Company Announcements

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FOR IMMEDIATE RELEASE
London 4 February 2020
BP p.l.c. Group results
Fourth quarter and full year 2019

 

 

For a printer friendly copy of this announcement, please click on the link below to open a PDF version
http://www.rns-pdf.londonstockexchange.com/rns/8294B_1-2020-2-3.pdf

 

Highlights

Operational momentum, growing cash flow, strategic progress: dividend increased

Cash flow strong, increased disposal plans

- Underlying replacement cost profit for the fourth quarter and full year 2019 was $2.6 billion and $10.0 billion respectively, compared to $3.5 billion and $12.7 billion for the same periods a year earlier, largely reflecting the impact of the weaker environment. Reported profit was $19 million for the fourth quarter and $4.0 billion for the full year.

- Non-operating items in the quarter included a $1.9 billion after-tax impairment charge, mainly for the disposal of US gas assets, and a $0.9 billion charge arising from the reclassification of past foreign exchange losses on the formation of BP's new biofuels joint venture.

- Full-year operating cash flow, excluding Gulf of Mexico oil spill payments, was $28.2 billion, including a $0.3 billion working capital release (after adjusting for net inventory holding gains).

- Gulf of Mexico oil spill payments for the year totalled $2.4 billion on a post-tax basis, and are expected to be less than $1 billion in 2020.

- Maintaining capital discipline, full-year organic capital expenditure of $15.2 billion was at the bottom of the guided range. Divestments and other disposals announced since the start of 2019 now total $9.4 billion, keeping BP ahead of schedule to meet its target of $10 billion proceeds by end-2020. BP expects to announce a further $5 billion of agreed disposals by mid-2021.

- In January 2020 BP completed its announced share buyback programme.

- Net debt reduced by $1.1 billion in the quarter with gearing at 31.1%, down from 31.7% at the end of the previous quarter.

- A dividend of 10.5 cents per share was announced for the quarter, an increase of 2.4% on a year earlier.

Continued reliable operations

- Downstream delivered full-year refining availability of 95% and record refining throughput for the second consecutive year. Upstream operated plant reliability was 94.4% for the year.

- Reported oil and gas production averaged 3.8 million barrels of oil equivalent a day in 2019, 2.7% higher than in 2018. Underlying full year Upstream production, which excludes both Rosneft and portfolio changes, was broadly flat with 2018.

Low-carbon expansions, new projects, retail growth

- BP expanded its low-carbon businesses in 2019, increasing ownership in its solar joint venture Lightsource BP to 50%, and completed formation of its new Brazilian biofuels and biopower joint venture, BP Bunge Bioenergia.

- Five Upstream major projects began production in 2019, and final investment decisions were taken for a further five.

- BP continued its expansion into fast-growing fuels markets during the year and agreed a major fuels joint venture with Reliance Industries Limited in India. 

 

 

See chart on PDF

 

Bob Dudley - Group chief executive:

"BP is performing well, with safe and reliable operations, continued strategic progress and strong cash delivery. This all supports our commitment to growing distributions to shareholders over the long term and the dividend rise we announced today. After almost ten years, this is now my last quarter as CEO. In that time, we have achieved a huge amount together and I am proud to be handing over a safer and stronger BP to Bernard and his team. I am confident that under their leadership, BP will continue to successfully navigate the rapidly-changing energy landscape."

 

Financial summary		Fourth		Third		Fourth
		quarter		quarter		quarter			Year		Year
$ million		2019		2019		2018			2019		2018
Profit (loss) for the period attributable to BP shareholders		19		(749	)	766			4,026		9,383
Inventory holding (gains) losses, net of tax		(23	)	398		1,951			(511	)	603
RC profit (loss)		(4	)	(351	)	2,717			3,515		9,986
Net (favourable) adverse impact of non-operating items and fair value accounting effects, net of tax		2,571		2,605		760			6,475		2,737
Underlying RC profit		2,567		2,254		3,477			9,990		12,723
RC profit (loss) per ordinary share (cents)		(0.02	)	(1.72	)	13.58			17.32		50.00
RC profit (loss) per ADS (dollars)		0.00		(0.10	)	0.81			1.04		3.00
Underlying RC profit per ordinary share (cents)		12.67		11.06		17.38			49.24		63.70
Underlying RC profit per ADS (dollars)		0.76		0.66		1.04			2.95		3.82

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

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

 

 

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Group headlines

 

Results For the full year, underlying replacement cost (RC) profit* was $9,990 million, compared with $12,723 million in 2018. Underlying RC profit is after adjusting RC profit* for a net charge for non-operating items* of $7,186 million and net favourable fair value accounting effects* of $711 million (both on a post-tax basis). RC profit was $3,515 million for the full year, compared with $9,986 million in 2018. For the fourth quarter, underlying RC profit was $2,567 million, compared with $3,477 million in 2018. Underlying RC profit is after adjusting RC loss for a net charge for non-operating items of $3,142 million primarily divestment-related impairment charges (see Note 3 and page 27) and reclassification of past foreign exchange losses on the formation of the BP Bunge Bioenergia joint venture, as well as net favourable fair value accounting effects of $571 million (both on a post-tax basis). RC loss was $4 million for the fourth quarter, compared with a profit of $2,717 million in 2018. BP's profit for the fourth quarter and full year was $19 million and $4,026 million respectively, compared with $766 million and $9,383 million for the same periods in 2018. See further information on pages 3, 27 and 28. Depreciation, depletion and amortization The charge for depreciation, depletion and amortization was $4.4 billion in the quarter and $17.8 billion in the full year. In the same periods in 2018 it was $4.0 billion and $15.5 billion respectively (prior to the implementation of IFRS 16). In 2020, we expect the full-year charge to be slightly lower than the 2019 level reflecting impacts of divestments. Effective tax rate The effective tax rate (ETR) on RC profit or loss* for the fourth quarter and full year was 102% and 51% respectively, compared with 45% and 42% for the same periods in 2018. Adjusting for non-operating items and fair value accounting effects, the underlying ETR* for the fourth quarter and full year was 27% and 36% respectively, compared with 38% and 38% for the same periods a year ago. The lower underlying ETR for the fourth quarter and full year reflects the reassessment of the recognition of deferred tax assets. In the current environment the underlying ETR in 2020 is expected to be lower than 40%. ETR on RC profit or loss and underlying ETR are non-GAAP measures. Dividend BP today announced a quarterly dividend of 10.5 cents per ordinary share ($0.63 per ADS), which is expected to be paid on 27 March 2020. The corresponding amount in sterling will be announced on 16 March 2020. See page 23 for more information. Share buybacks BP repurchased 184 million ordinary shares at a cost of $1,171 million in the fourth quarter, totalling 235 million ordinary shares at	a cost of $1,511 million (including fees and stamp duty) for the full year. In January 2020, the share buyback programme had fully offset the impact of scrip dilution since the third quarter 2017. Operating cash flow* Operating cash flow excluding Gulf of Mexico oil spill payments* was $7.6 billion for the fourth quarter and $28.2 billion for the full year. These amounts include a working capital* build of $0.2 billion in the fourth quarter and a release of $0.3 billion in the full year, after adjusting for net inventory holding losses or gains* and working capital effects of the Gulf of Mexico oil spill. The comparable amounts for the same periods in 2018 were $7.1 billion and $26.1 billion (prior to the implementation of IFRS 16). Operating cash flow as reported in the group cash flow statement was $7.6 billion for the fourth quarter and $25.8 billion for the full year. These amounts include a working capital build of $0.3 billion and $2.9 billion respectively. The comparable amounts for the same periods in 2018 were $6.8 billion and $22.9 billion (prior to the implementation of IFRS 16). See page 30 and Glossary for further information on Gulf of Mexico oil spill cash flows and on working capital. Capital expenditure* Organic capital expenditure* for the fourth quarter and full year was $4.0 billion and $15.2 billion respectively. We reported $4.4 billion and $15.1 billion for the same periods in 2018 (prior to the implementation of IFRS 16). Inorganic capital expenditure* for the fourth quarter and full year was $0.2 billion and $4.2 billion respectively, including $3.5 billion for the full year relating to the BHP acquisition, compared with $8.5 billion and $9.9 billion for the same periods in 2018. Organic capital expenditure and inorganic capital expenditure are non-GAAP measures. See page 26 for further information. Divestment and other proceeds Divestment proceeds* were $0.8 billion for the fourth quarter and $2.2 billion for the full year, in addition $0.6 billion was received in the fourth quarter in relation to the sale of a 49% interest in BP's retail property portfolio in Australia. Divestment proceeds for the same periods in 2018 were $2.4 billion and $2.9 billion respectively. Gearing* Net debt* at 31 December 2019 was $45.4 billion, compared with $43.5 billion a year ago. Gearing at 31 December 2019 was 31.1%, compared with 30.0% a year ago. Net debt and gearing are non-GAAP measures. See page 23 for more information. Reserves replacement ratio* The organic reserves replacement ratio on a combined basis of subsidiaries and equity-accounted entities was 67% for the year. Including acquisitions and divestments, the total reserves replacement ratio was 57%.
Brian Gilvary - Chief financial officer:
"We continue to make strong progress on our divestment programme, with announced transactions totalling $9.4 billion since the start of 2019. We are ahead of our target of $10 billion of proceeds by end-2020, and now plan a further $5 billion of agreed disposals by mid-2021. Net debt fell $1 billion in the fourth quarter, and with further disposal proceeds expected, and assuming recent average oil prices, we continue to expect gearing to move towards the middle of the 20 to 30% range through this year. Together with the continued strong operational momentum, growing free cash flow, and our confidence in delivery of 2021 free cash flow targets, this underpins our announcement today of an increase in the dividend to 10.5 cents per ordinary share."

