Edgar Filing: BP PLC

Blueprint

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 01 November, 2016

BP p.l.c.

(Translation of registrant's name into English)

1 ST JAMES'S SQUARE, LONDON, SW1Y 4PD, ENGLAND

(Address of principal executive offices)

Indicate by check mark whether the registrant files or will file annual

reports under cover Form 20-F or Form 40-F.

Form 20-F |X| Form 40-F

--------------- ----------------

Indicate by check mark whether the registrant by furnishing the information

contained in this Form is also thereby furnishing the information to the

Commission pursuant to Rule 12g3-2(b) under the Securities Exchange Act of

1934.

Yes No |X|

--------------- --------------

BP p.l.c.

Group results

Third quarter and nine months 2016

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FOR IMMEDIATE RELEASE London 1 November 2016

Third	Second	Third		Nine	Nine
quarter	quarter	quarter		months	months
2015	2016	2016	$ million	2016	2015
46	(1,419)	1,620	Profit (loss) for the period(a)	(382)	(3,175)
1,188	(828)	41	Inventory holding (gains) losses*, net of tax	(689)	246
1,234	(2,247)	1,661	Replacement cost profit (loss)*	(1,071)	(2,929)
			Net (favourable) unfavourable
			impact of non-operating items* and
585	2,967	(728)	fair value accounting effects*, net of tax	3,256	8,638
1,819	720	933	Underlying replacement cost profit*	2,185	5,709
			Replacement cost profit (loss)*
6.73	(12.03)	8.82	per ordinary share (cents)	(5.74)	(16.01)
0.40	(0.72)	0.53	per ADS (dollars)	(0.34)	(0.96)
			Underlying replacement cost profit*
9.92	3.85	4.96	per ordinary share (cents)	11.70	31.18
0.60	0.23	0.30	per ADS (dollars)	0.70	1.87

●

BP’s third-quarter replacement cost (RC) profit was $1,661 million, compared with $1,234 million a year ago. After adjusting for a net gain for non-operating items of $949 million and net unfavourable fair value accounting effects of $221 million (both on a post-tax basis), underlying RC profit for the third quarter was $933 million, compared with $1,819 million for the same period in 2015. For the first nine months of 2016 the RC loss was $1,071 million, compared with a loss of $2,929 million for the first nine months of 2015. Both periods were impacted by charges associated with the Deepwater Horizon accident and oil spill following the settlement of federal, state and local government claims in 2015 and additional provisions this year, when a reliable estimate for all the remaining material liabilities was determined. After adjusting for a net charge for non-operating items of $2,648 million and net unfavourable fair value accounting effects of $608 million (both on a post-tax basis), underlying RC profit for the nine months was $2,185 million, compared with $5,709 million for the same period in 2015. RC profit or loss for the group and underlying RC profit or loss are non-GAAP measures and further information is provided on page 3.

●

Non-operating items for the quarter reflect impairment reversals in the Upstream segment and for the nine months also reflect additional provisions recorded in the second quarter in relation to the Gulf of Mexico oil spill. Non-operating items also include a restructuring charge of $154 million for the quarter and $568 million for the nine months. Cumulative restructuring charges from the beginning of the fourth quarter 2014 totalled $2.1 billion by the end of the third quarter 2016. We now expect restructuring to continue throughout 2017.

●

All amounts, including finance costs, relating to the Gulf of Mexico oil spill have been treated as non-operating items, with a net pre-tax charge of $189 million for the third quarter and $6,335 million for the nine months. For further information on the Gulf of Mexico oil spill and its consequences see page 9 and Note 2 on page 16. See also Legal proceedings on page 31.

●

Net cash provided by operating activities for the third quarter and nine months was $2.5 billion and $8.3 billion respectively, compared with $5.2 billion and $13.3 billion for the same periods in 2015. Excluding post-tax amounts related to the Gulf of Mexico oil spill, net cash provided by operating activities* for the third quarter and nine months was $4.8 billion and $13.1 billion respectively, compared with $5.4 billion and $14.3 billion for the same periods in 2015.

●

Net debt* at 30 September 2016 was $32.4 billion, compared with $25.6 billion a year ago. The net debt ratio* at 30 September 2016 was 25.9%, compared with 20.0% a year ago. Net debt and the net debt ratio are non-GAAP measures. See page 22 for more information.

●

BP today announced a quarterly dividend of 10.00 cents per ordinary share ($0.600 per ADS), which is expected to be paid on 16 December 2016. The corresponding amount in sterling will be announced on 6 December 2016. See page 21 for further information.

*	For items marked with an asterisk throughout this document, definitions are provided in the Glossary on page 28.
(a)	Profit attributable to BP shareholders.
The commentaries above and following should be read in conjunction with the cautionary statement on page 32.

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Group headlines (continued)

●

Capital expenditure on an accruals basis* for the third quarter was $3.7 billion, of which organic capital expenditure* was $3.6 billion, compared with $4.3 billion for the same period in 2015, almost all of which was organic. For the nine months, capital expenditure on an accruals basis was $11.8 billion, of which organic capital expenditure was $11.5 billion, compared with $13.3 billion for the same period in 2015, of which organic capital expenditure was $13.2 billion. See page 24 for further information. Organic capital expenditure for 2016 is now expected to be around $16 billion, and in the range $15-17 billion in 2017.

●

Disposal proceeds, as per the cash flow statement, were $0.6 billion for the third quarter and $2.2 billion for the nine months, compared with $0.3 billion and $2.6 billion for the same periods in 2015. In addition, $0.3 billion was received in the third quarter in relation to the sale of 8.5% from our shareholding in Castrol India Limited (for the nine months, $0.6 billion was received in relation to the sale of 20% of the shareholding).

●

The effective tax rate (ETR) on RC profit or loss* for the third quarter and nine months was -16% and 73% respectively, compared with 52% and 45% for the same periods in 2015. Excluding non-operating items, fair value accounting effects and the impact of the reduction in the rate of the UK North Sea supplementary charge in the third quarter (and the first quarter 2015), the adjusted ETR* for the third quarter and nine months was 37% and 25% respectively, compared with 39% and 32% for the same periods in 2015. The adjusted ETR for the quarter and the nine months is lower than a year ago mainly due to foreign exchange effects and changes in the geographical mix of profits.

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Analysis of RC profit (loss) before interest and tax

and reconciliation to profit (loss) for the period

Third	Second	Third		Nine	Nine
quarter	quarter	quarter		months	months
2015	2016	2016	$ million	2016	2015
			RC profit (loss) before interest and tax*
743	(109)	1,196	Upstream	(118)	1,343
2,562	1,405	978	Downstream	4,263	6,273
382	246	120	Rosneft	432	1,075
(689)	(5,525)	(441)	Other businesses and corporate(a)	(7,040)	(12,522)
67	(121)	17	Consolidation adjustment – UPII*	(64)	(101)
3,065	(4,104)	1,870	RC profit (loss) before interest and tax	(2,527)	(3,932)
			Finance costs and net finance expense relating to
(474)	(460)	(481)	pensions and other post-retirement benefits	(1,381)	(1,196)
(1,347)	2,346	229	Taxation on a RC basis	2,848	2,298
(10)	(29)	43	Non-controlling interests	(11)	(99)
1,234	(2,247)	1,661	RC profit (loss) attributable to BP shareholders	(1,071)	(2,929)
(1,726)	1,188	(60)	Inventory holding gains (losses)	996	(343)
			Taxation (charge) credit on inventory holding
538	(360)	19	gains and losses	(307)	97
			Profit (loss) for the period attributable to
46	(1,419)	1,620	BP shareholders	(382)	(3,175)

(a)	Includes costs related to the Gulf of Mexico oil spill. See page 9 and also Note 2 on page 16 for further information on the accounting for the Gulf of Mexico oil spill.

Analysis of underlying RC profit before interest and tax

Third	Second	Third		Nine	Nine
quarter	quarter	quarter		months	months
2015	2016	2016	$ million	2016	2015
			Underlying RC profit before interest and tax*
823	29	(224)	Upstream	(942)	1,921
2,302	1,513	1,431	Downstream	4,757	6,327
382	246	120	Rosneft	432	1,075
(231)	(376)	(260)	Other businesses and corporate	(814)	(922)
67	(121)	17	Consolidation adjustment – UPII	(64)	(101)
3,343	1,291	1,084	Underlying RC profit before interest and tax	3,369	8,300
			Finance costs and net finance expense relating to
(359)	(337)	(358)	pensions and other post-retirement benefits	(1,012)	(1,064)
(1,155)	(205)	164	Taxation on an underlying RC basis	(161)	(1,428)
(10)	(29)	43	Non-controlling interests	(11)	(99)
1,819	720	933	Underlying RC profit attributable to BP shareholders	2,185	5,709

Reconciliations of underlying RC profit or loss to the nearest equivalent IFRS measure are provided on page 1 for the group and on pages 4-9 for the segments.

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Upstream

Third	Second	Third		Nine	Nine
quarter	quarter	quarter		months	months
2015	2016	2016	$ million	2016	2015
716	(24)	1,183	Profit (loss) before interest and tax	(77)	1,331
27	(85)	13	Inventory holding (gains) losses*	(41)	12
743	(109)	1,196	RC profit (loss) before interest and tax	(118)	1,343
			Net (favourable) unfavourable impact
			of non-operating items* and
80	138	(1,420)	fair value accounting effects*	(824)	578
823	29	(224)	Underlying RC profit (loss) before interest and tax*(a)	(942)	1,921

(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 third quarter and nine months was a profit of $1,196 million and a loss of $118 million respectively, compared with a profit of $743 million and $1,343 million for the same periods in 2015. The third quarter and nine months included a net non-operating gain of $1,465 million and $1,117 million respectively, compared with a net non-operating charge of $118 million and $596 million for the same periods a year ago. The net non-operating gain for the quarter arises mainly due to impairment reversals, predominantly relating to assets in Angola and the North Sea (see Notes 1 and 4 for further information). The net non-operating gain for the quarter and nine months also include other charges, gain on sale and restructuring costs. Fair value accounting effects in the third quarter and nine months had an unfavourable impact of $45 million and $293 million respectively, compared with a favourable impact of $38 million and $18 million in the same periods of 2015.

