TIDMBP.
RNS Number : 0431P
BP PLC
05 February 2019
FOR IMMEDIATE RELEASE
London 5 February 2019
BP p.l.c. Group results
Fourth quarter and full year 2018
====================================
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Top of page 1
Highlights Building business momentum, growing earnings and returns
-- More than double full-year earnings, near double returns
- Underlying replacement cost profit for full year 2018 was
$12.7 billion, more than double that reported for 2017. The fourth
quarter result was $3.5 billion, driven by the strong operating
performance across all business segments.
- Return on average capital employed was 11.2% compared to 5.8% in 2017.
- Operating cash flow, excluding Gulf of Mexico oil spill
payments, for full year 2018 was $26.1 billion, including a $2.6
billion working capital build (after adjusting for inventory
holding losses). This compares with $24.1 billion for 2017, which
included a working capital release of $2.6 billion.
- Gulf of Mexico oil spill payments in 2018 totalled $3.2 billion on a post-tax basis.
- Total divestments and other proceeds in 2018 were $3.5
billion. BP intends to complete more than $10 billion divestments
over the next two years, which includes plans announced following
the BHP transaction.
- Dividend of 10.25 cents a share announced for the fourth
quarter, 2.5% higher than a year earlier.
-- Record Upstream reliability, record refining throughput
- Operational reliability was very strong in 2018 for both main business segments.
- For the year, BP-operated Upstream plant reliability was a
record 96%, and Downstream delivered refining availability of 95%
and record refining throughput.
- Reported oil and gas production averaged 3.7 million barrels
of oil equivalent a day for 2018. Upstream underlying production,
which excludes Rosneft, was 8.2% higher than 2017.
-- Growing the business, advancing the energy transition
- Six Upstream major projects started up in 2018, making a total
of 19 brought online since 2016.
- Reserves replacement ratio (RRR) for 2018, including Rosneft,
is 100%. Including acquisitions and disposals, RRR is 209%,
primarily reflecting the BHP transaction.
- Fuels marketing continued to grow, with over 25% more
convenience partnership sites, as well as further retail expansion
in Mexico.
- BP set out its approach to advancing the energy transition in
2018, introducing its 'reduce-improve-create' framework and setting
clear targets for operational greenhouse gas emissions, towards
which it is already making significant progress.
- BP acquired UK electric vehicle charging company Chargemaster
and Lightsource BP saw important expansion internationally.
See chart on PDF
Bob Dudley - Group chief executive:
We now have a powerful track record of safe and reliable performance,
efficient execution and capital discipline. And we're doing this while
growing the business - bringing more high-quality projects online, expanding
marketing in the Downstream and doing transformative deals such as BHP.
Our strategy is clearly working and will serve the company and our shareholders
well through the energy transition.
Financial summary
Fourth Third Fourth
quarter quarter quarter Year Year
$ million 2018 2018 2017 2018 2017
======= ======= ======= ====== ========
Profit for the period attributable to
BP shareholders 766 3,349 27 9,383 3,389
Inventory holding (gains) losses, net
of tax 1,951 (258) (610) 603 (628)
RC profit (loss) 2,717 3,091 (583) 9,986 2,761
Net (favourable) adverse impact of non-operating
items and fair value accounting effects,
net of tax 760 747 2,690 2,737 3,405
=======
Underlying RC profit 3,477 3,838 2,107 12,723 6,166
=================================================== ======= ====== ====== ====== =====
RC profit (loss) per ordinary share (cents) 13.58 15.45 (2.94) 50.00 14.02
RC profit (loss) per ADS (dollars) 0.81 0.93 (0.18) 3.00 0.84
Underlying RC profit per ordinary share
(cents) 17.38 19.18 10.64 63.70 31.31
Underlying RC profit per ADS (dollars) 1.04 1.15 0.64 3.82 1.88
=================================================== ======= ====== ====== ====== =====
RC profit (loss), underlying RC profit, return on average
capital employed, operating cash flow excluding Gulf of Mexico oil
spill payments and working capital are non-GAAP measures. These
measures and Upstream plant reliability, refining availability,
major projects, inventory holding gains and losses, non-operating
items, fair value accounting effects, underlying production and
reserves replacement ratio are defined in the Glossary on page
32.
The commentary above and following should be read in conjunction with
the cautionary statement on page 36.
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Group headlines
Results Share buybacks
For the full year, underlying replacement BP repurchased 2 million ordinary
cost (RC) profit* was $12,723 million, shares at a cost of $16 million, including
compared with $6,166 million in 2017. fees and stamp duty, during the fourth
Underlying RC profit is after adjusting quarter of 2018. For the full year,
RC profit* for a net charge for non-operating BP repurchased 50 million ordinary
items* of $2,805 million and net favourable shares at a cost of $355 million,
fair value accounting effects* of including fees and stamp duty. We
$68 million (both on a post-tax basis). expect to continue our share buyback
RC profit was $9,986 million for the programme, and to fully offset the
full year, compared with $2,761 million impact of scrip dilution since the
a year ago. third quarter of 2017 by the end of
For the fourth quarter, underlying 2019.
RC profit was $3,477 million, compared Operating cash flow*
with $2,107 million in 2017. Underlying Excluding post-tax amounts related
RC profit is after adjusting RC profit to the Gulf of Mexico oil spill, operating
for a net charge for non-operating cash flow* for the fourth quarter
items of $1,186 million and net favourable was $7.1 billion, including a $1.5-billion
fair value accounting effects of $426 working capital* build (after adjusting
million (both on a post-tax basis). for inventory holding losses*) and
RC profit was $2,717 million for the $26.1 billion in the full year, including
fourth quarter, compared with a loss a $2.6-billion working capital build
of $583 million in 2017. (after adjusting for inventory holding
BP's profit for the fourth quarter losses), compared with $6.2 billion
and full year was $766 million and and $24.1 billion for the same periods
$9,383 million respectively, compared in 2017. Including amounts relating
with $27 million and $3,389 million to the Gulf of Mexico oil spill, operating
for the same periods in 2017. cash flow for the fourth quarter and
See further information on pages 3, full year was $6.8 billion and $22.9
28 and 29. billion respectively (after a $0.8-billion
Depreciation, depletion and amortization working capital release for the quarter
The charge for depreciation, depletion and a $4.8-billion working capital
and amortization was $15.5 billion build for the full year), compared
in 2018, compared with $15.6 billion with $5.9 billion and $18.9 billion
in 2017. In 2019, we expect the charge for the same periods in 2017. See
to be in line with 2018. also the Glossary on page 32 for further
Non-operating items information on working capital.
Non-operating items amounted to a Capital expenditure*
post-tax charge of $1,186 million Organic capital expenditure* for the
for the quarter and $2,805 million fourth quarter and full year was $4.4
for the full year. The charge for billion and $15.1 billion respectively,
the quarter includes the impact of compared with $4.6 billion and $16.5
the annual update of environmental billion for the same periods in 2017.
provisions, changes to non-Gulf of Inorganic capital expenditure* for
Mexico oil spill related legal provisions, the fourth quarter and full year was
as well as further restructuring costs. $8.5 billion and $9.9 billion respectively,
The group restructuring programme including $6.7 billion relating to
originally announced in 2014 has now the BHP acquisition (see Note 3),
been completed. See further information compared with $0.2 billion and $1.3
on page 28. billion for the same periods in 2017.
Effective tax rate Organic capital expenditure and inorganic
The effective tax rate (ETR) on RC capital expenditure are non-GAAP measures.
profit or loss* for the fourth quarter See page 27 for further information.
and full year was 45% and 42% respectively. Divestment and other proceeds
The ETR for both periods in 2017 was Total divestment and other proceeds
significantly impacted by the effect for the year were $3.5 billion, compared
of non-operating items and therefore with $4.3 billion a year ago, and
was not a meaningful measure. includes $0.6 billion loan repayment
Adjusting for non-operating items to BP relating to the refinancing
and fair value accounting effects, of Trans Adriatic Pipeline AG in the
the underlying ETR* for the fourth fourth quarter. Divestment proceeds*
quarter and full year was 38% for were $2.4 billion for the fourth quarter
both periods, compared with 27% and and $2.9 billion for the full year,
38% for the same periods in 2017. compared with $2.5 billion and $3.4
The higher underlying ETR for the billion for the same periods in 2017.
fourth quarter reflects the reassessment Gearing*
of the recognition of deferred tax Net debt* at 31 December 2018 was
assets, partly offset by changes in $44.1 billion, compared with $37.8
the geographical mix of profits. In billion a year ago. Gearing at 31
the current environment the underlying December 2018 was 30.3%, compared
ETR for 2019 is expected to be around with 27.4% a year ago. Net debt and
40%. ETR on RC profit or loss and gearing are non-GAAP measures. See
underlying ETR are non-GAAP measures. page 25 for more information.
Dividend Reserves replacement ratio*
BP today announced a quarterly dividend The organic reserves replacement ratio
of 10.25 cents per ordinary share on a combined basis of subsidiaries
($0.615 per ADS), which is expected and equity-accounted entities was
to be paid on 29 March 2019. The corresponding 100% for the year. Including acquisitions
amount in sterling will be announced and divestments, such as the BHP transaction
on 18 March 2019. See page 25 for and investment in LLC Kharampurneftegaz
further information. in Russia, the total reserves replacement
ratio was 209%.
Brian Gilvary - Chief financial officer:
Operating cash flow excluding working capital change* was up 33% for
the full year and 17% higher than last quarter, including a positive
contribution from our new US assets. The continued strong cash flow growth
underpins the balance sheet as we absorb the BHP acquisition and deliver
more than $10 billion of divestments over the next two years.
* For items marked with an asterisk throughout this document,
definitions are provided in the Glossary on page 32.
The commentary above contains forward-looking statements and should be
read in conjunction with the cautionary statement on page 36.
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Analysis of underlying RC profit* before interest and tax
Fourth Third Fourth
quarter quarter quarter Year Year
$ million 2018 2018 2017 2018 2017
======= ======= ======= ======= =========
Underlying RC profit before interest and
tax
Upstream 3,886 3,999 2,223 14,550 5,865
Downstream 2,169 2,111 1,474 7,561 6,967
Rosneft 431 872 321 2,316 836
Other businesses and corporate (344) (345) (394) (1,558) (1,598)
Consolidation adjustment - UPII* 142 78 (149) 211 (212)
Underlying RC profit before interest and
tax 6,284 6,715 3,475 23,080 11,858
Finance costs and net finance expense
relating to pensions and other post-retirement
benefits (654) (610) (550) (2,176) (1,801)
Taxation on an underlying RC basis (2,148) (2,213) (782) (7,986) (3,812)
Non-controlling interests (5) (54) (36) (195) (79)
====== ======
Underlying RC profit attributable to BP
shareholders 3,477 3,838 2,107 12,723 6,166
================================================== ====== ====== ====== ====== ======
Reconciliations of underlying RC profit or loss to the nearest
equivalent IFRS measure are provided on page 1 for the group and on
pages 6-11 for the segments.
