6-K 1 a30062019bp6kq2.htm 6-K Document


UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549


Form 6-K

Report of Foreign Private Issuer

Pursuant to Rule 13a-16 or 15d-16 of
the Securities Exchange Act of 1934

for the period ended 30 June 2019
Commission File Number 1-06262

BP p.l.c.
(Translation of registrant’s name into English)

1 ST JAMES’S SQUARE, LONDON, SW1Y 4PD, ENGLAND
(Address of principal executive offices)

Indicate by check mark whether the registrant files or will file annual reports under cover of Form 20-F or Form 40-F:
 
 
 
 
Form 20-F x  Form 40-F ¨
 
 
 
 
Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(1): ¨
Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(7): ¨

THIS REPORT ON FORM 6-K SHALL BE DEEMED TO BE INCORPORATED BY REFERENCE IN THE PROSPECTUS INCLUDED IN THE REGISTRATION STATEMENT ON FORM F-3 (FILE NOS. 333-226485, 333-226485-01 AND 333-226485-02) OF BP p.l.c., BP CAPITAL MARKETS p.l.c. AND BP CAPITAL MARKETS AMERICA INC.; THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-67206) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-79399) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-103924) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-123482) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-123483) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-131583) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-131584) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-132619) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-146868) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-146870) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-146873) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-173136) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-177423) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-179406) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-186462) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-186463) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-199015) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-200794) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-200795) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-207188) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-207189) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-210316) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-210318) OF BP p.l.c., AND TO BE A PART THEREOF FROM THE DATE ON WHICH THIS REPORT IS FURNISHED, TO THE EXTENT NOT SUPERSEDED BY DOCUMENTS OR REPORTS SUBSEQUENTLY FILED OR FURNISHED.


1

BP p.l.c. and subsidiaries
Form 6-K for the period ended 30 June 2019(a) 

(a)
In this Form 6-K, references to the half year 2019 and half year 2018 refer to six-month periods ended 30 June 2019 and 30 June 2018 respectively. References to the second quarter 2019 and second quarter 2018 refer to the three-month periods ended 30 June 2019 and 30 June 2018 respectively.
(b)
This discussion should be read in conjunction with the consolidated financial statements and related notes provided elsewhere in this Form 6-K and with the information, including the consolidated financial statements and related notes, in BP’s Annual Report on Form 20-F for the year ended 31 December 2018.


2

Group results second quarter and half year 2019

Highlights
Midway through 5-year plan, continuing to deliver strong performance and strategic progress
•    Strong financial results
–
Profit for the second quarter of 2019 was $1.8 billion, compared with $2.8 billion for the same period in 2018. Underlying replacement cost profit for the quarter was $2.8 billion, similar to a year earlier. The quarter’s result largely reflected continued good operating performance, offset by oil prices lower than in the second quarter of 2018.
–
Non-operating items in the second quarter of $0.9 billion, post-tax, related mainly to impairment charges.
–
Operating cash flow for the second quarter was $6.8 billion including the impact of Gulf of Mexico oil spill payments(a). 
–
Gulf of Mexico oil spill payments of $1.4 billion on a post-tax basis in the second quarter were primarily the scheduled annual payments.
–
A dividend of 10.25 cents a share was announced for the quarter.

•
Solid Upstream and Downstream performance
–
Reported oil and gas production for the quarter averaged 3.8 million barrels a day of oil equivalent, 4% higher than a year earlier.
–
With the start-up of Culzean in the North Sea this quarter, four Upstream major projects have begun production in the first half of the year.
–
Final investment decisions were taken in the quarter for new Upstream major projects in India and the Gulf of Mexico, as well as agreement for additional investment in Angola.
–
In Downstream, quarter on quarter growth in lubricants and fuels marketing, more than offset by planned turnarounds ahead of IMO 2020.
•
Growing low carbon businesses
–
BP agreed to combine its Brazilian biofuels and biopower business with that of Bunge in a new equally-owned joint venture. On completion, BP’s interest in the venture will be more than 50% larger than its existing biofuels business.
–
Lightsource BP (43% owned by BP) has continued to make strong progress, including agreeing a significant expansion in Brazil.
–
BP agreed a $30 million venturing investment in Calysta, which will use BP's natural gas to produce protein feed for aquaculture and agriculture.

(a)  
Operating cash flow excluding Gulf of Mexico oil spill payments is a measure used by management and BP believes it is useful as it allows for meaningful comparisons between reporting periods. It is not however disclosed in this SEC filing because SEC regulations do not permit the inclusion of this non-GAAP metric.

Financial summary
 
Second

Second

 
First

First

 
quarter

quarter

 
half

half

$ million
 
2019

2018

 
2019

2018

Sales and other operating revenues
 
72,676

75,439

 
138,997

143,611

Profit for the period attributable to BP shareholders
 
1,822

2,799

 
4,756

5,268

Inventory holding (gains) losses, before tax
 
(81
)
(1,310
)
 
(1,169
)
(1,402
)
Taxation charge (credit) on inventory holding gains and losses
 
34

300

 
283

312

RC profit
 
1,775

1,789

 
3,870

4,178

Net (favourable) adverse impact of non-operating items and fair value accounting effects, before tax
 
1,341

1,275

 
1,690

1,670

Taxation charge (credit) on non-operating items and fair value accounting effects
 
(305
)
(242
)
 
(391
)
(440
)
Underlying RC profit
 
2,811

2,822

 
5,169

5,408

Profit per ordinary share (cents)
 
8.95

14.03

 
23.47

26.42

Profit per ADS (dollars)
 
0.54

0.84

 
1.41

1.59

RC profit per ordinary share (cents)
 
8.72

8.96

 
19.10

20.96

RC profit per ADS (dollars)
 
0.52

0.54

 
1.15

1.26

Underlying RC profit per ordinary share (cents)
 
13.82

14.14

 
25.51

27.13

Underlying RC profit per ADS (dollars)
 
0.83

0.85

 
1.53

1.63


RC profit (loss) and underlying RC profit are non-GAAP measures. These measures and major projects, inventory holding gains and losses, non-operating items and fair value accounting effects are defined in the Glossary on page 44.
The commentary above and following should be read in conjunction with the cautionary statement on page 47.

3

Group headlines
Results
BP’s profit for the second quarter and half year was $1,822 million and $4,756 million respectively, compared with $2,799 million and $5,268 million for the same periods in 2018.
For the half year, replacement cost (RC) profit* was $3,870 million, compared with $4,178 million in 2018. Underlying RC profit* was $5,169 million, compared with $5,408 million in 2018. Underlying RC profit is after adjusting RC profit for a net charge for non-operating items* of $1,113 million, mainly relating to impairment charges, and net adverse fair value accounting effects* of $186 million (both on a post-tax basis).
For the second quarter, RC profit was $1,775 million, compared with $1,789 million in 2018. Underlying RC profit was $2,811 million, compared with $2,822 million in 2018. Underlying RC profit is after adjusting RC profit for a net charge for non-operating items of $861 million, mainly relating to impairment charges, and net adverse fair value accounting effects of $175 million (both on a post-tax basis).
See further information on pages 5, 37 and 38.
Depreciation, depletion and amortization
The charge for depreciation, depletion and amortization was $4.6 billion in the quarter and $9.0 billion in the half year. In the same periods in 2018 it was $3.8 billion and $7.7 billion respectively (prior to the implementation of IFRS 16). In 2019, we expect the full-year charge to be around $18 billion.
Effective tax rate
The effective tax rate (ETR) on the profit for the second quarter and half year was 40% and 38% respectively, compared with 42% and 39% for the same periods in 2018.
The ETR on RC profit or loss* for the second quarter and half year was 39% and 41% respectively, compared with 49% and 42% for the same periods in 2018. Adjusting for non-operating items and fair value accounting effects, the underlying ETR* for the second quarter and half year was 34% and 37% respectively, compared with 42% and 40% for the same periods a year ago. The underlying ETR for the quarter and the half year is lower than a year ago mainly due to the absence of deferred tax charges from foreign exchange impacts. In the current environment the underlying ETR in 2019 is expected to be around 40%. ETR on RC profit or loss and underlying ETR are non-GAAP measures.
Dividend
BP today announced a quarterly dividend of 10.25 cents per ordinary share ($0.615 per ADS), which is expected to be paid on 20 September 2019. The corresponding amount in sterling will be announced on 10 September 2019. See page 25 for further information.
 
Share buybacks
BP repurchased 11 million ordinary shares at a cost of $75 million, including fees and stamp duty, during the second quarter of 2019. For the half year, BP repurchased 17 million ordinary shares at a cost of $125 million, including fees and stamp duty. Our share buyback programme is expected to fully offset the impact of scrip dilution since the third quarter 2017 by the end of 2019.
Operating cash flow*
Operating cash flow was $6.8 billion in the second quarter and $12.1 billion in the half year including the impact of Gulf of Mexico oil spill payments of $1.4 billion and $2.1 billion respectively. For the same periods in 2018 we reported $6.3 billion and $10.0 billion (prior to the implementation of IFRS 16).
Capital expenditure*
Total capital expenditure for the second quarter and half year was $5.7 billion and $11.3 billion respectively. We reported $3.8 billion and $7.8 billion for the same periods in 2018 (prior to the implementation of IFRS 16).
Organic capital expenditure* for the second quarter and half year was $3.7 billion and $7.3 billion respectively. We reported $3.5 billion and $7.0 billion for the same periods in 2018 (prior to the implementation of IFRS 16).
Inorganic capital expenditure* for the second quarter and half year was $2.0 billion and $4.0 billion respectively, including $1.7 billion for the quarter and $3.5 billion for the half year relating to the BHP acquisition, compared with $0.4 billion and $0.8 billion for the same periods in 2018.
Organic capital expenditure and inorganic capital expenditure are non-GAAP measures. See page 36 for further information.
Divestment and other proceeds
Divestment proceeds* were $0.1 billion for the second quarter and $0.7 billion for the half year, compared with $0.2 billion and $0.3 billion for the same periods in 2018.
Debt
Finance debt at 30 June 2019 was $67.6 billion, compared with $59.7 billion a year ago. Finance debt ratio* at 30 June 2019 was 39.5%, compared with 37.0% a year ago. Net debt* at 30 June 2019 was $46.5 billion, compared with $38.7 billion a year ago. Gearing* at 30 June 2019 was 31.0%, compared with 27.5% a year ago.
Net debt and gearing are non-GAAP measures. See page 25 for more information.






* For items marked with an asterisk throughout this document, definitions are provided in the Glossary on page 44.

For more information on the impact of IFRS 16 'Leases' on key financial metrics, see page 35.
The commentary above contains forward-looking statements and should be read in conjunction with the cautionary statement on page 47.

4

Analysis of underlying RC profit* before interest and tax
 
 
Second

Second

 
First

First

 
 
quarter

quarter

 
half

half

$ million
 
2019

2018

 
2019

2018

Underlying RC profit before interest and tax
 
 
 
 
 
 
Upstream
 
3,413

3,508

 
6,341

6,665

Downstream
 
1,365

1,455

 
3,098

3,281

Rosneft
 
638

766

 
1,205

1,013

Other businesses and corporate
 
(290
)
(477
)
 
(708
)
(869
)
Consolidation adjustment – UPII*
 
34

151

 
21

(9
)
Underlying RC profit before interest and tax
 
5,160

5,403

 
9,957

10,081

Finance costs and net finance expense relating to pensions and other post-retirement benefits
 
(752
)
(448
)
 
(1,506
)
(912
)
Taxation on an underlying RC basis
 
(1,515
)
(2,059
)
 
(3,135
)
(3,625
)
Non-controlling interests
 
(82
)
(74
)
 
(147
)
(136
)
Underlying RC profit attributable to BP shareholders
 
2,811

2,822

 
5,169

5,408

Reconciliations of underlying RC profit or loss to the nearest equivalent IFRS measure are provided on page 3 for the group and on pages 8-14 for the segments.
 
Analysis of RC profit (loss)* before interest and tax and reconciliation to profit for the period
 
 
Second

Second

 
First

First

 
 
quarter

quarter

 
half

half

$ million
 
2019

2018

 
2019

2018

RC profit before interest and tax
 
 
 
 
 
 
Upstream
 
2,469

3,514

 
5,353

6,688

Downstream
 
1,288

840

 
3,053

2,553

Rosneft
 
525

766

 
1,011

1,013

Other businesses and corporate
 
(381
)
(1,025
)
 
(927
)
(1,596
)
Consolidation adjustment – UPII
 
34

151

 
21

(9
)
RC profit before interest and tax
 
3,935

4,246

 
8,511

8,649

Finance costs and net finance expense relating to pensions and other post-retirement benefits
 
(868
)
(566
)
 
(1,750
)
(1,150
)
Taxation on a RC basis
 
(1,210
)
(1,817
)
 
(2,744
)
(3,185
)
Non-controlling interests
 
(82
)
(74
)
 
(147
)
(136
)
RC profit attributable to BP shareholders
 
1,775

1,789

 
3,870

4,178

Inventory holding gains (losses)*
 
81

1,310

 
1,169

1,402

Taxation (charge) credit on inventory holding gains and losses
 
(34
)
(300
)
 
(283
)
(312
)
Profit for the period attributable to BP shareholders
 
1,822

2,799

 
4,756

5,268






5

Strategic progress
Upstream
Upstream production, which excludes Rosneft, for the first half of the year averaged 2,640mboe/d, 4.2% higher than a year earlier. Underlying production*, adjusted for portfolio changes and PSA* impacts was broadly flat.
Culzean in the North Sea (BP 32%) was BP’s fourth Upstream major project* to start up in 2019 and the 23rd since the start of 2016.
Final investment decisions were made for the Thunder Horse South Expansion Phase 2 project in the US Gulf of Mexico and the MJ project on Block KG D6 offshore India. BP and partners also agreed additional investment expected to increase and extend production from deepwater Block 15 offshore Angola.
In the quarter BP agreed the sale of mature oil interests in the Gulf of Suez, Egypt, including its interests in GUPCO, to Dragon Oil of Dubai. BP has agreed to sell its interest in oil and gas fields in Cleveland and McClain counties in Oklahoma, US.

Downstream
In fuels marketing, first-half earnings grew by more than 15% year on year.
Groupe Renault has recently appointed Castrol as its global service fill engine oil lubricants partner, effective from 1 January 2020. In addition Castrol extended the Renault Sport Racing Formula 1 sponsorship through to the end of 2024, further strengthening this strategic partnership.

Advancing the energy transition
In a significant advance for its biofuels position, in July BP announced it has agreed to combine its Brazilian biofuels and biopower business with that of Bunge to form a new equally-owned joint venture, BP Bunge Bioenergia. On completion, subject to regulatory approvals, BP’s 50% interest in the new venture will be more than 50% larger than its existing biofuels business.
BP’s equity-accounted solar entity Lightsource BP (LSBP) announced in July the acquisition of approximately two gigawatts of greenfield solar projects at various development stages across Brazil.
BP continues to make progress in its advanced mobility agenda. BP Chargemaster expanded its UK network of chargers by around 600 to 7,200 over the first half of 2019 and in the coming
 
weeks will begin installing the first of 400 ultra-fast chargers at BP retail sites in the UK.
BP Ventures announced a $30-million investment into Calysta, whose technology produces protein with natural gas as a feedstock. Its innovative process offers the potential to sustainably produce protein feed to meet fast-growing demand from aquaculture and agriculture.
Financial framework
Following the introduction of IFRS 16 on 1 January 2019, the positive impacts on Operating cash flow* and Organic capital expenditure* are fully offset in the cash flow statement by a new line, Lease liability payments. Lease payments are now included in the definition of free cash flow* as a use of cash, which means the net impact on this measure is zero.

Operating cash flow* was $12.1 billion for the half year of 2019, including Gulf of Mexico oil spill payments of $2.1 billion. For the half year of 2018, we reported $10.0 billion (prior to the implementation of IFRS 16).

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

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

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

Gulf of Mexico oil spill payments on a post-tax basis totalled $2.1 billion in the half year. Payments for the full year continue to be expected to be around $2 billion on a post-tax basis.

Gearing* at the end of the half year was 31.0%. See page 25 for more information. Assuming recent average oil prices, and in line with expected growth in free cash flow supported by divestment proceeds, we expect gearing to move towards the middle of our targeted range of 20-30% in 2020.
Safety
Tier 1 and tier 2 process safety events* increased in the first half of 2019 compared with the same period in 2018. This increase mainly related to tier 2 events. Safety remains our number one priority and we remain focused on reducing both tier 1 and tier 2 process safety events.

