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RNS
BP PLC   -  BP.   

3Q19 Part 1 of 1

Released 07:00 29-Oct-2019

RNS Number : 3915R
BP PLC
29 October 2019
 

 

Top of page 1

 

FOR IMMEDIATE RELEASE

 

 

London 29 October 2019

 

 

 

 

BP p.l.c. Group results

 

Third quarter and nine months 2019

 
     

 

 

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

 

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

  

Highlights

Continued strong operating cash flow and strategic delivery

•   Financial results

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

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

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

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

•   Upstream operations impacted by maintenance and weather, Downstream strong

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

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

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

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

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

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

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

 

See chart on PDF

 

 

Bob Dudley - Group chief executive:

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

 

Financial summary

 

Third

Second

Third

 

Nine

Nine

 

 

quarter

quarter

quarter

 

months

months

$ million

 

2019

2019

2018

 

2019

2018

Profit (loss) for the period attributable to BP shareholders

 

(749

)

1,822

 

3,349

 

 

4,007

 

8,617

 

Inventory holding (gains) losses, net of tax

 

398

 

(47

)

(258

)

 

(488

)

(1,348

)

RC profit (loss)

 

(351

)

1,775

 

3,091

 

 

3,519

 

7,269

 

Net (favourable) adverse impact of non-operating items and fair value accounting effects, net of tax

 

2,605

 

1,036

 

747

 

 

3,904

 

1,977

 

Underlying RC profit

 

2,254

 

2,811

 

3,838

 

 

7,423

 

9,246

 

RC profit (loss) per ordinary share (cents)

 

(1.72

)

8.72

 

15.45

 

 

17.33

 

36.42

 

RC profit (loss) per ADS (dollars)

 

(0.10

)

0.52

 

0.93

 

 

1.04

 

2.19

 

Underlying RC profit per ordinary share (cents)

 

11.06

 

13.82

 

19.18

 

 

36.57

 

46.32

 

Underlying RC profit per ADS (dollars)

 

0.66

 

0.83

 

1.15

 

 

2.19

 

2.78

 

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

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

 

 

Top of page 2

Group headlines

Results

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

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

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

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

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

See further information on pages 3, 27 and 28.

Depreciation, depletion and amortization

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

Effective tax rate

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

Dividend

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

 

Share buybacks

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

Operating cash flow*

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

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

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

Capital expenditure*

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

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

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

Divestment and other proceeds

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

Gearing*

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

 

Brian Gilvary - Chief financial officer:

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

 

 

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

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

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

 

 

Top of page 3

Analysis of underlying RC profit* before interest and tax

 

 

Third

Second

Third

 

Nine

Nine

 

 

quarter

quarter

quarter

 

months

months

$ million

 

2019

2019

2018

 

2019

2018

Underlying RC profit before interest and tax

 

 

 

 

 

 

 

Upstream

 

2,139

 

3,413

 

3,999

 

 

8,480

 

10,664

 

Downstream

 

1,883

 

1,365

 

2,111

 

 

4,981

 

5,392

 

Rosneft

 

802

 

638

 

872

 

 

2,007

 

1,885

 

Other businesses and corporate

 

(322

)

(290

)

(345

)

 

(1,030

)

(1,214

)

Consolidation adjustment - UPII*

 

30

 

34

 

78

 

 

51

 

69

 

Underlying RC profit before interest and tax

 

4,532

 

5,160

 

6,715

 

 

14,489

 

16,796

 

Finance costs and net finance expense relating to pensions and other post-retirement benefits

 

(754

)

(752

)

(610

)

 

(2,260

)

(1,522

)

Taxation on an underlying RC basis

 

(1,506

)

(1,515

)

(2,213

)

 

(4,641

)

(5,838

)

Non-controlling interests

 

(18

)

(82

)

(54

)

 

(165

)

(190

)

Underlying RC profit attributable to BP shareholders

 

2,254

 

2,811

 

3,838

 

 

7,423

 

9,246

 

 

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

 

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

 

 

Third

Second

Third

 

Nine

Nine

 

 

quarter

quarter

quarter

 

months

months

$ million

 

2019

2019

2018

 

2019

2018

RC profit before interest and tax

 

 

 

 

 

 

 

Upstream

 

(1,050

)

2,469

 

3,472

 

 

4,303

 

10,160

 

Downstream

 

2,016

 

1,288

 

2,249

 

 

5,069

 

4,802

 

Rosneft

 

802

 

525

 

808

 

 

1,813

 

1,821

 

Other businesses and corporate

 

(412

)

(381

)

(815

)

 

(1,339

)

(2,411

)

Consolidation adjustment - UPII

 

30

 

34

 

78

 

 

51

 

69

 

RC profit before interest and tax

 

1,386

 

3,935

 

5,792

 

 

9,897

 

14,441

 

Finance costs and net finance expense relating to pensions and other post-retirement benefits

 

(899

)

(868

)

(729

)

 

(2,649

)

(1,879

)

Taxation on a RC basis

 

(820

)

(1,210

)

(1,918

)

 

(3,564

)

(5,103

)

Non-controlling interests

 

(18

)

(82

)

(54

)

 

(165

)

(190

)

RC profit (loss) attributable to BP shareholders

 

(351

)

1,775

 

3,091

 

 

3,519

 

7,269

 

Inventory holding gains (losses)*

 

(512

)

81

 

371

 

 

657

 

1,773

 

Taxation (charge) credit on inventory holding gains and losses

 

114

 

(34

)

(113

)

 

(169

)

(425

)

Profit (loss) for the period attributable to BP shareholders

 

(749

)

1,822

 

3,349

 

 

4,007

 

8,617

 

 

 

Top of page 4

Strategic progress

Upstream

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

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

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

BP announced in August that it has agreed to sell its interests in Alaska to a subsidiary of Hilcorp Energy for a total consideration of $5.6 billion. Subject to regulatory approval, the transaction is expected to complete in 2020.

 

Downstream

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

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

 

Advancing the energy transition

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

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

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

Financial framework

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

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

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

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

 

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

 

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

 

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

Safety

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

 

 

 

 

Operating metrics

 

Nine months 2019

 

Financial metrics

 

Nine months 2019

 

(vs. Nine months 2018)

 

 

(vs. Nine months 2018)

Tier 1 and tier 2 process safety events

 

73

 

Underlying RC profit*

 

$7.4bn

 

(+23)

 

 

(-$1.8bn)

Reported recordable injury frequency*

 

0.18

 

Operating cash flow excluding Gulf of Mexico oil spill payments (post-tax)(b)

 

$20.6bn

 

(-13%)

 

 

(+$1.6bn)

Group production

 

3,758mboe/d

 

Organic capital expenditure

 

$11.3bn

 

(+3.1%)

 

 

(+$0.5bn)

Upstream production (excludes Rosneft segment)

 

2,616mboe/d

 

Gulf of Mexico oil spill payments (post-tax)

 

$2.5bn

 

(+4.2%)

 

 

(-$0.5bn)

Upstream unit production costs*(a)

 

$7.02/boe

 

Divestment proceeds*

 

$1.4bn

 

(-3.5%)

 

 

(+$1.0bn)

BP-operated Upstream plant reliability*

 

94.4%

 

Gearing

 

31.7%

 

(-1.2)

 

 

(+4.6)

BP-operated refining availability*

 

94.6%

 

Dividend per ordinary share(c)

 

10.25 cents

 

(-0.2)

 

 

(-%)

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

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

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

 

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

 

 

Top of page 5

 

 

 

 

 

 

 

This page is intentionally left blank

 

 

 

 

 

 

 

 

Top of page 6

Upstream

 

 

Third

Second

Third

 

Nine

Nine

 

 

quarter

quarter

quarter

 

months

months

$ million

 

2019

2019

2018

 

2019

2018

Profit (loss) before interest and tax

 

(1,050

)

2,459

 

3,473

 

 

4,295

 

10,166

 

Inventory holding (gains) losses*

 

-

 

10

 

(1

)

 

8

 

(6

)

RC profit (loss) before interest and tax

 

(1,050

)

2,469

 

3,472

 

 

4,303

 

10,160

 

Net (favourable) adverse impact of non-operating items* and fair value accounting effects*

 

3,189

 

944

 

527

 

 

4,177

 

504

 

Underlying RC profit before interest and tax*(a)

 

2,139

 

3,413

 

3,999

 

 

8,480

 

10,664

 

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

 

Financial results

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

 

After adjusting for non-operating items and fair value accounting effects, the underlying replacement cost profit before interest and tax for the third quarter and nine months was $2,139 million and $8,480 million respectively, compared with $3,999 million and $10,664 million for the same periods in 2018. The results for the third quarter and nine months mainly reflected lower liquids and gas realizations, higher depreciation, depletion and amortization, the impact of the divestment in the Greater Kuparuk Area in Alaska, and lower production due to seasonal turnaround and maintenance activities and Hurricane Barry in the US Gulf of Mexico, partly offset by higher gas marketing and trading.

