice has been issued and is not subject to appeal by BP within the claims facility. As disclosed in BP Annual Report and Form 20-F 2013, as part of its monitoring of payments made by the Deepwater Horizon Court Supervised Settlement Program (DHCSSP), BP identified multiple business economic loss claim determinations that appeared to result from an interpretation of the Economic and Property Damages Settlement Agreement (EPD Settlement Agreement) by the claims administrator that BP believes was incorrect. See Legal proceedings on pages 257-265 of BP Annual Report and Form 20-F 2013 and page 33 of this report for further details on the settlements with the PSC and related matters.

Management believes that no reliable estimate can currently be made of any business economic loss claims (i) not yet received; (ii) received, but not yet processed; or (iii) 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 inability to estimate reliably such claims is due to uncertainty regarding both the volume of such claims and the average value per claim.  

In respect of uncertainty regarding the volume of claims, in December 2014, the US Supreme Court declined to hear BP’s appeal of the district court ruling that the EPD Settlement Agreement contained no causation requirement beyond the revenue and related tests set forth in that agreement. This resolution, however, does not reduce uncertainty regarding the volume of claims in the short-term, since it is possible that additional claims will be made. In addition, a claims submission deadline of 8 June 2015 has now been set, which may lead to an increase in the rate of claims received until the deadline, compounding management’s inability to estimate the total volume of claims that will be made.

In respect of uncertainty regarding the average value per claim, a small proportion of the filed claims have been determined under the revised policy for the matching of revenue and expenses for business economic loss claims (introduced in May 2014) and disputes, disagreements and uncertainties regarding the proper application of the revised policy to particular claims and categories of claims continue to arise as the claims administrator has begun applying the revised policy.  Furthermore, there have been no, or only a small number of, claim determinations made under some of the specialised frameworks that have been put in place for particular industries and so determinations to date may not be representative of the total population of claims. In addition, due to a data secrecy order, detailed data about claims that have not yet been determined is not currently available to BP and so it is not possible to review claim demographics or identify potential populations for each category of claim.  


Top of page 20
Financial statements (continued)
 

Notes

2.       Gulf of Mexico oil spill (continued)

There is therefore very little data 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 therefore cannot estimate future trends of the number and proportion of claims that will be determined to be eligible, nor can we 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 is $9.9 billion. The DHCSSP has issued eligibility notices, most of which are disputed by BP, in respect of business economic loss claims of approximately $400 million which have not been provided for. The majority of these claims are being re-assessed using the new matching policy. Furthermore, a significant number of business economic loss claims have been received but have not yet been processed, and further claims are likely to be received. The total cost of the PSC settlement is likely to be significantly higher than the amount recognized to date of $9.9 billion because the current estimate does not reflect business economic loss claims not yet received, or received but 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 provision recognized for litigation and claims includes an estimate for State and Local Claims. Although the provision recognized is BP’s current reliable best estimate of the amount required to settle these obligations, significant uncertainty exists in relation to the outcome of any litigation proceedings and the amount of claims that will become payable by BP. See Legal proceedings on pages 257-265 of BP Annual Report and Form 20-F 2013 and Contingent liabilities below for further details.

Significant uncertainties exist in relation to the amount of claims that are to be paid and will become payable, including claims payable under the DHCSSP and State and Local Claims. There is significant uncertainty in relation to the amounts that ultimately will be paid in relation to current claims, and the number, type and amounts payable for claims not yet reported as described above and in Legal proceedings on page 33 and the outcomes of any further litigation including in relation to potential opt-outs from the PSC settlement or otherwise. There is also uncertainty as to the cost of administering the claims process under the DHCSSP.

Clean Water Act penalties
A provision of $3,510 million was recognized in 2010 for estimated civil penalties under Section 311 of the Clean Water Act. The Clean Water Act penalty is calculated by multiplying the number of barrels of oil spilled by a penalty rate per barrel. The number of barrels of oil spilled was determined by using the mid-point in the range of estimates (3.2 million barrels). A penalty rate of $1,100 per barrel was applied, the statutory maximum penalty in the absence of gross negligence or wilful misconduct.

In January 2015, the district court issued its decision in the Phase 2 trial that 3.19 million barrels of oil were discharged into the Gulf of Mexico and therefore subject to a Clean Water Act penalty. This amount is consistent with the number of barrels BP has used to calculate the provision. In addition, the district court found that BP was not grossly negligent in its source control efforts.

In September 2014, the district court issued its decision in the Phase 1 trial that the discharge of oil was the result of the gross negligence and wilful misconduct of BP Exploration & Production Inc. (BPXP) and that BPXP is therefore subject to enhanced civil penalties. The statutory maximum penalty is up to $4,300 per barrel of oil discharged where gross negligence or wilful misconduct is proven. BP does not believe that the evidence at trial supports a finding of gross negligence and wilful misconduct and in December 2014 filed notice of appeal of the Phase 1 ruling.

BP continues to believe that a provision of $3,510 million represents a reliable estimate of the amount of the liability if the appeal is successful and this provision, calculated on the basis of the previous assumptions, has been maintained in the accounts.

If BP is unsuccessful in its appeal, and the ruling of gross negligence and wilful misconduct is upheld, the maximum penalty that could be imposed is up to $4,300 per barrel. Based upon this penalty rate and the district court’s ruling on the number of barrels spilled, the maximum penalty could be up to $13.7 billion.

However, in assessing the amount of the penalty, the court is directed to consider the following statutory penalty factors: ‘the seriousness of the violation or violations, the economic benefit to the violator, if any, resulting from the violation, the degree of culpability involved, any other penalty for the same incident, any history of prior violations, the nature, extent, and degree of success of any efforts of the violator to minimize or mitigate the effects of the discharge, the economic impact of the penalty on the violator, and any other matters as justice may require’. The court has wide discretion in deciding how to apply these factors to determine the penalty and what weighting to ascribe to different factors. BP is therefore unable to ascribe probabilities to possible outcomes within the range of potential penalties and cannot determine a reliable estimate for any additional penalty which might apply should the gross negligence finding be upheld. The trial phase to determine the amount of the Clean Water Act penalty commenced on 20 January 2015.