After adjusting for non-operating items and fair value accounting effects, the underlying replacement cost loss before interest and tax for the third quarter and nine months was $224 million and $942 million respectively, compared with a profit of $823 million and $1,921 million for the same periods in 2015. The result for the third quarter reflected lower liquids and gas realizations, lower gas marketing and trading results, higher rig cancellation costs and exploration write-offs partly offset by lower costs reflecting the benefits of simplification and efficiency activities. The result for the nine months reflected lower liquids and gas realizations and lower gas marketing and trading results partly offset by lower costs reflecting the benefits of simplification and efficiency activities, lower depreciation, depletion and amortization expense, lower exploration write-offs and lower rig cancellation costs.

Production

Production for the quarter was 2,110mboe/d, 5.9% lower than the third quarter of 2015. Underlying production* for the quarter decreased by 2.0%, mainly due to seasonal turnaround and maintenance activities, and the impact of weather and the Pascagoula plant outage in the Gulf of Mexico. For the nine months, production was 2,209mboe/d, broadly flat versus the same period in 2015. Underlying production for the nine months was broadly flat versus the same period in 2015.

Key events

On 29 July, BP and Atlantic LNG announced the sanction of the Trinidad onshore compression project. The project is 100% funded and owned by BP Trinidad and Tobago LLC and will be operated by Atlantic LNG.

On 1 September, BP announced the signing of a second production-sharing agreement* with China National Petroleum Corporation (CNPC, operator) for shale gas exploration, development and production at Rong Chang Bei in the Sichuan Basin covering an area of approximately 1,000 square kilometres.

On 27 September, BP announced it has signed concession amendments for the Temsah, Ras El Barr and Nile Delta Offshore concessions in Egypt, enabling the fast track development of the Nooros field.

On 30 September, BP and Det norske oljeselskap completed the creation of Aker BP ASA, an independent oil and gas company, into which BP contributed its Norwegian upstream business. Aker BP is owned by Det norske shareholder Aker (40%), other Det norske shareholders (30%) and BP (30%).

In September, BP completed and installed the first jacket for Shah Deniz Stage 2.

On 11 October, BP announced the decision not to progress its exploration drilling programme in the Great Australian Bight, offshore South Australia.

In October, BP and Rosneft completed the transaction to create a new joint venture, Yermak Neftegaz LLC (Rosneft 51% and BP 49%).

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Upstream

Outlook

Looking ahead, we expect fourth-quarter reported production to be slightly higher than the third quarter, mainly reflecting recovery from planned seasonal turnaround and maintenance activity.

The commentary above contains forward-looking statements and should be read in conjunction with the cautionary statement on page 32.

Third	Second	Third		Nine	Nine
quarter	quarter	quarter		months	months
2015	2016	2016	$ million	2016	2015
			Underlying RC profit (loss) before interest and tax
(152)	(305)	(151)	US	(1,123)	(763)
975	334	(73)	Non-US	181	2,684
823	29	(224)		(942)	1,921
			Non-operating items(a)
(139)	(57)	326	US	106	(342)
21	64	1,139	Non-US	1,011	(254)
(118)	7	1,465		1,117	(596)
			Fair value accounting effects
26	(57)	(15)	US	(105)	(32)
12	(88)	(30)	Non-US	(188)	50
38	(145)	(45)		(293)	18
			RC profit (loss) before interest and tax
(265)	(419)	160	US	(1,122)	(1,137)
1,008	310	1,036	Non-US	1,004	2,480
743	(109)	1,196		(118)	1,343
			Exploration expense
61	48	22	US	182	333
295	302	781	Non-US(b)	1,225	1,097
356	350	803		1,407	1,430
234	260	687	Of which: Exploration expenditure written off(b)	1,108	1,132
			Production (net of royalties)(c)
			Liquids* (mb/d)
390	401	353	US	386	372
94	117	112	Europe	119	118
747	584	664	Rest of World	708	710
1,231	1,102	1,128		1,213	1,200
			Natural gas (mmcf/d)
1,569	1,666	1,679	US	1,649	1,521
232	238	262	Europe	263	259
4,062	3,829	3,753	Rest of World	3,867	4,138
5,864	5,733	5,695		5,779	5,918
			Total hydrocarbons* (mboe/d)
661	688	643	US	670	634
135	158	157	Europe	164	163
1,447	1,244	1,311	Rest of World	1,375	1,424
2,242	2,090	2,110		2,209	2,220
			Average realizations*(d)
44.01	44.99	41.23	Total liquids(e) ($/bbl)	36.71	48.87
3.49	2.66	2.77	Natural gas ($/mcf)	2.76	3.91
33.25	30.63	29.46	Total hydrocarbons ($/boe)	27.28	36.68

(a)	See Notes 1 and 4 for more information on impairment of fixed assets in the third quarter and nine months 2016. See also footnote (b) below.
(b)	Third quarter and nine months include $601 million relating to the BM-C-34 licence in Brazil, of which $334 million relates to the value ascribed to the licence as part of the accounting for the acquisition of upstream assets from Devon Energy in 2011. The $334 million write-off has been classified within the ‘other’ category of non-operating items. Nine months 2015 includes a $432-million write-off in Libya.
(c)	Includes BP’s share of production of equity-accounted entities in the Upstream segment.
(d)	Realizations are based on sales by consolidated subsidiaries only – this excludes equity-accounted entities.
(e)	Includes condensate, natural gas liquids and bitumen.
Because of rounding, some totals may not agree exactly with the sum of their component parts.

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Downstream

Third	Second	Third		Nine	Nine
quarter	quarter	quarter		months	months
2015	2016	2016	$ million	2016	2015
875	2,463	943	Profit before interest and tax	5,189	5,892
1,687	(1,058)	35	Inventory holding (gains) losses*	(926)	381
2,562	1,405	978	RC profit before interest and tax	4,263	6,273
			Net (favourable) unfavourable
			impact of non- operating items*
(260)	108	453	and fair value accounting effects*	494	54
2,302	1,513	1,431	Underlying RC profit before interest and tax*(a)	4,757	6,327

(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 third quarter and nine months was $978 million and $4,263 million respectively, compared with $2,562 million and $6,273 million for the same periods in 2015.

The 2016 results include a net non-operating charge of $196 million for the third quarter and a net non-operating gain of $53 million for the nine months, compared with a net non-operating gain of $43 million and a net non-operating charge of $42 million for the same periods in 2015. Fair value accounting effects had unfavourable impacts of $257 million in the third quarter and $547 million in the nine months, compared with a favourable impact of $217 million and an unfavourable impact of $12 million in the same periods of 2015.

After adjusting for non-operating items and fair value accounting effects, the underlying replacement cost profit before interest and tax for the third quarter and nine months was $1,431 million and $4,757 million respectively, compared with $2,302 million and $6,327 million for the same periods in 2015.

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 $983 million for the third quarter and $3,310 million for the nine months, compared with $1,917 million and $5,107 million for the same periods in 2015. The result for the quarter reflects a significantly weaker refining environment and a higher level of turnaround activity, partially offset by an increased retail performance and lower costs from simplification and efficiency programmes. The nine-months result reflects a significantly weaker refining environment and a lower contribution from supply and trading, partially offset by lower costs from simplification and efficiency programmes, an increased retail performance and stronger refining operations.

Lubricants business

The lubricants business reported an underlying replacement cost profit before interest and tax of $370 million for the third quarter and $1,166 million for the nine months, compared with $348 million and $1,090 million for the same periods in 2015. The results for the quarter and nine months reflect continued momentum in our growth markets and premium brands.

During the third quarter we sold an 8.5% shareholding in Castrol India Limited reducing our shareholding to 51%.

Petrochemicals business

The petrochemicals business reported an underlying replacement cost profit before interest and tax of $78 million for the third quarter and $281 million for the nine months, compared with $37 million and $130 million for the same periods in 2015. The result for the nine months reflects stronger operations and margin capture.

Outlook

In the fourth quarter we expect a higher level of turnaround activity compared with the third quarter, and that industry refining margins will continue to be under pressure.

The commentary above contains forward-looking statements and should be read in conjunction with the cautionary statement on page 32.

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Downstream

Third	Second	Third		Nine	Nine
quarter	quarter	quarter		months	months
2015	2016	2016	$ million	2016	2015
			Underlying RC profit before interest and tax -
			by region
885	386	298	US	1,224	2,122
1,417	1,127	1,133	Non-US	3,533	4,205
2,302	1,513	1,431		4,757	6,327
			Non-operating items
51	17	(56)	US	74	110
(8)	(54)	(140)	Non-US	(21)	(152)
43	(37)	(196)		53	(42)
			Fair value accounting effects
153	(78)	(178)	US	(343)	(22)
64	7	(79)	Non-US	(204)	10
217	(71)	(257)		(547)	(12)
			RC profit before interest and tax
1,089	325	64	US	955	2,210
1,473	1,080	914	Non-US	3,308	4,063
2,562	1,405	978		4,263	6,273
			Underlying RC profit before interest and tax -
			by business(a)(b)
1,917	1,011	983	Fuels	3,310	5,107
348	412	370	Lubricants	1,166	1,090
37	90	78	Petrochemicals	281	130
2,302	1,513	1,431		4,757	6,327
			Non-operating items and fair value
			accounting effects(c)
295	(93)	(455)	Fuels	(493)	83
(25)	(3)	1	Lubricants	(3)	(126)
(10)	(12)	1	Petrochemicals	2	(11)
260	(108)	(453)		(494)	(54)
			RC profit before interest and tax(a)(b)
2,212	918	528	Fuels	2,817	5,190
323	409	371	Lubricants	1,163	964
27	78	79	Petrochemicals	283	119
2,562	1,405	978		4,263	6,273

20.0	13.8	11.6	BP average refining marker margin (RMM)* ($/bbl)	12.0	18.2
			Refinery throughputs (mb/d)
681	668	613	US	660	642
785	805	795	Europe	802	800
230	231	242	Rest of World	237	259
1,696	1,704	1,650		1,699	1,701
94.9	95.7	95.4	Refining availability* (%)	95.4	94.4
			Marketing sales of refined products (mb/d)
1,121	1,115	1,205	US	1,130	1,122
1,272	1,170	1,236	Europe	1,184	1,202
479	515	503	Rest of World	502	479
2,872	2,800	2,944		2,816	2,803
2,781	2,875	2,581	Trading/supply sales of refined products	2,755	2,731
5,653	5,675	5,525	Total sales volumes of refined products	5,571	5,534
			Petrochemicals production (kte)
877	558	564	US	2,018	2,728
976	909	898	Europe	2,799	2,800
2,004	1,967	1,987	Rest of World	5,863	5,565
3,857	3,434	3,449		10,680	11,093

(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.