 

Production

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

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

 

Key events

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

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

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

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

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

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

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

 

Outlook

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

 

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

 

 

Top of page 7

Upstream (continued)

 

 

Third

Second

Third

 

Nine

Nine

 

 

quarter

quarter

quarter

 

months

months

$ million

 

2019

2019

2018

 

2019

2018

Underlying RC profit before interest and tax

 

 

 

 

 

 

 

US

 

552

 

861

 

1,025

 

 

2,025

 

2,293

 

Non-US

 

1,587

 

2,552

 

2,974

 

 

6,455

 

8,371

 

 

 

2,139

 

3,413

 

3,999

 

 

8,480

 

10,664

 

Non-operating items(a)

 

 

 

 

 

 

 

US

 

(3,338

)

(446

)

(149

)

 

(3,814

)

(323

)

Non-US

 

(116

)

(320

)

(93

)

 

(410

)

4

 

 

 

(3,454

)

(766

)

(242

)

 

(4,224

)

(319

)

Fair value accounting effects

 

 

 

 

 

 

 

US

 

19

 

(225

)

(10

)

 

(299

)

(162

)

Non-US

 

246

 

47

 

(275

)

 

346

 

(23

)

 

 

265

 

(178

)

(285

)

 

47

 

(185

)

RC profit (loss) before interest and tax

 

 

 

 

 

 

 

US

 

(2,767

)

190

 

866

 

 

(2,088

)

1,808

 

Non-US

 

1,717

 

2,279

 

2,606

 

 

6,391

 

8,352

 

 

 

(1,050

)

2,469

 

3,472

 

 

4,303

 

10,160

 

Exploration expense

 

 

 

 

 

 

 

US

 

53

 

69

 

39

 

 

147

 

425

 

Non-US

 

132

 

77

 

271

 

 

551

 

563

 

 

 

185

 

146

 

310

 

 

698

 

988

 

Of which: Exploration expenditure written off

 

115

 

77

 

227

 

 

476

 

734

 

Production (net of royalties)(b)

 

 

 

 

 

 

 

Liquids* (mb/d)

 

 

 

 

 

 

 

US

 

449

 

506

 

424

 

 

470

 

428

 

Europe

 

118

 

137

 

128

 

 

138

 

138

 

Rest of World

 

657

 

658

 

663

 

 

667

 

684

 

 

 

1,224

 

1,301

 

1,216

 

 

1,274

 

1,250

 

Natural gas (mmcf/d)

 

 

 

 

 

 

 

US

 

2,396

 

2,410

 

1,805

 

 

2,372

 

1,780

 

Europe

 

188

 

132

 

212

 

 

155

 

210

 

Rest of World

 

5,211

 

5,138

 

5,201

 

 

5,254

 

5,317

 

 

 

7,795

 

7,680

 

7,218

 

 

7,782

 

7,307

 

Total hydrocarbons* (mboe/d)

 

 

 

 

 

 

 

US

 

862

 

921

 

736

 

 

879

 

734

 

Europe

 

151

 

160

 

165

 

 

165

 

175

 

Rest of World

 

1,555

 

1,544

 

1,560

 

 

1,573

 

1,601

 

 

 

2,568

 

2,625

 

2,460

 

 

2,616

 

2,510

 

Average realizations*(c)

 

 

 

 

 

 

 

Total liquids(d) ($/bbl)

 

55.68

 

62.63

 

69.68

 

 

58.38

 

66.11

 

Natural gas ($/mcf)

 

3.11

 

3.35

 

3.86

 

 

3.49

 

3.77

 

Total hydrocarbons ($/boe)

 

35.48

 

40.64

 

46.14

 

 

38.55

 

43.64

 

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

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

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

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

 

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

 

 

Top of page 8

Downstream

 

 

Third

Second

Third

 

Nine

Nine

 

 

quarter

quarter

quarter

 

months

months

$ million

 

2019

2019

2018

 

2019

2018

Profit (loss) before interest and tax

 

1,583

 

1,381

 

2,592

 

 

5,775

 

6,410

 

Inventory holding (gains) losses*

 

433

 

(93

)

(343

)

 

(706

)

(1,608

)

RC profit before interest and tax

 

2,016

 

1,288

 

2,249

 

 

5,069

 

4,802

 

Net (favourable) adverse impact of non-operating items* and fair value accounting effects*

 

(133

)

77

 

(138

)

 

(88

)

590

 

Underlying RC profit before interest and tax*(a)

 

1,883

 

1,365

 

2,111

 

 

4,981

 

5,392

 

(a)       See page 9 for a reconciliation to segment RC profit before interest and tax by region and by business.

 

Financial results

The replacement cost profit before interest and tax for the third quarter and nine months was $2,016 million and $5,069 million respectively, compared with $2,249 million and $4,802 million for the same periods in 2018.

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

After adjusting for non-operating items and fair value accounting effects, the underlying replacement cost profit before interest and tax for the third quarter and nine months was $1,883 million and $4,981 million respectively, compared with $2,111 million and $5,392 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 $1,438 million for the third quarter and $3,691 million for the nine months, compared with $1,566 million and $4,018 million for the same periods in 2018. The result for the quarter and nine months reflects significantly lower refining margins, primarily driven by the impact of narrower heavy crude oil discounts, partially offset by fuels marketing growth, strong refining operations and a higher contribution from supply and trading. The result for the nine months was also impacted by higher levels of turnaround activity.

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

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

 

Lubricants

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

 

Petrochemicals

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

 

Outlook

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

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

 

 

 

Top of page 9

Downstream (continued)

 

 

Third

Second

Third

 

Nine

Nine

 

 

quarter

quarter

quarter

 

months

months

$ million

 

2019

2019

2018

 

2019

2018

Underlying RC profit before interest and tax - by region

 

 

 

 

 

 

 

US

 

537

 

566

 

835

 

 

1,634

 

1,823

 

Non-US

 

1,346

 

799

 

1,276

 

 

3,347

 

3,569

 

 

 

1,883

 

1,365

 

2,111

 

 

4,981

 

5,392

 

Non-operating items

 

 

 

 

 

 

 

US

 

(5

)

2

 

(14

)

 

(2

)

(186

)

Non-US

 

(9

)

(33

)

(23

)

 

(47

)

(129

)

 

 

(14

)

(31

)

(37

)

 

(49

)

(315

)

Fair value accounting effects(a)

 

 

 

 

 

 

 

US

 

116

 

8

 

81

 

 

185

 

(339

)

Non-US

 

31

 

(54

)

94

 

 

(48

)

64

 

 

 

147

 

(46

)

175

 

 

137

 

(275

)

RC profit before interest and tax

 

 

 

 

 

 

 

US

 

648

 

576

 

902

 

 

1,817

 

1,298

 

Non-US

 

1,368

 

712

 

1,347

 

 

3,252

 

3,504

 

 

 

2,016

 

1,288

 

2,249

 

 

5,069

 

4,802

 

Underlying RC profit before interest and tax - by business(b)(c)

 

 

 

 

 

 

 

Fuels

 

1,438

 

961

 

1,566

 

 

3,691

 

4,018

 

Lubricants

 

332

 

321

 

324

 

 

925

 

981

 

Petrochemicals

 

113

 

83

 

221

 

 

365

 

393

 

 

 

1,883

 

1,365

 

2,111

 

 

4,981

 

5,392

 

Non-operating items and fair value accounting effects(a)

 

 

 

 

 

 

 

Fuels

 

135

 

(99

)

140

 

 

73

 

(554

)

Lubricants

 

-

 

22

 

-

 

 

18

 

(29

)

Petrochemicals

 

(2

)

-

 

(2

)

 

(3

)

(7

)

 

 

133

 

(77

)

138

 

 

88

 

(590

)

RC profit before interest and tax(b)(c)

 

 

 

 

 

 

 

Fuels

 

1,573

 

862

 

1,706

 

 

3,764

 

3,464

 

Lubricants

 

332

 

343

 

324

 

 

943

 

952

 

Petrochemicals

 

111

 

83

 

219

 

 

362

 

386

 

 

 

2,016

 

1,288

 

2,249

 

 

5,069

 

4,802

 

 

 

 

 

 

 

 

 

BP average refining marker margin (RMM)* ($/bbl)

 

14.7

 

15.2

 

14.7

 

 

13.4

 

13.8

 

 

 

 

 

 

 

 

 

Refinery throughputs (mb/d)

 

 

 

 

 

 

 

US

 

781

 

673

 

740

 

 

730

 

707

 

Europe

 

815

 

715

 

805

 

 

766

 

796

 

Rest of World

 

217

 

209

 

248

 

 

221

 

242

 

 

 

1,813

 

1,597

 

1,793

 

 

1,717

 

1,745

 

BP-operated refining availability* (%)

 

96.1

 

93.4

 

96.4

 

 

94.6

 

94.8

 

 

 

 

 

 

 

 

 

Marketing sales of refined products (mb/d)

 

 

 

 

 

 

 

US

 

1,172

 

1,174

 

1,169

 

 

1,141

 

1,142

 

Europe

 

1,157

 

1,091

 

1,166

 

 

1,081

 

1,116

 

Rest of World

 

459

 

520

 

497

 

 

500

 

485

 

 

 

2,788

 

2,785

 

2,832

 

 

2,722

 

2,743

 

Trading/supply sales of refined products

 

3,157

 

3,099

 

3,147

 

 

3,183

 

3,192

 

Total sales volumes of refined products

 

5,945

 

5,884

 

5,979

 

 

5,905

 

5,935

 

 

 

 

 

 

 

 

 

Petrochemicals production (kte)

 

 

 

 

 

 

 

US

 

564

 

584

 

660

 

 

1,749

 

1,563

 

Europe

 

1,187

 

1,226

 

1,209

 

 

3,573

 

3,431

 

Rest of World

 

1,325

 

1,156

 

1,146

 

 

3,780

 

3,896

 