Operating metrics
 
First half 2019
 
Financial metrics
 
First half 2019
 
(vs. First half 2018)
 
 
(vs. First half 2018)
Tier 1 and tier 2 process safety events
 
49
 
Underlying RC profit*i
 
$5.2bn
 
(+16)
 
 
(-$0.2bn)
Reported recordable injury frequency*
 
0.19
 
Operating cash flow excluding Gulf of Mexico oil spill payments (post-tax)
 
(b) 
 
(-15%)
 
 
 
Group production
 
3,786mboe/d
 
Organic capital expenditureii
 
$7.3bn
 
(+3.4%)
 
 
(+$0.3bn)
Upstream production (excludes Rosneft segment)
 
2,640mboe/d
 
Gulf of Mexico oil spill payments (post-tax)
 
$2.1bn
 
(+4.2%)
 
 
(-$0.4bn)
Upstream unit production costs(a)
 
$7.02/boe
 
Divestment proceeds*
 
$0.7bn
 
(-4.1%)
 
 
(+$0.4bn)
BP-operated Upstream plant reliability
 
94.9%
 
Gearingiii
 
31.0%
 
(-0.9)
 
 
(+3.5)
BP-operated refining availability*
 
93.9%
 
Dividend per ordinary share(c)
 
10.25 cents
 
(-0.1)
 
 
—
(a)
Slight increase from the same period in 2018 after excluding the impacts of IFRS 16 on production costs.
(b)
SEC regulations do not permit inclusion of this non-GAAP metric in this SEC filing. Operating cash flow excluding Gulf of Mexico oil spill payments is calculated by excluding post-tax payments relating to the Gulf of Mexico oil spill from net cash provided by operating activities,

6

as reported in the condensed group cash flow statement. For the half year, net cash provided by operating activities was $12.1 billion and post-tax Gulf of Mexico oil spill payments were $2.1 billion.
(c)
Represents dividend announced in the quarter (vs. prior year quarter).




 
Nearest GAAP equivalent measures
i
Profit for the period:
$4.8bn
ii
Capital expenditure*:
$11.3bn
iii
Finance debt ratio*:
39.5%


The commentary above contains forward-looking statements and should be read in conjunction with the cautionary statement on page 47.

7

Upstream
 
 
Second

Second

 
First

First

 
 
quarter

quarter

 
half

half

$ million
 
2019

2018

 
2019

2018

Sales and other operating revenues(a)
 
13,556

12,698

 
28,150

26,568

Profit before interest and tax
 
2,459

3,518

 
5,345

6,693

Inventory holding (gains) losses*
 
10

(4
)
 
8

(5
)
RC profit before interest and tax
 
2,469

3,514

 
5,353

6,688

Net (favourable) adverse impact of non-operating items* and fair value accounting effects*
 
944

(6
)
 
988

(23
)
Underlying RC profit before interest and tax*(b)
 
3,413

3,508

 
6,341

6,665

(a)
Includes sales to other segments.
(b)
See page 10 for a reconciliation to segment RC profit before interest and tax by region.

Financial results
Sales and other operating revenues for the second quarter and half year were $14 billion and $28 billion respectively, compared with $13 billion and $27 billion for the corresponding periods in 2018. For the second quarter, revenues were higher mainly due to higher volumes. For the half year, revenues were higher mainly due to higher volumes and higher gas marketing and trading revenues.
The replacement cost profit before interest and tax for the second quarter and half year was $2,469 million and $5,353 million respectively, compared with $3,514 million and $6,688 million for the same periods in 2018. The second quarter and half year included a net non-operating charge of $766 million and $770 million respectively, compared with a net gain of $27 million and a net charge of $77 million for the same periods in 2018. Fair value accounting effects in the second quarter and half year had an adverse impact of $178 million and $218 million respectively, compared with an adverse impact of $21 million and a favourable impact of $100 million in the same periods of 2018.

After adjusting for non-operating items and fair value accounting effects, the underlying replacement cost profit before interest and tax for the second quarter and half year was $3,413 million and $6,341 million respectively, compared with $3,508 million and $6,665 million for the same periods in 2018. The results for the second quarter and half year mainly reflected lower liquids realizations, partly offset by ramp up of major projects* in the US Gulf of Mexico and North Sea and very strong gas marketing and trading.

Production
Production for the quarter was 2,625mboe/d, 6.5% higher than the second quarter of 2018. Underlying production* for the quarter increased by 0.7%, mainly due to the ramp-up of major projects.
For the half year, production was 2,640mboe/d, 4.2% higher than 2018. Underlying production* was broadly flat.

Key events
On 6 May, BP announced the final investment decision for the Thunder Horse South Expansion Phase 2 in the US Gulf of Mexico (BP operator 75%, ExxonMobil 25%).
On 3 June, BP announced an agreement to sell its interests in Gulf of Suez oil concessions in Egypt to Dragon Oil. The agreement, which is subject to the Egyptian Ministry of Petroleum and Mineral Resources' approval, includes producing and exploration concessions, including BP’s interest in the Gulf of Suez Petroleum Company (GUPCO).
On 4 June, BP confirmed the discovery of King Embayment in the Mars corridor, in the US Gulf of Mexico (Shell operator 71.5%, BP 28.5%).
On 6 June, BP confirmed further investment into deepwater Block 15, offshore Angola. The agreement will extend the production-sharing agreement* for Block 15 through 2032. (Exxon 36% operator, BP 24%, ENI 18%, and Equinor 12%).
On 11 June, BP and Reliance Industries Limited (RIL) announced the sanction of the MJ gas development project in Block KG D6, offshore the east coast of India. MJ is the third of three new projects in the Block KG D6 integrated development plan (RIL operator 60%, BP 30%, NIKO 10%).
On 11 June, BP confirmed the start-up of gas production from the Culzean field in the UK North Sea (Total operator 49.99%, BP 32%, JX Nippon 18.01%).
On 19 June, BP confirmed an agreement to sell its interest in oil and gas fields in Cleveland and McClain counties in Oklahoma, US.
On 1 July, BP confirmed the Greater Tortue Ahmeyim-1 appraisal well, located offshore Senegal, encountered approximately 30 metres of net gas pay in high-quality Albian reservoir confirming gas resource expectations (BP operator 56%, Kosmos 27%, Petrosen 10%, SMHPM 7%).
On 17 July, BP confirmed the Bélé-1 and Tuk-1 gas discoveries, as well as the successful Hi-Hat-1 appraisal well, located offshore Trinidad and Tobago (BHP operator 70%, BP 30%).
During the second quarter, BP achieved new access in Argentina’s first offshore licensing round blocks CAN-111 and CAN-113 (Total operator 50%, BP 50%), offshore Gambia block A1 (BP 100%), West of Shetland in the North Sea for one licence covering 10 blocks (BP operator 50%, Shell 50%), and a farm-in to an exploration permit WA-359-P offshore Western Australia (BP operator 42.5%, Cue 21.5%, Beach 21%, New Zealand Oil & Gas 15%).
This builds on the progress announced in our first-quarter results, which comprised the following: the Constellation development in the US Gulf of Mexico commenced production; commencement of gas production from the second stage of Egypt’s West Nile Delta development, in the Giza and Fayoum fields; first gas from the Angelin project in Trinidad; BPX Energy assumed control of all Petrohawk Energy Corporation operations from BHP; BP and Environmental Defense Fund announced a three-year strategic commitment to advance technologies to reduce methane emissions from the global oil and gas supply chain; a gas discovery in the

8

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

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



The commentary above contains forward-looking statements and should be read in conjunction with the cautionary statement on page 47.


9

Upstream (continued)
 
 
Second

Second

 
First

First

 
 
quarter

quarter

 
half

half

$ million
 
2019

2018

 
2019

2018

Underlying RC profit before interest and tax
 
 
 
 
 
 
US
 
861

742

 
1,473

1,268

Non-US
 
2,552

2,766

 
4,868

5,397

 
 
3,413

3,508

 
6,341

6,665

Non-operating items(a)
 
 
 
 
 
 
US
 
(446
)
(29
)
 
(476
)
(174
)
Non-US
 
(320
)
56

 
(294
)
97

 
 
(766
)
27

 
(770
)
(77
)
Fair value accounting effects
 
 
 
 
 
 
US
 
(225
)
(143
)
 
(318
)
(152
)
Non-US
 
47

122

 
100

252

 
 
(178
)
(21
)
 
(218
)
100

RC profit before interest and tax
 
 
 
 
 
 
US
 
190

570

 
679

942

Non-US
 
2,279

2,944

 
4,674

5,746

 
 
2,469

3,514

 
5,353

6,688

Exploration expense
 
 
 
 
 
 
US
 
69

77

 
94

386

Non-US
 
77

87

 
419

292

 
 
146

164

 
513

678

Of which: Exploration expenditure written off
 
77

81

 
361

507

Production (net of royalties)(b)
 
 
 
 
 
 
Liquids* (mb/d)
 
 
 
 
 
 
US
 
506

411

 
480

429

Europe
 
137

147

 
148

143

Rest of World
 
658

659

 
672

695

 
 
1,301

1,217

 
1,300

1,267

Of which equity-accounted entities
 
130

112

 
134

144

Natural gas (mmcf/d)
 
 
 
 
 
 
US
 
2,410

1,744

 
2,360

1,767

Europe
 
132

202

 
139

209

Rest of World
 
5,138

5,297

 
5,276

5,376

 
 
7,680

7,242

 
7,775

7,352

Of which equity-accounted entities
 
454

493

 
457

485

Total hydrocarbons* (mboe/d)
 
 
 
 
 
 
US
 
921

711

 
887

734

Europe
 
160

182

 
172

180

Rest of World
 
1,544

1,572

 
1,581

1,622

 
 
2,625

2,465

 
2,640

2,535

Of which equity-accounted entities
 
209

197

 
212

227

Average realizations*(c)
 
 
 
 
 
 
Total liquids(d) ($/bbl)
 
62.63

67.24

 
59.61

64.21

Natural gas ($/mcf)
 
3.35

3.65

 
3.68

3.72

Total hydrocarbons ($/boe)
 
40.64

43.37

 
40.02

42.36

(a)
Second quarter and first half 2019 include impairment charges related to BPX Energy and GUPCO divestments.
(b)
Includes BP’s share of production of equity-accounted entities in the Upstream segment.
(c)
Realizations are based on sales by consolidated subsidiaries only - this excludes equity-accounted entities.
(d)
Includes condensate, natural gas liquids and bitumen.

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

10

Downstream
 
 
Second

Second

 
First

First

 
 
quarter

quarter

 
half

half

$ million
 
2019

2018

 
2019

2018

Sales and other operating revenues(a)
 
66,396

69,174

 
124,812

130,580

Profit (loss) before interest and tax
 
1,381

2,036

 
4,192

3,818

Inventory holding (gains) losses*
 
(93
)
(1,196
)
 
(1,139
)
(1,265
)
RC profit before interest and tax
 
1,288

840

 
3,053

2,553

Net (favourable) adverse impact of non-operating items* and fair value accounting effects*
 
77

615

 
45

728

Underlying RC profit before interest and tax*(b)
 
1,365

1,455

 
3,098

3,281

(a)
Includes sales to other segments.
(b)
See page 12 for a reconciliation to segment RC profit before interest and tax by region and by business.

Financial results
Sales and other operating revenues for the second quarter and half year were $66 billion and $125 billion respectively, compared with $69 billion and $131 billion for the corresponding periods in 2018. The reduction in the second quarter and half year was mainly due to lower oil prices.
The replacement cost profit before interest and tax for the second quarter and half year was $1,288 million and $3,053 million respectively, compared with $840 million and $2,553 million for the same periods in 2018.
The second quarter and half year include a net non-operating charge of $31 million and $35 million respectively, compared with a charge of $225 million and $278 million for the same periods in 2018. Fair value accounting effects had an adverse impact of $46 million in the second quarter and an adverse impact of $10 million in the half year, compared with an adverse impact of $390 million and $450 million for the same periods in 2018.
After adjusting for non-operating items and fair value accounting effects, the underlying replacement cost profit before interest and tax for the second quarter and half year was $1,365 million and $3,098 million respectively, compared with $1,455 million and $3,281 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 12.
Fuels
The fuels business reported an underlying replacement cost profit before interest and tax of $961 million for the second quarter and $2,253 million for the half year, compared with $1,054 million and $2,452 million for the same periods in 2018. The result for the quarter and half year reflects the impact of significantly higher turnaround activity, lower refining margins and weaker North American heavy crude oil differentials partially offset by a stronger contribution from supply and trading. The result for the half year also reflects strong fuels marketing growth driven by higher retail earnings. Year on year we have grown the number of convenience partnership sites and continued to deliver premium fuel volume growth.
Lubricants
The lubricants business reported an underlying replacement cost profit before interest and tax of $321 million for the second quarter and $593 million for the half year, compared with $326 million and $657 million for the same periods in 2018. The result for the quarter and half year reflects the impact of adverse foreign exchange rate movements. Year on year we have continued to make strategic progress, delivering record premium brand volumes in the quarter.
Groupe Renault has recently appointed Castrol as its global service fill engine oil lubricants partner, effective from 1 January 2020. In addition Castrol extended the Renault Sport Racing Formula 1 sponsorship through to the end of 2024, further strengthening this strategic partnership.
Petrochemicals
The petrochemicals business reported an underlying replacement cost profit before interest and tax of $83 million for the second quarter and $252 million for the half year, compared with $75 million and $172 million for the same periods in 2018. The result for the quarter reflects high levels of turnaround, similar to the second quarter of 2018. The result for the half year reflects increased margin optimization, supported by stronger operational reliability.
During the first quarter we announced an expansion of capacity at our joint venture petrochemicals facility in South Korea and signed an agreement with Virent and Johnson Matthey to further advance the development of bio-paraxylene, a key raw material for the production of renewable polyester.
Outlook
Looking to the third quarter of 2019, we expect a lower level of turnaround activity and lower industry refining margins.


The commentary above contains forward-looking statements and should be read in conjunction with the cautionary statement on page 47.

11

Downstream (continued)
 
 
Second

Second

 
First

First

 
 
quarter

quarter

 
half

half

$ million
 
2019

2018

 
2019

2018

Underlying RC profit before interest and tax - by region
 
 
 
 
 
 
US
 
566

399

 
1,097

988

Non-US
 
799

1,056

 
2,001

2,293

 
 
1,365

1,455

 
3,098

3,281

Non-operating items
 
 
 
 
 
 
US
 
2

(155
)
 
3

(172
)
Non-US
 
(33
)
(70
)
 
(38
)
(106
)
 
 
(31
)
(225
)
 
(35
)
(278
)
Fair value accounting effects(a)
 
 
 
 
 
 
US
 
8

(299
)
 
69

(420
)
Non-US
 
(54
)
(91
)
 
(79
)
(30
)
 
 
(46
)
(390
)
 
(10
)
(450
)
RC profit before interest and tax
 
 
 
 
 
 
US
 
576

(55
)
 
1,169

396

Non-US
 
712

895

 
1,884

2,157

 
 
1,288

840

 
3,053

2,553

Underlying RC profit before interest and tax - by business(b)(c)
 
 
 
 
 
 
Fuels
 
961

1,054

 
2,253

2,452

Lubricants
 
321

326

 
593

657

Petrochemicals
 
83

75

 
252

172

 
 
1,365

1,455

 
3,098

3,281

Non-operating items and fair value accounting effects(a)
 
 
 
 
 
 
Fuels
 
(99
)
(584
)
 
(62
)
(694
)
Lubricants
 
22

(26
)
 
18

(29
)
Petrochemicals
 
—

(5
)
 
(1
)
(5
)
 
 
(77
)
(615
)
 
(45
)
(728
)
RC profit before interest and tax(b)(c)
 
 
 
 
 
 
Fuels
 
862

470

 
2,191

1,758

Lubricants
 
343

300

 
611

628

Petrochemicals
 
83

70

 
251

167

 
 
1,288

840

 
3,053

2,553

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

14.9

 
12.7

13.3

 
 
 
 
 
 
 
Refinery throughputs (mb/d)
 
 
 
 
 
 
US
 
673

666

 
703

690

Europe
 
715

786

 
741

792

Rest of World
 
209

228

 
223

238

 
 
1,597

1,680

 
1,667

1,720

BP-operated refining availability* (%)
 
93.4

93.1

 
93.9

94.0

 
 
 
 
 
 
 
Marketing sales of refined products (mb/d)
 
 
 
 
 
 
US
 
1,174

1,161

 
1,126

1,129

Europe
 
1,091

1,135

 
1,042

1,090

Rest of World
 
520

477

 
520

479

 
 
2,785

2,773

 
2,688

2,698

Trading/supply sales of refined products
 
3,099

3,247

 
3,197

3,215

Total sales volumes of refined products
 
5,884

6,020

 
5,885

5,913

 
 
 
 
 
 
 
Petrochemicals production (kte)
 
 
 
 
 
 
US
 
584

404

 
1,185

903

Europe
 
1,226

1,094

 
2,386

2,222

Rest of World
 
1,156

1,358

 
2,455

2,749

 
 
2,966

2,856

 
6,026

5,874

(a)
For Downstream, fair value accounting effects arise solely in the fuels business. See page 38 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.