Top of page 21
Financial statements (continued)
 

Notes

2.       Gulf of Mexico oil spill (continued)

The amount that may become payable by BP is subject to a very high level of uncertainty since it will depend on the outcome of BP’s appeal as well as what is determined by the district court with respect to the application of statutory penalty factors as noted above. The court has wide discretion in the application of statutory penalty factors. The timing of any payment is also uncertain.

Given the significant uncertainty, the very wide range of possible outcomes if BP is unsuccessful in its appeal of the September ruling, and the inability to ascribe probabilities to possible outcomes within the range, management is not able to estimate reliably any further liability for the Clean Water Act penalty arising in the event that BP is not successful in its appeal. A contingent liability is therefore disclosed. See Contingent liabilities below for further information.

See BP Annual Report and Form 20-F 2013 – Financial statements – Note 2 for further details and Legal proceedings on pages 257-265 and on page 33 of this report.

Provision movements and analysis of income statement charge
A net increase in provisions of $435 million for the fourth quarter ($1,327 million for the full year) arises due to increases in the provision for litigation costs and the provision for business economic loss claims. The increase in provisions for the year also includes increases in estimated claims administration and legal costs.

Expenses incurred that are eligible to be paid from the Trust exceeded the Trust headroom by $260 million during the year.

     
Fourth
  
Cumulative
     
quarter
Year
since the
 
$ million 
  
2014
2014
incident
 
Environmental costs
  
2
192
3,223
 
Spill response costs
  
–
–
14,304
 
Litigation and claims costs
  
435
1,137
26,780
 
Clean Water Act penalties – amount provided
  
–
–
3,510
 
Other costs charged directly to the income statement
  
31
114
1,257
 
Recoveries credited to the income statement
  
–
–
(5,681)
 
Charge (credit) related to the trust fund
  
–
(662)
(137)
 
Other costs of the trust fund
  
–
–
8
 
Loss before interest and taxation
  
468
781
43,264
 
Finance costs
– related to the trust funds
  
–
–
137
   
– not related to the trust funds
  
9
38
94
 
Loss before taxation
  
477
819
43,495

Further information on provisions is provided in BP Annual Report and Form 20-F 2013 – Financial statements – Note 2.

Contingent liabilities

BP currently considers that it is not possible to measure reliably other obligations arising from the incident, namely:

·  
Any obligation in relation to natural resource damages claims or associated legal costs (except for the estimated costs of the assessment phase and the costs relating to early restoration agreements referred to above).

·  
Claims asserted in civil litigation, including any further litigation through excluded parties from the PSC settlement, including as set out in Legal proceedings on pages 257-265 of BP Annual Report and Form 20-F 2013 and page 33 of this report.

·  
The cost of business economic loss claims under the PSC settlement not yet received, or received but 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 further obligation that may arise from State and Local Claims.

·  
Any obligation that may arise from securities-related litigation.

·  
Any obligation in relation to any further liability for the Clean Water Act penalty arising in the event that BP is not successful in its appeal of the Phase 1 ruling.

·  
Any obligation in relation to other potential private or governmental litigation, fines or penalties (except for those items provided for as described above under Provisions).


Top of page 22
Financial statements (continued)
 

Notes

2.       Gulf of Mexico oil spill (continued)

It is not practicable to estimate the magnitude or possible timing of payment of these contingent liabilities.

The magnitude and timing of all possible obligations in relation to the Gulf of Mexico oil spill continue to be subject to a very high degree of uncertainty.

See also BP Annual Report and Form 20-F 2013 – Financial statements – Note 2.


3.        Impairment of fixed assets

Included within the line item in the income statement for Impairment and losses on sale of businesses and fixed assets is a net impairment loss for the fourth quarter and full year of $6,491 million and $8,216 million respectively. The fourth-quarter net impairment loss comprised $5,663 million in Upstream, $517 million in Downstream, and $311 million in Other businesses and corporate. The full-year net impairment loss comprised $6,635 million in Upstream, $1,264 million in Downstream, and $317 million in Other businesses and corporate.

The main elements of Upstream impairment losses were in the North Sea (fourth quarter 2014 $4,518 million, and full year 2014 $4,774 million) and in Angola (fourth quarter and full year 2014 $968 million).

The impairments arose for various reasons, including the impact of a lower price environment in the near term, technical reserves revisions, and increases in expected decommissioning cost estimates.


4.        Analysis of replacement cost profit before interest and tax and reconciliation to
           profit before taxation

 
Fourth
Third
Fourth
          
 
quarter
quarter
quarter
      
Year
Year
 
2013
2014
2014
  
$ million
  
2014
2013
 
2,537
3,311
(3,085)
  
Upstream
  
8,934
16,657
 
(360)
1,231
780
  
Downstream
  
3,738
2,919
 
–
–
–
  
TNK-BP(a)
  
–
12,500
 
1,058
107
451
  
Rosneft(b)
  
2,100
2,153
 
(605)
(432)
(647)
  
Other businesses and corporate
  
(2,010)
(2,319)
 
2,630
4,217
(2,501)
      
12,762
31,910
 
(179)
(33)
(468)
  
Gulf of Mexico oil spill response
  
(781)
(430)
 
(240)
370
257
  
Consolidation adjustment – UPII*
  
641
579
 
2,211
4,554
(2,712)
  
RC profit (loss) before interest and tax
  
12,622
32,059
         
Inventory holding gains (losses)*
      
 
3
1
(80)
  
  Upstream
  
(86)
4
 
(480)
(1,566)
(4,844)
  
  Downstream
  
(6,100)
(194)
 
(157)
(20)
(61)
  
  Rosneft (net of tax)
  
(24)
(100)
 
1,577
2,969
(7,697)
  
Profit (loss) before interest and tax
  
6,412
31,769
 
255
285
299
  
Finance costs
  
1,148
1,068
         
Net finance expense relating to pensions
      
 
123
73
82
  
  and other post-retirement benefits
  
314
480
 
1,199
2,611
(8,078)
  
Profit (loss) before taxation
  
4,950
30,221
                 
         
RC profit (loss) before interest and tax*(c)
      
 
(299)
1,800
683
  
US
  
5,251
3,114
 
2,510
2,754
(3,395)
  
Non-US
  
7,371
28,945
 
2,211
4,554
(2,712)
      
12,622
32,059

(a)
BP ceased equity accounting for its share of TNK-BP’s earnings from 22 October 2012. Full year 2013 includes the gain arising on the disposal of BP’s interest in TNK-BP.
(b)
BP’s investment in Rosneft is accounted under the equity method from 21 March 2013. See Rosneft on page 8 for further information.
(c)
A minor amendment has been made to the analysis by region for the comparative periods in 2013.


