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 29 October, 2019

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|

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		Top of page 1
FOR IMMEDIATE RELEASE
London 29 October 2019

BP p.l.c. Group results
Third quarter and nine months 2019

For a printer friendly copy of this announcement, please click on the link below to open a PDF version

http://www.rns-pdf.londonstockexchange.com/rns/3914R_1-2019-10-28.pdf

Highlights

Continued strong operating cash flow and strategic delivery

●

Financial results

Underlying replacement cost profit for the third quarter of 2019 was $2.3 billion, compared to $3.8 billion a year earlier. The result was impacted by significantly lower Upstream earnings, resulting from lower prices, maintenance and weather impacts.

A divestment-related, non-cash, non-operating after-tax charge of $2.6 billion resulted in a reported loss for the quarter of $0.7 billion.

Operating cash flow, excluding Gulf of Mexico oil spill payments, was $6.5 billion for the quarter, including a $0.1 billion working capital release (after adjusting for net inventory holding losses). Gulf of Mexico oil spill payments were $0.4 billion on a post-tax basis.

A dividend of 10.25 cents per share was announced for the quarter. Scrip dividend alternative suspended for the third quarter.

● Upstream operations impacted by maintenance and weather, Downstream strong

Reported oil and gas production for the quarter averaged 3.7 million barrels of oil equivalent a day, compared to 3.6 million barrels of oil equivalent a day a year earlier.

Underlying Upstream production, excluding Rosneft, was down 2.5% from a year earlier, reflecting maintenance across a number of regions and weather impacts in the US Gulf of Mexico.

The Downstream delivered strong operations with overall 96% Solomon availability for the quarter, and record crude was processed at the Whiting and Cherry Point refineries in the US.

●

Divestments ahead of schedule, Downstream expansion in fast-growing markets

Following the agreement to sell all BP’s interests in Alaska to Hilcorp Energy, divestment transactions announced in 2019 totalled $7.2 billion at the end of the third quarter. BP expects this to reach around $10 billion by year end.

In the Downstream, BP continued its strategic delivery in new markets, announcing joint ventures in fuels marketing in India and electric vehicle charging in China.

In the quarter BP announced that it will deploy continuous measurement of methane emissions on all its future major operated oil and gas processing projects.

See chart on PDF

Bob Dudley – Group chief executive:

BP delivered strong operating cash flow and underlying earnings in a quarter that saw lower oil and gas prices and significant hurricane impacts. Our focus remains firmly on maintaining financial discipline and delivering safe and reliable operations throughout BP. We’re also continuing to advance our strategy, making strong progress with our divestment plans and building exciting new opportunities in fast-growing downstream markets in Asia.

Financial summary	Third		Second		Third		Nine		Nine
	quarter		quarter		quarter		months		months
$ million	2019		2019		2018		2019		2018
Profit (loss) for the period attributable to BP shareholders	(749	)	1,822		3,349		4,007		8,617
Inventory holding (gains) losses, net of tax	398		(47	)	(258	)	(488	)	(1,348	)
RC profit (loss)	(351	)	1,775		3,091		3,519		7,269
Net (favourable) adverse impact of non-operating items and fair value accounting effects, net of tax	2,605		1,036		747		3,904		1,977
Underlying RC profit	2,254		2,811		3,838		7,423		9,246
RC profit (loss) per ordinary share (cents)	(1.72	)	8.72		15.45		17.33		36.42
RC profit (loss) per ADS (dollars)	(0.10	)	0.52		0.93		1.04		2.19
Underlying RC profit per ordinary share (cents)	11.06		13.82		19.18		36.57		46.32
Underlying RC profit per ADS (dollars)	0.66		0.83		1.15		2.19		2.78

RC profit (loss), underlying RC profit, operating cash flow excluding Gulf of Mexico oil spill payments and working capital are non-GAAP measures. These measures and underlying production, Solomon availability, inventory holding gains and losses, non-operating items and fair value accounting effects are defined in the Glossary on page 32.

The commentary above and following should be read in conjunction with the cautionary statement on page 36.

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Group headlines

Results

For the nine months, underlying replacement cost (RC) profit* was $7,423 million, compared with $9,246 million in 2018. Underlying RC profit is after adjusting RC profit* for a net charge for non-operating items* of $4,044 million and net favourable fair value accounting effects* of $140 million (both on a post-tax basis).

RC profit was $3,519 million for the nine months, compared with $7,269 million in 2018.

For the third quarter, underlying RC profit was $2,254 million, compared with $3,838 million in 2018. Underlying RC profit is after adjusting RC loss for a net charge for non-operating items of $2,931 million, primarily divestment-related impairment charges (see Note 3 and page 27), and net favourable fair value accounting effects of $326 million (both on a post-tax basis).

RC loss was $351 million for the third quarter, compared with a profit of $3,091 million in 2018.

BP’s reported result for the third quarter and nine months was a loss of $749 million and a profit of $4,007 million respectively, compared with a profit of $3,349 million and $8,617 million for the same periods in 2018.

See further information on pages 3, 27 and 28.

Depreciation, depletion and amortization

The charge for depreciation, depletion and amortization was $4.3 billion in the quarter and $13.3 billion in the nine months. In the same periods in 2018 it was $3.7 billion and $11.5 billion respectively (prior to the implementation of IFRS 16). In 2019, we expect the full-year charge to be around $18 billion.

Effective tax rate

The effective tax rate (ETR) on RC profit or loss* for the third quarter and nine months was 168% and 49% respectively, compared with 38% and 41% for the same periods in 2018. Adjusting for non-operating items and fair value accounting effects, the underlying ETR* for the third quarter and nine months was 40% and 38% respectively, compared with 36% and 38% for the same periods a year ago. The higher underlying ETR for the third quarter reflects deferred tax charges due to foreign exchange impacts. In the current environment the underlying ETR in 2019 is expected to be around 40%. ETR on RC profit or loss and underlying ETR are non-GAAP measures.

Dividend

BP today announced a quarterly dividend of 10.25 cents per ordinary share ($0.615 per ADS), which is expected to be paid on 20 December 2019. The corresponding amount in sterling will be announced on 9 December 2019. BP also announced that the board has suspended the scrip dividend alternative in respect of the third quarter 2019 dividend. Dividend reinvestment plans will be introduced effective from this third quarter dividend. See page 23 for further information.

Share buybacks

BP repurchased 34 million ordinary shares at a cost of $215 million, including fees and stamp duty, during the third quarter of 2019. For the nine months, BP repurchased 52 million ordinary shares at a cost of $340 million, including fees and stamp duty. Our share buyback programme is expected to fully offset the impact of scrip dilution since the third quarter 2017 by the end of 2019.

Operating cash flow*

Operating cash flow excluding Gulf of Mexico oil spill payments* was $6.5 billion for the third quarter and $20.6 billion for the nine months. These amounts include a working capital* release of $0.1 billion in the third quarter and $0.6 billion in the nine months, after adjusting for net inventory holding losses or gains* and working capital effects of the Gulf of Mexico oil spill. The comparable amounts for the same periods in 2018 were $6.6 billion and $19.0 billion (prior to the implementation of IFRS 16).

Operating cash flow as reported in the group cash flow statement was $6.1 billion for the third quarter and $18.2 billion for the nine months. These amounts include a working capital release of $141 million and build of $2.6 billion respectively. The comparable amounts for the same periods in 2018 were $6.1 billion and $16.0 billion (prior to the implementation of IFRS 16).

See page 30 and Glossary for further information on Gulf of Mexico oil spill cash flows and on working capital.

Capital expenditure*

Organic capital expenditure* for the third quarter and nine months was $3.9 billion and $11.3 billion respectively. We reported $3.7 billion and $10.7 billion for the same periods in 2018 (prior to the implementation of IFRS 16).

Inorganic capital expenditure* for the third quarter and nine months was $0.1 billion and $4.0 billion respectively, including $3.5 billion for the nine months relating to the BHP acquisition, compared with $0.7 billion and $1.5 billion for the same periods in 2018.

Organic capital expenditure and inorganic capital expenditure are non-GAAP measures. See page 26 for further information.

Divestment and other proceeds

Divestment proceeds* were $0.7 billion for the third quarter and $1.4 billion for the nine months, compared with $0.1 billion and $0.4 billion for the same periods in 2018.

Gearing*

Net debt* at 30 September 2019 was $46.5 billion, compared with $38.5 billion a year ago. Gearing at 30 September 2019 was 31.7%, compared with 27.1% a year ago. Net debt and gearing are non-GAAP measures. See page 23 for more information.

Brian Gilvary – Chief financial officer:

BP’s third quarter results demonstrate the resilience of our financial performance, even at lower prices. Net debt stayed flat in the quarter, though gearing rose slightly following a reduction in equity as a result of divestment-related impairment charges. With growing free cash flow and receipt of disposal proceeds, we continue to expect net debt to trend down over time. In addition, the underlying effective tax rate for the quarter was lower than previously indicated, mainly due to higher-than-expected estimated Rosneft earnings and a lower-than-expected impact from the Upstream profit mix.

* For items marked with an asterisk throughout this document, definitions are provided in the Glossary on page 32.

For more information on the impact of IFRS 16 'Leases' on key financial metrics, see page 25.

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

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Analysis of underlying RC profit* before interest and tax

	Third		Second		Third		Nine		Nine
	quarter		quarter		quarter		months		months
$ million	2019		2019		2018		2019		2018
Underlying RC profit before interest and tax
Upstream	2,139		3,413		3,999		8,480		10,664
Downstream	1,883		1,365		2,111		4,981		5,392
Rosneft	802		638		872		2,007		1,885
Other businesses and corporate	(322	)	(290	)	(345	)	(1,030	)	(1,214	)
Consolidation adjustment – UPII*	30		34		78		51		69
Underlying RC profit before interest and tax	4,532		5,160		6,715		14,489		16,796
Finance costs and net finance expense relating to pensions and other post-retirement benefits	(754	)	(752	)	(610	)	(2,260	)	(1,522	)
Taxation on an underlying RC basis	(1,506	)	(1,515	)	(2,213	)	(4,641	)	(5,838	)
Non-controlling interests	(18	)	(82	)	(54	)	(165	)	(190	)
Underlying RC profit attributable to BP shareholders	2,254		2,811		3,838		7,423		9,246

Reconciliations of underlying RC profit or loss to the nearest equivalent IFRS measure are provided on page 1 for the group and on pages 6-11 for the segments.

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
$ million	2019		2019		2018		2019		2018
RC profit before interest and tax
Upstream	(1,050	)	2,469		3,472		4,303		10,160
Downstream	2,016		1,288		2,249		5,069		4,802
Rosneft	802		525		808		1,813		1,821
Other businesses and corporate	(412	)	(381	)	(815	)	(1,339	)	(2,411	)
Consolidation adjustment – UPII	30		34		78		51		69
RC profit before interest and tax	1,386		3,935		5,792		9,897		14,441
Finance costs and net finance expense relating to pensions and other post-retirement benefits	(899	)	(868	)	(729	)	(2,649	)	(1,879	)
Taxation on a RC basis	(820	)	(1,210	)	(1,918	)	(3,564	)	(5,103	)
Non-controlling interests	(18	)	(82	)	(54	)	(165	)	(190	)
RC profit (loss) attributable to BP shareholders	(351	)	1,775		3,091		3,519		7,269
Inventory holding gains (losses)*	(512	)	81		371		657		1,773
Taxation (charge) credit on inventory holding gains and losses	114		(34	)	(113	)	(169	)	(425	)
Profit (loss) for the period attributable to BP shareholders	(749	)	1,822		3,349		4,007		8,617

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Strategic progress

Upstream

Upstream production for the third quarter, which excludes Rosneft, was 2,568mboe/d, 4.4% higher than a year earlier. Underlying production*, adjusted for portfolio changes and PSA* impact, decreased by 2.5% due to increased maintenance and the impact of Hurricane Barry in the US Gulf of Mexico.

