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 30 July, 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|

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


FOR IMMEDIATE RELEASE		Top of page 1
London 30 July 2019

BP p.l.c. Group results
Second quarter and half year 2019(a)

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/1061H_1-2019-7-29.pdf

Highlights

Midway through 5-year plan, continuing to deliver strong performance and strategic progress

●

Strong financial results

Underlying replacement cost profit for the second quarter of 2019 was $2.8 billion, similar to a year earlier. The quarter’s result largely reflected continued good operating performance, offset by oil prices lower than in the second quarter of 2018.

Non-operating items in the second quarter of $0.9 billion, post-tax, related mainly to impairment charges.

Operating cash flow, excluding Gulf of Mexico oil spill payments, was $8.2 billion for the second quarter, including a $1.5-billion working capital release (after adjusting for net inventory holding gains), and $14.2 billion for the first half, including a $0.5-billion working capital release.

Gulf of Mexico oil spill payments of $1.4 billion on a post-tax basis in the second quarter were primarily the scheduled annual payments.

A dividend of 10.25 cents a share was announced for the quarter.

● Solid Upstream and Downstream performance

Reported oil and gas production for the quarter averaged 3.8 million barrels a day of oil equivalent, 4% higher than a year earlier.

With the start-up of Culzean in the North Sea this quarter, four Upstream major projects have begun production in the first half of the year.

Final investment decisions were taken in the quarter for new Upstream major projects in India and the Gulf of Mexico, as well as agreement for additional investment in Angola.

In Downstream, quarter on quarter growth in lubricants and fuels marketing, more than offset by planned turnarounds ahead of IMO 2020.

● Growing low carbon businesses

BP agreed to combine its Brazilian biofuels and biopower business with that of Bunge in a new equally-owned joint venture. On completion, BP’s interest in the venture will be more than 50% larger than its existing biofuels business.

Lightsource BP (43% owned by BP) has continued to make strong progress, including agreeing a significant expansion in Brazil.

BP agreed a $30 million venturing investment in Calysta, which will use BP's natural gas to produce protein feed for aquaculture and agriculture.

See chart on PDF

Bob Dudley – Group chief executive:

At the midpoint of our five-year plan, BP is right on target. Reliable performance and disciplined growth across our businesses are delivering strong earnings, cash flow and returns to shareholders. And this is also allowing us to grow businesses that can make a significant contribution in the energy transition, helping deliver the energy the world needs with lower carbon.

Financial summary	Second		First		Second		First		First
	quarter		quarter		quarter		half		half
$ million	2019		2019		2018		2019		2018
Profit for the period attributable to BP shareholders	1,822		2,934		2,799		4,756		5,268
Inventory holding (gains) losses, net of tax	(47	)	(839	)	(1,010	)	(886	)	(1,090	)
RC profit	1,775		2,095		1,789		3,870		4,178
Net (favourable) adverse impact of non-operating items and fair value accounting effects, net of tax	1,036		263		1,033		1,299		1,230
Underlying RC profit	2,811		2,358		2,822		5,169		5,408
RC profit per ordinary share (cents)	8.72		10.38		8.96		19.10		20.96
RC profit per ADS (dollars)	0.52		0.62		0.54		1.15		1.26
Underlying RC profit per ordinary share (cents)	13.82		11.69		14.14		25.51		27.13
Underlying RC profit per ADS (dollars)	0.83		0.70		0.85		1.53		1.63

(a)

This results announcement also represents BP's half-yearly financial report (see page 12).

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 major projects, inventory holding gains and losses, non-operating items and fair value accounting effects are defined in the Glossary on page 35.

The commentary above and following should be read in conjunction with the cautionary statement on page 39.

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Group headlines

Results

For the half year, underlying replacement cost (RC) profit* was $5,169 million, compared with $5,408 million in 2018. Underlying RC profit is after adjusting RC profit* for a net charge for non-operating items* of $1,113 million, mainly relating to impairment charges, and net adverse fair value accounting effects* of $186 million (both on a post-tax basis).

RC profit was $3,870 million for the half year, compared with $4,178 million in 2018.

For the second quarter, underlying RC profit was $2,811 million, compared with $2,822 million in 2018. Underlying RC profit is after adjusting RC profit for a net charge for non-operating items of $861 million, mainly relating to impairment charges, and net adverse fair value accounting effects of $175 million (both on a post-tax basis).

RC profit was $1,775 million for the second quarter, compared with $1,789 million in 2018.

BP’s profit for the second quarter and half year was $1,822 million and $4,756 million respectively, compared with $2,799 million and $5,268 million for the same periods in 2018.

See further information on pages 3, 29 and 30.

Depreciation, depletion and amortization

The charge for depreciation, depletion and amortization was $4.6 billion in the quarter and $9.0 billion in the half year. In the same periods in 2018 it was $3.8 billion and $7.7 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 second quarter and half year was 39% and 41% respectively, compared with 49% and 42% for the same periods in 2018. Adjusting for non-operating items and fair value accounting effects, the underlying ETR* for the second quarter and half year was 34% and 37% respectively, compared with 42% and 40% for the same periods a year ago. The underlying ETR for the quarter and the half year is lower than a year ago mainly due to the absence of deferred tax charges from 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 September 2019. The corresponding amount in sterling will be announced on 10 September 2019. See page 25 for further information.

Share buybacks

BP repurchased 11 million ordinary shares at a cost of $75 million, including fees and stamp duty, during the second quarter of 2019. For the half year, BP repurchased 17 million ordinary shares at a cost of $125 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 $8.2 billion for the second quarter and $14.2 billion for the half year. These amounts include a working capital* release of $1.5 billion in the second quarter and $0.5 billion in the half year, after adjusting for net inventory holding gains* and working capital effects of the Gulf of Mexico oil spill. The comparable amounts for the same periods in 2018 were $7.0 billion and $12.4 billion (prior to the implementation of IFRS 16).

Operating cash flow as reported in the group cash flow statement was $6.8 billion for the second quarter and $12.1 billion for the half year. These amounts include a working capital build of $58 million and $2.8 billion respectively. The comparable amounts for the same periods in 2018 were $6.3 billion and $10.0 billion (prior to the implementation of IFRS 16).

See page 32 and Glossary for further information on Gulf of Mexico oil spill cash flows and on working capital.

Capital expenditure*

Organic capital expenditure* for the second quarter and half year was $3.7 billion and $7.3 billion respectively. We reported $3.5 billion and $7.0 billion for the same periods in 2018 (prior to the implementation of IFRS 16).

Inorganic capital expenditure* for the second quarter and half year was $2.0 billion and $4.0 billion respectively, including $1.7 billion for the quarter and $3.5 billion for the half year relating to the BHP acquisition, compared with $0.4 billion and $0.8 billion for the same periods in 2018.

Organic capital expenditure and inorganic capital expenditure are non-GAAP measures. See page 28 for further information.

Divestment and other proceeds

Divestment proceeds* were $0.1 billion for the second quarter and $0.7 billion for the half year, compared with $0.2 billion and $0.3 billion for the same periods in 2018.

Gearing*

Net debt* at 30 June 2019 was $46.5 billion, compared with $38.7 billion a year ago. Gearing at 30 June 2019 was 31.0%, compared with 27.5% a year ago. Net debt and gearing are non-GAAP measures. See page 25 for more information.

Brian Gilvary – Chief financial officer:

We have announced another resilient set of quarterly results, in particular delivering strong underlying cash* of over $8 billion. Following the final acquisition payments to BHP and the scheduled annual payments relating to the Gulf of Mexico oil spill being made in the quarter, we continue to expect gearing to trend down through 2020 in line with disposal proceeds from our $10 billion programme and ongoing operating cash flow delivery.

* For items marked with an asterisk throughout this document, definitions are provided in the Glossary on page 35.

For more information on the impact of IFRS 16 'Leases' on key financial metrics, see page 27.

The commentary above contains forward-looking statements and should be read in conjunction with the cautionary statement on page 39.

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Analysis of underlying RC profit* before interest and tax

	Second		First		Second		First		First
	quarter		quarter		quarter		half		half
$ million	2019		2019		2018		2019		2018
Underlying RC profit before interest and tax
Upstream	3,413		2,928		3,508		6,341		6,665
Downstream	1,365		1,733		1,455		3,098		3,281
Rosneft	638		567		766		1,205		1,013
Other businesses and corporate	(290	)	(418	)	(477	)	(708	)	(869	)
Consolidation adjustment – UPII*	34		(13	)	151		21		(9	)
Underlying RC profit before interest and tax	5,160		4,797		5,403		9,957		10,081
Finance costs and net finance expense relating to pensions and other post-retirement benefits	(752	)	(754	)	(448	)	(1,506	)	(912	)
Taxation on an underlying RC basis	(1,515	)	(1,620	)	(2,059	)	(3,135	)	(3,625	)
Non-controlling interests	(82	)	(65	)	(74	)	(147	)	(136	)
Underlying RC profit attributable to BP shareholders	2,811		2,358		2,822		5,169		5,408

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 for the period

	Second		First		Second		First		First
	quarter		quarter		quarter		half		half
$ million	2019		2019		2018		2019		2018
RC profit before interest and tax
Upstream	2,469		2,884		3,514		5,353		6,688
Downstream	1,288		1,765		840		3,053		2,553
Rosneft	525		486		766		1,011		1,013
Other businesses and corporate	(381	)	(546	)	(1,025	)	(927	)	(1,596	)
Consolidation adjustment – UPII	34		(13	)	151		21		(9	)
RC profit before interest and tax	3,935		4,576		4,246		8,511		8,649
Finance costs and net finance expense relating to pensions and other post-retirement benefits	(868	)	(882	)	(566	)	(1,750	)	(1,150	)
Taxation on a RC basis	(1,210	)	(1,534	)	(1,817	)	(2,744	)	(3,185	)
Non-controlling interests	(82	)	(65	)	(74	)	(147	)	(136	)
RC profit attributable to BP shareholders	1,775		2,095		1,789		3,870		4,178
Inventory holding gains (losses)*	81		1,088		1,310		1,169		1,402
Taxation (charge) credit on inventory holding gains and losses	(34	)	(249	)	(300	)	(283	)	(312	)
Profit for the period attributable to BP shareholders	1,822		2,934		2,799		4,756		5,268

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Strategic progress

Upstream

Upstream production, which excludes Rosneft, for the first half of the year averaged 2,640mboe/d, 4.2% higher than a year earlier. Underlying production*, adjusted for portfolio changes and PSA* impacts was broadly flat.