Top of page 23
 
Financial statements (continued)
 

Notes

5.        Sales and other operating revenues

 
Fourth
Third
Fourth
          
 
quarter
quarter
quarter
      
Year
Year
 
2013
2014
2014
  
$ million
  
2014
2013
         
By segment
      
 
18,928
15,879
15,800
  
Upstream
  
65,424
70,374
 
85,582
87,068
65,249
  
Downstream
  
323,486
351,195
 
517
530
616
  
Other businesses and corporate
  
1,989
1,805
 
105,027
103,477
81,665
      
390,899
423,374
                 
         
Less: sales and other operating revenues
      
         
  between segments
      
 
10,838
9,427
8,270
  
Upstream
  
36,643
42,327
 
256
(73)
(814)
  
Downstream
  
(173)
1,045
 
216
219
212
  
Other businesses and corporate
  
861
866
 
11,310
9,573
7,668
      
37,331
44,238
                 
         
Third party sales and other operating revenues
      
 
8,090
6,452
7,530
  
Upstream
  
28,781
28,047
 
85,326
87,141
66,063
  
Downstream
  
323,659
350,150
 
301
311
404
  
Other businesses and corporate
  
1,128
939
         
Total third party sales and other operating
      
 
93,717
93,904
73,997
  
  revenues
  
353,568
379,136
                 
         
By geographical area(a)
      
 
32,267
34,678
27,300
  
US
  
132,310
137,539
 
70,139
66,402
51,933
  
Non-US
  
251,943
280,317
 
102,406
101,080
79,233
      
384,253
417,856
         
Less: sales and other operating revenues
      
 
8,689
7,176
5,236
  
  between areas
  
30,685
38,720
 
93,717
93,904
73,997
      
353,568
379,136

(a)
A minor amendment has been made to the analysis by region for the comparative periods in 2013.


 
6.     Production and similar taxes

 
Fourth
Third
Fourth
          
 
quarter
quarter
quarter
      
Year
Year
 
2013
2014
2014
  
$ million
  
2014
2013
 
299
140
56
  
US
  
690
1,112
 
1,192
604
356
  
Non-US
  
2,268
5,935
 
1,491
744
412
      
2,958
7,047


Top of page 24
Financial statements (continued)
 

Notes

 
7.        Earnings per share and shares in issue

Basic earnings per ordinary share (EpS) amounts are calculated by dividing the profit (loss) for the period attributable to ordinary shareholders by the weighted average number of ordinary shares outstanding during the period. During the quarter the company repurchased 105 million ordinary shares at a cost of $715 million as part of the share buybacks as announced on 29 April 2014. The number of shares in issue is reduced when shares are repurchased, but is not reduced in respect of the period-end commitment to repurchase shares subsequent to the end of 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.

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. If the inclusion of potentially issuable shares would decrease the loss per share, the potentially issuable shares are excluded from the diluted EpS calculation.

 
Fourth
Third
Fourth
          
 
quarter
quarter
quarter
      
Year
Year
 
2013
2014
2014
  
$ million
  
2014
2013
         
Results for the period
      
         
Profit (loss) for the period attributable to
     
 
1,042
1,290
(4,407)
  
  BP shareholders
  
3,780
23,451
 
1
–
1
  
Less: preference dividend
  
2
2
         
Profit (loss) attributable to BP ordinary
     
 
1,041
1,290
(4,408)
  
  shareholders
  
3,778
23,449
                 
         
Number of shares (thousand)(a)
      
         
Basic weighted average number of
     
 
18,689,386
18,390,006
18,232,147
  
  shares outstanding
  
18,385,458
18,931,021
 
3,114,897
3,065,001
3,038,691
  
ADS equivalent
  
3,064,243
3,155,170
                 
         
Weighted average number of shares
     
         
  outstanding used to calculate diluted
      
 
18,802,026
18,499,505
18,332,091
  
  earnings per share
  
18,497,294
19,046,173
 
3,133,671
3,083,250
3,055,348
  
ADS equivalent
  
3,082,882
3,174,362
                 
 
18,611,489
18,311,461
18,199,882
  
Shares in issue at period-end
  
18,199,882
18,611,489
 
3,101,914
3,051,910
3,033,313
  
ADS equivalent
  
3,033,313
3,101,914

(a)
Excludes treasury shares and the shares held by the Employee Share Ownership Plans (ESOPs) and includes certain shares that will be issued in the future under employee share-based payment plans.


Top of page 25
Financial statements (continued)
 

Notes

 
8.        Dividends

Dividends payable

BP today announced a dividend of 10.00 cents per ordinary share expected to be paid in March. The corresponding amount in sterling will be announced on 16 March 2015, calculated based on the average of the market exchange rates for the four dealing days commencing on 10 March 2015. Holders of American Depositary Shares (ADSs) will receive $0.600 per ADS. The dividend is due to be paid on 27 March 2015 to shareholders and ADS holders on the register on 13 February 2015. 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
 
2013
2014
2014
      
2014
2013
         
Dividends paid per ordinary share
      
 
9.500
9.750
10.000
  
  cents
  
39.000
36.500
 
5.801
5.959
6.377
  
  pence
  
23.850
23.399
 
57.00
58.50
60.00
  
Dividends paid per ADS (cents)
  
234.00
219.00
         
Scrip dividends
     
 
78.1
85.2
13.7
  
Number of shares issued (millions)
  
165.6
202.1
 
602
672
95
  
Value of shares issued ($ million)
  