 

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

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

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

 

 

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Analysis of underlying RC profit* before interest and tax

		Fourth		Third		Fourth
		quarter		quarter		quarter			Year		Year
$ million		2019		2019		2018			2019		2018
Underlying RC profit before interest and tax
Upstream		2,678		2,139		3,886			11,158		14,550
Downstream		1,438		1,883		2,169			6,419		7,561
Rosneft		412		802		431			2,419		2,316
Other businesses and corporate		(250	)	(322	)	(344	)		(1,280	)	(1,558	)
Consolidation adjustment - UPII*		24		30		142			75		211
Underlying RC profit before interest and tax		4,302		4,532		6,284			18,791		23,080
Finance costs and net finance expense relating to pensions and other post-retirement benefits		(781	)	(754	)	(654	)		(3,041	)	(2,176	)
Taxation on an underlying RC basis		(955	)	(1,506	)	(2,148	)		(5,596	)	(7,986	)
Non-controlling interests		1		(18	)	(5	)		(164	)	(195	)
Underlying RC profit attributable to BP shareholders		2,567		2,254		3,477			9,990		12,723

 

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

 

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

		Fourth		Third		Fourth
		quarter		quarter		quarter			Year		Year
$ million		2019		2019		2018			2019		2018
RC profit before interest and tax
Upstream		614		(1,050	)	4,168			4,917		14,328
Downstream		1,433		2,016		2,138			6,502		6,940
Rosneft		503		802		400			2,316		2,221
Other businesses and corporate		(1,432	)	(412	)	(1,110	)		(2,771	)	(3,521	)
Consolidation adjustment - UPII		24		30		142			75		211
RC profit before interest and tax		1,142		1,386		5,738			11,039		20,179
Finance costs and net finance expense relating to pensions and other post-retirement benefits		(903	)	(899	)	(776	)		(3,552	)	(2,655	)
Taxation on a RC basis		(244	)	(820	)	(2,240	)		(3,808	)	(7,343	)
Non-controlling interests		1		(18	)	(5	)		(164	)	(195	)
RC profit (loss) attributable to BP shareholders		(4	)	(351	)	2,717			3,515		9,986
Inventory holding gains (losses)*		10		(512	)	(2,574	)		667		(801	)
Taxation (charge) credit on inventory holding gains and losses		13		114		623			(156	)	198
Profit (loss) for the period attributable to BP shareholders		19		(749	)	766			4,026		9,383

 

 

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Strategic progress Upstream Upstream production for the fourth quarter, which excludes Rosneft, was 2,698mboe/d, 2.7% higher than a year earlier. Underlying production*, adjusted for portfolio changes and PSA* impact, increased by 2.1%, mainly due to major project growth. In 2019 BP announced seven discoveries. In December, it confirmed the success of a three-well drilling campaign offshore Mauritania and Senegal, offering the potential for possible future developments. The Alligin project, a tie-back to the Quad 204 development west of Shetland, UK, began production ahead of schedule in December and was the fifth Upstream major project start-up of 2019. The Raven project in Egypt is now expected to come onstream around the end of 2020. Final investment decisions for five further projects, in the US Gulf of Mexico, UK North Sea, Azerbaijan and India, were taken in 2019. In November BP agreed to sell its interests in the onshore San Juan and Arkoma fields in the US. In early January 2020, BP announced it had agreed terms to sell its interests in the Andrew area and in the Shearwater field, both in the central UK North Sea.   Downstream BP continued to make strategic progress in fuels marketing, with its convenience partnership model now in around 1,600 sites across the network. BP also made progress towards its growth ambition in new markets, most notably in Mexico, where there are now over 520 BP-branded sites and volumes more than doubled in 2019. In December, BP signed key agreements with Reliance Industries Limited to form a new fuels marketing joint venture, which will build on Reliance's existing network of retail sites in India and include access to the country's aviation fuels market. A consortium of leading companies across the PET plastics value chain, including BP, was formed. It aims to help accelerate the commercialisation of BP's enhanced recycling technology, BP Infinia, which is capable of processing currently-unrecyclable plastic waste. Advancing the energy transition In December BP increased its interest in its solar joint venture Lightsource BP, creating a simplified equal ownership structure with the company's management. The cash injection will support Lightsource BP's planned continuing rapid growth.

The formation of the BP Bunge Bioenergia joint venture has completed. BP's 50% share in the company represents a 50% increase in BP's Brazilian biofuels and biopower business. BP continued to progress its advanced mobility agenda in 2019, forming an electric vehicle charging joint venture in China with DiDi and beginning the roll out of 150kW ultra-fast electric chargers on BP forecourts across the UK. 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 $28.2 billion for the full year of 2019. For the full year of 2018, we reported $26.1 billion (prior to the implementation of IFRS 16). Organic capital expenditure for the full year of 2019 was $15.2 billion. BP expects 2020 organic capital expenditure to remain towards the lower end of our $15-17 billion range. Lease liability payments of principal for the full year of 2019 were $2.4 billion. Divestment and other transactions announced have now reached $9.4 billion since the start of 2019. BP expects this total to be around $15 billion by mid-2021. Gulf of Mexico oil spill payments on a post-tax basis totalled $2.4 billion in the full year. Payments for 2020 are expected to be less than $1 billion on a post-tax basis. Gearing* at the end of the year was 31.1%. See page 23 for more information. We expect gearing to move towards the middle of the 20-30% range through 2020, assuming recent average oil prices. Safety Both tier 1 and tier 2 process safety events* were higher in 2019 compared with 2018. The increase in this group metric mainly reflects performance in assets acquired over the past year; excluding these the number of events fell slightly. Safety remains our number one priority and we continue to focus on working to reduce all process safety events.

 

Operating metrics		Year 2019		Financial metrics		Year 2019
		(vs.  Year 2018)				(vs.  Year 2018)
Tier 1 and tier 2 process safety events		98		Underlying RC profit*		$10.0bn
		(+26)				(-$2.7bn)
Reported recordable injury frequency*		0.17		Operating cash flow excluding Gulf of Mexico oil spill payments (post-tax)(b)		$28.2bn
		(-16%)				(+$2.1bn)
Group production		3,781mboe/d		Organic capital expenditure		$15.2bn
		(+2.7%)				(+$0.1bn)
Upstream production (excludes Rosneft segment)		2,637mboe/d		Gulf of Mexico oil spill payments (post-tax)		$2.4bn
		(+3.8%)				(-$0.8bn)
Upstream unit production costs*(a)		$6.84/boe		Divestment proceeds*		$2.2bn
		(-4.4%)				(-$0.7bn)
BP-operated Upstream plant reliability*		94.4%		Gearing		31.1%
		(-1.3)				(+1.1)
BP-operated refining availability*		94.9%		Dividend per ordinary share(c)		10.50 cents
		(-0.1)				(2.4%)
				Return on average capital employed*		8.9%
						(-2.3)

(a)       Slight decrease from the same period in 2018 after excluding the impacts of IFRS 16 on production costs.

(b)       Full year 2019 includes estimated $2.0 billion favourable impact due to IFRS 16 (see page 25).

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

 

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

 

 

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Upstream

		Fourth		Third		Fourth
		quarter		quarter		quarter			Year		Year
$ million		2019		2019		2018			2019		2018
Profit (loss) before interest and tax		614		(1,050	)	4,156			4,909		14,322
Inventory holding (gains) losses*		-		-		12			8		6
RC profit (loss) before interest and tax		614		(1,050	)	4,168			4,917		14,328
Net (favourable) adverse impact of non-operating items* and fair value accounting effects*		2,064		3,189		(282	)		6,241		222
Underlying RC profit before interest and tax*(a)		2,678		2,139		3,886			11,158		14,550

(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 fourth quarter and full year was $614 million and $4,917 million respectively, compared with $4,168 million and $14,328 million for the same periods in 2018. The fourth quarter and full year included a net non-operating charge of $2,723 million and $6,947 million respectively, which principally relate to impairments arising from disposal transactions, compared with a net gain of $136 million and a net charge $183 million for the same periods in 2018. Fair value accounting effects in the fourth quarter and full year had a favourable impact of $659 million and $706 million respectively, compared with a favourable impact of $146 million and an adverse impact of $39 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 fourth quarter and full year was $2,678 million and $11,158 million respectively, compared with $3,886 million and $14,550 million for the same periods in 2018. The result for the fourth quarter mainly reflected lower liquids and gas realizations partly offset by higher production. The result for the full year mainly reflected lower liquids and gas realizations and higher depreciation, depletion and amortization partly offset by strong gas marketing and trading results and higher production.

 

Production

Production for the quarter was 2,698mboe/d, 2.7% higher than the fourth quarter of 2018. Underlying production* for the quarter increased by 2.1%, mainly due to major project growth.

For the full year, production was 2,637mboe/d, 3.8% higher than 2018. Underlying production for the full year was broadly flat versus full year 2018.

 

Key events

On 29 October, BP announced the New Gas Consortium (NGC), a joint venture with Chevron, Eni, Total and Angolan state-owned Sonangol. This is the first upstream natural gas partnership in Angola, initially comprised of the Quiluma & Maboqueiro fields (Eni operator 25.6%, Chevron 31%, Sonangol 18.8%, BP 11.8%, and Total 11.8%).

On 14 November, BP signed an agreement to acquire KrisEnergy's 30% non-operating working interest in the Andaman II production-sharing contract* in the Malacca Strait, Indonesia, subject to government approval.

On 15 November, BP Trinidad and Tobago LLC announced a gas discovery with the Ginger exploration well, offshore Trinidad. The well is currently under evaluation.

In November, BP signed agreements to sell its interests in the San Juan field in Colorado and New Mexico, and in the Arkoma field in Oklahoma, US. Subject to regulatory approvals, the transactions are expected to complete by the end of the first quarter of 2020.

On 30 November, the Trans-Anatolian Natural Gas Pipeline (TANAP) through Turkey and its connection to the Trans Adriatic Pipeline (TAP) in Greece was completed. TANAP is expected to begin transporting gas to Turkish and European markets in late 2020 (Azeri state energy company SOCAR 51%, BOTAS 30%, BP 12%, and SOCAR Turkey 7%).

On 16 December, BP confirmed the production licence extension on Block 17, offshore Angola, to 2045, and for Sonangol to assume an equity interest in the block (Total operator 38%, Equinor 22.16%, ExxonMobil 19%, BP 15.84%, and Sonangol 5%).

On 7 January 2020, BP announced it has agreed terms to sell its interest in the Andrew area and the Shearwater field, both located in the UK North Sea, to Premier Oil. Subject to regulatory approval, the transaction is expected to complete by the end of the third quarter of 2020.

On 4 February 2020, BP confirmed the start-up of oil production from the Alligin field in the UK North Sea. This was the fifth major project start-up in 2019 (BP operator 50% and Shell 50%).

 

Outlook

We expect full-year 2020 underlying production to be lower than 2019 due to declines in lower margin gas basins. We expect reported production to be lower due to the above factor and the impact of the ongoing divestment programme.

We expect first-quarter 2020 reported production to be lower than fourth-quarter 2019 due to the impact of our ongoing divestment programme and planned seasonal maintenance and turnaround activities.