Culzean in the North Sea (BP 32%) was BP’s fourth Upstream major project* to start up in 2019 and the 23rd since the start of 2016.

Final investment decisions were made for the Thunder Horse South Expansion Phase 2 project in the US Gulf of Mexico and the MJ project on Block KG D6 offshore India. BP and partners also agreed additional investment expected to increase and extend production from deepwater Block 15 offshore Angola.

In the quarter BP agreed the sale of mature oil interests in the Gulf of Suez, Egypt, including its interests in GUPCO, to Dragon Oil of Dubai. BP has agreed to sell its interest in oil and gas fields in Cleveland and McClain counties in Oklahoma, US.

Downstream

In fuels marketing, first-half earnings grew by more than 15% year on year.

Groupe Renault has recently appointed Castrol as its global service fill engine oil lubricants partner, effective from 1 January 2020. In addition Castrol extended the Renault Sport Racing Formula 1 sponsorship through to the end of 2024, further strengthening this strategic partnership.

Advancing the energy transition

In a significant advance for its biofuels position, in July BP announced it has agreed to combine its Brazilian biofuels and biopower business with that of Bunge to form a new equally-owned joint venture, BP Bunge Bioenergia. On completion, subject to regulatory approvals, BP’s 50% interest in the new venture will be more than 50% larger than its existing biofuels business.

BP’s equity-accounted solar entity Lightsource BP (LSBP) announced in July the acquisition of approximately two gigawatts of greenfield solar projects at various development stages across Brazil.

BP continues to make progress in its advanced mobility agenda. BP Chargemaster expanded its UK network of chargers by around 600 to 7,200 over the first half of 2019 and in the coming weeks will begin installing the first of 400 ultra-fast chargers at BP retail sites in the UK.

BP Ventures announced a $30-million investment into Calysta, whose technology produces protein with natural gas as a feedstock. Its innovative process offers the potential to sustainably produce protein feed to meet fast-growing demand from aquaculture and agriculture.

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 $14.2 billion for the half year of 2019. For the half year of 2018, we reported $12.4 billion (prior to the implementation of IFRS 16).

Organic capital expenditure for the half year of 2019 was $7.3 billion. BP expects 2019 organic capital expenditure to be in the range of $15-17 billion.

Lease liability payments of principal for the half year of 2019 were $1.2 billion.

Divestment proceeds and announced transactions totalled $1.5 billion in the first half of 2019. BP continues to expect to divest more than $10 billion by the end of 2020.

Gulf of Mexico oil spill payments on a post-tax basis totalled $2.1 billion in the half year. 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 half year was 31.0%. See page 25 for more information. Assuming recent average oil prices, and in line with expected growth in free cash flow supported by divestment proceeds, we expect gearing to move towards the middle of our targeted range of 20-30% in 2020.

Safety

Tier 1 and tier 2 process safety events* increased in the first half of 2019 compared with the same period in 2018. This increase mainly related to tier 2 events. Safety remains our number one priority and we remain focused on reducing both tier 1 and tier 2 process safety events.

Operating metrics	First half 2019	Financial metrics	First half 2019
Operating metrics	(vs. First half 2018)	Financial metrics	(vs. First half 2018)
Tier 1 and tier 2 process safety events	49	Underlying RC profit*	$5.2bn
Tier 1 and tier 2 process safety events	(+16)	Underlying RC profit*	(-$0.2bn)
Reported recordable injury frequency*	0.19	Operating cash flow excluding Gulf of Mexico oil spill payments (post-tax)(b)	$14.2bn
Reported recordable injury frequency*	(-15%)		(+$1.8bn)
Group production	3,786mboe/d	Organic capital expenditure	$7.3bn
Group production	(+3.4%)	Organic capital expenditure	(+$0.3bn)
Upstream production (excludes Rosneft segment)	2,640mboe/d	Gulf of Mexico oil spill payments (post-tax)	$2.1bn
Upstream production (excludes Rosneft segment)	(+4.2%)	Gulf of Mexico oil spill payments (post-tax)	(-$0.4bn)
Upstream unit production costs(a)	$7.02/boe	Divestment proceeds*	$0.7bn
Upstream unit production costs(a)	(-4.1%)	Divestment proceeds*	(+$0.4bn)
BP-operated Upstream plant reliability	94.9%	Gearing	31.0%
BP-operated Upstream plant reliability	(-0.9)	Gearing	(+3.5)
BP-operated refining availability*	93.9%	Dividend per ordinary share(c)	10.25 cents
BP-operated refining availability*	(-0.1)	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)

First half 2019 includes estimated $1.0 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 39.

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Upstream

	Second	First		Second		First	First
	quarter	quarter		quarter		half	half
$ million	2019	2019		2018		2019	2018
Profit before interest and tax	2,459	2,886		3,518		5,345	6,693
Inventory holding (gains) losses*	10	(2	)	(4	)	8	(5	)
RC profit before interest and tax	2,469	2,884		3,514		5,353	6,688
Net (favourable) adverse impact of non-operating items* and fair value accounting effects*	944	44		(6	)	988	(23	)
Underlying RC profit before interest and tax*(a)	3,413	2,928		3,508		6,341	6,665

(a)

See page 7 for a reconciliation to segment RC profit before interest and tax by region.

Financial results

The replacement cost profit before interest and tax for the second quarter and half year was $2,469 million and $5,353 million respectively, compared with $3,514 million and $6,688 million for the same periods in 2018. The second quarter and half year included a net non-operating charge of $766 million and $770 million respectively, compared with a net gain of $27 million and a net charge of $77 million for the same periods in 2018. Fair value accounting effects in the second quarter and half year had an adverse impact of $178 million and $218 million respectively, compared with an adverse impact of $21 million and a favourable impact of $100 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 second quarter and half year was $3,413 million and $6,341 million respectively, compared with $3,508 million and $6,665 million for the same periods in 2018. The results for the second quarter and half year mainly reflected lower liquids realizations, partly offset by ramp up of major projects* in the US Gulf of Mexico and North Sea and very strong gas marketing and trading.

Production

Production for the quarter was 2,625mboe/d, 6.5% higher than the second quarter of 2018. Underlying production* for the quarter increased by 0.7%, mainly due to the ramp-up of major projects.

For the half year, production was 2,640mboe/d, 4.2% higher than 2018. Underlying production* was broadly flat.

Key events

On 6 May, BP announced the final investment decision for the Thunder Horse South Expansion Phase 2 in the US Gulf of Mexico (BP operator 75%, ExxonMobil 25%).

On 3 June, BP announced an agreement to sell its interests in Gulf of Suez oil concessions in Egypt to Dragon Oil. The agreement, which is subject to the Egyptian Ministry of Petroleum and Mineral Resources' approval, includes producing and exploration concessions, including BP’s interest in the Gulf of Suez Petroleum Company (GUPCO).

On 4 June, BP confirmed the discovery of King Embayment in the Mars corridor, in the US Gulf of Mexico (Shell operator 71.5%, BP 28.5%).

On 6 June, BP confirmed further investment into deepwater Block 15, offshore Angola. The agreement will extend the production-sharing agreement* for Block 15 through 2032. (Exxon 36% operator, BP 24%, ENI 18%, and Equinor 12%).

On 11 June, BP and Reliance Industries Limited (RIL) announced the sanction of the MJ gas development project in Block KG D6, offshore the east coast of India. MJ is the third of three new projects in the Block KG D6 integrated development plan (RIL operator 60%, BP 30%, NIKO 10%).

On 11 June, BP confirmed the start-up of gas production from the Culzean field in the UK North Sea (Total operator 49.99%, BP 32%, JX Nippon 18.01%).

On 19 June, BP confirmed an agreement to sell its interest in oil and gas fields in Cleveland and McClain counties in Oklahoma, US.

On 1 July, BP confirmed the Greater Tortue Ahmeyim-1 appraisal well, located offshore Senegal, encountered approximately 30 metres of net gas pay in high-quality Albian reservoir confirming gas resource expectations (BP operator 56%, Kosmos 27%, Petrosen 10%, SMHPM 7%).

On 17 July, BP confirmed the Bélé-1 and Tuk-1 gas discoveries, as well as the successful Hi-Hat-1 appraisal well, located offshore Trinidad and Tobago (BHP operator 70%, BP 30%).

During the second quarter, BP achieved new access in Argentina’s first offshore licensing round blocks CAN-111 and CAN-113 (Total operator 50%, BP 50%), offshore Gambia block A1 (BP 100%), West of Shetland in the North Sea for one licence covering 10 blocks (BP operator 50%, Shell 50%), and a farm-in to an exploration permit WA-359-P offshore Western Australia (BP operator 42.5%, Cue 21.5%, Beach 21%, New Zealand Oil & Gas 15%).

This builds on the progress announced in our first-quarter results, which comprised the following: the Constellation development in the US Gulf of Mexico commenced production; commencement of gas production from the second stage of Egypt’s West Nile Delta development, in the Giza and Fayoum fields; first gas from the Angelin project in Trinidad; BPX Energy assumed control of all Petrohawk Energy Corporation operations from BHP; BP and Environmental Defense Fund announced a three-year strategic commitment to advance technologies to reduce methane emissions from the global oil and gas supply chain; a gas discovery in the

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Upstream (continued)

Nour exploration prospect located in the Nour North Sinai Concession, located in the Eastern Egyptian Mediterranean; a fund of up to $100-million for projects that will deliver new greenhouse gas (GHG) emissions reductions in its Upstream oil and gas operations; and final investment decisions on Seagull, a development tieback in the Central UK North Sea and on the Azeri Central East (ACE) project, the next stage of the Azeri-Chirag-Deepwater Gunashli (ACG) field.