In July BP deepened its presence in Oman, signing an exploration and production sharing contract together with Eni for Block 77 in Oman, east of the BP-operated Block 61.

In October BP added to its position in the pre-salt region offshore Brazil, accessing two new blocks in the Santos and Campos basins.

BP announced in August that it has agreed to sell its interests in Alaska to a subsidiary of Hilcorp Energy for a total consideration of $5.6 billion. Subject to regulatory approval, the

transaction is expected to complete in 2020.

Downstream

During the quarter BP announced an agreement to form a new joint venture in India with Reliance Industries Limited. This will build on Reliance’s current retail network of over 1,400 sites across India and includes access to the country’s fast-growing aviation fuels market.

BP also recently announced the development of BP Infinia, an enhanced recycling technology capable of processing currently unrecyclable PET plastic waste into recycled feedstock.

Advancing the energy transition

In the quarter BP continued to progress its advanced mobility agenda, announcing an agreement with DiDi, the world’s leading mobile transportation platform, to develop an electric vehicle charging network in China, the world’s largest market for electric vehicles.

In the UK BP Chargemaster has installed the first 150kW ultra-fast electric chargers at BP retail sites, the start of a roll out of 400 such chargers across the country over the next two years.

BP continues to take steps to limit operational emissions of methane, including announcing that it will deploy continuous measurement of methane emissions through technologies such as gas cloud imaging (GCI) on all future major BP-operated oil and gas processing projects.

Financial framework

Following the introduction of IFRS 16 on 1 January 2019, the positive impacts on Operating cash flow* and Organic capital expenditure* are fully offset in the cash flow statement by a new line, Lease liability payments. Lease payments are now included in the definition of free cash flow* as a use of cash, which means the net impact on this measure is zero.

Operating cash flow excluding Gulf of Mexico oil spill payments* was $20.6 billion for the nine months of 2019. For the nine months of 2018, we reported $19.0 billion (prior to the implementation of IFRS 16).

Organic capital expenditure for the nine months of 2019 was $11.3 billion. BP expects 2019 organic capital expenditure to be under $16 billion.

Lease liability payments of principal for the nine months of 2019 were $1.8 billion.

Divestment transactions announced totalled $7.2 billion in the nine months of 2019. BP expects this total to reach around $10 billion by the end of 2019.

Gulf of Mexico oil spill payments on a post-tax basis totalled $2.5 billion in the nine months. Payments for the full year continue to be expected to be around $2 billion on a post-tax basis.

Gearing* at the end of the nine months was 31.7%. See page 23 for more information. We expect gearing to remain above the target 20-30% range through 2019, before reducing towards the middle of the targeted range in 2020, assuming recent average oil prices.

Safety

Tier 1 and tier 2 process safety events* increased in the first nine months of 2019 compared with the same period in 2018. The increase related to both tier 1 and tier 2 events and includes performance in assets acquired over the past year. Safety remains our number one priority and we continue to be focused on working to reduce all process safety events.

Operating metrics	Nine months 2019	Financial metrics	Nine months 2019
Operating metrics	(vs. Nine months 2018)	Financial metrics	(vs. Nine months 2018)
Tier 1 and tier 2 process safety events	73	Underlying RC profit*	$7.4bn
Tier 1 and tier 2 process safety events	(+23)	Underlying RC profit*	(-$1.8bn)
Reported recordable injury frequency*	0.18	Operating cash flow excluding Gulf of Mexico oil spill payments (post-tax)(b)	$20.6bn
Reported recordable injury frequency*	(-13%)		(+$1.6bn)
Group production	3,758mboe/d	Organic capital expenditure	$11.3bn
Group production	(+3.1%)	Organic capital expenditure	(+$0.5bn)
Upstream production (excludes Rosneft segment)	2,616mboe/d	Gulf of Mexico oil spill payments (post-tax)	$2.5bn
Upstream production (excludes Rosneft segment)	(+4.2%)	Gulf of Mexico oil spill payments (post-tax)	(-$0.5bn)
Upstream unit production costs*(a)	$7.02/boe	Divestment proceeds*	$1.4bn
Upstream unit production costs*(a)	(-3.5%)	Divestment proceeds*	(+$1.0bn)
BP-operated Upstream plant reliability*	94.4%	Gearing	31.7%
BP-operated Upstream plant reliability*	(-1.2)	Gearing	(+4.6)
BP-operated refining availability*	94.6%	Dividend per ordinary share(c)	10.25 cents
BP-operated refining availability*	(-0.2)	Dividend per ordinary share(c)	(—%)

(a)

Slight increase from the same period in 2018 after excluding the impacts of IFRS 16 on production costs.

(b)

Nine months 2019 includes estimated $1.5 billion impact due to IFRS 16.

(c)

Represents dividend announced in the quarter (vs. prior year quarter).

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

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Upstream

	Third		Second	Third		Nine	Nine
	quarter		quarter	quarter		months	months
$ million	2019		2019	2018		2019	2018
Profit (loss) before interest and tax	(1,050	)	2,459	3,473		4,295	10,166
Inventory holding (gains) losses*	—		10	(1	)	8	(6	)
RC profit (loss) before interest and tax	(1,050	)	2,469	3,472		4,303	10,160
Net (favourable) adverse impact of non-operating items* and fair value accounting effects*	3,189		944	527		4,177	504
Underlying RC profit before interest and tax*(a)	2,139		3,413	3,999		8,480	10,664

(a)

See page 7 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 loss of $1,050 million and a profit of $4,303 million respectively, compared with a profit of $3,472 million and $10,160 million for the same periods in 2018. The third quarter and nine months included a net non-operating charge of $3,454 million and $4,224 million respectively, compared with a net charge of $242 million and $319 million for the same periods in 2018. The net non-operating charge for the quarter is primarily related to impairments associated with the disposal of heritage BPX Energy assets and Alaska (see Note 3 for further information). Fair value accounting effects in the third quarter and nine months had a favourable impact of $265 million and $47 million respectively, compared with an adverse impact of $285 million and $185 million in the same periods of 2018.

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 $2,139 million and $8,480 million respectively, compared with $3,999 million and $10,664 million for the same periods in 2018. The results for the third quarter and nine months mainly reflected lower liquids and gas realizations, higher depreciation, depletion and amortization, the impact of the divestment in the Greater Kuparuk Area in Alaska, and lower production due to seasonal turnaround and maintenance activities and Hurricane Barry in the US Gulf of Mexico, partly offset by higher gas marketing and trading.

Production

Production for the quarter was 2,568mboe/d, 4.4% higher than the third quarter of 2018. Underlying production* for the quarter decreased by 2.5%, mainly due to increased seasonal turnaround and maintenance activities, and weather impacts resulting from Hurricane Barry in the US Gulf of Mexico.

For the nine months, production was 2,616mboe/d, 4.2% higher than 2018. Underlying production for the nine months was 1.0% lower than 2018, mainly due to increased seasonal turnaround and maintenance activities, and weather impacts resulting from Hurricane Barry in the US Gulf of Mexico.

Key events

On 31 July, BP and Eni signed an exploration and production-sharing agreement for Block 77 in central Oman with the Ministry of Oil and Gas of the Sultanate of Oman (Eni operator 50%, BP 50%).

On 27 August, BP announced an agreement to sell its entire interests in Alaska to Hilcorp Energy including upstream and midstream businesses. Subject to regulatory approval, the transaction is expected to complete in 2020.

On 17 September, BP confirmed the start-up of the offshore Baltim South West gas field in Egypt (Eni operator 50%, BP 50%).

On 27 September, BP confirmed the award of the WA-541 acreage permit in Western Australia’s offshore Northern Carnarvon basin (Santos operator 50%, BP 50%).

On 10 October, BP was awarded production and exploration rights for two blocks offshore Brazil in the Santos (BP 100%) and the Campos Basins (Petrobras operator 70%, BP 30%).

On 17 October, BP confirmed the Boom-1 exploration well, located offshore Trinidad and Tobago, encountered hydrocarbons. Evaluation and analysis is on-going. (BHP operator 70%, BP 30%).

On 28 October, Kosmos Energy announced the successful result of the Orca-1 exploration well located in block C8 in the Bir Allah appraisal area offshore Mauritania (BP operator 62%, Kosmos Energy 28% and SMHPM 10%).

Outlook

Looking ahead, we expect fourth quarter 2019 reported production to be higher than third quarter due to completion of seasonal maintenance and turnaround activities.

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

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Upstream (continued)

	Third		Second		Third		Nine		Nine
	quarter		quarter		quarter		months		months
$ million	2019		2019		2018		2019		2018
Underlying RC profit before interest and tax
US	552		861		1,025		2,025		2,293
Non-US	1,587		2,552		2,974		6,455		8,371
	2,139		3,413		3,999		8,480		10,664
Non-operating items(a)
US	(3,338	)	(446	)	(149	)	(3,814	)	(323	)
Non-US	(116	)	(320	)	(93	)	(410	)	4
	(3,454	)	(766	)	(242	)	(4,224	)	(319	)
Fair value accounting effects
US	19		(225	)	(10	)	(299	)	(162	)
Non-US	246		47		(275	)	346		(23	)
	265		(178	)	(285	)	47		(185	)
RC profit (loss) before interest and tax
US	(2,767	)	190		866		(2,088	)	1,808
Non-US	1,717		2,279		2,606		6,391		8,352
	(1,050	)	2,469		3,472		4,303		10,160
Exploration expense
US	53		69		39		147		425
Non-US	132		77		271		551		563
	185		146		310		698		988
Of which: Exploration expenditure written off	115		77		227		476		734
Production (net of royalties)(b)
Liquids* (mb/d)
US	449		506		424		470		428
Europe	118		137		128		138		138
Rest of World	657		658		663		667		684
	1,224		1,301		1,216		1,274		1,250
Natural gas (mmcf/d)
US	2,396		2,410		1,805		2,372		1,780
Europe	188		132		212		155		210
Rest of World	5,211		5,138		5,201		5,254		5,317
	7,795		7,680		7,218		7,782		7,307
Total hydrocarbons* (mboe/d)
US	862		921		736		879		734
Europe	151		160		165		165		175
Rest of World	1,555		1,544		1,560		1,573		1,601
	2,568		2,625		2,460		2,616		2,510
Average realizations*(c)
Total liquids(d) ($/bbl)	55.68		62.63		69.68		58.38		66.11
Natural gas ($/mcf)	3.11		3.35		3.86		3.49		3.77
Total hydrocarbons ($/boe)	35.48		40.64		46.14		38.55		43.64

(a)

Third quarter and nine months 2019 include impairment charges related to the disposal of heritage BPX Energy assets, Alaska and GUPCO.

(b)

Includes BP’s share of production of equity-accounted entities in the Upstream segment.

(c)

Realizations are based on sales by consolidated subsidiaries only - this excludes equity-accounted entities.