1,318
1,470


 
9.       Net debt*

Net debt ratio*

 
Fourth
Third
Fourth
          
 
quarter
quarter
quarter
      
Year
Year
 
2013
2014
2014
  
$ million
  
2014
2013
 
48,192
53,610
52,854
  
Gross debt
  
52,854
48,192
         
Fair value asset of hedges related
      
 
(477)
(434)
(445)
  
  to finance debt
  
(445)
(477)
 
47,715
53,176
52,409
      
52,409
47,715
 
22,520
30,729
29,763
  
Less: cash and cash equivalents
  
29,763
22,520
 
25,195
22,447
22,646
  
Net debt
  
22,646
25,195
 
130,407
126,894
112,642
  
Equity
  
112,642
130,407
 
16.2%
15.0%
16.7%
  
Net debt ratio
  
16.7%
16.2%


Top of page 26
Financial statements (continued)
 

Notes

 
9.       Net debt* (continued)

Analysis of changes in net debt

 
Fourth
Third
Fourth
          
 
quarter
quarter
quarter
      
Year
Year
 
2013
2014
2014
  
$ million
  
2014
2013
         
Opening balance
      
 
50,284
52,906
53,610
  
Finance debt
  
48,192
48,800
         
Fair value asset of hedges
     
 
(734)
(1,001)
(434)
  
  related to finance debt
  
(477)
(1,700)
 
29,499
27,506
30,729
  
Less: cash and cash equivalents
  
22,520
19,635
 
20,051
24,399
22,447
  
Opening net debt
  
25,195
27,465
         
Closing balance
      
 
48,192
53,610
52,854
  
Finance debt
  
52,854
48,192
         
Fair value asset of hedges
     
 
(477)
(434)
(445)
  
  related to finance debt
  
(445)
(477)
 
22,520
30,729
29,763
  
Less: cash and cash equivalents
  
29,763
22,520
 
25,195
22,447
22,646
  
Closing net debt
  
22,646
25,195
 
(5,144)
1,952
(199)
  
Decrease (increase) in net debt
  
2,549
2,270
         
Movement in cash and cash equivalents
      
 
(7,022)
3,641
(709)
  
  (excluding exchange adjustments)
  
7,914
2,845
         
Net cash outflow (inflow) from financing
      
 
2,013
(1,865)
344
  
  (excluding share capital and dividends)
  
(5,419)
(836)
         
Movement in finance debt relating to
      
 
–
–
–
  
  investing activities
  
–
632
 
(69)
(38)
(3)
  
Other movements
  
(435)
(192)
         
Movement in net debt before
     
 
(5,078)
1,738
(368)
  
  exchange effects
  
2,060
2,449
 
(66)
214
169
  
Exchange adjustments
  
489
(179)
 
(5,144)
1,952
(199)
  
Decrease (increase) in net debt
  
2,549
2,270


 
10.     Inventory valuation

A provision of $2,879 million was held at 31 December 2014 ($1,006 million at 30 September 2014 and $322 million at 31 December 2013) to write inventories down to their net realizable value. The net movement charged to the income statement during the fourth quarter 2014 was $1,924 million (third quarter 2014 was a charge of $554 million and fourth quarter 2013 was a charge of $313 million).


 
11.    Statutory accounts

The financial information shown in this publication, which was approved by the Board of Directors on 2 February 2015, 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 2014 in early March 2015 and delivered to the Registrar of Companies in due course. BP Annual Report and Form 20-F 2013 has been filed with the Registrar of Companies in England and Wales. The report of the auditor on those accounts was unqualified and contained an emphasis of matter paragraph relating to significant uncertainty over provisions and contingencies related to the Gulf of Mexico oil spill. The report of the auditor on those accounts did not contain a statement under section 498(2) or section 498(3) of the UK Companies Act 2006.


Top of page 27
Additional information
 

Capital expenditure and acquisitions

Fourth
Third
Fourth
          
quarter
quarter
quarter
      
Year
Year
2013
2014
2014
  
$ million
  
2014
2013
       
By segment
      
       
Upstream(a)
      
1,726
1,510
1,560
  
US
  
6,203
6,410
3,752
2,973
3,546
  
Non-US(b)
  
13,569
12,705
5,478
4,483
5,106
      
19,772
19,115
       
Downstream
      
360
239
265
  
US
  
942
2,535
921
458
984
  
Non-US
  
2,164
1,971
1,281
697
1,249
      
3,106
4,506
       
Rosneft
      
–
–
–
  
Non-US(c)
  
–
11,941
–
–
–
      
–
11,941
       
Other businesses and corporate
      
85
28
38
  
US
  
82
231
375
141
341
  
Non-US
  
821
819
460
169
379
      
903
1,050
7,219
5,349
6,734
      
23,781
36,612
       
By geographical area(a)
      
2,171
1,777
1,863
  
US
  
7,227
9,176
5,048
3,572
4,871
  
Non-US(b)(c)
  
16,554
27,436
7,219
5,349
6,734
      
23,781
36,612
       
Included above:
      
71
24
150
  
Acquisitions and asset exchanges
  
420
71
–
–
27
  
Other inorganic capital expenditure(b)(c)
  
469
11,941

(a)
A minor amendment has been made to the analysis by region for the comparative periods in 2013.
(b)
Fourth quarter and full year 2014 include $27 million and $469 million respectively relating to the purchase of additional 3.3% equity in Shah Deniz, Azerbaijan and the South Caucasus Pipeline.
(c)
The full year 2013 includes $11,941 million relating to our investment in Rosneft.