Analysis of RC profit (loss)* before interest and tax and
reconciliation to profit for the period
Fourth Third Fourth
quarter quarter quarter Year Year
$ million 2018 2018 2017 2018 2017
======= ======= ======= ======= =========
RC profit before interest and tax
Upstream 4,168 3,472 1,928 14,328 5,221
Downstream 2,138 2,249 1,773 6,940 7,221
Rosneft 400 808 321 2,221 836
Other businesses and corporate(a) (1,110) (815) (2,833) (3,521) (4,445)
Consolidation adjustment - UPII 142 78 (149) 211 (212)
RC profit before interest and tax 5,738 5,792 1,040 20,179 8,621
Finance costs and net finance expense
relating to pensions and other post-retirement
benefits (776) (729) (674) (2,655) (2,294)
Taxation on a RC basis (2,240) (1,918) (913) (7,343) (3,487)
Non-controlling interests (5) (54) (36) (195) (79)
RC profit (loss) attributable to BP shareholders 2,717 3,091 (583) 9,986 2,761
Inventory holding gains (losses)* (2,574) 371 816 (801) 853
Taxation (charge) credit on inventory
holding gains and losses 623 (113) (206) 198 (225)
Profit for the period attributable to
BP shareholders 766 3,349 27 9,383 3,389
=================================================== ====== ====== ====== ====== ======
(a) Includes costs related to the Gulf of Mexico oil spill. See
page 11 and also Note 2 on page 19 for further information on the
accounting for the Gulf of Mexico oil spill.
Top of page 4
Strategic progress
Upstream Advancing the energy transition
2018 Upstream production, which excludes Solar development company Lightsource
Rosneft, was 3% higher than in 2017, BP (BP 43%) has doubled its global
the highest since 2010. Adjusted for footprint over the past year, with
portfolio changes and PSA* impacts, a presence now in 10 countries. Most
underlying production* was 8.2% higher recently it announced it would enter
than 2017 due to major project* ramp-ups Brazil. During the fourth quarter,
and improved plant reliability*. Upstream Lightsource BP was awarded power purchase
production for the fourth quarter agreements (PPAs) in Australia and
was 2,627mboe/d, 1.8% higher than in the US. In the UK, it announced
a year earlier. Upstream unit production an agreement to power AB InBev's manufacturing
costs* for 2018 were higher than 2017 plants through an innovative 100MW
due to increased wellwork* activity PPA.
and the impact of higher prices on BP made a series of investments in
production entitlements. electric vehicle technology and infrastructure
The Clair Ridge project, west of Shetland during the year that significantly
in the North Sea, was the sixth Upstream progress its advanced mobility agenda.
major project to come onstream in This included the purchase of Chargemaster,
2018, following earlier start-ups operator of the UK's largest vehicle
in Egypt, Russia, Azerbaijan, the charging network, as well as venturing
Gulf of Mexico and Australia. BP has investment into battery company StoreDot.
brought 19 new major projects online Financial framework
over 2016-2018. Operating cash flow excluding Gulf
Sanction for the first phase of the of Mexico oil spill payments* was
Greater Tortue Ahmeyim LNG development $26.1 billion for the full year of
offshore Mauritania and Senegal and 2018. This compares with $24.1 billion
the Cassia Compression and Matapal for the full year of 2017.
gas projects in Trinidad were announced
in the quarter. In January, BP announced Organic capital expenditure* for the
approval of the Atlantis Phase 3 development full year of 2018 was $15.1 billion,
in the Gulf of Mexico. in the range of $15-16 billion previously
indicated. BP expects 2019 organic
Downstream capital expenditure to be in the range
Strong Downstream performance in 2018, of $15-17 billion.
with record earnings in a fourth quarter.
2018 manufacturing performance was Divestments and other proceeds totalled
strong with Solomon availability* $3.5 billion for the full year. BP
for the year of 95% and record refining intends to complete more than $10
throughput on a current portfolio billion divestments over the next
basis. two years, which includes plans announced
There was continued growth in marketing, following the BHP transaction.
with our convenience partnership model Gulf of Mexico oil spill payments
now rolled out to around 1,400 sites on a post-tax basis totalled $3.2
across the network, an increase of billion in the full year of 2018.
more than 25% in the year, and BP's Payments for 2019 are expected to
retail network in Mexico reaching be around $2 billion on a post-tax
440 sites by year end. basis.
In the quarter, BP and SOCAR announced
an agreement to explore the creation Gearing* at the end of the quarter
of a joint venture to build and operate was 30.3%. At current oil prices,
a new world-scale petrochemicals complex and in line with growing free cash
in Turkey. flow* supported by divestment proceeds,
we expect gearing to move towards
the middle of our targeted range of
20-30% in 2020.
Operating metrics Year 2018 Financial metrics Year 2018
========================== ============================
(vs. Year 2017) (vs. Year 2017)
========================== ================ ============================ ================
Tier 1 process safety Underlying RC profit*
events* 16 $12.7bn
========================== ============================
(-2) (+$6.6bn)
========================== ================ ============================ ================
Reported recordable Operating cash flow
injury frequency* excluding Gulf of
Mexico oil spill payments
0.20 (post-tax) $26.1bn
========================== ============================
(-9%) (+$2.0bn)
========================== ================ ============================ ================
Group production 3,683mboe/d Organic capital expenditure $15.1bn
========================== ============================
(+2.4%) (-$1.4bn)
========================== ================ ============================ ================
Upstream production Gulf of Mexico oil
(excludes Rosneft spill payments (post-tax)
segment) 2,539mboe/d $3.2bn
========================== ============================
(+3.0%) (-$1.9bn)
========================== ================ ============================ ================
Upstream unit production Divestment proceeds*
costs $7.15/boe $2.9bn
========================== ============================
(+0.6%) (-$0.6bn)
========================== ================ ============================ ================
BP-operated Upstream
plant reliability(a) 95.7% Net debt ratio* (gearing) 30.3%
=========================== ============================
(+1.0) (+2.9)
================ ============================ ================
Refining availability* Dividend per ordinary
94.9% share(b) 10.25 cents
========================== ============================
(-0.4) (+2.5%)
================ ============================ ================
Return on average
capital employed*(c) 11.2%
============================
(+5.4)
============================ ================
(a) BP-operated Upstream operating efficiency* has been replaced
with Upstream plant reliability as a group operating metric in the
first quarter 2018. It is more comparable with the equivalent
metric disclosed for the Downstream, which is 'Refining
availability'.
(b) Represents dividend announced in the quarter (vs. prior year quarter).
(c) Return on average capital employed is included as this is a full year report.
The commentary above contains forward-looking statements and should be
read in conjunction with the cautionary statement on page 36.
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Upstream
Fourth Third Fourth
quarter quarter quarter Year Year
$ million 2018 2018 2017 2018 2017
====== ========
Profit before interest and tax 4,156 3,473 1,928 14,322 5,229
Inventory holding (gains) losses* 12 (1) - 6 (8)
=======
RC profit before interest and tax 4,168 3,472 1,928 14,328 5,221
Net (favourable) adverse impact of non-operating
items* and fair value accounting effects* (282) 527 295 222 644
Underlying RC profit before interest and
tax*(a) 3,886 3,999 2,223 14,550 5,865
=================================================== ====== ====== ======= ====== =====
(a) See page 7 for a reconciliation to segment RC profit before interest and tax by region.
Financial results
The replacement cost profit before interest and tax for the
fourth quarter and full year was $4,168 million and $14,328 million
respectively, compared with $1,928 million and $5,221 million for
the same periods in 2017. The fourth quarter and full year included
a net non-operating gain of $136 million and a net charge of $183
million respectively, compared with a net charge of $144 million
and $671 million for the same periods in 2017. Fair value
accounting effects in the fourth quarter and full year had a
favourable impact of $146 million and an adverse impact of $39
million respectively, compared with an adverse impact of $151
million and a favourable impact of $27 million in the same periods
of 2017.
After adjusting for non-operating items and fair value
accounting effects, the underlying replacement cost profit before
interest and tax for the fourth quarter and full year was $3,886
million and $14,550 million respectively, compared with $2,223
million and $5,865 million for the same periods in 2017. The result
for the fourth quarter mainly reflected higher liquids and gas
realizations, strong gas marketing and trading results and higher
production including BHP assets acquired by BPX Energy (previously
known as the US Lower 48 business). The result for the full year
mainly reflected higher liquids and gas realizations, higher
production and lower exploration write-offs.
Production
Production for the quarter was 2,627mboe/d, 1.8% higher than
2017. Underlying production* for the quarter increased by 3.4%, due
to major project ramp-ups.
For the full year, production was 2,539mboe/d, 3.0% higher than
2017. Underlying production for the full year was 8.2% higher than
2017 due to major project ramp-ups and improved plant
reliability.
Key events
On 31 October, BP completed the acquisition of BHP's US
unconventional oil and gas assets.
On 23 November, BP announced the start-up of the Clair Ridge
project. This was the sixth major project to start up in 2018 (BP
operator 45.1%, Shell 28%, Chevron 19.4% and ConocoPhillips
7.5%).
On 14 December, BP announced the sanction for two new gas
developments offshore Trinidad, Cassia Compression and Matapal.
On 17 December, Sonangol and BP signed an agreement to progress
to final investment decision the development of the Platina field
in deepwater Block 18, offshore Angola. Sonangol also agreed to
extend the production licence for the BP-operated Greater Plutonio
project on Block 18 to 2032, subject to government approval, and
for Sonangol to assume an equity interest in the block (BP operator
50% and Sonangol Sinopec International Limited 50%).
On 21 December, BP announced final investment decision, subject
to regulatory approvals, for Phase 1 of the Greater Tortue Ahmeyim
LNG development in Mauritania and Senegal (BP operator 62% in
Mauritania and 60% in Senegal).
On 8 January, BP announced sanction of Atlantis Phase 3
development (BP operator 56% and BHP 44%) in US Gulf of Mexico. In
addition, two oil discoveries were also announced: Manuel (BP
operator 50% and Shell 50%) and Nearly Headless Nick (LLOG operator
26.84%, BP 20.25% and other partners) in the Gulf of Mexico.
On 14 January, BP and Eni signed a heads of agreement with the
Ministry of Oil and Gas of the Sultanate of Oman to work jointly
towards the award of a new exploration and production-sharing
agreement (EPSA) for Block 77 in central Oman (Eni operator 50% and
BP 50%).
Outlook
We expect full-year 2019 underlying production to be higher than
2018 due to major projects. The actual reported outcome will depend
on the exact timing of project start-ups, acquisition and
divestment activities, OPEC quotas and entitlement impacts in our
production-sharing agreements*.