 

 

3,076

 

2,966

 

3,015

 

 

9,102

 

8,890

 

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

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

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

 

 

Top of page 10

Rosneft

 

 

Third

Second

Third

 

Nine

Nine

 

 

quarter

quarter

quarter

 

months

months

$ million

 

2019(a)

2019

2018

 

2019(a)

2018

Profit before interest and tax(b)(c)

 

723

 

523

 

835

 

 

1,772

 

1,980

 

Inventory holding (gains) losses*

 

79

 

2

 

(27

)

 

41

 

(159

)

RC profit before interest and tax

 

802

 

525

 

808

 

 

1,813

 

1,821

 

Net charge (credit) for non-operating items*

 

-

 

113

 

64

 

 

194

 

64

 

Underlying RC profit before interest and tax*

 

802

 

638

 

872

 

 

2,007

 

1,885

 

 

Financial results

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

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

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

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

 

 

 

Third

Second

Third

 

Nine

Nine

 

 

quarter

quarter

quarter

 

months

months

 

 

2019(a)

2019

2018

 

2019(a)

2018

Production (net of royalties) (BP share)

 

 

 

 

 

 

 

Liquids* (mb/d)

 

920

 

912

 

933

 

 

923

 

915

 

Natural gas (mmcf/d)

 

1,236

 

1,250

 

1,260

 

 

1,271

 

1,276

 

Total hydrocarbons* (mboe/d)

 

1,133

 

1,127

 

1,151

 

 

1,142

 

1,135

 

(a)       The operational and financial information of the Rosneft segment for the third quarter and nine months is based on preliminary operational and financial results of Rosneft for the three months and nine months ended 30 September 2019. Actual results may differ from these amounts.

(b)       The Rosneft segment result includes equity-accounted earnings arising from BP's 19.75% shareholding in Rosneft as adjusted for the accounting required under IFRS relating to BP's purchase of its interest in Rosneft and the amortization of the deferred gain relating to the divestment of BP's interest in TNK-BP. These adjustments increase the segment's reported profit before interest and tax, as shown in the table above, compared with the amounts reported in Rosneft's IFRS financial statements.

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

 

 

Top of page 11

Other businesses and corporate

 

 

Third

Second

Third

 

Nine

Nine

 

 

quarter

quarter

quarter

 

months

months

$ million

 

2019

2019

2018

 

2019

2018

Profit (loss) before interest and tax

 

(412

)

(381

)

(815

)

 

(1,339

)

(2,411

)

Inventory holding (gains) losses*

 

-

 

-

 

-

 

 

-

 

-

 

RC profit (loss) before interest and tax

 

(412

)

(381

)

(815

)

 

(1,339

)

(2,411

)

Net charge (credit) for non-operating items*

 

90

 

91

 

470

 

 

309

 

1,197

 

Underlying RC profit (loss) before interest and tax*

 

(322

)

(290

)

(345

)

 

(1,030

)

(1,214

)

Underlying RC profit (loss) before interest and tax

 

 

 

 

 

 

 

US

 

(249

)

(224

)

(166

)

 

(628

)

(436

)

Non-US

 

(73

)

(66

)

(179

)

 

(402

)

(778

)

 

 

(322

)

(290

)

(345

)

 

(1,030

)

(1,214

)

Non-operating items

 

 

 

 

 

 

 

US

 

(85

)

(78

)

(438

)

 

(291

)

(1,084

)

Non-US

 

(5

)

(13

)

(32

)

 

(18

)

(113

)

 

 

(90

)

(91

)

(470

)

 

(309

)

(1,197

)

RC profit (loss) before interest and tax

 

 

 

 

 

 

 

US

 

(334

)

(302

)

(604

)

 

(919

)

(1,520

)

Non-US

 

(78

)

(79

)

(211

)

 

(420

)

(891

)

 

 

(412

)

(381

)

(815

)

 

(1,339

)

(2,411

)

Other businesses and corporate comprises our alternative energy business, shipping, treasury, BP ventures and corporate activities including centralized functions, and any residual costs of the Gulf of Mexico oil spill.

Financial results

The replacement cost loss before interest and tax for the third quarter and nine months was $412 million and $1,339 million respectively, compared with $815 million and $2,411 million for the same periods in 2018.

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

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

 

Alternative Energy

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

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

 

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

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

 

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

 

Outlook

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

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

 

 

Top of page 12

Financial statements

Group income statement

 

 

Third

Second

Third

 

Nine

Nine

 

 

quarter

quarter

quarter

 

months

months

$ million

 

2019

2019

2018

 

2019

2018

 

 

 

 

 

 

 

 

Sales and other operating revenues (Note 5)

 

68,291

 

72,676

 

79,468

 

 

207,288

 

223,079

 

Earnings from joint ventures - after interest and tax

 

90

 

138

 

148

 

 

413

 

661

 

Earnings from associates - after interest and tax

 

784

 

608

 

990

 

 

2,041

 

2,431

 

Interest and other income

 

126

 

270

 

154

 

 

559

 

478

 

Gains on sale of businesses and fixed assets

 

1

 

55

 

43

 

 

145

 

204

 

Total revenues and other income

 

69,292

 

73,747

 

80,803

 

 

210,446

 

226,853

 

Purchases

 

52,273

 

55,683

 

60,923

 

 

156,228

 

170,859

 

Production and manufacturing expenses

 

5,259

 

5,391

 

5,879

 

 

16,006

 

16,832

 

Production and similar taxes (Note 7)

 

340

 

371

 

451

 

 

1,135

 

1,350

 

Depreciation, depletion and amortization (Note 6)

 

4,297

 

4,588

 

3,728

 

 

13,346

 

11,470

 

Impairment and losses on sale of businesses and fixed assets (Note 3)

 

3,416

 

906

 

548

 

 

4,418

 

616

 

Exploration expense

 

185

 

146

 

310

 

 

698

 

988

 

Distribution and administration expenses

 

2,648

 

2,646

 

2,801

 

 

8,061

 

8,524

 

Profit (loss) before interest and taxation

 

874

 

4,016

 

6,163

 

 

10,554

 

16,214

 

Finance costs

 

883

 

853

 

698

 

 

2,603

 

1,786

 

Net finance expense relating to pensions and other post-retirement benefits

 

16

 

15

 

31

 

 

46

 

93

 

Profit (loss) before taxation

 

(25

)

3,148

 

5,434

 

 

7,905

 

14,335

 

Taxation

 

706

 

1,244

 

2,031

 

 

3,733

 

5,528

 

Profit (loss) for the period

 

(731

)

1,904

 

3,403

 

 

4,172

 

8,807

 

Attributable to

 

 

 

 

 

 

 

BP shareholders

 

(749

)

1,822

 

3,349

 

 

4,007

 

8,617

 

Non-controlling interests

 

18

 

82

 

54

 

 

165

 

190

 

 

 

(731

)

1,904

 

3,403

 

 

4,172

 

8,807

 

 

 

 

 

 

 

 

 

Earnings per share (Note 8)

 

 

 

 

 

 

 

Profit (loss) for the period attributable to BP shareholders

 

 

 

 

 

 

 

Per ordinary share (cents)

 

 

 

 

 

 

 

Basic

 

(3.68

)

8.95

 

16.74

 

 

19.74

 

43.17

 

Diluted

 

(3.68

)

8.92

 

16.65

 

 

19.63

 

42.91

 

Per ADS (dollars)

 

 

 

 

 

 

 

Basic

 

(0.22

)

0.54

 

1.00

 

 

1.18

 

2.59

 

Diluted

 

(0.22

)

0.54

 

1.00

 

 

1.18

 

2.57

 

 

 

Top of page 13

Condensed group statement of comprehensive income

 

 

Third

Second

Third

 

Nine

Nine

 

 

quarter

quarter

quarter

 

months

months

$ million

 

2019

2019

2018

 

2019

2018

 

 

 

 

 

 

 

 

Profit (loss) for the period

 

(731

)

1,904

 

3,403

 

 

4,172

 

8,807

 

Other comprehensive income

 

 

 

 

 

 

 

Items that may be reclassified subsequently to profit or loss

 

 

 

 

 

 

 

Currency translation differences

 

(986

)

131

 

(753

)

 

134

 

(2,834

)

Cash flow hedges and costs of hedging

 

(17

)

133

 

65

 

 

135

 

(124

)

Share of items relating to equity-accounted entities, net of tax

 

119

 

(30

)

95

 

 

39

 

217

 

Income tax relating to items that may be reclassified

 

12

 

(9

)

9

 

 

(31

)

(29

)

 

 

(872

)

225

 

(584

)

 

277

 

(2,770

)

Items that will not be reclassified to profit or loss

 

 

 

 

 

 

 

Remeasurements of the net pension and other post-retirement benefit liability or asset

 

(260

)

(39

)

389

 

 

(1,152

)

2,968

 

Cash flow hedges that will subsequently be transferred to the balance sheet

 

(10

)

(7

)

(7

)

 

(9

)

(29

)

Income tax relating to items that will not be reclassified

 

27

 

2

 

(119

)

 

302

 

(941

)

 

 

(243

)

(44

)

263

 

 

(859

)

1,998

 

Other comprehensive income

 

(1,115

)

181

 

(321

)

 

(582

)

(772

)

Total comprehensive income

 

(1,846

)

2,085

 

3,082

 

 

3,590

 

8,035

 

Attributable to

 

 

 

 

 

 

 

BP shareholders

 