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Rosneft

Third	Second	Third		Nine	Nine
quarter	quarter	quarter		months	months
2015	2016	2016(a)	$ million	2016(a)	2015
370	291	108	Profit before interest and tax(b)	461	1,125
12	(45)	12	Inventory holding (gains) losses*	(29)	(50)
382	246	120	RC profit before interest and tax	432	1,075
–	–	–	Net charge (credit) for non-operating items*	–	–
382	246	120	Underlying RC profit before interest and tax*	432	1,075

Financial results

Replacement cost profit before interest and tax and underlying replacement cost profit before interest and tax for the third quarter and nine months was $120 million and $432 million respectively, compared with $382 million and $1,075 million for the same periods in 2015. There were no non-operating items in the third quarter and nine months of either year.

Compared with the same period last year, the result for the third quarter was primarily affected by adverse foreign exchange, lower oil prices and increased government take, partially offset by favourable duty lag effects. For the nine months, the result was primarily affected by lower oil prices and increased government take, partially offset by favourable duty lag effects.

In June 2016 Rosneft’s annual general meeting adopted a resolution to pay a dividend of 11.75 Russian roubles per ordinary share in relation to the 2015 annual results. BP received a dividend of $332 million, after the deduction of withholding tax, in July 2016.

Key events

On 12 October Rosneft acquired from the Russian government a 50.0755% stake in Bashneft, a Russian oil company, for 329.69 billion Russian roubles (approximately $5.3 billion). This acquisition is expected to provide Rosneft with significant synergies, additional refining throughput and additional liquid hydrocarbon production, which will be reflected in BP’s production and reserves through BP equity accounting for its 19.75% share in Rosneft.

On 15 October Rosneft announced the signing of an agreement for the purchase, subject to regulatory approval, of a 49% stake in Essar Oil Limited, an Indian downstream business, from the Essar group.

Third	Second	Third		Nine	Nine
quarter	quarter	quarter		months	months
2015	2016	2016(a)		2016(a)	2015
			Production (net of royalties) (BP share)
810	812	820	Liquids* (mb/d)	813	813
1,125	1,266	1,221	Natural gas (mmcf/d)	1,256	1,173
1,003	1,030	1,030	Total hydrocarbons* (mboe/d)	1,030	1,016

(a)

The operational and financial information of the Rosneft segment for the third quarter and nine months of the year is based on preliminary operational and financial results of Rosneft for the nine months ended 30 September 2016. Actual results may differ from these amounts.

(b)

The Rosneft segment result includes equity-accounted earnings arising from BP’s 19.75% shareholding in Rosneft as adjusted for the accounting required under IFRS relating to BP’s purchase of its interest in Rosneft and the amortization of the deferred gain relating to the disposal of BP’s interest in TNK-BP. These adjustments have increased the reported profit before interest and tax for the third quarter and nine months of 2016, as shown in the table above, compared with the equivalent amount in Russian roubles that we expect Rosneft to report in its own financial statements under IFRS. BP’s share of Rosneft’s profit before interest and tax for each year-to-date period is calculated by translating the amounts reported in Russian roubles into US dollars using the average exchange rate for the year to date. BP's share of Rosneft’s earnings after finance costs, taxation and non-controlling interests, as adjusted, is included in the BP group income statement within profit before interest and taxation.

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Other businesses and corporate

Third	Second	Third		Nine	Nine
quarter	quarter	quarter		months	months
2015	2016	2016	$ million	2016	2015
			Profit (loss) before interest and tax
(311)	(5,106)	(66)	Gulf of Mexico oil spill	(5,966)	(11,381)
(378)	(419)	(375)	Other	(1,074)	(1,141)
(689)	(5,525)	(441)	Profit (loss) before interest and tax	(7,040)	(12,522)
–	–	–	Inventory holding (gains) losses*	–	–
(689)	(5,525)	(441)	RC profit (loss) before interest and tax	(7,040)	(12,522)
			Net charge (credit) for non-operating items*
311	5,106	66	Gulf of Mexico oil spill	5,966	11,381
147	43	115	Other	260	219
458	5,149	181	Net charge (credit) for non-operating items	6,226	11,600
(231)	(376)	(260)	Underlying RC profit (loss) before interest and tax*	(814)	(922)
			Underlying RC profit (loss) before interest and tax
(126)	(109)	(107)	US	(326)	(332)
(105)	(267)	(153)	Non-US	(488)	(590)
(231)	(376)	(260)		(814)	(922)
			Non-operating items
(438)	(5,136)	(168)	US	(6,152)	(11,519)
(20)	(13)	(13)	Non-US	(74)	(81)
(458)	(5,149)	(181)		(6,226)	(11,600)
			RC profit (loss) before interest and tax
(564)	(5,245)	(275)	US	(6,478)	(11,851)
(125)	(280)	(166)	Non-US	(562)	(671)
(689)	(5,525)	(441)		(7,040)	(12,522)

Other businesses and corporate comprises biofuels and wind businesses, shipping, treasury (which includes interest income on the group's cash and cash equivalents), corporate activities including centralized functions, and the costs of the Gulf of Mexico oil spill.

Financial results

The replacement cost loss before interest and tax for the third quarter and nine months was $441 million and $7,040 million respectively, compared with $689 million and $12,522 million for the same periods in 2015.

The third-quarter result included a net non-operating charge of $181 million, primarily relating to environmental provisions and costs for the Gulf of Mexico oil spill, compared with a net non-operating charge of $458 million a year ago. For the nine months, the net non-operating charge was $6,226 million, compared with a net non-operating charge of $11,600 million a year ago, both primarily relating to costs for the Gulf of Mexico oil spill. For further information see Note 2 on page 16.

After adjusting for non-operating items, the underlying replacement cost loss before interest and tax for the third quarter and nine months was $260 million and $814 million respectively, compared with $231 million and $922 million for the same periods in 2015. The nine-months result reflects lower corporate costs and favourable foreign exchange impacts.

Biofuels

The net ethanol-equivalent production (which includes ethanol and sugar) for the third quarter and nine months was 352 million litres and 635 million litres, compared with 359 million litres and 606 million litres for the same periods in 2015.

Wind

Net wind generation capacity*(a) was 1,474MW at 30 September 2016 compared with 1,588MW at 30 September 2015. BP’s net share of wind generation for the third quarter and nine months was 828GWh and 3,235GWh respectively, compared with 894GWh and 3,171GWh for the same periods in 2015.

(a)	Capacity figures include 22.5MW in the Netherlands managed by our Downstream segment at 30 September 2016, and 32MW at 30 September 2015.

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Financial statements

Group income statement

Third	Second	Third		Nine	Nine
quarter	quarter	quarter		months	months
2015	2016	2016	$ million	2016	2015

56,152	46,442	47,047	Sales and other operating revenues (Note 6)	132,001	173,722
327	274	174	Earnings from joint ventures – after interest and tax	477	587
504	380	209	Earnings from associates – after interest and tax	731	1,536
151	101	146	Interest and other income	392	466
167	79	467	Gains on sale of businesses and fixed assets	884	438
57,301	47,276	48,043	Total revenues and other income	134,485	176,749
42,485	32,752	34,981	Purchases	94,336	127,897
6,407	10,446	5,517	Production and manufacturing expenses(a)	22,482	30,592
238	258	212	Production and similar taxes (Note 7)	484	773
3,737	3,637	3,496	Depreciation, depletion and amortization	10,863	11,338
			Impairment and losses on sale of businesses and
40	52	(1,424)	fixed assets	(1,359)	523
356	350	803	Exploration expense	1,407	1,430
2,699	2,697	2,648	Distribution and administration expenses	7,803	8,471
1,339	(2,916)	1,810	Profit (loss) before interest and taxation	(1,531)	(4,275)
398	414	433	Finance costs(a)	1,241	968
			Net finance expense relating to pensions and other
76	46	48	post-retirement benefits	140	228
865	(3,376)	1,329	Profit (loss) before taxation	(2,912)	(5,471)
809	(1,986)	(248)	Taxation(a)	(2,541)	(2,395)
56	(1,390)	1,577	Profit (loss) for the period	(371)	(3,076)
			Attributable to
46	(1,419)	1,620	BP shareholders	(382)	(3,175)
10	29	(43)	Non-controlling interests	11	99
56	(1,390)	1,577		(371)	(3,076)

			Earnings per share (Note 8)
			Profit (loss) for the period attributable to
			BP shareholders
			Per ordinary share (cents)
0.25	(7.60)	8.61	Basic	(2.05)	(17.35)
0.25	(7.60)	8.56	Diluted	(2.05)	(17.35)
			Per ADS (dollars)
0.02	(0.46)	0.52	Basic	(0.12)	(1.04)
0.02	(0.46)	0.51	Diluted	(0.12)	(1.04)

(a)	See Note 2 for information on the impact of the Gulf of Mexico oil spill on these income statement line items.

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Financial statements (continued)

Group statement of comprehensive income

Third	Second	Third		Nine	Nine
quarter	quarter	quarter		months	months
2015	2016	2016	$ million	2016	2015

56	(1,390)	1,577	Profit (loss) for the period	(371)	(3,076)
			Other comprehensive income
			Items that may be reclassified subsequently to
			profit or loss
(2,247)	(35)	192	Currency translation differences	1,031	(3,161)
			Exchange gains (losses) on translation of foreign
			operations reclassified to gain or loss on sale of
7	–	–	businesses and fixed assets	6	23
–	–	1	Available-for-sale investments	1	1
(70)	(289)	(84)	Cash flow hedges marked to market	(435)	(154)
			Cash flow hedges reclassified to the income
65	16	71	statement	110	220
7	6	30	Cash flow hedges reclassified to the balance sheet	49	16
			Share of items relating to equity-accounted
(830)	197	174	entities, net of tax	661	(581)
268	80	(78)	Income tax relating to items that may be reclassified	(84)	300
(2,800)	(25)	306		1,339	(3,336)
			Items that will not be reclassified to profit or loss
			Remeasurements of the net pension and other
(551)	(1,763)	(2,995)	post-retirement benefit liability or asset	(5,980)	1,569
			Share of items relating to equity-accounted
(1)	–	–	entities, net of tax	–	(1)
			Income tax relating to items that will not be
80	592	510	reclassified	1,504	(516)
(472)	(1,171)	(2,485)		(4,476)	1,052
(3,272)	(1,196)	(2,179)	Other comprehensive income	(3,137)	(2,284)
(3,216)	(2,586)	(602)	Total comprehensive income	(3,508)	(5,360)
			Attributable to
(3,204)	(2,604)	(558)	BP shareholders	(3,513)	(5,423)
(12)	18	(44)	Non-controlling interests	5	63
(3,216)	(2,586)	(602)		(3,508)	(5,360)