(d)

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
$ million	2019		2019		2018		2019		2018
Profit (loss) before interest and tax	1,583		1,381		2,592		5,775		6,410
Inventory holding (gains) losses*	433		(93	)	(343	)	(706	)	(1,608	)
RC profit before interest and tax	2,016		1,288		2,249		5,069		4,802
Net (favourable) adverse impact of non-operating items* and fair value accounting effects*	(133	)	77		(138	)	(88	)	590
Underlying RC profit before interest and tax*(a)	1,883		1,365		2,111		4,981		5,392

(a)

See page 9 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 $2,016 million and $5,069 million respectively, compared with $2,249 million and $4,802 million for the same periods in 2018.

The third quarter and nine months include a net non-operating charge of $14 million and $49 million respectively, compared with a charge of $37 million and $315 million for the same periods in 2018. Fair value accounting effects had a favourable impact of $147 million in the third quarter and a favourable impact of $137 million in the nine months, compared with a favourable impact of $175 million in the third quarter and an adverse impact of $275 million in the nine months in 2018.

Replacement cost profit before interest and tax for the fuels, lubricants and petrochemicals businesses is set out on page 9.

Fuels

The fuels business reported an underlying replacement cost profit before interest and tax of $1,438 million for the third quarter and $3,691 million for the nine months, compared with $1,566 million and $4,018 million for the same periods in 2018. The result for the quarter and nine months reflects significantly lower refining margins, primarily driven by the impact of narrower heavy crude oil discounts, partially offset by fuels marketing growth, strong refining operations and a higher contribution from supply and trading. The result for the nine months was also impacted by higher levels of turnaround activity.

During the quarter we announced an agreement to form a new joint venture in India with Reliance Industries Limited. This will build on Reliance’s current retail network of over 1,400 sites across India and includes access to India’s fast-growing aviation fuels market.

We also announced an agreement with DiDi to build an electric vehicle charging network in China, the world’s largest market for electric vehicles. This builds on the acquisition of BP Chargemaster in the UK last year, progressing our strategy to create the fastest and most convenient electrification network.

Lubricants

The lubricants business reported an underlying replacement cost profit before interest and tax of $332 million for the third quarter and $925 million for the nine months, compared with $324 million and $981 million for the same periods in 2018. The result for the nine months primarily reflects the impact of adverse foreign exchange rate movements. We also recently announced a partnership with Bosch to run jointly branded workshop pilots in China and the US.

Petrochemicals

The petrochemicals business reported an underlying replacement cost profit before interest and tax of $113 million for the third quarter and $365 million for the nine months, compared with $221 million and $393 million for the same periods in 2018. The result for the quarter and nine months reflects a weaker margin environment. The result for the nine months also reflects stronger operational performance and lower turnaround activity. We recently signed a memorandum of understanding to explore the creation of a new world-scale joint venture partnership with Zhejiang Petroleum and Chemical Corporation for a 1 million tonne per annum acetic acid plant in Zhejiang Province, China. We also recently announced the development of BP Infinia, an enhanced recycling technology capable of processing currently unrecyclable PET plastic waste into recycled feedstock. This is an important step in BP’s commitment to advancing circularity in the polyester value chain.

Outlook

Looking to the fourth quarter of 2019, we expect a similar level of turnaround activity and seasonally lower industry refining margins compared with the third quarter.

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

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Downstream (continued)

	Third		Second		Third		Nine		Nine
	quarter		quarter		quarter		months		months
$ million	2019		2019		2018		2019		2018
Underlying RC profit before interest and tax - by region
US	537		566		835		1,634		1,823
Non-US	1,346		799		1,276		3,347		3,569
	1,883		1,365		2,111		4,981		5,392
Non-operating items
US	(5	)	2		(14	)	(2	)	(186	)
Non-US	(9	)	(33	)	(23	)	(47	)	(129	)
	(14	)	(31	)	(37	)	(49	)	(315	)
Fair value accounting effects(a)
US	116		8		81		185		(339	)
Non-US	31		(54	)	94		(48	)	64
	147		(46	)	175		137		(275	)
RC profit before interest and tax
US	648		576		902		1,817		1,298
Non-US	1,368		712		1,347		3,252		3,504
	2,016		1,288		2,249		5,069		4,802
Underlying RC profit before interest and tax - by business(b)(c)
Fuels	1,438		961		1,566		3,691		4,018
Lubricants	332		321		324		925		981
Petrochemicals	113		83		221		365		393
	1,883		1,365		2,111		4,981		5,392
Non-operating items and fair value accounting effects(a)
Fuels	135		(99	)	140		73		(554	)
Lubricants	—		22		—		18		(29	)
Petrochemicals	(2	)	—		(2	)	(3	)	(7	)
	133		(77	)	138		88		(590	)
RC profit before interest and tax(b)(c)
Fuels	1,573		862		1,706		3,764		3,464
Lubricants	332		343		324		943		952
Petrochemicals	111		83		219		362		386
	2,016		1,288		2,249		5,069		4,802

BP average refining marker margin (RMM)* ($/bbl)	14.7		15.2		14.7		13.4		13.8

Refinery throughputs (mb/d)
US	781		673		740		730		707
Europe	815		715		805		766		796
Rest of World	217		209		248		221		242
	1,813		1,597		1,793		1,717		1,745
BP-operated refining availability* (%)	96.1		93.4		96.4		94.6		94.8

Marketing sales of refined products (mb/d)
US	1,172		1,174		1,169		1,141		1,142
Europe	1,157		1,091		1,166		1,081		1,116
Rest of World	459		520		497		500		485
	2,788		2,785		2,832		2,722		2,743
Trading/supply sales of refined products	3,157		3,099		3,147		3,183		3,192
Total sales volumes of refined products	5,945		5,884		5,979		5,905		5,935

Petrochemicals production (kte)
US	564		584		660		1,749		1,563
Europe	1,187		1,226		1,209		3,573		3,431
Rest of World	1,325		1,156		1,146		3,780		3,896
	3,076		2,966		3,015		9,102		8,890

(a)

For Downstream, fair value accounting effects arise solely in the fuels business. See page 28 for further information.

(b)

Segment-level overhead expenses are included in the fuels business result.

(c)

Results from petrochemicals at our Gelsenkirchen and Mülheim sites in Germany are reported in the fuels business.

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Rosneft

	Third	Second	Third		Nine	Nine
	quarter	quarter	quarter		months	months
$ million	2019(a)	2019	2018		2019(a)	2018
Profit before interest and tax(b)(c)	723	523	835		1,772	1,980
Inventory holding (gains) losses*	79	2	(27	)	41	(159	)
RC profit before interest and tax	802	525	808		1,813	1,821
Net charge (credit) for non-operating items*	—	113	64		194	64
Underlying RC profit before interest and tax*	802	638	872		2,007	1,885

Financial results

Replacement cost (RC) profit before interest and tax for the third quarter and nine months was $802 million and $1,813 million respectively, compared with $808 million and $1,821 million for the same periods in 2018.

After adjusting for non-operating items, the underlying RC profit before interest and tax for the third quarter and nine months was $802 million and $2,007 million respectively, compared with $872 million and $1,885 million for the same periods in 2018. There were no non-operating items in the third quarter of 2019.

Compared with the same period in 2018, the result for the third quarter primarily reflects lower oil prices, partially offset by higher sales volumes. Compared with the same period in 2018, the result for the nine months primarily reflects favourable foreign exchange effects and higher sales volumes, partially offset by lower oil prices.

The extraordinary general meeting held on 30 September adopted a resolution to pay interim dividends of 15.34 roubles per ordinary share which constitute 50% of Rosneft’s IFRS net profit for the first half of 2019. BP expects to receive dividends of 28.9 billion roubles (net of withholding tax) in the fourth quarter.

	Third	Second	Third	Nine	Nine
	quarter	quarter	quarter	months	months
	2019(a)	2019	2018	2019(a)	2018
Production (net of royalties) (BP share)
Liquids* (mb/d)	920	912	933	923	915
Natural gas (mmcf/d)	1,236	1,250	1,260	1,271	1,276
Total hydrocarbons* (mboe/d)	1,133	1,127	1,151	1,142	1,135

(a)

The operational and financial information of the Rosneft segment for the third quarter and nine months is based on preliminary operational and financial results of Rosneft for the three months and nine months ended 30 September 2019. 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 divestment of BP’s interest in TNK-BP. These adjustments increase the segment's reported profit before interest and tax, as shown in the table above, compared with the amounts reported in Rosneft’s IFRS financial statements.

(c)

BP’s adjusted share of Rosneft’s earnings after Rosneft's own finance costs, taxation and non-controlling interests is included in the BP group income statement within profit before interest and taxation. For each year-to-date period it is calculated by translating the amounts reported in Russian roubles into US dollars using the average exchange rate for the year to date.

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Other businesses and corporate

	Third		Second		Third		Nine		Nine
	quarter		quarter		quarter		months		months
$ million	2019		2019		2018		2019		2018
Profit (loss) before interest and tax	(412	)	(381	)	(815	)	(1,339	)	(2,411	)
Inventory holding (gains) losses*	—		—		—		—		—
RC profit (loss) before interest and tax	(412	)	(381	)	(815	)	(1,339	)	(2,411	)
Net charge (credit) for non-operating items*	90		91		470		309		1,197
Underlying RC profit (loss) before interest and tax*	(322	)	(290	)	(345	)	(1,030	)	(1,214	)
Underlying RC profit (loss) before interest and tax
US	(249	)	(224	)	(166	)	(628	)	(436	)
Non-US	(73	)	(66	)	(179	)	(402	)	(778	)
	(322	)	(290	)	(345	)	(1,030	)	(1,214	)
Non-operating items
US	(85	)	(78	)	(438	)	(291	)	(1,084	)
Non-US	(5	)	(13	)	(32	)	(18	)	(113	)
	(90	)	(91	)	(470	)	(309	)	(1,197	)
RC profit (loss) before interest and tax
US	(334	)	(302	)	(604	)	(919	)	(1,520	)
Non-US	(78	)	(79	)	(211	)	(420	)	(891	)
	(412	)	(381	)	(815	)	(1,339	)	(2,411	)

Other businesses and corporate comprises our alternative energy business, shipping, treasury, BP ventures and corporate activities including centralized functions, and any residual 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 $412 million and $1,339 million respectively, compared with $815 million and $2,411 million for the same periods in 2018.

The results included a net non-operating charge of $90 million for the third quarter and $309 million for the nine months, primarily relating to costs of the Gulf of Mexico oil spill, compared with a charge of $470 million and $1,197 million for the same periods in 2018.

After adjusting for non-operating items, the underlying replacement cost loss before interest and tax for the third quarter and nine months was $322 million and $1,030 million respectively, compared with $345 million and $1,214 million for the same periods in 2018.

Alternative Energy

The net ethanol-equivalent production (which includes ethanol and sugar) for the third quarter and nine months was 357 million litres and 624 million litres respectively, compared with 354 million litres and 621 million litres for the same periods in 2018.

Net wind generation capacity* was 926MW at 30 September 2019, compared with 1,431MW at 30 September 2018. BP’s net share of wind generation for the third quarter and nine months was 506GWh and 1,967GWh respectively, compared with 687GWh and 2,888GWh for the same periods in 2018. The reduced capacity and lower production in 2019 is due to divestments in the second quarter of 2019 and fourth quarter of 2018.

Lightsource BP (an equity-accounted entity, in which BP holds 43%) manages a total portfolio of 2GW of operating solar facilities, of which 1.3GW was developed in-house. During the third quarter, Lightsource BP was awarded a 20-year power purchase agreement in the sixth Brazil Federal Energy auction, to supply renewable power from a 200MW solar installation.