(1,848

)

2,001

 

3,040

 

 

3,434

 

7,888

 

Non-controlling interests

 

2

 

84

 

42

 

 

156

 

147

 

 

 

(1,846

)

2,085

 

3,082

 

 

3,590

 

8,035

 

 

 

Top of page 14

Condensed group statement of changes in equity

 

 

BP shareholders'

Non-controlling

Total

$ million

 

equity

interests

equity

At 31 December 2018

 

99,444

 

2,104

 

101,548

 

Adjustment on adoption of IFRS 16, net of tax(a)

 

(329

)

(1

)

(330

)

At 1 January 2019

 

99,115

 

2,103

 

101,218

 

 

 

 

 

 

Total comprehensive income

 

3,434

 

156

 

3,590

 

Dividends

 

(4,857

)

(166

)

(5,023

)

Cash flow hedges transferred to the balance sheet, net of tax

 

18

 

-

 

18

 

Repurchase of ordinary share capital

 

(340

)

-

 

(340

)

Share-based payments, net of tax

 

544

 

-

 

544

 

Share of equity-accounted entities' changes in equity, net of tax

 

8

 

-

 

8

 

At 30 September 2019

 

97,922

 

2,093

 

100,015

 

 

 

 

 

 

 

 

BP shareholders'

Non-controlling

Total

$ million

 

equity

interests

equity

At 31 December 2017

 

98,491

 

1,913

 

100,404

 

Adjustment on adoption of IFRS 9, net of tax(b)

 

(180

)

-

 

(180

)

At 1 January 2018

 

98,311

 

1,913

 

100,224

 

 

 

 

 

 

Total comprehensive income

 

7,888

 

147

 

8,035

 

Dividends

 

(4,965

)

(129

)

(5,094

)

Cash flow hedges transferred to the balance sheet, net of tax

 

17

 

-

 

17

 

Repurchase of ordinary share capital

 

(339

)

-

 

(339

)

Share-based payments, net of tax

 

582

 

-

 

582

 

Share of equity-accounted entities' changes in equity, net of tax

 

(6

)

-

 

(6

)

Transactions involving non-controlling interests, net of tax

 

-

 

1

 

1

 

At 30 September 2018

 

101,488

 

1,932

 

103,420

 

(a)            See Note 1 for further information.

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

 

 

Top of page 15

Group balance sheet

 

 

30 September

31 December

$ million

 

2019

2018(a)

Non-current assets

 

 

 

Property, plant and equipment

 

134,661

 

135,261

 

Goodwill

 

11,712

 

12,204

 

Intangible assets

 

15,084

 

17,284

 

Investments in joint ventures

 

8,678

 

8,647

 

Investments in associates

 

19,492

 

17,673

 

Other investments

 

1,248

 

1,341

 

Fixed assets

 

190,875

 

192,410

 

Loans

 

642

 

637

 

Trade and other receivables

 

2,054

 

1,834

 

Derivative financial instruments

 

5,829

 

5,145

 

Prepayments

 

789

 

1,179

 

Deferred tax assets

 

4,195

 

3,706

 

Defined benefit pension plan surpluses

 

5,972

 

5,955

 

 

 

210,356

 

210,866

 

Current assets

 

 

 

Loans

 

350

 

326

 

Inventories

 

19,240

 

17,988

 

Trade and other receivables

 

22,788

 

24,478

 

Derivative financial instruments

 

3,346

 

3,846

 

Prepayments

 

1,138

 

963

 

Current tax receivable

 

1,090

 

1,019

 

Other investments

 

114

 

222

 

Cash and cash equivalents

 

19,692

 

22,468

 

 

 

67,758

 

71,310

 

Assets classified as held for sale (Note 2)

 

8,149

 

-

 

 

 

75,907

 

71,310

 

Total assets

 

286,263

 

282,176

 

Current liabilities

 

 

 

Trade and other payables

 

43,203

 

46,265

 

Derivative financial instruments

 

2,527

 

3,308

 

Accruals

 

4,569

 

4,626

 

Lease liabilities

 

2,012

 

44

 

Finance debt

 

7,556

 

9,329

 

Current tax payable

 

1,805

 

2,101

 

Provisions

 

2,189

 

2,564

 

 

 

63,861

 

68,237

 

Liabilities directly associated with assets classified as held for sale (Note 2)

 

1,107

 

-

 

 

 

64,968

 

68,237

 

Non-current liabilities

 

 

 

Other payables

 

12,550

 

13,830

 

Derivative financial instruments

 

5,694

 

5,625

 

Accruals

 

612

 

575

 

Lease liabilities

 

7,627

 

623

 

Finance debt

 

58,311

 

55,803

 

Deferred tax liabilities

 

9,715

 

9,812

 

Provisions

 

17,487

 

17,732

 

Defined benefit pension plan and other post-retirement benefit plan deficits

 

9,284

 

8,391

 

 

 

121,280

 

112,391

 

Total liabilities

 

186,248

 

180,628

 

Net assets

 

100,015

 

101,548

 

Equity

 

 

 

BP shareholders' equity

 

97,922

 

99,444

 

Non-controlling interests

 

2,093

 

2,104

 

Total equity

 

100,015

 

101,548

 

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

 

 

Top of page 16

Condensed group cash flow statement

 

 

Third

Second

Third

 

Nine

Nine

 

 

quarter

quarter

quarter

 

months

months

$ million

 

2019

2019

2018

 

2019

2018

Operating activities

 

 

Profit (loss) before taxation

 

(25

)

3,148

 

5,434

 

 

7,905

 

14,335

 

Adjustments to reconcile profit (loss) before taxation to net cash provided by operating activities

 

 

 

 

 

 

 

Depreciation, depletion and amortization and exploration expenditure written off

 

4,412

 

4,665

 

3,955

 

 

13,822

 

12,204

 

Impairment and (gain) loss on sale of businesses and fixed assets

 

3,415

 

851

 

505

 

 

4,273

 

412

 

Earnings from equity-accounted entities, less dividends received

 

(236

)

(395

)

(664

)

 

(1,220

)

(2,188

)

Net charge for interest and other finance expense, less net interest paid

 

257

 

62

 

114

 

 

407

 

385

 

Share-based payments

 

149

 

117

 

160

 

 

563

 

564

 

Net operating charge for pensions and other post-retirement benefits, less contributions and benefit payments for unfunded plans

 

(50

)

(68

)

(62

)

 

(195

)

(326

)

Net charge for provisions, less payments

 

(132

)

(198

)

145

 

 

(446

)

369

 

Movements in inventories and other current and non-current assets and liabilities

 

141

 

(58

)

(1,573

)

 

(2,612

)

(5,541

)

Income taxes paid

 

(1,875

)

(1,309

)

(1,922

)

 

(4,330

)

(4,170

)

Net cash provided by operating activities

 

6,056

 

6,815

 

6,092

 

 

18,167

 

16,044

 

Investing activities

 

 

 

 

 

 

 

Expenditure on property, plant and equipment, intangible and other assets

 

(3,954

)

(3,833

)

(3,675

)

 

(11,482

)

(10,745

)

Acquisitions, net of cash acquired

 

13

 

(1,747

)

(606

)

 

(3,529

)

(607

)

Investment in joint ventures

 

(60

)

(20

)

(35

)

 

(80

)

(92

)

Investment in associates

 

(22

)

(54

)

(88

)

 

(221

)

(748

)

Total cash capital expenditure

 

(4,023

)

(5,654

)

(4,404

)

 

(15,312

)

(12,192

)

Proceeds from disposal of fixed assets

 

171

 

70

 

90

 

 

476

 

280

 

Proceeds from disposal of businesses, net of cash disposed

 

536

 

8

 

26

 

 

909

 

153

 

Proceeds from loan repayments

 

63

 

64

 

14

 

 

182

 

47

 

Net cash used in investing activities

 

(3,253

)

(5,512

)

(4,274

)

 

(13,745

)

(11,712

)

Financing activities(a)

 

 

 

 

 

 

 

Net issue (repurchase) of shares

 

(215

)

(80

)

(139

)

 

(340

)

(339

)

Lease liability payments

 

(594

)

(595

)

-

 

 

(1,806

)

(14

)

Proceeds from long-term financing

 

213

 

4,381

 

5,888

 

 

6,718

 

6,920

 

Repayments of long-term financing

 

(516

)

(3,602

)

(2,521

)

 

(6,758

)

(5,390

)

Net increase (decrease) in short-term debt

 

(852

)

(119

)

485

 

 

118

 

428

 

Net increase (decrease) in non-controlling interests

 

-

 

-

 

1

 

 

-

 

-

 

Dividends paid - BP shareholders

 

(1,656

)

(1,779

)

(1,410

)

 

(4,870

)

(4,966

)

 - non-controlling interests

 

(47

)

(83

)

(59

)

 

(166

)

(129

)

Net cash provided by (used in) financing activities

 

(3,667

)

(1,877

)

2,245

 

 

(7,104

)

(3,490

)

Currency translation differences relating to cash and cash equivalents

 

(118

)

(8

)

(56

)

 

(94

)

(225

)

Increase (decrease) in cash and cash equivalents

 

(982

)

(582

)

4,007

 

 

(2,776

)

617

 

Cash and cash equivalents at beginning of period

 

20,674

 

21,256

 

22,185

 

 

22,468

 

25,575

 

Cash and cash equivalents at end of period

 

19,692

 

20,674

 

26,192

 