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Financial statements (continued)

Group statement of changes in equity

	BP
	shareholders’	Non-controlling	Total
$ million	equity	interests	equity

At 1 January 2016	97,216	1,171	98,387

Total comprehensive income	(3,513)	5	(3,508)
Dividends	(3,429)	(83)	(3,512)
Share-based payments, net of tax	622	–	622
Share of equity-accounted entities’ change in equity, net of tax	49	–	49
Transactions involving non-controlling interests	431	328	759
At 30 September 2016	91,376	1,421	92,797

	BP
	shareholders’	Non-controlling	Total
$ million	equity	interests	equity

At 1 January 2015	111,441	1,201	112,642

Total comprehensive income	(5,423)	63	(5,360)
Dividends	(5,118)	(71)	(5,189)
Share-based payments, net of tax	486	–	486
Share of equity-accounted entities’ change in equity, net of tax	(3)	–	(3)
Transactions involving non-controlling interests	–	23	23
At 30 September 2015	101,383	1,216	102,599

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Financial statements (continued)

Group balance sheet

	30 September	31 December
$ million	2016	2015
Non-current assets
Property, plant and equipment	128,262	129,758
Goodwill	11,204	11,627
Intangible assets	17,163	18,660
Investments in joint ventures	8,240	8,412
Investments in associates	13,326	9,422
Other investments	1,005	1,002
Fixed assets	179,200	178,881
Loans	497	529
Trade and other receivables	2,146	2,216
Derivative financial instruments	5,437	4,409
Prepayments	1,036	1,003
Deferred tax assets	4,797	1,545
Defined benefit pension plan surpluses	96	2,647
	193,209	191,230
Current assets
Loans	261	272
Inventories	15,897	14,142
Trade and other receivables	21,230	22,323
Derivative financial instruments	3,012	4,242
Prepayments	1,841	1,838
Current tax receivable	568	599
Other investments	46	219
Cash and cash equivalents	25,520	26,389
	68,375	70,024
Assets classified as held for sale (Note 3)	632	578
	69,007	70,602
Total assets	262,216	261,832
Current liabilities
Trade and other payables	34,662	31,949
Derivative financial instruments	2,325	3,239
Accruals	5,220	6,261
Finance debt	5,689	6,944
Current tax payable	1,411	1,080
Provisions	5,586	5,154
	54,893	54,627
Liabilities directly associated with assets classified as held for sale (Note 3)	148	97
	55,041	54,724
Non-current liabilities
Other payables	14,025	2,910
Derivative financial instruments	4,322	4,283
Accruals	483	890
Finance debt	53,308	46,224
Deferred tax liabilities	6,926	9,599
Provisions	23,039	35,960
Defined benefit pension plan and other post-retirement benefit plan deficits	12,275	8,855
	114,378	108,721
Total liabilities	169,419	163,445
Net assets	92,797	98,387
Equity
BP shareholders’ equity	91,376	97,216
Non-controlling interests	1,421	1,171
Total equity	92,797	98,387

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Financial statements (continued)

Condensed group cash flow statement

Third	Second	Third			Nine	Nine
quarter	quarter	quarter			months	months
2015	2016	2016	$ million		2016	2015
			Operating activities
865	(3,376)	1,329	Profit (loss) before taxation		(2,912)	(5,471)
			Adjustments to reconcile profit (loss) before taxation
			to net cash provided by operating activities
			Depreciation, depletion and amortization and
3,971	3,897	4,183	exploration expenditure written off		11,971	12,470
			Impairment and (gain) loss on sale of businesses
(127)	(27)	(1,891)	and fixed assets		(2,243)	85
			Earnings from equity-accounted entities,
(295)	(485)	259	less dividends received		(250)	(1,225)
			Net charge for interest and other finance
196	113	204	expense less net interest paid		485	338
137	204	166	Share-based payments		629	154
			Net operating charge for pensions and other post-
			retirement benefits, less contributions and
(41)	(56)	(96)	benefit payments for unfunded plans		(120)	(128)
113	4,565	(184)	Net charge for provisions, less payments		5,116	11,201
			Movements in inventories and other current and
1,231	(863)	(1,001)	non-current assets and liabilities		(3,591)	(2,135)
(867)	(89)	(461)	Income taxes paid		(822)	(1,962)
5,183	3,883	2,508	Net cash provided by operating activities		8,263	13,327
			Investing activities
(4,357)	(4,283)	(3,379)	Capital expenditure		(12,043)	(13,522)
33	–	–	Acquisitions, net of cash acquired		–	33
(55)	(8)	(1)	Investment in joint ventures		(13)	(178)
(119)	(196)	(185)	Investment in associates		(474)	(424)
88	153	590	Proceeds from disposal of fixed assets		981	1,049
			Proceeds from disposal of businesses, net of
200	291	(21)	cash disposed		1,181	1,511
61	6	9	Proceeds from loan repayments		61	109
(4,149)	(4,037)	(2,987)	Net cash used in investing activities		(10,307)	(11,422)
			Financing activities
117	2,710	3,925	Proceeds from long-term financing		9,373	7,988
(18)	(1,318)	(75)	Repayments of long-term financing		(4,952)	(2,867)
(115)	300	(512)	Net increase (decrease) in short-term debt		(324)	597
–	368	323	Net increase (decrease) in non-controlling interests		761	–
(1,718)	(1,169)	(1,161)	Dividends paid	– BP shareholders	(3,429)	(5,118)
(29)	(43)	(31)		– non-controlling interests	(83)	(71)
(1,763)	848	2,469	Net cash provided by (used in) financing activities		1,346	529
			Currency translation differences relating to cash
(158)	(226)	13	and cash equivalents		(171)	(495)
(887)	468	2,003	Increase (decrease) in cash and cash equivalents		(869)	1,939
32,589	23,049	23,517	Cash and cash equivalents at beginning of period		26,389	29,763
31,702	23,517	25,520	Cash and cash equivalents at end of period		25,520	31,702

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Financial statements (continued)

Notes

1. Basis of preparation

The interim financial information included in this report has been prepared in accordance with IAS 34 ‘Interim Financial Reporting’.

The results for the interim periods are unaudited and, in the opinion of management, include all adjustments necessary for a fair presentation of the results for each period. All such adjustments are of a normal recurring nature. This report should be read in conjunction with the consolidated financial statements and related notes for the year ended 31 December 2015 included in BP Annual Report and Form 20-F 2015.

BP prepares its consolidated financial statements included within BP Annual Report and Form 20-F on the basis of International Financial Reporting Standards (IFRS) as issued by the International Accounting Standards Board (IASB), IFRS as adopted by the European Union (EU) and in accordance with the provisions of the UK Companies Act 2006. IFRS as adopted by the EU differs in certain respects from IFRS as issued by the IASB. The differences have no impact on the group’s consolidated financial statements for the periods presented.

The financial information presented herein has been prepared in accordance with the accounting policies expected to be used in preparing BP Annual Report and Form 20-F 2016, which do not differ significantly from those used in BP Annual Report and Form 20-F 2015.

In BP Annual Report and Form 20-F 2015 we disclosed a significant estimate or judgement relating to provisions arising from the Gulf of Mexico oil spill in 2010. At that time, no reliable estimate could be made of any business economic loss (BEL) claims under the Plaintiffs’ Steering Committee (PSC) settlement that were not yet processed or processed but not yet paid, except where an eligibility notice had been issued and was not subject to appeal by BP within the Deepwater Horizon Court Supervised Settlement Program claims facility (DHCSSP). A reliable estimate could also not be made in relation to securities-related litigation and other litigation, including economic loss and property damage claims from parties excluded from and/or who opted out of the PSC settlement. No amounts were provided for these items and they were disclosed as contingent liabilities.

As a result of developments during the second quarter of 2016 sufficient information now exists in order to make a reliable estimate of the amounts that BP will pay relating to all outstanding BEL claims under the DHCSSP, securities class actions and economic loss and property damage claims from parties who were excluded from and/or opted out of the PSC settlement. Liabilities for these items were therefore recognized in the financial statements in the second quarter of 2016. See Note 2 for further information.

In BP Annual Report and Form 20-F 2015 – Financial statements – Note 1 we disclosed a significant estimate or judgement relating to the recoverability of asset values, including oil and natural gas price assumptions used to estimate future cash flows and the discount rates applied to determine the recoverable amounts of assets when performing impairment tests. During the third quarter of 2016, the price assumptions and discount rates used in impairment tests were revised.

In the third quarter, the long-term price assumptions used to determine recoverable amount based on fair value less costs of disposal from 2022 onwards were derived from $75 per barrel for Brent and $4/mmBtu for Henry Hub (both in 2015 prices) inflated for the remaining life of the asset. To determine the recoverable amount based on value in use, the price assumption was inflated to 2022 but from 2022 onwards was not inflated.

For both value-in-use and fair value less costs of disposal impairment tests performed during the third quarter, the price assumptions used have been set such that there is a gradual transition over a five-year period from current market prices to the long-term price assumptions for 2022, as noted above.

The post-tax discount rate applied to Upstream asset cash flows used to calculate fair value less costs of disposal in the third quarter was 6%. For value-in-use calculations the pre-tax discount rate applied in the third quarter was 9%. For both calculations a premium of 2% continues to be added for assets located in higher-risk countries.

See Note 4 for further information on impairment charges and reversals in the third quarter.

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Financial statements (continued)

Notes

2. Gulf of Mexico oil spill

(a) Overview

The information presented in this note should be read in conjunction with BP Annual Report and Form 20-F 2015 – Financial statements – Note 2 and Legal proceedings on page 237 and on page 31 of this report.

During the second quarter, significant progress was made in resolving outstanding claims arising from the 2010 Deepwater Horizon accident and oil spill and a reliable estimate was determined for all remaining material liabilities arising from the incident.