12

Rosneft
 
 
Second

Second

 
First

First

 
 
quarter

quarter

 
half

half

$ million
 
2019(a)

2018

 
2019(a)

2018

Profit before interest and tax(b)(c)
 
523

876

 
1,049

1,145

Inventory holding (gains) losses*
 
2

(110
)
 
(38
)
(132
)
RC profit before interest and tax
 
525

766

 
1,011

1,013

Net charge (credit) for non-operating items*
 
113

—

 
194

—

Underlying RC profit before interest and tax*
 
638

766

 
1,205

1,013

Financial results
Replacement cost (RC) profit before interest and tax for the second quarter and half year was $525 million and $1,011 million respectively, compared with $766 million and $1,013 million for the same periods in 2018.
After adjusting for non-operating items, the underlying RC profit before interest and tax for the second quarter and half year was $638 million and $1,205 million respectively. There were no non-operating items in the second quarter and half year in 2018.
Compared with the same periods in 2018, the result for the second quarter primarily reflects lower oil prices, adverse effects of duty lag and foreign exchange, whilst the result for the half year was primarily affected by favourable foreign exchange effects partially offset by lower oil prices.
BP’s two nominees, Bob Dudley and Guillermo Quintero, were re-elected to Rosneft’s board at Rosneft's annual general meeting (AGM) on 4 June 2019. At the AGM, shareholders also approved a resolution to pay a dividend of 11.33 roubles per ordinary share, which brings the total dividend for 2018 to 25.91 roubles per ordinary share, constituting 50% of the company’s IFRS net profit. BP received a payment of $334 million, after the deduction of withholding tax, on 16 July.



 
 
Second

Second

 
First

First

 
 
quarter

quarter

 
half

half

 
 
2019(a)

2018

 
2019(a)

2018

Production (net of royalties) (BP share)
 
 
 
 
 
 
Liquids* (mb/d)
 
912

909

 
924

906

Natural gas (mmcf/d)
 
1,250

1,262

 
1,288

1,285

Total hydrocarbons* (mboe/d)
 
1,127

1,127

 
1,146

1,127

(a)
The operational and financial information of the Rosneft segment for the second quarter and half year is based on preliminary operational and financial results of Rosneft for the three months and six months ended 30 June 2019. Actual results may differ from these amounts.
(b)
The Rosneft segment result includes equity-accounted earnings arising from BP’s 19.75% shareholding in Rosneft as adjusted for the accounting required under IFRS relating to BP’s purchase of its interest in Rosneft and the amortization of the deferred gain relating to the divestment of BP’s interest in TNK-BP. These adjustments increase the segment's reported profit before interest and tax, as shown in the table above, compared with the amounts reported in Rosneft’s IFRS financial statements.
(c)
BP’s adjusted share of Rosneft’s earnings after Rosneft's own finance costs, taxation and non-controlling interests is included in the BP group income statement within profit before interest and taxation. For each year-to-date period it is calculated by translating the amounts reported in Russian roubles into US dollars using the average exchange rate for the year to date.


13

Other businesses and corporate
 
 
Second

Second

 
First

First

 
 
quarter

quarter

 
half

half

$ million
 
2019

2018

 
2019

2018

Sales and other operating revenues(a)
 
433

376

 
789

719

Profit (loss) before interest and tax
 
(381
)
(1,025
)
 
(927
)
(1,596
)
Inventory holding (gains) losses*
 
—

—

 
—

—

RC profit (loss) before interest and tax
 
(381
)
(1,025
)
 
(927
)
(1,596
)
Net charge (credit) for non-operating items*
 
91

548

 
219

727

Underlying RC profit (loss) before interest and tax*
 
(290
)
(477
)
 
(708
)
(869
)
Underlying RC profit (loss) before interest and tax
 
 
 
 
 
 
US
 
(224
)
(123
)
 
(379
)
(270
)
Non-US
 
(66
)
(354
)
 
(329
)
(599
)
 
 
(290
)
(477
)
 
(708
)
(869
)
Non-operating items
 
 
 
 
 
 
US
 
(78
)
(498
)
 
(206
)
(646
)
Non-US
 
(13
)
(50
)
 
(13
)
(81
)
 
 
(91
)
(548
)
 
(219
)
(727
)
RC profit (loss) before interest and tax
 
 
 
 
 
 
US
 
(302
)
(621
)
 
(585
)
(916
)
Non-US
 
(79
)
(404
)
 
(342
)
(680
)
 
 
(381
)
(1,025
)
 
(927
)
(1,596
)

(a)
Includes sales to other segments.

Other businesses and corporate comprises our alternative energy business, shipping, treasury, BP ventures and corporate activities including centralized functions, and any residual costs of the Gulf of Mexico oil spill.
Financial results
The replacement cost loss before interest and tax for the second quarter and half year was $381 million and $927 million respectively, compared with $1,025 million and $1,596 million for the same periods in 2018.
The results included a net non-operating charge of $91 million for the second quarter and a charge of $219 million for the half year, primarily relating to costs of the Gulf of Mexico oil spill, compared with a charge of $548 million and $727 million for the same periods in 2018.
After adjusting for non-operating items, the underlying replacement cost loss before interest and tax for the second quarter and half year was $290 million and $708 million respectively, compared with $477 million and $869 million for the same periods in 2018.

Alternative Energy
The net ethanol-equivalent production (which includes ethanol and sugar) for the second quarter and half year was 254 million litres and 268 million litres respectively, compared with 259 million litres and 267 million litres for the same periods in 2018.
Net wind generation capacity* was 926MW at 30 June 2019, compared with 1,432MW at 30 June 2018. BP’s net share of wind generation for the second quarter and half year was 688GWh and 1,461GWh respectively, compared with 984GWh and 2,201GWh for the same periods in 2018. The lower production and reduced capacity in 2019 is due to divestments in the fourth quarter of 2018 and second quarter of 2019.

Lightsource BP (an equity-accounted entity, in which BP holds 43%) manages a total portfolio of 2GW of operating solar facilities, of which 1.3GW was developed in-house. During the second quarter, Lightsource BP announced expansion of its activities in Brazil, acquiring a 1.9GW portfolio of greenfield solar projects from Enerlife. In the US, Lightsource BP has executed a long-term agreement to supply renewable power from a 100MW solar facility in Alabama and has also begun construction of a 20MW solar facility in Kansas. This builds on the first quarter announcement that the Green Growth Equity Fund, managed by Lightsource BP's Indian joint venture, EverSource Capital, is partnering with the National Investment and Infrastructure Fund (NIIF) and CDC Group plc to invest a total of $330 million in Ayana Renewable Power. Ayana was launched to develop utility scale solar and wind generation projects in India.

On 22 July, BP and Bunge Limited announced that they had agreed to form a 50:50 joint venture, BP Bunge Bioenergia, that will create a leading bioenergy company in Brazil. On completion, BP’s interest in the venture will increase its existing biofuels business by more than 50% and create opportunities to drive value from economies of scale, synergy and modernization of operations. The venture will have 11 biofuels sites in Brazil, with 32 million metric tonnes of combined crushing capacity per year. It will also generate renewable electricity – fuelled by waste biomass from the sugar cane – through its cogeneration facilities to power all its sites and sell surplus electricity to the Brazilian power grid.
In 2018, the two businesses produced a total of around 2.2 billion litres of ethanol equivalent and, after powering the sites, exported 1,200 gigawatt hours of low-carbon biopower to the national grid. Together the two businesses currently employ over 10,000 people in Brazil.

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

Outlook
During 2019, Other businesses and corporate average quarterly charges, excluding non-operating items, are expected to be around $350 million although this will fluctuate quarter to quarter.

The commentary above contains forward-looking statements and should be read in conjunction with the cautionary statement on page 47.


14

Financial statements
Group income statement
 
 
Second

Second

 
First

First

 
 
quarter

quarter

 
half

half

$ million
 
2019

2018

 
2019

2018

 
 
 
 
 
 
 
Sales and other operating revenues (Note 4)
 
72,676

75,439

 
138,997

143,611

Earnings from joint ventures – after interest and tax
 
138

220

 
323

513

Earnings from associates – after interest and tax
 
608

1,027

 
1,257

1,441

Interest and other income
 
270

165

 
433

324

Gains on sale of businesses and fixed assets
 
55

56

 
144

161

Total revenues and other income
 
73,747

76,907

 
141,154

146,050

Purchases
 
55,683

58,424

 
103,955

109,936

Production and manufacturing expenses
 
5,391

5,515

 
10,747

10,953

Production and similar taxes (Note 6)
 
371

531

 
795

899

Depreciation, depletion and amortization (Note 5)
 
4,588

3,811

 
9,049

7,742

Impairment and losses on sale of businesses and fixed assets
 
906

(23
)
 
1,002

68

Exploration expense
 
146

164

 
513

678

Distribution and administration expenses
 
2,646

2,929

 
5,413

5,723

Profit (loss) before interest and taxation
 
4,016

5,556

 
9,680

10,051

Finance costs
 
853

535

 
1,720

1,088

Net finance expense relating to pensions and other post-retirement benefits
 
15

31

 
30

62

Profit (loss) before taxation
 
3,148

4,990

 
7,930

8,901

Taxation
 
1,244

2,117

 
3,027

3,497

Profit (loss) for the period
 
1,904

2,873

 
4,903

5,404

Attributable to
 
 
 
 
 
 
BP shareholders
 
1,822

2,799

 
4,756

5,268

Non-controlling interests
 
82

74

 
147

136

 
 
1,904

2,873

 
4,903

5,404

 
 
 
 
 
 
 
Earnings per share (Note 7)
 
 
 
 
 
 
Profit (loss) for the period attributable to BP shareholders
 
 
 
 
 
 
Per ordinary share (cents)
 
 
 
 
 
 
Basic
 
8.95

14.03

 
23.47

26.42

Diluted
 
8.92

13.96

 
23.35

26.27

Per ADS (dollars)
 
 
 
 
 
 
Basic
 
0.54

0.84

 
1.41

1.59

Diluted
 
0.54

0.84

 
1.40

1.58




15

Condensed group statement of comprehensive income
 
 
Second

Second

 
First

First

 
 
quarter

quarter

 
half

half

$ million
 
2019

2018

 
2019

2018

 
 
 
 
 
 
 
Profit (loss) for the period
 
1,904

2,873

 
4,903

5,404

Other comprehensive income
 
 
 
 
 
 
Items that may be reclassified subsequently to profit or loss
 
 
 
 
 
 
Currency translation differences
 
131

(2,612
)
 
1,120

(2,081
)
Cash flow hedges and costs of hedging
 
133

(107
)
 
152

(189
)
Share of items relating to equity-accounted entities, net of tax
 
(30
)
(33
)
 
(80
)
122

Income tax relating to items that may be reclassified
 
(9
)
52

 
(43
)
(38
)
 
 
225

(2,700
)
 
1,149

(2,186
)
Items that will not be reclassified to profit or loss
 
 
 
 
 
 
Remeasurements of the net pension and other post-retirement benefit liability or asset
 
(39
)
1,714

 
(892
)
2,579

Cash flow hedges that will subsequently be transferred to the balance sheet
 
(7
)
(35
)
 
1

(22
)
Income tax relating to items that will not be reclassified
 
2

(557
)
 
275

(822
)
 
 
(44
)
1,122

 
(616
)
1,735

Other comprehensive income
 
181

(1,578
)
 
533

(451
)
Total comprehensive income
 
2,085

1,295

 
5,436

4,953

Attributable to
 
 
 
 
 
 
BP shareholders
 
2,001

1,268

 
5,282

4,848

Non-controlling interests
 
84

27

 
154

105

 
 
2,085

1,295

 
5,436

4,953


16

Condensed group statement of changes in equity
 
 
BP shareholders’

Non-controlling

Total

$ million
 
equity

interests

equity

At 31 December 2018
 
99,444

2,104

101,548

Adjustment on adoption of IFRS 16, net of tax(a)
 
(329
)
(1
)
(330
)
At 1 January 2019
 
99,115

2,103

101,218

 
 
 
 
 
Total comprehensive income
 
5,282

154

5,436

Dividends
 
(3,200
)
(119
)
(3,319
)
Cash flow hedges transferred to the balance sheet, net of tax
 
12

—

12

Repurchase of ordinary share capital
 
(125
)
—

(125
)
Share-based payments, net of tax
 
398

—

398

Share of equity-accounted entities’ changes in equity, net of tax
 
3

—

3

At 30 June 2019
 
101,485

2,138

103,623

 
 
 
 
 
 
 
BP shareholders’

Non-controlling

Total

$ million
 
equity

interests

equity

At 31 December 2017
 
98,491

1,913

100,404

Adjustment on adoption of IFRS 9, net of tax(b)
 
(180
)
—

(180
)
At 1 January 2018
 
98,311

1,913

100,224

 
 
 
 
 
Total comprehensive income
 
4,848

105

4,953

Dividends
 
(3,556
)
(70
)
(3,626
)
Cash flow hedges transferred to the balance sheet, net of tax
 
5

—

5

Repurchase of ordinary share capital
 
(200
)
—

(200
)
Share-based payments, net of tax
 
414

—

414

Transactions involving non-controlling interests, net of tax
 
(1
)
1

—

At 30 June 2018
 
99,821

1,949

101,770

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



17

Group balance sheet
 
 
30 June

31 December

$ million
 
2019

2018(a)

Non-current assets
 
 
 
Property, plant and equipment
 
145,291

135,261

Goodwill
 
12,158

12,204

Intangible assets
 
15,631

17,284

Investments in joint ventures
 
8,637

8,647

Investments in associates
 
19,587

17,673

Other investments
 
1,250

1,341

Fixed assets
 
202,554

192,410

Loans
 
689

637

Trade and other receivables
 
2,146

1,834

Derivative financial instruments
 
6,014

5,145

Prepayments
 
776

1,179

Deferred tax assets
 
3,624

3,706

Defined benefit pension plan surpluses
 
5,816

5,955

 
 
221,619

210,866

Current assets
 
 
 
Loans
 
313

326

Inventories
 
20,042

17,988

Trade and other receivables
 
24,343

24,478

Derivative financial instruments
 
3,384

3,846

Prepayments
 
1,001

963

Current tax receivable
 
930

1,019

Other investments
 
135

222

Cash and cash equivalents
 
20,674

22,468

 
 
70,822

71,310

Assets classified as held for sale (Note 2)
 
721

—

 
 
71,543

71,310

Total assets
 
293,162

282,176

Current liabilities
 
 
 
Trade and other payables
 
44,774

46,265

Derivative financial instruments
 
2,601

3,308

Accruals
 
4,143

4,626

Lease liabilities
 
2,094

44

Finance debt
 
8,677

9,329

Current tax payable
 
2,384

2,101

Provisions
 
2,070

2,564

 
 
66,743

68,237

Liabilities directly associated with assets classified as held for sale (Note 2)
 
112

—

 
 
66,855

68,237

Non-current liabilities
 
 
 
Other payables
 
12,654

13,830

Derivative financial instruments
 
5,187

5,625

Accruals
 
610

575

Lease liabilities
 
8,285

623

Finance debt
 
58,876

55,803

Deferred tax liabilities
 
9,672

9,812

Provisions
 
18,393

17,732

Defined benefit pension plan and other post-retirement benefit plan deficits
 
9,007

8,391

 
 
122,684

112,391

Total liabilities
 
189,539

180,628

Net assets
 
103,623

101,548

Equity
 
 
 