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

 

 

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Upstream (continued)

		Fourth		Third		Fourth
		quarter		quarter		quarter			Year		Year
$ million		2019		2019		2018			2019		2018
Underlying RC profit before interest and tax
US		645		552		1,400			2,670		3,693
Non-US		2,033		1,587		2,486			8,488		10,857
		2,678		2,139		3,886			11,158		14,550
Non-operating items(a)(b)
US		(2,451	)	(3,338	)	(267	)		(6,265	)	(590	)
Non-US		(272	)	(116	)	403			(682	)	407
		(2,723	)	(3,454	)	136			(6,947	)	(183	)
Fair value accounting effects
US		120		19		127			(179	)	(35	)
Non-US		539		246		19			885		(4	)
		659		265		146			706		(39	)
RC profit (loss) before interest and tax
US		(1,686	)	(2,767	)	1,260			(3,774	)	3,068
Non-US		2,300		1,717		2,908			8,691		11,260
		614		(1,050	)	4,168			4,917		14,328
Exploration expense
US		86		53		84			233		509
Non-US		180		132		373			731		936
		266		185		457			964		1,445
Of which: Exploration expenditure written off(b)		155		115		351			631		1,085
Production (net of royalties)(c)(d)
Liquids* (mb/d)
US		517		449		495			482		445
Europe		149		118		154			141		142
Rest of World		662		657		673			666		681
		1,328		1,224		1,321			1,288		1,268
Natural gas (mmcf/d)
US		2,317		2,396		2,255			2,358		1,900
Europe		275		188		215			185		211
Rest of World		5,354		5,211		5,104			5,279		5,263
		7,945		7,795		7,574			7,823		7,374
Total hydrocarbons* (mboe/d)
US		916		862		884			888		772
Europe		196		151		191			173		179
Rest of World		1,585		1,555		1,553			1,576		1,589
		2,698		2,568		2,627			2,637		2,539
Average realizations*(e)
Total liquids(f) ($/bbl)		55.90		55.68		61.80			57.73		64.98
Natural gas ($/mcf)		3.12		3.11		4.33			3.39		3.92
Total hydrocarbons ($/boe)		36.42		35.48		42.98			38.00		43.47

(a)       Fourth quarter and full year 2019 include impairment charges which principally related to the disposal of heritage BPX Energy assets, Alaska and GUPCO. Fourth quarter and full year 2018 include impairment reversals for assets in the North Sea and Angola.

(b)       Full year 2018 includes the write-off of $124 million in relation to the value ascribed to certain licences in the deepwater Gulf of Mexico as part of the accounting for the acquisition of upstream assets from Devon Energy in 2011. This has been classified within the 'other' category of non-operating items.

(c)       Includes BP's share of production of equity-accounted entities in the Upstream segment.

(d)       Because of rounding, some totals may not agree exactly with the sum of their component parts.

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

(f)        Includes condensate, natural gas liquids and bitumen.

 

 

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Downstream

		Fourth		Third		Fourth
		quarter		quarter		quarter			Year		Year
$ million		2019		2019		2018			2019		2018
Profit (loss) before interest and tax		1,412		1,583		(332	)		7,187		6,078
Inventory holding (gains) losses*		21		433		2,470			(685	)	862
RC profit before interest and tax		1,433		2,016		2,138			6,502		6,940
Net (favourable) adverse impact of non-operating items* and fair value accounting effects*		5		(133	)	31			(83	)	621
Underlying RC profit before interest and tax*(a)		1,438		1,883		2,169			6,419		7,561

(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 fourth quarter and full year was $1,433 million and $6,502 million respectively, compared with $2,138 million and $6,940 million for the same periods in 2018.

The fourth quarter and full year include a net non-operating charge of $28 million and $77 million respectively, compared with a charge of $401 million and $716 million for the same periods in 2018. Fair value accounting effects in the fourth quarter and full year had a favourable impact of $23 million and $160 million respectively, compared with $370 million and $95 million in the same periods in 2018.

After adjusting for non-operating items and fair value accounting effects, the underlying replacement cost profit before interest and tax for the fourth quarter and full year was $1,438 million and $6,419 million respectively, compared with $2,169 million and $7,561 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 $1,068 million for the fourth quarter and $4,759 million for the full year, compared with $1,624 million and $5,642 million for the same periods in 2018. Year on year we delivered growth in marketing and refining operational performance, offset by a significantly weaker environment.

The result for the quarter reflects increased refining margin capture, supported by improved operations, higher levels of advantaged feedstocks, and a lower level of turnaround activity. This was more than offset, however, by narrower heavy crude oil discounts and a lower fuels marketing result compared to a very strong result in the fourth quarter of 2018.

The full-year result reflects strong refining operational performance, which led to a second consecutive year of record refining throughput and higher commercial optimization, despite high levels of turnaround activity. This was more than offset, however, by lower refining margins including significantly narrower heavy crude oil discounts, which together represented one of the weakest refining environments in the last 10 years. In fuels marketing we saw volumes and margins grow year on year, offset by adverse foreign exchange effects. The full-year result also reflects a higher contribution from supply and trading.

We continued to make strategic progress in fuels marketing, with our convenience partnership model now in around 1,600 sites across our network. We also made progress towards our growth ambition in new markets, most notably in Mexico where we now have over 520 sites, with volumes more than doubling in 2019.

In December we also signed an agreement with Reliance Industries Limited to form a fuels retail and aviation joint venture in India, providing access to one of the world's largest and fastest growing fuels markets.

 

Lubricants

The lubricants business reported an underlying replacement cost profit before interest and tax of $333 million for the fourth quarter and $1,258 million for the full year, compared with $311 million and $1,292 million for the same periods in 2018. The result for the full year reflects year-on-year unit margin improvement, offset by adverse foreign exchange effects.

Following the decision by Groupe Renault to select Castrol as its aftersales' global service fill engine oil lubricants partner from 1 January 2020, a new Renault Castrol jointly branded product range has been launched to all Renault dealers globally.

 

Petrochemicals

The petrochemicals business reported an underlying replacement cost profit before interest and tax of $37 million for the fourth quarter and $402 million for the full year, compared with $234 million and $627 million for the same periods in 2018. The result for the quarter and full year reflects a significantly weaker margin environment across both aromatics and acetyls.

In October we announced BP Infinia, an enhanced recycling technology, and in December a consortium of leading companies was formed which aims to help accelerate the commercialisation of this technology. These are important steps to enable a stronger circular economy in the polyethylene terephthalate (PET) plastics industry and to help reduce plastic waste.

 

Outlook

Looking to the first quarter of 2020, we expect lower levels of industry refining margins and wider North American heavy crude oil discounts compared with the fourth quarter of 2019.

 

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

 

 

 

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Downstream (continued)

		Fourth		Third		Fourth
		quarter		quarter		quarter			Year		Year
$ million		2019		2019		2018			2019		2018
Underlying RC profit before interest and tax - by region
US		556		537		995			2,190		2,818
Non-US		882		1,346		1,174			4,229		4,743
		1,438		1,883		2,169			6,419		7,561
Non-operating items
US		(40	)	(5	)	(109	)		(42	)	(295	)
Non-US		12		(9	)	(292	)		(35	)	(421	)
		(28	)	(14	)	(401	)		(77	)	(716	)
Fair value accounting effects(a)
US		(37	)	116		184			148		(155	)
Non-US		60		31		186			12		250
		23		147		370			160		95
RC profit before interest and tax
US		479		648		1,070			2,296		2,368
Non-US		954		1,368		1,068			4,206		4,572
		1,433		2,016		2,138			6,502		6,940
Underlying RC profit before interest and tax - by business(b)(c)
Fuels		1,068		1,438		1,624			4,759		5,642
Lubricants		333		332		311			1,258		1,292
Petrochemicals		37		113		234			402		627
		1,438		1,883		2,169			6,419		7,561
Non-operating items and fair value accounting effects(a)
Fuels		(41	)	135		173			32		(381	)
Lubricants		39		-		(198	)		57		(227	)
Petrochemicals		(3	)	(2	)	(6	)		(6	)	(13	)
		(5	)	133		(31	)		83		(621	)
RC profit before interest and tax(b)(c)
Fuels		1,027		1,573		1,797			4,791		5,261
Lubricants		372		332		113			1,315		1,065
Petrochemicals		34		111		228			396		614
		1,433		2,016		2,138			6,502		6,940
BP average refining marker margin (RMM)* ($/bbl)		12.4		14.7		11.0			13.2		13.1
Refinery throughputs (mb/d)
US		761		781		691			737		703
Europe		848		815		735			787		781
Rest of World		238		217		240			225		241
		1,847		1,813		1,666			1,749		1,725
BP-operated refining availability* (%)		95.7		96.1		95.6			94.9		95.0
Marketing sales of refined products (mb/d)
US		1,156		1,172		1,138			1,145		1,141
Europe		1,051		1,157		1,053			1,073		1,100
Rest of World		537		459		526			509		495
		2,744		2,788		2,717			2,727		2,736
Trading/supply sales of refined products		3,519		3,157		3,199			3,268		3,194
Total sales volumes of refined products		6,263		5,945		5,916			5,995		5,930
Petrochemicals production (kte)
US		518		564		672			2,267		2,235
Europe		1,141		1,187		1,037			4,714		4,468
Rest of World		1,353		1,325		1,259			5,133		5,154
		3,012		3,076		2,968			12,114		11,857

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

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

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

 

 

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Rosneft

		Fourth		Third		Fourth
		quarter		quarter		quarter			Year		Year
$ million		2019(a)		2019		2018			2019(a)		2018
Profit before interest and tax(b)(c)		534		723		308			2,306		2,288
Inventory holding (gains) losses*		(31	)	79		92			10		(67	)
RC profit before interest and tax		503		802		400			2,316		2,221
Net charge (credit) for non-operating items*		(91	)	-		31			103		95
Underlying RC profit before interest and tax*		412		802		431			2,419		2,316

 

Financial results

Replacement cost (RC) profit before interest and tax for the fourth quarter and full year was $503 million and $2,316 million respectively, compared with $400 million and $2,221 million for the same periods in 2018.

After adjusting for non-operating items, the underlying RC profit before interest and tax for the fourth quarter and full year was $412 million and $2,419 million respectively, compared with $431 million and $2,316 million for the same periods in 2018.

Compared with the same period in 2018, the result for the fourth quarter primarily reflects lower oil prices partially offset by duty lag benefit. Compared with 2018, the result for the full year primarily reflects favourable foreign exchange and certain one-off items offset by lower oil prices.

The extraordinary general meeting held on 30 September adopted a resolution to pay interim dividends of 15.34 roubles per ordinary share which constitute 50% of Rosneft's IFRS net profit for the first half of 2019. BP received dividends of $451 million (net of withholding tax) in November.