We expect first-quarter 2019 reported production to be flat with
fourth-quarter 2018 with divestments of assets in the North Sea and
Alaska and turnaround and maintenance activities mainly in the high
margin Gulf of Mexico region, offset by major project start-ups and
the benefit of the BHP assets acquired by BPX Energy.
The commentary above contains forward-looking statements and should be
read in conjunction with the cautionary statement on page 36.
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Upstream (continued)
Fourth Third Fourth
quarter quarter quarter Year Year
$ million 2018 2018 2017 2018 2017
======= ========
Underlying RC profit before interest and
tax
US 1,400 1,025 629 3,693 1,238
Non-US 2,486 2,974 1,594 10,857 4,627
3,886 3,999 2,223 14,550 5,865
====== ====== ====== ====== =====
Non-operating items
US(a)(b) (267) (149) (187) (590) (330)
Non-US(c) 403 (93) 43 407 (341)
136 (242) (144) (183) (671)
====== ====== ====== ====== =====
Fair value accounting effects
US 127 (10) 8 (35) 192
Non-US 19 (275) (159) (4) (165)
146 (285) (151) (39) 27
====== ====== ====== ====== =====
RC profit before interest and tax
US 1,260 866 450 3,068 1,100
Non-US 2,908 2,606 1,478 11,260 4,121
4,168 3,472 1,928 14,328 5,221
====== ====== ====== ====== =====
Exploration expense
US(b) 84 39 27 509 282
Non-US(d) 373 271 494 936 1,798
457 310 521 1,445 2,080
Of which: Exploration expenditure written
off(b)(d) 351 227 372 1,085 1,603
============================================ ====== ====== ====== ====== =====
Production (net of royalties)(e)
Liquids* (mb/d)
US 495 424 430 445 426
Europe 154 128 117 142 119
Rest of World 673 663 796 681 811
1,321 1,216 1,344 1,268 1,356
====== ====== ====== ====== =====
Natural gas (mmcf/d)
US 2,255 1,805 1,759 1,900 1,659
Europe 215 212 186 211 235
Rest of World 5,104 5,201 5,231 5,263 4,543
7,574 7,218 7,176 7,374 6,436
====== ====== ====== ====== =====
Total hydrocarbons* (mboe/d)
US 884 736 734 772 712
Europe 191 165 150 179 160
Rest of World 1,553 1,560 1,698 1,589 1,594
2,627 2,460 2,581 2,539 2,466
====== ====== ====== ====== =====
Average realizations*(f)
Total liquids(g) ($/bbl) 61.80 69.68 56.16 64.98 49.92
Natural gas ($/mcf) 4.33 3.86 3.23 3.92 3.19
Total hydrocarbons ($/boe) 42.98 46.14 37.48 43.47 35.38
============================================ ====== ====== ====== ====== =====
(a) Fourth quarter and full year 2017 include an impairment
charge relating to BPX Energy (previously known as the US Lower 48
business), partially offset by gains associated with asset
divestments.
(b) Full year 2018 and full year 2017 include the write-off of
$124 million and $145 million respectively in relation to the value
ascribed to certain licences in the deepwater Gulf of Mexico as
part of the accounting for the acquisition of upstream assets from
Devon Energy in 2011. This has been classified within the 'other'
category of non-operating items.
(c) Fourth quarter and full year 2018 include an impairment
reversal for assets in the North Sea and Angola. Fourth quarter and
full year 2017 include BP's share of an impairment reversal
recognized by the Angola LNG equity-accounted entity, partially
offset by other items. In addition, full year 2017 includes an
impairment charge arising following the announcement of the
agreement to sell the Forties Pipeline System business to
INEOS.
(d) Full year 2017 predominantly relates to the write-off of
exploration well and lease costs in Angola. Full year 2017 also
includes the write-off of exploration well costs in Egypt.
(e) Includes BP's share of production of equity-accounted entities in the Upstream segment.
(f) Realizations are based on sales by consolidated subsidiaries
only - this excludes equity-accounted entities.
(g) Includes condensate, natural gas liquids and bitumen.
Because of rounding, some totals may not agree exactly with the
sum of their component parts.
Top of page 8
Downstream
Fourth Third Fourth
quarter quarter quarter Year Year
$ million 2018 2018 2017 2018 2017
===== ========
Profit (loss) before interest and tax (332) 2,592 2,492 6,078 7,979
Inventory holding (gains) losses* 2,470 (343) (719) 862 (758)
RC profit before interest and tax 2,138 2,249 1,773 6,940 7,221
Net (favourable) adverse impact of non-operating
items* and fair value accounting effects* 31 (138) (299) 621 (254)
Underlying RC profit before interest and
tax*(a) 2,169 2,111 1,474 7,561 6,967
=================================================== ====== ====== ====== ===== =====
(a) See page 9 for a reconciliation to segment RC profit before
interest and tax by region and by business.
Financial results
The replacement cost profit before interest and tax for the
fourth quarter and full year was $2,138 million and $6,940 million
respectively, compared with $1,773 million and $7,221 million for
the same periods in 2017.
The fourth quarter and full year include a net non-operating
charge of $401 million and $716 million respectively, compared with
a gain of $382 million and $389 million for the same periods in
2017. Fair value accounting effects had a favourable impact of $370
million in the fourth quarter and $95 million for the full year,
compared with an adverse impact of $83 million and $135 million for
the same periods in 2017.
After adjusting for non-operating items and fair value
accounting effects, the underlying replacement cost profit before
interest and tax for the fourth quarter and full year was $2,169
million and $7,561 million respectively, compared with $1,474
million and $6,967 million for the same periods in 2017.
Replacement cost profit before interest and tax for the fuels,
lubricants and petrochemicals businesses is set out on page 9.
Fuels
The fuels business reported an underlying replacement cost
profit before interest and tax of $1,624 million for the fourth
quarter and $5,642 million for the full year, compared with $976
million and $4,872 million for the same periods in 2017.
Strong fuels marketing earnings growth for the quarter and full
year reflects the benefits from our strategic improvement
programmes, enabling improved margin capture and supply chain
optimization. Our convenience partnership model is now in around
1,400 sites across our network, with more than 460 sites in Germany
with our REWE to Go offer. We also continue to grow in Mexico, with
440 BP-branded retail sites at year end, and in the quarter we
opened our first retail sites in Indonesia.
The higher refining result for the full year reflects increased
commercial optimization and strong operations, which in North
America allowed us to capture the benefits from higher North
American heavy crude oil discounts, net of pipeline capacity
apportionment impacts. These factors were partially offset by lower
industry refining margins and a higher level of turnaround
activity.
In addition, the contribution from supply and trading for the
full year was lower than last year, although the result for the
quarter was slightly higher than in the previous year.
Lubricants
The lubricants business reported an underlying replacement cost
profit before interest and tax of $311 million for the fourth
quarter and $1,292 million for the full year, compared with $375
million and $1,479 million for the same periods in 2017. The result
for the quarter and full year reflects continued premium brand
growth, more than offset by the adverse lag impact of increasing
base oil prices, as well as adverse foreign exchange rate
movements. Volumes in the fourth quarter were lower due to a
planned systems implementation.
Petrochemicals
The petrochemicals business reported an underlying replacement
cost profit before interest and tax of $234 million for the fourth
quarter and $627 million for the full year, compared with $123
million and $616 million for the same periods in 2017. The result
for the quarter and full year reflects an improved margin
environment, increased margin optimization and continued strong
cost management. The result for the full year was higher than last
year despite the divestment of our interest in the SECCO joint
venture in 2017 and a higher level of turnaround activity in
2018.
In the quarter we signed a heads of agreement with SOCAR Turkey
to evaluate the creation of a joint venture to build and operate
the largest integrated PTA, PX and aromatics complex in the western
hemisphere.
Outlook
Looking to the first quarter of 2019, we expect significantly
lower industry refining margins and narrower North American heavy
crude oil discounts.
The commentary above contains forward-looking statements and should be
read in conjunction with the cautionary statement on page 36.
-----------------------------------------------------------------------
Top of page 9
Downstream (continued)
Fourth Third Fourth
quarter quarter quarter Year Year
$ million 2018 2018 2017 2018 2017
======= ======= ======= ======= =========
Underlying RC profit before interest and
tax - by region
US 995 835 501 2,818 1,978
Non-US 1,174 1,276 973 4,743 4,989
2,169 2,111 1,474 7,561 6,967
====== ====== ====== ====== ======
Non-operating items
US (109) (14) (25) (295) (48)
Non-US(a) (292) (23) 407 (421) 437
(401) (37) 382 (716) 389
====== ====== ====== ====== ======
Fair value accounting effects(b)
US 184 81 3 (155) (29)
Non-US 186 94 (86) 250 (106)
370 175 (83) 95 (135)
====== ====== ====== ====== ======
RC profit before interest and tax
US 1,070 902 479 2,368 1,901
Non-US 1,068 1,347 1,294 4,572 5,320
2,138 2,249 1,773 6,940 7,221
====== ====== ====== ====== ======
Underlying RC profit before interest and
tax - by business(c)(d)
Fuels 1,624 1,566 976 5,642 4,872
Lubricants 311 324 375 1,292 1,479
Petrochemicals 234 221 123 627 616
2,169 2,111 1,474 7,561 6,967
====== ====== ====== ====== ======
Non-operating items and fair value accounting
effects(b)
Fuels 173 140 (202) (381) (193)
Lubricants (198) - (14) (227) (22)
Petrochemicals (6) (2) 515 (13) 469
(31) 138 299 (621) 254
====== ====== ====== ====== ======
RC profit before interest and tax(c)(d)
Fuels 1,797 1,706 774 5,261 4,679
Lubricants 113 324 361 1,065 1,457
Petrochemicals 228 219 638 614 1,085
======
2,138 2,249 1,773 6,940 7,221
====== ====== ====== ====== ======
BP average refining marker margin (RMM)*
($/bbl) 11.0 14.7 14.4 13.1 14.1
Refinery throughputs (mb/d)
US 691 740 714 703 713
Europe 735 805 741 781 773
Rest of World 240 248 243 241 216
1,666 1,793 1,698 1,725 1,702
Refining availability* (%) 95.2 96.3 96.1 94.9 95.3
================================================ ====== ====== ====== ====== ======
Marketing sales of refined products (mb/d)
US 1,138 1,169 1,127 1,141 1,151
Europe 1,053 1,166 1,132 1,100 1,140
Rest of World 526 497 542 495 508
2,717 2,832 2,801 2,736 2,799
Trading/supply sales of refined products 3,199 3,147 3,549 3,194 3,149
Total sales volumes of refined products 5,916 5,979 6,350 5,930 5,948
================================================ ====== ====== ====== ====== ======
Petrochemicals production (kte)
US 672 660 641 2,235 2,428
Europe 1,037 1,209 1,559 4,468 5,462
Rest of World 1,259 1,146 1,306 5,154 7,405
2,968 3,015 3,506 11,857 15,295
====== ====== ====== ====== ======
(a) Fourth quarter and full year 2017 gain primarily reflects
the disposal of our shareholding in the SECCO joint venture.