The group income statement includes a pre-tax charge of $189 million for the third quarter and $6,335 million for the nine months in relation to the Gulf of Mexico oil spill. The cumulative pre-tax income statement charge since the incident, in April 2010, amounts to $61,786 million. The charge for the third quarter comprises finance costs relating to unwinding of discounting effects, functional costs and other items. As previously described in BP p.l.c. Group results – Second quarter and half year 2016, it is now possible to reliably estimate the cost of resolving all outstanding business economic loss claims under the Plaintiffs’ Steering Committee (PSC) settlement and the cost of resolving economic loss and property damage claims from individuals and businesses that either opted out of the PSC settlement and/or were excluded from that settlement. The charge for the nine months is primarily attributable to the recognition of additional provisions for these claims, as well as the cost of the securities claims settlement with the certified class of post-explosion ADS purchasers which was agreed in June 2016.

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.

Third	Second	Third		Nine	Nine
quarter	quarter	quarter		months	months
2015	2016	2016	$ million	2016	2015
			Income statement
311	5,106	66	Production and manufacturing expenses	5,966	11,381
(311)	(5,106)	(66)	Profit (loss) before interest and taxation	(5,966)	(11,381)
115	123	123	Finance costs	369	132
(426)	(5,229)	(189)	Profit (loss) before taxation	(6,335)	(11,513)
(87)	2,533	53	Taxation	2,837	3,626
(513)	(2,696)	(136)	Profit (loss) for the period	(3,498)	(7,887)

	30 September	31 December
$ million	2016	2015
Balance sheet
Current assets
Trade and other receivables	330	686
Prepayments	4	–
Current liabilities
Trade and other payables	(1,979)	(693)
Accruals	–	(40)
Provisions	(3,348)	(3,076)
Net current assets (liabilities)	(4,993)	(3,123)
Non-current assets
Deferred tax assets	7,824	–
Non-current liabilities
Other payables	(13,293)	(2,057)
Accruals	–	(186)
Provisions	(1,784)	(13,431)
Deferred tax liabilities	–	5,200
Net non-current assets (liabilities)	(7,253)	(10,474)
Net assets (liabilities)	(12,246)	(13,597)

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Financial statements (continued)

Notes

2. Gulf of Mexico oil spill (continued)

Third	Second	Third		Nine	Nine
quarter	quarter	quarter		months	months
2015	2016	2016	$ million	2016	2015
			Cash flow statement - Operating activities
(426)	(5,229)	(189)	Profit (loss) before taxation	(6,335)	(11,513)
			Adjustments to reconcile profit (loss)
			before taxation to net cash provided
			by operating activities
			Net charge for interest and other finance
115	123	123	expense, less net interest paid	369	132
235	4,466	(494)	Net charge for provisions, less payments	4,729	11,069
			Movements in inventories and other current
(135)	(971)	(1,766)	and non-current assets and liabilities	(3,825)	(696)
(211)	(1,611)	(2,326)	Pre-tax cash flows	(5,062)	(1,008)

Net cash from operating activities relating to the Gulf of Mexico oil spill, on a post-tax basis, amounted to an outflow of $2,326 million and an outflow of $4,849 million in the third quarter and nine months of 2016 respectively. For the same periods in 2015, the amounts were an outflow of $196 million and an outflow of $993 million respectively.

Trust fund

During the first half of 2016, the remaining cash in the Deepwater Horizon Oil Spill Trust (the Trust) was exhausted and BP commenced paying claims and other costs previously funded from the Trust. For certain costs, these payments are made by BP into a qualified settlement fund, the fund then distributes the amounts to claimants; $835 million was paid into a qualified settlement fund during the third quarter ($2,234 million during the nine months).

(b) Provisions and contingent liabilities

Provisions

BP had 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 the third quarter, all of which relate to litigation and claims provisions, are presented in the table below.



$ million		Total
At 1 July 2016		6,490
Net increase (decrease) in provision		50
Utilization	– paid by BP	(544)
	– paid by settlement fund or Trust	(864)
At 30 September 2016		5,132
Of which	– current	3,348
	– non-current	1,784

Movements in each class of provision during the nine months are presented in the table below.

			Litigation	Clean
			and	Water Act
		Environmental	claims	penalties	Total
$ million
At 1 January 2016		5,919	6,459	4,129	16,507
Net increase (decrease) in provision		–	5,765	–	5,765
Unwinding of discount		52	25	38	115
Reclassified to Other payables		(5,970)	(3,741)	(4,167)	(13,878)
Utilization	– paid by BP	(1)	(1,035)	–	(1,036)
	– paid by settlement fund or
	Trust	–	(2,341)	–	(2,341)
At 30 September 2016		–	5,132	–	5,132

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Financial statements (continued)

Notes

2. Gulf of Mexico oil spill (continued)

Environmental

The environmental provisions relating to natural resource damage costs and the early restoration framework agreement were reclassified to Other payables during the first quarter following approval by the Court in April 2016 of the Consent Decree between the United States, the Gulf states and BP. Remaining amounts related to early restoration were paid during the second quarter.

Litigation and claims

The litigation and claims provision includes amounts for the future cost of resolving 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. Claims administration costs and legal costs have also been provided for.

At 31 December 2015, the litigation and claims provision included amounts provided under the state claims settlement agreement with the Gulf states in relation to state claims that had not yet been paid. These amounts were reclassified to Other payables during the first quarter and are payable over 18 years; $0.9 billion was paid during the third quarter.

Litigation and claims – PSC settlement

BP has provided for its best estimate of the cost associated with the 2012 PSC settlement. The provision has been determined based upon an expected value of the remaining claims, including business economic loss claims. Claims are determined by the DHCSSP in accordance with the PSC settlement agreement. Amounts to settle these claims are expected to be paid by 2019. The amounts ultimately payable may differ from the amount provided.

Litigation and claims – Other claims

An estimate of the cost of the economic loss and property damage claims from individuals and businesses that either opted out of the PSC settlement and/or were excluded from that settlement, most of which is expected to be paid by the end of 2016, is also recognized in provisions.

Clean Water Act penalties

The provision previously recognized for penalties under Section 311 of the Clean Water Act, as determined by the civil settlement with the United States, was reclassified to Other payables during the first quarter following approval by the Court of the Consent Decree. The amount is payable in instalments over 15 years, commencing April 2017. The unpaid balance of this penalty accrues interest at a fixed rate.

Further information on provisions is provided in BP Annual Report and Form 20-F 2015 – Financial statements –Note 2.

Contingent liabilities

Any further outstanding Deepwater Horizon related claims are not expected to have a material impact on the group’s financial performance.

3. Non-current assets held for sale

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

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Financial statements (continued)

Notes

4. 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 reversal for the third quarter and nine months of $1,456 million and $1,550 million respectively.

The net impairment reversal in Upstream was $1,465 million for the third quarter and $1,561 million for the nine months. For the third quarter, impairment reversals were $2,038 million offset by impairment charges of $573 million. The impairment reversals relate predominantly to assets in Angola and the North Sea, the recoverable amounts for which were calculated on a value-in-use basis.

The impairment reversals arose following a reduction in the discount rate applied and changes to future price assumptions as explained in Note 1.

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

reconciliation to profit (loss) before taxation

Third	Second	Third		Nine	Nine
quarter	quarter	quarter		months	months
2015	2016	2016	$ million	2016	2015
743	(109)	1,196	Upstream	(118)	1,343
2,562	1,405	978	Downstream	4,263	6,273
382	246	120	Rosneft	432	1,075
(689)	(5,525)	(441)	Other businesses and corporate(a)	(7,040)	(12,522)
2,998	(3,983)	1,853		(2,463)	(3,831)
67	(121)	17	Consolidation adjustment – UPII*	(64)	(101)
3,065	(4,104)	1,870	RC profit (loss) before interest and tax*	(2,527)	(3,932)
			Inventory holding gains (losses)*
(27)	85	(13)	Upstream	41	(12)
(1,687)	1,058	(35)	Downstream	926	(381)
(12)	45	(12)	Rosneft (net of tax)	29	50
1,339	(2,916)	1,810	Profit (loss) before interest and tax	(1,531)	(4,275)
398	414	433	Finance costs	1,241	968
			Net finance expense relating to pensions
76	46	48	and other post-retirement benefits	140	228
865	(3,376)	1,329	Profit (loss) before taxation	(2,912)	(5,471)

			RC profit (loss) before interest and tax
324	(5,394)	(15)	US	(6,665)	(10,814)
2,741	1,290	1,885	Non-US	4,138	6,882
3,065	(4,104)	1,870		(2,527)	(3,932)

(a)	Includes costs related to the Gulf of Mexico oil spill. See Note 2 for further information.

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Financial statements (continued)

Notes

6. Sales and other operating revenues

Third	Second	Third		Nine	Nine
quarter	quarter	quarter		months	months
2015	2016	2016	$ million	2016	2015
			By segment
10,357	8,176	8,452	Upstream	24,059	33,023
50,921	42,809	43,488	Downstream	120,849	157,106
552	422	425	Other businesses and corporate	1,243	1,492
61,830	51,407	52,365		146,151	191,621

			Less: sales and other operating revenues
			between segments
5,809	4,301	4,952	Upstream	12,886	16,962
(377)	475	175	Downstream	768	201
246	189	191	Other businesses and corporate	496	736
5,678	4,965	5,318		14,150	17,899

			Third party sales and other operating revenues
4,548	3,875	3,500	Upstream	11,173	16,061
51,298	42,334	43,313	Downstream	120,081	156,905
306	233	234	Other businesses and corporate	747	756
56,152	46,442	47,047	Total sales and other operating revenues	132,001	173,722

			By geographical area
20,680	17,701	18,853	US	50,130	61,345
39,200	32,482	31,762	Non-US	91,390	123,746
59,880	50,183	50,615		141,520	185,091
			Less: sales and other operating revenues
3,728	3,741	3,568	between areas	9,519	11,369
56,152	46,442	47,047		132,001	173,722

7. Production and similar taxes

Third	Second	Third		Nine	Nine
quarter	quarter	quarter		months	months
2015	2016	2016	$ million	2016	2015
30	67	32	US	117	97
208	191	180	Non-US	367	676
238	258	212		484	773

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Financial statements (continued)

Notes

8. Earnings per share and shares in issue

Basic earnings per ordinary share (EpS) amounts are calculated by dividing the profit for the period attributable to ordinary shareholders by the weighted average number of ordinary shares outstanding during the period.

The calculation of EpS is performed separately for each discrete quarterly period, and for the year-to-date period. As a result, the sum of the discrete quarterly EpS amounts in any particular year-to-date period may not be equal to the EpS amount for the year-to-date period.

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.