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
2013
2014
2014
  
$ million
  
2014
2013
       
Upstream
      
       
Impairment and gain (loss) on sale of businesses and
      
(391)
(248)
(5,685)
  
  fixed assets(a)
  
(6,576)
(802)
1
(59)
(1)
  
Environmental and other provisions
  
(60)
(20)
–
–
(100)
  
Restructuring, integration and rationalization costs
  
(100)
–
55
113
187
  
Fair value gain (loss) on embedded derivatives
  
430
459
(866)
(307)
42
  
Other(b)
  
8
(1,001)
(1,201)
(501)
(5,557)
      
(6,298)
(1,364)
       
Downstream
      
       
Impairment and gain (loss) on sale of businesses and
      
(61)
(400)
(614)
  
  fixed assets(a)
  
(1,190)
(348)
7
(128)
(5)
  
Environmental and other provisions
  
(133)
(134)
(11)
(5)
(158)
  
Restructuring, integration and rationalization costs
  
(165)
(15)
–
–
–
  
Fair value gain (loss) on embedded derivatives
  
–
–
(9)
(19)
(13)
  
Other
  
(82)
(38)
(74)
(552)
(790)
      
(1,570)
(535)
       
TNK-BP
      
       
Impairment and gain (loss) on sale of businesses and
      
–
–
–
  
  fixed assets
  
–
12,500
–
–
–
  
Environmental and other provisions
  
–
–
–
–
–
  
Restructuring, integration and rationalization costs
  
–
–
–
–
–
  
Fair value gain (loss) on embedded derivatives
  
–
–
–
–
–
  
Other
  
–
–
–
–
–
      
–
12,500
       
Rosneft
      
       
Impairment and gain (loss) on sale of businesses and
      
(19)
(3)
(19)
  
  fixed assets
  
225
(35)
(10)
–
–
  
Environmental and other provisions
  
–
(10)
–
–
–
  
Restructuring, integration and rationalization costs
  
–
–
–
–
–
  
Fair value gain (loss) on embedded derivatives
  
–
–
–
–
–
  
Other
  
–
–
(29)
(3)
(19)
      
225
(45)
       
Other businesses and corporate
      
       
Impairment and gain (loss) on sale of businesses and
      
21
6
(308)
  
  fixed assets(a)
  
(304)
(196)
(19)
(145)
(35)
  
Environmental and other provisions
  
(180)
(241)
3
–
(175)
  
Restructuring, integration and rationalization costs
  
(176)
(3)
–
–
–
  
Fair value gain (loss) on embedded derivatives
  
–
–
4
–
(9)
  
Other
  
(10)
19
9
(139)
(527)
      
(670)
(421)
(179)
(33)
(468)
  
Gulf of Mexico oil spill response
  
(781)
(430)
(1,474)
(1,228)
(7,361)
  
Total before interest and taxation
  
(9,094)
9,705
(10)
(10)
(9)
  
Finance costs(c)
  
(38)
(39)
(1,484)
(1,238)
(7,370)
  
Total before taxation
  
(9,132)
9,666
481
440
3,805
  
Taxation credit (charge)(d)
  
4,512
867
(1,003)
(798)
(3,565)
  
Total after taxation for period
  
(4,620)
10,533

(a)
See Note 3 for further information.
(b)
Third quarter, fourth quarter and full year 2014 include write-offs of $375 million, $20 million and $395 million respectively relating to Block KG D6 in India (see page 5 for further information). Fourth quarter and full year 2013 include $845 million relating to the value ascribed to block BM-CAL-13 offshore Brazil, following the acquisition of upstream assets from Devon Energy in 2011, which was written off as a result of the Pitanga exploration well not encountering commercial quantities of oil or gas.
(c)
Finance costs relate to the Gulf of Mexico oil spill. See Note 2 for further details.
(d)
From the first quarter 2014, tax is based on statutory rates except for non-deductible or non-taxable items. For earlier periods tax for the Gulf of Mexico oil spill and certain impairment losses, disposal gains and fair value gains and losses on embedded derivatives, is based on statutory rates, except for non-deductible items; for other items reported for consolidated subsidiaries, tax is calculated using the group’s discrete quarterly effective tax rate (adjusted for the items noted above, equity-accounted earnings and a deferred tax adjustment in the third quarter 2013 relating to a reduction in UK corporation tax rates). Non-operating items reported within the equity-accounted earnings of Rosneft are reported net of income tax.


Top of page 29
 
Additional information (continued)
 

Non-GAAP information on fair value accounting effects

Fourth
Third
Fourth
          
quarter
quarter
quarter
      
Year
Year
2013
2014
2014
  
$ million
  
2014
2013
       
Favourable (unfavourable) impact relative to
     
       
  management’s measure of performance
      
(114)
(87)
226
  
Upstream
  
31
(244)
(356)
299
357
  
Downstream
  
867
(178)
(470)
212
583
      
898
(422)
171
(66)
(226)
  
Taxation credit (charge)(a)
  
(341)
142
(299)
146
357
      
557
(280)

(a)
From the first quarter 2014, tax is calculated using statutory rates. For earlier periods tax is calculated using the group’s discrete quarterly effective tax rate (adjusted for certain non-operating items, equity-accounted earnings and a deferred tax adjustment in the third quarter 2013 relating to a reduction in UK corporation tax rates).

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 be 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
2013
2014
2014
  
$ million
  
2014
2013
       
Upstream
      
       
Replacement cost profit (loss) before interest and tax
      
2,651
3,398
(3,311)
  
  adjusted for fair value accounting effects
  
8,903
16,901
(114)
(87)
226
  
Impact of fair value accounting effects
  
31
(244)
2,537
3,311
(3,085)
  
Replacement cost profit (loss) before interest and tax
  
8,934
16,657
       
Downstream
      
       
Replacement cost profit (loss) before interest and tax
      
(4)
932
423
  
  adjusted for fair value accounting effects
  
2,871
3,097
(356)
299
357
  
Impact of fair value accounting effects
  
867
(178)
(360)
1,231
780
  
Replacement cost profit (loss) before interest and tax
  
3,738
2,919
       
Total group
      
       
Profit (loss) before interest and tax adjusted for fair value
      
2,047
2,757
(8,280)
  
  accounting effects
  
5,514
32,191
(470)
212
583
  
Impact of fair value accounting effects
  
898
(422)
1,577
2,969
(7,697)
  
Profit (loss) before interest and tax
  
6,412
31,769


Top of page 30
Additional information (continued)
 

Realizations and marker prices

Fourth
Third
Fourth
          
quarter
quarter
quarter
      
Year
Year
2013
2014
2014
      
2014
2013
       
Average realizations(a)
      
       
Liquids* ($/bbl)
      
89.87
87.26
71.41
  
US
  
84.24
91.88
105.23
96.33
71.10
  
Europe
  
93.84
104.77
104.60
94.14
66.61
  
Rest of World
  
90.19
104.20
98.26
91.42
69.03
  
BP Average
  
87.96
99.24
       
Natural gas ($/mcf)
      