In September, Lightsource BP announced a project with Xcel Energy in the US to develop a 240MW solar facility in Colorado. Lightsource BP will build, own and operate the facility and sell all the electricity generated to Xcel Energy under a long-term power purchase agreement.

In October, Lightsource BP acquired a 300MW portfolio of solar development projects from Forestalia, a Spanish renewables company. The projects are split across six separate sites in Spain’s Zaragoza province. Lightsource BP plans to negotiate power purchase agreements with renewable energy buyers to supply renewable energy to corporate and utility customers across the region.

Outlook

Other businesses and corporate average quarterly charges, excluding non-operating items, are expected to be around $350 million although this will fluctuate quarter to quarter.

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

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Financial statements

Group income statement

	Third		Second	Third	Nine	Nine
	quarter		quarter	quarter	months	months
$ million	2019		2019	2018	2019	2018

Sales and other operating revenues (Note 5)	68,291		72,676	79,468	207,288	223,079
Earnings from joint ventures – after interest and tax	90		138	148	413	661
Earnings from associates – after interest and tax	784		608	990	2,041	2,431
Interest and other income	126		270	154	559	478
Gains on sale of businesses and fixed assets	1		55	43	145	204
Total revenues and other income	69,292		73,747	80,803	210,446	226,853
Purchases	52,273		55,683	60,923	156,228	170,859
Production and manufacturing expenses	5,259		5,391	5,879	16,006	16,832
Production and similar taxes (Note 7)	340		371	451	1,135	1,350
Depreciation, depletion and amortization (Note 6)	4,297		4,588	3,728	13,346	11,470
Impairment and losses on sale of businesses and fixed assets (Note 3)	3,416		906	548	4,418	616
Exploration expense	185		146	310	698	988
Distribution and administration expenses	2,648		2,646	2,801	8,061	8,524
Profit (loss) before interest and taxation	874		4,016	6,163	10,554	16,214
Finance costs	883		853	698	2,603	1,786
Net finance expense relating to pensions and other post-retirement benefits	16		15	31	46	93
Profit (loss) before taxation	(25	)	3,148	5,434	7,905	14,335
Taxation	706		1,244	2,031	3,733	5,528
Profit (loss) for the period	(731	)	1,904	3,403	4,172	8,807
Attributable to
BP shareholders	(749	)	1,822	3,349	4,007	8,617
Non-controlling interests	18		82	54	165	190
	(731	)	1,904	3,403	4,172	8,807

Earnings per share (Note 8)
Profit (loss) for the period attributable to BP shareholders
Per ordinary share (cents)
Basic	(3.68	)	8.95	16.74	19.74	43.17
Diluted	(3.68	)	8.92	16.65	19.63	42.91
Per ADS (dollars)
Basic	(0.22	)	0.54	1.00	1.18	2.59
Diluted	(0.22	)	0.54	1.00	1.18	2.57

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Condensed group statement of comprehensive income

	Third		Second		Third		Nine		Nine
	quarter		quarter		quarter		months		months
$ million	2019		2019		2018		2019		2018

Profit (loss) for the period	(731	)	1,904		3,403		4,172		8,807
Other comprehensive income
Items that may be reclassified subsequently to profit or loss
Currency translation differences	(986	)	131		(753	)	134		(2,834	)
Cash flow hedges and costs of hedging	(17	)	133		65		135		(124	)
Share of items relating to equity-accounted entities, net of tax	119		(30	)	95		39		217
Income tax relating to items that may be reclassified	12		(9	)	9		(31	)	(29	)
	(872	)	225		(584	)	277		(2,770	)
Items that will not be reclassified to profit or loss
Remeasurements of the net pension and other post-retirement benefit liability or asset	(260	)	(39	)	389		(1,152	)	2,968
Cash flow hedges that will subsequently be transferred to the balance sheet	(10	)	(7	)	(7	)	(9	)	(29	)
Income tax relating to items that will not be reclassified	27		2		(119	)	302		(941	)
	(243	)	(44	)	263		(859	)	1,998
Other comprehensive income	(1,115	)	181		(321	)	(582	)	(772	)
Total comprehensive income	(1,846	)	2,085		3,082		3,590		8,035
Attributable to
BP shareholders	(1,848	)	2,001		3,040		3,434		7,888
Non-controlling interests	2		84		42		156		147
	(1,846	)	2,085		3,082		3,590		8,035

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Condensed group statement of changes in equity

	BP shareholders’		Non-controlling		Total
$ million	equity		interests		equity
At 31 December 2018	99,444		2,104		101,548
Adjustment on adoption of IFRS 16, net of tax(a)	(329	)	(1	)	(330	)
At 1 January 2019	99,115		2,103		101,218

Total comprehensive income	3,434		156		3,590
Dividends	(4,857	)	(166	)	(5,023	)
Cash flow hedges transferred to the balance sheet, net of tax	18		—		18
Repurchase of ordinary share capital	(340	)	—		(340	)
Share-based payments, net of tax	544		—		544
Share of equity-accounted entities’ changes in equity, net of tax	8		—		8
At 30 September 2019	97,922		2,093		100,015

	BP shareholders’		Non-controlling		Total
$ million	equity		interests		equity
At 31 December 2017	98,491		1,913		100,404
Adjustment on adoption of IFRS 9, net of tax(b)	(180	)	—		(180	)
At 1 January 2018	98,311		1,913		100,224

Total comprehensive income	7,888		147		8,035
Dividends	(4,965	)	(129	)	(5,094	)
Cash flow hedges transferred to the balance sheet, net of tax	17		—		17
Repurchase of ordinary share capital	(339	)	—		(339	)
Share-based payments, net of tax	582		—		582
Share of equity-accounted entities’ changes in equity, net of tax	(6	)	—		(6	)
Transactions involving non-controlling interests, net of tax	—		1		1
At 30 September 2018	101,488		1,932		103,420

(a)

See Note 1 for further information.

(b)

See Note 1 in BP Annual Report and Form 20-F 2018 for further information.

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Group balance sheet

	30 September	31 December
$ million	2019	2018(a)
Non-current assets
Property, plant and equipment	134,661	135,261
Goodwill	11,712	12,204
Intangible assets	15,084	17,284
Investments in joint ventures	8,678	8,647
Investments in associates	19,492	17,673
Other investments	1,248	1,341
Fixed assets	190,875	192,410
Loans	642	637
Trade and other receivables	2,054	1,834
Derivative financial instruments	5,829	5,145
Prepayments	789	1,179
Deferred tax assets	4,195	3,706
Defined benefit pension plan surpluses	5,972	5,955
	210,356	210,866
Current assets
Loans	350	326
Inventories	19,240	17,988
Trade and other receivables	22,788	24,478
Derivative financial instruments	3,346	3,846
Prepayments	1,138	963
Current tax receivable	1,090	1,019
Other investments	114	222
Cash and cash equivalents	19,692	22,468
	67,758	71,310
Assets classified as held for sale (Note 2)	8,149	—
	75,907	71,310
Total assets	286,263	282,176
Current liabilities
Trade and other payables	43,203	46,265
Derivative financial instruments	2,527	3,308
Accruals	4,569	4,626
Lease liabilities	2,012	44
Finance debt	7,556	9,329
Current tax payable	1,805	2,101
Provisions	2,189	2,564
	63,861	68,237
Liabilities directly associated with assets classified as held for sale (Note 2)	1,107	—
	64,968	68,237
Non-current liabilities
Other payables	12,550	13,830
Derivative financial instruments	5,694	5,625
Accruals	612	575
Lease liabilities	7,627	623
Finance debt	58,311	55,803
Deferred tax liabilities	9,715	9,812
Provisions	17,487	17,732
Defined benefit pension plan and other post-retirement benefit plan deficits	9,284	8,391
	121,280	112,391
Total liabilities	186,248	180,628
Net assets	100,015	101,548
Equity
BP shareholders’ equity	97,922	99,444
Non-controlling interests	2,093	2,104
Total equity	100,015	101,548

(a)

Finance debt on the comparative balance sheet has been re-presented to align with the current period. See Note 1 for further information.

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Condensed group cash flow statement

	Third		Second		Third		Nine		Nine
	quarter		quarter		quarter		months		months
$ million	2019		2019		2018		2019		2018
Operating activities
Profit (loss) before taxation	(25	)	3,148		5,434		7,905		14,335
Adjustments to reconcile profit (loss) before taxation to net cash provided by operating activities
Depreciation, depletion and amortization and exploration expenditure written off	4,412		4,665		3,955		13,822		12,204
Impairment and (gain) loss on sale of businesses and fixed assets	3,415		851		505		4,273		412
Earnings from equity-accounted entities, less dividends received	(236	)	(395	)	(664	)	(1,220	)	(2,188	)
Net charge for interest and other finance expense, less net interest paid	257		62		114		407		385
Share-based payments	149		117		160		563		564
Net operating charge for pensions and other post-retirement benefits, less contributions and benefit payments for unfunded plans	(50	)	(68	)	(62	)	(195	)	(326	)
Net charge for provisions, less payments	(132	)	(198	)	145		(446	)	369
Movements in inventories and other current and non-current assets and liabilities	141		(58	)	(1,573	)	(2,612	)	(5,541	)
Income taxes paid	(1,875	)	(1,309	)	(1,922	)	(4,330	)	(4,170	)
Net cash provided by operating activities	6,056		6,815		6,092		18,167		16,044
Investing activities
Expenditure on property, plant and equipment, intangible and other assets	(3,954	)	(3,833	)	(3,675	)	(11,482	)	(10,745	)
Acquisitions, net of cash acquired	13		(1,747	)	(606	)	(3,529	)	(607	)
Investment in joint ventures	(60	)	(20	)	(35	)	(80	)	(92	)
Investment in associates	(22	)	(54	)	(88	)	(221	)	(748	)
Total cash capital expenditure	(4,023	)	(5,654	)	(4,404	)	(15,312	)	(12,192	)
Proceeds from disposal of fixed assets	171		70		90		476		280
Proceeds from disposal of businesses, net of cash disposed	536		8		26		909		153
Proceeds from loan repayments	63		64		14		182		47
Net cash used in investing activities	(3,253	)	(5,512	)	(4,274	)	(13,745	)	(11,712	)
Financing activities(a)
Net issue (repurchase) of shares	(215	)	(80	)	(139	)	(340	)	(339	)
Lease liability payments	(594	)	(595	)	—		(1,806	)	(14	)
Proceeds from long-term financing	213		4,381		5,888		6,718		6,920
Repayments of long-term financing	(516	)	(3,602	)	(2,521	)	(6,758	)	(5,390	)
Net increase (decrease) in short-term debt	(852	)	(119	)	485		118		428
Net increase (decrease) in non-controlling interests	—		—		1		—		—
Dividends paid - BP shareholders	(1,656	)	(1,779	)	(1,410	)	(4,870	)	(4,966	)
- non-controlling interests	(47	)	(83	)	(59	)	(166	)	(129	)
Net cash provided by (used in) financing activities	(3,667	)	(1,877	)	2,245		(7,104	)	(3,490	)
Currency translation differences relating to cash and cash equivalents	(118	)	(8	)	(56	)	(94	)	(225	)
Increase (decrease) in cash and cash equivalents	(982	)	(582	)	4,007		(2,776	)	617
Cash and cash equivalents at beginning of period	20,674		21,256		22,185		22,468		25,575
Cash and cash equivalents at end of period	19,692		20,674		26,192		19,692		26,192

(a)

Financing cash flows for the third quarter and nine months 2018 have been re-presented to align with the current period. See Note 1 for further information.