Outlook

Looking ahead, we expect third-quarter 2019 reported production to be lower than second-quarter reflecting continued seasonal turnaround and maintenance activities, including in the North Sea, Angola and the US Gulf of Mexico, as well as the impact of Hurricane Barry on operations in the US Gulf of Mexico.

The commentary above contains forward-looking statements and should be read in conjunction with the cautionary statement on page 39.

	Second		First		Second		First		First
	quarter		quarter		quarter		half		half
$ million	2019		2019		2018		2019		2018
Underlying RC profit before interest and tax
US	861		612		742		1,473		1,268
Non-US	2,552		2,316		2,766		4,868		5,397
	3,413		2,928		3,508		6,341		6,665
Non-operating items(a)
US	(446	)	(30	)	(29	)	(476	)	(174	)
Non-US	(320	)	26		56		(294	)	97
	(766	)	(4	)	27		(770	)	(77	)
Fair value accounting effects
US	(225	)	(93	)	(143	)	(318	)	(152	)
Non-US	47		53		122		100		252
	(178	)	(40	)	(21	)	(218	)	100
RC profit before interest and tax
US	190		489		570		679		942
Non-US	2,279		2,395		2,944		4,674		5,746
	2,469		2,884		3,514		5,353		6,688
Exploration expense
US	69		25		77		94		386
Non-US	77		342		87		419		292
	146		367		164		513		678
Of which: Exploration expenditure written off	77		284		81		361		507
Production (net of royalties)(b)
Liquids* (mb/d)
US	506		455		411		480		429
Europe	137		159		147		148		143
Rest of World	658		685		659		672		695
	1,301		1,299		1,217		1,300		1,267
Natural gas (mmcf/d)
US	2,410		2,310		1,744		2,360		1,767
Europe	132		145		202		139		209
Rest of World	5,138		5,417		5,297		5,276		5,376
	7,680		7,872		7,242		7,775		7,352
Total hydrocarbons* (mboe/d)
US	921		853		711		887		734
Europe	160		184		182		172		180
Rest of World	1,544		1,619		1,572		1,581		1,622
	2,625		2,656		2,465		2,640		2,535
Average realizations*(c)
Total liquids(d) ($/bbl)	62.63		56.47		67.24		59.61		64.21
Natural gas ($/mcf)	3.35		4.02		3.65		3.68		3.72
Total hydrocarbons ($/boe)	40.64		39.37		43.37		40.02		42.36

(a)

Second quarter and first half 2019 include impairment charges related to BPX Energy and GUPCO divestments.

(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

	Second		First		Second		First		First
	quarter		quarter		quarter		half		half
$ million	2019		2019		2018		2019		2018
Profit (loss) before interest and tax	1,381		2,811		2,036		4,192		3,818
Inventory holding (gains) losses*	(93	)	(1,046	)	(1,196	)	(1,139	)	(1,265	)
RC profit before interest and tax	1,288		1,765		840		3,053		2,553
Net (favourable) adverse impact of non-operating items* and fair value accounting effects*	77		(32	)	615		45		728
Underlying RC profit before interest and tax*(a)	1,365		1,733		1,455		3,098		3,281

(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 second quarter and half year was $1,288 million and $3,053 million respectively, compared with $840 million and $2,553 million for the same periods in 2018.

The second quarter and half year include a net non-operating charge of $31 million and $35 million respectively, compared with a charge of $225 million and $278 million for the same periods in 2018. Fair value accounting effects had an adverse impact of $46 million in the second quarter and an adverse impact of $10 million in the half year, compared with an adverse impact of $390 million and $450 million for the same periods 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 $961 million for the second quarter and $2,253 million for the half year, compared with $1,054 million and $2,452 million for the same periods in 2018. The result for the quarter and half year reflects the impact of significantly higher turnaround activity, lower refining margins and weaker North American heavy crude oil differentials partially offset by a stronger contribution from supply and trading. The result for the half year also reflects strong fuels marketing growth driven by higher retail earnings. Year on year we have grown the number of convenience partnership sites and continued to deliver premium fuel volume growth.

Lubricants

The lubricants business reported an underlying replacement cost profit before interest and tax of $321 million for the second quarter and $593 million for the half year, compared with $326 million and $657 million for the same periods in 2018. The result for the quarter and half year reflects the impact of adverse foreign exchange rate movements. Year on year we have continued to make strategic progress, delivering record premium brand volumes in the quarter.

Petrochemicals

The petrochemicals business reported an underlying replacement cost profit before interest and tax of $83 million for the second quarter and $252 million for the half year, compared with $75 million and $172 million for the same periods in 2018. The result for the quarter reflects high levels of turnaround, similar to the second quarter of 2018. The result for the half year reflects increased margin optimization, supported by stronger operational reliability.

During the first quarter we announced an expansion of capacity at our joint venture petrochemicals facility in South Korea and signed an agreement with Virent and Johnson Matthey to further advance the development of bio-paraxylene, a key raw material for the production of renewable polyester.

Outlook

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

The commentary above contains forward-looking statements and should be read in conjunction with the cautionary statement on page 39.

Top of page 9

Downstream (continued)

	Second		First		Second		First		First
	quarter		quarter		quarter		half		half
$ million	2019		2019		2018		2019		2018
Underlying RC profit before interest and tax - by region
US	566		531		399		1,097		988
Non-US	799		1,202		1,056		2,001		2,293
	1,365		1,733		1,455		3,098		3,281
Non-operating items
US	2		1		(155	)	3		(172	)
Non-US	(33	)	(5	)	(70	)	(38	)	(106	)
	(31	)	(4	)	(225	)	(35	)	(278	)
Fair value accounting effects(a)
US	8		61		(299	)	69		(420	)
Non-US	(54	)	(25	)	(91	)	(79	)	(30	)
	(46	)	36		(390	)	(10	)	(450	)
RC profit before interest and tax
US	576		593		(55	)	1,169		396
Non-US	712		1,172		895		1,884		2,157
	1,288		1,765		840		3,053		2,553
Underlying RC profit before interest and tax - by business(b)(c)
Fuels	961		1,292		1,054		2,253		2,452
Lubricants	321		272		326		593		657
Petrochemicals	83		169		75		252		172
	1,365		1,733		1,455		3,098		3,281
Non-operating items and fair value accounting effects(a)
Fuels	(99	)	37		(584	)	(62	)	(694	)
Lubricants	22		(4	)	(26	)	18		(29	)
Petrochemicals	—		(1	)	(5	)	(1	)	(5	)
	(77	)	32		(615	)	(45	)	(728	)
RC profit before interest and tax(b)(c)
Fuels	862		1,329		470		2,191		1,758
Lubricants	343		268		300		611		628
Petrochemicals	83		168		70		251		167
	1,288		1,765		840		3,053		2,553

BP average refining marker margin (RMM)* ($/bbl)	15.2		10.2		14.9		12.7		13.3

Refinery throughputs (mb/d)
US	673		735		666		703		690
Europe	715		767		786		741		792
Rest of World	209		237		228		223		238
	1,597		1,739		1,680		1,667		1,720
BP-operated refining availability* (%)	93.4		94.3		93.1		93.9		94.0

Marketing sales of refined products (mb/d)
US	1,174		1,077		1,161		1,126		1,129
Europe	1,091		993		1,135		1,042		1,090
Rest of World	520		520		477		520		479
	2,785		2,590		2,773		2,688		2,698
Trading/supply sales of refined products	3,099		3,296		3,247		3,197		3,215
Total sales volumes of refined products	5,884		5,886		6,020		5,885		5,913

Petrochemicals production (kte)
US	584		601		404		1,185		903
Europe	1,226		1,160		1,094		2,386		2,222
Rest of World	1,156		1,299		1,358		2,455		2,749
	2,966		3,060		2,856		6,026		5,874

(a)

For Downstream, fair value accounting effects arise solely in the fuels business. See page 30 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

	Second	First		Second		First		First
	quarter	quarter		quarter		half		half
$ million	2019(a)	2019		2018		2019(a)		2018
Profit before interest and tax(b)(c)	523	526		876		1,049		1,145
Inventory holding (gains) losses*	2	(40	)	(110	)	(38	)	(132	)
RC profit before interest and tax	525	486		766		1,011		1,013
Net charge (credit) for non-operating items*	113	81		—		194		—
Underlying RC profit before interest and tax*	638	567		766		1,205		1,013

Financial results

Replacement cost (RC) profit before interest and tax for the second quarter and half year was $525 million and $1,011 million respectively, compared with $766 million and $1,013 million for the same periods in 2018.

After adjusting for non-operating items, the underlying RC profit before interest and tax for the second quarter and half year was $638 million and $1,205 million respectively. There were no non-operating items in the second quarter and half year in 2018.

Compared with the same periods in 2018, the result for the second quarter primarily reflects lower oil prices, adverse effects of duty lag and foreign exchange, whilst the result for the half year was primarily affected by favourable foreign exchange effects partially offset by lower oil prices.

BP’s two nominees, Bob Dudley and Guillermo Quintero, were re-elected to Rosneft’s board at Rosneft's annual general meeting (AGM) on 4 June 2019. At the AGM, shareholders also approved a resolution to pay a dividend of 11.33 roubles per ordinary share, which brings the total dividend for 2018 to 25.91 roubles per ordinary share, constituting 50% of the company’s IFRS net profit. BP received a payment of $334 million, after the deduction of withholding tax, on 16 July.