BP shareholders’ equity
 
101,485

99,444

Non-controlling interests
 
2,138

2,104

Total equity
 
103,623

101,548

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


18

Condensed group cash flow statement
 
 
Second

Second

 
First

First

 
 
quarter

quarter

 
half

half

$ million
 
2019

2018

 
2019

2018

Operating activities
 
 
 
 
 
 
Profit (loss) before taxation
 
3,148

4,990

 
7,930

8,901

Adjustments to reconcile profit (loss) before taxation to net cash provided by operating activities
 
 
 
 
 
 
Depreciation, depletion and amortization and exploration expenditure written off
 
4,665

3,892

 
9,410

8,249

Impairment and (gain) loss on sale of businesses and fixed assets
 
851

(79
)
 
858

(93
)
Earnings from equity-accounted entities, less dividends received
 
(395
)
(988
)
 
(984
)
(1,524
)
Net charge for interest and other finance expense, less net interest paid
 
62

191

 
150

271

Share-based payments
 
117

167

 
414

404

Net operating charge for pensions and other post-retirement benefits, less contributions and benefit payments for unfunded plans
 
(68
)
(62
)
 
(145
)
(264
)
Net charge for provisions, less payments
 
(198
)
80

 
(314
)
224

Movements in inventories and other current and non-current assets and liabilities
 
(58
)
(570
)
 
(2,753
)
(3,968
)
Income taxes paid
 
(1,309
)
(1,315
)
 
(2,455
)
(2,248
)
Net cash provided by operating activities
 
6,815

6,306

 
12,111

9,952

Investing activities
 
 
 
 
 
 
Expenditure on property, plant and equipment, intangible and other assets
 
(3,833
)
(3,484
)
 
(7,528
)
(7,070
)
Acquisitions, net of cash acquired
 
(1,747
)
(1
)
 
(3,542
)
(1
)
Investment in joint ventures
 
(20
)
(18
)
 
(20
)
(57
)
Investment in associates
 
(54
)
(322
)
 
(199
)
(660
)
Total cash capital expenditure
 
(5,654
)
(3,825
)
 
(11,289
)
(7,788
)
Proceeds from disposal of fixed assets
 
70

105

 
305

190

Proceeds from disposal of businesses, net of cash disposed
 
8

45

 
373

127

Proceeds from loan repayments
 
64

24

 
119

33

Net cash used in investing activities
 
(5,512
)
(3,651
)
 
(10,492
)
(7,438
)
Financing activities(a)
 
 
 
 
 
 
Net issue (repurchase) of shares
 
(80
)
(90
)
 
(125
)
(200
)
Lease liability payments
 
(595
)
(4
)
 
(1,212
)
(14
)
Proceeds from long-term financing
 
4,381

910

 
6,505

1,032

Repayments of long-term financing
 
(3,602
)
(1,722
)
 
(6,242
)
(2,869
)
Net increase (decrease) in short-term debt
 
(119
)
292

 
970

(57
)
Net increase (decrease) in non-controlling interests
 
—

—

 
—

(1
)
Dividends paid - BP shareholders
 
(1,779
)
(1,727
)
 
(3,214
)
(3,556
)
 - non-controlling interests
 
(83
)
(57
)
 
(119
)
(70
)
Net cash provided by (used in) financing activities
 
(1,877
)
(2,398
)
 
(3,437
)
(5,735
)
Currency translation differences relating to cash and cash equivalents
 
(8
)
(314
)
 
24

(169
)
Increase (decrease) in cash and cash equivalents
 
(582
)
(57
)
 
(1,794
)
(3,390
)
Cash and cash equivalents at beginning of period
 
21,256

22,242

 
22,468

25,575

Cash and cash equivalents at end of period
 
20,674

22,185

 
20,674

22,185

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



19

Notes
Note 1. Basis of preparation

The interim financial information included in this report has been prepared in accordance with IAS 34 'Interim Financial Reporting'.
The results for the interim periods are unaudited and, in the opinion of management, include all adjustments necessary for a fair presentation of the results for each period. All such adjustments are of a normal recurring nature. This report should be read in conjunction with the consolidated financial statements and related notes for the year ended 31 December 2018 included in BP Annual Report and Form 20-F 2018.
The directors consider it appropriate to adopt the going concern basis of accounting in preparing these interim financial statements.
BP prepares its consolidated financial statements included within BP Annual Report and Form 20-F on the basis of International Financial Reporting Standards (IFRS) as issued by the International Accounting Standards Board (IASB), IFRS as adopted by the European Union (EU) and in accordance with the provisions of the UK Companies Act 2006 as applicable to companies reporting under IFRS. IFRS as adopted by the EU differs in certain respects from IFRS as issued by the IASB. The differences have no impact on the group’s consolidated financial statements for the periods presented.
The financial information presented herein has been prepared in accordance with the accounting policies expected to be used in preparing BP Annual Report and Form 20-F 2019, which are the same as those used in preparing BP Annual Report and Form 20-F 2018 with the exception of the adoption of IFRS 16 'Leases' from 1 January 2019.

New International Financial Reporting Standards adopted
BP adopted IFRS 16 ‘Leases’, which replaced IAS 17 ‘Leases’ and IFRIC 4 ‘Determining whether an arrangement contains a lease’, with effect from 1 January 2019. Further information is included in BP Annual Report and Form 20-F 2018 - Financial statements - Note 1 Significant accounting policies, judgements, estimates and assumptions - Impact of new International Financial Reporting Standards.
IFRS 16 provides a new model for lessee accounting in which the majority of leases are accounted for by the recognition on the balance sheet of a right-of-use asset and a lease liability.
Agreements that convey the right to control the use of an identified asset for a period of time in exchange for consideration are accounted for as leases. A lease liability is recognized at the present value of future lease payments over the reasonably certain lease term. Variable lease payments that do not depend on an index or a rate are not included in the lease liability. The right-of-use asset is recognized at a value equivalent to the initial measurement of the lease liability adjusted for lease prepayments, lease incentives, initial direct costs and any restoration obligations. The subsequent amortization of the right-of-use asset and the interest expense related to the lease liability are recognized in the income statement over the lease term.
The group recognizes the full lease liability, rather than its working interest share, for leases entered into on behalf of a joint operation if the group has the primary responsibility for making the lease payments. If the right-of-use asset is jointly controlled by the group and the other joint operators, a receivable is recognized for the share of the asset transferred to the other joint operators.
BP elected to apply the modified retrospective transition approach in which the cumulative effect of initial application is recognized in opening retained earnings at the date of initial application with no restatement of comparative periods’ financial information. Comparative information in the group balance sheet and group cash flow statement has, however, been re-presented to align with current year presentation, showing lease liabilities and lease liability payments as separate line items. These were previously included within the finance debt and repayments of long-term financing line items respectively. Amounts presented in these line items for the comparative periods relate to leases accounted for as finance leases under IAS 17.
IFRS 16 introduces a revised definition of a lease. As permitted by the standard, BP elected not to reassess the existing population of leases under the new definition and will only apply the new definition for the assessment of contracts entered into after the transition date. On transition the standard permits, on a lease-by-lease basis, the right-of-use asset to be measured either at an amount equal to the lease liability (as adjusted for prepaid or accrued lease payments), or on a historical basis as if the standard had always applied. BP elected to use the historical asset measurement for its more material leases and used the asset equals liability approach for the remainder of the population. BP also elected to adjust the carrying amounts of the right-of-use assets as at 1 January 2019 for onerous lease provisions that had been recognized on the group balance sheet as at 31 December 2018, rather than performing impairment tests on transition.
The effect of the adoption of IFRS 16 on the group balance sheet is set out below.


20

Note 1. Basis of preparation (continued)
 
 
 
 
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



21

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

On 3 June 2019 BP announced that it had agreed to sell its interests in Gulf of Suez oil concessions in Egypt to Dragon Oil. Under the terms of the agreement, Dragon Oil will purchase producing and exploration concessions and BP's interest in the Gulf of Suez Petroleum Company (GUPCO). The deal, which is subject to the Egyptian Ministry of Petroleum and Mineral Resources' approval, is expected to complete during the second half of 2019. Assets and associated liabilities relating to these concessions, which are reported in the Upstream segment, have been classified as held for sale in the group balance sheet.
On 22 July, BP and Bunge announced that they will each contribute their existing Brazilian biofuel, biopower and sugar businesses into a new 50:50 joint venture. Assets and associated liabilities relating to the BP businesses will be classified as held for sale in the group’s balance sheet from 22 July. Subject to satisfaction of conditions precedent, including obtaining the necessary regulatory clearances and approval, the deal is expected to complete in the fourth quarter of 2019.


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

Second

 
First

First

 
 
quarter

quarter

 
half

half

$ million
 
2019

2018

 
2019

2018

Upstream
 
2,469

3,514

 
5,353

6,688

Downstream
 
1,288

840

 
3,053

2,553

Rosneft
 
525

766

 
1,011

1,013

Other businesses and corporate
 
(381
)
(1,025
)
 
(927
)
(1,596
)
 
 
3,901

4,095

 
8,490

8,658

Consolidation adjustment – UPII*
 
34

151

 
21

(9
)
RC profit (loss) before interest and tax*
 
3,935

4,246

 
8,511

8,649

Inventory holding gains (losses)*
 
 
 
 
 
 
Upstream
 
(10
)
4

 
(8
)
5

Downstream
 
93

1,196

 
1,139

1,265

Rosneft (net of tax)
 
(2
)
110

 
38

132

Profit (loss) before interest and tax
 
4,016

5,556

 
9,680

10,051

Finance costs
 
853

535

 
1,720

1,088

Net finance expense relating to pensions and other post-retirement benefits
 
15

31

 
30

62

Profit (loss) before taxation
 
3,148

4,990

 
7,930

8,901

 
 
 
 
 
 
 
RC profit (loss) before interest and tax*
 
 
 
 
 
 
US
 
498

(20
)
 
1,269

339

Non-US
 
3,437

4,266

 
7,242

8,310

 
 
3,935

4,246

 
8,511

8,649





22

Note 4. Sales and other operating revenues
 
 
Second

Second

 
First

First

 
 
quarter

quarter

 
half

half

$ million
 
2019

2018

 
2019

2018

By segment
 
 
 
 
 
 
Upstream
 
13,556

12,698

 
28,150

26,568

Downstream
 
66,396

69,174

 
124,812

130,580

Other businesses and corporate
 
433

376

 
789

719

 
 
80,385

82,248

 
153,751

157,867

 
 
 
 
 
 
 
Less: sales and other operating revenues between segments
 
 
 
 
 
 
Upstream
 
7,481

5,795

 
13,805

12,528

Downstream
 
62

785

 
648

1,267

Other businesses and corporate
 
166

229

 
301

461

 
 
7,709

6,809

 
14,754

14,256

 
 
 
 
 
 
 
Third party sales and other operating revenues
 
 
 
 
 
 
Upstream
 
6,075

6,903

 
14,345

14,040

Downstream
 
66,334

68,389

 
124,164

129,313

Other businesses and corporate
 
267

147

 
488

258

Total sales and other operating revenues
 
72,676

75,439

 
138,997

143,611

 
 
 
 
 
 
 
By geographical area
 
 
 
 
 
 
US
 
26,086

26,676

 
47,934

50,289

Non-US
 
52,933

56,032

 
102,551

107,272

 
 
79,019

82,708

 
150,485

157,561

Less: sales and other operating revenues between areas
 
6,343

7,269

 
11,488

13,950

 
 
72,676

75,439

 
138,997

143,611

 
 
 
 
 
 
 
Revenues from contracts with customers
 
 
 
 
 
 
Sales and other operating revenues include the following in relation to revenues from contracts with customers:
 
 
 
 
 
 
Crude oil
 
17,070

17,167

 
31,352

32,084

Oil products
 
46,999

51,440

 
89,582

95,570

Natural gas, LNG and NGLs
 
4,823

4,960

 
10,616

10,119

Non-oil products and other revenues from contracts with customers
 
3,173

3,081

 
6,674

6,576

 
 
72,065

76,648

 
138,224

144,349




Note 5. Depreciation, depletion and amortization
 
 
Second

Second

 
First

First

 
 
quarter

quarter

 
half

half

$ million
 
2019

2018

 
2019

2018

Upstream
 
 
 
 
 
 
US
 
1,288

999

 
2,401

2,087

Non-US
 
2,396

2,226

 
4,894

4,498

 
 
3,684

3,225

 
7,295

6,585

Downstream
 
 
 
 
 
 
US
 
333

221

 
656

440

Non-US
 
392

293

 
775

595

 
 
725

514

 
1,431

1,035

Other businesses and corporate
 
 
 
 
 
 
US
 
14

16

 
27

32

Non-US
 
165

56

 
296

90

 
 
179

72

 
323

122

Total group
 
4,588

3,811

 
9,049

7,742



23

Note 6. Production and similar taxes
 
 
Second

Second

 
First

First

 
 
quarter

quarter

 
half

half

$ million
 
2019

2018

 
2019

2018

US
 
79

89

 
160

179

Non-US
 
292

442

 
635

720

 
 
371

531

 
795

899



Note 7. Earnings per share and shares in issue
Basic earnings per ordinary share (EpS) amounts are calculated by dividing the profit (loss) for the period attributable to ordinary shareholders by the weighted average number of ordinary shares outstanding during the period. During the quarter the company repurchased for cancellation 11 million ordinary shares for a total cost of $75 million, as part of the share buyback programme as announced on 31 October 2017. This brings the total number of shares repurchased in the first half to 17 million for a total cost of $125 million. The number of shares in issue is reduced when shares are repurchased.
The calculation of EpS is performed separately for each discrete quarterly period, and for the year-to-date period. As a result, the sum of the discrete quarterly EpS amounts in any particular year-to-date period may not be equal to the EpS amount for the year-to-date period.
For the diluted EpS calculation the weighted average number of shares outstanding during the period is adjusted for the number of shares that are potentially issuable in connection with employee share-based payment plans using the treasury stock method.
 
 
Second

Second

 
First

First

 
 
quarter

quarter

 
half

half

$ million
 
2019

2018

 
2019

2018

Results for the period
 
 
 
 
 
 
Profit (loss) for the period attributable to BP shareholders
 
1,822

2,799

 
4,756

5,268

Less: preference dividend
 
1

1

 
1

1

Profit (loss) attributable to BP ordinary shareholders
 
1,821

2,798

 
4,755

5,267

 
 
 
 
 
 
 
Number of shares (thousand)(a)
 
 
 
 
 
 
Basic weighted average number of shares outstanding
 
20,336,347

19,945,053

 
20,256,254

19,931,945

ADS equivalent
 
3,389,391

3,324,175

 
3,376,042

3,321,990

 
 
 
 
 
 
 
Weighted average number of shares outstanding used to calculate diluted earnings per share
 
20,421,184

20,044,277

 
20,368,125

20,050,123

ADS equivalent
 
3,403,530

3,340,712

 
3,394,687

3,341,687

 
 
 
 
 
 
 
Shares in issue at period-end
 
20,373,332

19,973,943

 
20,373,332

19,973,943

ADS equivalent
 
3,395,555

3,328,991

 
3,395,555

3,328,991

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

Issued ordinary share capital as at 30 June 2019 comprised 20,387,117,077 ordinary shares (31 December 2018 20,260,732,488 ordinary shares). This includes shares held in trust to settle future employee share plan obligations and excludes 1,257,120,831 ordinary shares which have been bought back and are held in treasury by BP (31 December 2018 1,264,731,539 ordinary shares).

24

Note 8. Dividends
Dividends payable
BP today announced an interim dividend of 10.25 cents per ordinary share which is expected to be paid on 20 September 2019 to ordinary shareholders and American Depositary Share (ADS) holders on the register on 9 August 2019. The corresponding amount in sterling is due to be announced on 10 September 2019, calculated based on the average of the market exchange rates for the four dealing days commencing on 4 September 2019. Holders of ADSs are expected to receive $0.615 per ADS (less applicable fees). A scrip dividend alternative is available, allowing shareholders to elect to receive their dividend in the form of new ordinary shares and ADS holders in the form of new ADSs. Details of the second quarter dividend and timetable are available at bp.com/dividends and details of the scrip dividend programme are available at bp.com/scrip.
 