(b) For Downstream, fair value accounting effects arise solely
in the fuels business. See page 29 for further information.
(c) Segment-level overhead expenses are included in the fuels business result.
(d) Results from petrochemicals at our Gelsenkirchen and Mülheim
sites in Germany are reported in the fuels business.
Top of page 10
Rosneft
Fourth Third Fourth
quarter quarter quarter Year Year
$ million 2018(a) 2018 2017 2018(a) 2017
======= ======= ======= ======= ======
Profit before interest and tax(b)(c) 308 835 418 2,288 923
Inventory holding (gains) losses* 92 (27) (97) (67) (87)
RC profit before interest and tax 400 808 321 2,221 836
Net charge (credit) for non-operating
items* 31 64 - 95 -
Underlying RC profit before interest and
tax* 431 872 321 2,316 836
=========================================== ======= ====== ====== ====== ===
Financial results
Replacement cost (RC) profit before interest and tax for the
fourth quarter and full year was $400 million and $2,221 million
respectively, compared with $321 million and $836 million for the
same periods in 2017.
After adjusting for non-operating items, the underlying RC
profit before interest and tax for the fourth quarter and full year
was $431 million and $2,316 million respectively. There were no
non-operating items in the fourth quarter or full year of 2017.
Compared with the same periods in 2017, the results for the
fourth quarter and full year were primarily affected by higher oil
prices and favourable foreign exchange, partially offset by adverse
duty lag effects.
In September the extraordinary general meeting adopted a
resolution to pay interim dividends for the first half of 2018 of
14.58 Russian roubles per ordinary share. In October BP received a
dividend of $420 million, after the deduction of withholding
tax.
Key events
In September Rosneft and BP agreed to jointly explore two
additional oil and gas licence areas located in the Sakha (Yakutia)
republic of the Russian Federation. In December the first closing
of the deal was completed with LLC Yermakneftegaz, a 51:49 joint
venture between Rosneft and BP, acquiring a subsidiary company from
Rosneft. The transfer of licences to the subsidiary, subject to
external approvals, is expected in 2019.
In December the re-issue was completed of the Kharampurskoe and
Festivalnoe subsoil-use licences to LLC Kharampurneftegaz, in which
Rosneft and BP own 51% and 49% interests respectively.
BP's interests in LLC Yermakneftegaz and LLC Kharampurneftegaz
are reported through the Upstream segment.
Fourth Third Fourth
quarter quarter quarter Year Year
2018(a) 2018 2017 2018(a) 2017
========================================== ======= ======= ======= ======= =======
Production (net of royalties) (BP share)
Liquids* (mb/d) 946 933 899 923 904
Natural gas (mmcf/d) 1,312 1,260 1,333 1,285 1,308
Total hydrocarbons* (mboe/d) 1,173 1,151 1,129 1,144 1,129
=========================================== ======= ======= ======= ======= =====
(a) The operational and financial information of the Rosneft
segment for the fourth quarter and full year is based on
preliminary operational and financial results of Rosneft for the
full year ended 31 December 2018. Actual results may differ from
these amounts.
(b) The Rosneft segment result includes equity-accounted
earnings arising from BP's 19.75% shareholding in Rosneft as
adjusted for the accounting required under IFRS relating to BP's
purchase of its interest in Rosneft and the amortization of the
deferred gain relating to the divestment of BP's interest in
TNK-BP. These adjustments increase the segment's reported profit
before interest and tax, as shown in the table above, compared with
the amounts reported in Rosneft's IFRS financial statements.
(c) BP's adjusted share of Rosneft's earnings after Rosneft's own finance costs, taxation and non-controlling interests is included in the BP group income statement within profit before interest and taxation. For each year-to-date period it is calculated by translating the amounts reported in Russian roubles into US dollars using the average exchange rate for the year to date.
Top of page 11
Other businesses and corporate
Fourth Third Fourth
quarter quarter quarter Year Year
$ million 2018 2018 2017 2018 2017
======= ======= ======= ======= =========
Profit (loss) before interest and tax
Gulf of Mexico oil spill - business economic
loss claims (26) (69) (2,110) (344) (2,370)
Gulf of Mexico oil spill - other (41) (59) (111) (370) (317)
Other (1,043) (687) (612) (2,807) (1,758)
Profit (loss) before interest and tax (1,110) (815) (2,833) (3,521) (4,445)
Inventory holding (gains) losses* - - - - -
RC profit (loss) before interest and
tax (1,110) (815) (2,833) (3,521) (4,445)
Net charge (credit) for non-operating
items*
Gulf of Mexico oil spill - business economic
loss claims 26 69 2,110 344 2,370
Gulf of Mexico oil spill - other 41 59 111 370 317
Other 699 342 218 1,249 160
Net charge (credit) for non-operating
items 766 470 2,439 1,963 2,847
====== ====== ====== ====== ======
Underlying RC profit (loss) before interest
and tax* (344) (345) (394) (1,558) (1,598)
=============================================== ====== ====== ====== ====== ======
Underlying RC profit (loss) before interest
and tax
US (179) (166) (29) (615) (475)
Non-US (165) (179) (365) (943) (1,123)
(344) (345) (394) (1,558) (1,598)
====== ====== ====== ====== ======
Non-operating items
US (654) (438) (2,381) (1,738) (2,861)
Non-US (112) (32) (58) (225) 14
(766) (470) (2,439) (1,963) (2,847)
====== ====== ====== ====== ======
RC profit (loss) before interest and
tax
US (833) (604) (2,410) (2,353) (3,336)
Non-US (277) (211) (423) (1,168) (1,109)
(1,110) (815) (2,833) (3,521) (4,445)
====== ====== ====== ====== ======
Other businesses and corporate comprises our alternative energy
business, shipping, treasury, corporate activities including
centralized functions, and the costs of the Gulf of Mexico oil
spill.
Financial results
The replacement cost loss before interest and tax for the fourth
quarter and full year was $1,110 million and $3,521 million
respectively, compared with $2,833 million and $4,445 million for
the same periods in 2017.
The results included a net non-operating charge of $766 million
for the fourth quarter and $1,963 million for the full year,
primarily relating to the costs for the Gulf of Mexico oil spill,
environmental and other provisions, impairments and restructuring
costs, compared with a charge of $2,439 million and $2,847 million
for the same periods in 2017. See Note 2 on page 19 for more
information on the Gulf of Mexico oil spill.
After adjusting for non-operating items, the underlying
replacement cost loss before interest and tax for the fourth
quarter and full year was $344 million and $1,558 million
respectively, compared with $394 million and $1,598 million for the
same periods in 2017.
Alternative Energy
The net ethanol-equivalent production (which includes ethanol
and sugar) for the fourth quarter and full year was 144 million
litres and 765 million litres respectively, compared with 188
million litres and 776 million litres for the same periods in 2017.
In the fourth quarter formal approvals were received for the Opla
ethanol logistics JV with Copersucar, which is now established and
operating well.
Net wind generation capacity was 1,001MW at 31 December 2018,
compared with 1,432MW at 31 December 2017. BP's net share of wind
generation for the fourth quarter and full year was 933GWh and
3,821GWh respectively, compared with 1,148GWh and 4,004GWh for the
same periods in 2017. In 2018 we divested three of our wind
facilities in Texas. We intend to focus on optimizing and investing
in upgrades to our remaining sites, enabling us to continue to grow
a wind energy business that we believe is sustainable for the long
term.
In December, BP's strategic solar partnership with Lightsource
BP (BP 43%) reached its first anniversary. In that time,
Lightsource BP has doubled its global footprint, with a presence
now in 10 countries. Most recently the company announced it would
enter Brazil, leveraging BP's relationships and existing operations
to fund, develop and operate solar projects locally. Also during
the fourth quarter, Lightsource BP was awarded a 105MW power
purchase agreement (PPA) in New South Wales, Australia and PPAs
totalling 25MW in California and New Mexico in the US. In the UK,
Lightsource BP also announced that it will power AB InBev's
manufacturing plants through an innovative 100MW PPA.
Outlook
In 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 36.
-----------------------------------------------------------------------
Top of page 12
Financial statements
Group income statement
Fourth Third Fourth
quarter quarter quarter Year Year
$ million 2018 2018 2017 2018 2017
======= ======= ======= ======= =========
Sales and other operating revenues (Note
5) 75,677 79,468 67,816 298,756 240,208
Earnings from joint ventures - after interest
and tax 236 148 581 897 1,177
Earnings from associates - after interest
and tax 425 990 526 2,856 1,330
Interest and other income 295 154 223 773 657
Gains on sale of businesses and fixed
assets 252 43 876 456 1,210
=======
Total revenues and other income 76,885 80,803 70,022 303,738 244,582
Purchases 59,019 60,923 51,745 229,878 179,716
Production and manufacturing expenses(a) 6,173 5,879 7,759 23,005 24,229
Production and similar taxes (Note 7) 186 451 511 1,536 1,775
Depreciation, depletion and amortization
(Note 6) 3,987 3,728 4,045 15,457 15,584
Impairment and losses on sale of businesses
and fixed assets 244 548 604 860 1,216
Exploration expense 457 310 521 1,445 2,080
Distribution and administration expenses 3,655 2,801 2,981 12,179 10,508
=======
Profit (loss) before interest and taxation 3,164 6,163 1,856 19,378 9,474
Finance costs(a) 742 698 616 2,528 2,074
Net finance expense relating to pensions
and other post-retirement benefits 34 31 58 127 220
Profit (loss) before taxation 2,388 5,434 1,182 16,723 7,180
Taxation(a) 1,617 2,031 1,119 7,145 3,712
Profit (loss) for the period 771 3,403 63 9,578 3,468
================================================ ======= ======= ======= ======= =======
Attributable to
BP shareholders 766 3,349 27 9,383 3,389
Non-controlling interests 5 54 36 195 79
771 3,403 63 9,578 3,468
======= ======= ======= ======= =======
Earnings per share (Note 8)
Profit (loss) for the period attributable
to BP shareholders
Per ordinary share (cents)
Basic 3.83 16.74 0.14 46.98 17.20
Diluted 3.80 16.65 0.14 46.67 17.10
Per ADS (dollars)
Basic 0.23 1.00 0.01 2.82 1.03
Diluted 0.23 1.00 0.01 2.80 1.03
================================================ ======= ======= ======= ======= =======
(a) See Note 2 for information on the impact of the Gulf of
Mexico oil spill on these income statement line items.