	Second	First	Second	First	First
	quarter	quarter	quarter	half	half
	2019(a)	2019	2018	2019(a)	2018
Production (net of royalties) (BP share)
Liquids* (mb/d)	912	937	909	924	906
Natural gas (mmcf/d)	1,250	1,327	1,262	1,288	1,285
Total hydrocarbons* (mboe/d)	1,127	1,166	1,127	1,146	1,127

(a)

The operational and financial information of the Rosneft segment for the second quarter and half year is based on preliminary operational and financial results of Rosneft for the three months and six months ended 30 June 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

	Second		First		Second		First		First
	quarter		quarter		quarter		half		half
$ million	2019		2019		2018		2019		2018
Profit (loss) before interest and tax	(381	)	(546	)	(1,025	)	(927	)	(1,596	)
Inventory holding (gains) losses*	—		—		—		—		—
RC profit (loss) before interest and tax	(381	)	(546	)	(1,025	)	(927	)	(1,596	)
Net charge (credit) for non-operating items*	91		128		548		219		727
Underlying RC profit (loss) before interest and tax*	(290	)	(418	)	(477	)	(708	)	(869	)
Underlying RC profit (loss) before interest and tax
US	(224	)	(155	)	(123	)	(379	)	(270	)
Non-US	(66	)	(263	)	(354	)	(329	)	(599	)
	(290	)	(418	)	(477	)	(708	)	(869	)
Non-operating items
US	(78	)	(128	)	(498	)	(206	)	(646	)
Non-US	(13	)	—		(50	)	(13	)	(81	)
	(91	)	(128	)	(548	)	(219	)	(727	)
RC profit (loss) before interest and tax
US	(302	)	(283	)	(621	)	(585	)	(916	)
Non-US	(79	)	(263	)	(404	)	(342	)	(680	)
	(381	)	(546	)	(1,025	)	(927	)	(1,596	)

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 second quarter and half year was $381 million and $927 million respectively, compared with $1,025 million and $1,596 million for the same periods in 2018.

The results included a net non-operating charge of $91 million for the second quarter and a charge of $219 million for the half year, primarily relating to costs of the Gulf of Mexico oil spill, compared with a charge of $548 million and $727 million for the same periods in 2018.

After adjusting for non-operating items, the underlying replacement cost loss before interest and tax for the second quarter and half year was $290 million and $708 million respectively, compared with $477 million and $869 million for the same periods in 2018.

Alternative Energy

The net ethanol-equivalent production (which includes ethanol and sugar) for the second quarter and half year was 254 million litres and 268 million litres respectively, compared with 259 million litres and 267 million litres for the same periods in 2018.

Net wind generation capacity* was 926MW at 30 June 2019, compared with 1,432MW at 30 June 2018. BP’s net share of wind generation for the second quarter and half year was 688GWh and 1,461GWh respectively, compared with 984GWh and 2,201GWh for the same periods in 2018. The lower production and reduced capacity in 2019 is due to divestments in the fourth quarter of 2018 and second quarter of 2019.

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 second quarter, Lightsource BP announced expansion of its activities in Brazil, acquiring a 1.9GW portfolio of greenfield solar projects from Enerlife. In the US, Lightsource BP has executed a long-term agreement to supply renewable power from a 100MW solar facility in Alabama and has also begun construction of a 20MW solar facility in Kansas. This builds on the first quarter announcement that the Green Growth Equity Fund, managed by Lightsource BP's Indian joint venture, EverSource Capital, is partnering with the National Investment and Infrastructure Fund (NIIF) and CDC Group plc to invest a total of $330 million in Ayana Renewable Power. Ayana was launched to develop utility scale solar and wind generation projects in India.

On 22 July, BP and Bunge Limited announced that they had agreed to form a 50:50 joint venture, BP Bunge Bioenergia, that will create a leading bioenergy company in Brazil. On completion, BP’s interest in the venture will increase its existing biofuels business by more than 50% and create opportunities to drive value from economies of scale, synergy and modernization of operations. The venture will have 11 biofuels sites in Brazil, with 32 million metric tonnes of combined crushing capacity per year. It will also generate renewable electricity – fuelled by waste biomass from the sugar cane – through its cogeneration facilities to power all its sites and sell surplus electricity to the Brazilian power grid.

In 2018, the two businesses produced a total of around 2.2 billion litres of ethanol equivalent and, after powering the sites, exported 1,200 gigawatt hours of low-carbon biopower to the national grid. Together the two businesses currently employ over 10,000 people in Brazil.

BP Ventures

During the second quarter, BP Ventures invested $30 million in Calysta, Inc., an alternative protein producer, that will use BP’s natural gas to produce protein for fish, livestock and pet feeds. Calysta’s proprietary gas fermentation technology produces FeedKind® protein, a sustainable feedstock that can be used for fish, livestock and pet nutritional products. The process has the potential to help meet the growing demand for feed in the aquaculture and wider agriculture markets, without some of the environmental impacts of current sourcing methods.

Outlook

During 2019, 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 39.

Top of page 12

Half-yearly financial report

This results announcement also represents BP’s half-yearly financial report for the purposes of the Disclosure Guidance and Transparency Rules made by the UK Financial Conduct Authority. In this context: (i) the condensed set of financial statements can be found on pages 14-26; (ii) pages 1-11, and 27-39 comprise the interim management report; and (iii) the directors’ responsibility statement and auditors’ independent review report can be found on pages 12-13.

Statement of directors’ responsibilities

The directors confirm that, to the best of their knowledge, the condensed set of financial statements on pages 14-26 has been prepared in accordance with IAS 34 ‘Interim Financial Reporting’, and that the interim management report on pages 1-11 and 27-39 includes a fair review of the information required by the Disclosure Guidance and Transparency Rules.

The directors of BP p.l.c. are listed on pages 58-62 of BP Annual Report and Form 20-F 2018, with the following exceptions. Admiral Frank Bowman and Alan Boeckmann retired at the 2019 Annual General Meeting on 21 May 2019.

By order of the board

Bob Dudley	Brian Gilvary
Group Chief Executive	Chief Financial Officer
29 July 2019	29 July 2019

Top of page 13

Independent review report to BP p.l.c.

Introduction

We have been engaged by the company to review the condensed set of financial statements in the half-yearly financial report for the six months ended 30 June 2019 which comprises the group income statement, condensed group statement of comprehensive income, condensed group statement of changes in equity, group balance sheet, condensed group cash flow statement and related notes 1 to 11. We have read the other information contained in the half-yearly financial report and considered whether it contains any apparent misstatements or material inconsistencies with the information in the condensed set of financial statements.

This report is made solely to the company in accordance with International Standard on Review Engagements (UK and Ireland) 2410 'Review of Interim Financial Information Performed by the Independent Auditor of the Entity' issued by the Financial Reporting Council. Our work has been undertaken so that we might state to the company those matters we are required to state to it in an independent review report and for no other purpose. To the fullest extent permitted by law, we do not accept or assume responsibility to anyone other than the company, for our review work, for this report, or for the conclusions we have formed.

Directors’ responsibilities

The half-yearly financial report is the responsibility of, and has been approved by, the directors. The directors are responsible for preparing the half-yearly financial report in accordance with the Disclosure Guidance and Transparency Rules of the United Kingdom’s Financial Conduct Authority.

As disclosed in Note 1, the annual financial statements of the group are prepared in accordance with International Financial Reporting Standards (IFRSs) as issued by the International Accounting Standards Board (IASB) and IFRSs as adopted by the European Union. The condensed set of financial statements included in this half-yearly financial report has been prepared in accordance with International Accounting Standard 34, 'Interim Financial Reporting', as issued by the IASB and as adopted by the European Union.

Our responsibility

Our responsibility is to express to the company a conclusion on the condensed set of financial statements in the half-yearly financial report based on our review.

Scope of review

We conducted our review in accordance with International Standard on Review Engagements (UK and Ireland) 2410 'Review of Interim Financial Information Performed by the Independent Auditor of the Entity' issued by the Financial Reporting Council for use in the United Kingdom. A review of interim financial information consists of making inquiries, primarily of persons responsible for financial and accounting matters, and applying analytical and other review procedures. A review is substantially less in scope than an audit conducted in accordance with International Standards on Auditing (UK) and consequently does not enable us to obtain assurance that we would become aware of all significant matters that might be identified in an audit. Accordingly, we do not express an audit opinion.

Conclusion

Based on our review, nothing has come to our attention that causes us to believe that the condensed set of financial statements in the half-yearly financial report for the six months ended 30 June 2019 is not prepared, in all material respects, in accordance with International Accounting Standard 34 as issued by the IASB and as adopted by the European Union and the Disclosure Guidance and Transparency Rules of the United Kingdom’s Financial Conduct Authority.

Deloitte LLP

Statutory Auditor

London

United Kingdom

29 July 2019

The maintenance and integrity of the BP p.l.c. website are the responsibility of the directors; the review work carried out by the statutory auditors does not involve consideration of these matters and, accordingly, the statutory auditors accept no responsibility for any changes that may have occurred to the financial information since it was initially presented on the website.

Legislation in the United Kingdom governing the preparation and dissemination of financial statements may differ from legislation in other jurisdictions.