 

		Fourth		Third		Fourth
		quarter		quarter		quarter			Year		Year
		2019(a)		2019		2018			2019(a)		2018
Production (net of royalties) (BP share)
Liquids* (mb/d)		923		920		946			923		923
Natural gas (mmcf/d)		1,306		1,236		1,312			1,279		1,285
Total hydrocarbons* (mboe/d)		1,148		1,133		1,173			1,144		1,144

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

		Fourth		Third		Fourth
		quarter		quarter		quarter			Year		Year
$ million		2019		2019		2018			2019		2018
Profit (loss) before interest and tax		(1,432	)	(412	)	(1,110	)		(2,771	)	(3,521	)
Inventory holding (gains) losses*		-		-		-			-		-
RC profit (loss) before interest and tax		(1,432	)	(412	)	(1,110	)		(2,771	)	(3,521	)
Net charge (credit) for non-operating items*		1,182		90		766			1,491		1,963
Underlying RC profit (loss) before interest and tax*		(250	)	(322	)	(344	)		(1,280	)	(1,558	)
Underlying RC profit (loss) before interest and tax
US		(85	)	(249	)	(179	)		(713	)	(615	)
Non-US		(165	)	(73	)	(165	)		(567	)	(943	)
		(250	)	(322	)	(344	)		(1,280	)	(1,558	)
Non-operating items
US		(268	)	(85	)	(654	)		(559	)	(1,738	)
Non-US		(914	)	(5	)	(112	)		(932	)	(225	)
		(1,182	)	(90	)	(766	)		(1,491	)	(1,963	)
RC profit (loss) before interest and tax
US		(353	)	(334	)	(833	)		(1,272	)	(2,353	)
Non-US		(1,079	)	(78	)	(277	)		(1,499	)	(1,168	)
		(1,432	)	(412	)	(1,110	)		(2,771	)	(3,521	)

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 fourth quarter and full year was $1,432 million and $2,771 million respectively, compared with $1,110 million and $3,521 million for the same periods in 2018.

The results included a net non-operating charge of $1,182 million for the fourth quarter and $1,491 million for the full year, primarily relating to the reclassification of $877 million of accumulated foreign exchange losses from reserves to the income statement which arose as a result of the contribution of our Brazilian biofuels business to BP Bunge Bioenergia, as well as costs of the Gulf of Mexico oil spill, compared with a charge of $766 million and $1,963 million for the same periods in 2018.

After adjusting for non-operating items, the underlying replacement cost loss before interest and tax for the fourth quarter and full year was $250 million and $1,280 million respectively, compared with $344 million and $1,558 million for the same periods in 2018.

 

Alternative Energy

The net ethanol-equivalent production (which includes ethanol and sugar) for the fourth quarter and full year was 172 million litres and 796 million litres respectively, compared with 144 million litres and 765 million litres for the same periods in 2018.

Net wind generation capacity* was 926MW at 31 December 2019, compared with 1,001MW at 31 December 2018. BP's net share of wind generation for the fourth quarter and full year was 785GWh and 2,752GWh respectively, compared with 933GWh and 3,821GWh 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 has an operating portfolio of 2GW of solar projects under its management and has plans for 10GW of developed assets by the end of 2023. During the fourth quarter BP increased its shareholding, to become an equal partner in the business, with the balance of shares continuing to be held by Lightsource BP's management and staff.

In November, Lightsource BP became the first company in the UK to provide a reactive power service from a solar plant at night following a successful trial at its East Sussex solar plant. The trial follows three years of testing and development working with UK Power Networks and the National Grid Electricity System Operator.

In December, BP and Bunge Limited completed the formation of BP Bunge Bioenergia. The joint venture combines the Brazilian biofuels and biopower assets of the two companies into a 50/50 JV, and has 11 biofuel sites, with 32 million metric tonnes of combined crushing capacity per year. In 2018 the combined operations produced 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.

In early January 2020, BP participated in an artificial intelligence (AI) venture by investing in energy management specialist R&B whose systems are designed to predict, control and improve a building's energy use. Buildings currently account for one third of the world's total energy consumption and this venture will enable building managers to make informed decisions to optimize energy use and reduce carbon emissions.

 

Outlook

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

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

 

 

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Financial statements

Group income statement

		Fourth		Third		Fourth
		quarter		quarter		quarter			Year		Year
$ million		2019		2019		2018			2019		2018
Sales and other operating revenues (Note 5)		71,109		68,291		75,677			278,397		298,756
Earnings from joint ventures - after interest and tax		163		90		236			576		897
Earnings from associates - after interest and tax		640		784		425			2,681		2,856
Interest and other income		210		126		295			769		773
Gains on sale of businesses and fixed assets		48		1		252			193		456
Total revenues and other income		72,170		69,292		76,885			282,616		303,738
Purchases		53,444		52,273		59,019			209,672		229,878
Production and manufacturing expenses		5,809		5,259		6,173			21,815		23,005
Production and similar taxes (Note 7)		412		340		186			1,547		1,536
Depreciation, depletion and amortization (Note 6)		4,434		4,297		3,987			17,780		15,457
Impairment and losses on sale of businesses and fixed assets (Note 3)		3,657		3,416		244			8,075		860
Exploration expense		266		185		457			964		1,445
Distribution and administration expenses		2,996		2,648		3,655			11,057		12,179
Profit (loss) before interest and taxation		1,152		874		3,164			11,706		19,378
Finance costs		886		883		742			3,489		2,528
Net finance expense relating to pensions and other post-retirement benefits		17		16		34			63		127
Profit (loss) before taxation		249		(25	)	2,388			8,154		16,723
Taxation		231		706		1,617			3,964		7,145
Profit (loss) for the period		18		(731	)	771			4,190		9,578
Attributable to
BP shareholders		19		(749	)	766			4,026		9,383
Non-controlling interests		(1	)	18		5			164		195
		18		(731	)	771			4,190		9,578
Earnings per share (Note 8)
Profit (loss) for the period attributable to BP shareholders
Per ordinary share (cents)
Basic		0.09		(3.68	)	3.83			19.84		46.98
Diluted		0.09		(3.68	)	3.80			19.73		46.67
Per ADS (dollars)
Basic		0.01		(0.22	)	0.23			1.19		2.82
Diluted		0.01		(0.22	)	0.23			1.18		2.80

 

 

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Condensed group statement of comprehensive income

		Fourth		Third		Fourth
		quarter		quarter		quarter			Year		Year
$ million		2019		2019		2018			2019		2018
Profit (loss) for the period		18		(731	)	771			4,190		9,578
Other comprehensive income
Items that may be reclassified subsequently to profit or loss
Currency translation differences		1,404		(986	)	(937	)		1,538		(3,771	)
Exchange (gains) losses on translation of foreign operations reclassified to gain or loss on sale of businesses and fixed assets		880		-		-			880		-
Cash flow hedges and costs of hedging		(76	)	(17	)	(68	)		59		(192	)
Share of items relating to equity-accounted entities, net of tax		43		119		200			82		417
Income tax relating to items that may be reclassified		(39	)	12		33			(70	)	4
		2,212		(872	)	(772	)		2,489		(3,542	)
Items that will not be reclassified to profit or loss
Remeasurements of the net pension and other post-retirement benefit liability or asset		1,480		(260	)	(651	)		328		2,317
Cash flow hedges that will subsequently be transferred to the balance sheet		6		(10	)	(8	)		(3	)	(37	)
Income tax relating to items that will not be reclassified		(459	)	27		223			(157	)	(718	)
		1,027		(243	)	(436	)		168		1,562
Other comprehensive income		3,239		(1,115	)	(1,208	)		2,657		(1,980	)
Total comprehensive income		3,257		(1,846	)	(437	)		6,847		7,598
Attributable to
BP shareholders		3,240		(1,848	)	(444	)		6,674		7,444
Non-controlling interests		17		2		7			173		154
		3,257		(1,846	)	(437	)		6,847		7,598

 

 

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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		6,674		173		6,847
Dividends		(6,929	)	(213	)	(7,142	)
Cash flow hedges transferred to the balance sheet, net of tax		23		-		23
Repurchase of ordinary share capital		(1,511	)	-		(1,511	)
Share-based payments, net of tax		719		-		719
Share of equity-accounted entities' changes in equity, net of tax		5		-		5
Transactions involving non-controlling interests, net of tax		316		233		549
At 31 December 2019		98,412		2,296		100,708
		BP shareholders'		Non-controlling		Total
$ million		equity		interests		equity
At 31 December 2017		98,491		1,913		100,404
Adjustment on adoption of IFRS 9, net of tax(b)		(180	)	-		(180	)
At 1 January 2018		98,311		1,913		100,224
Total comprehensive income		7,444		154		7,598
Dividends		(6,699	)	(170	)	(6,869	)
Cash flow hedges transferred to the balance sheet, net of tax		26		-		26
Repurchase of ordinary share capital		(355	)	-		(355	)
Share-based payments, net of tax		703		-		703
Share of equity-accounted entities' changes in equity, net of tax		14		-		14
Transactions involving non-controlling interests, net of tax		-		207		207
At 31 December 2018		99,444		2,104		101,548

(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

		31 December		31 December
$ million		2019		2018(a)
Non-current assets
Property, plant and equipment		132,642		135,261
Goodwill		11,868		12,204
Intangible assets		15,539		17,284
Investments in joint ventures		9,991		8,647
Investments in associates		20,334		17,673
Other investments		1,276		1,341
Fixed assets		191,650		192,410
Loans		630		637
Trade and other receivables		2,147		1,834
Derivative financial instruments		6,314		5,145
Prepayments		781		1,179
Deferred tax assets		4,560		3,706
Defined benefit pension plan surpluses		7,053		5,955
		213,135		210,866
Current assets
Loans		339		326
Inventories		20,880		17,988
Trade and other receivables		24,442		24,478
Derivative financial instruments		4,153		3,846
Prepayments		857		963
Current tax receivable		1,282		1,019
Other investments		169		222
Cash and cash equivalents		22,472		22,468
		74,594		71,310
Assets classified as held for sale (Note 2)		7,465		-
		82,059		71,310
Total assets		295,194		282,176
Current liabilities
Trade and other payables		46,829		46,265
Derivative financial instruments		3,261		3,308
Accruals		5,066		4,626
Lease liabilities		2,067		44
Finance debt		10,487		9,329
Current tax payable		2,039		2,101
Provisions		2,453		2,564
		72,202		68,237
Liabilities directly associated with assets classified as held for sale (Note 2)		1,393		-
		73,595		68,237
Non-current liabilities
Other payables		12,626		13,830
Derivative financial instruments		5,537		5,625
Accruals		996		575
Lease liabilities		7,655		623
Finance debt		57,237		55,803
Deferred tax liabilities		9,750		9,812
Provisions		18,498		17,732
Defined benefit pension plan and other post-retirement benefit plan deficits		8,592		8,391
		120,891		112,391
Total liabilities		194,486		180,628
Net assets		100,708		101,548
Equity
BP shareholders' equity		98,412		99,444
Non-controlling interests		2,296		2,104
Total equity		100,708		101,548

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

 

 

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Condensed group cash flow statement