3.08
3.48
3.30
  
US
  
3.80
3.07
9.95
6.41
8.19
  
Europe
  
8.18
9.68
6.21
6.15
6.33
  
Rest of World
  
6.35
5.97
5.49
5.40
5.54
  
BP Average
  
5.70
5.35
       
Total hydrocarbons* ($/boe)
      
62.11
60.69
51.92
  
US
  
60.37
60.78
93.29
82.16
65.35
  
Europe
  
82.63
90.46
63.36
59.91
49.88
  
Rest of World
  
58.61
61.72
65.04
61.61
51.53
  
BP Average
  
60.85
63.58
       
Average oil marker prices ($/bbl)
      
109.24
101.93
76.58
  
Brent
  
98.95
108.66
97.59
97.56
73.62
  
West Texas Intermediate
  
93.28
97.99
66.07
77.67
57.47
  
Western Canadian Select
  
73.65
73.33
104.80
101.47
74.66
  
Alaska North Slope
 
97.52
107.67
95.98
97.34
72.69
  
Mars
  
92.93
102.23
107.65
100.73
75.19
  
Urals (NWE – cif)
  
97.23
107.38
55.95
51.42
38.79
  
Russian domestic oil
  
50.40
54.97
       
Average natural gas marker prices
      
3.60
4.07
4.04
  
Henry Hub gas price ($/mmBtu)(b)
  
4.43
3.65
67.48
42.17
52.83
  
UK Gas – National Balancing Point (p/therm)
  
50.01
67.99

(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
2013
2014
2014
      
2014
2013
1.62
1.67
1.58
  
US dollar/sterling average rate for the period
  
1.65
1.56
1.65
1.62
1.56
  
US dollar/sterling period-end rate
  
1.56
1.65
1.36
1.33
1.25
  
US dollar/euro average rate for the period
  
1.33
1.33
1.38
1.27
1.22
  
US dollar/euro period-end rate
  
1.22
1.38
32.53
36.25
47.71
  
Rouble/US dollar average rate for the period
  
38.52
31.87
32.81
39.48
55.65
  
Rouble/US dollar period-end rate
  
55.65
32.81


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 comprises crude oil, condensate and natural gas liquids.

Net debt and net debt ratio are non-GAAP measures. Net debt includes the fair value of associated derivative financial instruments that are used to hedge foreign exchange and interest rate risks relating to finance debt, for which hedge accounting is claimed. The derivatives are reported on the balance sheet within the headings ‘Derivative financial instruments’. We believe that net debt and net debt ratio 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 net debt ratio is defined as the ratio of finance debt (borrowings, including the fair value of associated derivative financial instruments that are used to hedge foreign exchange and interest rate risks relating to finance debt, plus obligations under finance leases) to the total of finance debt plus shareholders’ interest.

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 arising in consolidated entities and in TNK-BP and Rosneft that are included in the financial statements and 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. 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.

Proved reserves replacement ratio is the extent to which production is replaced by proved reserves additions. This ratio is expressed in oil equivalent terms and includes changes resulting from revisions to previous estimates, improved recovery, and extensions and discoveries.

Refining availability represents Solomon Associates’ operational availability, which is defined as the percentage of the year that a unit is available for processing after subtracting the annualized time lost due to turnaround activity and all planned mechanical, process and regulatory downtime.

The Refining marker margin (RMM) is the average of regional indicator margins weighted for BP’s crude refining capacity in each region. Each regional marker margin is based on product yields and a marker crude oil deemed appropriate for the region. The regional indicator margins may not be representative of the margins achieved by BP in any period because of BP’s particular refinery configurations and crude and product slate.


Top of page 32
Glossary (continued)
 

Replacement cost (RC) profit or loss reflects the replacement cost of inventories sold in the period and is arrived at by excluding inventory holding gains and losses from profit or loss. RC profit or loss is the measure of profit or loss that is required to be disclosed for each operating segment under International Financial Reporting Standards (IFRS). RC profit or loss for the group is not a recognized GAAP measure. Management believes this measure is useful to illustrate to investors the fact that crude oil and product prices can vary significantly from period to period and that the impact on our reported result under IFRS can be significant. Inventory holding gains and losses vary from period to period due to changes in prices as well as changes in underlying inventory levels. In order for investors to understand the operating performance of the group excluding the impact of price changes on the replacement of inventories, and to make comparisons of operating performance between reporting periods, BP’s management believes it is helpful to disclose this measure.

Underlying production – 2014 underlying production, when compared with 2013, is after adjusting for the effects of the Abu Dhabi onshore concession expiry in January 2014, divestments and entitlement impacts in our production-sharing agreements. 2015 underlying production, when comparing with 2014, is 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.


Top of page 33
 
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 257-267 of BP Annual Report and Form 20-F 2013, pages 42-44 of our second-quarter 2014 results announcement and pages 33-36 of our third-quarter 2014 results announcement.

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

Federal multi-district litigation proceeding in New Orleans (MDL 2179) and related matters
US Department of Justice (DoJ) Action – Liability under Section 311(b)(7)(A) of the Clean Water Act – As previously disclosed, on 8 December 2011, the US brought a motion for partial summary judgment in the DoJ Action seeking, among other things, an order finding that BP Exploration & Production Inc. (BPXP), Transocean Ltd. and Anadarko Petroleum Company (Anadarko) are strictly liable for a civil penalty under Section 311(b)(7)(A) of the Clean Water Act. On 22 February 2012, the federal district court in New Orleans (the District Court) held that the subsurface discharge which occurred during the Incident was from the Macondo well, rather than from the Deepwater Horizon vessel, and that BPXP and Anadarko, and not Transocean Ltd., are strictly liable for civil penalties under Section 311 of the Clean Water Act as owners of the well. On 4 June 2014, the US Court of Appeals for the Fifth Circuit (Fifth Circuit) unanimously affirmed the District Court’s 22 February 2012 decision. On 21 July 2014, Anadarko and BPXP filed petitions requesting that all active judges of the Fifth Circuit review the 4 June 2014 decision. On 9 January 2015, the Fifth Circuit denied the petitions on a 7-6 vote. Absent an extension, BPXP’s deadline for seeking US Supreme Court review is 9 April 2015.