Top of page 13
Condensed group statement of comprehensive income
Fourth Third Fourth
quarter quarter quarter Year Year
$ million 2018 2018 2017 2018 2017
======= ======= ======= ======= =========
Profit (loss) for the period 771 3,403 63 9,578 3,468
Other comprehensive income
Items that may be reclassified subsequently
to profit or loss
Currency translation differences (937) (753) 264 (3,771) 1,986
Exchange (gains) losses on translation
of foreign operations reclassified to
gain or loss on sale of businesses and
fixed assets - - (138) - (120)
Available-for-sale investments - - 11 - 14
Cash flow hedges and costs of hedging (68) 65 50 (192) 425
Share of items relating to equity-accounted
entities, net of tax 200 95 133 417 564
Income tax relating to items that may
be reclassified 33 9 (16) 4 (196)
(772) (584) 304 (3,542) 2,673
====== ====== ====== ====== ======
Items that will not be reclassified to
profit or loss
Remeasurements of the net pension and
other post-retirement benefit liability
or asset (651) 389 1,599 2,317 3,646
Cash flow hedges that will subsequently
be transferred to the balance sheet (8) (7) - (37) -
Income tax relating to items that will
not be reclassified 223 (119) (604) (718) (1,303)
(436) 263 995 1,562 2,343
====== ====== ====== ====== ======
Other comprehensive income (1,208) (321) 1,299 (1,980) 5,016
====== ====== ====== ====== ======
Total comprehensive income (437) 3,082 1,362 7,598 8,484
================================================ ====== ====== ====== ====== ======
Attributable to
BP shareholders (444) 3,040 1,312 7,444 8,353
Non-controlling interests 7 42 50 154 131
(437) 3,082 1,362 7,598 8,484
====== ====== ====== ====== ======
Top of page 14
Condensed group statement of changes in equity
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(a) (180) - (180)
========================================= ============== ============= =======
At 1 January 2018 98,311 1,913 100,224
=========================================
Total comprehensive income 7,444 154 7,598
Dividends (6,699) (170) (6,869)
Cash flow hedges transferred to the
balance sheet, net of tax 26 - 26
Repurchase of ordinary share capital (355) - (355)
Share-based payments, net of tax 703 - 703
Share of equity-accounted entities'
changes in equity, net of tax 14 - 14
Transactions involving non-controlling
interests, net of tax - 207 207
At 31 December 2018 99,444 2,104 101,548
========================================= ============== ============= =======
BP shareholders' Non-controlling Total
$ million equity interests equity
========================================
At 1 January 2017 95,286 1,557 96,843
=========================================
Total comprehensive income 8,353 131 8,484
Dividends (6,153) (141) (6,294)
Repurchase of ordinary share capital (343) - (343)
Share-based payments, net of tax 687 - 687
Share of equity-accounted entities'
changes in equity, net of tax 215 - 215
Transactions involving non-controlling
interests, net of tax 446 366 812
At 31 December 2017 98,491 1,913 100,404
========================================= ============== ============= =======
(a) See Note 1 for further information.
Top of page 15
Group balance sheet
31 December 31 December
$ million 2018 2017
Non-current assets
Property, plant and equipment 135,261 129,471
Goodwill 12,204 11,551
Intangible assets 17,284 18,355
Investments in joint ventures 8,647 7,994
Investments in associates 17,673 16,991
Other investments 1,341 1,245
Fixed assets 192,410 185,607
Loans 637 646
Trade and other receivables 1,834 1,434
Derivative financial instruments 5,145 4,110
Prepayments 1,179 1,112
Deferred tax assets 3,706 4,469
Defined benefit pension plan surpluses 5,955 4,169
210,866 201,547
=========== ===========
Current assets
Loans 326 190
Inventories 17,988 19,011
Trade and other receivables 24,478 24,849
Derivative financial instruments 3,846 3,032
Prepayments 963 1,414
Current tax receivable 1,019 761
Other investments 222 125
Cash and cash equivalents 22,468 25,586
=========================================================
71,310 74,968
=========== ===========
Total assets 282,176 276,515
========================================================= =========== ===========
Current liabilities
Trade and other payables 46,265 44,209
Derivative financial instruments 3,308 2,808
Accruals 4,626 4,960
Finance debt 9,373 7,739
Current tax payable 2,101 1,686
Provisions 2,564 3,324
68,237 64,726
=========== ===========
Non-current liabilities
Other payables 13,830 13,889
Derivative financial instruments 5,625 3,761
Accruals 575 505
Finance debt 56,426 55,491
Deferred tax liabilities 9,812 7,982
Provisions 17,732 20,620
Defined benefit pension plan and other post-retirement
benefit plan deficits 8,391 9,137
112,391 111,385
=========== ===========
Total liabilities 180,628 176,111
========================================================= =========== ===========
Net assets 101,548 100,404
========================================================= =========== ===========
Equity
BP shareholders' equity 99,444 98,491
Non-controlling interests 2,104 1,913
=========================================================
Total equity 101,548 100,404
========================================================= =========== ===========
Top of page 16
Condensed group cash flow statement
Fourth Third Fourth
quarter quarter quarter Year Year
$ million 2018 2018 2017 2018 2017
======== ======= ======= ======== ==========
Operating activities
Profit (loss) before taxation 2,388 5,434 1,182 16,723 7,180
Adjustments to reconcile profit (loss)
before taxation to net cash provided by
operating activities
Depreciation, depletion and amortization
and exploration expenditure written off 4,338 3,955 4,417 16,542 17,187
Impairment and (gain) loss on sale of
businesses and fixed assets (8) 505 (272) 404 6
Earnings from equity-accounted entities,
less dividends received (30) (664) (820) (2,218) (1,254)
Net charge for interest and other finance
expense, less net interest paid 222 114 294 607 793
Share-based payments 126 160 166 690 661
Net operating charge for pensions and
other post-retirement benefits, less
contributions and benefit payments for
unfunded plans (60) (62) (215) (386) (394)
Net charge for provisions, less payments 617 145 2,244 986 2,106
Movements in inventories and other current
and non-current assets and liabilities 778 (1,573) (60) (4,763) (3,352)
Income taxes paid (1,542) (1,922) (1,033) (5,712) (4,002)
Net cash provided by operating activities 6,829 6,092 5,903 22,873 18,931
=================================================== ======= ====== ====== ======= =======
Investing activities
Expenditure on property, plant and equipment,
intangible and other assets (5,962) (3,675) (4,422) (16,707) (16,562)
Acquisitions, net of cash acquired (6,379) (606) (16) (6,986) (327)
Investment in joint ventures (290) (35) (15) (382) (50)
Investment in associates (265) (88) (368) (1,013) (901)
Total cash capital expenditure (12,896) (4,404) (4,821) (25,088) (17,840)
Proceeds from disposal of fixed assets 660 90 2,287 940 2,936
Proceeds from disposal of businesses,
net of cash disposed 1,758 26 173 1,911 478
Proceeds from loan repayments 619 14 8 666 349
Net cash used in investing activities (9,859) (4,274) (2,353) (21,571) (14,077)
=================================================== ======= ====== ====== ======= =======
Financing activities
Net issue (repurchase) of shares (16) (139) (343) (355) (343)
Proceeds from long-term financing 2,118 5,888 201 9,038 8,712
Repayments of long-term financing (1,806) (2,521) (2,657) (7,210) (6,276)
Net increase (decrease) in short-term
debt 889 485 (297) 1,317 (158)
Net increase (decrease) in non-controlling
interests - 1 982 - 1,063
Dividends paid - BP shareholders (1,733) (1,410) (1,627) (6,699) (6,153)
- non-controlling interests (41) (59) (32) (170) (141)
Net cash provided by (used in) financing
activities (589) 2,245 (3,773) (4,079) (3,296)
=================================================== ======= ====== ====== ======= =======
Currency translation differences relating
to cash and cash equivalents (105) (56) 29 (330) 544
Increase (decrease) in cash and cash equivalents (3,724) 4,007 (194) (3,107) 2,102
=================================================== ======= ====== ====== ======= =======
Cash and cash equivalents at beginning
of period(a) 26,192 22,185 25,780 25,575 23,484
Cash and cash equivalents at end of period 22,468 26,192 25,586 22,468 25,586
=================================================== ======= ====== ====== ======= =======
(a) See Note 1 for further information.
Top of page 17
Notes
Note 1. Basis of preparation
The results for the interim periods and for the year ended 31
December 2018 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 2017 included in BP Annual Report and Form
20-F 2017.
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. 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 2018, which are the same
as those used in preparing BP Annual Report and Form 20-F 2017 with
the exception of the implementation of IFRS 9 'Financial
Instruments' and IFRS 15 'Revenue from Contracts with Customers'
from 1 January 2018.
New International Financial Reporting Standards adopted
BP adopted IFRS 9 'Financial Instruments' and IFRS 15 'Revenue
from Contracts with Customers' with effect from 1 January 2018.
Information on the implementation of new accounting standards is
included in BP Annual Report and Form 20-F 2017 - Financial
statements - Note 1 Significant accounting policies, judgements,
estimates and assumptions - Impact of new International Financial
Reporting Standards.
IFRS 9 'Financial Instruments'
IFRS 9 provides a single classification and measurement approach
for financial assets that reflects the business model in which they
are managed and their cash flow characteristics. The group's
financial assets are classified as measured at amortized cost, fair
value through profit or loss, or fair value through other
comprehensive income. Investments in equity instruments are
classified as measured at fair value through profit or loss unless
the group elects, on an instrument-by-instrument basis, on initial
recognition to recognize fair value gains and losses in other
comprehensive income. The adoption of IFRS 9 did not have a
significant effect on the group's accounting policies relating to
financial liabilities.
Under IFRS 9, impairments of financial assets classified as
measured at amortized cost are recognized on an expected loss basis
which incorporates forward-looking information when assessing
credit risk. Movements in the expected loss reserve are recognized
in profit or loss.
Under IFRS 9, fair value movements on the time value and cross
currency basis spreads of certain hedging instruments are initially
recognized in equity to the extent that they relate to the hedged
item. Previously these were recognized in the income statement. In
addition where the gain or loss on cash flow hedging instruments
initially reported in other comprehensive income is transferred to
the initial carrying amount of a non-financial asset or liability
this is no longer presented as a reclassification adjustment.
Instead the transfer to the balance sheet is presented in the
statement of changes in equity.
The overall impact on transition to IFRS 9, including the impact
upon the group's share of equity-accounted entities, was a
reduction of $180 million in net assets, net of tax. This
adjustment mainly related to an increase in the credit reserve of
financial assets in the scope of IFRS 9's impairment requirements.
As permitted by IFRS 9 comparatives were not restated. For certain
line items in the balance sheet the closing balance at 31 December
2017 and the opening balance at 1 January 2018 therefore differ (as
summarized below). Cash and cash equivalents at the beginning of
2018 in the Condensed group cash flow statement and Note 10 (Net
debt) are the 1 January 2018 amounts included in the table
below.