 
Second

Second

 
First

First

 
 
quarter

quarter

 
half

half

 
 
2019

2018

 
2019

2018

Dividends paid per ordinary share
 
 
 
 
 
 
cents
 
10.250

10.000

 
20.500

20.000

pence
 
8.066

7.444

 
15.804

14.613

Dividends paid per ADS (cents)
 
61.50

60.00

 
123.00

120.00

Scrip dividends
 
 
 
 
 
 
Number of shares issued (millions)
 
46.3

34.5

 
136.4

57.9

Value of shares issued ($ million)
 
318

266

 
947

421

Note 9. Net debt and net debt including leases
Net debt*
 
Second

Second

 
First

First

 
 
 
quarter

quarter

 
half

half

Year

$ million
 
2019

2018

 
2019

2018

2018

Finance debt(a)
 
67,553

59,739

 
67,553

59,739

65,132

Fair value (asset) liability of hedges related to finance debt(b)
 
(378
)
1,104

 
(378
)
1,104

813

 
 
67,175

60,843

 
67,175

60,843

65,945

Less: cash and cash equivalents
 
20,674

22,185

 
20,674

22,185

22,468

Net debt
 
46,501

38,658

 
46,501

38,658

43,477

Equity
 
103,623

101,770

 
103,623

101,770

101,548

Gearing
 
31.0
%
27.5
%
 
31.0
%
27.5
%
30.0
%
(a)
The fair value of finance debt at 30 June 2019 was $68,857 million (31 December 2018 $65,259 million).
(b)
Derivative financial instruments entered into for the purpose of managing interest rate and foreign currency exchange risk associated with net debt with a fair value liability position of $563 million (first quarter 2019 liability of $609 million and second quarter 2018 liability of $774 million) are not included in the calculation of net debt shown above as hedge accounting is not applied for these instruments.

As a result of the adoption of IFRS 16 ‘Leases’, leases that were previously classified as finance leases under IAS 17 are now presented as ‘Lease liabilities’ on the group balance sheet and therefore do not form part of finance debt. Comparative information for finance debt (previously termed ‘gross debt’), net debt and gearing (previously termed 'net debt ratio') have been amended to be on a consistent basis with amounts presented for 2019. The relevant amount for finance lease liabilities that has been excluded from comparative information for the second quarter and first half 2018 is $619 million. The previously disclosed amount for finance debt for the second quarter and first half 2018 was $60,358 million. The previously disclosed amount for net debt for the second quarter and first half 2018 was $39,277 million. The previously disclosed gearing for the second quarter and first half 2018 was 27.8%.
Net debt including leases*
 
Second

Second

 
First

First

 
 
 
quarter

quarter

 
half

half

Year

$ million
 
2019

2018

 
2019

2018

2018

Net debt
 
46,501

38,658

 
46,501

38,658

43,477

Lease liabilities
 
10,379

619

 
10,379

619

667

Net partner (receivable) payable for leases entered into on behalf of joint operations
 
(230
)
—

 
(230
)
—

—

Net debt including leases
 
56,650

39,277

 
56,650

39,277

44,144





25

Note 10. Inventory valuation

A provision of $242 million was held against hydrocarbon inventories at 30 June 2019 ($38 million at 30 June 2018) to write them down to their net realizable value. The net movement charged to the income statement during the second quarter 2019 was $120 million (second quarter 2018 was a credit of $15 million).
Note 11. Statutory accounts

The financial information shown in this publication, which was approved by the Board of Directors on 29 July 2019, is unaudited and does not constitute statutory financial statements. Audited financial information will be published in BP Annual Report and Form 20-F 2019.

26

Note 12. Condensed consolidating information on certain US subsidiaries
BP p.l.c. fully and unconditionally guarantees the payment obligations of its 100%-owned subsidiary BP Exploration (Alaska) Inc. under the BP Prudhoe Bay Royalty Trust. The following financial information for BP p.l.c., BP Exploration (Alaska) Inc. and all other subsidiaries on a condensed consolidating basis is intended to provide investors with meaningful and comparable financial information about BP p.l.c. and its subsidiary issuers of registered securities and is provided pursuant to Rule 3-10 of Regulation S-X in lieu of the separate financial statements of each subsidiary issuer of public debt securities. Non-current assets for BP p.l.c. includes investments in subsidiaries recorded under the equity method for the purposes of the condensed consolidating financial information. Equity-accounted income of subsidiaries is the group’s share of profit related to such investments. The eliminations and reclassifications column includes the necessary amounts to eliminate the intercompany balances and transactions between BP p.l.c., BP Exploration (Alaska) Inc. and other subsidiaries. The financial information presented in the following tables for BP Exploration (Alaska) Inc. incorporates subsidiaries of BP Exploration (Alaska) Inc. using the equity method of accounting and excludes the BP group’s midstream operations in Alaska that are reported through different legal entities and that are included within the ‘other subsidiaries’ column in these tables. BP p.l.c. also fully and unconditionally guarantees securities issued by BP Capital Markets p.l.c. and BP Capital Markets America Inc. These companies are 100%-owned finance subsidiaries of BP p.l.c.
Income statement
First half 2019
 
Issuer

Guarantor

 
 
 
$ million
 
BP Exploration (Alaska) Inc.

BP p.l.c.

Other subsidiaries

Eliminations and reclassifications

BP group

Sales and other operating revenues
 
2,315

—

138,876

(2,194
)
138,997

Earnings from joint ventures - after interest and tax
 
—

—

323

—

323

Earnings from associates - after interest and tax
 
—

—

1,257

—

1,257

Equity-accounted income of subsidiaries - after interest and tax
 
—

5,713

—

(5,713
)
—

Interest and other income
 
26

155

1,203

(951
)
433

Gains on sale of businesses and fixed assets
 
4

—

140

—

144

Total revenues and other income
 
2,345

5,868

141,799

(8,858
)
141,154

Purchases
 
1,254

—

104,895

(2,194
)
103,955

Production and manufacturing expenses
 
471

—

10,276

—

10,747

Production and similar taxes
 
93

—

702

—

795

Depreciation, depletion and amortization
 
132

—

8,917

—

9,049

Impairment and losses on sale of businesses and fixed assets
 
—

—

1,002

—

1,002

Exploration expense
 
—

—

513

—

513

Distribution and administration expenses
 
11

386

5,048

(32
)
5,413

Profit (loss) before interest and taxation
 
384

5,482

10,446

(6,632
)
9,680

Finance costs
 
6

803

1,830

(919
)
1,720

Net finance (income) expense relating to pensions and other post-retirement benefits
 
—

(78
)
108

—

30

Profit (loss) before taxation
 
378

4,757

8,508

(5,713
)
7,930

Taxation
 
70

1

2,956

—

3,027

Profit (loss) for the year
 
308

4,756

5,552

(5,713
)
4,903

Attributable to
 
 
 
 
 
 
BP shareholders
 
308

4,756

5,405

(5,713
)
4,756

Non-controlling interests
 
—

—

147

—

147

 
 
308

4,756

5,552

(5,713
)
4,903



27

Note 12. Condensed consolidating information on certain US subsidiaries (continued)
Statement of comprehensive income
First half 2019
 
Issuer

Guarantor

 
 
 
$ million
 
BP Exploration (Alaska) Inc.

BP p.l.c.

Other subsidiaries

Eliminations and reclassifications

BP group

Profit (loss) for the year
 
308

4,756

5,552

(5,713
)
4,903

Other comprehensive income
 
 
 
 
 
 
Items that may be reclassified subsequently to profit or loss
 
 
 
 
 
 
Currency translation differences
 
—

(2
)
1,122

—

1,120

Cash flow hedges and costs of hedging
 
—

—

152

—

152

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

—

(80
)
—

(80
)
Income tax relating to items that may be reclassified
 
—

—

(43
)
—

(43
)
 
 
—

(2
)
1,151

—

1,149

Items that will not be reclassified to profit or loss
 
 
 
 
 
 
Remeasurements of the net pension and other post-retirement benefit liability or asset
 
—

(300
)
(592
)
—

(892
)
Cash flow hedges that will subsequently be transferred to the balance sheet
 
—

—

1

—

1

Income tax relating to items that will not be reclassified
 
—

—

275

—

275

 
 
—

(300
)
(316
)
—

(616
)
Other comprehensive income
 
—

(302
)
835

—

533

Equity-accounted other comprehensive income of subsidiaries
 
—

828

—

(828
)
—

Total comprehensive income
 
308

5,282

6,387

(6,541
)
5,436

Attributable to
 
 
 
 
 
 
  BP shareholders
 
308

5,282

6,233

(6,541
)
5,282

  Non-controlling interests
 
—

—

154

—

154

 
 
308

5,282

6,387

(6,541
)
5,436


28

Note 12. Condensed consolidating information on certain US subsidiaries (continued)
Income statement continued
First half 2018
 
Issuer

Guarantor

 
 
 
$ million
 
BP Exploration (Alaska) Inc.

BP p.l.c.

Other subsidiaries

Eliminations and reclassifications

BP group

Sales and other operating revenues
 
2,199

—

143,552

(2,140
)
143,611

Earnings from joint ventures - after interest and tax
 
—

—

513

—

513

Earnings from associates - after interest and tax
 
—

—

1,441

—

1,441

Equity-accounted income of subsidiaries - after interest and tax
 
—

6,028

—

(6,028
)
—

Interest and other income
 
18

112

893

(699
)
324

Gains on sale of businesses and fixed assets
 
—

—

161

—

161

Total revenues and other income
 
2,217

6,140

146,560

(8,867
)
146,050

Purchases
 
705

—

111,371

(2,140
)
109,936

Production and manufacturing expenses
 
481

—

10,472

—

10,953

Production and similar taxes
 
144

—

755

—

899

Depreciation, depletion and amortization
 
262

—

7,480

—

7,742

Impairment and losses on sale of businesses and fixed assets
 
—

—

68

—

68

Exploration expense
 
—

—

678

—

678

Distribution and administration expenses
 
10

344

5,402

(33
)
5,723

Profit (loss) before interest and taxation
 
615

5,796

10,334

(6,694
)
10,051

Finance costs
 
3

577

1,174

(666
)
1,088

Net finance (income) expense relating to pensions and other post-retirement benefits
 
—

(49
)
111

—

62

Profit (loss) before taxation
 
612

5,268

9,049

(6,028
)
8,901

Taxation
 
83

—

3,414

—

3,497

Profit (loss) for the year
 
529

5,268

5,635

(6,028
)
5,404

Attributable to
 
 
 
 
 
 
BP shareholders
 
529

5,268

5,499

(6,028
)
5,268

Non-controlling interests
 
—

—

136

—

136

 
 
529

5,268

5,635

(6,028
)
5,404


29

Note 12. Condensed consolidating information on certain US subsidiaries (continued)
Statement of comprehensive income continued
First half 2018
 
Issuer

Guarantor

 
 
 
$ million
 
BP Exploration (Alaska) Inc.

BP p.l.c.

Other subsidiaries

Eliminations and reclassifications

BP group

Profit (loss) for the year
 
529

5,268

5,635

(6,028
)
5,404

Other comprehensive income
 
 
 
 
 
 
Items that may be reclassified subsequently to profit or loss
 
 
 
 
 
 
Currency translation differences
 
—

(191
)
(1,890
)
—

(2,081
)
Cash flow hedges and costs of hedging
 
—

—

(189
)
—

(189
)
Share of items relating to equity-accounted entities, net of tax
 
—

—

122

—

122

Income tax relating to items that may be reclassified
 
—

—

(38
)
—

(38
)
 
 
—

(191
)
(1,995
)
—

(2,186
)
Items that will not be reclassified to profit or loss
 
 
 
 
 
 
Remeasurements of the net pension and other post-retirement benefit liability or asset
 
—

1,877

702

—

2,579

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

—

(22
)
—

(22
)
Income tax relating to items that will not be reclassified
 
—

—

(822
)
—

(822
)
 
 
—

1,877

(142
)
—

1,735

Other comprehensive income
 
—

1,686

(2,137
)
—

(451
)
Equity-accounted other comprehensive income of subsidiaries
 
—

(2,106
)
—

2,106

—

Total comprehensive income
 
529

4,848

3,498

(3,922
)
4,953

Attributable to
 
 
 
 
 
 
BP shareholders
 
529

4,848

3,393

(3,922
)
4,848

Non-controlling interests
 
—

—

105

—

105

 
 
529

4,848

3,498

(3,922
)
4,953




30

Note 12. Condensed consolidating information on certain US subsidiaries (continued)
Balance sheet
At 30 June 2019
 
Issuer

Guarantor

 
 
 
$ million
 
BP Exploration (Alaska) Inc.

BP p.l.c.

Other subsidiaries

Eliminations and reclassifications

BP group

Non-current assets
 
 
 
 
 
 
Property, plant and equipment
 
4,501

—

140,790

—

145,291

Goodwill
 
—

—

12,158

—

12,158

Intangible assets
 
608

—

15,023

—

15,631

Investments in joint ventures
 
—

—

8,637

—

8,637

Investments in associates
 
—

2

19,585

—

19,587

Other investments
 
—

—

1,250

—

1,250

Subsidiaries - equity-accounted basis
 
—

172,529

—

(172,529
)
—

Fixed assets
 
5,109

172,531

197,443

(172,529
)
202,554

Loans
 
9

—

27,422

(26,742
)
689

Trade and other receivables
 
13

2,599

2,133

(2,599
)
2,146

Derivative financial instruments
 
—

—

6,014

—

6,014

Prepayments
 
—

—

776

—

776

Deferred tax assets
 
—

—

3,624

—

3,624

Defined benefit pension plan surpluses
 
—

5,310

506

—

5,816

 
 
5,131

180,440

237,918

(201,870
)
221,619

Current assets
 
 
 
 
 
 
Loans
 
—

—

313

—

313

Inventories
 
322

—

19,720

—

20,042

Trade and other receivables
 
2,692

151

47,808

(26,308
)
24,343

Derivative financial instruments
 
—

—

3,384

—

3,384

Prepayments
 
41

—

960

—

1,001

Current tax receivable
 
—

—

930

—

930

Other investments
 
—

—

135

—

135

Cash and cash equivalents
 
—

1

20,673

—

20,674

 
 
3,055

152

93,923

(26,308
)
70,822

Assets classified as held for sale (Note 2)
 
—

—

721

—

721

 
 
3,055

152

94,644

(26,308
)
71,543

Total assets
 
8,186

180,592

332,562

(228,178
)
293,162

Current liabilities
 
 
 
 
 
 
Trade and other payables
 
600

23,653

46,829

(26,308
)
44,774

Derivative financial instruments
 
—

—

2,601

—

2,601

Accruals
 
53

36

4,054

—

4,143

Lease liabilities
 
23

—

2,071

—

2,094

Finance debt
 
—

—

8,677

—

8,677

Current tax payable
 
7

—

2,377

—

2,384

Provisions
 
1

—

2,069

—

2,070

 
 
684

23,689

68,678

(26,308
)
66,743

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

—

112

—

112

 
 
684

23,689

68,790

(26,308
)
66,855

Non-current liabilities
 
 
 
 
 
 
Other payables
 
1

26,758

15,236

(29,341
)
12,654

Derivative financial instruments
 
—

—

5,187

—

5,187

Accruals
 
—

—

610

—

610

Lease liabilities
 
68

—

8,217

—

8,285

Finance debt
 
—

—

58,876

—

58,876

Deferred tax liabilities
 
637

1,907

7,128

—

9,672

Provisions
 
672

—

17,721

—

18,393

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

203

8,804

—

9,007

 
 
1,378

28,868

121,779

(29,341
)
122,684

Total liabilities
 
2,062

52,557

190,569

(55,649
)
189,539

Net assets
 
6,124

128,035

141,993

(172,529
)
103,623

Equity
 
 
 
 
 
 
BP shareholders’ equity
 
6,124

128,035

139,855

(172,529
)
101,485

Non-controlling interests
 
—

—

2,138

—

2,138

 
 
6,124

128,035

141,993

(172,529
)
103,623


31

Note 12. Condensed consolidating information on certain US subsidiaries (continued)
Balance sheet continued
At 31 December 2018
 
Issuer

Guarantor

 
 
 
$ million
 
BP Exploration (Alaska) Inc.

BP p.l.c.