		Fourth		Third		Fourth
		quarter		quarter		quarter			Year		Year
$ million		2019		2019		2018			2019		2018
Operating activities
Profit (loss) before taxation		249		(25	)	2,388			8,154		16,723
Adjustments to reconcile profit (loss) before taxation to net cash provided by operating activities
Depreciation, depletion and amortization and exploration expenditure written off		4,589		4,412		4,338			18,411		16,542
Impairment and (gain) loss on sale of businesses and fixed assets		3,609		3,415		(8	)		7,882		404
Earnings from equity-accounted entities, less dividends received		(75	)	(236	)	(30	)		(1,295	)	(2,218	)
Net charge for interest and other finance expense, less net interest paid		250		257		222			657		607
Share-based payments		167		149		126			730		690
Net operating charge for pensions and other post-retirement benefits, less contributions and benefit payments for unfunded plans		(43	)	(50	)	(60	)		(238	)	(386	)
Net charge for provisions, less payments		270		(132	)	617			(176	)	986
Movements in inventories and other current and non-current assets and liabilities		(306	)	141		778			(2,918	)	(4,763	)
Income taxes paid		(1,107	)	(1,875	)	(1,542	)		(5,437	)	(5,712	)
Net cash provided by operating activities		7,603		6,056		6,829			25,770		22,873
Investing activities
Expenditure on property, plant and equipment, intangible and other assets		(3,936	)	(3,954	)	(5,962	)		(15,418	)	(16,707	)
Acquisitions, net of cash acquired		(33	)	13		(6,379	)		(3,562	)	(6,986	)
Investment in joint ventures		(57	)	(60	)	(290	)		(137	)	(382	)
Investment in associates		(83	)	(22	)	(265	)		(304	)	(1,013	)
Total cash capital expenditure		(4,109	)	(4,023	)	(12,896	)		(19,421	)	(25,088	)
Proceeds from disposal of fixed assets		24		171		660			500		940
Proceeds from disposal of businesses, net of cash disposed		792		536		1,758			1,701		1,911
Proceeds from loan repayments		64		63		619			246		666
Net cash used in investing activities		(3,229	)	(3,253	)	(9,859	)		(16,974	)	(21,571	)
Financing activities(a)
Net issue (repurchase) of shares (Note 8)		(1,171	)	(215	)	(16	)		(1,511	)	(355	)
Lease liability payments		(566	)	(594	)	(11	)		(2,372	)	(35	)
Proceeds from long-term financing		1,879		213		2,118			8,597		9,038
Repayments of long-term financing		(360	)	(516	)	(1,795	)		(7,118	)	(7,175	)
Net increase (decrease) in short-term debt		62		(852	)	889			180		1,317
Net increase (decrease) in non-controlling interests		566		-		-			566		-
Dividends paid - BP shareholders		(2,076	)	(1,656	)	(1,733	)		(6,946	)	(6,699	)
- non-controlling interests		(47	)	(47	)	(41	)		(213	)	(170	)
Net cash provided by (used in) financing activities		(1,713	)	(3,667	)	(589	)		(8,817	)	(4,079	)
Currency translation differences relating to cash and cash equivalents		119		(118	)	(105	)		25		(330	)
Increase (decrease) in cash and cash equivalents		2,780		(982	)	(3,724	)		4		(3,107	)
Cash and cash equivalents at beginning of period		19,692		20,674		26,192			22,468		25,575
Cash and cash equivalents at end of period		22,472		19,692		22,468			22,472		22,468

(a)      Financing cash flows for the fourth quarter and full 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 results for the interim periods and the year ended 31 December 2019 are unaudited and, in the opinion of management, include all adjustments necessary for a fair presentation of the results for each period. All such adjustments are of a normal recurring nature. This report should be read in conjunction with the consolidated financial statements and related notes for the year ended 31 December 2018 included in BP Annual Report and Form 20-F 2018.

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

The financial information presented herein has been prepared in accordance with the accounting policies expected to be used in preparing BP Annual Report and Form 20-F 2019, which are the same as those used in preparing BP Annual Report and Form 20-F 2018 with the exception of the adoption of IFRS 16 'Leases' from 1 January 2019.

 

Changes in significant accounting estimates

In BP Annual Report and Form 20-F 2018 we disclosed significant estimates relating to provisions and the recoverability of asset carrying values. During the fourth quarter 2019 certain key assumptions used in these estimates were reviewed.

Provisions discount rate

The nominal discount rate applied to provisions was revised to 2.5% (31 December 2018 3.0%). The principal impact of this rate reduction was a $1.4 billion increase in the decommissioning provision with a similar increase in the carrying amount of property, plant and equipment.

Impairment testing assumptions

The price assumptions used in value-in-use impairment testing were reviewed. The long-term assumption for Brent oil used in the fourth quarter is derived from $70 per barrel in 2015 prices (31 December 2018 $75 per barrel). The long-term natural gas price assumption for Henry Hub used in the fourth quarter is unchanged from 2018. Short-term oil and gas price assumptions were updated to reflect recent market rates and a gradual transition to the long-term assumptions over 5 years for Brent oil (2018 5 years), and 12 years for Henry Hub gas (2018 5 years).

The pre-tax discount rate applied to value-in-use impairment testing during the fourth quarter typically ranged from 7% to 13% depending on the applicable tax rate in the geographic location of the relevant cash-generating unit (31 December 2018 9%). The additional premium applied to higher-risk countries ranged from 1% to 4% (31 December 2018 2%).

The revision to the group's oil and gas price assumptions and impairment discount rates did not result in the recognition of any significant impairment charges.

Further details will be provided in BP Annual Report and Form 20-F 2019, which is expected to be published in March 2020.

 

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.

 

 

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Note 1. Basis of preparation (continued)

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.

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.

 

 

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Note 1. Basis of preparation (continued)

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

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

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

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

 

IFRIC agenda decision on IFRS 9 'Financial Instruments'

In March 2019, the IFRS Interpretations Committee (IFRIC) issued an agenda decision on the application of IFRS 9 to the physical settlement of contracts to buy or sell a non-financial item. The agenda decision concluded that where a derivative contract is settled by the physical receipt (or delivery) of the commodity, the transaction price reported for the purchase (or sale) should include the fair value of the derivative instrument in addition to the cash payable (or receivable). BP is currently assessing the impact of the agenda decision but expects it to have no effect on reported earnings. Further details will be provided in BP Annual Report and Form 20-F 2019.

 

Note 2. Non-current assets held for sale

The carrying amount of assets classified as held for sale at 31 December 2019 is $7,465 million, with associated liabilities of $1,393 million. These principally relate to two material disposal transactions which have been classified as held for sale in the group balance sheet.

On 27 August 2019, BP announced that it had agreed to sell all its Alaska operations and interests to Hilcorp Energy for up to $5.6 billion, subject to customary closing adjustments, of which $1.6 billion is contingent on future cash flows. The sale will include BP's entire upstream and midstream business in the state, including BP Exploration (Alaska) Inc., which owns all of BP's upstream oil and gas interests in Alaska, and BP Pipelines (Alaska) Inc.'s 49% interest in the Trans Alaska Pipeline System (TAPS). BP will retain decommissioning liability relating to TAPS, which will be partially offset by a 30% cost reimbursement from Hilcorp. The deal, which is subject to governmental authorizations, is expected to complete during 2020. Assets of $6,518 million and associated liabilities of $969 million relating to this transaction are classified as held for sale at 31 December 2019.

In November 2019, BP agreed to sell its interests in the San Juan basin in Colorado and New Mexico to IKAV. The deal is expected to complete during the first half of 2020. Assets and associated liabilities relating to this transaction are classified as held for sale at 31 December 2019.

 

 

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Note 3. Impairment and losses on sale of businesses and fixed assets

Included within the line item in the income statement for impairment and losses on sale of businesses and fixed assets is a net impairment charge for the fourth quarter of $2,543 million. The net charge for the year is $6,716 million.

The impairment charges, which are substantially all reported in the Upstream segment, principally relate to BP's ongoing divestment programme. They include $1,986 million in the fourth quarter and $4,703 million in the year relating to heritage BPX Energy assets; $258 million in the fourth quarter and the $1,264 million in the year relating to the group's interests in its Alaska business; and $244 million in the year relating to the group's interests in Gulf of Suez oil concessions in Egypt. The impairment charges were determined based on the assets' fair value less costs of disposal referenced to expected sales proceeds. See Note 1 and Note 2 for further information.

Also included is an $877 million loss on disposal relating to the reclassification of accumulated foreign exchange losses from reserves which arose as a result of the contribution of our Brazilian biofuels business to BP Bunge Bioenergia.

 

Note 4. Analysis of replacement cost profit (loss) before interest and tax and reconciliation to profit (loss) before taxation

		Fourth		Third		Fourth
		quarter		quarter		quarter			Year		Year
$ million		2019		2019		2018			2019		2018
Upstream		614		(1,050	)	4,168			4,917		14,328
Downstream		1,433		2,016		2,138			6,502		6,940
Rosneft		503		802		400			2,316		2,221
Other businesses and corporate		(1,432	)	(412	)	(1,110	)		(2,771	)	(3,521	)
		1,118		1,356		5,596			10,964		19,968
Consolidation adjustment - UPII*		24		30		142			75		211
RC profit (loss) before interest and tax*		1,142		1,386		5,738			11,039		20,179
Inventory holding gains (losses)*
Upstream		-		-		(12	)		(8	)	(6	)
Downstream		(21	)	(433	)	(2,470	)		685		(862	)
Rosneft (net of tax)		31		(79	)	(92	)		(10	)	67
Profit (loss) before interest and tax		1,152		874		3,164			11,706		19,378
Finance costs		886		883		742			3,489		2,528
Net finance expense relating to pensions and other post-retirement benefits		17		16		34			63		127
Profit (loss) before taxation		249		(25	)	2,388			8,154		16,723
RC profit (loss) before interest and tax*
US		(1,603	)	(2,425	)	1,487			(2,759	)	3,041
Non-US		2,745		3,811		4,251			13,798		17,138
		1,142		1,386		5,738			11,039		20,179

 

 

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Note 5. Sales and other operating revenues

		Fourth		Third		Fourth
		quarter		quarter		quarter			Year		Year
$ million		2019		2019		2018			2019		2018
By segment
Upstream		13,955		12,396		15,050			54,501		56,399
Downstream		64,251		61,834		67,733			250,897		270,689
Other businesses and corporate		538		461		536			1,788		1,678
		78,744		74,691		83,319			307,186		328,766
Less: sales and other operating revenues between segments
Upstream		6,823		6,406		8,669			27,034		28,565
Downstream		384		(59	)	(1,232	)		973		574
Other businesses and corporate		428		53		205			782		871
		7,635		6,400		7,642			28,789		30,010
Third party sales and other operating revenues
Upstream		7,132		5,990		6,381			27,467		27,834
Downstream		63,867		61,893		68,965			249,924		270,115
Other businesses and corporate		110		408		331			1,006		807
Total sales and other operating revenues		71,109		68,291		75,677			278,397		298,756
By geographical area
US		24,148		23,413		26,890			95,495		104,759
Non-US		54,450		51,030		53,540			208,031		219,681
		78,598		74,443		80,430			303,526		324,440
Less: sales and other operating revenues between areas		7,489		6,152		4,753			25,129		25,684
		71,109		68,291		75,677			278,397		298,756
Revenues from contracts with customers
Sales and other operating revenues include the following in relation to revenues from contracts with customers:
Crude oil		16,276		14,502		15,448			62,130		65,276
Oil products		46,279		44,667		47,847			180,528		195,466
Natural gas, LNG and NGLs		5,086		4,465		5,862			20,167		21,745
Non-oil products and other revenues from contracts with customers		3,280		3,300		3,618			13,254		13,768
		70,921		66,934		72,775			276,079		296,255