Adjustment
31 December 1 January on adoption
$ million 2017 2018 of IFRS 9
=========== ========= =============
Non-current
Investments in equity-accounted entities 24,985 24,903 (82)
Loans, trade and other receivables 2,080 2,069 (11)
Deferred tax liabilities (7,982) (7,946) 36
Current
Loans, trade and other receivables 25,039 24,927 (112)
Cash and cash equivalents 25,586 25,575 (11)
=========================================== ========== ======== =========
Net assets 100,404 100,224 (180)
=========================================== ========== ======== =========
Top of page 18
Note 1. Basis of preparation (continued)
IFRS 15 'Revenue from Contracts with Customers'
Under IFRS 15, revenue from contracts with customers is
recognized as or when the group satisfies a performance obligation
by transferring a promised good or service to a customer. A good or
service is transferred when the customer obtains control of that
good or service. The transfer of control of oil, natural gas,
natural gas liquids, LNG, petroleum and chemical products, and
other items sold by the group usually coincides with title passing
to the customer and the customer taking physical possession. The
group principally satisfies its performance obligations at a point
in time and the amounts of revenue recognized relating to
performance obligations satisfied over time are not significant.
The accounting for revenue under IFRS 15 does not, therefore,
represent a substantive change from the group's previous practice
for recognizing revenue from sales to customers.
BP elected to apply the 'modified retrospective' approach to
transition permitted by IFRS 15 under which comparative financial
information is not restated. Certain changes in accounting arising
from the implementation of IFRS 15 were identified but the standard
did not have a material effect on the group's financial statements
as at 1 January 2018 and so no transition adjustment was made. The
implementation of the standard has also not had a material effect
on the group's results for the year ended 31 December 2018 compared
to those that would have been reported under the group's previous
accounting policy for revenue.
An analysis of revenue from contracts with customers by product
is presented in Note 5. Amounts presented for comparative periods
in 2017 include revenues determined in accordance with the group's
previous accounting policies relating to revenue. The total amounts
presented do not, therefore, represent the revenue from contracts
with customers that would have been reported for those periods had
IFRS 15 been applied using a fully retrospective approach to
transition but the differences are not significant.
Change in significant estimate - decommissioning provision
Decommissioning provision cost estimates are reviewed regularly
and a review was undertaken in the second quarter of 2018. The
timing and amount of estimated future expenditures were re-assessed
and discounted to determine the present value. From 30 June 2018
the present value of the decommissioning provision is determined by
discounting the estimated cash flows expressed in expected future
prices, i.e. taking account of expected inflation, at a nominal
discount rate of 2.5% as at 30 June 2018. Prior to 30 June 2018,
the group estimated future cash flows in real terms i.e. at current
prices and discounted them using a real discount rate of 0.5% as at
31 December 2017.
The impact of the review was a reduction in the decommissioning
provision of $1.5 billion as at 30 June 2018, with a similar
reduction in the carrying amount of property, plant and equipment.
There was no significant impact on the income statement for the
first half of 2018. The impact on the income statement for the
second half of 2018 was a decrease in depreciation, depletion and
amortization of approximately $80 million and an increase in
finance costs of approximately $80 million.
The nominal discount rate applied to provisions was revised at
31 December 2018 to 3.0%. The impact of this rate increase was a
further $1.3 billion reduction in the decommissioning provision,
with a similar reduction in the carrying amount of property, plant
and equipment.
For further information on the group's accounting policy on
significant estimates and judgements relating to provisions, see BP
Annual Report and 20-F 2017 - Financial statements - Note 1
Significant accounting policies, estimates and assumptions.
Top of page 19
Note 2. Gulf of Mexico oil spill
(a) Overview
The information presented in this note should be read in
conjunction with Note 2 of the consolidated financial statements
and pages 270-272 of Legal proceedings included in BP Annual Report
and Form 20-F 2017.
The group income statement includes a post-tax charge for the
fourth quarter of $20 million relating to business economic loss
(BEL) claims and $15 million relating to other claims and
litigation. The group income statement also includes finance costs
relating to the unwinding of discounting effects relating to
payables.
The amounts set out below reflect the impacts on the
consolidated financial statements of the Gulf of Mexico oil spill
for the periods presented. The income statement, balance sheet and
cash flow statement impacts are included within the relevant line
items in those statements as set out below.
Fourth Third Fourth
quarter quarter quarter Year Year
$ million 2018 2018 2017 2018 2017
======= ======= ======= ======= =========
Income statement
Production and manufacturing expenses 67 128 2,221 714 2,687
Profit (loss) before interest and taxation (67) (128) (2,221) (714) (2,687)
Finance costs 122 119 124 479 493
Profit (loss) before taxation (189) (247) (2,345) (1,193) (3,180)
Taxation (8) 15 (2,495) 174 (2,222)
Profit (loss) for the period (197) (232) (4,840) (1,019) (5,402)
============================================= ====== ====== ====== ====== ======
The cumulative pre-tax income statement charge since the
incident, in April 2010, amounts to $66,958 million.
31 December 31 December
$ million 2018 2017
=========== =============
Balance sheet
Current assets
Trade and other receivables 214 252
Current liabilities
Trade and other payables (2,279) (2,089)
Provisions (333) (1,439)
Net current assets (liabilities) (2,398) (3,276)
======================================= ========== ==========
Non-current assets
Deferred tax assets 1,563 2,067
Non-current liabilities
Other payables (11,922) (12,253)
Provisions (12) (1,141)
Deferred tax liabilities 3,999 3,634
Net non-current assets (liabilities) (6,372) (7,693)
Net assets (liabilities) (8,770) (10,969)
======================================= ========== ==========
Fourth Third Fourth
quarter quarter quarter Year Year
$ million 2018 2018 2017 2018 2017
======= ======= ======= ======= =========
Cash flow statement - Operating activities
Profit (loss) before taxation (189) (247) (2,345) (1,193) (3,180)
Adjustments to reconcile profit (loss)
before taxation to net cash provided by
operating activities
Net charge for interest and other finance
expense, less net interest paid 122 119 124 479 493
Net charge for provisions, less payments 32 106 2,181 240 2,542
Movements in inventories and other current
and non-current assets and liabilities (238) (538) (413) (3,057) (5,191)
Pre-tax cash flows (273) (560) (453) (3,531) (5,336)
============================================= ====== ====== ====== ====== ======
Top of page 20
Note 2. Gulf of Mexico oil spill (continued)
Cash outflows in 2018 and 2017 include payments made under the
2012 agreement with the US government to resolve all federal
criminal claims arising from the incident and the 2016 consent
decree and settlement agreement with the United States and the five
Gulf coast states. Net cash from operating activities relating to
the Gulf of Mexico oil spill, on a post-tax basis, amounted to an
outflow of $272 million and $3,218 million in the fourth quarter
and full year of 2018 respectively. For the same periods in 2017,
the amount was an outflow of $284 million and $5,167 million
respectively.
(b) Provisions and other payables
Provisions
Movements in the remaining provision, which relates to
litigation and claims, for the fourth quarter are shown in the
table below.
$ million
================================ ======
At 1 October 2018 389
Net increase in provision 45
Reclassified to other payables (60)
Utilization (29)
At 31 December 2018 345
================================= ===
Movements in the remaining provision, which relates to
litigation and claims, for the full year are shown in the table
below.
$ million
================================ =========
At 1 January 2018 2,580
Net increase in provision 629
Reclassified to other payables (2,045)
Utilization (819)
At 31 December 2018 345
================================= ======
The provision includes amounts for the future cost of resolving
claims by individuals and businesses for damage to real or personal
property, lost profits or impairment of earning capacity and loss
of subsistence use of natural resources.
PSC settlement
Provisions and other payables include the latest estimate for
the remaining costs associated with the 2012 Plaintiffs' Steering
Committee (PSC) settlement. These costs relate predominantly to
business economic loss (BEL) claims and associated administration
costs. The amounts ultimately payable may differ from the amount
provided and the timing of payments is uncertain.
The settlement programme's determination of BEL claims was
substantially completed by the end of 2017 and remaining claims
continued to be processed throughout 2018 with only a very small
number of claims now remaining to be determined. Nevertheless, a
significant number of BEL claims determined by the settlement
programme have been and continue to be appealed by BP and/or the
claimants.
As settlement agreements have been reached with claimants
amounts payable have been reclassified from provisions to other
payables. The remaining amount provided for includes the latest
estimate of the amounts that are expected ultimately to be paid to
resolve outstanding BEL claims. Claims under appeal will ultimately
only be resolved once the full judicial appeals process has been
concluded, including appeals to the Federal District Court and
Fifth Circuit, as may be the case, or when settlements are reached
with individual claimants. Depending upon the ultimate resolution
of these claims, the amounts payable may differ from those
currently provided.
Payments to resolve outstanding claims under the PSC settlement
are expected to be made over a number of years. The timing of
payments, however, is uncertain, and, in particular, will be
impacted by how long it takes to resolve claims that have been
appealed and may be appealed in the future.
Other payables
Other payables includes amounts payable under the consent decree
and settlement agreement with the United States and the five Gulf
coast states for natural resource damages, state claims and Clean
Water Act penalties, and BP's remaining commitment to fund the Gulf
of Mexico Research Initiative.
Other payables also includes amounts payable for settled
economic loss and property damage claims which are payable over a
period of up to nine years.
Further information on provisions, other payables, and
contingent liabilities is provided in BP Annual Report and Form
20-F 2017 - Financial statements - Note 2.
Top of page 21
Note 3. Business combinations
BP undertook a number of business combinations in 2018. For the
full year, total consideration paid in cash amounted to $7,100
million, offset by cash acquired of $114 million. For the fourth
quarter, total consideration paid in cash amounted to $6,485
million, offset by cash acquired of $106 million.
On 31 October 2018, BP acquired from BHP Billiton Petroleum
(North America) Inc. 100% of the issued share capital of Petrohawk
Energy Corporation, a wholly owned subsidiary of BHP that holds a
portfolio of unconventional onshore US oil and gas assets.
The acquisition brings BP extensive oil and gas production and
resources in the liquids-rich regions of the Permian and Eagle Ford
basins in Texas and in the Haynesville gas basin in Texas and
Louisiana.
The total consideration for the transaction, after customary
closing adjustments and the effect of discounting deferred
payments, is $10,302 million, which will all be paid in cash. As at
31 December 2018, $6,788 million of the consideration had been
paid, including $525 million during the third quarter 2018 and
$6,263 million during the fourth quarter 2018. The remaining
discounted amount of $3,514 million is included within other
payables on the group balance sheet and will be paid in four
instalments, with the final instalment being paid in April
2019.
The transaction has been accounted for as a business combination
using the acquisition method. The provisional fair values of the
identifiable assets and liabilities acquired, as at the date of
acquisition, are shown in the table below. No goodwill has been
recognized on the acquisition.
$ million
Assets
Property, plant and equipment 10,845
Intangible assets 21
Inventories 27
Trade and other receivables 493
Cash 104
Liabilities
Trade and other payables (659)
Provisions (323)
Non-controlling interest (206)
Total consideration 10,302
================================== ======
The acquisition-date fair values of the assets and liabilities
acquired are provisional. As we gain further understanding of the
acquired properties and development options, these fair values may
be adjusted.