 

19,692

 

26,192

 

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

 

 

Top of page 17

Notes

Note 1. Basis of preparation

 

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

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

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

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

 

New International Financial Reporting Standards adopted

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

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

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

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

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

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

 

 

Top of page 18

Note 1. Basis of preparation (continued)

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

 

 

 

 

Adjustment

 

 

31 December

1 January

on adoption

$ million

 

2018

2019

of IFRS 16

Non-current assets

 

 

 

 

Property, plant and equipment

 

135,261

 

143,950

 

8,689

 

Trade and other receivables

 

1,834

 

2,159

 

325

 

Prepayments

 

1,179

 

849

 

(330

)

Deferred tax assets

 

3,706

 

3,736

 

30

 

Current assets

 

 

 

 

Trade and other receivables

 

24,478

 

24,673

 

195

 

Prepayments

 

963

 

872

 

(91

)

Current liabilities

 

 

 

 

Trade and other payables

 

46,265

 

46,209

 

(56

)

Accruals

 

4,626

 

4,578

 

(48

)

Lease liabilities

 

44

 

2,196

 

2,152

 

Finance debt

 

9,329

 

9,329

 

-

 

Provisions

 

2,564

 

2,547

 

(17

)

Non-current liabilities

 

 

 

 

Other payables

 

13,830

 

14,013

 

183

 

Accruals

 

575

 

548

 

(27

)

Lease liabilities

 

623

 

7,704

 

7,081

 

Finance debt

 

55,803

 

55,803

 

-

 

Deferred tax liabilities

 

9,812

 

9,767

 

(45

)

Provisions

 

17,732

 

17,657

 

(75

)

 

 

 

 

 

Net assets

 

101,548

 

101,218

 

(330

)

 

 

 

 

 

Equity

 

 

 

 

BP shareholders' equity

 

99,444

 

99,115

 

(329

)

Non-controlling interests

 

2,104

 

2,103

 

(1

)

 

 

101,548

 

101,218

 

(330

)

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

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

$ million

 

 

Operating lease commitments at 31 December 2018

 

11,979

 

 

 

 

Leases not yet commenced

 

(1,372

)

Leases below materiality threshold

 

(86

)

Short-term leases

 

(91

)

Effect of discounting

 

(1,512

)

Impact on leases in joint operations

 

836

 

Variable lease payments

 

(58

)

Redetermination of lease term

 

(252

)

Other

 

(22

)

Total additional lease liabilities recognized on adoption of IFRS 16

 

9,422

 

Finance lease obligations at 31 December 2018

 

667

 

Adjustment for finance leases in joint operations

 

(189

)

Total lease liabilities at 1 January 2019

 

9,900

 

 

 

Top of page 19

Note 1. Basis of preparation (continued)

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

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

$ million

 

 

Total additional lease liabilities recognized on adoption of IFRS 16

 

9,422

 

Less: adjustment for finance leases in joint operations

 

(189

)

Total adjustment to lease liabilities

 

9,233

 

Of which  - current

 

2,152

 

- non-current

 

7,081

 

 

IFRIC agenda decision on IFRS 9 'Financial Instruments'

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

 

 

Note 2. Non-current assets held for sale

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

Upstream

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

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

Other businesses and corporate

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

 

 

Top of page 20

Note 3. Impairments

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

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

 

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

 

 

Third

Second

Third

 

Nine

Nine

 

 

quarter

quarter

quarter

 

months

months

$ million

 

2019

2019

2018

 

2019

2018

Upstream

 

(1,050

)

2,469

 

3,472

 

 

4,303

 

10,160

 

Downstream

 

2,016

 

1,288

 

2,249

 

 

5,069

 

4,802

 

Rosneft

 

802

 

525

 

808

 

 

1,813

 

1,821

 

Other businesses and corporate

 

(412

)

(381

)

(815

)

 

(1,339

)

(2,411

)

 

 

1,356

 

3,901

 

5,714

 

 

9,846

 

14,372

 

Consolidation adjustment - UPII*

 

30

 

34

 

78

 

 

51

 

69

 

RC profit (loss) before interest and tax*

 

1,386

 

3,935

 

5,792

 

 

9,897

 

14,441

 

Inventory holding gains (losses)*

 

 

 

 

 

 

 

Upstream

 

-

 

(10

)

1

 

 

(8

)

6

 

Downstream

 

(433

)

93

 

343

 

 

706

 

1,608

 

Rosneft (net of tax)

 

(79

)

(2

)

27

 

 

(41

)

159

 

Profit (loss) before interest and tax

 

874

 

4,016

 

6,163

 

 

10,554

 

16,214

 

Finance costs

 

883

 

853

 

698

 

 

2,603

 

1,786

 

Net finance expense relating to pensions and other post-retirement benefits

 

16

 

15

 

31

 

 

46

 

93

 

Profit (loss) before taxation

 

(25

)

3,148

 

5,434

 

 

7,905

 

14,335

 

 

 

 

 

 

 

 

 

RC profit (loss) before interest and tax*

 

 

 

 

 

 

 

US

 

(2,425

)

498

 

1,215

 

 

(1,156

)

1,554

 

Non-US

 

3,811

 

3,437

 

4,577

 

 

11,053

 

12,887

 

 

 

1,386

 

3,935

 

5,792

 

 

9,897

 

14,441

 

 

 

 

Top of page 21

Note 5. Sales and other operating revenues

 

 

Third

Second

Third

 

Nine

Nine

 

 

quarter

quarter

quarter

 

months

months

$ million

 

2019

2019

2018

 

2019

2018

By segment

 

 

 

 

 

 

 

Upstream

 

12,396

 

13,556

 

14,781

 

 

40,546

 

41,349

 

Downstream

 

61,834

 

66,396

 

72,376

 

 

186,646

 

202,956

 

Other businesses and corporate

 

461

 

433

 

423

 

 

1,250

 

1,142

 

 

 

74,691

 

80,385

 

87,580

 

 

228,442

 

245,447

 

 

 

 

 

 

 

 

 

Less: sales and other operating revenues between segments

 

 

 

 

 

 

 

Upstream

 

6,406

 

7,481

 

7,368

 

 

20,211

 

19,896

 

Downstream

 

(59

)

62

 

539

 

 

589

 

1,806

 

Other businesses and corporate

 

53

 

166

 

205

 

 

354

 

666

 

 

 

6,400

 

7,709

 

8,112

 

 

21,154

 

22,368

 

 

 

 

 

 

 

 

 

Third party sales and other operating revenues

 

 

 

 

 

 

 

Upstream

 

5,990

 

6,075

 

7,413

 

 

20,335

 

21,453

 

Downstream

 

61,893

 

66,334

 

71,837

 

 

186,057

 

201,150

 

Other businesses and corporate

 

408

 

267

 

218

 

 

896

 

476

 

Total sales and other operating revenues

 

68,291

 

72,676

 

79,468

 

 

207,288

 

223,079

 

 

 

 

 

 

 

 

 

By geographical area

 

 

 

 

 

 

 

US

 

23,413

 

26,086

 

27,580

 

 

71,347

 

77,869

 

Non-US

 

51,030

 

52,933

 

58,869

 

 

153,581

 

166,141

 

 

 

74,443

 

79,019

 

86,449

 

 

224,928

 

244,010

 

Less: sales and other operating revenues between areas

 

6,152

 

6,343

 

6,981

 

 

17,640

 

20,931

 

 

 

68,291

 

72,676

 

79,468

 

 

207,288

 

223,079

 

 

 

 

 

 

 

 

 

Revenues from contracts with customers

 

 

 

 

 

 

 

Sales and other operating revenues include the following in relation to revenues from contracts with customers:

 

 

 

 

 

 

 

Crude oil

 

14,502

 

17,070

 

17,744

 

 

45,854

 

49,828

 

Oil products

 

44,667

 

46,999

 

52,049

 

 

134,249

 

147,619

 

Natural gas, LNG and NGLs

 

4,465

 

4,823

 

5,764

 

 

15,081

 

15,883

 

Non-oil products and other revenues from contracts with customers

 

3,300

 

3,173

 

3,574

 

 

9,974

 

10,150

 

 

 

66,934

 

72,065

 

79,131

 

 

205,158

 

223,480

 

 

 

Note 6. Depreciation, depletion and amortization

 

 

Third

Second

Third

 

Nine

Nine

 

 

quarter

quarter

quarter

 

months

months

$ million

 

2019

2019

2018

 

2019

2018

Upstream

 

 

 

 

 

 

 

US

 

1,121

 

1,288

 

987

 

 

3,522

 

3,074

 

Non-US

 

2,295

 

2,396

 

2,167

 

 

7,189

 

6,665

 

 

 

3,416

 

3,684

 

3,154

 

 

10,711

 

9,739

 

Downstream

 

 

 

 

 

 

 

US

 

336

 

333

 

220

 

 

992

 

660

 

Non-US

 

394

 

392

 

284

 

 

1,169

 

879

 

 

 

730

 

725

 

504

 

 

2,161

 

1,539

 

Other businesses and corporate

 

 

 

 

 

 

 

US

 

14

 

14

 

16

 

 

41

 

48

 

Non-US

 

137

 

165

 

54

 

 

433

 

144

 

 

 

151

 

179

 

70

 

 

474

 

192

 

Total group

 

4,297

 

4,588

 

3,728

 

 

13,346

 

11,470

 

 

 

Top of page 22

Note 7. Production and similar taxes

 

 

Third

Second

Third

 

Nine

Nine

 

 

quarter

quarter

quarter

 

months

months

$ million

 

2019

2019

2018

 

2019

2018

US

 

66

 

79

 

91

 

 

226

 

270

 

Non-US

 

274

 

292

 

360

 

 

909

 

1,080

 

 

 

340

 

371

 

451

 

 

1,135

 

1,350

 

 

Note 8. Earnings per share and shares in issue

 

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

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

For the diluted EpS calculation the weighted average number of shares outstanding during the period is adjusted for the number of shares that are potentially issuable in connection with employee share-based payment plans using the treasury stock method.