 

Note 6. Depreciation, depletion and amortization

		Fourth		Third		Fourth
		quarter		quarter		quarter			Year		Year
$ million		2019		2019		2018			2019		2018
Upstream
US		1,150		1,121		1,137			4,672		4,211
Non-US		2,371		2,295		2,242			9,560		8,907
		3,521		3,416		3,379			14,232		13,118
Downstream
US		343		336		240			1,335		900
Non-US		417		394		298			1,586		1,177
		760		730		538			2,921		2,077
Other businesses and corporate
US		14		14		11			55		59
Non-US		139		137		59			572		203
		153		151		70			627		262
Total group		4,434		4,297		3,987			17,780		15,457

 

 

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Note 7. Production and similar taxes

		Fourth		Third		Fourth
		quarter		quarter		quarter			Year		Year
$ million		2019		2019		2018			2019		2018
US		89		66		99			315		369
Non-US		323		274		87			1,232		1,167
		412		340		186			1,547		1,536

 

Note 8. Earnings per share and shares in issue

 

Basic earnings per ordinary share (EpS) amounts are calculated by dividing the profit (loss) for the period attributable to ordinary shareholders by the weighted average number of ordinary shares outstanding during the period. During the quarter the company repurchased for cancellation 184 million ordinary shares for a total cost of $1,171 million, including transaction costs of $6 million, as part of the share buyback programme announced on 31 October 2017. This brings the total number of shares repurchased in the  year to 235 million for a total cost of $1,511 million, including transaction costs of $8 million. A further 120 million of shares have been repurchased in January 2020 at a total cost of $776 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.

		Fourth		Third		Fourth
		quarter		quarter		quarter			Year		Year
$ million		2019		2019		2018			2019		2018
Results for the period
Profit (loss) for the period attributable to BP shareholders		19		(749	)	766			4,026		9,383
Less: preference dividend		-		-		-			1		1
Profit (loss) attributable to BP ordinary shareholders		19		(749	)	766			4,025		9,382
Number of shares (thousand)(a)(b)
Basic weighted average number of shares outstanding		20,254,234		20,371,728		20,007,781			20,284,859		19,970,215
ADS equivalent		3,375,705		3,395,288		3,334,630			3,380,809		3,328,369
Weighted average number of shares outstanding used to calculate diluted earnings per share		20,351,808		20,371,728		20,133,087			20,399,670		20,102,493
ADS equivalent		3,391,968		3,395,288		3,355,514			3,399,945		3,350,415
Shares in issue at period-end		20,241,170		20,417,220		20,101,658			20,241,170		20,101,658
ADS equivalent		3,373,528		3,402,870		3,350,276			3,373,528		3,350,276

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

(b)       If the inclusion of potentially issuable shares would decrease loss per share, the potentially issuable shares are excluded from the weighted average number of shares outstanding used to calculate diluted earnings per share.

 

 

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Note 9. Dividends

Dividends payable

BP today announced an interim dividend of 10.50 cents per ordinary share which is expected to be paid on 27 March 2020 to ordinary shareholders and American Depositary Share (ADS) holders on the register on 14 February 2020. The corresponding amount in sterling is due to be announced on 16 March 2020, calculated based on the average of the market exchange rates for the four dealing days commencing on 10 March 2020. Holders of ADSs are expected to receive $0.630 per ADS (less applicable fees). The board has decided not to offer a scrip dividend alternative in respect of the fourth quarter 2019 dividend. Ordinary shareholders and ADS holders (subject to certain exceptions) will be able to participate in a dividend reinvestment programme. Details of the fourth quarter dividend and timetable are available at bp.com/dividends and further details of the dividend reinvestment programmes are available at bp.com/drip.

 

		Fourth		Third		Fourth
		quarter		quarter		quarter			Year		Year
		2019		2019		2018			2019		2018
Dividends paid per ordinary share
cents		10.250		10.250		10.250			41.000		40.500
pence		7.825		8.348		8.025			31.977		30.568
Dividends paid per ADS (cents)		61.50		61.50		61.50			246.00		243.00
Scrip dividends
Number of shares issued (millions)		-		72.5		47.5			208.9		195.3
Value of shares issued ($ million)		-		440		322			1,387		1,381

 

Note 10. Net debt and net debt including leases

Net debt*		Fourth		Third		Fourth
		quarter		quarter		quarter			Year		Year
$ million		2019		2019		2018			2019		2018
Finance debt(a)		67,724		65,867		65,132			67,724		65,132
Fair value (asset) liability of hedges related to finance debt(b)		190		319		813			190		813
		67,914		66,186		65,945			67,914		65,945
Less: cash and cash equivalents		22,472		19,692		22,468			22,472		22,468
Net debt		45,442		46,494		43,477			45,442		43,477
Total equity		100,708		100,015		101,548			100,708		101,548
Gearing*		31.1%		31.7%		30.0%			31.1%		30.0%

(a)       The fair value of finance debt at 31 December 2019 was $69,376 million (31 December 2018 $65,366 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 $601 million (third quarter 2019 liability of $682 million and fourth quarter 2018 liability of $827 million) are not included in the calculation of net debt shown above as hedge accounting is not applied for these instruments.

 

As a result of the adoption of IFRS 16 'Leases' from 1 January 2019, leases that were previously classified as finance leases under IAS 17 are now presented as 'Lease liabilities' on the group balance sheet and, therefore, do not form part of finance debt. Comparative information for finance debt (previously termed 'gross debt'), net debt and gearing (previously termed 'net debt ratio') have been amended to be on a consistent basis with amounts presented for 2019. The relevant amount for finance lease liabilities that has been excluded from comparative information for the fourth quarter and full year 2018 is $667 million. The previously disclosed amount for finance debt for the fourth quarter and full year 2018 was $65,799 million. The previously disclosed amount for net debt for the fourth quarter and full year 2018 was $44,144 million. The previously disclosed gearing for the fourth quarter and full year 2018 was 30.3%.

Net debt including leases*		Fourth		Third		Fourth
		quarter		quarter		quarter			Year		Year
$ million		2019		2019		2018			2019		2018
Net debt		45,442		46,494		43,477			45,442		43,477
Lease liabilities		9,722		9,639		667			9,722		667
Net partner (receivable) payable for leases entered into on behalf of joint operations		(158	)	(197	)	-			(158	)	-
Net debt including leases		55,006		55,936		44,144			55,006		44,144

 

 

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Note 11. Inventory valuation

 

A provision of $290 million was held against hydrocarbon inventories at 31 December 2019 ($369 million at 30 September 2019 and $604 million at 31 December 2018) to write them down to their net realizable value. The net movement credited to the income statement during the fourth quarter 2019 was $80 million (third quarter 2019 was a charge of $131 million and fourth quarter 2018 was a charge of $562 million).

 

Note 12. Statutory accounts

 

The financial information shown in this publication, which was approved by the Board of Directors on 3 February 2020, is unaudited and does not constitute statutory financial statements. Audited financial information will be published in BP Annual Report and Form 20-F 2019. BP Annual Report and Form 20-F 2018 has been filed with the Registrar of Companies in England and Wales. The report of the auditor on those accounts was unqualified, did not include a reference to any matters to which the auditor drew attention by way of emphasis without qualifying the report and did not contain a statement under section 498(2) or section 498(3) of the UK Companies Act 2006.

 

 

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Additional information

Effects on the financial statements of the adoption of IFRS 16 'Leases'

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

Balance sheet

As a result of the adoption of IFRS 16, $9.0 billion of right-of-use assets and $9.7 billion of lease liabilities have been included in the group balance sheet as at 31 December 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.

		31 December		31 December
$ billion		2019		2018
Property, plant and equipment(a) (b)		9.0		0.5
Lease liabilities(a)		9.7		0.7
Finance debt		67.7		65.1

(a)      Comparative information represents finance leases accounted for under IAS 17.

(b)      Net additions to right-of-use assets for the fourth quarter and full year 2019 were $0.5 billion and $2.5 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 fourth quarter and full year 2019 was $0.5 billion and $1.9 billion respectively. Interest on the group's lease liabilities for the fourth quarter and full year 2019 was $0.1 billion and $0.4 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 largely 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 fourth quarter and full year 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 fourth 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 $2.4 billion of lease payments included within financing activities for the full year 2019, it is estimated that $2.0 billion would have been reported as operating cash flows and $0.4 billion would have been reported as capital expenditure cash flows, ignoring the effects of IFRS 16.

		Fourth		Third		Fourth
		quarter		quarter		quarter			Year		Year
$ billion		2019		2019		2018			2019		2018
Financing activities
Lease liability payments(a)		(0.6	)	(0.6	)	-			(2.4	)	-

(a)       Comparative information represents finance leases accounted for under IAS 17.

 

 

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Capital expenditure*

		Fourth		Third		Fourth
		quarter		quarter		quarter			Year		Year
$ million		2019		2019		2018			2019		2018
Capital expenditure on a cash basis
Organic capital expenditure*		3,958		3,946		4,402			15,238		15,140
Inorganic capital expenditure*(a)		151		77		8,494			4,183		9,948
		4,109		4,023		12,896			19,421		25,088

 

		Fourth		Third		Fourth
		quarter		quarter		quarter			Year		Year
$ million		2019		2019		2018			2019		2018
Organic capital expenditure by segment
Upstream
US		1,029		1,036		1,048			4,019		3,482
Non-US		2,029		2,110		2,419			7,885		8,545
		3,058		3,146		3,467			11,904		12,027
Downstream
US		258		197		237			913		877
Non-US		522		558		562			2,084		1,904
		780		755		799			2,997		2,781
Other businesses and corporate
US		15		8		34			47		54
Non-US		105		37		102			290		278
		120		45		136			337		332
		3,958		3,946		4,402			15,238		15,140
Organic capital expenditure by geographical area
US		1,302		1,241		1,319			4,979		4,413
Non-US		2,656		2,705		3,083			10,259		10,727
		3,958		3,946		4,402			15,238		15,140

(a)       On 31 October 2018, BP acquired from BHP Billiton Petroleum (North America) Inc. 100% of the issued share capital of Petrohawk Energy Corporation, a wholly owned subsidiary of BHP that holds a portfolio of unconventional onshore US oil and gas assets. The entire consideration payable of $10,268 million, after customary closing adjustments, was paid in instalments between July 2018 and April 2019. The amounts presented as inorganic capital expenditure include $6,263 million for the fourth quarter 2018, $3,480 million for the full year 2019 and $6,788 million for the full year 2018 relating to this transaction. Fourth quarter and full year 2018 include $1,739 million relating to the purchase of an additional 16.5% interest in the Clair field west of Shetland in the North Sea, as part of the agreements with Conoco-Phillips in which Conoco-Philips simultaneously purchased BP's entire 39.2% interest in the Greater Kuparuk Area on the North Slope of Alaska. Full year 2019 and 2018 also include amounts relating to the 25-year extension to our ACG production-sharing agreement* in Azerbaijan.