Top of page 14

Financial statements

Group income statement

	Second	First	Second		First	First
	quarter	quarter	quarter		half	half
$ million	2019	2019	2018		2019	2018

Sales and other operating revenues (Note 4)	72,676	66,321	75,439		138,997	143,611
Earnings from joint ventures – after interest and tax	138	185	220		323	513
Earnings from associates – after interest and tax	608	649	1,027		1,257	1,441
Interest and other income	270	163	165		433	324
Gains on sale of businesses and fixed assets	55	89	56		144	161
Total revenues and other income	73,747	67,407	76,907		141,154	146,050
Purchases	55,683	48,272	58,424		103,955	109,936
Production and manufacturing expenses	5,391	5,356	5,515		10,747	10,953
Production and similar taxes (Note 6)	371	424	531		795	899
Depreciation, depletion and amortization (Note 5)	4,588	4,461	3,811		9,049	7,742
Impairment and losses on sale of businesses and fixed assets	906	96	(23	)	1,002	68
Exploration expense	146	367	164		513	678
Distribution and administration expenses	2,646	2,767	2,929		5,413	5,723
Profit (loss) before interest and taxation	4,016	5,664	5,556		9,680	10,051
Finance costs	853	867	535		1,720	1,088
Net finance expense relating to pensions and other post-retirement benefits	15	15	31		30	62
Profit (loss) before taxation	3,148	4,782	4,990		7,930	8,901
Taxation	1,244	1,783	2,117		3,027	3,497
Profit (loss) for the period	1,904	2,999	2,873		4,903	5,404
Attributable to
BP shareholders	1,822	2,934	2,799		4,756	5,268
Non-controlling interests	82	65	74		147	136
	1,904	2,999	2,873		4,903	5,404

Earnings per share (Note 7)
Profit (loss) for the period attributable to BP shareholders
Per ordinary share (cents)
Basic	8.95	14.54	14.03		23.47	26.42
Diluted	8.92	14.47	13.96		23.35	26.27
Per ADS (dollars)
Basic	0.54	0.87	0.84		1.41	1.59
Diluted	0.54	0.87	0.84		1.40	1.58

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Condensed group statement of comprehensive income

	Second		First		Second		First		First
	quarter		quarter		quarter		half		half
$ million	2019		2019		2018		2019		2018

Profit (loss) for the period	1,904		2,999		2,873		4,903		5,404
Other comprehensive income
Items that may be reclassified subsequently to profit or loss
Currency translation differences	131		989		(2,612	)	1,120		(2,081	)
Cash flow hedges and costs of hedging	133		19		(107	)	152		(189	)
Share of items relating to equity-accounted entities, net of tax	(30	)	(50	)	(33	)	(80	)	122
Income tax relating to items that may be reclassified	(9	)	(34	)	52		(43	)	(38	)
	225		924		(2,700	)	1,149		(2,186	)
Items that will not be reclassified to profit or loss
Remeasurements of the net pension and other post-retirement benefit liability or asset	(39	)	(853	)	1,714		(892	)	2,579
Cash flow hedges that will subsequently be transferred to the balance sheet	(7	)	8		(35	)	1		(22	)
Income tax relating to items that will not be reclassified	2		273		(557	)	275		(822	)
	(44	)	(572	)	1,122		(616	)	1,735
Other comprehensive income	181		352		(1,578	)	533		(451	)
Total comprehensive income	2,085		3,351		1,295		5,436		4,953
Attributable to
BP shareholders	2,001		3,281		1,268		5,282		4,848
Non-controlling interests	84		70		27		154		105
	2,085		3,351		1,295		5,436		4,953

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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	5,282		154		5,436
Dividends	(3,200	)	(119	)	(3,319	)
Cash flow hedges transferred to the balance sheet, net of tax	12		—		12
Repurchase of ordinary share capital	(125	)	—		(125	)
Share-based payments, net of tax	398		—		398
Share of equity-accounted entities’ changes in equity, net of tax	3		—		3
At 30 June 2019	101,485		2,138		103,623

	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	4,848		105		4,953
Dividends	(3,556	)	(70	)	(3,626	)
Cash flow hedges transferred to the balance sheet, net of tax	5		—		5
Repurchase of ordinary share capital	(200	)	—		(200	)
Share-based payments, net of tax	414		—		414
Transactions involving non-controlling interests, net of tax	(1	)	1		—
At 30 June 2018	99,821		1,949		101,770

(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 June	31 December
$ million	2019	2018(a)
Non-current assets
Property, plant and equipment	145,291	135,261
Goodwill	12,158	12,204
Intangible assets	15,631	17,284
Investments in joint ventures	8,637	8,647
Investments in associates	19,587	17,673
Other investments	1,250	1,341
Fixed assets	202,554	192,410
Loans	689	637
Trade and other receivables	2,146	1,834
Derivative financial instruments	6,014	5,145
Prepayments	776	1,179
Deferred tax assets	3,624	3,706
Defined benefit pension plan surpluses	5,816	5,955
	221,619	210,866
Current assets
Loans	313	326
Inventories	20,042	17,988
Trade and other receivables	24,343	24,478
Derivative financial instruments	3,384	3,846
Prepayments	1,001	963
Current tax receivable	930	1,019
Other investments	135	222
Cash and cash equivalents	20,674	22,468
	70,822	71,310
Assets classified as held for sale (Note 2)	721	—
	71,543	71,310
Total assets	293,162	282,176
Current liabilities
Trade and other payables	44,774	46,265
Derivative financial instruments	2,601	3,308
Accruals	4,143	4,626
Lease liabilities	2,094	44
Finance debt	8,677	9,329
Current tax payable	2,384	2,101
Provisions	2,070	2,564
	66,743	68,237
Liabilities directly associated with assets classified as held for sale (Note 2)	112	—
	66,855	68,237
Non-current liabilities
Other payables	12,654	13,830
Derivative financial instruments	5,187	5,625
Accruals	610	575
Lease liabilities	8,285	623
Finance debt	58,876	55,803
Deferred tax liabilities	9,672	9,812
Provisions	18,393	17,732
Defined benefit pension plan and other post-retirement benefit plan deficits	9,007	8,391
	122,684	112,391
Total liabilities	189,539	180,628
Net assets	103,623	101,548
Equity
BP shareholders’ equity	101,485	99,444
Non-controlling interests	2,138	2,104
Total equity	103,623	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.

Top of page 18

Condensed group cash flow statement

	Second		First		Second		First		First
	quarter		quarter		quarter		half		half
$ million	2019		2019		2018		2019		2018
Operating activities
Profit (loss) before taxation	3,148		4,782		4,990		7,930		8,901
Adjustments to reconcile profit (loss) before taxation to net cash provided by operating activities
Depreciation, depletion and amortization and exploration expenditure written off	4,665		4,745		3,892		9,410		8,249
Impairment and (gain) loss on sale of businesses and fixed assets	851		7		(79	)	858		(93	)
Earnings from equity-accounted entities, less dividends received	(395	)	(589	)	(988	)	(984	)	(1,524	)
Net charge for interest and other finance expense, less net interest paid	62		88		191		150		271
Share-based payments	117		297		167		414		404
Net operating charge for pensions and other post-retirement benefits, less contributions and benefit payments for unfunded plans	(68	)	(77	)	(62	)	(145	)	(264	)
Net charge for provisions, less payments	(198	)	(116	)	80		(314	)	224
Movements in inventories and other current and non-current assets and liabilities	(58	)	(2,695	)	(570	)	(2,753	)	(3,968	)
Income taxes paid	(1,309	)	(1,146	)	(1,315	)	(2,455	)	(2,248	)
Net cash provided by operating activities	6,815		5,296		6,306		12,111		9,952
Investing activities
Expenditure on property, plant and equipment, intangible and other assets	(3,833	)	(3,695	)	(3,484	)	(7,528	)	(7,070	)
Acquisitions, net of cash acquired	(1,747	)	(1,795	)	(1	)	(3,542	)	(1	)
Investment in joint ventures	(20	)	—		(18	)	(20	)	(57	)
Investment in associates	(54	)	(145	)	(322	)	(199	)	(660	)
Total cash capital expenditure	(5,654	)	(5,635	)	(3,825	)	(11,289	)	(7,788	)
Proceeds from disposal of fixed assets	70		235		105		305		190
Proceeds from disposal of businesses, net of cash disposed	8		365		45		373		127
Proceeds from loan repayments	64		55		24		119		33
Net cash used in investing activities	(5,512	)	(4,980	)	(3,651	)	(10,492	)	(7,438	)
Financing activities(a)
Net issue (repurchase) of shares	(80	)	(45	)	(90	)	(125	)	(200	)
Lease liability payments	(595	)	(617	)	(4	)	(1,212	)	(14	)
Proceeds from long-term financing	4,381		2,124		910		6,505		1,032
Repayments of long-term financing	(3,602	)	(2,640	)	(1,722	)	(6,242	)	(2,869	)
Net increase (decrease) in short-term debt	(119	)	1,089		292		970		(57	)
Net increase (decrease) in non-controlling interests	—		—		—		—		(1	)
Dividends paid - BP shareholders	(1,779	)	(1,435	)	(1,727	)	(3,214	)	(3,556	)
- non-controlling interests	(83	)	(36	)	(57	)	(119	)	(70	)
Net cash provided by (used in) financing activities	(1,877	)	(1,560	)	(2,398	)	(3,437	)	(5,735	)
Currency translation differences relating to cash and cash equivalents	(8	)	32		(314	)	24		(169	)
Increase (decrease) in cash and cash equivalents	(582	)	(1,212	)	(57	)	(1,794	)	(3,390	)
Cash and cash equivalents at beginning of period	21,256		22,468		22,242		22,468		25,575
Cash and cash equivalents at end of period	20,674		21,256		22,185		20,674		22,185

(a)

Financing cash flows for the second quarter and half year 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.

The directors consider it appropriate to adopt the going concern basis of accounting in preparing these interim financial statements.

BP prepares its consolidated financial statements included within BP Annual Report and Form 20-F on the basis of International Financial Reporting Standards (IFRS) as issued by the International Accounting Standards Board (IASB), IFRS as adopted by the European Union (EU) and in accordance with the provisions of the UK Companies Act 2006 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
1 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

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 will purchase producing and exploration concessions and BP's interest in the Gulf of Suez Petroleum Company (GUPCO). The deal, which is subject to the Egyptian Ministry of Petroleum and Mineral Resources' approval, is expected to complete during the second half of 2019. Assets and associated liabilities relating to these concessions, which are reported in the Upstream segment, have been classified as held for sale in the group balance sheet.