Trial Phases. On 4 September 2014, the District Court issued its ruling on Findings of Fact and Conclusion of Law for Phase 1 (the Phase 1 Ruling) of the Trial of Liability, Limitation, Exoneration and Fault Allocation in MDL 2179. The District Court found that BPXP, BP America Production Company (BPAPC), Transocean Holdings LLC, Transocean Deepwater Inc., Transocean Offshore Deepwater Drilling Inc. (Transocean, but excluding Transocean Ltd), and Halliburton Energy Services, Inc. (Halliburton) are each liable under general maritime law for the blowout, explosion, and oil spill from the Macondo well.  

With respect to the US’ claims against BPXP under the Clean Water Act, the District Court found that the discharge of oil was the result of BPXP’s gross negligence and wilful misconduct and that BPXP is therefore subject to enhanced civil penalties. The court further found that BPXP was an ‘operator’ and ‘person in charge’ of the Macondo well and the Deepwater Horizon vessel for the purposes of the Clean Water Act.

On 2 October 2014, BPXP and BPAPC filed a motion with the District Court to amend the findings in the Phase 1 Ruling, to alter or amend the judgment, or for a new trial on the grounds that the court’s allocation of fault and findings of gross negligence and wilful misconduct relied upon testimony which had been excluded from the evidence presented at the Phase 1 trial and as to which BPXP and BPAPC did not have adequate notice and opportunity to present evidence in rebuttal. On 13 November 2014, the court denied BPXP’s and BPAPC’s motion to amend the Phase 1 Ruling. On 11 December 2014, BPXP and BPAPC filed a notice of appeal of the Phase 1 Ruling to the Fifth Circuit, and subsequently notices of appeal were also filed by the PSC, Transocean, Halliburton and the State of Alabama.

On 15 January 2015, the District Court issued its ruling for Phase 2 of MDL 2179 on the quantification of oil spilled and BP’s source control efforts following the accident. The District Court found that 3.19 million barrels of oil were discharged into the Gulf of Mexico and are therefore subject to a Clean Water Act penalty. In addition, the District Court found that BP was not grossly negligent in its source control efforts.

Trial in the penalty phase of MDL 2179 (the Penalty Phase) commenced on 20 January 2015 and is scheduled to last three weeks. In the Penalty Phase, the District Court will determine the amount of civil penalties owed to the US under the Clean Water Act based on the court’s rulings (or ultimate determinations on appeal) in Phases 1 and 2, and the application of the penalty factors under the Clean Water Act. On 7 January 2015, the court established a post-trial briefing schedule for the Penalty Phase under which briefing is to be concluded on 24 April 2015. The District Court has wide discretion in its application of statutory penalty factors.

For further information, see pages 257-265 of BP Annual Report and Form 20-F 2013 and Note 2 on page 16.

Plaintiffs’ Steering Committee (PSC) Settlements – Deepwater Horizon Court Supervised Settlement Program (DHCSSP) and interpretation of the Economic and Property Damages Settlement Agreement. As previously disclosed, on 1 August 2014, BP filed a petition for certiorari with the US Supreme Court for review of the Fifth Circuit’s decision upholding the District Court’s ruling that the Economic and Property Damages Settlement Agreement contained no causation requirement beyond the revenue and related tests set forth in an exhibit to that agreement, as well as a related decision by a different panel of the Fifth Circuit interpreting the Economic and Property Damages Settlement Agreement to permit payment to business economic loss claimants whose losses (if any) were not caused by the spill. On 8 December 2014, the US Supreme Court denied that petition. Accordingly, the effective date of the Economic and Property Damages Settlement Agreement is 8 December 2014, and the final deadline for filing all claims other than those that fall under the Seafood Compensation Program is 8 June 2015.


Top of page 34
 
Legal proceedings (continued)
 

On 2 September 2014, BP filed a motion seeking an order removing Patrick Juneau from his roles as Claims Administrator and Settlement Trustee for the Economic and Property Damages Settlement. On 10 November 2014, the District Court denied BP’s motion. BP appealed this decision to the Fifth Circuit on 18 November 2014 and oral argument has been scheduled for 3 February 2015.

For information about BP’s current estimate of the total cost of the PSC settlements, see Note 2 on page 16.

PSC settlements – Seafood Compensation Fund (Fund) – Pursuant to the Economic and Property Damages Settlement, BP paid $2.3 billion to the Fund to help resolve economic loss claims related to the Gulf seafood industry, a portion of which has not yet been distributed. On 19 September 2014, the District Court designated-neutrals appointed to preside over the settlement of the seafood program (the Neutrals) submitted to the District Court their report on Recommendations for Seafood Compensation Program Supplement Distribution (Recommendations). The Neutrals observed that there remain some claims against the Fund which have not been paid, and that BP has filed a motion which seeks a return of part of the Fund, on the basis that it is currently impossible to fully distribute the balance of the Fund. The Neutrals recommended that the Court target a $500-million partial distribution in the second round of payments using a proportionate distribution method. The District Court issued an Order filing the Recommendations into the court record and requiring that any objections to or comments on the Recommendations to be filed by 20 October 2014. BP filed a motion asserting that the District Court should not yet order second round distributions on the basis that, amongst other things, the first round distributions are not complete. On 18 November 2014, the District Court approved the Neutrals’ Recommendations.

Medical Benefits Class Action Settlement (Medical Settlement) – The District Court approved the Medical Settlement Agreement (MSA) in a final order and judgment on 11 January 2013. The effective date was 12 February 2014 and the deadline for submitting claims for Specified Physical Conditions (SPC) under the MSA is 12 February 2015. Claimants filed a motion to extend the date to 12 August 2015. The Medical Claims Administrator issued a policy statement, with which BP agrees, classifying physical conditions first diagnosed after 16 April 2012 as Later-Manifested Physical Conditions (LMPC), requiring a class member seeking compensation to file a notice of intent to sue that allows BP the option to mediate the claim in lieu of litigation. On 23 July 2014, the District Court issued an order affirming the policy statement. On 26 November 2014, the District Court directed the Medical Claims Administrator to issue another policy statement regarding the impact of the release provisions under the MSA on the filing of SPC and LMPC claims, which was filed on 17 December. The court’s decision to adopt, modify or reject the policy statement is pending.