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Notes

Note 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 2018 included in BP Annual Report and Form 20-F 2018.

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 as applicable to companies reporting under IFRS. 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 2019, which are the same as those used in preparing BP Annual Report and Form 20-F 2018 with the exception of the adoption of IFRS 16 'Leases' from 1 January 2019.

New International Financial Reporting Standards adopted

BP adopted IFRS 16 ‘Leases’, which replaced IAS 17 ‘Leases’ and IFRIC 4 ‘Determining whether an arrangement contains a lease’, with effect from 1 January 2019. Further information is included in BP Annual Report and Form 20-F 2018 - Financial statements - Note 1 Significant accounting policies, judgements, estimates and assumptions - Impact of new International Financial Reporting Standards.

IFRS 16 provides a new model for lessee accounting in which the majority of leases are accounted for by the recognition on the balance sheet of a right-of-use asset and a lease liability.

Agreements that convey the right to control the use of an identified asset for a period of time in exchange for consideration are accounted for as leases. A lease liability is recognized at the present value of future lease payments over the reasonably certain lease term. Variable lease payments that do not depend on an index or a rate are not included in the lease liability. The right-of-use asset is recognized at a value equivalent to the initial measurement of the lease liability adjusted for lease prepayments, lease incentives, initial direct costs and any restoration obligations. The subsequent amortization of the right-of-use asset and the interest expense related to the lease liability are recognized in the income statement over the lease term.

The group recognizes the full lease liability, rather than its working interest share, for leases entered into on behalf of a joint operation if the group has the primary responsibility for making the lease payments. If the right-of-use asset is jointly controlled by the group and the other joint operators, a receivable is recognized for the share of the asset transferred to the other joint operators.

BP elected to apply the modified retrospective transition approach in which the cumulative effect of initial application is recognized in opening retained earnings at the date of initial application with no restatement of comparative periods’ financial information. Comparative information in the group balance sheet and group cash flow statement has, however, been re-presented to align with current year presentation, showing lease liabilities and lease liability payments as separate line items. These were previously included within the finance debt and repayments of long-term financing line items respectively. Amounts presented in these line items for the comparative periods relate to leases accounted for as finance leases under IAS 17.

IFRS 16 introduces a revised definition of a lease. As permitted by the standard, BP elected not to reassess the existing population of leases under the new definition and will only apply the new definition for the assessment of contracts entered into after the transition date. On transition the standard permits, on a lease-by-lease basis, the right-of-use asset to be measured either at an amount equal to the lease liability (as adjusted for prepaid or accrued lease payments), or on a historical basis as if the standard had always applied. BP elected to use the historical asset measurement for its more material leases and used the asset equals liability approach for the remainder of the population. BP also elected to adjust the carrying amounts of the right-of-use assets as at 1 January 2019 for onerous lease provisions that had been recognized on the group balance sheet as at 31 December 2018, rather than performing impairment tests on transition.

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Note 1. Basis of preparation (continued)

The effect of the adoption of IFRS 16 on the group balance sheet is set out below.

			Adjustment
	31 December	1 January	on adoption
$ million	2018	2019	of IFRS 16
Non-current assets
Property, plant and equipment	135,261	143,950	8,689
Trade and other receivables	1,834	2,159	325
Prepayments	1,179	849	(330	)
Deferred tax assets	3,706	3,736	30
Current assets
Trade and other receivables	24,478	24,673	195
Prepayments	963	872	(91	)
Current liabilities
Trade and other payables	46,265	46,209	(56	)
Accruals	4,626	4,578	(48	)
Lease liabilities	44	2,196	2,152
Finance debt	9,329	9,329	—
Provisions	2,564	2,547	(17	)
Non-current liabilities
Other payables	13,830	14,013	183
Accruals	575	548	(27	)
Lease liabilities	623	7,704	7,081
Finance debt	55,803	55,803	—
Deferred tax liabilities	9,812	9,767	(45	)
Provisions	17,732	17,657	(75	)

Net assets	101,548	101,218	(330	)

Equity
BP shareholders' equity	99,444	99,115	(329	)
Non-controlling interests	2,104	2,103	(1	)
	101,548	101,218	(330	)

The presentation and timing of recognition of charges in the income statement has changed following the adoption of IFRS 16. The operating lease expense previously reported under IAS 17, typically on a straight-line basis, has been replaced by depreciation of the right-of-use asset and interest on the lease liability. In the cash flow statement payments are now presented as financing cash flows, representing payments of principal, and as operating cash flows, representing payments of interest. Variable lease payments that do not depend on an index or rate are not included in the lease liability and will continue to be presented as operating cash flows. In prior years, operating lease payments were principally presented within cash flows from operating activities.

The following table provides a reconciliation of the group’s operating lease commitments as at 31 December 2018 to the total lease liability recognized on the group balance sheet in accordance with IFRS 16 as at 1 January 2019.

$ million
Operating lease commitments at 31 December 2018	11,979

Leases not yet commenced	(1,372	)
Leases below materiality threshold	(86	)
Short-term leases	(91	)
Effect of discounting	(1,512	)
Impact on leases in joint operations	836
Variable lease payments	(58	)
Redetermination of lease term	(252	)
Other	(22	)
Total additional lease liabilities recognized on adoption of IFRS 16	9,422
Finance lease obligations at 31 December 2018	667
Adjustment for finance leases in joint operations	(189	)
Total lease liabilities at 1 January 2019	9,900

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Note 1. Basis of preparation (continued)

An explanation of each reconciling item shown in the table above is provided in BP Annual Report and Form 20-F 2018 - Financial statements - Note 1 Significant accounting policies, judgements, estimates and assumptions - Impact of new International Financial Reporting Standards.

The total adjustments to the group's lease liabilities at 1 January 2019 are reconciled as follows:

$ million
Total additional lease liabilities recognized on adoption of IFRS 16	9,422
Less: adjustment for finance leases in joint operations	(189	)
Total adjustment to lease liabilities	9,233
Of which – current	2,152
– non-current	7,081

IFRIC agenda decision on IFRS 9 'Financial Instruments'

In March 2019, the IFRS Interpretations Committee (IFRIC) issued an agenda decision on the application of IFRS 9 to the physical settlement of contracts to buy or sell a non-financial item. The agenda decision concluded that where a derivative contract is settled by the physical receipt (or delivery) of the commodity, the transaction price reported for the purchase (or sale) should include the fair value of the derivative instrument in addition to the cash payable (or receivable). BP is currently assessing the impact of the agenda decision but expects it to have no effect on reported earnings.

Note 2. Non-current assets held for sale

Assets and liabilities relating to three disposal transactions have been classified as held for sale in the group balance sheet as at 30 September 2019. The carrying amount of assets classified as held for sale is $8,149 million, with associated liabilities of $1,107 million.

Upstream

On 27 August 2019 BP announced that it had agreed to sell all its Alaska operations and interests to Hilcorp Energy for up to $5.6 billion, subject to customary closing adjustments, of which $1.6 billion is contingent on future cash flows. The sale will include BP’s entire upstream and midstream business in the state, including BP Exploration (Alaska) Inc., which owns all of BP’s upstream oil and gas interests in Alaska, and BP Pipelines (Alaska) Inc.’s 49% interest in the Trans Alaska Pipeline System (TAPS). BP will retain decommissioning liability relating to TAPS, which will be offset by a 30% cost reimbursement from Hilcorp. The deal, which is subject to governmental authorizations, is expected to complete during 2020. Assets of $6,456 million and associated liabilities of $866 million relating to this transaction are classified as held for sale at 30 September 2019.

On 3 June 2019 BP announced that it had agreed to sell its interests in Gulf of Suez oil concessions in Egypt to Dragon Oil. Under the terms of the agreement, Dragon Oil purchased producing and exploration concessions and BP's interest in the Gulf of Suez Petroleum Company (GUPCO). Following approval from the Egyptian Ministry of Petroleum and Mineral Resources the deal completed on 9 October 2019. Assets of $684 million and associated liabilities of $107 million relating to this transaction are classified as held for sale at 30 September 2019.

Other businesses and corporate

On 22 July 2019, BP and Bunge announced that they will each contribute their existing Brazilian biofuel, biopower and sugar businesses into a new 50:50 joint venture. Subject to satisfaction of conditions precedent, including obtaining the necessary regulatory clearances and approval, the deal is expected to complete in the fourth quarter of 2019. Assets of $1,009 million and associated liabilities of $134 million relating to this transaction are classified as held for sale at 30 September 2019.

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Note 3. Impairments

Included within the line item in the income statement for impairment and losses on sale of businesses and fixed assets is a net impairment charge for the third quarter of $3,319 million. The net charge for the nine months ended 30 September is $4,174 million.

The impairment charges, which are substantially all reported in the Upstream segment, principally relate to BP’s ongoing divestment programme. They include $2,274 million in the third quarter and $2,716 million in the nine months relating to heritage BPX Energy assets; $1,007 million in the third quarter and the nine months relating to the group’s interests in its Alaska business, of which $288 million relates to the impairment of associated goodwill and $223 million relates to retained shipping vessels; and $53 million in the third quarter and $244 million in the nine months relating to the group’s interests in Gulf of Suez oil concessions in Egypt. The recoverable amount of these assets at 30 September 2019 is their fair value less costs of disposal, determined by reference to expected sales proceeds. See Note 2 for further information.

Note 4. 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
$ million	2019		2019		2018		2019		2018
Upstream	(1,050	)	2,469		3,472		4,303		10,160
Downstream	2,016		1,288		2,249		5,069		4,802
Rosneft	802		525		808		1,813		1,821
Other businesses and corporate	(412	)	(381	)	(815	)	(1,339	)	(2,411	)
	1,356		3,901		5,714		9,846		14,372
Consolidation adjustment – UPII*	30		34		78		51		69
RC profit (loss) before interest and tax*	1,386		3,935		5,792		9,897		14,441
Inventory holding gains (losses)*
Upstream	—		(10	)	1		(8	)	6
Downstream	(433	)	93		343		706		1,608
Rosneft (net of tax)	(79	)	(2	)	27		(41	)	159
Profit (loss) before interest and tax	874		4,016		6,163		10,554		16,214
Finance costs	883		853		698		2,603		1,786
Net finance expense relating to pensions and other post-retirement benefits	16		15		31		46		93
Profit (loss) before taxation	(25	)	3,148		5,434		7,905		14,335

RC profit (loss) before interest and tax*
US	(2,425	)	498		1,215		(1,156	)	1,554
Non-US	3,811		3,437		4,577		11,053		12,887
	1,386		3,935		5,792		9,897		14,441

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Note 5. Sales and other operating revenues

	Third		Second	Third	Nine	Nine
	quarter		quarter	quarter	months	months
$ million	2019		2019	2018	2019	2018
By segment
Upstream	12,396		13,556	14,781	40,546	41,349
Downstream	61,834		66,396	72,376	186,646	202,956
Other businesses and corporate	461		433	423	1,250	1,142
	74,691		80,385	87,580	228,442	245,447

Less: sales and other operating revenues between segments
Upstream	6,406		7,481	7,368	20,211	19,896
Downstream	(59	)	62	539	589	1,806
Other businesses and corporate	53		166	205	354	666
	6,400		7,709	8,112	21,154	22,368

Third party sales and other operating revenues
Upstream	5,990		6,075	7,413	20,335	21,453
Downstream	61,893		66,334	71,837	186,057	201,150
Other businesses and corporate	408		267	218	896	476
Total sales and other operating revenues	68,291		72,676	79,468	207,288	223,079