Third	Second	Third		Nine	Nine
quarter	quarter	quarter		months	months
2015	2016	2016	$ million	2016	2015
			Results for the period
			Profit (loss) for the period
46	(1,419)	1,620	attributable to BP shareholders	(382)	(3,175)
–	1	–	Less: preference dividend	1	1
			Profit (loss) attributable to BP
46	(1,420)	1,620	ordinary shareholders	(383)	(3,176)

			Number of shares (thousand)(a)(b)
			Basic weighted average number of
18,329,701	18,685,199	18,824,739	shares outstanding	18,660,397	18,304,504
3,054,950	3,114,200	3,137,456	ADS equivalent	3,110,066	3,050,750

			Weighted average number of shares
			outstanding used to calculate
18,371,656	18,685,199	18,920,920	diluted earnings per share	18,660,397	18,304,504
3,061,942	3,114,200	3,153,486	ADS equivalent	3,110,066	3,050,750

18,349,963	18,777,156	18,912,989	Shares in issue at period-end	18,912,989	18,349,963
3,058,327	3,129,526	3,152,164	ADS equivalent	3,152,164	3,058,327

(a)	Excludes treasury shares and includes certain shares that will be issued in the future under employee share-based payment plans.
(b)	If the inclusion of potentially issuable shares would decrease loss per share, the potentially issuable shares are excluded from the weighted average number of shares outstanding used to calculate diluted earnings per share.

9. Dividends

Dividends payable

BP today announced an interim dividend of 10.00 cents per ordinary share which is expected to be paid on 16 December 2016 to shareholders and American Depositary Share (ADS) holders on the register on 11 November 2016. The corresponding amount in sterling is due to be announced on 6 December 2016, calculated based on the average of the market exchange rates for the four dealing days commencing on 30 November 2016. Holders of ADSs are expected to receive $0.600 per ADS (less applicable fees). A scrip dividend alternative is available, allowing shareholders to elect to receive their dividend in the form of new ordinary shares and ADS holders in the form of new ADSs. Details of the third-quarter dividend and timetable are available at bp.com/dividends and details of the scrip dividend programme are available at bp.com/scrip.

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Financial statements (continued)

Notes

9. Dividends (continued)

Third	Second	Third		Nine	Nine
quarter	quarter	quarter		months	months
2015	2016	2016		2016	2015
			Dividends paid per ordinary share
10.000	10.000	10.000	cents	30.000	30.000
6.549	6.917	7.558	pence	21.487	19.749
60.00	60.00	60.00	Dividends paid per ADS (cents)	180.00	180.00
			Scrip dividends
18.5	134.4	130.0	Number of shares issued (millions)	418.8	53.1
110	695	714	Value of shares issued ($ million)	2,148	353

10. Net debt*

Net debt ratio*

Third	Second	Third		Nine	Nine
quarter	quarter	quarter		months	months
2015	2016	2016	$ million	2016	2015
57,405	55,727	58,997	Gross debt	58,997	57,405
			Fair value (asset) liability of hedges related
(57)	(1,279)	(1,113)	to finance debt(a)	(1,113)	(57)
57,348	54,448	57,884		57,884	57,348
31,702	23,517	25,520	Less: cash and cash equivalents	25,520	31,702
25,646	30,931	32,364	Net debt	32,364	25,646
102,599	94,108	92,797	Equity	92,797	102,599
20.0%	24.7%	25.9%	Net debt ratio	25.9%	20.0%

Analysis of changes in net debt

Third	Second	Third		Nine	Nine
quarter	quarter	quarter		months	months
2015	2016	2016	$ million	2016	2015
			Opening balance
57,104	54,012	55,727	Finance debt	53,168	52,854
			Fair value (asset) liability of hedges
315	(967)	(1,279)	related to finance debt(a)	379	(445)
32,589	23,049	23,517	Less: cash and cash equivalents	26,389	29,763
24,830	29,996	30,931	Opening net debt	27,158	22,646
			Closing balance
57,405	55,727	58,997	Finance debt	58,997	57,405
			Fair value (asset) liability of hedges
(57)	(1,279)	(1,113)	related to finance debt(a)	(1,113)	(57)
31,702	23,517	25,520	Less: cash and cash equivalents	25,520	31,702
25,646	30,931	32,364	Closing net debt	32,364	25,646
(816)	(935)	(1,433)	Decrease (increase) in net debt	(5,206)	(3,000)
			Movement in cash and cash equivalents
(729)	694	1,990	(excluding exchange adjustments)	(698)	2,434
			Net cash outflow (inflow) from financing
16	(1,692)	(3,338)	(excluding share capital and dividends)	(4,097)	(5,718)
40	36	29	Other movements	424	50
(673)	(962)	(1,319)	Movement in net debt before exchange effects	(4,371)	(3,234)
(143)	27	(114)	Exchange adjustments	(835)	234
(816)	(935)	(1,433)	Decrease (increase) in net debt	(5,206)	(3,000)

(a)

Derivative financial instruments entered into for the purpose of managing interest rate and foreign currency exchange risk associated with net debt with a fair value liability position of $1,323 million (second quarter 2016 liability of $1,440 million and third quarter 2015 liability of $1,349 million) are not included in the calculation of net debt shown above as hedge accounting is not applied for these instruments.

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Financial statements (continued)

Notes

11. Inventory valuation

A provision of $509 million was held at 30 September 2016 ($689 million at 30 June 2016 and $722 million at 30 September 2015) to write inventories down to their net realizable value. The net movement credited to the income statement during the third quarter 2016 was $178 million (second quarter 2016 was a charge of $12 million and third quarter 2015 was a charge of $144 million).

12. Statutory accounts

The financial information shown in this publication, which was approved by the Board of Directors on 31 October 2016, is unaudited and does not constitute statutory financial statements. BP Annual Report and Form 20-F 2015 has been filed with the Registrar of Companies in England and Wales. The report of the auditor on those accounts was unqualified and did not contain a statement under section 498(2) or section 498(3) of the UK Companies Act 2006.

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Additional information

Capital expenditure on an accruals basis*

Third	Second	Third		Nine	Nine
quarter	quarter	quarter		months	months
2015	2016	2016	$ million	2016	2015
			Capital expenditure on an accruals basis
4,287	3,919	3,622	Organic capital expenditure*	11,485	13,216
(33)	276	45	Inorganic capital expenditure*	321	126
4,254	4,195	3,667		11,806	13,342

Third	Second	Third		Nine	Nine
quarter	quarter	quarter		months	months
2015	2016	2016	$ million	2016	2015
			Organic capital expenditure by segment
			Upstream
1,107	754	458	US	2,272	3,205
2,673	2,699	2,642	Non-US	7,924	8,531
3,780	3,453	3,100		10,196	11,736
			Downstream
143	191	166	US	467	478
300	237	306	Non-US	698	789
443	428	472		1,165	1,267
			Other businesses and corporate
11	12	2	US	15	33
53	26	48	Non-US	109	180
64	38	50		124	213
4,287	3,919	3,622		11,485	13,216
			Organic capital expenditure by geographical area
1,261	957	626	US	2,754	3,716
3,026	2,962	2,996	Non-US	8,731	9,500
4,287	3,919	3,622		11,485	13,216

Reconciliation of additions to non-current assets to capital expenditure on an accruals basis

Third	Second	Third		Nine	Nine
quarter	quarter	quarter		months	months
2015	2016	2016	$ million	2016	2015
4,138	3,993	5,773	Additions to non-current assets(a)	13,701	13,704
8	12	7	Additions to other investments	25	19
			Element of business combinations not related to
(41)	–	–	non-current assets	–	(24)
164	190	(565)	(Additions to) reductions in decommissioning asset	(321)	(307)
(15)	–	(1,548)	Asset exchanges(b)	(1,599)	(50)
4,254	4,195	3,667	Capital expenditure on an accruals basis	11,806	13,342

(a)	Includes additions to property, plant and equipment; goodwill; intangible assets; investments in joint ventures; and investments in associates.
(b)	Third quarter and nine months 2016 principally relates to the contribution of BP’s Norwegian upstream business into Aker BP ASA in exchange for a 30% interest in Aker BP ASA.

Top of page 25

Additional information (continued)

Non-operating items*

Third	Second	Third		Nine	Nine
quarter	quarter	quarter		months	months
2015	2016	2016	$ million	2016	2015
			Upstream
			Impairment and gain (loss) on sale of businesses
(44)	–	1,908	and fixed assets(a)	1,912	(351)
(35)	–	(8)	Environmental and other provisions	(8)	(24)
(92)	(3)	(36)	Restructuring, integration and rationalization costs	(302)	(340)
40	28	8	Fair value gain (loss) on embedded derivatives	49	102
13	(18)	(407)	Other(b)	(534)	17
(118)	7	1,465		1,117	(596)
			Downstream
			Impairment and gain (loss) on sale of businesses
182	23	(11)	and fixed assets	333	316
(92)	(3)	(72)	Environmental and other provisions	(75)	(99)
(46)	(54)	(108)	Restructuring, integration and rationalization costs	(197)	(256)
–	–	–	Fair value gain (loss) on embedded derivatives	–	–
(1)	(3)	(5)	Other	(8)	(3)
43	(37)	(196)		53	(42)
			Rosneft
			Impairment and gain (loss) on sale of businesses
–	–	–	and fixed assets	–	–
–	–	–	Environmental and other provisions	–	–
–	–	–	Restructuring, integration and rationalization costs	–	–
–	–	–	Fair value gain (loss) on embedded derivatives	–	–
–	–	–	Other	–	–
–	–	–		–	–
			Other businesses and corporate
			Impairment and gain (loss) on sale of businesses
(11)	4	(6)	and fixed assets	(2)	(50)
(123)	(35)	(99)	Environmental and other provisions	(134)	(127)
(13)	(11)	(10)	Restructuring, integration and rationalization costs	(69)	(42)
–	–	–	Fair value gain (loss) on embedded derivatives	–	–
(311)	(5,106)	(66)	Gulf of Mexico oil spill(c)	(5,966)	(11,381)
–	(1)	–	Other	(55)	–
(458)	(5,149)	(181)		(6,226)	(11,600)
(533)	(5,179)	1,088	Total before interest and taxation	(5,056)	(12,238)
(115)	(123)	(123)	Finance costs(c)	(369)	(132)
(648)	(5,302)	965	Total before taxation	(5,425)	(12,370)
(108)	2,483	(16)	Taxation credit (charge)	2,777	3,715
(756)	(2,819)	949	Total after taxation for period	(2,648)	(8,655)

(a)	See Notes 1 and 4 for further information on impairment charges and reversals.
(b)	Third quarter and nine months 2016 include the write-off of $334 million in relation to the value ascribed to the BM-C-34 licence in Brazil as part of the accounting for the acquisition of upstream assets from Devon Energy in 2011 (see footnote (b) on page 5).
(c)	See Note 2 for further details regarding costs relating to the Gulf of Mexico oil spill.