Other subsidiaries

Eliminations and reclassifications

BP group

Non-current assets
 
 
 
 
 
 
Property, plant and equipment
 
4,445

—

130,816

—

135,261

Goodwill
 
—

—

12,204

—

12,204

Intangible assets
 
598

—

16,686

—

17,284

Investments in joint ventures
 
—

—

8,647

—

8,647

Investments in associates
 
—

2

17,671

—

17,673

Other investments
 
—

—

1,341

—

1,341

Subsidiaries - equity-accounted basis
 
—

166,311

—

(166,311
)
—

Fixed assets
 
5,043

166,313

187,365

(166,311
)
192,410

Loans
 
—

—

32,402

(31,765
)
637

Trade and other receivables
 
—

2,600

1,834

(2,600
)
1,834

Derivative financial instruments
 
—

—

5,145

—

5,145

Prepayments
 
—

—

1,179

—

1,179

Deferred tax assets
 
—

—

3,706

—

3,706

Defined benefit pension plan surpluses
 
—

5,473

482

—

5,955

 
 
5,043

174,386

232,113

(200,676
)
210,866

Current assets
 
 
 
 
 
 
Loans
 
—

—

326

—

326

Inventories
 
302

—

17,686

—

17,988

Trade and other receivables
 
2,536

151

38,931

(17,140
)
24,478

Derivative financial instruments
 
—

—

3,846

—

3,846

Prepayments
 
7

—

956

—

963

Current tax receivable
 
—

—

1,019

—

1,019

Other investments
 
—

—

222

—

222

Cash and cash equivalents
 
—

13

22,455

—

22,468

 
 
2,845

164

85,441

(17,140
)
71,310

Total assets
 
7,888

174,550

317,554

(217,816
)
282,176

Current liabilities
 
 
 
 
 
 
Trade and other payables
 
413

14,634

48,358

(17,140
)
46,265

Derivative financial instruments
 
—

—

3,308

—

3,308

Accruals
 
89

31

4,506

—

4,626

Lease liabilities
 
—

—

44

—

44

Finance debt(a)
 
—

—

9,329

—

9,329

Current tax payable
 
310

—

1,791

—

2,101

Provisions
 
1

—

2,563

—

2,564

 
 
813

14,665

69,899

(17,140
)
68,237

Non-current liabilities
 
 
 
 
 
 
Other payables
 
—

31,800

16,395

(34,365
)
13,830

Derivative financial instruments
 
—

—

5,625

—

5,625

Accruals
 
—

—

575

—

575

Lease liabilities
 
—

—

623

—

623

Finance debt(a)
 
—

—

55,803

—

55,803

Deferred tax liabilities
 
586

1,907

7,319

—

9,812

Provisions
 
670

—

17,062

—

17,732

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

184

8,207

—

8,391

 
 
1,256

33,891

111,609

(34,365
)
112,391

Total liabilities
 
2,069

48,556

181,508

(51,505
)
180,628

Net assets
 
5,819

125,994

136,046

(166,311
)
101,548

Equity
 
 
 
 
 
 
BP shareholders’ equity
 
5,819

125,994

133,942

(166,311
)
99,444

Non-controlling interests
 
—

—

2,104

—

2,104

 
 
5,819

125,994

136,046

(166,311
)
101,548

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

32

Note 12. Condensed consolidating information on certain US subsidiaries (continued)
Cash flow statement
First half 2019
 
Issuer

Guarantor

 
 
 
$ million
 
BP Exploration (Alaska) Inc.

BP p.l.c.

Other subsidiaries

Eliminations and reclassifications

BP group

Operating activities
 
 
 
 
 
 
Profit (loss) before taxation
 
378

4,757

8,508

(5,713
)
7,930

Adjustments to reconcile profit (loss) before taxation to net cash provided by operating activities
 
 
 
 
 
 
Depreciation, depletion and amortization and exploration expenditure written off
 
132

—

9,278

—

9,410

Impairment and (gain) loss on sale of businesses and fixed assets
 
(4
)
—

862

—

858

Earnings from equity-accounted entities, less dividends received
 
—

—

(984
)
—

(984
)
Equity accounted income of subsidiaries - after interest and tax
 
—

(5,713
)
—

5,713

—

Dividends received from subsidiaries
 
—

(1
)
—

1

—

Net charge for interest and other finance expense, less net interest paid
 
4

(71
)
217

—

150

Share-based payments
 
—

404

10

—

414

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

(41
)
(104
)
—

(145
)
Net charge for provisions, less payments
 
24

—

(338
)
—

(314
)
Movements in inventories and other current and non-current assets and liabilities
 
(108
)
3,980

(6,625
)
—

(2,753
)
Income taxes paid
 
(321
)
(1
)
(2,133
)
—

(2,455
)
Net cash provided by operating activities
 
105

3,314

8,691

1

12,111

Investing activities
 
 
 
 
 
 
Expenditure on property, plant and equipment, intangible and other assets
 
(109
)
—

(7,419
)
—

(7,528
)
Acquisitions, net of cash acquired
 
—

—

(3,542
)
—

(3,542
)
Investment in joint ventures
 
—

—

(20
)
—

(20
)
Investment in associates
 
—

—

(199
)
—

(199
)
Total cash capital expenditure
 
(109
)
—

(11,180
)
—

(11,289
)
Proceeds from disposal of fixed assets
 
15

—

290

—

305

Proceeds from disposal of businesses, net of cash disposed
 
—

—

373

—

373

Proceeds from loan repayments
 
9

—

110

—

119

Net cash used in investing activities
 
(85
)
—

(10,407
)
—

(10,492
)
Financing activities(a)
 
 
 
 
 
 
Net issue (repurchase) of shares
 
—

(125
)
—

—

(125
)
Lease liability payments
 
(20
)
—

(1,192
)
—

(1,212
)
Proceeds from long-term financing
 
—

—

6,505

—

6,505

Repayments of long-term financing
 
—

—

(6,242
)
—

(6,242
)
Net increase (decrease) in short-term debt
 
—

—

970

—

970

Net increase (decrease) in non-controlling interests
 
—

—

—

—

—

Dividends paid - BP shareholders
 
—

(3,201
)
(12
)
(1
)
(3,214
)
 - non-controlling interests
 
—

—

(119
)
—

(119
)
Net cash provided by (used in) financing activities
 
(20
)
(3,326
)
(90
)
(1
)
(3,437
)
Currency translation differences relating to cash and cash equivalents
 
—

—

24

—

24

Increase (decrease) in cash and cash equivalents
 
—

(12
)
(1,782
)
—

(1,794
)
Cash and cash equivalents at beginning of period
 
—

13

22,455

—

22,468

Cash and cash equivalents at end of period
 
—

1

20,673

—

20,674



33

Note 12. Condensed consolidating information on certain US subsidiaries (continued)
Cash flow statement continued
First half 2018
 
Issuer

Guarantor

 
 
 
$ million
 
BP Exploration (Alaska) Inc.

BP p.l.c.

Other subsidiaries

Eliminations and reclassifications

BP group

Operating activities
 
 
 
 
 
 
Profit (loss) before taxation
 
612

5,268

9,049

(6,028
)
8,901

Adjustments to reconcile profit (loss) before taxation to net cash provided by operating activities
 
 
 
 
 
 
Depreciation, depletion and amortization and exploration expenditure written off
 
261

—

7,988

—

8,249

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

—

(93
)
—

(93
)
Earnings from equity-accounted entities, less dividends received
 
—

—

(1,524
)
—

(1,524
)
Equity accounted income of subsidiaries - after interest and tax
 
—

(6,028
)
—

6,028

—

Dividends received from subsidiaries
 
—

3

—

(3
)
—

Net charge for interest and other finance expense, less net interest paid
 
3

(49
)
317

—

271

Share-based payments
 
—

210

194

—

404

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

(160
)
(104
)
—

(264
)
Net charge for provisions, less payments
 
9

—

215

—

224

Movements in inventories and other current and non-current assets and liabilities
 
(703
)
4,299

(5,564
)
(2,000
)
(3,968
)
Income taxes paid
 
(11
)
—

(2,237
)
—

(2,248
)
Net cash provided by operating activities
 
171

3,543

8,241

(2,003
)
9,952

Investing activities
 
 
 
 
 
 
Expenditure on property, plant and equipment, intangible and other assets
 
(171
)
—

(6,899
)
—

(7,070
)
Acquisitions, net of cash acquired
 
—

—

(1
)
—

(1
)
Investment in joint ventures
 
—

—

(57
)
—

(57
)
Investment in associates
 
—

—

(660
)
—

(660
)
Total cash capital expenditure
 
(171
)
—

(7,617
)
—

(7,788
)
Proceeds from disposal of fixed assets
 
—

—

190

—

190

Proceeds from disposal of businesses, net of cash disposed
 
—

—

127

—

127

Proceeds from loan repayments
 
—

—

33

—

33

Net cash used in investing activities
 
(171
)
—

(7,267
)
—

(7,438
)
Financing activities(a)
 
 
 
 
 
 
Net issue (repurchase) of shares
 
—

18

(218
)
—

(200
)
Lease liability payments
 
—

—

(14
)
—

(14
)
Proceeds from long-term financing
 
—

—

1,032

—

1,032

Repayments of long-term financing
 
—

—

(2,869
)
—

(2,869
)
Net increase (decrease) in short-term debt
 
—

—

(57
)
—

(57
)
Net increase (decrease) in non-controlling interests
 
—

—

(1
)
—

(1
)
Dividends paid - BP shareholders
 
—

(3,556
)
(2,003
)
2,003

(3,556
)
 - non-controlling interests
 
—

—

(70
)
—

(70
)
Net cash provided by (used in) financing activities
 
—

(3,538
)
(4,200
)
2,003

(5,735
)
Currency translation differences relating to cash and cash equivalents
 
—

—

(169
)
—

(169
)
Increase (decrease) in cash and cash equivalents
 
—

5

(3,395
)
—

(3,390
)
Cash and cash equivalents at beginning of period
 
—

10

25,565

—

25,575

Cash and cash equivalents at end of period
 
—

15

22,170

—

22,185

(a)
Financing cash flows for the half year 2018 have been re-presented to align with the current period. See Note 1 for further information.

34

Additional information
Effects on the financial statements of the adoption of IFRS 16 ‘Leases’
BP adopted IFRS 16 ‘Leases’ with effect from 1 January 2019. The principal effects of the adoption are described below. BP elected to apply the modified retrospective transition approach in which the cumulative effect of initial application is recognized in opening retained earnings at the date of initial application with no restatement of comparative periods’ financial information. For further information of the effects of adoption see Financial statements - Note 1 and Note 9.
Balance sheet
As a result of the adoption of IFRS 16, $9.7 billion of right-of-use assets and $10.4 billion of lease liabilities have been included in the group balance sheet as at 30 June 2019. Lease liabilities are now presented separately on the group balance sheet and do not form part of finance debt. Comparative information for finance debt in the group balance sheet has been re-presented to align with current year presentation.
 
 
30 June

31 December

$ billion
 
2019

2018

Property, plant and equipment(a) (b)
 
9.7

0.5

Lease liabilities(a)
 
10.4

0.7

Finance debt
 
67.6

65.1

(a)
Comparative information represents finance leases accounted for under IAS 17.
(b)
Net additions to right-of-use assets for the second quarter and half year 2019 were $0.8 billion and $1.7 billion respectively.

Income statement
The presentation and timing of recognition of charges in the income statement has changed following the adoption of IFRS 16. The operating lease expense reported under the previous lease accounting standard, IAS 17, typically on a straight-line basis, has been replaced by depreciation of the right-of-use asset and interest on the lease liability. Depreciation of right-of-use assets for the second quarter and first half 2019 was $0.5 billion and $0.9 billion respectively. Interest on the group’s lease liabilities for the second quarter and first half 2019 was $0.1 billion and $0.2 billion respectively. Operating lease expenses were previously principally included within Production and manufacturing expenses and Distribution and administration expenses in the income statement. It is estimated that the resulting benefit to these line items is offset, in total, by an equivalent amount in depreciation and interest charges. Therefore, there has been no material overall effect on group profit measures in the second quarter of 2019.
Cash flow statement
Lease payments are now presented as financing cash flows, representing payments of principal, and as operating cash flows, representing payments of interest. In prior years, operating lease payments were presented as operating cash flows and capital expenditure. Of the $0.6 billion of lease payments included within financing activities for the second quarter of 2019, it is estimated that $0.5 billion would have been reported as operating cash flows and $0.1 billion would have been reported as capital expenditure cash flows ignoring the effects of IFRS 16. Of the $1.2 billion of lease payments included within financing activities for the first half 2019, it is estimated that $1.0 billion would have been reported as operating cash flows and $0.2 billion would have been reported as capital expenditure cash flows ignoring the effects of IFRS 16.
 
 
Second

Second

 
First

First

 
 
quarter

quarter

 
half

half

$ billion
 
2019

2018

 
2019

2018

Financing activities
 
 
 
 
 
 
Lease liability payments(a)
 
(0.6
)
—

 
(1.2
)
—

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


35

Capital expenditure*
 
 
Second

Second

 
First

First

 
 
quarter

quarter

 
half

half

$ million
 
2019

2018

 
2019

2018

Capital expenditure on a cash basis
 
 
 
 
 
 
Organic capital expenditure*
 
3,686

3,470

 
7,334

7,008

Inorganic capital expenditure*(a)
 
1,968

355

 
3,955

780

 
 
5,654

3,825

 
11,289

7,788


 
 
Second

Second

 
First

First

 
 
quarter

quarter

 
half

half

$ million
 
2019

2018

 
2019

2018

Organic capital expenditure by segment
 
 
 
 
 
 
Upstream
 
 
 
 
 
 
US
 
972

826

 
1,954

1,580

Non-US
 
1,858

1,941

 
3,746

4,053

 
 
2,830

2,767

 
5,700

5,633

Downstream
 
 
 
 
 
 
US
 
271

232

 
458

403

Non-US
 
470

382

 
1,004

829

 
 
741

614

 
1,462

1,232

Other businesses and corporate
 
 
 
 
 
 
US
 
15

7

 
24

14

Non-US
 
100

82

 
148

129

 
 
115

89

 
172

143

 
 
3,686

3,470

 
7,334

7,008

Organic capital expenditure by geographical area
 
 
 
 
 
 
US
 
1,258

1,065

 
2,436

1,997

Non-US
 
2,428

2,405

 
4,898

5,011

 
 
3,686

3,470

 
7,334

7,008

(a)
On 31 October 2018, BP acquired from BHP Billiton Petroleum (North America) Inc. 100% of the issued share capital of Petrohawk Energy Corporation, a wholly owned subsidiary of BHP that holds a portfolio of unconventional onshore US oil and gas assets. As at 30 June 2019, the entire consideration payable of $10,268 million, after customary closing adjustments, had been paid. This includes $1,748 million during the second quarter 2019. These amounts are included, net of cash acquired, in inorganic capital expenditure. First half 2019 and first half 2018 include amounts relating to the 25-year extension to our ACG production-sharing agreement* in Azerbaijan.




36

Non-operating items*
 
 
Second

Second

 
First

First

 
 
quarter

quarter

 
half

half

$ million
 
2019

2018(a)

 
2019

2018(a)

Upstream
 
 
 
 
 
 
Impairment and gain (loss) on sale of businesses and fixed assets(b)
 
(796
)
81

 
(807
)
107

Environmental and other provisions
 
—

—

 
—

—

Restructuring, integration and rationalization costs
 
(17
)
(62
)
 
(52
)
(61
)
Fair value gain (loss) on embedded derivatives
 
—

9

 
—

16

Other
 
47

(1
)
 
89

(139
)
 
 
(766
)
27

 
(770
)
(77
)
Downstream
 
 
 
 
 
 
Impairment and gain (loss) on sale of businesses and fixed assets
 
(51
)
(1
)
 
(47
)
(15
)
Environmental and other provisions
 
—

—

 
—

—

Restructuring, integration and rationalization costs
 
20

(74
)
 
18

(110
)
Fair value gain (loss) on embedded derivatives
 
—

—

 
—

—

Other
 
—

(150
)
 
(6
)
(153
)
 
 
(31
)
(225
)
 
(35
)
(278
)
Rosneft
 
 
 
 
 
 
Impairment and gain (loss) on sale of businesses and fixed assets
 
(113
)
—

 
(194
)
—

Environmental and other provisions
 
—

—

 
—

—

Restructuring, integration and rationalization costs
 
—

—

 
—

—

Fair value gain (loss) on embedded derivatives
 
—

—

 
—

—

Other
 
—

—

 
—

—

 
 
(113
)
—

 
(194
)
—

Other businesses and corporate
 
 
 
 
 
 
Impairment and gain (loss) on sale of businesses and fixed assets
 
(4
)
(1
)
 
(4
)
1

Environmental and other provisions
 
(22
)
1

 
(28
)
(20
)
Restructuring, integration and rationalization costs
 
(3
)
(30
)
 
7

(45
)
Fair value gain (loss) on embedded derivatives
 
—

—

 
—

—

Gulf of Mexico oil spill
 
(57
)
(433
)
 
(172
)
(519
)
Other
 
(5
)
(85
)
 
(22
)
(144
)
 
 
(91
)
(548
)
 
(219
)
(727
)
Total before interest and taxation
 
(1,001
)
(746
)
 
(1,218
)
(1,082
)
Finance costs(c)
 
(116
)
(118
)
 
(244
)
(238
)
Total before taxation
 
(1,117
)
(864
)
 
(1,462
)
(1,320
)
Taxation credit (charge) on non-operating items
 
256

141

 
349

350

Total after taxation for period
 
(861
)
(723
)
 
(1,113
)
(970
)
(a)
Amounts reported as restructuring, integration and rationalization costs relate to the group's restructuring programme, originally announced in 2014, which was completed in fourth quarter 2018.
(b)
Second quarter and first half 2019 include impairment charges of $634 million resulting from the announcements to dispose of certain assets in Egypt and the US.
(c)
Relates to the unwinding of discounting effects relating to Gulf of Mexico oil spill payables.