An analysis of the cash flows relating to the acquisition
included within the cash flow statement for the full year 2018 is
provided below.
Year
$ million 2018
============================================================== =======
Transaction costs of the acquisition (included in cash flows
from operating activities) 62
Interest on deferred payments (included in cash flows from
operating activities) 21
Cash consideration paid, net of cash acquired (included in
cash flows from investing activities) 6,684
Total net cash outflow for the acquisition 6,767
=============================================================== =====
From the date of acquisition to 31 December 2018, the acquired
activities generated revenues of $472 million and profit before tax
of $49 million. If the business combination had taken place on 1
January 2018, it is estimated that the acquired activities would
have generated revenues of $2,798 million and profit before tax of
$431 million.
Top of page 22
Note 4. Analysis of replacement cost profit (loss) before
interest and tax and reconciliation to profit (loss) before
taxation
Fourth Third Fourth
quarter quarter quarter Year Year
$ million 2018 2018 2017 2018 2017
======= ======= ======= ======= =========
Upstream 4,168 3,472 1,928 14,328 5,221
Downstream 2,138 2,249 1,773 6,940 7,221
Rosneft 400 808 321 2,221 836
Other businesses and corporate(a) (1,110) (815) (2,833) (3,521) (4,445)
5,596 5,714 1,189 19,968 8,833
Consolidation adjustment - UPII* 142 78 (149) 211 (212)
RC profit (loss) before interest and tax* 5,738 5,792 1,040 20,179 8,621
Inventory holding gains (losses)*
Upstream (12) 1 - (6) 8
Downstream (2,470) 343 719 (862) 758
Rosneft (net of tax) (92) 27 97 67 87
Profit (loss) before interest and tax 3,164 6,163 1,856 19,378 9,474
Finance costs 742 698 616 2,528 2,074
Net finance expense relating to pensions
and other post-retirement benefits 34 31 58 127 220
Profit (loss) before taxation 2,388 5,434 1,182 16,723 7,180
============================================ ====== ====== ====== ====== ======
RC profit (loss) before interest and tax*
US 1,487 1,215 (1,509) 3,041 (266)
Non-US 4,251 4,577 2,549 17,138 8,887
5,738 5,792 1,040 20,179 8,621
====== ====== ====== ====== ======
(a) Includes costs related to the Gulf of Mexico oil spill. See
Note 2 for further information.
Top of page 23
Note 5. Sales and other operating revenues
Fourth Third Fourth
quarter quarter quarter Year Year
$ million 2018 2018 2017 2018 2017
============================================ ======= ======= ======= ======= =========
By segment
Upstream 15,050 14,781 12,651 56,399 45,440
Downstream 67,733 72,376 62,697 270,689 219,853
Other businesses and corporate 536 423 480 1,678 1,469
83,319 87,580 75,828 328,766 266,762
====== ======= ======= ======= =======
Less: sales and other operating revenues
between segments
Upstream 8,669 7,368 6,929 28,565 24,179
Downstream (1,232) 539 913 574 1,800
Other businesses and corporate 205 205 170 871 575
7,642 8,112 8,012 30,010 26,554
====== ======= ======= ======= =======
Third party sales and other operating
revenues
Upstream 6,381 7,413 5,722 27,834 21,261
Downstream 68,965 71,837 61,784 270,115 218,053
Other businesses and corporate 331 218 310 807 894
Total sales and other operating revenues 75,677 79,468 67,816 298,756 240,208
============================================= ====== ======= ======= ======= =======
By geographical area
US 26,890 27,580 24,127 104,759 88,709
Non-US 53,540 58,869 50,778 219,681 176,113
============================================= ====== ======= ======= ======= =======
80,430 86,449 74,905 324,440 264,822
Less: sales and other operating revenues
between areas 4,753 6,981 7,089 25,684 24,614
75,677 79,468 67,816 298,756 240,208
====== ======= ======= ======= =======
Sales and other operating revenues include
the following in relation to revenues
from contracts with customers
Crude oil 15,448 17,744 13,838 65,276 49,670
Oil products 47,847 52,049 45,992 195,466 159,821
Natural gas, LNG and NGLs 5,862 5,764 4,777 21,745 16,196
Non-oil products and other revenues from
contracts with customers 3,618 3,574 3,773 13,768 12,538
Revenues from contracts with customers(a) 72,775 79,131 68,380 296,255 238,225
============================================= ====== ======= ======= ======= =======
(a) See Note 1 for further information.
Note 6. Depreciation, depletion and amortization
Fourth Third Fourth
quarter quarter quarter Year Year
$ million 2018 2018 2017 2018 2017
================================ ======= ======= ======= ====== ========
Upstream
US 1,137 987 1,107 4,211 4,631
Non-US 2,242 2,167 2,339 8,907 8,637
3,379 3,154 3,446 13,118 13,268
======= ======= ======= ====== ======
Downstream
US 240 220 218 900 875
Non-US 298 284 301 1,177 1,141
538 504 519 2,077 2,016
======= ======= ======= ====== ======
Other businesses and corporate
US 11 16 16 59 65
Non-US 59 54 64 203 235
================================= ======= ======= ======= ====== ======
70 70 80 262 300
Total group 3,987 3,728 4,045 15,457 15,584
================================= ======= ======= ======= ====== ======
Top of page 24
Note 7. Production and similar taxes
Fourth Third Fourth
quarter quarter quarter Year Year
$ million 2018 2018 2017 2018 2017
======= ======= ======= ===== =======
US 99 91 44 369 52
Non-US 87 360 467 1,167 1,723
186 451 511 1,536 1,775
======= ======= ======= ===== =====
Note 8. Earnings per share and shares in issue
Basic earnings per ordinary share (EpS) amounts are calculated
by dividing the profit (loss) for the period attributable to
ordinary shareholders by the weighted average number of ordinary
shares outstanding during the period. During the quarter the
company repurchased for cancellation 2 million ordinary shares for
a total cost of $16 million, as part of the share buyback programme
as announced on 31 October 2017. The number of shares in issue is
reduced when shares are repurchased.
The calculation of EpS is performed separately for each discrete
quarterly period, and for the year-to-date period. As a result, the
sum of the discrete quarterly EpS amounts in any particular
year-to-date period may not be equal to the EpS amount for the
year-to-date period.
For the diluted EpS calculation the weighted average number of
shares outstanding during the period is adjusted for the number of
shares that are potentially issuable in connection with employee
share-based payment plans using the treasury stock method.
Fourth Third Fourth
quarter quarter quarter Year Year
$ million 2018 2018 2017 2018 2017
========== ========== ========== ========== ============
Results for the period
Profit (loss) for the period attributable
to BP shareholders 766 3,349 27 9,383 3,389
Less: preference dividend - - - 1 1
Profit (loss) attributable to
BP ordinary shareholders 766 3,349 27 9,382 3,388
============================================ ========== ========== ========== ========== ==========
Number of shares (thousand)(a)
Basic weighted average number
of shares outstanding 20,007,781 20,006,872 19,804,932 19,970,215 19,692,613
ADS equivalent 3,334,630 3,334,478 3,300,822 3,328,369 3,282,102
============================================ ========== ========== ========== ========== ==========
Weighted average number of shares
outstanding used to calculate
diluted earnings per share 20,133,087 20,118,456 19,929,655 20,102,493 19,816,442
ADS equivalent 3,355,514 3,353,076 3,321,609 3,350,415 3,302,740
============================================ ========== ========== ========== ========== ==========
Shares in issue at period-end 20,101,658 20,050,414 19,817,325 20,101,658 19,817,325
ADS equivalent 3,350,276 3,341,735 3,302,887 3,350,276 3,302,887
============================================ ========== ========== ========== ========== ==========
(a) Excludes treasury shares and includes certain shares that
will be issued in the future under employee share-based payment
plans.
Top of page 25
Note 9. Dividends
Dividends payable
BP today announced an interim dividend of 10.25 cents per
ordinary share which is expected to be paid on 29 March 2019 to
ordinary shareholders and American Depositary Share (ADS) holders
on the register on 15 February 2019. The corresponding amount in
sterling is due to be announced on 18 March 2019, calculated based
on the average of the market exchange rates for the four dealing
days commencing on 12 March 2019. Holders of ADSs are expected to
receive $0.615 per ADS (less applicable fees). A scrip dividend
alternative is available, allowing shareholders to elect to receive
their dividend in the form of new ordinary shares and ADS holders
in the form of new ADSs. Details of the fourth quarter dividend and
timetable are available at bp.com/dividends and details of the
scrip dividend programme are available at bp.com/scrip.
Fourth Third Fourth
quarter quarter quarter Year Year
2018 2018 2017 2018 2017
======= ======= ======= ====== ========
Dividends paid per ordinary share
cents 10.250 10.250 10.000 40.500 40.000
pence 8.025 7.930 7.443 30.568 30.979
Dividends paid per ADS (cents) 61.50 61.50 60.00 243.00 240.00
=======
Scrip dividends
Number of shares issued (millions) 47.5 89.9 53.3 195.3 289.8
Value of shares issued ($ million) 322 638 354 1,381 1,714
===================================== ======= ======= ======= ====== ======
Note 10. Net Debt*
Net debt ratio* Fourth Third Fourth
quarter quarter quarter Year Year
$ million 2018 2018 2017 2018 2017
=========== =========== =========== =========== ===========
Gross debt 65,799 64,135 63,230 65,799 63,230
Fair value (asset) liability of hedges
related to finance debt(a) 813 1,234 175 813 175
66,612 65,369 63,405 66,612 63,405
Less: cash and cash equivalents 22,468 26,192 25,586 22,468 25,586
Net debt 44,144 39,177 37,819 44,144 37,819
========================================= ======= ======= ======= ======= =======
Equity 101,548 103,420 100,404 101,548 100,404
Net debt ratio 30.3% 27.5% 27.4% 30.3% 27.4%
========================================= ======= ======= ======= ======= =======
Top of page 26
Note 10. Net Debt* (continued)
Analysis of changes in net debt Fourth Third Fourth
quarter quarter quarter Year Year
$ million 2018 2018 2017 2018 2017
============================================= ======= ======= ======= ======= =========
Opening balance
Finance debt(a) 64,135 60,358 65,784 63,230 58,300
Fair value (asset) liability of hedges
related to finance debt(b) 1,234 1,104 (227) 175 697
Less: cash and cash equivalents(c) 26,192 22,185 25,780 25,575 23,484
==============================================
Opening net debt 39,177 39,277 39,777 37,830 35,513
============================================== ====== ====== ====== ====== ======
Closing balance
Finance debt(a) 65,799 64,135 63,230 65,799 63,230
Fair value (asset) liability of hedges
related to finance debt(b) 813 1,234 175 813 175
Less: cash and cash equivalents 22,468 26,192 25,586 22,468 25,586
==============================================
Closing net debt 44,144 39,177 37,819 44,144 37,819
Decrease (increase) in net debt (4,967) 100 1,958 (6,314) (2,306)
============================================== ====== ====== ====== ====== ======
Movement in cash and cash equivalents
(excluding exchange adjustments) (3,619) 4,063 (223) (2,777) 1,558
Net cash outflow (inflow) from financing(d) (1,201) (3,852) 2,511 (3,145) (2,520)
Other movements (147) (24) (299) (321) (564)
============================================== ====== ====== ====== ====== ======
Movement in net debt before exchange
effects (4,967) 187 1,989 (6,243) (1,526)
Exchange adjustments - (87) (31) (71) (780)
Decrease (increase) in net debt (4,967) 100 1,958 (6,314) (2,306)
============================================== ====== ====== ====== ====== ======
(a) The fair value of finance debt at 31 December 2018 was
$66,346 million (1 January 2018 $65,165 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 $827 million (third quarter 2018 liability of $723 million and
fourth quarter 2017 liability of $634 million) are not included in
the calculation of net debt shown above as hedge accounting is not
applied for these instruments.