Top of page 26

Additional information (continued)

Non-GAAP information on fair value accounting effects

Third	Second	Third		Nine	Nine
quarter	quarter	quarter		months	months
2015	2016	2016	$ million	2016	2015
			Favourable (unfavourable) impact relative to
			management’s measure of performance
38	(145)	(45)	Upstream	(293)	18
217	(71)	(257)	Downstream	(547)	(12)
255	(216)	(302)		(840)	6
(84)	68	81	Taxation credit (charge)	232	11
171	(148)	(221)		(608)	17

BP uses derivative instruments to manage the economic exposure relating to inventories above normal operating requirements of crude oil, natural gas and petroleum products. Under IFRS, these inventories are recorded at historical cost. The related derivative instruments, however, are required to be recorded at fair value with gains and losses recognized in income because hedge accounting is either not permitted or not followed, principally due to the impracticality of effectiveness testing requirements. Therefore, measurement differences in relation to recognition of gains and losses occur. Gains and losses on these inventories are not recognized until the commodity is sold in a subsequent accounting period. Gains and losses on the related derivative commodity contracts are recognized in the income statement, from the time the derivative commodity contract is entered into, on a fair value basis using forward prices consistent with the contract maturity.

BP enters into commodity contracts to meet certain business requirements, such as the purchase of crude for a refinery or the sale of BP’s gas production. Under IFRS these contracts are treated as derivatives and are required to be fair valued when they are managed as part of a larger portfolio of similar transactions. Gains and losses arising are recognized in the income statement from the time the derivative commodity contract is entered into.

IFRS requires that inventory held for trading is recorded at its fair value using period-end spot prices whereas any related derivative commodity instruments are required to be recorded at values based on forward prices consistent with the contract maturity. Depending on market conditions, these forward prices can be either higher or lower than spot prices resulting in measurement differences.

BP enters into contracts for pipelines and storage capacity, oil and gas processing and liquefied natural gas (LNG) that, under IFRS, are recorded on an accruals basis. These contracts are risk-managed using a variety of derivative instruments, which are fair valued under IFRS. This results in measurement differences in relation to recognition of gains and losses.

The way that BP manages the economic exposures described above, and measures performance internally, differs from the way these activities are measured under IFRS. BP calculates this difference for consolidated entities by comparing the IFRS result with management’s internal measure of performance. Under management’s internal measure of performance the inventory and capacity contracts in question are valued based on fair value using relevant forward prices prevailing at the end of the period, the fair values of certain derivative instruments used to risk manage LNG and oil and gas 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.

Third	Second	Third		Nine	Nine
quarter	quarter	quarter		months	months
2015	2016	2016	$ million	2016	2015
			Upstream
			Replacement cost profit (loss) before interest and
705	36	1,241	tax adjusted for fair value accounting effects	175	1,325
38	(145)	(45)	Impact of fair value accounting effects	(293)	18
743	(109)	1,196	Replacement cost profit before interest and tax	(118)	1,343
			Downstream
			Replacement cost profit before interest and tax
2,345	1,476	1,235	adjusted for fair value accounting effects	4,810	6,285
217	(71)	(257)	Impact of fair value accounting effects	(547)	(12)
2,562	1,405	978	Replacement cost profit before interest and tax	4,263	6,273
			Total group
			Profit (loss) before interest and tax adjusted for fair
1,084	(2,700)	2,112	value accounting effects	(691)	(4,281)
255	(216)	(302)	Impact of fair value accounting effects	(840)	6
1,339	(2,916)	1,810	Profit (loss) before interest and tax	(1,531)	(4,275)

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Additional information (continued)

Realizations and marker prices

Third	Second	Third		Nine	Nine
quarter	quarter	quarter		months	months
2015	2016	2016		2016	2015
			Average realizations(a)
			Liquids* ($/bbl)
46.22	34.89	39.16	US	34.20	47.70
47.68	43.62	42.87	Europe	39.18	53.06
41.80	55.10	42.41	Rest of World	37.95	48.77
44.01	44.99	41.23	BP Average	36.71	48.87
			Natural gas ($/mcf)
2.18	1.53	2.19	US	1.77	2.24
6.44	4.64	3.94	Europe	4.28	7.72
3.88	3.10	2.98	Rest of World	3.14	4.34
3.49	2.66	2.77	BP Average	2.76	3.91
			Total hydrocarbons* ($/boe)
32.85	24.00	27.71	US	24.15	33.62
44.76	39.25	37.10	Europe	35.19	50.78
32.05	33.90	29.41	Rest of World	28.00	36.35
33.25	30.63	29.46	BP Average	27.28	36.68
			Average oil marker prices ($/bbl)
50.47	45.59	45.86	Brent	41.88	55.31
46.45	45.53	44.88	West Texas Intermediate	41.41	50.93
31.93	33.78	31.60	Western Canadian Select	29.26	39.37
51.52	45.74	44.65	Alaska North Slope	41.58	55.39
45.34	42.08	41.83	Mars	38.14	51.34
49.19	43.37	43.73	Urals (NWE – cif)	39.67	54.20
			Average natural gas marker prices
2.77	1.95	2.81	Henry Hub gas price ($/mmBtu)(b)	2.28	2.80
41.48	31.37	31.00	UK Gas – National Balancing Point (p/therm)	30.93	44.64

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

Exchange rates

Third	Second	Third		Nine	Nine
quarter	quarter	quarter		months	months
2015	2016	2016		2016	2015
1.55	1.43	1.31	$/£ average rate for the period	1.39	1.53
1.51	1.34	1.30	$/£ period-end rate	1.30	1.51

1.11	1.13	1.12	$/€ average rate for the period	1.12	1.11
1.12	1.11	1.12	$/€ period-end rate	1.12	1.12

63.08	65.86	64.60	Rouble/$ average rate for the period	68.37	59.68
65.63	63.64	63.14	Rouble/$ period-end rate	63.14	65.63

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Glossary

Non-GAAP measures are provided for investors because they are closely tracked by management to evaluate BP’s operating performance and to make financial, strategic and operating decisions.

Adjusted effective tax rate (ETR) is a non-GAAP measure. The adjusted ETR is calculated by dividing taxation on an underlying RC basis excluding the impact of reductions in the rate of the UK North Sea supplementary charge (in the third quarter 2016 and the first quarter 2015) by underlying RC profit or loss before tax. Taxation on an underlying RC basis is taxation on a RC basis for the period adjusted for taxation on non-operating items and fair value accounting effects. Information on underlying RC profit or loss is provided below. BP believes it is helpful to disclose the adjusted ETR because this measure 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. The nearest equivalent measure on an IFRS basis is the ETR on profit or loss for the period.

Capital expenditure on an accruals basis is a non-GAAP measure. It comprises additions to property, plant and equipment, intangible assets and investments in joint ventures and associates, and reflects consideration payable in business combinations. It does not include additions arising from asset exchanges and certain other non-cash items. The nearest equivalent measure on an IFRS basis for the group is Additions to non-current assets. BP believes that Capital expenditure on an accruals basis provides useful information for investors as it is the measure used by management to plan and prioritize the group’s investment of its resources and allows investors to understand how the group balances funds between shareholder distributions and investment for the future. Further information and a reconciliation to GAAP information is provided on page 24.

Consolidation adjustment – UPII is unrealized profit in inventory arising on inter-segment transactions.

Effective tax rate (ETR) on replacement cost (RC) profit or loss is a non-GAAP measure. The ETR on RC profit or loss is calculated by dividing taxation on a RC basis by RC profit or loss before tax. Information on RC profit or loss is provided below. BP believes it is helpful to disclose the ETR on RC profit or loss because this measure excludes the impact of price changes on the replacement of inventories and allows for more meaningful comparisons between reporting periods. The nearest equivalent measure on an IFRS basis is the ETR on profit or loss for the period.

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 is provided on page 26.

Hydrocarbons – Liquids and natural gas. Natural gas is converted to oil equivalent at 5.8 billion cubic feet = 1 million barrels.

Inorganic capital expenditure is a subset of Capital expenditure on an accruals basis, which is a non-GAAP measure. Inorganic capital expenditure comprises consideration in business combinations and certain other significant investments made by the group. It is reported on an accruals basis. BP believes that this measure provides useful information as it allows investors to understand how BP’s management invests funds in projects which expand the group’s activities through acquisition. Further information and a reconciliation to GAAP information is provided on page 24.

Inventory holding gains and losses represent the difference between the cost of sales calculated using the replacement cost of inventory and the cost of sales calculated on the first-in first-out (FIFO) method after adjusting for any changes in provisions where the net realizable value of the inventory is lower than its cost. Under the FIFO method, which we use for IFRS reporting, the cost of inventory charged to the income statement is based on its historical cost of purchase or manufacture, rather than its replacement cost. In volatile energy markets, this can have a significant distorting effect on reported income. The amounts disclosed represent the difference between the charge to the income statement for inventory on a FIFO basis (after adjusting for any related movements in net realizable value provisions) and the charge that would have arisen based on the replacement cost of inventory. For this purpose, the replacement cost of inventory is calculated using data from each operation’s production and manufacturing system, either on a monthly basis, or separately for each transaction where the system allows this approach. The amounts disclosed are not separately reflected in the financial statements as a gain or loss. No adjustment is made in respect of the cost of inventories held as part of a trading position and certain other temporary inventory positions. See Replacement cost (RC) profit or loss definition below.

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

Major projects have a BP net investment of at least $250 million, or are considered to be of strategic importance to BP or of a high degree of complexity.

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Glossary (continued)

Net cash provided by operating activities excluding amounts related to the Gulf of Mexico oil spill is a non-GAAP measure calculated by excluding post-tax operating cash flows relating to the Gulf of Mexico oil spill as reported in Note 2 from Net cash provided by operating activities as reported in the Condensed group cash flow statement. BP believes it is helpful to disclose net cash provided by operating activities excluding amounts related to the Gulf of Mexico oil spill because this measure allows for more meaningful comparisons between reporting periods. The nearest equivalent measure on an IFRS basis is Net cash provided by operating activities.