 

 

Third

Second

Third

 

Nine

Nine

 

 

quarter

quarter

quarter

 

months

months

$ million

 

2019

2019

2018

 

2019

2018

Results for the period

 

 

 

 

 

 

 

Profit (loss) for the period attributable to BP shareholders

 

(749

)

1,822

 

3,349

 

 

4,007

 

8,617

 

Less: preference dividend

 

-

 

1

 

-

 

 

1

 

1

 

Profit (loss) attributable to BP ordinary shareholders

 

(749

)

1,821

 

3,349

 

 

4,006

 

8,616

 

 

 

 

 

 

 

 

 

Number of shares (thousand)(a)(b)

 

 

 

 

 

 

 

Basic weighted average number of shares outstanding

 

20,371,728

 

20,336,347

 

20,006,872

 

 

20,295,078

 

19,957,265

 

ADS equivalent

 

3,395,288

 

3,389,391

 

3,334,478

 

 

3,382,513

 

3,326,210

 

 

 

 

 

 

 

 

 

Weighted average number of shares outstanding used to calculate diluted earnings per share

 

20,371,728

 

20,421,184

 

20,118,456

 

 

20,411,739

 

20,081,256

 

ADS equivalent

 

3,395,288

 

3,403,530

 

3,353,076

 

 

3,401,957

 

3,346,876

 

 

 

 

 

 

 

 

 

Shares in issue at period-end

 

20,417,220

 

20,373,332

 

20,050,414

 

 

20,417,220

 

20,050,414

 

ADS equivalent

 

3,402,870

 

3,395,555

 

3,341,735

 

 

3,402,870

 

3,341,735

 

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

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

          

 

 

Top of page 23

Note 9. Dividends

Dividends payable

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

 

 

 

Third

Second

Third

 

Nine

Nine

 

 

quarter

quarter

quarter

 

months

months

 

 

2019

2019

2018

 

2019

2018

Dividends paid per ordinary share

 

 

 

 

 

 

 

cents

 

10.250

 

10.250

 

10.250

 

 

30.750

 

30.250

 

pence

 

8.348

 

8.066

 

7.930

 

 

24.152

 

22.543

 

Dividends paid per ADS (cents)

 

61.50

 

61.50

 

61.50

 

 

184.50

 

181.50

 

Scrip dividends

 

 

 

 

 

 

 

Number of shares issued (millions)

 

72.5

 

46.3

 

89.9

 

 

208.9

 

147.8

 

Value of shares issued ($ million)

 

440

 

318

 

638

 

 

1,387

 

1,059

 

 

Note 10. Net debt and net debt including leases

Net debt*

 

Third

Second

Third

 

Nine

Nine

 

 

quarter

quarter

quarter

 

months

months

$ million

 

2019

2019

2018

 

2019

2018

Finance debt(a)

 

65,867

 

67,553

 

63,460

 

 

65,867

 

63,460

 

Fair value (asset) liability of hedges related to finance debt(b)

 

319

 

(378

)

1,234

 

 

319

 

1,234

 

 

 

66,186

 

67,175

 

64,694

 

 

66,186

 

64,694

 

Less: cash and cash equivalents

 

19,692

 

20,674

 

26,192

 

 

19,692

 

26,192

 

Net debt

 

46,494

 

46,501

 

38,502

 

 

46,494

 

38,502

 

Equity

 

100,015

 

103,623

 

103,420

 

 

100,015

 

103,420

 

Gearing*

 

31.7%

31.0%

27.1%

 

31.7%

27.1%

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

(b)       Derivative financial instruments entered into for the purpose of managing interest rate and foreign currency exchange risk associated with net debt with a fair value liability position of $682 million (second quarter 2019 liability of $563 million and third quarter 2018 liability of $723 million) are not included in the calculation of net debt shown above as hedge accounting is not applied for these instruments.

 

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

Net debt including leases*

 

Third

Second

Third

 

Nine

Nine

 

 

quarter

quarter

quarter

 

months

months

$ million

 

2019

2019

2018

 

2019

2018

Net debt

 

46,494

 

46,501

 

38,502

 

 

46,494

 

38,502

 

Lease liabilities

 

9,639

 

10,379

 

675

 

 

9,639

 

675

 

Net partner (receivable) payable for leases entered into on behalf of joint operations

 

(197

)

(230

)

-

 

 

(197

)

-

 

Net debt including leases

 

55,936

 

56,650

 

39,177

 

 

55,936

 

39,177

 

 

 

Top of page 24

Note 11. Inventory valuation

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

 

Note 12. Statutory accounts

The financial information shown in this publication, which was approved by the Board of Directors on 28 October 2019, is unaudited and does not constitute statutory financial statements. Audited financial information will be published in BP Annual Report and Form 20-F 2019. BP Annual Report and Form 20-F 2018 has been filed with the Registrar of Companies in England and Wales. The report of the auditor on those accounts was unqualified, did not include a reference to any matters to which the auditor drew attention by way of emphasis without qualifying the report and did not contain a statement under section 498(2) or section 498(3) of the UK Companies Act 2006.

 

 

Top of page 25

Additional information

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

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

Balance sheet

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

 

 

30 September

31 December

$ billion

 

2019

2018

Property, plant and equipment(a) (b)

 

9.0

 

0.5

 

Lease liabilities(a)

 

9.6

 

0.7

 

Finance debt

 

65.9

 

65.1

 

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

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

 

Income statement

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

Cash flow statement

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

 

 

Third

Second

Third

 

Nine

Nine

 

 

quarter

quarter

quarter

 

months

months

$ billion

 

2019

2019

2018

 

2019

2018

Financing activities

 

 

 

 

 

 

 

Lease liability payments(a)

 

(0.6

)

(0.6

)

-

 

 

(1.8

)

-

 

                         

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

 

 

Top of page 26

Capital expenditure*

 

 

Third

Second

Third

 

Nine

Nine

 

 

quarter

quarter

quarter

 

months

months

$ million

 

2019

2019

2018

 

2019

2018

Capital expenditure on a cash basis

 

 

 

 

 

 

 

Organic capital expenditure*

 

3,946

 

3,686

 

3,730

 

 

11,280

 

10,738

 

Inorganic capital expenditure*(a)

 

77

 

1,968

 

674

 

 

4,032

 

1,454

 

 

 

4,023

 

5,654

 

4,404

 

 

15,312

 

12,192

 

 

 

 

Third

Second

Third

 

Nine

Nine

 

 

quarter

quarter

quarter

 

months

months

$ million

 

2019

2019

2018

 

2019

2018

Organic capital expenditure by segment

 

 

 

 

 

 

 

Upstream

 

 

 

 

 

 

 

US

 

1,036

 

972

 

854

 

 

2,990

 

2,434

 

Non-US

 

2,110

 

1,858

 

2,073

 

 

5,856

 

6,126

 

 

 

3,146

 

2,830

 

2,927

 

 

8,846

 

8,560

 

Downstream

 

 

 

 

 

 

 

US

 

197

 

271

 

237

 

 

655

 

640

 

Non-US

 

558

 

470

 

513

 

 

1,562

 

1,342

 

 

 

755

 

741

 

750

 

 

2,217

 

1,982

 

Other businesses and corporate

 

 

 

 

 

 

 

US

 

8

 

15

 

6

 

 

32

 

20

 

Non-US

 

37

 

100

 

47

 

 

185

 

176

 

 

 

45

 

115

 

53

 

 

217

 

196

 

 

 

3,946

 

3,686

 

3,730

 

 

11,280

 

10,738

 

Organic capital expenditure by geographical area

 

 

 

 

 

 

 

US

 

1,241

 

1,258

 

1,097

 

 

3,677

 

3,094

 

Non-US

 

2,705

 

2,428

 

2,633

 

 

7,603

 

7,644

 

 

 

3,946

 

3,686

 

3,730

 

 

11,280

 

10,738

 

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

 

 

Top of page 27

Non-operating items*

 

 

Third

Second

Third

 

Nine

Nine

 

 

quarter

quarter

quarter

 

months

months

$ million

 

2019

2019

2018(a)

 

2019

2018(a)

Upstream

 

 

 

 

 

 

 

Impairment and gain (loss) on sale of businesses and fixed assets(b)

 

(3,406

)

(796

)

(231

)

 

(4,213

)

(124

)

Environmental and other provisions

 

-

 

-

 

-

 

 

-

 

-

 

Restructuring, integration and rationalization costs

 

(24

)

(17

)

(17

)

 

(76

)

(78

)

Fair value gain (loss) on embedded derivatives

 

-

 

-

 

1

 

 

-

 

17

 

Other

 

(24

)

47

 

5

 

 

65

 

(134

)

 

 

(3,454

)

(766

)

(242

)

 

(4,224

)

(319

)

Downstream

 

 

 

 

 

 

 