37

Non-GAAP information on fair value accounting effects
 
 
Second

Second

 
First

First

 
 
quarter

quarter

 
half

half

$ million
 
2019

2018

 
2019

2018

Favourable (adverse) impact relative to management’s measure of performance
 
 
 
 
 
 
Upstream
 
(178
)
(21
)
 
(218
)
100

Downstream
 
(46
)
(390
)
 
(10
)
(450
)
 
 
(224
)
(411
)
 
(228
)
(350
)
Taxation credit (charge)
 
49

101

 
42

90

 
 
(175
)
(310
)
 
(186
)
(260
)
BP uses derivative instruments to manage the economic exposure relating to inventories above normal operating requirements of crude oil, natural gas and petroleum products. Under IFRS, these inventories are recorded at historical cost. The related derivative instruments, however, are required to be recorded at fair value with gains and losses recognized in the income statement. This is because hedge accounting is either not permitted or not followed, principally due to the impracticality of effectiveness-testing requirements. Therefore, measurement differences in relation to recognition of gains and losses occur. Gains and losses on these inventories are not recognized until the commodity is sold in a subsequent accounting period. Gains and losses on the related derivative commodity contracts are recognized in the income statement, from the time the derivative commodity contract is entered into, on a fair value basis using forward prices consistent with the contract maturity.
BP enters into physical commodity contracts to meet certain business requirements, such as the purchase of crude for a refinery or the sale of BP’s gas production. Under IFRS these physical contracts are treated as derivatives and are required to be fair valued when they are managed as part of a larger portfolio of similar transactions. Gains and losses arising are recognized in the income statement from the time the derivative commodity contract is entered into.
IFRS require that inventory held for trading is recorded at its fair value using period-end spot prices, whereas any related derivative commodity instruments are required to be recorded at values based on forward prices consistent with the contract maturity. Depending on market conditions, these forward prices can be either higher or lower than spot prices, resulting in measurement differences.
BP enters into contracts for pipelines and other transportation, storage capacity, oil and gas processing and liquefied natural gas (LNG) that, under IFRS, are recorded on an accruals basis. These contracts are risk-managed using a variety of derivative instruments that are fair valued under IFRS. This results in measurement differences in relation to recognition of gains and losses.
The way that BP manages the economic exposures described above, and measures performance internally, differs from the way these activities are measured under IFRS. BP calculates this difference for consolidated entities by comparing the IFRS result with management’s internal measure of performance. Under management’s internal measure of performance the inventory, transportation and capacity contracts in question are valued based on fair value using relevant forward prices prevailing at the end of the period. The fair values of derivative instruments used to risk manage certain oil, gas and other contracts, are deferred to match with the underlying exposure and the commodity contracts for business requirements are accounted for on an accruals basis. We believe that disclosing management’s estimate of this difference provides useful information for investors because it enables investors to see the economic effect of these activities as a whole.
In addition, fair value accounting effects include changes in the fair value of the near-term portions of LNG contracts that fall within BP’s risk management framework. LNG contracts are not considered derivatives, because there is insufficient market liquidity, and they are therefore accrual accounted under IFRS. However, oil and natural gas derivative financial instruments (used to risk manage the near-term portions of the LNG contracts) are fair valued under IFRS. The fair value accounting effect reduces timing differences between recognition of the derivative financial instruments used to risk manage the LNG contracts and the recognition of the LNG contracts themselves, which therefore gives a better representation of performance in each period.





38

Non-GAAP information on fair value accounting effects (continued)
The impacts of fair value accounting effects, relative to management’s internal measure of performance, are shown in the table above. A reconciliation to GAAP information is set out below.
 
 
Second

Second

 
First

First

 
 
quarter

quarter

 
half

half

$ million
 
2019

2018

 
2019

2018

Upstream
 
 
 
 
 
 
Replacement cost profit (loss) before interest and tax adjusted for fair value accounting effects
 
2,647

3,535

 
5,571

6,588

Impact of fair value accounting effects
 
(178
)
(21
)
 
(218
)
100

Replacement cost profit (loss) before interest and tax
 
2,469

3,514

 
5,353

6,688

Downstream
 
 
 
 
 
 
Replacement cost profit (loss) before interest and tax adjusted for fair value accounting effects
 
1,334

1,230

 
3,063

3,003

Impact of fair value accounting effects
 
(46
)
(390
)
 
(10
)
(450
)
Replacement cost profit (loss) before interest and tax
 
1,288

840

 
3,053

2,553

Total group
 
 
 
 
 
 
Profit (loss) before interest and tax adjusted for fair value accounting effects
 
4,240

5,967

 
9,908

10,401

Impact of fair value accounting effects
 
(224
)
(411
)
 
(228
)
(350
)
Profit (loss) before interest and tax
 
4,016

5,556

 
9,680

10,051

Readily marketable inventory* (RMI)
 
 
30 June

31 December

$ million
 
2019

2018

RMI at fair value*
 
5,497

4,202

Paid-up RMI*
 
2,317

1,641

Readily marketable inventory (RMI) is oil and oil products inventory held and price risk-managed by BP’s integrated supply and trading function (IST) which could be sold to generate funds if required. Paid-up RMI is RMI that BP has paid for.
We believe that disclosing the amounts of RMI and paid-up RMI is useful to investors as it enables them to better understand and evaluate the group’s inventories and liquidity position by enabling them to see the level of discretionary inventory held by IST and to see builds or releases of liquid trading inventory.
See the Glossary on page 44 for a more detailed definition of RMI. RMI, RMI at fair value, paid-up RMI and unpaid RMI are non-GAAP measures. A reconciliation of total inventory as reported on the group balance sheet to paid-up RMI is provided below.
 
 
30 June

31 December

$ million
 
2019

2018

Reconciliation of total inventory to paid-up RMI
 
 
 
Inventories as reported on the group balance sheet under IFRS
 
20,042

17,988

Less: (a) inventories that are not oil and oil products and (b) oil and oil product inventories that are not risk-managed by IST
 
(14,821
)
(14,066
)
 
 
5,221

3,922

Plus: difference between RMI at fair value and RMI on an IFRS basis
 
276

280

RMI at fair value
 
5,497

4,202

Less: unpaid RMI* at fair value
 
(3,180
)
(2,561
)
Paid-up RMI
 
2,317

1,641



39

Gulf of Mexico oil spill

Net cash from operating activities relating to the Gulf of Mexico oil spill on a pre-tax basis amounted to an outflow of $1,472 million and $2,126 million in the second quarter and half year of 2019 respectively. For the same periods in 2018, the amount was an outflow of $1,078 million and $2,698 million respectively. Net cash outflows relating to the Gulf of Mexico oil spill in 2019 and 2018 include payments made under the 2016 consent decree and settlement agreement with the United States and the five Gulf coast states. Included in the current quarter are payments of $1,194 million on a pre-tax basis relating to the 2016 consent decree and settlement agreement. Cash outflows in 2018 also include the final payment made under the 2012 agreement with the US government to resolve all federal criminal claims arising from the incident. Net cash from operating activities relating to the Gulf of Mexico oil spill on a post-tax basis amounted to an outflow of $1,413 million and $2,062 million in the second quarter and half year of 2019 respectively. For the same periods in 2018, the amount was an outflow of $707 million and $2,421 million respectively.
 
 
30 June

31 December

$ million
 
2019

2018

Trade and other payables
 
(12,623
)
(14,201
)
Provisions
 
(199
)
(345
)
Gulf of Mexico oil spill payables and provisions
 
(12,822
)
(14,546
)
Of which - current
 
(2,022
)
(2,612
)
 
 
 
 
Deferred tax asset
 
5,600

5,562

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

 
 
Second

Second

 
First

First

 
 
quarter

quarter

 
half

half

Per ordinary share (cents)
 
2019

2018

 
2019

2018

Profit for the period
 
8.95

14.03

 
23.47

26.42

Inventory holding (gains) losses*, before tax
 
(0.40
)
(6.57
)
 
(5.77
)
(7.03
)
Taxation charge (credit) on inventory holding gains and losses
 
0.17

1.50

 
1.40

1.57

Replacement cost (RC) profit (loss)*
 
8.72

8.96

 
19.10

20.96

Net (favourable) adverse impact of non-operating items* and fair value accounting effects*, before tax
 
6.59

6.39

 
8.34

8.38

Taxation charge (credit) on non-operating items and fair value accounting effects
 
(1.49
)
(1.21
)
 
(1.93
)
(2.21
)
Underlying RC profit*
 
13.82

14.14

 
25.51

27.13


Reconciliation of effective tax rate (ETR) to ETR on RC profit or loss and underlying ETR

Taxation (charge) credit
 
 
 
 
 
 
 
 
Second

Second

 
First

First

 
 
quarter

quarter

 
half

half

$ million
 
2019

2018

 
2019

2018

Taxation on profit or loss
 
(1,244
)
(2,117
)
 
(3,027
)
(3,497
)
Taxation on inventory holding gains and losses
 
(34
)
(300
)
 
(283
)
(312
)
Taxation on a replacement cost (RC) profit or loss basis
 
(1,210
)
(1,817
)
 
(2,744
)
(3,185
)
Taxation on non-operating items and fair value accounting effects
 
305

242

 
391

440

Taxation on underlying replacement cost profit or loss
 
(1,515
)
(2,059
)
 
(3,135
)
(3,625
)


40

Effective tax rate
 
 
 
 
 
 
 
 
Second

Second

 
First

First

 
 
quarter

quarter

 
half

half

%
 
2019

2018

 
2019

2018

ETR on profit or loss
 
40

42

 
38

39

Adjusted for inventory holding gains or losses
 
(1
)
7

 
3

3

ETR on RC profit or loss*
 
39

49

 
41

42

Adjusted for non-operating items and fair value accounting effects
 
(5
)
(7
)
 
(4
)
(2
)
Underlying ETR*
 
34

42

 
37

40


41

Realizations* and marker prices
 
 
Second

Second

 
First

First

 
 
quarter

quarter

 
half

half

 
 
2019

2018

 
2019

2018

Average realizations(a)
 
 
 
 
 
 
Liquids* ($/bbl)
 
 
 
 
 
 
US
 
56.98

62.47

 
53.91

60.01

Europe
 
68.73

71.70

 
65.04

68.56

Rest of World
 
66.24

69.88

 
63.18

66.50

BP Average
 
62.63

67.24

 
59.61

64.21

Natural gas ($/mcf)
 
 
 
 
 
 
US
 
1.80

1.96

 
2.18

2.10

Europe
 
3.63

7.04

 
4.75

7.11

Rest of World
 
4.12

4.16

 
4.40

4.19

BP Average
 
3.35

3.65

 
3.68

3.72

Total hydrocarbons* ($/boe)
 
 
 
 
 
 
US
 
35.94

40.77

 
35.08

40.19

Europe
 
63.40

64.91

 
61.02

62.72

Rest of World
 
41.60

42.89

 
41.06

41.69

BP Average
 
40.64

43.37

 
40.02

42.36

Average oil marker prices ($/bbl)
 
 
 
 
 
 
Brent
 
68.86

74.39

 
65.95

70.58

West Texas Intermediate
 
59.90

68.02

 
57.42

65.52

Western Canadian Select
 
47.37

49.76

 
46.06

43.30

Alaska North Slope
 
68.29

73.93

 
66.37

70.64

Mars
 
65.20

69.47

 
63.20

66.04

Urals (NWE – cif)
 
67.62

72.21

 
65.23

68.71

Average natural gas marker prices
 
 
 
 
 
 
Henry Hub gas price(b) ($/mmBtu)
 
2.64

2.80

 
2.90

2.90

UK Gas – National Balancing Point (p/therm)
 
31.53

53.88

 
40.01

55.94

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

Second

 
First

First

 
 
quarter

quarter

 
half

half

 
 
2019

2018

 
2019

2018

$/£ average rate for the period
 
1.29

1.36

 
1.29

1.38

$/£ period-end rate
 
1.27

1.31

 
1.27

1.31

 
 
 
 
 
 
 
$/€ average rate for the period
 
1.12

1.19

 
1.13

1.21

$/€ period-end rate
 
1.14

1.16

 
1.14

1.16

 
 
 
 
 
 
 
Rouble/$ average rate for the period
 
64.58

62.13

 
65.29

59.47

Rouble/$ period-end rate
 
63.09

63.07

 
63.09

63.07



42

Principal risks and uncertainties
The principal risks and uncertainties affecting BP are described in the Risk factors section of BP Annual Report and Form 20-F 2018 (pages 55-56) and are summarized below. There are no material changes in those risk factors for the remaining six months of the financial year.
The risks summarized below, separately or in combination, could have a material adverse effect on the implementation of our strategy, our business, financial performance, results of operations, cash flows, liquidity, prospects, shareholder value and returns and reputation.

Strategic and commercial risks
•
Prices and markets – our financial performance is impacted by fluctuating prices of oil, gas and refined products, technological change, exchange rate fluctuations, and the general macroeconomic outlook.
•
Access, renewal and reserves progression – inability to access, renew and progress upstream resources in a timely manner could adversely affect our long-term replacement of reserves.
•
Major project* delivery – failure to invest in the best opportunities or deliver major projects successfully could adversely affect our financial performance.
•
Geopolitical – exposure to a range of political developments and consequent changes to the operating and regulatory environment could cause business disruption.
•
Liquidity, financial capacity and financial, including credit, exposure – failure to work within our financial framework could impact our ability to operate and result in financial loss.
•
Joint arrangements and contractors – varying levels of control over the standards, operations and compliance of our partners, contractors and sub-contractors could result in legal liability and reputational damage.
•
Digital infrastructure and cyber security – breach of our digital security or failure of our digital infrastructure including loss or misuse of sensitive information could damage our operations, increase costs and damage our reputation.
•
Climate change and the transition to a lower carbon economy – policy, legal, regulatory, technology and market change related to the issue of climate change could increase costs, reduce demand for our products, reduce revenue and limit certain growth opportunities.
•
Competition – inability to remain efficient, maintain a high quality portfolio of assets, innovate and retain an appropriately skilled workforce could negatively impact delivery of our strategy in a highly competitive market.
•
Crisis management and business continuity – failure to address an incident effectively could potentially disrupt our business.
•
Insurance – our insurance strategy could expose the group to material uninsured losses.

Safety and operational risks
•
Process safety, personal safety, and environmental risks – exposure to a wide range of health, safety, security and environmental risks could cause harm to people, the environment and our assets and result in regulatory action, legal liability, business interruption, increased costs, damage to our reputation and potentially denial of our licence to operate.
•
Drilling and production – challenging operational environments and other uncertainties could impact drilling and production activities.
•
Security – hostile acts against our staff and activities could cause harm to people and disrupt our operations.
•
Product quality – supplying customers with off-specification products could damage our reputation, lead to regulatory action and legal liability, and impact our financial performance.

Compliance and control risks
•
Regulation – changes in the regulatory and legislative environment could increase the cost of compliance, affect our provisions and limit our access to new growth opportunities.
•
Ethical misconduct and non-compliance – ethical misconduct or breaches of applicable laws by our businesses or our employees could be damaging to our reputation, and could result in litigation, regulatory action and penalties.
•
Treasury and trading activities – ineffective oversight of treasury and trading activities could lead to business disruption, financial loss, regulatory intervention or damage to our reputation.
•
Reporting – failure to accurately report our data could lead to regulatory action, legal liability and reputational damage.