Net debt and net debt ratio are non-GAAP measures. Net debt is calculated as gross finance debt, as shown in the balance sheet, plus the fair value of associated derivative financial instruments that are used to hedge foreign currency exchange and interest rate risks relating to finance debt, for which hedge accounting is applied, less cash and cash equivalents. The net debt ratio is defined as the ratio of net debt to the total of net debt plus shareholders’ equity. All components of equity are included in the denominator of the calculation. BP believes these measures provide useful information to investors. Net debt enables investors to see the economic effect of gross debt, related hedges and cash and cash equivalents in total. The net debt ratio enables investors to see how significant net debt is relative to equity from shareholders. The derivatives are reported on the balance sheet within the headings ‘Derivative financial instruments’.

Net wind generation capacity is the sum of the rated capacities of the assets/turbines that have entered into commercial operation, including BP’s share of equity-accounted entities. The gross data is the equivalent capacity on a gross-JV basis, which includes 100% of the capacity of equity-accounted entities where BP has partial ownership.

Non-operating items are charges and credits included in the financial statements that BP discloses separately because it considers such disclosures to be meaningful and relevant to investors. They are items that management considers not to be part of underlying business operations and are disclosed in order to enable investors better to understand and evaluate the group’s reported financial performance. Non-operating items within equity-accounted earnings are reported net of incremental income tax reported by the equity-accounted entity. An analysis of non-operating items by region is shown on pages 5, 7 and 9, and by segment and type is shown on page 25.

Organic capital expenditure is a subset of Capital expenditure on an accruals basis, which is a non-GAAP measure. Organic capital expenditure comprises capital expenditure on an accruals basis less inorganic capital expenditure. BP believes that this measure provides useful information as it allows investors to understand how BP’s management invests funds in developing and maintaining the group’s assets. An analysis of organic capital expenditure by segment and region, and a reconciliation to GAAP information is provided on page 24.

Production-sharing agreement (PSA) is an arrangement through which an oil company bears the risks and costs of exploration, development and production. In return, if exploration is successful, the oil company receives entitlement to variable physical volumes of hydrocarbons, representing recovery of the costs incurred and a stipulated share of the production remaining after such cost recovery.

Realizations are the result of dividing revenue generated from hydrocarbon sales, excluding revenue generated from purchases made for resale and royalty volumes, by revenue generating hydrocarbon production volumes. Revenue generating hydrocarbon production reflects the BP share of production as adjusted for any production which does not generate revenue. Adjustments may include losses due to shrinkage, amounts consumed during processing, and contractual or regulatory host committed volumes such as royalties.

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

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

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 IFRS. RC profit or loss for the group is not a recognized GAAP measure. BP 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. The nearest equivalent measure on an IFRS basis is profit or loss attributable to BP shareholders.

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Glossary (continued)

RC profit or loss per share is a non-GAAP measure. Earnings per share is defined in Note 8. RC profit or loss per share is calculated using the same denominator. The numerator used is RC profit or loss attributable to BP shareholders rather than profit or loss attributable to BP shareholders. BP believes it is helpful to disclose the RC profit or loss per share because this measure excludes the impact of price changes on the replacement of inventories and allows for more meaningful comparisons between reporting periods. The nearest equivalent measure on an IFRS basis is basic earnings per share based on profit or loss for the period attributable to BP shareholders.

Underlying production is production after adjusting for divestments and entitlement impacts in our production-sharing agreements.

Underlying RC profit or loss is RC profit or loss after adjusting for non-operating items and fair value accounting effects. Underlying RC profit or loss and adjustments for fair value accounting effects are not recognized GAAP measures. See pages 25 and 26 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 attributable to BP shareholders. The nearest equivalent measure on an IFRS basis for segments is RC profit or loss before interest and taxation.

Underlying RC profit or loss per share is a non-GAAP measure. Earnings per share is defined in Note 8. Underlying RC profit or loss per share is calculated using the same denominator. The numerator used is underlying RC profit or loss attributable to BP shareholders rather than profit or loss attributable to BP shareholders. BP believes it is helpful to disclose the underlying RC profit or loss per share because this measure 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. The nearest equivalent measure on an IFRS basis is basic earnings per share based on profit or loss for the period attributable to BP shareholders.

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Legal proceedings

The following discussion sets out the material developments in the group’s material legal proceedings during the recent period. For a full discussion of the group’s material legal proceedings, see pages 237-242 of BP Annual Report and Form 20-F 2015 and pages 33 to 34 of BP p.l.c. Group results - Second quarter and half year 2016.

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

Oil Pollution Act (OPA) Test Case Proceedings Six OPA test cases were before the federal district court in New Orleans to address certain OPA liability questions focusing on, among other issues, whether the plaintiffs’ alleged losses tied to the 2010 federal government moratoria on deepwater drilling and federal permit delays are compensable. In December 2015, BP filed a motion to dismiss the plaintiffs’ claims arising from the moratoria or permit process, and the plaintiffs filed a motion asking the court to prevent BP from arguing that government action and/or inaction following the oil spill is a “superseding” cause with respect to some or all of the damages that plaintiffs claim. On 10 March 2016, the court granted BP’s motion and denied the plaintiffs’ motion, ruling that BP is not, as a “Responsible Party” under OPA, liable for economic losses that resulted from the 2010 deepwater drilling moratoria. The court’s order dismissed the plaintiffs’ claims with prejudice. On 19 March 2016, the plaintiffs appealed the court’s ruling to the Fifth Circuit. Subsequently, BPXP settled the claims of each of the test case plaintiffs and their cases and the pending appeals to the Fifth Circuit have been dismissed.

Securities Class Action Since the Incident, shareholders have sued BP and various of its current and former officers and directors asserting class securities fraud claims. On 31 May 2016, the federal district court in Houston issued a decision on the parties’ summary judgment motions in relation to the certification of the class of post-explosion ADS purchasers from 26 April 2010 to 28 May 2010. In that decision, the court denied the plaintiffs’ motion and granted in part and denied in part BP’s motion. Following that decision, on 2 June 2016, BP announced that it agreed with the plaintiffs’ representatives to settle the post explosion class claims for the amount of $175 million, payable during 2016-2017, subject to approval by the court. The parties filed the settlement agreement and other papers in support of approval with the court on 15 September 2016, with a final hearing date for approval of the settlements to be scheduled.

ERISA In an ERISA case related to BP share funds in several employee benefit savings plans, on 15 January 2015 the federal district court in Houston allowed the plaintiffs to amend their complaint to allege some of their proposed claims against certain defendants. The district court certified that decision for appeal; the Fifth Circuit accepted that appeal on 20 May 2015. On 26 September 2016, the Fifth Circuit reversed the decision of the district court, holding that the amended complaint is insufficient to state a claim against defendants, that the district court erred in granting the plaintiffs’ motion to amend, and remanding the case to the district court for further proceedings.

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Cautionary statement

In order to utilize the ‘safe harbor’ provisions of the United States Private Securities Litigation Reform Act of 1995 (the ‘PSLRA’), BP is providing the following cautionary statement: The discussion in this results announcement contains certain forecasts, projections and forward-looking statements – that is, statements related to future, not past events – with respect to the financial condition, results of operations and businesses of BP and certain of the plans and objectives of BP with respect to these items. These statements may generally, but not always, be identified by the use of words such as ‘will’, ‘expects’, ‘is expected to’, ‘aims’, ‘should’, ‘may’, ‘objective’, ‘is likely to’, ‘intends’, ‘believes’, ‘anticipates’, ‘plans’, ‘we see’ or similar expressions. In particular, among other statements, expectations regarding the continuance of restructuring activities throughout 2017; the expected quarterly dividend payment and timing of such payment; expectations regarding the amount of organic capital expenditure for 2016 and 2017; plans and expectations regarding Upstream activities in Trinidad and Tobago and Egypt; expectations regarding the planned restructuring of the German refining joint operation with Rosneft and Rosneft’s acquisition of Bashneft ; expectations regarding Upstream fourth-quarter 2016 reported production and Downstream fourth-quarter 2016 turnaround activity and industry refining margins; statements regarding Rosneft’s profit before interest as it will be reported in Rosneft’s financial statements; expectations with respect to the total amounts that will ultimately be paid by BP in relation to the Gulf of Mexico incident and the timing thereof; statements regarding price assumptions; and certain statements regarding the legal and trial proceedings, court decisions, claims, penalties, potential investigations and civil actions by regulators, government entities and/or other entities or parties and the risks associated with such proceedings; are all forward looking in nature. By their nature, forward-looking statements involve risk and uncertainty because they relate to events and depend on circumstances that will or may occur in the future and are outside the control of BP. Actual results may differ materially from those expressed in such statements, depending on a variety of factors, including: the specific factors identified in the discussions accompanying such forward-looking statements; the receipt of relevant third party and/or regulatory approvals; the timing and level of maintenance and/or turnaround activity; the timing and volume of refinery additions and outages; the timing of bringing new fields onstream; the timing, quantum and nature of certain divestments; future levels of industry product supply, demand and pricing, including supply growth in North America; OPEC quota restrictions; PSA effects; operational and safety problems; potential lapses in product quality; economic and financial market conditions generally or in various countries and regions; political stability and economic growth in relevant areas of the world; changes in laws and governmental regulations; regulatory or legal actions including the types of enforcement action pursued and the nature of remedies sought or imposed; the actions of prosecutors, regulatory authorities and courts; exchange rate fluctuations; development and use of new technology; recruitment and retention of a skilled workforce; the success or otherwise of partnering; the actions of competitors, trading partners, contractors, subcontractors, creditors, rating agencies and others; our access to future credit resources; business disruption and crisis management; the impact on our reputation of ethical misconduct and non-compliance with regulatory obligations; trading losses; major uninsured losses; decisions by Rosneft’s management and board of directors; the actions of contractors; natural disasters and adverse weather conditions; changes in public expectations and other changes to business conditions; wars and acts of terrorism; cyber-attacks or sabotage; and other factors discussed under “Principal risks and uncertainties” in our Form 6-K for the period ended 30 June 2016 and under “Risk factors” in BP Annual Report and Form 20-F 2015 as filed with the US Securities and Exchange Commission.

Contacts

	London	Houston

Press Office	David Nicholas	Brett Clanton
	+44 (0)20 7496 4708	+1 281 366 8346

Investor Relations	Jessica Mitchell	Craig Marshall
bp.com/investors	+44 (0)20 7496 4962	+1 281 892 4312

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: 01 November 2016
	/s/ J. BERTELSEN
	------------------------
	J. BERTELSEN
	Deputy Company Secretary