On 22 July, BP and Bunge announced that they will each contribute their existing Brazilian biofuel, biopower and sugar businesses into a new 50:50 joint venture. Assets and associated liabilities relating to the BP businesses will be classified as held for sale in the group’s balance sheet from 22 July. 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.

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Note 3. Analysis of replacement cost profit (loss) before interest and tax and reconciliation to profit (loss) before taxation

	Second		First		Second		First		First
	quarter		quarter		quarter		half		half
$ million	2019		2019		2018		2019		2018
Upstream	2,469		2,884		3,514		5,353		6,688
Downstream	1,288		1,765		840		3,053		2,553
Rosneft	525		486		766		1,011		1,013
Other businesses and corporate	(381	)	(546	)	(1,025	)	(927	)	(1,596	)
	3,901		4,589		4,095		8,490		8,658
Consolidation adjustment – UPII*	34		(13	)	151		21		(9	)
RC profit (loss) before interest and tax*	3,935		4,576		4,246		8,511		8,649
Inventory holding gains (losses)*
Upstream	(10	)	2		4		(8	)	5
Downstream	93		1,046		1,196		1,139		1,265
Rosneft (net of tax)	(2	)	40		110		38		132
Profit (loss) before interest and tax	4,016		5,664		5,556		9,680		10,051
Finance costs	853		867		535		1,720		1,088
Net finance expense relating to pensions and other post-retirement benefits	15		15		31		30		62
Profit (loss) before taxation	3,148		4,782		4,990		7,930		8,901

RC profit (loss) before interest and tax*
US	498		771		(20	)	1,269		339
Non-US	3,437		3,805		4,266		7,242		8,310
	3,935		4,576		4,246		8,511		8,649

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Note 4. Sales and other operating revenues

	Second	First	Second	First	First
	quarter	quarter	quarter	half	half
$ million	2019	2019	2018	2019	2018
By segment
Upstream	13,556	14,594	12,698	28,150	26,568
Downstream	66,396	58,416	69,174	124,812	130,580
Other businesses and corporate	433	356	376	789	719
	80,385	73,366	82,248	153,751	157,867

Less: sales and other operating revenues between segments
Upstream	7,481	6,324	5,795	13,805	12,528
Downstream	62	586	785	648	1,267
Other businesses and corporate	166	135	229	301	461
	7,709	7,045	6,809	14,754	14,256

Third party sales and other operating revenues
Upstream	6,075	8,270	6,903	14,345	14,040
Downstream	66,334	57,830	68,389	124,164	129,313
Other businesses and corporate	267	221	147	488	258
Total sales and other operating revenues	72,676	66,321	75,439	138,997	143,611

By geographical area
US	26,086	21,848	26,676	47,934	50,289
Non-US	52,933	49,618	56,032	102,551	107,272
	79,019	71,466	82,708	150,485	157,561
Less: sales and other operating revenues between areas	6,343	5,145	7,269	11,488	13,950
	72,676	66,321	75,439	138,997	143,611

Revenues from contracts with customers
Sales and other operating revenues include the following in relation to revenues from contracts with customers:
Crude oil	17,070	14,282	17,167	31,352	32,084
Oil products	46,999	42,583	51,440	89,582	95,570
Natural gas, LNG and NGLs	4,823	5,793	4,960	10,616	10,119
Non-oil products and other revenues from contracts with customers	3,173	3,501	3,081	6,674	6,576
	72,065	66,159	76,648	138,224	144,349

Note 5. Depreciation, depletion and amortization

	Second	First	Second	First	First
	quarter	quarter	quarter	half	half
$ million	2019	2019	2018	2019	2018
Upstream
US	1,288	1,113	999	2,401	2,087
Non-US	2,396	2,498	2,226	4,894	4,498
	3,684	3,611	3,225	7,295	6,585
Downstream
US	333	323	221	656	440
Non-US	392	383	293	775	595
	725	706	514	1,431	1,035
Other businesses and corporate
US	14	13	16	27	32
Non-US	165	131	56	296	90
	179	144	72	323	122
Total group	4,588	4,461	3,811	9,049	7,742

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Note 6. Production and similar taxes

	Second	First	Second	First	First
	quarter	quarter	quarter	half	half
$ million	2019	2019	2018	2019	2018
US	79	81	89	160	179
Non-US	292	343	442	635	720
	371	424	531	795	899

Note 7. Earnings per share and shares in issue

Basic earnings per ordinary share (EpS) amounts are calculated by dividing the profit (loss) for the period attributable to ordinary shareholders by the weighted average number of ordinary shares outstanding during the period. During the quarter the company repurchased for cancellation 11 million ordinary shares for a total cost of $75 million, as part of the share buyback programme as announced on 31 October 2017. This brings the total number of shares repurchased in the first half to 17 million for a total cost of $125 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.

	Second	First	Second	First	First
	quarter	quarter	quarter	half	half
$ million	2019	2019	2018	2019	2018
Results for the period
Profit (loss) for the period attributable to BP shareholders	1,822	2,934	2,799	4,756	5,268
Less: preference dividend	1	—	1	1	1
Profit (loss) attributable to BP ordinary shareholders	1,821	2,934	2,798	4,755	5,267

Number of shares (thousand)(a)
Basic weighted average number of shares outstanding	20,336,347	20,175,634	19,945,053	20,256,254	19,931,945
ADS equivalent	3,389,391	3,362,605	3,324,175	3,376,042	3,321,990

Weighted average number of shares outstanding used to calculate diluted earnings per share	20,421,184	20,281,773	20,044,277	20,368,125	20,050,123
ADS equivalent	3,403,530	3,380,295	3,340,712	3,394,687	3,341,687

Shares in issue at period-end	20,373,332	20,330,597	19,973,943	20,373,332	19,973,943
ADS equivalent	3,395,555	3,388,432	3,328,991	3,395,555	3,328,991

(a)

Excludes treasury shares and includes certain shares that will be issued in the future under employee share-based payment plans.

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Note 8. Dividends

Dividends payable

BP today announced an interim dividend of 10.25 cents per ordinary share which is expected to be paid on 20 September 2019 to ordinary shareholders and American Depositary Share (ADS) holders on the register on 9 August 2019. The corresponding amount in sterling is due to be announced on 10 September 2019, calculated based on the average of the market exchange rates for the four dealing days commencing on 4 September 2019. Holders of ADSs are expected to receive $0.615 per ADS (less applicable fees). A scrip dividend alternative is available, allowing shareholders to elect to receive their dividend in the form of new ordinary shares and ADS holders in the form of new ADSs. Details of the second quarter dividend and timetable are available at bp.com/dividends and details of the scrip dividend programme are available at bp.com/scrip.

	Second	First	Second	First	First
	quarter	quarter	quarter	half	half
	2019	2019	2018	2019	2018
Dividends paid per ordinary share
cents	10.250	10.250	10.000	20.500	20.000
pence	8.066	7.738	7.444	15.804	14.613
Dividends paid per ADS (cents)	61.50	61.50	60.00	123.00	120.00
Scrip dividends
Number of shares issued (millions)	46.3	90.1	34.5	136.4	57.9
Value of shares issued ($ million)	318	629	266	947	421

Note 9. Net debt and net debt including leases

Net debt*	Second		First	Second	First		First
	quarter		quarter	quarter	half		half
$ million	2019		2019	2018	2019		2018
Finance debt(a)	67,553		65,990	59,739	67,553		59,739
Fair value (asset) liability of hedges related to finance debt(b)	(378	)	350	1,104	(378	)	1,104
	67,175		66,340	60,843	67,175		60,843
Less: cash and cash equivalents	20,674		21,256	22,185	20,674		22,185
Net debt	46,501		45,084	38,658	46,501		38,658
Equity	103,623		103,336	101,770	103,623		101,770
Gearing	31.0%		30.4%	27.5%	31.0%		27.5%

(a)

The fair value of finance debt at 30 June 2019 was $68,857 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 $563 million (first quarter 2019 liability of $609 million and second quarter 2018 liability of $774 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’, 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 second quarter and first half 2018 is $619 million. The previously disclosed amount for finance debt for the second quarter and first half 2018 was $60,358 million. The previously disclosed amount for net debt for the second quarter and first half 2018 was $39,277 million. The previously disclosed gearing for the second quarter and first half 2018 was 27.8%.

Net debt including leases*	Second		First		Second	First		First
	quarter		quarter		quarter	half		half
$ million	2019		2019		2018	2019		2018
Net debt	46,501		45,084		38,658	46,501		38,658
Lease liabilities	10,379		10,294		619	10,379		619
Net partner (receivable) payable for leases entered into on behalf of joint operations	(230	)	(303	)	—	(230	)	—
Net debt including leases	56,650		55,075		39,277	56,650		39,277

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Note 10. Inventory valuation

A provision of $242 million was held against hydrocarbon inventories at 30 June 2019 ($124 million at 31 March 2019 and $38 million at 30 June 2018) to write them down to their net realizable value. The net movement charged to the income statement during the second quarter 2019 was $120 million (first quarter 2019 was a credit of $480 million and second quarter 2018 was a credit of $15 million).

Note 11. Statutory accounts

The financial information shown in this publication, which was approved by the Board of Directors on 29 July 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 9.

Balance sheet

As a result of the adoption of IFRS 16, $9.7 billion of right-of-use assets and $10.4 billion of lease liabilities have been included in the group balance sheet as at 30 June 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 June	31 December
$ billion	2019	2018
Property, plant and equipment(a) (b)	9.7	0.5
Lease liabilities(a)	10.4	0.7
Finance debt	67.6	65.1

(a)

Comparative information represents finance leases accounted for under IAS 17.