43

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

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

 

Glossary
Non-GAAP measures are provided for investors because they are closely tracked by management to evaluate BP’s operating performance and to make financial, strategic and operating decisions. Non-GAAP measures are sometimes referred to as alternative performance measures.
Capital expenditure is total cash capital expenditure as stated in the condensed group cash flow statement.
Consolidation adjustment – UPII is unrealized profit in inventory arising on inter-segment transactions.
Divestment proceeds are disposal proceeds as per the condensed group cash flow statement.
Effective tax rate (ETR) on replacement cost (RC) profit or loss is a non-GAAP measure. The ETR on RC profit or loss is calculated by dividing taxation on a RC basis by RC profit or loss before tax. Information on RC profit or loss is provided below. BP believes it is helpful to disclose the ETR on RC profit or loss because this measure excludes the impact of price changes on the replacement of inventories and allows for more meaningful comparisons between reporting periods. The nearest equivalent measure on an IFRS basis is the ETR on profit or loss for the period. A reconciliation to GAAP information is provided on page 40.
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 38.
Finance debt ratio is defined as the ratio of finance debt to the total of finance debt plus total equity.
Free cash flow is operating cash flow less net cash used in investing activities and lease liability payments included in financing activities, as presented in the condensed group cash flow statement.
Gearing and net debt are non-GAAP measures. Net debt is calculated as finance debt, as shown in the balance sheet, plus the fair value of associated derivative financial instruments that are used to hedge foreign currency exchange and interest rate risks relating to finance debt, for which hedge accounting is applied, less cash and cash equivalents. Gearing is defined as the ratio of net debt to the total of net debt plus total equity. BP believes these measures provide useful information to investors. Net debt enables investors to see the economic effect of finance debt, related hedges and cash and cash equivalents in total. Gearing enables investors to see how significant net debt is relative to total equity. The derivatives are reported on the balance sheet within the headings ‘Derivative financial instruments’. The nearest equivalent GAAP measures on an IFRS basis are finance debt and finance debt ratio. A reconciliation of finance debt to net debt is provided on page 25.
We are unable to present reconciliations of forward-looking information for gearing to finance debt ratio, because without unreasonable efforts, we are unable to forecast accurately certain adjusting items required to present a meaningful comparable GAAP forward-looking financial measure. These items include fair value asset (liability) of hedges related to finance debt and cash and cash equivalents, that are difficult to predict in advance in order to include in a GAAP estimate.
Hydrocarbons – Liquids and natural gas. Natural gas is converted to oil equivalent at 5.8 billion cubic feet = 1 million barrels.
Inorganic capital expenditure is a subset of capital expenditure and is a non-GAAP measure. Inorganic capital expenditure comprises consideration in business combinations and certain other significant investments made by the group. It is reported on a cash basis. BP believes that this measure provides useful information as it allows investors to understand how BP’s management invests funds in projects which expand the group’s activities through acquisition. Further information and a reconciliation to GAAP information is provided on page 36.

44

Glossary (continued)
Inventory holding gains and losses represent the difference between the cost of sales calculated using the replacement cost of inventory and the cost of sales calculated on the first-in first-out (FIFO) method after adjusting for any changes in provisions where the net realizable value of the inventory is lower than its cost. Under the FIFO method, which we use for IFRS reporting, the cost of inventory charged to the income statement is based on its historical cost of purchase or manufacture, rather than its replacement cost. In volatile energy markets, this can have a significant distorting effect on reported income. The amounts disclosed represent the difference between the charge to the income statement for inventory on a FIFO basis (after adjusting for any related movements in net realizable value provisions) and the charge that would have arisen based on the replacement cost of inventory. For this purpose, the replacement cost of inventory is calculated using data from each operation’s production and manufacturing system, either on a monthly basis, or separately for each transaction where the system allows this approach. The amounts disclosed are not separately reflected in the financial statements as a gain or loss. No adjustment is made in respect of the cost of inventories held as part of a trading position and certain other temporary inventory positions. See Replacement cost (RC) profit or loss definition below.
Liquids – Liquids for Upstream and Rosneft comprises crude oil, condensate and natural gas liquids. For Upstream, liquids also includes bitumen.
Major projects have a BP net investment of at least $250 million, or are considered to be of strategic importance to BP or of a high degree of complexity.
Net debt including leases is a non-GAAP measure. Net debt including leases is calculated as net debt plus lease liabilities, less the net amount of partner receivables and payables relating to leases entered into on behalf of joint operations. BP believes this measure provides useful information to investors as it enables investors to understand the impact of the group’s lease portfolio on net debt. The nearest equivalent GAAP measure on an IFRS basis is finance debt. A reconciliation of finance debt to net debt including leases is provided on page 25.
Net wind generation capacity is the sum of the rated capacities of the assets/turbines that have entered into commercial operation, including BP’s share of equity-accounted entities.
Non-operating items are charges and credits included in the financial statements that BP discloses separately because it considers such disclosures to be meaningful and relevant to investors. They are items that management considers not to be part of underlying business operations and are disclosed in order to enable investors better to understand and evaluate the group’s reported financial performance. Non-operating items within equity-accounted earnings are reported net of incremental income tax reported by the equity-accounted entity. An analysis of non-operating items by region is shown on pages 10, 12 and 14, and by segment and type is shown on page 37.
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 36.
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 39.
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.


45

Glossary (continued)
Refining availability represents Solomon Associates’ operational availability for BP-operated refineries, which is defined as the percentage of the year that a unit is available for processing after subtracting the annualized time lost due to turnaround activity and all planned mechanical, process and regulatory downtime.
The Refining marker margin (RMM) is the average of regional indicator margins weighted for BP’s crude refining capacity in each region. Each regional marker margin is based on product yields and a marker crude oil deemed appropriate for the region. The regional indicator margins may not be representative of the margins achieved by BP in any period because of BP’s particular refinery configurations and crude and product slate.
Replacement cost (RC) profit or loss reflects the replacement cost of inventories sold in the period and is arrived at by excluding inventory holding gains and losses from profit or loss. RC profit or loss for the group is not a recognized GAAP measure. BP believes this measure is useful to illustrate to investors the fact that crude oil and product prices can vary significantly from period to period and that the impact on our reported result under IFRS can be significant. Inventory holding gains and losses vary from period to period due to changes in prices as well as changes in underlying inventory levels. In order for investors to understand the operating performance of the group excluding the impact of price changes on the replacement of inventories, and to make comparisons of operating performance between reporting periods, BP’s management believes it is helpful to disclose this measure. The nearest equivalent measure on an IFRS basis is profit or loss attributable to BP shareholders. A reconciliation to GAAP information is provided on page 3. RC profit or loss before interest and tax is the measure of profit or loss that is required to be disclosed for each operating segment under IFRS.
RC profit or loss per share is a non-GAAP measure. Earnings per share is defined in Note 7. RC profit or loss per share is calculated using the same denominator. The numerator used is RC profit or loss attributable to BP shareholders rather than profit or loss attributable to BP shareholders. BP believes it is helpful to disclose the RC profit or loss per share because this measure excludes the impact of price changes on the replacement of inventories and allows for more meaningful comparisons between reporting periods. The nearest equivalent measure on an IFRS basis is basic earnings per share based on profit or loss for the period attributable to BP shareholders. A reconciliation to GAAP information is provided on page 40.
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. A reconciliation to GAAP information is provided on page 40.
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 37 and 38 for additional information on the non-operating items and fair value accounting effects that are used to arrive at underlying RC profit or loss in order to enable a full understanding of the events and their financial impact. BP believes that underlying RC profit or loss is a useful measure for investors because it is a measure closely tracked by management to evaluate BP’s operating performance and to make financial, strategic and operating decisions and because it may help investors to understand and evaluate, in the same manner as management, the underlying trends in BP’s operational performance on a comparable basis, period on period, by adjusting for the effects of these non-operating items and fair value accounting effects. The nearest equivalent measure on an IFRS basis for the group is profit or loss attributable to BP shareholders. The nearest equivalent measure on an IFRS basis for segments is RC profit or loss before interest and taxation. A reconciliation to GAAP information is provided on page 3.
Underlying RC profit or loss per share is a non-GAAP measure. Earnings per share is defined in Note 7. Underlying RC profit or loss per share is calculated using the same denominator. The numerator used is underlying RC profit or loss attributable to BP shareholders rather than profit or loss attributable to BP shareholders. BP believes it is helpful to disclose the underlying RC profit or loss per share because this measure may help investors to understand and evaluate, in the same manner as management, the underlying trends in BP’s operational performance on a comparable basis, period on period. The nearest equivalent measure on an IFRS basis is basic earnings per share based on profit or loss for the period attributable to BP shareholders. A reconciliation to GAAP information is provided on page 40.

46

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.
Cautionary statement
In order to utilize the ‘safe harbor’ provisions of the United States Private Securities Litigation Reform Act of 1995 (the ‘PSLRA’) and the general doctrine of cautionary statements, BP is providing the following cautionary statement: The discussion in this results announcement contains certain forecasts, projections and forward-looking statements - that is, statements related to future, not past events and circumstances - with respect to the financial condition, results of operations and businesses of BP and certain of the plans and objectives of BP with respect to these items. These statements may generally, but not always, be identified by the use of words such as ‘will’, ‘expects’, ‘is expected to’, ‘aims’, ‘should’, ‘may’, ‘objective’, ‘is likely to’, ‘intends’, ‘believes’, ‘anticipates’, ‘plans’, ‘we see’ or similar expressions. In particular, the following, among other statements, are all forward looking in nature: plans and expectations regarding BP’s low-carbon business, including with regard to BP’s $30 million venturing investment in Calysta and Calysta’s business model and impacts thereof, and to the timing of the installation of 400 ultra-fast chargers at BP’s UK retail sites; plans and expectations with respect to the joint venture between BP’s Brazilian biofuels business and Bunge, including BP’s interest in the venture, the combined business plan and completion timing; expectations regarding the expected quarterly dividend payment and timing of such payment; plans and expectations regarding share buybacks, including to offset the impact of dilution from the scrip program; expectations regarding the underlying effective tax rate in 2019; expectations regarding 2019 organic capital expenditure and depreciation, depletion and amortization charges; plans and expectations with respect to gearing, including for gearing to move toward the middle of the 20-30% targeted range in 2020; expectations with respect to new discoveries and the potential to develop them; plans and expectations with respect to expected project start-ups for which final investment decisions have been made; plans and expectations regarding Upstream investments, including with regard to the agreement to sell BP’s interests in Gulf of Suez oil concessions to Dragon Oil and timing thereof, for the investment in deepwater Block 15 offshore Angola to increase and extend production and to BP’s intention to sell BP’s interest in oil and gas fields in Oklahoma, US; expectations with regard to the strategic partnership between Castrol and Renault Sport Racing; plans and expectations regarding divestments and disposals, including to have more than $10 billion of divestments by the end of 2020; plans and expectations with respect to BP’s and Environmental Defense Fund’s commitment to reduce methane emissions; plans regarding the $100-million fund for projects that will deliver emissions reductions; expectations regarding Upstream third-quarter 2019 reported production, seasonal turnaround and maintenance activities; expectations regarding Downstream third-quarter 2019 refining margins and turnaround activity; expectations regarding the impact of the IFRIC agenda decision on IFRS 9 on reported earnings; expectations that the second and final payment in connection with the Scharfstein litigation will be made in July 2020; plans and expectations regarding Lightsource BP, including for the Green Energy Equity Fund to invest a total of $330 million in Ayana Renewable Power; plans and expectations regarding the Other businesses and corporate 2019 average quarterly charges; and expectations with respect to the amount of future payments relating to the Gulf of Mexico oil spill. By their nature, forward-looking statements involve risk and uncertainty because they relate to events and depend on circumstances that will or may occur in the future and are outside the control of BP. Actual results may differ materially from those expressed in such statements, depending on a variety of factors, including: the specific factors identified in the discussions accompanying such forward-looking statements; the receipt of relevant third party and/or regulatory approvals; the timing and level of maintenance and/or turnaround activity; the timing and volume of refinery additions and outages; the timing of bringing new fields onstream; the timing, quantum and nature of certain acquisitions and divestments; future levels of industry product supply, demand and pricing, including supply growth in North America; OPEC quota restrictions; PSA effects; operational and safety problems; potential lapses in product quality; economic and financial market conditions generally or in various countries and regions; political stability and economic growth in relevant areas of the world; changes in laws and governmental regulations; regulatory or legal actions including the types of enforcement action pursued and the nature of remedies sought or imposed; the actions of prosecutors, regulatory authorities and courts; delays in the processes for resolving claims; amounts ultimately payable and timing of payments relating to the Gulf of Mexico oil spill; exchange rate fluctuations; development and use of new technology; recruitment and retention of a skilled workforce; the success or otherwise of partnering; the actions of competitors, trading partners, contractors, subcontractors, creditors, rating agencies and others; our access to future credit resources; business disruption and crisis management; the impact on our reputation of ethical misconduct and non-compliance with regulatory obligations; trading losses; major uninsured losses; decisions by Rosneft’s management and board of directors; natural disasters and adverse weather conditions; changes in public expectations and other changes to business conditions; wars and acts of terrorism; cyber-attacks or sabotage; and other factors discussed in this Form 6-K for the period ended 30 June 2019 including under “Principal risks and uncertainties”, and under “Risk factors” in BP Annual Report and Form 20-F 2018 as filed with the US Securities and Exchange Commission.






47

The following table shows the unaudited consolidated capitalization and indebtedness of the BP group as of 30 June 2019 in
accordance with IFRS:
Capitalization and indebtedness

 
 
30 June

$ million
 
2019

Share capital and reserves
 
 
Capital shares (1-2)
 
5,428

Paid-in surplus (3)
 
13,882

Merger reserve (3)
 
27,206

Treasury shares
 
(14,584
)
Cash flow hedge reserve
 
(737
)
Costs of hedging reserve
 
(96
)
Foreign currency translation reserve
 
(7,782
)
Profit and loss account
 
78,168

BP shareholders' equity
 
101,485

 
 
 
Finance debt and lease liabilities (4-6)
 
 
Lease liabilities due within one year
 
2,094

Finance debt due within one year
 
8,677

Lease liabilities due after more than one year
 
8,285

Finance debt due after more than one year
 
58,876

Total finance debt and lease liabilities
 
77,932

Total (7)
 
179,417


1.
Issued share capital as of 30 June 2019 comprised 20,387,117,077 ordinary shares, par value US$0.25 per share, and 12,706,252 preference shares, par value £1 per share. This excludes 1,257,120,831 ordinary shares which have been bought back and are held in treasury by BP. These shares are not taken into consideration in relation to the payment of dividends and voting at shareholders’ meetings.

2.
Capital shares represent the ordinary and preference shares of BP which have been issued and are fully paid.

3.
Paid-in surplus and merger reserve represent additional paid-in capital of BP which cannot normally be returned to
shareholders.

4.
Finance debt and lease liabilities recorded in currencies other than US dollars has been translated into US dollars at the relevant exchange rates existing on 30 June 2019.

5.
Finance debt and lease liabilities presented in the table above consists of borrowings and obligations under finance leases. This includes one hundred percent of lease liabilities for joint operations where BP is the only party with the legal obligation to make lease payments to the lessor. Other contractual obligations are not presented in the table above – see BP Annual Report and Form 20-F 2018 – Liquidity and capital resources for further information.

6.
At 30 June 2019, the parent company, BP p.l.c., had issued guarantees totalling $64,277 million relating to finance debt of subsidiaries. Thus 95% of the group’s finance debt had been guaranteed by BP p.l.c.

At 30 June 2019, $158 million of finance debt was secured by the pledging of assets. The remainder of finance debt was unsecured.

7.
At 30 June 2019 the group had issued third-party guarantees under which amounts outstanding, incremental to amounts recognized on the group balance sheet, were $764 million in respect of the borrowings of equity-accounted entities and $381 million in respect of the borrowings of other third parties.

8.
There has been no material change since 30 June 2019 in the consolidated capitalization and indebtedness of BP.



48

Recent credit ratings update
On 12 July 2019, Standard & Poor’s changed the outlook from stable to positive on the A- long term credit rating of BP p.l.c. Standard & Poor’s affirmed the current rating.

 

Signatures

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.


BP p.l.c.
(Registrant)



Dated:
30 July 2019
 
/s/ BEN MATHEWS
 
 
 
BEN MATHEWS
 
 
 
Company Secretary
                                        


49