By geographical area
US	23,413		26,086	27,580	71,347	77,869
Non-US	51,030		52,933	58,869	153,581	166,141
	74,443		79,019	86,449	224,928	244,010
Less: sales and other operating revenues between areas	6,152		6,343	6,981	17,640	20,931
	68,291		72,676	79,468	207,288	223,079

Revenues from contracts with customers
Sales and other operating revenues include the following in relation to revenues from contracts with customers:
Crude oil	14,502		17,070	17,744	45,854	49,828
Oil products	44,667		46,999	52,049	134,249	147,619
Natural gas, LNG and NGLs	4,465		4,823	5,764	15,081	15,883
Non-oil products and other revenues from contracts with customers	3,300		3,173	3,574	9,974	10,150
	66,934		72,065	79,131	205,158	223,480

Note 6. Depreciation, depletion and amortization

	Third	Second	Third	Nine	Nine
	quarter	quarter	quarter	months	months
$ million	2019	2019	2018	2019	2018
Upstream
US	1,121	1,288	987	3,522	3,074
Non-US	2,295	2,396	2,167	7,189	6,665
	3,416	3,684	3,154	10,711	9,739
Downstream
US	336	333	220	992	660
Non-US	394	392	284	1,169	879
	730	725	504	2,161	1,539
Other businesses and corporate
US	14	14	16	41	48
Non-US	137	165	54	433	144
	151	179	70	474	192
Total group	4,297	4,588	3,728	13,346	11,470

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Note 7. Production and similar taxes

	Third	Second	Third	Nine	Nine
	quarter	quarter	quarter	months	months
$ million	2019	2019	2018	2019	2018
US	66	79	91	226	270
Non-US	274	292	360	909	1,080
	340	371	451	1,135	1,350

Note 8. Earnings per share and shares in issue

Basic earnings per ordinary share (EpS) amounts are calculated by dividing the profit (loss) for the period attributable to ordinary shareholders by the weighted average number of ordinary shares outstanding during the period. During the quarter the company repurchased for cancellation 34 million ordinary shares for a total cost of $215 million, including transaction costs of $2 million, as part of the share buyback programme as announced on 31 October 2017. This brings the total number of shares repurchased in the nine months to 52 million for a total cost of $340 million. The number of shares in issue is reduced when shares are repurchased.

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
$ million	2019		2019	2018	2019	2018
Results for the period
Profit (loss) for the period attributable to BP shareholders	(749	)	1,822	3,349	4,007	8,617
Less: preference dividend	—		1	—	1	1
Profit (loss) attributable to BP ordinary shareholders	(749	)	1,821	3,349	4,006	8,616

Number of shares (thousand)(a)(b)
Basic weighted average number of shares outstanding	20,371,728		20,336,347	20,006,872	20,295,078	19,957,265
ADS equivalent	3,395,288		3,389,391	3,334,478	3,382,513	3,326,210

Weighted average number of shares outstanding used to calculate diluted earnings per share	20,371,728		20,421,184	20,118,456	20,411,739	20,081,256
ADS equivalent	3,395,288		3,403,530	3,353,076	3,401,957	3,346,876

Shares in issue at period-end	20,417,220		20,373,332	20,050,414	20,417,220	20,050,414
ADS equivalent	3,402,870		3,395,555	3,341,735	3,402,870	3,341,735

(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.

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Note 9. Dividends

Dividends payable

BP today announced an interim dividend of 10.25 cents per ordinary share which is expected to be paid on 20 December 2019 to ordinary shareholders and American Depositary Share (ADS) holders on the register on 8 November 2019. The corresponding amount in sterling is due to be announced on 9 December 2019, calculated based on the average of the market exchange rates for the four dealing days commencing on 3 December 2019. Holders of ADSs are expected to receive $0.615 per ADS (less applicable fees). The board has decided not to offer a scrip dividend alternative in respect of the third quarter 2019 dividend. Ordinary shareholders and ADS holders (subject to certain exceptions) will be able to participate in a dividend reinvestment programme. Details of the third quarter dividend and timetable are available at bp.com/dividends and further details of the dividend reinvestment programmes are available at bp.com/drip.

	Third	Second	Third	Nine	Nine
	quarter	quarter	quarter	months	months
	2019	2019	2018	2019	2018
Dividends paid per ordinary share
cents	10.250	10.250	10.250	30.750	30.250
pence	8.348	8.066	7.930	24.152	22.543
Dividends paid per ADS (cents)	61.50	61.50	61.50	184.50	181.50
Scrip dividends
Number of shares issued (millions)	72.5	46.3	89.9	208.9	147.8
Value of shares issued ($ million)	440	318	638	1,387	1,059

Note 10. Net debt and net debt including leases

Net debt*	Third	Second		Third	Nine	Nine
	quarter	quarter		quarter	months	months
$ million	2019	2019		2018	2019	2018
Finance debt(a)	65,867	67,553		63,460	65,867	63,460
Fair value (asset) liability of hedges related to finance debt(b)	319	(378	)	1,234	319	1,234
	66,186	67,175		64,694	66,186	64,694
Less: cash and cash equivalents	19,692	20,674		26,192	19,692	26,192
Net debt	46,494	46,501		38,502	46,494	38,502
Equity	100,015	103,623		103,420	100,015	103,420
Gearing*	31.7%	31.0%		27.1%	31.7%	27.1%

(a)

The fair value of finance debt at 30 September 2019 was $66,879 million (31 December 2018 $65,259 million).

(b)

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 $682 million (second quarter 2019 liability of $563 million and third quarter 2018 liability of $723 million) are not included in the calculation of net debt shown above as hedge accounting is not applied for these instruments.

As a result of the adoption of IFRS 16 ‘Leases’ from 1 January 2019, leases that were previously classified as finance leases under IAS 17 are now presented as ‘Lease liabilities’ on the group balance sheet and therefore do not form part of finance debt. Comparative information for finance debt (previously termed ‘gross debt’), net debt and gearing (previously termed 'net debt ratio') have been amended to be on a consistent basis with amounts presented for 2019. The relevant amount for finance lease liabilities that has been excluded from comparative information for the third quarter and nine months 2018 is $675 million. The previously disclosed amount for finance debt for the third quarter and nine months 2018 was $64,135 million. The previously disclosed amount for net debt for the third quarter and nine months 2018 was $39,177 million. The previously disclosed gearing for the third quarter and nine months 2018 was 27.5%.

Net debt including leases*	Third		Second		Third	Nine		Nine
	quarter		quarter		quarter	months		months
$ million	2019		2019		2018	2019		2018
Net debt	46,494		46,501		38,502	46,494		38,502
Lease liabilities	9,639		10,379		675	9,639		675
Net partner (receivable) payable for leases entered into on behalf of joint operations	(197	)	(230	)	—	(197	)	—
Net debt including leases	55,936		56,650		39,177	55,936		39,177

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Note 11. Inventory valuation

A provision of $369 million was held against hydrocarbon inventories at 30 September 2019 ($242 million at 30 June 2019 and $53 million at 30 September 2018) to write them down to their net realizable value. The net movement charged to the income statement during the third quarter 2019 was $131 million (second quarter 2019 was a charge of $120 million and third quarter 2018 was a charge of $15 million).

Note 12. Statutory accounts

The financial information shown in this publication, which was approved by the Board of Directors on 28 October 2019, is unaudited and does not constitute statutory financial statements. Audited financial information will be published in BP Annual Report and Form 20-F 2019. BP Annual Report and Form 20-F 2018 has been filed with the Registrar of Companies in England and Wales. The report of the auditor on those accounts was unqualified, did not include a reference to any matters to which the auditor drew attention by way of emphasis without qualifying the report 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

Effects on the financial statements of the adoption of IFRS 16 ‘Leases’

BP adopted IFRS 16 ‘Leases’ with effect from 1 January 2019. The principal effects of the adoption are described below. BP elected to apply the modified retrospective transition approach in which the cumulative effect of initial application is recognized in opening retained earnings at the date of initial application with no restatement of comparative periods’ financial information. For further information of the effects of adoption see Financial statements - Note 1 and Note 10.

Balance sheet

As a result of the adoption of IFRS 16, $9.0 billion of right-of-use assets and $9.6 billion of lease liabilities have been included in the group balance sheet as at 30 September 2019. Lease liabilities are now presented separately on the group balance sheet and do not form part of finance debt. Comparative information for finance debt in the group balance sheet has been re-presented to align with current year presentation.

	30 September	31 December
$ billion	2019	2018
Property, plant and equipment(a) (b)	9.0	0.5
Lease liabilities(a)	9.6	0.7
Finance debt	65.9	65.1

(a)

Comparative information represents finance leases accounted for under IAS 17.

(b)

Net additions to right-of-use assets for the third quarter and nine months 2019 were $0.3 billion and $2.0 billion respectively.

Income statement

The presentation and timing of recognition of charges in the income statement has changed following the adoption of IFRS 16. The operating lease expense reported under the previous lease accounting standard, IAS 17, typically on a straight-line basis, has been replaced by depreciation of the right-of-use asset and interest on the lease liability. Depreciation of right-of-use assets for the third quarter and nine months 2019 was $0.5 billion and $1.4 billion respectively. Interest on the group’s lease liabilities for the third quarter and nine months 2019 was $0.1 billion and $0.3 billion respectively. Operating lease expenses were previously principally included within Production and manufacturing expenses and Distribution and administration expenses in the income statement. It is estimated that the resulting benefit to these line items is offset, in total, by an equivalent amount in depreciation and interest charges. Therefore, there has been no material overall effect on group profit measures in the third quarter and nine months of 2019.

Cash flow statement

Lease payments are now presented as financing cash flows, representing payments of principal, and as operating cash flows, representing payments of interest. In prior years, operating lease payments were presented as operating cash flows and capital expenditure. Of the $0.6 billion of lease payments included within financing activities for the third quarter of 2019, it is estimated that $0.5 billion would have been reported as operating cash flows and $0.1 billion would have been reported as capital expenditure cash flows ignoring the effects of IFRS 16. Of the $1.8 billion of lease payments included within financing activities for the nine months 2019, it is estimated that $1.5 billion would have been reported as operating cash flows and $0.3 billion would have been reported as capital expenditure cash flows ignoring the effects of IFRS 16.

	Third		Second		Third	Nine		Nine
	quarter		quarter		quarter	months		months
$ billion	2019		2019		2018	2019		2018
Financing activities
Lease liability payments(a)	(0.6	)	(0.6	)	—	(1.8	)	—

(a)

Comparative information represents finance leases accounted for under IAS 17.