 

 

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Non-operating items*

		Fourth		Third		Fourth
		quarter		quarter		quarter			Year		Year
$ million		2019		2019		2018(a)			2019		2018(a)
Upstream
Impairment and gain (loss) on sale of businesses and fixed assets(b)		(2,680	)	(3,406	)	34			(6,893	)	(90	)
Environmental and other provisions		(32	)	-		(35	)		(32	)	(35	)
Restructuring, integration and rationalization costs		(13	)	(24	)	(53	)		(89	)	(131	)
Fair value gain (loss) on embedded derivatives		-		-		-			-		17
Other(c)		2		(24	)	190			67		56
		(2,723	)	(3,454	)	136			(6,947	)	(183	)
Downstream
Impairment and gain (loss) on sale of businesses and fixed assets		(16	)	(9	)	(20	)		(72	)	(54	)
Environmental and other provisions		(77	)	(1	)	(83	)		(78	)	(83	)
Restructuring, integration and rationalization costs		71		(4	)	(279	)		85		(405	)
Fair value gain (loss) on embedded derivatives		-		-		-			-		-
Other		(6	)	-		(19	)		(12	)	(174	)
		(28	)	(14	)	(401	)		(77	)	(716	)
Rosneft
Impairment and gain (loss) on sale of businesses and fixed assets		91		-		(31	)		(103	)	(95	)
Environmental and other provisions		-		-		-			-		-
Restructuring, integration and rationalization costs		-		-		-			-		-
Fair value gain (loss) on embedded derivatives		-		-		-			-		-
Other		-		-		-			-		-
		91		-		(31	)		(103	)	(95	)
Other businesses and corporate
Impairment and gain (loss) on sale of businesses and fixed assets(d)		(913	)	-		(6	)		(917	)	(260	)
Environmental and other provisions(e)		(203	)	-		(575	)		(231	)	(640	)
Restructuring, integration and rationalization costs		(1	)	-		(112	)		6		(190	)
Fair value gain (loss) on embedded derivatives		-		-		-			-		-
Gulf of Mexico oil spill		(63	)	(84	)	(67	)		(319	)	(714	)
Other		(2	)	(6	)	(6	)		(30	)	(159	)
		(1,182	)	(90	)	(766	)		(1,491	)	(1,963	)
Total before interest and taxation		(3,842	)	(3,558	)	(1,062	)		(8,618	)	(2,957	)
Finance costs(f)		(122	)	(145	)	(122	)		(511	)	(479	)
Total before taxation		(3,964	)	(3,703	)	(1,184	)		(9,129	)	(3,436	)
Taxation credit (charge) on non-operating items		822		772		(2	)		1,943		631
Total after taxation for period		(3,142	)	(2,931	)	(1,186	)		(7,186	)	(2,805	)

(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)       Fourth quarter and full year 2019 include impairment charges of $2,506 million and $6,621 million respectively, principally resulting from the announcements to dispose of certain assets in the US and Egypt. See Note 3 for further information. Fourth quarter and full year 2018 include impairment reversals for assets in the North Sea and Angola.

(c)       Full year 2018 includes the write-off of $124 million in relation to the value ascribed to certain licences in the deepwater Gulf of Mexico as part of the accounting for the acquisition of upstream assets from Devon Energy in 2011.

(d)       Fourth quarter and full year 2019 include $877 million relating to the reclassification of accumulated foreign exchange losses from reserves to the income statement upon the contribution of our Brazilian biofuels business to BP Bunge Bioenergia.

(e)       Fourth quarter and full year 2019 and 2018 primarily reflects charges due to the annual update of environmental provisions, including asbestos-related provisions for past operations, together with updates of non-Gulf of Mexico oil spill related legal provisions.

(f)        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

		Fourth		Third		Fourth
		quarter		quarter		quarter			Year		Year
$ million		2019		2019		2018			2019		2018
Favourable (adverse) impact relative to management's measure of performance
Upstream		659		265		146			706		(39	)
Downstream		23		147		370			160		95
		682		412		516			866		56
Taxation credit (charge)		(111	)	(86	)	(90	)		(155	)	12
		571		326		426			711		68

 

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.

		Fourth		Third		Fourth
		quarter		quarter		quarter			Year		Year
$ million		2019		2019		2018			2019		2018
Upstream
Replacement cost profit (loss) before interest and tax adjusted for fair value accounting effects		(45	)	(1,315	)	4,022			4,211		14,367
Impact of fair value accounting effects		659		265		146			706		(39	)
Replacement cost profit (loss) before interest and tax		614		(1,050	)	4,168			4,917		14,328
Downstream
Replacement cost profit (loss) before interest and tax adjusted for fair value accounting effects		1,410		1,869		1,768			6,342		6,845
Impact of fair value accounting effects		23		147		370			160		95
Replacement cost profit (loss) before interest and tax		1,433		2,016		2,138			6,502		6,940
Total group
Profit (loss) before interest and tax adjusted for fair value accounting effects		470		462		2,648			10,840		19,322
Impact of fair value accounting effects		682		412		516			866		56
Profit (loss) before interest and tax		1,152		874		3,164			11,706		19,378

 

Readily marketable inventory* (RMI)

		31 December		31 December
$ million		2019		2018
RMI at fair value*		6,837		4,202
Paid-up RMI*		3,217		1,641

 

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

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

See the Glossary on page 32 for a more detailed definition of RMI. RMI 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.

		31 December		31 December
$ million		2019		2018
Reconciliation of total inventory to paid-up RMI
Inventories as reported on the group balance sheet under IFRS		20,880		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		(14,280	)	(14,066	)
		6,600		3,922
Plus: difference between RMI at fair value and RMI on an IFRS basis		237		280
RMI at fair value		6,837		4,202
Less: unpaid RMI* at fair value		(3,620	)	(2,561	)
Paid-up RMI		3,217		1,641

 

 

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Gulf of Mexico oil spill

		Fourth		Third		Fourth
		quarter		quarter		quarter			Year		Year
$ million		2019		2019		2018			2019		2018
Net cash provided by operating activities as per condensed group cash flow statement		7,603		6,056		6,829			25,770		22,873
Exclude net cash from operating activities relating to the Gulf of Mexico oil spill on a post-tax basis		(42	)	409		272			2,429		3,218
Operating cash flow, excluding Gulf of Mexico oil spill payments*		7,561		6,465		7,101			28,199		26,091

Net cash from operating activities relating to the Gulf of Mexico oil spill on a pre-tax basis amounted to an outflow of $125 million and $2,694 million in the fourth quarter and full year of 2019 respectively. For the same periods in 2018, the amount was an outflow of $273 million and $3,531 million respectively. Net cash outflows relating to the Gulf of Mexico oil spill in 2019 and 2018 include payments made under the 2016 consent decree and settlement agreement with the United States and the five Gulf coast states. Cash outflows in 2018 also include the final payment made under the 2012 agreement with the US government to resolve all federal criminal claims arising from the incident.

		31 December		31 December
$ million		2019		2018
Trade and other payables		(12,480	)	(14,201	)
Provisions		(189	)	(345	)
Gulf of Mexico oil spill payables and provisions		(12,669	)	(14,546	)
Of which - current		(1,800	)	(2,612	)
Deferred tax asset		5,526		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

		Fourth		Third		Fourth
		quarter		quarter		quarter			Year		Year
$ 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		(306	)	141		778			(2,918	)	(4,763	)
Adjustments to exclude movements in inventories and other current and non-current assets and liabilities for the Gulf of Mexico oil spill		91		413		238			2,586		3,057
Adjusted for Inventory holding gains (losses)* (Note 4)
Upstream		-		-		(12	)		(8	)	(6	)
Downstream		(21	)	(433	)	(2,470	)		685		(862	)
Working capital release (build)		(236	)	121		(1,466	)		345		(2,574	)

 

 

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Realizations* and marker prices

		Fourth		Third		Fourth
		quarter		quarter		quarter			Year		Year
		2019		2019		2018			2019		2018
Average realizations(a)
Liquids* ($/bbl)
US		49.34		50.46		61.61			51.88		61.72
Europe		63.01		61.90		65.07			63.95		69.20
Rest of World		60.34		59.14		61.42			61.50		66.68
BP Average		55.90		55.68		61.80			57.73		64.98
Natural gas ($/mcf)
US		1.65		1.72		3.10			1.93		2.43
Europe		4.06		3.03		8.80			4.01		7.71
Rest of World		3.77		3.82		4.77			4.10		4.37
BP Average		3.12		3.11		4.33			3.39		3.92
Total hydrocarbons* ($/boe)
US		31.84		31.23		42.50			33.30		41.59
Europe		51.91		52.47		61.98			56.87		64.11
Rest of World		37.91		36.82		41.64			39.23		42.65
BP Average		36.42		35.48		42.98			38.00		43.47
Average oil marker prices ($/bbl)
Brent		63.08		62.00		68.81			64.21		71.31
West Texas Intermediate		56.88		56.40		59.98			57.03		65.20
Western Canadian Select		37.70		43.61		25.31			43.42		38.27
Alaska North Slope		64.32		62.98		69.53			65.00		71.54
Mars		57.85		59.19		64.45			60.84		66.86
Urals (NWE - cif)		60.74		60.82		68.02			62.96		69.89
Average natural gas marker prices
Henry Hub gas price(b) ($/mmBtu)		2.50		2.23		3.65			2.63		3.09
UK Gas - National Balancing Point (p/therm)		31.77		27.46		65.13			34.70		60.38

(a)       Based on sales of consolidated subsidiaries only - this excludes equity-accounted entities.

(b)       Henry Hub First of Month Index.

 

Exchange rates

		Fourth		Third		Fourth
		quarter		quarter		quarter			Year		Year
		2019		2019		2018			2019		2018
$/£ average rate for the period		1.29		1.23		1.29			1.28		1.33
$/£ period-end rate		1.31		1.23		1.27			1.31		1.27
$/€ average rate for the period		1.11		1.11		1.14			1.12		1.18
$/€ period-end rate		1.12		1.09		1.14			1.12		1.14
Rouble/$ average rate for the period		63.74		64.64		66.48			64.73		62.73
Rouble/$ period-end rate		61.98		64.32		69.57			61.98		69.57

 

 

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Legal proceedings

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

 

 

Glossary

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

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

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

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

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

Fair value accounting effects are non-GAAP adjustments to our IFRS profit (loss). They reflect the difference between the way BP manages the economic exposure and internally measures performance of certain activities and the way those activities are measured under IFRS. Further information on fair value accounting effects is provided on page 28.