Impairment and gain (loss) on sale of businesses and fixed assets

 

(9

)

(51

)

(19

)

 

(56

)

(34

)

Environmental and other provisions

 

(1

)

-

 

-

 

 

(1

)

-

 

Restructuring, integration and rationalization costs

 

(4

)

20

 

(16

)

 

14

 

(126

)

Fair value gain (loss) on embedded derivatives

 

-

 

-

 

-

 

 

-

 

-

 

Other

 

-

 

-

 

(2

)

 

(6

)

(155

)

 

 

(14

)

(31

)

(37

)

 

(49

)

(315

)

Rosneft

 

 

 

 

 

 

 

Impairment and gain (loss) on sale of businesses and fixed assets

 

-

 

(113

)

(64

)

 

(194

)

(64

)

Environmental and other provisions

 

-

 

-

 

-

 

 

-

 

-

 

Restructuring, integration and rationalization costs

 

-

 

-

 

-

 

 

-

 

-

 

Fair value gain (loss) on embedded derivatives

 

-

 

-

 

-

 

 

-

 

-

 

Other

 

-

 

-

 

-

 

 

-

 

-

 

 

 

-

 

(113

)

(64

)

 

(194

)

(64

)

Other businesses and corporate

 

 

 

 

 

 

 

Impairment and gain (loss) on sale of businesses and fixed assets

 

-

 

(4

)

(255

)

 

(4

)

(254

)

Environmental and other provisions

 

-

 

(22

)

(45

)

 

(28

)

(65

)

Restructuring, integration and rationalization costs

 

-

 

(3

)

(33

)

 

7

 

(78

)

Fair value gain (loss) on embedded derivatives

 

-

 

-

 

-

 

 

-

 

-

 

Gulf of Mexico oil spill

 

(84

)

(57

)

(128

)

 

(256

)

(647

)

Other

 

(6

)

(5

)

(9

)

 

(28

)

(153

)

 

 

(90

)

(91

)

(470

)

 

(309

)

(1,197

)

Total before interest and taxation

 

(3,558

)

(1,001

)

(813

)

 

(4,776

)

(1,895

)

Finance costs(c)

 

(145

)

(116

)

(119

)

 

(389

)

(357

)

Total before taxation

 

(3,703

)

(1,117

)

(932

)

 

(5,165

)

(2,252

)

Taxation credit (charge) on non-operating items

 

772

 

256

 

283

 

 

1,121

 

633

 

Total after taxation for period

 

(2,931

)

(861

)

(649

)

 

(4,044

)

(1,619

)

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

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

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

 

 

Top of page 28

Non-GAAP information on fair value accounting effects

 

 

Third

Second

Third

 

Nine

Nine

 

 

quarter

quarter

quarter

 

months

months

$ million

 

2019

2019

2018

 

2019

2018

Favourable (adverse) impact relative to management's measure of performance

 

 

 

 

 

 

 

Upstream

 

265

 

(178

)

(285

)

 

47

 

(185

)

Downstream

 

147

 

(46

)

175

 

 

137

 

(275

)

 

 

412

 

(224

)

(110

)

 

184

 

(460

)

Taxation credit (charge)

 

(86

)

49

 

12

 

 

(44

)

102

 

 

 

326

 

(175

)

(98

)

 

140

 

(358

)

 

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

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

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

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

The way that BP manages the economic exposures described above, and measures performance internally, differs from the way these activities are measured under IFRS. BP calculates this difference for consolidated entities by comparing the IFRS result with management's internal measure of performance. Under management's internal measure of performance the inventory, transportation and capacity contracts in question are valued based on fair value using relevant forward prices prevailing at the end of the period. The fair values of derivative instruments used to risk manage certain oil, gas and other contracts, are deferred to match with the underlying exposure and the commodity contracts for business requirements are accounted for on an accruals basis. We believe that disclosing management's estimate of this difference provides useful information for investors because it enables investors to see the economic effect of these activities as a whole.

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

 

 

Top of page 29

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

The impacts of fair value accounting effects, relative to management's internal measure of performance, are shown in the table above. A reconciliation to GAAP information is set out below.

 

 

Third

Second

Third

 

Nine

Nine

 

 

quarter

quarter

quarter

 

months

months

$ million

 

2019

2019

2018

 

2019

2018

Upstream

 

 

 

 

 

 

 

Replacement cost profit (loss) before interest and tax adjusted for fair value accounting effects

 

(1,315

)

2,647

 

3,757

 

 

4,256

 

10,345

 

Impact of fair value accounting effects

 

265

 

(178

)

(285

)

 

47

 

(185

)

Replacement cost profit (loss) before interest and tax

 

(1,050

)

2,469

 

3,472

 

 

4,303

 

10,160

 

Downstream

 

 

 

 

 

 

 

Replacement cost profit (loss) before interest and tax adjusted for fair value accounting effects

 

1,869

 

1,334

 

2,074

 

 

4,932

 

5,077

 

Impact of fair value accounting effects

 

147

 

(46

)

175

 

 

137

 

(275

)

Replacement cost profit (loss) before interest and tax

 

2,016

 

1,288

 

2,249

 

 

5,069

 

4,802

 

Total group

 

 

 

 

 

 

 

Profit (loss) before interest and tax adjusted for fair value accounting effects

 

462

 

4,240

 

6,273

 

 

10,370

 

16,674

 

Impact of fair value accounting effects

 

412

 

(224

)

(110

)

 

184

 

(460

)

Profit (loss) before interest and tax

 

874

 

4,016

 

6,163

 

 

10,554

 

16,214

 

Readily marketable inventory* (RMI)

 

 

30 September

31 December

$ million

 

2019

2018

RMI at fair value*

 

5,604

 

4,202

 

Paid-up RMI*

 

2,754

 

1,641

 

 

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

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

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

 

 

30 September

31 December

$ million

 

2019

2018

Reconciliation of total inventory to paid-up RMI

 

 

 

Inventories as reported on the group balance sheet under IFRS

 

19,240

 

17,988

 

Less: (a) inventories that are not oil and oil products and (b) oil and oil product inventories that are not risk-managed by IST

 

(13,805

)

(14,066

)

 

 

5,435

 

3,922

 

Plus: difference between RMI at fair value and RMI on an IFRS basis

 

169

 

280

 

RMI at fair value

 

5,604

 

4,202

 

Less: unpaid RMI* at fair value

 

(2,850

)

(2,561

)

Paid-up RMI

 

2,754

 

1,641

 

 

 

Top of page 30

Gulf of Mexico oil spill

 

 

Third

Second

Third

 

Nine

Nine

 

 

quarter

quarter

quarter

 

months

months

$ million

 

2019

2019

2018

 

2019

2018

Net cash provided by operating activities as per condensed group cash flow statement

 

6,056

 

6,815

 

6,092

 

 

18,167

 

16,044

 

Exclude net cash from operating activities relating to the Gulf of Mexico oil spill on a post-tax basis

 

409

 

1,413

 

525

 

 

2,471

 

2,946

 

Operating cash flow, excluding Gulf of Mexico oil spill payments*

 

6,465

 

8,228

 

6,617

 

 

20,638

 

18,990

 

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

 

 

30 September

31 December

$ million

 

2019

2018

Trade and other payables

 

(12,402

)

(14,201

)

Provisions

 

(207

)

(345

)

Gulf of Mexico oil spill payables and provisions

 

(12,609

)

(14,546

)

Of which - current

 

(1,829

)

(2,612

)

 

 

 

 

Deferred tax asset

 

5,610

 

5,562

 

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

Working capital* reconciliation

 

 

Third

Second

Third

 

Nine

Nine

 

 

quarter

quarter

quarter

 

months

months

$ million

 

2019

2019

2018

 

2019

2018

Movements in inventories and other current and non-current assets and liabilities as per condensed group cash flow statement

 

141

 

(58

)

(1,573

)

 

(2,612

)

(5,541

)

Adjustments to exclude movements in inventories and other current and non-current assets and liabilities for the Gulf of Mexico oil spill

 

413

 

1,451

 

538

 

 

2,495

 

2,819

 

Adjusted for Inventory holding gains (losses)* (Note 4)

 

 

 

 

 

 

 

Upstream

 

-

 

(10

)

1

 

 

(8

)

6

 

Downstream

 

(433

)

93

 

343

 

 

706

 

1,608

 

Working capital release (build)

 

121

 

1,476

 

(691

)

 

581

 

(1,108

)

 

 

Top of page 31

Realizations* and marker prices

 

 

Third

Second

Third

 

Nine

Nine

 

 

quarter

quarter

quarter

 

months

months

 

 

2019

2019

2018

 

2019

2018

Average realizations(a)

 

 

 

 

 

 

 

Liquids* ($/bbl)

 

 

 

 

 

 

 

US

 

50.46

 

56.98

 

65.22

 

 

52.80

 

61.76

 

Europe

 

61.90

 

68.73

 

73.90

 

 

64.21

 

70.51

 

Rest of World

 

59.14

 

66.24

 

71.95

 

 

61.91

 

68.41

 

BP Average

 

55.68

 

62.63

 

69.68

 

 

58.38

 

66.11

 

Natural gas ($/mcf)

 

 

 

 

 

 

 

US

 

1.72

 

1.80

 

2.22

 

 

2.02

 

2.15

 

Europe

 

3.03

 

3.63

 

7.79

 

 

3.98

 

7.33

 

Rest of World

 

3.82

 

4.12

 

4.36

 