(b)

Net additions to right-of-use assets for the second quarter and half year 2019 were $0.8 billion and $1.7 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 second quarter and first half 2019 was $0.5 billion and $0.9 billion respectively. Interest on the group’s lease liabilities for the second quarter and first half 2019 was $0.1 billion and $0.2 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 second quarter 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 second 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 $1.2 billion of lease payments included within financing activities for the first half 2019, it is estimated that $1.0 billion would have been reported as operating cash flows and $0.2 billion would have been reported as capital expenditure cash flows ignoring the effects of IFRS 16.

	Second		First		Second	First		First
	quarter		quarter		quarter	half		half
$ billion	2019		2019		2018	2019		2018
Financing activities
Lease liability payments(a)	(0.6	)	(0.6	)	—	(1.2	)	—

(a)

Comparative information represents finance leases accounted for under IAS 17.

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Capital expenditure*

	Second	First	Second	First	First
	quarter	quarter	quarter	half	half
$ million	2019	2019	2018	2019	2018
Capital expenditure on a cash basis
Organic capital expenditure*	3,686	3,648	3,470	7,334	7,008
Inorganic capital expenditure*(a)	1,968	1,987	355	3,955	780
	5,654	5,635	3,825	11,289	7,788

	Second	First	Second	First	First
	quarter	quarter	quarter	half	half
$ million	2019	2019	2018	2019	2018
Organic capital expenditure by segment
Upstream
US	972	982	826	1,954	1,580
Non-US	1,858	1,888	1,941	3,746	4,053
	2,830	2,870	2,767	5,700	5,633
Downstream
US	271	187	232	458	403
Non-US	470	534	382	1,004	829
	741	721	614	1,462	1,232
Other businesses and corporate
US	15	9	7	24	14
Non-US	100	48	82	148	129
	115	57	89	172	143
	3,686	3,648	3,470	7,334	7,008
Organic capital expenditure by geographical area
US	1,258	1,178	1,065	2,436	1,997
Non-US	2,428	2,470	2,405	4,898	5,011
	3,686	3,648	3,470	7,334	7,008

(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. As at 30 June 2019, the entire consideration payable of $10,268 million, after customary closing adjustments, had been paid. This includes $1,732 million during the first quarter 2019 and $1,748 million during the second quarter 2019. These amounts are included, net of cash acquired, in inorganic capital expenditure. First quarter and first half 2019 and first half 2018 include amounts relating to the 25-year extension to our ACG production-sharing agreement* in Azerbaijan.

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Non-operating items*

	Second		First		Second		First		First
	quarter		quarter		quarter		half		half
$ million	2019		2019		2018(a)		2019		2018(a)
Upstream
Impairment and gain (loss) on sale of businesses and fixed assets(b)	(796	)	(11	)	81		(807	)	107
Environmental and other provisions	—		—		—		—		—
Restructuring, integration and rationalization costs	(17	)	(35	)	(62	)	(52	)	(61	)
Fair value gain (loss) on embedded derivatives	—		—		9		—		16
Other	47		42		(1	)	89		(139	)
	(766	)	(4	)	27		(770	)	(77	)
Downstream
Impairment and gain (loss) on sale of businesses and fixed assets	(51	)	4		(1	)	(47	)	(15	)
Environmental and other provisions	—		—		—		—		—
Restructuring, integration and rationalization costs	20		(2	)	(74	)	18		(110	)
Fair value gain (loss) on embedded derivatives	—		—		—		—		—
Other	—		(6	)	(150	)	(6	)	(153	)
	(31	)	(4	)	(225	)	(35	)	(278	)
Rosneft
Impairment and gain (loss) on sale of businesses and fixed assets	(113	)	(81	)	—		(194	)	—
Environmental and other provisions	—		—		—		—		—
Restructuring, integration and rationalization costs	—		—		—		—		—
Fair value gain (loss) on embedded derivatives	—		—		—		—		—
Other	—		—		—		—		—
	(113	)	(81	)	—		(194	)	—
Other businesses and corporate
Impairment and gain (loss) on sale of businesses and fixed assets	(4	)	—		(1	)	(4	)	1
Environmental and other provisions	(22	)	(6	)	1		(28	)	(20	)
Restructuring, integration and rationalization costs	(3	)	10		(30	)	7		(45	)
Fair value gain (loss) on embedded derivatives	—		—		—		—		—
Gulf of Mexico oil spill	(57	)	(115	)	(433	)	(172	)	(519	)
Other	(5	)	(17	)	(85	)	(22	)	(144	)
	(91	)	(128	)	(548	)	(219	)	(727	)
Total before interest and taxation	(1,001	)	(217	)	(746	)	(1,218	)	(1,082	)
Finance costs(c)	(116	)	(128	)	(118	)	(244	)	(238	)
Total before taxation	(1,117	)	(345	)	(864	)	(1,462	)	(1,320	)
Taxation credit (charge) on non-operating items	256		93		141		349		350
Total after taxation for period	(861	)	(252	)	(723	)	(1,113	)	(970	)

(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)

Second quarter and first half 2019 include impairment charges of $634 million resulting from the announcements to dispose of certain assets in Egypt and the US.

(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

	Second		First		Second		First		First
	quarter		quarter		quarter		half		half
$ million	2019		2019		2018		2019		2018
Favourable (adverse) impact relative to management’s measure of performance
Upstream	(178	)	(40	)	(21	)	(218	)	100
Downstream	(46	)	36		(390	)	(10	)	(450	)
	(224	)	(4	)	(411	)	(228	)	(350	)
Taxation credit (charge)	49		(7	)	101		42		90
	(175	)	(11	)	(310	)	(186	)	(260	)

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.

	Second		First		Second		First		First
	quarter		quarter		quarter		half		half
$ million	2019		2019		2018		2019		2018
Upstream
Replacement cost profit (loss) before interest and tax adjusted for fair value accounting effects	2,647		2,924		3,535		5,571		6,588
Impact of fair value accounting effects	(178	)	(40	)	(21	)	(218	)	100
Replacement cost profit (loss) before interest and tax	2,469		2,884		3,514		5,353		6,688
Downstream
Replacement cost profit (loss) before interest and tax adjusted for fair value accounting effects	1,334		1,729		1,230		3,063		3,003
Impact of fair value accounting effects	(46	)	36		(390	)	(10	)	(450	)
Replacement cost profit (loss) before interest and tax	1,288		1,765		840		3,053		2,553
Total group
Profit (loss) before interest and tax adjusted for fair value accounting effects	4,240		5,668		5,967		9,908		10,401
Impact of fair value accounting effects	(224	)	(4	)	(411	)	(228	)	(350	)
Profit (loss) before interest and tax	4,016		5,664		5,556		9,680		10,051

Readily marketable inventory* (RMI)

	30 June	31 December
$ million	2019	2018
RMI at fair value*	5,497	4,202
Paid-up RMI*	2,317	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 35 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 June		31 December
$ million	2019		2018
Reconciliation of total inventory to paid-up RMI
Inventories as reported on the group balance sheet under IFRS	20,042		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	(14,821	)	(14,066	)
	5,221		3,922
Plus: difference between RMI at fair value and RMI on an IFRS basis	276		280
RMI at fair value	5,497		4,202
Less: unpaid RMI* at fair value	(3,180	)	(2,561	)
Paid-up RMI	2,317		1,641

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Gulf of Mexico oil spill

	Second	First	Second	First	First
	quarter	quarter	quarter	half	half
$ million	2019	2019	2018	2019	2018
Net cash provided by operating activities as per condensed group cash flow statement	6,815	5,296	6,306	12,111	9,952
Exclude net cash from operating activities relating to the Gulf of Mexico oil spill on a post-tax basis	1,413	649	707	2,062	2,421
Operating cash flow, excluding Gulf of Mexico oil spill payments*	8,228	5,945	7,013	14,173	12,373

Net cash from operating activities relating to the Gulf of Mexico oil spill on a pre-tax basis amounted to an outflow of $1,472 million and $2,126 million in the second quarter and first half of 2019 respectively. For the same periods in 2018, the amount was an outflow of $1,078 million and $2,698 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. Included in the current quarter are payments of $1,194 million on a pre-tax basis relating to the 2016 consent decree and settlement agreement. 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 June		31 December
$ million	2019		2018
Trade and other payables	(12,623	)	(14,201	)
Provisions	(199	)	(345	)
Gulf of Mexico oil spill payables and provisions	(12,822	)	(14,546	)
Of which - current	(2,022	)	(2,612	)

Deferred tax asset	5,600		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

	Second		First		Second		First		First
	quarter		quarter		quarter		half		half
$ 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	(58	)	(2,695	)	(570	)	(2,753	)	(3,968	)
Adjustments to exclude movements in inventories and other current and non-current assets and liabilities for the Gulf of Mexico oil spill	1,451		631		693		2,082		2,281
Adjusted for Inventory holding gains (losses)* (Note 3)
Upstream	(10	)	2		4		(8	)	5
Downstream	93		1,046		1,196		1,139		1,265
Working capital release (build)	1,476		(1,016	)	1,323		460		(417	)

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Realizations* and marker prices

	Second	First	Second	First	First
	quarter	quarter	quarter	half	half
	2019	2019	2018	2019	2018
Average realizations(a)
Liquids* ($/bbl)
US	56.98	50.57	62.47	53.91	60.01
Europe	68.73	61.78	71.70	65.04	68.56
Rest of World	66.24	60.02	69.88	63.18	66.50
BP Average	62.63	56.47	67.24	59.61	64.21
Natural gas ($/mcf)
US	1.80	2.57	1.96	2.18	2.10
Europe	3.63	5.84	7.04	4.75	7.11
Rest of World	4.12	4.67	4.16	4.40	4.19
BP Average	3.35	4.02	3.65	3.68	3.72
Total hydrocarbons* ($/boe)
US	35.94	34.17	40.77	35.08	40.19
Europe	63.40	58.89	64.91	61.02	62.72
Rest of World	41.60	40.52	42.89	41.06	41.69
BP Average	40.64	39.37	43.37	40.02	42.36
Average oil marker prices ($/bbl)
Brent	68.86	63.13	74.39	65.95	70.58
West Texas Intermediate	59.90	54.87	68.02	57.42	65.52
Western Canadian Select	47.37	44.91	49.76	46.06	43.30
Alaska North Slope	68.29	64.39	73.93	66.37	70.64
Mars	65.20	61.13	69.47	63.20	66.04
Urals (NWE – cif)	67.62	62.91	72.21	65.23	68.71
Average natural gas marker prices
Henry Hub gas price(b) ($/mmBtu)	2.64	3.15	2.80	2.90	2.90
UK Gas – National Balancing Point (p/therm)	31.53	48.23	53.88	40.01	55.94

(a)

Based on sales of consolidated subsidiaries only – this excludes equity-accounted entities.