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Capital expenditure*

	Third	Second	Third	Nine	Nine
	quarter	quarter	quarter	months	months
$ million	2019	2019	2018	2019	2018
Capital expenditure on a cash basis
Organic capital expenditure*	3,946	3,686	3,730	11,280	10,738
Inorganic capital expenditure*(a)	77	1,968	674	4,032	1,454
	4,023	5,654	4,404	15,312	12,192

	Third	Second	Third	Nine	Nine
	quarter	quarter	quarter	months	months
$ million	2019	2019	2018	2019	2018
Organic capital expenditure by segment
Upstream
US	1,036	972	854	2,990	2,434
Non-US	2,110	1,858	2,073	5,856	6,126
	3,146	2,830	2,927	8,846	8,560
Downstream
US	197	271	237	655	640
Non-US	558	470	513	1,562	1,342
	755	741	750	2,217	1,982
Other businesses and corporate
US	8	15	6	32	20
Non-US	37	100	47	185	176
	45	115	53	217	196
	3,946	3,686	3,730	11,280	10,738
Organic capital expenditure by geographical area
US	1,241	1,258	1,097	3,677	3,094
Non-US	2,705	2,428	2,633	7,603	7,644
	3,946	3,686	3,730	11,280	10,738

(a)

On 31 October 2018, BP acquired from BHP Billiton Petroleum (North America) Inc. 100% of the issued share capital of Petrohawk Energy Corporation, a wholly owned subsidiary of BHP that holds a portfolio of unconventional onshore US oil and gas assets. The entire consideration payable of $10,268 million, after customary closing adjustments, was paid in instalments between July 2018 and April 2019. The amounts presented as inorganic capital expenditure include $1,748 million for the second quarter 2019, $3,480 million for the nine months 2019 and $525 million for the third quarter and nine months 2018 relating to this transaction. Nine months 2019 and 2018 also include amounts relating to the 25-year extension to our ACG production-sharing agreement* in Azerbaijan.

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Non-operating items*

	Third		Second		Third		Nine		Nine
	quarter		quarter		quarter		months		months
$ million	2019		2019		2018(a)		2019		2018(a)
Upstream
Impairment and gain (loss) on sale of businesses and fixed assets(b)	(3,406	)	(796	)	(231	)	(4,213	)	(124	)
Environmental and other provisions	—		—		—		—		—
Restructuring, integration and rationalization costs	(24	)	(17	)	(17	)	(76	)	(78	)
Fair value gain (loss) on embedded derivatives	—		—		1		—		17
Other	(24	)	47		5		65		(134	)
	(3,454	)	(766	)	(242	)	(4,224	)	(319	)
Downstream
Impairment and gain (loss) on sale of businesses and fixed assets	(9	)	(51	)	(19	)	(56	)	(34	)
Environmental and other provisions	(1	)	—		—		(1	)	—
Restructuring, integration and rationalization costs	(4	)	20		(16	)	14		(126	)
Fair value gain (loss) on embedded derivatives	—		—		—		—		—
Other	—		—		(2	)	(6	)	(155	)
	(14	)	(31	)	(37	)	(49	)	(315	)
Rosneft
Impairment and gain (loss) on sale of businesses and fixed assets	—		(113	)	(64	)	(194	)	(64	)
Environmental and other provisions	—		—		—		—		—
Restructuring, integration and rationalization costs	—		—		—		—		—
Fair value gain (loss) on embedded derivatives	—		—		—		—		—
Other	—		—		—		—		—
	—		(113	)	(64	)	(194	)	(64	)
Other businesses and corporate
Impairment and gain (loss) on sale of businesses and fixed assets	—		(4	)	(255	)	(4	)	(254	)
Environmental and other provisions	—		(22	)	(45	)	(28	)	(65	)
Restructuring, integration and rationalization costs	—		(3	)	(33	)	7		(78	)
Fair value gain (loss) on embedded derivatives	—		—		—		—		—
Gulf of Mexico oil spill	(84	)	(57	)	(128	)	(256	)	(647	)
Other	(6	)	(5	)	(9	)	(28	)	(153	)
	(90	)	(91	)	(470	)	(309	)	(1,197	)
Total before interest and taxation	(3,558	)	(1,001	)	(813	)	(4,776	)	(1,895	)
Finance costs(c)	(145	)	(116	)	(119	)	(389	)	(357	)
Total before taxation	(3,703	)	(1,117	)	(932	)	(5,165	)	(2,252	)
Taxation credit (charge) on non-operating items	772		256		283		1,121		633
Total after taxation for period	(2,931	)	(861	)	(649	)	(4,044	)	(1,619	)

(a)

Amounts reported as restructuring, integration and rationalization costs relate to the group's restructuring programme, originally announced in 2014, which was completed in fourth quarter 2018.

(b)

Third quarter and nine months 2019 include impairment charges of $3,317 million and $4,115 million respectively, principally resulting from the announcements to dispose of certain assets in the US and Egypt. See Note 3 for further information.

(c)

Relates to the unwinding of discounting effects relating to Gulf of Mexico oil spill payables.

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Non-GAAP information on fair value accounting effects

	Third		Second		Third		Nine		Nine
	quarter		quarter		quarter		months		months
$ million	2019		2019		2018		2019		2018
Favourable (adverse) impact relative to management’s measure of performance
Upstream	265		(178	)	(285	)	47		(185	)
Downstream	147		(46	)	175		137		(275	)
	412		(224	)	(110	)	184		(460	)
Taxation credit (charge)	(86	)	49		12		(44	)	102
	326		(175	)	(98	)	140		(358	)

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 the income statement. This is 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 physical 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 physical 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 require 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 other transportation, 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 that 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, transportation 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 derivative instruments used to risk manage certain oil, gas and other 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.

In addition, fair value accounting effects include changes in the fair value of the near-term portions of LNG contracts that fall within BP’s risk management framework. LNG contracts are not considered derivatives, because there is insufficient market liquidity, and they are therefore accrual accounted under IFRS. However, oil and natural gas derivative financial instruments (used to risk manage the near-term portions of the LNG contracts) are fair valued under IFRS. The fair value accounting effect reduces timing differences between recognition of the derivative financial instruments used to risk manage the LNG contracts and the recognition of the LNG contracts themselves, which therefore gives a better representation of performance in each period.

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Non-GAAP information on fair value accounting effects (continued)

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
$ million	2019		2019		2018		2019	2018
Upstream
Replacement cost profit (loss) before interest and tax adjusted for fair value accounting effects	(1,315	)	2,647		3,757		4,256	10,345
Impact of fair value accounting effects	265		(178	)	(285	)	47	(185	)
Replacement cost profit (loss) before interest and tax	(1,050	)	2,469		3,472		4,303	10,160
Downstream
Replacement cost profit (loss) before interest and tax adjusted for fair value accounting effects	1,869		1,334		2,074		4,932	5,077
Impact of fair value accounting effects	147		(46	)	175		137	(275	)
Replacement cost profit (loss) before interest and tax	2,016		1,288		2,249		5,069	4,802
Total group
Profit (loss) before interest and tax adjusted for fair value accounting effects	462		4,240		6,273		10,370	16,674
Impact of fair value accounting effects	412		(224	)	(110	)	184	(460	)
Profit (loss) before interest and tax	874		4,016		6,163		10,554	16,214

Readily marketable inventory* (RMI)

	30 September	31 December
$ million	2019	2018
RMI at fair value*	5,604	4,202
Paid-up RMI*	2,754	1,641

Readily marketable inventory (RMI) is oil and oil products inventory held and price risk-managed by BP’s integrated supply and trading function (IST) which could be sold to generate funds if required. Paid-up RMI is RMI that BP has paid for.

We believe that disclosing the amounts of RMI and paid-up RMI is useful to investors as it enables them to better understand and evaluate the group’s inventories and liquidity position by enabling them to see the level of discretionary inventory held by IST and to see builds or releases of liquid trading inventory.

See the Glossary on page 32 for a more detailed definition of RMI. RMI, RMI at fair value, paid-up RMI and unpaid RMI are non-GAAP measures. A reconciliation of total inventory as reported on the group balance sheet to paid-up RMI is provided below.

	30 September		31 December
$ million	2019		2018
Reconciliation of total inventory to paid-up RMI
Inventories as reported on the group balance sheet under IFRS	19,240		17,988
Less: (a) inventories that are not oil and oil products and (b) oil and oil product inventories that are not risk-managed by IST	(13,805	)	(14,066	)
	5,435		3,922
Plus: difference between RMI at fair value and RMI on an IFRS basis	169		280
RMI at fair value	5,604		4,202
Less: unpaid RMI* at fair value	(2,850	)	(2,561	)
Paid-up RMI	2,754		1,641

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Gulf of Mexico oil spill

	Third	Second	Third	Nine	Nine
	quarter	quarter	quarter	months	months
$ million	2019	2019	2018	2019	2018
Net cash provided by operating activities as per condensed group cash flow statement	6,056	6,815	6,092	18,167	16,044
Exclude net cash from operating activities relating to the Gulf of Mexico oil spill on a post-tax basis	409	1,413	525	2,471	2,946
Operating cash flow, excluding Gulf of Mexico oil spill payments*	6,465	8,228	6,617	20,638	18,990

Net cash from operating activities relating to the Gulf of Mexico oil spill on a pre-tax basis amounted to an outflow of $443 million and $2,569 million in the third quarter and nine months of 2019 respectively. For the same periods in 2018, the amount was an outflow of $560 million and $3,258 million respectively. Net cash outflows relating to the Gulf of Mexico oil spill in 2019 and 2018 include payments made under the 2016 consent decree and settlement agreement with the United States and the five Gulf coast states. Cash outflows in 2018 also include the final payment made under the 2012 agreement with the US government to resolve all federal criminal claims arising from the incident.

	30 September		31 December
$ million	2019		2018
Trade and other payables	(12,402	)	(14,201	)
Provisions	(207	)	(345	)
Gulf of Mexico oil spill payables and provisions	(12,609	)	(14,546	)
Of which - current	(1,829	)	(2,612	)

Deferred tax asset	5,610		5,562

The provision reflects the latest estimate for the remaining costs associated with the Gulf of Mexico oil spill. The amounts ultimately payable may differ from the amount provided and the timing of payments is uncertain. Further information relating to the Gulf of Mexico oil spill, including information on the nature and expected timing of payments relating to provisions and other payables, is provided in BP Annual Report and Form 20-F 2018 - Financial statements - Note 2 and pages 296 to 298 of Legal proceedings.

Working capital* reconciliation

	Third		Second		Third		Nine		Nine
	quarter		quarter		quarter		months		months
$ million	2019		2019		2018		2019		2018
Movements in inventories and other current and non-current assets and liabilities as per condensed group cash flow statement	141		(58	)	(1,573	)	(2,612	)	(5,541	)
Adjustments to exclude movements in inventories and other current and non-current assets and liabilities for the Gulf of Mexico oil spill	413		1,451		538		2,495		2,819
Adjusted for Inventory holding gains (losses)* (Note 4)
Upstream	—		(10	)	1		(8	)	6
Downstream	(433	)	93		343		706		1,608
Working capital release (build)	121		1,476		(691	)	581		(1,108	)

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Realizations* and marker prices

	Third	Second	Third	Nine	Nine
	quarter	quarter	quarter	months	months
	2019	2019	2018	2019	2018
Average realizations(a)
Liquids* ($/bbl)
US	50.46	56.98	65.22	52.80	61.76
Europe	61.90	68.73	73.90	64.21	70.51
Rest of World	59.14	66.24	71.95	61.91	68.41
BP Average	55.68	62.63	69.68	58.38	66.11
Natural gas ($/mcf)
US	1.72	1.80	2.22	2.02	2.15
Europe	3.03	3.63	7.79	3.98	7.33
Rest of World	3.82	4.12	4.36	4.21	4.24
BP Average	3.11	3.35	3.86	3.49	3.77
Total hydrocarbons* ($/boe)
US	31.23	35.94	43.20	33.81	41.21
Europe	52.47	63.40	68.54	58.55	64.80
Rest of World	36.82	41.60	45.51	39.69	42.98
BP Average	35.48	40.64	46.14	38.55	43.64
Average oil marker prices ($/bbl)
Brent	62.00	68.86	75.16	64.59	72.13
West Texas Intermediate	56.40	59.90	69.63	57.08	66.90
Western Canadian Select	43.61	47.37	40.33	45.30	42.35
Alaska North Slope	62.98	68.29	75.26	65.23	72.19
Mars	59.19	65.20	70.79	61.85	67.63
Urals (NWE – cif)	60.82	67.62	73.98	63.71	70.50
Average natural gas marker prices
Henry Hub gas price(b) ($/mmBtu)	2.23	2.64	2.91	2.67	2.90
UK Gas – National Balancing Point (p/therm)	27.46	31.53	64.46	35.70	58.83

(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
	2019	2019	2018	2019	2018
$/£ average rate for the period	1.23	1.29	1.30	1.27	1.35
$/£ period-end rate	1.23	1.27	1.31	1.23	1.31

$/€ average rate for the period	1.11	1.12	1.16	1.12	1.19
$/€ period-end rate	1.09	1.14	1.17	1.09	1.17

Rouble/$ average rate for the period	64.64	64.58	65.54	65.06	61.52
Rouble/$ period-end rate	64.32	63.09	65.76	64.32	65.76

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Legal proceedings

For a full discussion of the group’s material legal proceedings, see pages 296-298 of BP Annual Report and Form 20-F 2018, and page 35 of BP p.l.c. Group results second quarter and half-year 2019.