 

4.21

 

4.24

 

BP Average

 

3.11

 

3.35

 

3.86

 

 

3.49

 

3.77

 

Total hydrocarbons* ($/boe)

 

 

 

 

 

 

 

US

 

31.23

 

35.94

 

43.20

 

 

33.81

 

41.21

 

Europe

 

52.47

 

63.40

 

68.54

 

 

58.55

 

64.80

 

Rest of World

 

36.82

 

41.60

 

45.51

 

 

39.69

 

42.98

 

BP Average

 

35.48

 

40.64

 

46.14

 

 

38.55

 

43.64

 

Average oil marker prices ($/bbl)

 

 

 

 

 

 

 

Brent

 

62.00

 

68.86

 

75.16

 

 

64.59

 

72.13

 

West Texas Intermediate

 

56.40

 

59.90

 

69.63

 

 

57.08

 

66.90

 

Western Canadian Select

 

43.61

 

47.37

 

40.33

 

 

45.30

 

42.35

 

Alaska North Slope

 

62.98

 

68.29

 

75.26

 

 

65.23

 

72.19

 

Mars

 

59.19

 

65.20

 

70.79

 

 

61.85

 

67.63

 

Urals (NWE - cif)

 

60.82

 

67.62

 

73.98

 

 

63.71

 

70.50

 

Average natural gas marker prices

 

 

 

 

 

 

 

Henry Hub gas price(b) ($/mmBtu)

 

2.23

 

2.64

 

2.91

 

 

2.67

 

2.90

 

UK Gas - National Balancing Point (p/therm)

 

27.46

 

31.53

 

64.46

 

 

35.70

 

58.83

 

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

(b)       Henry Hub First of Month Index.

Exchange rates

 

 

Third

Second

Third

 

Nine

Nine

 

 

quarter

quarter

quarter

 

months

months

 

 

2019

2019

2018

 

2019

2018

$/£ average rate for the period

 

1.23

 

1.29

 

1.30

 

 

1.27

 

1.35

 

$/£ period-end rate

 

1.23

 

1.27

 

1.31

 

 

1.23

 

1.31

 

 

 

 

 

 

 

 

 

$/€ average rate for the period

 

1.11

 

1.12

 

1.16

 

 

1.12

 

1.19

 

$/€ period-end rate

 

1.09

 

1.14

 

1.17

 

 

1.09

 

1.17

 

 

 

 

 

 

 

 

 

Rouble/$ average rate for the period

 

64.64

 

64.58

 

65.54

 

 

65.06

 

61.52

 

Rouble/$ period-end rate

 

64.32

 

63.09

 

65.76

 

 

64.32

 

65.76

 

 

 

Top of page 32

Legal proceedings

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

 

Glossary

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

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

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

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

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

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

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

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

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

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

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

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

 

Top of page 33

 

Glossary (continued)

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

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

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

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

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

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

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

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

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

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

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

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

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

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

 

 

Top of page 34

 

Glossary (continued)

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

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

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

Solomon availability - See Refining availability definition.

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

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

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

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

Underlying RC profit or loss is RC profit or loss after adjusting for non-operating items and fair value accounting effects. Underlying RC profit or loss and adjustments for fair value accounting effects are not recognized GAAP measures. See pages 27 and 28 for additional information on the non-operating items and fair value accounting effects that are used to arrive at underlying RC profit or loss in order to enable a full understanding of the events and their financial impact. BP believes that underlying RC profit or loss is a useful measure for investors because it is a measure closely tracked by management to evaluate BP's operating performance and to make financial, strategic and operating decisions and because it may help investors to understand and evaluate, in the same manner as management, the underlying trends in BP's operational performance on a comparable basis, period on period, by adjusting for the effects of these non-operating items and fair value accounting effects. The nearest equivalent measure on an IFRS basis for the group is profit or loss attributable to BP shareholders. The nearest equivalent measure on an IFRS basis for segments is RC profit or loss before interest and taxation. Underlying earnings on page 1 refer to underlying RC profit for the group. A reconciliation to GAAP information is provided on page 1.

Underlying RC profit or loss per share is a non-GAAP measure. Earnings per share is defined in Note 8. Underlying RC profit or loss per share is calculated using the same denominator. The numerator used is underlying RC profit or loss attributable to BP shareholders rather than profit or loss attributable to BP shareholders. BP believes it is helpful to disclose the underlying RC profit or loss per share because this measure may help investors to understand and evaluate, in the same manner as management, the underlying trends in BP's operational performance on a comparable basis, period on period. The nearest equivalent measure on an IFRS basis is basic earnings per share based on profit or loss for the period attributable to BP shareholders.

 

 

Top of page 35

Glossary (continued)

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

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

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

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

 

 

Top of page 36

Cautionary statement

In order to utilize the 'safe harbor' provisions of the United States Private Securities Litigation Reform Act of 1995 (the 'PSLRA') and the general doctrine of cautionary statements, BP is providing the following cautionary statement: The discussion in this results announcement contains certain forecasts, projections and forward-looking statements - that is, statements related to future, not past events and circumstances - with respect to the financial condition, results of operations and businesses of BP and certain of the plans and objectives of BP with respect to these items. These statements may generally, but not always, be identified by the use of words such as 'will', 'expects', 'is expected to', 'aims', 'should', 'may', 'objective', 'is likely to', 'intends', 'believes', 'anticipates', 'plans', 'we see' or similar expressions. In particular, the following, among other statements, are all forward looking in nature: expectations regarding the expected quarterly dividend payment and timing of such payment and the suspension of the scrip dividend alternative and introduction of dividend reinvestment plans; expectations regarding the underlying effective tax rate in 2019; expectations regarding 2019 organic capital expenditure and depreciation, depletion and amortization charges; expectations that net debt levels will trend down over time and that gearing will remain above the target 20-30% range before reducing towards the middle of the range in 2020; expectations regarding share buybacks, including to offset the impact of dilution from the scrip program; plans and expectations relating to divestments and disposals, including that around $10 billion of divestment transactions will be announced by the end of 2019; plans and expectations regarding the announced sale of BP's interests in Alaska to a subsidiary of Hilcorp Energy, including the completion of the sale and expected timing and proceeds thereof; plans and expectations with respect to the joint venture in India with Reliance Industries Limited; plans and expectations regarding BP's low-carbon business, including with regard to BP's joint venture with DiDi to develop an electric vehicle charging network in China and to the installation of 400 ultra-fast chargers at BP Chargemaster's UK retail sites; plans and expectations to run jointly branded workshop pilots in China and the US with Bosch; plans and expectations regarding BP Infinia; plans to deploy continuous measurement of methane emissions on all future major operated oil and gas processing projects; expectations regarding Upstream fourth-quarter 2019 reported production, seasonal maintenance and turnaround activities; expectations regarding Downstream fourth-quarter 2019 refining margins and turnaround activity; expectations regarding the amount of the Rosneft dividend; plans and expectations regarding Lightsource BP, including to develop a solar facility in Colorado and negotiate power purchase agreements to supply customers across Spain's Zaragoza province; plans and expectations with respect to the joint venture between BP's Brazilian biofuels business and Bunge, including the completion of the joint venture transaction and the timing thereof; expectations regarding the Other businesses and corporate 2019 average quarterly charges excluding non-operating items; and expectations with respect to the amount of future payments relating to the Gulf of Mexico oil spill. By their nature, forward-looking statements involve risk and uncertainty because they relate to events and depend on circumstances that will or may occur in the future and are outside the control of BP. Actual results may differ materially from those expressed in such statements, depending on a variety of factors, including: the specific factors identified in the discussions accompanying such forward-looking statements; the receipt of relevant third party and/or regulatory approvals; the timing and level of maintenance and/or turnaround activity; the timing and volume of refinery additions and outages; the timing of bringing new fields onstream; the timing, quantum and nature of certain acquisitions and divestments; future levels of industry product supply, demand and pricing, including supply growth in North America; OPEC quota restrictions; PSA effects; operational and safety problems; potential lapses in product quality; economic and financial market conditions generally or in various countries and regions; political stability and economic growth in relevant areas of the world; changes in laws and governmental regulations; regulatory or legal actions including the types of enforcement action pursued and the nature of remedies sought or imposed; the actions of prosecutors, regulatory authorities and courts; delays in the processes for resolving claims; amounts ultimately payable and timing of payments relating to the Gulf of Mexico oil spill; exchange rate fluctuations; development and use of new technology; recruitment and retention of a skilled workforce; the success or otherwise of partnering; the actions of competitors, trading partners, contractors, subcontractors, creditors, rating agencies and others; our access to future credit resources; business disruption and crisis management; the impact on our reputation of ethical misconduct and non-compliance with regulatory obligations; trading losses; major uninsured losses; decisions by Rosneft's management and board of directors; the actions of contractors; natural disasters and adverse weather conditions; changes in public expectations and other changes to business conditions; wars and acts of terrorism; cyber-attacks or sabotage; and other factors discussed elsewhere in this report, and under "Risk factors" in BP Annual Report and Form 20-F 2018 as filed with the US Securities and Exchange Commission.

 

 

 

Contacts

 

London

Houston

 

 

 

Press Office

David Nicholas

Brett Clanton

 

+44 (0)20 7496 4708

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Investor Relations

Craig Marshall

Brian Sullivan

bp.com/investors

+44 (0)20 7496 4962

 +1 281 892 3421

 

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3Q19 Part 1 of 1 - RNS