(b)

Henry Hub First of Month Index.

Exchange rates

	Second	First	Second	First	First
	quarter	quarter	quarter	half	half
	2019	2019	2018	2019	2018
$/£ average rate for the period	1.29	1.30	1.36	1.29	1.38
$/£ period-end rate	1.27	1.31	1.31	1.27	1.31

$/€ average rate for the period	1.12	1.14	1.19	1.13	1.21
$/€ period-end rate	1.14	1.12	1.16	1.14	1.16

Rouble/$ average rate for the period	64.58	66.00	62.13	65.29	59.47
Rouble/$ period-end rate	63.09	65.02	63.07	63.09	63.07

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Principal risks and uncertainties

The principal risks and uncertainties affecting BP are described in the Risk factors section of BP Annual Report and Form 20-F 2018 (pages 55-56) and are summarized below. There are no material changes in those risk factors for the remaining six months of the financial year.

The risks summarized below, separately or in combination, could have a material adverse effect on the implementation of our strategy, our business, financial performance, results of operations, cash flows, liquidity, prospects, shareholder value and returns and reputation.

Strategic and commercial risks

●

Prices and markets – our financial performance is impacted by fluctuating prices of oil, gas and refined products, technological change, exchange rate fluctuations, and the general macroeconomic outlook.

●

Access, renewal and reserves progression – inability to access, renew and progress upstream resources in a timely manner could adversely affect our long-term replacement of reserves.

●

Major project* delivery – failure to invest in the best opportunities or deliver major projects successfully could adversely affect our financial performance.

●

Geopolitical – exposure to a range of political developments and consequent changes to the operating and regulatory environment could cause business disruption.

●

Liquidity, financial capacity and financial, including credit, exposure – failure to work within our financial framework could impact our ability to operate and result in financial loss.

●

Joint arrangements and contractors – varying levels of control over the standards, operations and compliance of our partners, contractors and sub-contractors could result in legal liability and reputational damage.

●

Digital infrastructure and cyber security – breach of our digital security or failure of our digital infrastructure including loss or misuse of sensitive information could damage our operations, increase costs and damage our reputation.

●

Climate change and the transition to a lower carbon economy – policy, legal, regulatory, technology and market change related to the issue of climate change could increase costs, reduce demand for our products, reduce revenue and limit certain growth opportunities.

●

Competition – inability to remain efficient, maintain a high quality portfolio of assets, innovate and retain an appropriately skilled workforce could negatively impact delivery of our strategy in a highly competitive market.

●

Crisis management and business continuity – failure to address an incident effectively could potentially disrupt our business.

●

Insurance – our insurance strategy could expose the group to material uninsured losses.

Safety and operational risks

●

Process safety, personal safety, and environmental risks – exposure to a wide range of health, safety, security and environmental risks could cause harm to people, the environment and our assets and result in regulatory action, legal liability, business interruption, increased costs, damage to our reputation and potentially denial of our licence to operate.

●

Drilling and production – challenging operational environments and other uncertainties could impact drilling and production activities.

●

Security – hostile acts against our staff and activities could cause harm to people and disrupt our operations.

●

Product quality – supplying customers with off-specification products could damage our reputation, lead to regulatory action and legal liability, and impact our financial performance.

Compliance and control risks

●

Regulation – changes in the regulatory and legislative environment could increase the cost of compliance, affect our provisions and limit our access to new growth opportunities.

●

Ethical misconduct and non-compliance – ethical misconduct or breaches of applicable laws by our businesses or our employees could be damaging to our reputation, and could result in litigation, regulatory action and penalties.

●

Treasury and trading activities – ineffective oversight of treasury and trading activities could lead to business disruption, financial loss, regulatory intervention or damage to our reputation.

●

Reporting – failure to accurately report our data could lead to regulatory action, legal liability and reputational damage.

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Legal proceedings

The following discussion sets out the material developments in the group’s material legal proceedings during the first half of 2019. For a full discussion of the group’s material legal proceedings, see pages 296-298 of BP Annual Report and Form 20-F 2018.

Scharfstein v BP West Coast Products LLC

A class action lawsuit was filed against BP West Coast Products, LLC (BPWCP) in Oregon State Court under the Oregon Unlawful Trade Practices Act on behalf of customers who used a debit card at ARCO gasoline stations in Oregon during the period 1 January 2011 to 30 August 2013, alleging that ARCO sites in Oregon failed to provide sufficient notice of the 35 cents per transaction debit card fee. In January 2014, the jury rendered a verdict against BPWCP and awarded statutory damages of $200 per class member. On 25 August 2015, the trial court determined the size of the class to be slightly in excess of two million members. On 31 May 2016 the trial court entered a judgment against BPWCP for the amount of $417.3 million. On 31 May 2018 the Oregon Court of Appeals affirmed the trial court’s ruling. In March 2019, BP and the Plaintiffs agreed to a settlement of the class action lawsuit, subject to final court approval. On 4 June 2019 the court granted final approval of the settlement agreement. The judgment dismissing the case was entered on 13 June 2019. No appeal was taken from the judgment on or before the 14 July 2019 deadline. On 15 July 2019, BP made its first payment under the terms of the settlement agreement. The second and final payment is due in July 2020. BP’s provisions for litigation and claims include a provision for this lawsuit.

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 30.

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 25.

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 28.

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Glossary (continued)

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

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

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

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 25.

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 29.

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 working capital change is a non-GAAP measure. It is operating cash flow excluding Gulf of Mexico oil spill payments less change in working capital adjusted for inventory holding gains/losses (see below). BP believes operating cash flow excluding working capital change 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.

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 28.

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 31.

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Glossary (continued)

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.

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 7. 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 cash is a non-GAAP measure. See operating cash flow excluding Gulf of Mexico oil spill payments.

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 29 and 30 for additional information on the non-operating items and fair value accounting effects that are used to arrive at underlying RC profit or loss in order to enable a full understanding of the events and their financial impact. BP believes that underlying RC profit or loss is a useful measure for investors because it is a measure closely tracked by management to evaluate BP’s operating performance and to make financial, strategic and operating decisions and because it may help investors to understand and evaluate, in the same manner as management, the underlying trends in BP’s operational performance on a comparable basis, period on period, by adjusting for the effects of these non-operating items and fair value accounting effects. The nearest equivalent measure on an IFRS basis for the group is profit or loss attributable to BP shareholders. The nearest equivalent measure on an IFRS basis for segments is RC profit or loss before interest and taxation. A reconciliation to GAAP information is provided on page 1.

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Glossary (continued)

Underlying RC profit or loss per share is a non-GAAP measure. Earnings per share is defined in Note 7. 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.

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 32 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: plans and expectations regarding BP’s low-carbon business, including with regard to BP’s $30 million venturing investment in Calysta and Calysta’s business model and impacts thereof, and to the timing of the installation of 400 ultra-fast chargers at BP’s UK retail sites; plans and expectations with respect to the joint venture between BP’s Brazilian biofuels business and Bunge, including BP’s interest in the venture, the combined business plan and completion timing; expectations regarding the expected quarterly dividend payment and timing of such payment; plans and expectations regarding share buybacks, including to offset the impact of dilution from the scrip program; expectations regarding the underlying effective tax rate in 2019; expectations regarding 2019 organic capital expenditure and depreciation, depletion and amortization charges; plans and expectations with respect to gearing, including for gearing to move toward the middle of the 20-30% targeted range in 2020; expectations with respect to new discoveries and the potential to develop them; plans and expectations with respect to expected project start-ups for which final investment decisions have been made; plans and expectations regarding Upstream investments, including with regard to the agreement to sell BP’s interests in Gulf of Suez oil concessions to Dragon Oil and timing thereof, for the investment in deepwater Block 15 offshore Angola to increase and extend production and to BP’s intention to sell BP’s interest in oil and gas fields in Oklahoma, US; expectations with regard to the strategic partnership between Castrol and Renault Sport Racing; plans and expectations regarding divestments and disposals, including to have more than $10 billion of divestments by the end of 2020; plans and expectations with respect to BP’s and Environmental Defense Fund’s commitment to reduce methane emissions; plans regarding the $100-million fund for projects that will deliver emissions reductions; expectations regarding Upstream third-quarter 2019 reported production, seasonal turnaround and maintenance activities; expectations regarding Downstream third-quarter 2019 refining margins and turnaround activity; expectations regarding the impact of the IFRIC agenda decision on IFRS 9 on reported earnings; expectations that the second and final payment in connection with the Scharfstein litigation will be made in July 2020; plans and expectations regarding Lightsource BP, including for the Green Energy Equity Fund to invest a total of $330 million in Ayana Renewable Power; plans and expectations regarding the Other businesses and corporate 2019 average quarterly charges; 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; natural disasters and adverse weather conditions; changes in public expectations and other changes to business conditions; wars and acts of terrorism; cyber-attacks or sabotage; and other factors discussed elsewhere in this report, including under “Principal risks and uncertainties” and under “Risk factors” in BP Annual Report and Form 20-F 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
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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: 30 July 2019
	/s/ B. MATHEWS
	------------------------
	B. MATHEWS
	Company Secretary