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

Gearing and net debt are non-GAAP measures. Net debt is calculated as finance debt, as shown in the balance sheet, plus the fair value of associated derivative financial instruments that are used to hedge foreign currency exchange and interest rate risks relating to finance debt, for which hedge accounting is applied, less cash and cash equivalents. Gearing is defined as the ratio of net debt to the total of net debt plus total equity. BP believes these measures provide useful information to investors. Net debt enables investors to see the economic effect of finance debt, related hedges and cash and cash equivalents in total. Gearing enables investors to see how significant net debt is relative to total equity. The derivatives are reported on the balance sheet within the headings 'Derivative financial instruments'. The nearest equivalent GAAP measures on an IFRS basis are finance debt and finance debt ratio. A reconciliation of finance debt to net debt is provided on page 23.

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

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

Inorganic capital expenditure is a subset of capital expenditure and is a non-GAAP measure. Inorganic capital expenditure comprises consideration in business combinations and certain other significant investments made by the group. It is reported on a cash basis. BP believes that this measure provides useful information as it allows investors to understand how BP's management invests funds in projects which expand the group's activities through acquisition. Further information and a reconciliation to GAAP information is provided on page 26.

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

 

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Glossary (continued)

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

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

Net wind generation capacity is the sum of the rated capacities of the assets/turbines that have entered into commercial operation, including BP's share of equity-accounted entities.

Non-operating items are charges and credits included in the financial statements that BP discloses separately because it considers such disclosures to be meaningful and relevant to investors. They are items that management considers not to be part of underlying business operations and are disclosed in order to enable investors better to understand and evaluate the group's reported financial performance. Non-operating items within equity-accounted earnings are reported net of incremental income tax reported by the equity-accounted entity. An analysis of non-operating items by region is shown on pages 7, 9 and 11, and by segment and type is shown on page 27.

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

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

Organic capital expenditure is a subset of capital expenditure and is a non-GAAP measure. Organic capital expenditure comprises capital expenditure less inorganic capital expenditure. BP believes that this measure provides useful information as it allows investors to understand how BP's management invests funds in developing and maintaining the group's assets. An analysis of organic capital expenditure by segment and region, and a reconciliation to GAAP information is provided on page 26.

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

Production-sharing agreement/contract (PSA/PSC) 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 at fair value, Paid-up RMI and Unpaid RMI are non-GAAP measures. Further information is provided on page 29.

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

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

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

 

 

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Glossary (continued)

Replacement cost (RC) profit or loss reflects the replacement cost of inventories sold in the period and is arrived at by excluding inventory holding gains and losses from profit or loss. RC profit or loss for the group is not a recognized GAAP measure. BP believes this measure is useful to illustrate to investors the fact that crude oil and product prices can vary significantly from period to period and that the impact on our reported result under IFRS can be significant. Inventory holding gains and losses vary from period to period due to changes in prices as well as changes in underlying inventory levels. In order for investors to understand the operating performance of the group excluding the impact of price changes on the replacement of inventories, and to make comparisons of operating performance between reporting periods, BP's management believes it is helpful to disclose this measure. The nearest equivalent measure on an IFRS basis is profit or loss attributable to BP shareholders. A reconciliation to GAAP information is provided on page 1. RC profit or loss before interest and tax is the measure of profit or loss that is required to be disclosed for each operating segment under IFRS.

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

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

Reserves replacement ratio is the extent to which the year's production has been replaced by proved reserves added to our reserve base. The ratio is expressed in oil-equivalent terms and includes changes resulting from discoveries, improved recovery and extensions and revisions to previous estimates, but excludes changes resulting from acquisitions and disposals. The reserves replacement ratio will be reported in BP Annual Report and Form 20-F 2019.

Return on average capital employed (ROACE) is a non-GAAP measure and is underlying replacement cost profit, after adding back non-controlling interest and interest expense net of tax, divided by average capital employed (total equity plus finance debt), excluding cash and cash equivalents and goodwill. Interest expense is finance costs excluding lease interest and the unwinding of the discount on provisions and other payables, and for full year 2019 interest expense was $2,032 million (2018 $1,779 million) before tax. BP believes it is helpful to disclose the ROACE because this measure gives an indication of the company's capital efficiency. The nearest GAAP measures of the numerator and denominator are profit or loss for the period attributable to BP shareholders and average capital employed respectively.

Solomon availability - See Refining availability definition.

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

Underlying effective tax rate (ETR) is a non-GAAP measure. The underlying ETR is calculated by dividing taxation on an underlying replacement cost (RC) basis by underlying RC profit or loss before tax. Taxation on an underlying RC basis is taxation on a RC basis for the period adjusted for taxation on non-operating items and fair value accounting effects. Information on underlying RC profit or loss is provided below. BP believes it is helpful to disclose the underlying ETR because this measure may help investors to understand and evaluate, in the same manner as management, the underlying trends in BP's operational performance on a comparable basis, period on period. The nearest equivalent measure on an IFRS basis is the ETR on profit or loss for the period.

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

Underlying production - 2019 underlying production, when compared with 2018, is production after adjusting for BPX Energy, other acquisitions and divestments, and entitlement impacts in our production-sharing agreements.

Underlying RC profit or loss is RC profit or loss after adjusting for non-operating items and fair value accounting effects. Underlying RC profit or loss and adjustments for fair value accounting effects are not recognized GAAP measures. See pages 27 and 28 for additional information on the non-operating items and fair value accounting effects that are used to arrive at underlying RC profit or loss in order to enable a full understanding of the events and their financial impact. BP believes that underlying RC profit or loss is a useful measure for investors because it is a measure closely tracked by management to evaluate BP's operating performance and to make financial, strategic and operating decisions and because it may help investors to understand and evaluate, in the same manner as management, the underlying trends in BP's operational performance on a comparable basis, period on period, by adjusting for the effects of these non-operating items and fair value accounting effects. The nearest equivalent measure on an IFRS basis for the group is profit or loss attributable to BP shareholders. The nearest equivalent measure on an IFRS basis for segments is RC profit or loss before interest and taxation. 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 8. Underlying RC profit or loss per share is calculated using the same denominator. The numerator used is underlying RC profit or loss attributable to BP shareholders rather than profit or loss attributable to BP shareholders. BP believes it is helpful to disclose the underlying RC profit or loss per share because this measure may help investors to understand and evaluate, in the same manner as management, the underlying trends in BP's operational performance on a comparable basis, period on period. The nearest equivalent measure on an IFRS basis is basic earnings per share based on profit or loss for the period attributable to BP shareholders.

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

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

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

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

 

 

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Cautionary statement

In order to utilize the 'safe harbor' provisions of the United States Private Securities Litigation Reform Act of 1995 (the 'PSLRA') and the general doctrine of cautionary statements, BP is providing the following cautionary statement: The discussion in this results announcement contains certain forecasts, projections and forward-looking statements - that is, statements related to future, not past events and circumstances - with respect to the financial condition, results of operations and businesses of BP and certain of the plans and objectives of BP with respect to these items. These statements may generally, but not always, be identified by the use of words such as 'will', 'expects', 'is expected to', 'aims', 'should', 'may', 'objective', 'is likely to', 'intends', 'believes', 'anticipates', 'plans', 'we see' or similar expressions. In particular, the following, among other statements, are all forward looking in nature: expectations regarding the expected quarterly dividend payment and timing of such payment; expectations regarding the underlying effective tax rate in 2020; expectations regarding 2020 organic capital expenditure and depreciation, depletion and amortization charges; expectations for gearing to move towards the middle of the 20-30% range through 2020; plans and expectations to meet cash flow and returns objectives and to increase distributions to shareholders over the long term; plans and expectations relating to divestments and disposals, including expectations that BP will meet its target of $10 billion of divestment proceeds by the end of 2020 and announce a further $5 billion of agreed disposals by mid-2021, for a total of $15 billion of announced disposals by mid-2021 and expectations with respect to completion and the timing of receipt of proceeds of agreed divestments and disposals; plans and expectations regarding Upstream projects, including for Raven to come onstream around the end of 2020 and for TANAP to begin transporting gas to Turkish and European markets in late 2020; expectations regarding Upstream full year and first-quarter 2020 reported production, seasonal maintenance and turnaround activities; plans and expectations with respect to the joint venture in India with Reliance Industries Limited; expectations regarding Downstream turnaround activity and first-quarter 2020 industry refining margins and North American heavy crude oil discounts; plans and expectations regarding Lightsource BP, including plans to have 10GW of developed assets by the end of 2023; plans and expectations regarding the joint venture in China with DiDi, including the roll out of 150kW ultra-fast chargers across BP's UK retail network; plans and expectations with respect to BP's AI venture, including the venture's impact on energy use and carbon emissions of buildings, and plans and expectations with respect to BP Infinia, including to accelerate Infinia's commercialisation; expectations regarding the Other businesses and corporate average quarterly charges excluding non-operating items; and expectations with respect to the amount of future payments relating to the Gulf of Mexico oil spill. By their nature, forward-looking statements involve risk and uncertainty because they relate to events and depend on circumstances that will or may occur in the future and are outside the control of BP. Actual results may differ materially from those expressed in such statements, depending on a variety of factors, including: the specific factors identified in the discussions accompanying such forward-looking statements; the receipt of relevant third party and/or regulatory approvals; the timing and level of maintenance and/or turnaround activity; the timing and volume of refinery additions and outages; the timing of bringing new fields onstream; the timing, quantum and nature of certain acquisitions and divestments; future levels of industry product supply, demand and pricing, including supply growth in North America; OPEC quota restrictions; PSA effects; operational and safety problems; potential lapses in product quality; economic and financial market conditions generally or in various countries and regions; political stability and economic growth in relevant areas of the world; changes in laws and governmental regulations; regulatory or legal actions including the types of enforcement action pursued and the nature of remedies sought or imposed; the actions of prosecutors, regulatory authorities and courts; delays in the processes for resolving claims; amounts ultimately payable and timing of payments relating to the Gulf of Mexico oil spill; exchange rate fluctuations; development and use of new technology; recruitment and retention of a skilled workforce; the success or otherwise of partnering; the actions of competitors, trading partners, contractors, subcontractors, creditors, rating agencies and others; our access to future credit resources; business disruption and crisis management; the impact on our reputation of ethical misconduct and non-compliance with regulatory obligations; trading losses; major uninsured losses; decisions by Rosneft's management and board of directors; the actions of contractors; natural disasters and adverse weather conditions; changes in public expectations and other changes to business conditions; wars and acts of terrorism; cyber-attacks or sabotage; and other factors discussed elsewhere in this report, and under "Risk factors" in BP Annual Report and Form 20-F 2018 as filed with the US Securities and Exchange Commission.

 

This announcement contains inside information.

 

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