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. Non-GAAP measures are sometimes referred to as alternative performance measures.

Capital expenditure is total cash capital expenditure as stated in the condensed group cash flow statement.

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

Divestment proceeds are disposal proceeds as per the condensed group cash flow statement.

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). They reflect the difference between the way BP manages the economic exposure and internally measures performance of certain activities and the way those activities are measured under IFRS. Further information on fair value accounting effects is provided on page 28.

Free cash flow is operating cash flow less net cash used in investing activities and lease liability payments included in financing activities, as presented in the condensed group cash flow statement.

Gearing and net debt are non-GAAP measures. Net debt is calculated as 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. Gearing is defined as the ratio of net debt to the total of net debt plus total equity. BP believes these measures provide useful information to investors. Net debt enables investors to see the economic effect of finance debt, related hedges and cash and cash equivalents in total. Gearing enables investors to see how significant net debt is relative to total equity. The derivatives are reported on the balance sheet within the headings ‘Derivative financial instruments’. The nearest equivalent GAAP measures on an IFRS basis are finance debt and finance debt ratio. A reconciliation of finance debt to net debt is provided on page 23.

We are unable to present reconciliations of forward-looking information for gearing to finance debt ratio, because without unreasonable efforts, we are unable to forecast accurately certain adjusting items required to present a meaningful comparable GAAP forward-looking financial measure. These items include fair value asset (liability) of hedges related to finance debt and cash and cash equivalents, that are difficult to predict in advance in order to include in a GAAP estimate.

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 and 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 a cash 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 26.

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.

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Glossary (continued)

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

Net debt including leases is a non-GAAP measure. Net debt including leases is calculated as net debt plus lease liabilities, less the net amount of partner receivables and payables relating to leases entered into on behalf of joint operations. BP believes this measure provides useful information to investors as it enables investors to understand the impact of the group’s lease portfolio on net debt. The nearest equivalent GAAP measure on an IFRS basis is finance debt. A reconciliation of finance debt to net debt including leases is provided on page 23.

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.

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 7, 9 and 11, and by segment and type is shown on page 27.

Operating cash flow is net cash provided by (used in) operating activities as stated in the condensed group cash flow statement. When used in the context of a segment rather than the group, the terms refer to the segment’s share thereof.

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

Organic capital expenditure is a subset of capital expenditure and is a non-GAAP measure. Organic capital expenditure comprises capital expenditure 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 26.

We are unable to present reconciliations of forward-looking information for organic capital expenditure to total cash capital expenditure, because without unreasonable efforts, we are unable to forecast accurately the adjusting item, inorganic capital expenditure, that is difficult to predict in advance in order to derive the nearest GAAP estimate.

Production-sharing agreement (PSA) is an arrangement through which an oil and gas 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.

Readily marketable inventory (RMI) is inventory held and price risk-managed by our integrated supply and trading function (IST) which could be sold to generate funds if required. It comprises oil and oil products for which liquid markets are available and excludes inventory which is required to meet operational requirements and other inventory which is not price risk-managed. RMI is reported at fair value. Inventory held by the Downstream fuels business for the purpose of sales and marketing, and all inventories relating to the lubricants and petrochemicals businesses, are not included in RMI.

Paid-up RMI excludes RMI which has not yet been paid for. For inventory that is held in storage, a first-in first-out (FIFO) approach is used to determine whether inventory has been paid for or not. Unpaid RMI is RMI which has not yet been paid for by BP. RMI, RMI at fair value, Paid-up RMI and Unpaid RMI are non-GAAP measures. Further information is provided on page 29.

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 for BP-operated refineries, which is defined as the percentage of the year that a unit is available for processing after subtracting the annualized time lost due to turnaround activity and all planned mechanical, process and regulatory downtime.

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

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Glossary (continued)

Replacement cost (RC) profit or loss reflects the replacement cost of inventories sold in the period and is arrived at by excluding inventory holding gains and losses from profit or loss. RC profit or loss 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. A reconciliation to GAAP information is provided on page 1. RC profit or loss before interest and tax is the measure of profit or loss that is required to be disclosed for each operating segment under IFRS.

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.

Reported recordable injury frequency measures the number of reported work-related employee and contractor incidents that result in a fatality or injury per 200,000 hours worked. This represents reported incidents occurring within BP’s operational HSSE reporting boundary. That boundary includes BP’s own operated facilities and certain other locations or situations.

Solomon availability – See Refining availability definition.

Tier 1 and tier 2 process safety events – Tier 1 events are losses of primary containment from a process of greatest consequence – causing harm to a member of the workforce, damage to equipment from a fire or explosion, a community impact or exceeding defined quantities. Tier 2 events are those of lesser consequence. These represent reported incidents occurring within BP’s operational HSSE reporting boundary. That boundary includes BP’s own operated facilities and certain other locations or situations.

Underlying effective tax rate (ETR) is a non-GAAP measure. The underlying ETR is calculated by dividing taxation on an underlying replacement cost (RC) basis 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 underlying 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.

We are unable to present reconciliations of forward-looking information for underlying ETR to ETR on profit or loss for the period, because without unreasonable efforts, we are unable to forecast accurately certain adjusting items required to present a meaningful comparable GAAP forward-looking financial measure. These items include the taxation on inventory holding gains and losses, non-operating items and fair value accounting effects, that are difficult to predict in advance in order to include in a GAAP estimate.

Underlying production – 2019 underlying production, when compared with 2018, is production after adjusting for BPX Energy, other acquisitions and 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 27 and 28 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 earnings on page 1 refer to underlying RC profit for the group. A reconciliation to GAAP information is provided on page 1.

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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Glossary (continued)

Upstream plant reliability (BP-operated) is calculated taking 100% less the ratio of total unplanned plant deferrals divided by installed production capacity. Unplanned plant deferrals are associated with the topside plant and where applicable the subsea equipment (excluding wells and reservoir). Unplanned plant deferrals include breakdowns, which does not include Gulf of Mexico weather related downtime.

Upstream unit production cost is calculated as production cost divided by units of production. Production cost does not include ad valorem and severance taxes. Units of production are barrels for liquids and thousands of cubic feet for gas. Amounts disclosed are for BP subsidiaries only and do not include BP’s share of equity-accounted entities.

Working capital - Change in working capital is movements in inventories and other current and non-current assets and liabilities as reported in the condensed group cash flow statement. Change in working capital adjusted for inventory holding gains/losses is a non-GAAP measure. It is calculated by adjusting for inventory holding gains/losses reported in the period and this therefore represents what would have been reported as movements in inventories and other current and non-current assets and liabilities, if the starting point in determining net cash provided by operating activities had been replacement cost profit rather than profit for the period. The nearest equivalent measure on an IFRS basis for this is movements in inventories and other current and non-current assets and liabilities. In the context of describing operating cash flow excluding Gulf of Mexico oil spill payments, change in working capital also excludes movements in inventories and other current and non-current assets and liabilities relating to the Gulf of Mexico oil spill. See page 30 for further details.

BP utilizes various arrangements in order to manage its working capital including discounting of receivables and, in the supply and trading business, the active management of supplier payment terms, inventory and collateral.

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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’) and the general doctrine of cautionary statements, 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 and circumstances - 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, the following, among other statements, are all forward looking in nature: expectations regarding the expected quarterly dividend payment and timing of such payment and the suspension of the scrip dividend alternative and introduction of dividend reinvestment plans; expectations regarding the underlying effective tax rate in 2019; expectations regarding 2019 organic capital expenditure and depreciation, depletion and amortization charges; expectations that net debt levels will trend down over time and that gearing will remain above the target 20-30% range before reducing towards the middle of the range in 2020; expectations regarding share buybacks, including to offset the impact of dilution from the scrip program; plans and expectations relating to divestments and disposals, including that around $10 billion of divestment transactions will be announced by the end of 2019; plans and expectations regarding the announced sale of BP’s interests in Alaska to a subsidiary of Hilcorp Energy, including the completion of the sale and expected timing and proceeds thereof; plans and expectations with respect to the joint venture in India with Reliance Industries Limited; plans and expectations regarding BP’s low-carbon business, including with regard to BP’s joint venture with DiDi to develop an electric vehicle charging network in China and to the installation of 400 ultra-fast chargers at BP Chargemaster’s UK retail sites; plans and expectations to run jointly branded workshop pilots in China and the US with Bosch; plans and expectations regarding BP Infinia; plans to deploy continuous measurement of methane emissions on all future major operated oil and gas processing projects; expectations regarding Upstream fourth-quarter 2019 reported production, seasonal maintenance and turnaround activities; expectations regarding Downstream fourth-quarter 2019 refining margins and turnaround activity; expectations regarding the amount of the Rosneft dividend; plans and expectations regarding Lightsource BP, including to develop a solar facility in Colorado and negotiate power purchase agreements to supply customers across Spain’s Zaragoza province; plans and expectations with respect to the joint venture between BP’s Brazilian biofuels business and Bunge, including the completion of the joint venture transaction and the timing thereof; expectations regarding the Other businesses and corporate 2019 average quarterly charges excluding non-operating items; and expectations with respect to the amount of future payments relating to the Gulf of Mexico oil spill. 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 acquisitions and 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; delays in the processes for resolving claims; amounts ultimately payable and timing of payments relating to the Gulf of Mexico oil spill; exchange rate fluctuations; development and use of new technology; recruitment and retention of a skilled workforce; the success or otherwise of partnering; the actions of competitors, trading partners, contractors, subcontractors, creditors, rating agencies and others; our access to future credit resources; business disruption and crisis management; the impact on our reputation of ethical misconduct and non-compliance with regulatory obligations; trading losses; major uninsured losses; decisions by Rosneft’s management and board of directors; the actions of contractors; natural disasters and adverse weather conditions; changes in public expectations and other changes to business conditions; wars and acts of terrorism; cyber-attacks or sabotage; and other factors discussed elsewhere in this report, and under “Risk factors” in BP Annual Report and Form 20-F 2018 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	Craig Marshall	Brian Sullivan
bp.com/investors	+44 (0)20 7496 4962	+1 281 892 3421

BP p.l.c.’s LEI Code 213800LH1BZH3D16G760

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: 29 October 2019
	/s/ Ben J. S. Mathews
	------------------------
	Ben J. S. Mathews
	Company Secretary