MDL 2185 and other securities-related litigation
Securities class litigation – The trial of the consolidated securities fraud complaint filed on behalf of a certified class of BP ADS holders who purchased ADSs between 26 April 2010 and 28 May 2010 has been scheduled to commence on 11 January 2016.

ERISA – On 30 March 2012, the federal district court in Houston in MDL 2185 issued a decision granting the defendants’ motions to dismiss the ERISA case related to BP share funds in several employee benefit savings plans. Final judgment dismissing the case was entered on 4 September 2012 and, on 25 September 2012, the plaintiffs filed a notice of appeal to the Fifth Circuit. On 15 July 2014, the Fifth Circuit remanded the case to the district court in light of new pleading standards recently set forth by the US Supreme Court. BP opposed that motion. On 15 January 2015, the district court granted in part and denied in part the motion to amend, permitting plaintiffs to amend their complaint to allege some of their proposed claims against certain defendants. Plaintiffs must file an amended complaint by 12 February 2015.

For further information about MDL 2185 and other securities-related litigation, see pages 257-264 of BP Annual Report and Form 20-F 2013, pages 43-44 of our second-quarter 2014 results announcement and page 35 of our third-quarter 2014 results announcement.


Top of page 35
 
Legal proceedings (continued)
 

Other legal proceedings

Bolivia – In March 2012 Pan American Energy (PAE) commenced an arbitration proceeding against the Republic of Bolivia (Bolivia) in connection with the expropriation of its shares in Empresa Petrolera Chaco S.A. On 18 December 2014 Bolivia and PAE signed a $357-million settlement agreement and agreed to terminate the arbitration.

California False Claims Act matters – On 4 November 2014 the California Attorney General filed a notice in California state court that it was intervening in a previously-sealed California False Claims Act (CFCA) lawsuit filed by relator Christopher Schroen against BP p.l.c., BP Energy Company, BP Corporation North America Inc., BP Products and BPAPC. On 7 January 2015, the California Attorney General filed a complaint in intervention alleging that BP violated the CFCA and the California Unfair Competition Law by falsely and fraudulently overcharging California state entities for natural gas. The relator’s complaint makes similar allegations, in addition to individual claims. The complaints seek treble damages, punitive damages, penalties and injunctive relief.

US Federal Energy Regulatory Commission (FERC) and US Commodity Futures Trading Commission (CFTC) matters – The CFTC is currently investigating certain practices relating to crude oil pipeline nominations procedures on Canadian pipelines. On 17 November 2014, the CFTC Enforcement staff notified BP that it intends to recommend an enforcement action naming certain parties, including several BP entities, alleging violations of the anti-fraud and false reporting provisions of the Commodity Exchange Act in connection with these nomination procedures and related trades. On 17 December 2014 BP submitted a detailed defence responding to the allegations in the notice and challenging the CFTC’s jurisdiction over the alleged conduct.

Investigations by the CFTC and the FERC into BP’s trading activities continue to be conducted from time to time.


Other matters
 

During 2014 the US and the EU have imposed sanctions on certain Russian activities, individuals and entities, including Rosneft. To date, these sanctions have had no material adverse impact on BP or Ruhr Oel GmbH.


Top of page 36
 
Cautionary statement
 

Cautionary statement regarding forward-looking statements: The discussion in this results announcement contains certain forecasts, projections and forward-looking statements – that is, statements related to future, not past events – with respect to the financial condition, results of operation and businesses of BP and certain of the plans and objectives of BP with respect to these items. These statements may generally, but not always, be identified by the use of words such as ‘will’, ‘expects’, ‘is expected to’, ‘aims’, ‘should’, ‘may’, ‘objective’, ‘is likely to’, ‘intends’, ‘believes’, ‘anticipates’, ‘plans’, ‘we see’ or similar expressions. In particular, among other statements, the expected level of organic capital expenditure in 2015; plans regarding the divestment of $10 billion in assets by the end of 2015; the expected quarterly dividend payment and timing of such payment; expectations regarding the underlying effective tax rate during 2015; expectations regarding the 2015 charge for depreciation, depletion and amortization; expectations regarding BP’s operatorship in the onshore Nile Delta and future investments in that region; expectations and plans regarding the formation of a new ownership and operating model with Chevron and ConocoPhillips in deepwater Gulf of Mexico; expectations regarding the level of reported production for first quarter 2015 and full year 2015; the expected level of underlying production in full year 2015; expectations regarding the refining environment and the financial impact of refinery turnarounds in 2015; expectations regarding gradual improvement in the petrochemicals margin environment; the expected level of Other businesses and corporate average quarterly charges in 2015; and certain statements regarding the legal and trial proceedings, court decisions, 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. Actual results may differ from those expressed in such statements, depending on a variety of factors including the timing of bringing new fields onstream; the timing and level of maintenance and/or turnaround activity; the nature, timing and volume of refinery additions and outages; the timing, quantum and nature of divestments; the receipt of relevant third-party and/or regulatory approvals; future levels of industry product supply, demand and pricing; OPEC quota restrictions; PSA effects; operational problems; 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 court decisions, the types of enforcement action pursued and the nature of remedies sought or imposed; the impact on our reputation following the Gulf of Mexico oil spill; exchange rate fluctuations; development and use of new technology; the success or otherwise of partnering; the actions of competitors, trading partners, creditors, rating agencies and others; 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 2014 and under “Risk factors” in BP Annual Report and Form 20-F 2013, each as filed with the US Securities and Exchange Commission.

Notice to investors: BP has received written comments from the US Securities and Exchange Commission regarding its Form 6-K for the fiscal quarter ended 30 September 2014 in a letter dated 17 December 2014.






Contacts
 

 
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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: 03 February, 2015
 
/s/ J. BERTELSEN
...............................
J. BERTELSEN
Deputy Company Secretary