(c) See Note 1 for further information.
(d) An amendment was made to reduce the amount presented for net
financing cash outflow for the fourth quarter of 2017 by $242
million to eliminate cash flows related to non-hedge accounted
derivatives. Exchange adjustments have been amended by the same
amount with no overall change in net debt.
Note 11. Inventory valuation
A provision of $604 million was held against hydrocarbon
inventories at 31 December 2018 ($53 million at 30 September 2018
and $62 million at 31 December 2017) to write them down to their
net realizable value. The net movement charged to the income
statement during the fourth quarter 2018 was $562 million (third
quarter 2018 was a charge of $15 million and fourth quarter 2017
was a credit of $46 million).
Note 12. Statutory accounts
The financial information shown in this publication, which was
approved by the Board of Directors on 4 February 2019, is unaudited
and does not constitute statutory financial statements. Audited
financial information will be published in BP Annual Report and
Form 20-F 2018. BP Annual Report and Form 20-F 2017 has been filed
with the Registrar of Companies in England and Wales. The report of
the auditor on those accounts was unqualified and did not contain a
statement under section 498(2) or section 498(3) of the UK
Companies Act 2006.
Top of page 27
Additional information
Capital expenditure*
Fourth Third Fourth
quarter quarter quarter Year Year
$ million 2018 2018 2017 2018 2017
======= ======= ======= ====== ========
Capital expenditure on a cash basis
Organic capital expenditure* 4,402 3,730 4,622 15,140 16,501
Inorganic capital expenditure*(a) 8,494 674 199 9,948 1,339
12,896 4,404 4,821 25,088 17,840
======= ======= ======= ====== ======
Fourth Third Fourth
quarter quarter quarter Year Year
$ million 2018 2018 2017 2018 2017
======= ======= ======= ====== ========
Organic capital expenditure by segment
Upstream
US 1,048 854 726 3,482 2,999
Non-US 2,419 2,073 2,819 8,545 10,764
3,467 2,927 3,545 12,027 13,763
======= ======= ======= ====== ======
Downstream
US 237 237 349 877 809
Non-US 562 513 598 1,904 1,590
799 750 947 2,781 2,399
======= ======= ======= ====== ======
Other businesses and corporate
US 34 6 30 54 64
Non-US 102 47 100 278 275
136 53 130 332 339
4,402 3,730 4,622 15,140 16,501
======= ======= ======= ====== ======
Organic capital expenditure by geographical
area
US 1,319 1,097 1,105 4,413 3,872
Non-US 3,083 2,633 3,517 10,727 12,629
4,402 3,730 4,622 15,140 16,501
======= ======= ======= ====== ======
(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 31
December 2018, $6,788 million of the consideration had been paid,
including $525 million during the third quarter 2018 and $6,263
million during the fourth quarter 2018. These amounts are included,
net of cash acquired of $104 million in the fourth quarter, in
inorganic capital expenditure. See Note 3 for more information.
Fourth quarter and full year 2018 include $1,739 million relating
to the purchase of an additional 16.5% interest in the Clair field
west of Shetland in the North Sea, as part of the agreements with
ConocoPhillips in which ConocoPhillips simultaneously purchased
BP's entire 39.2% interest in the Greater Kuparuk Area on the North
Slope of Alaska. Full year 2018 also includes amounts relating to
the 25-year extension to our ACG production-sharing agreement* in
Azerbaijan. Full year 2017 includes amounts paid to acquire
interests in Mauritania and Senegal and amounts paid to purchase an
interest in the Zohr gas field in Egypt and in exploration blocks
in Senegal.
Top of page 28
Non-operating items*
Fourth Third Fourth
quarter quarter quarter Year Year
$ million 2018 2018 2017 2018 2017
======= ======= ======= ======= =========
Upstream
Impairment and gain (loss) on sale of
businesses and fixed assets(a) 34 (231) (181) (90) (563)
Environmental and other provisions (35) - 1 (35) 1
Restructuring, integration and rationalization
costs(b) (53) (17) (4) (131) (24)
Fair value gain (loss) on embedded derivatives - 1 2 17 33
Other(c) 190 5 38 56 (118)
136 (242) (144) (183) (671)
====== ====== ====== ====== ======
Downstream
Impairment and gain (loss) on sale of
businesses and fixed assets(d) (20) (19) 469 (54) 579
Environmental and other provisions (83) - (19) (83) (19)
Restructuring, integration and rationalization
costs(b) (279) (16) (69) (405) (171)
Fair value gain (loss) on embedded derivatives - - - - -
Other (19) (2) 1 (174) -
(401) (37) 382 (716) 389
====== ====== ====== ====== ======
Rosneft
Impairment and gain (loss) on sale of
businesses and fixed assets (31) (64) - (95) -
Environmental and other provisions - - - - -
Restructuring, integration and rationalization
costs - - - - -
Fair value gain (loss) on embedded derivatives - - - - -
Other - - - - -
(31) (64) - (95) -
====== ====== ====== ====== ======
Other businesses and corporate
Impairment and gain (loss) on sale of
businesses and fixed assets (6) (255) (16) (260) (22)
Environmental and other provisions(e) (575) (45) (153) (640) (156)
Restructuring, integration and rationalization
costs(b) (112) (33) (35) (190) (72)
Fair value gain (loss) on embedded derivatives - - - - -
Gulf of Mexico oil spill - business economic
loss claims(f) (26) (69) (2,110) (344) (2,370)
Gulf of Mexico oil spill - other(f) (41) (59) (111) (370) (317)
Other (6) (9) (14) (159) 90
(766) (470) (2,439) (1,963) (2,847)
====== ====== ====== ====== ======
Total before interest and taxation (1,062) (813) (2,201) (2,957) (3,129)
Finance costs(f) (122) (119) (124) (479) (493)
Total before taxation (1,184) (932) (2,325) (3,436) (3,622)
Taxation credit (charge) on non-operating
items(g) (2) 283 669 510 1,172
Taxation - impact of US tax reform(h) - - (859) 121 (859)
================================================= ====== ====== ====== ====== ======
Total after taxation for period (1,186) (649) (2,515) (2,805) (3,309)
================================================= ====== ====== ====== ====== ======
(a) Fourth quarter and full year 2018 include an impairment
reversal for assets in the North Sea and Angola. Fourth quarter and
full year 2017 include an impairment charge relating to BPX Energy
(previously known as the US Lower 48 business), partially offset by
gains associated with asset divestments. In addition, full year
2017 includes an impairment charge arising following the
announcement of the agreement to sell the Forties Pipeline System
business to INEOS.
(b) The group's restructuring programme, originally announced in
2014, has now been completed.
(c) Fourth quarter and full year 2017 include BP's share of an
impairment reversal recognized by the Angola LNG equity-accounted
entity, partially offset by other items. Full year 2018 and full
year 2017 also include the write-off of $124 million and $145
million respectively in relation to the value ascribed to certain
licences in the deepwater Gulf of Mexico as part of the accounting
for the acquisition of upstream assets from Devon Energy in
2011.
(d) Fourth quarter and full year 2017 gain primarily reflects
the disposal of our shareholding in the SECCO joint venture.
(e) Fourth quarter and full year 2018 primarily reflects charges
due to the annual update of environmental provisions, including
asbestos-related provisions for past operations, together with
updates of non-Gulf of Mexico oil spill related legal
provisions.
(f) See Note 2 for further details regarding costs relating to the Gulf of Mexico oil spill.
(g) Fourth quarter and full year 2017 include the tax effect of
the increase in the provision in the fourth quarter for business
economic loss and other claims associated with the Deepwater
Horizon Court Supervised Settlement Program at the tax rate
applicable from 1 January 2018.
(h) Fourth quarter and full year 2017 include the impact of US
tax reform, which reduced the US federal corporate income tax rate
from 35% to 21% effective from 1 January 2018. Full year 2018
reflects a further impact following a clarification of the tax
reform. The impact of the US tax reform has been treated as a
non-operating item because it is not considered to be part of
underlying business operations, has a material impact upon the
reported result and is substantially impacted by Gulf of Mexico oil
spill charges, which are also treated as non-operating items.
Separate disclosure is considered meaningful and relevant to
investors.
Top of page 29
Non-GAAP information on fair value accounting effects
Fourth Third Fourth
quarter quarter quarter Year Year
$ million 2018 2018 2017 2018 2017
======= ======= ======= ==== =======
Favourable (adverse) impact relative to
management's measure of performance
Upstream 146 (285) (151) (39) 27
Downstream 370 175 (83) 95 (135)
516 (110) (234) 56 (108)
Taxation credit (charge) (90) 12 59 12 12
426 (98) (175) 68 (96)
====== ====== ====== === ====
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, from the first quarter 2018 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. Comparative information has not been restated on the
basis that the effect was not material.
Top of page 30
Non-GAAP information on fair value accounting effects
(continued)
The impacts of fair value accounting effects, relative to
management's internal measure of performance, are shown in the
table above. A reconciliation to GAAP information is set out
below.
Fourth Third Fourth
quarter quarter quarter Year Year
$ million 2018 2018 2017 2018 2017
======= ======= ======= ======= ========
Upstream
Replacement cost profit (loss) before
interest and tax adjusted for fair value
accounting effects 4,022 3,757 2,079 14,367 5,194
Impact of fair value accounting effects 146 (285) (151) (39) 27
====== =====
Replacement cost profit (loss) before
interest and tax 4,168 3,472 1,928 14,328 5,221
============================================== ======= ====== ====== ====== =====
Downstream
Replacement cost profit (loss) before
interest and tax adjusted for fair value
accounting effects 1,768 2,074 1,856 6,845 7,356
Impact of fair value accounting effects 370 175 (83) 95 (135)
Replacement cost profit (loss) before
interest and tax 2,138 2,249 1,773 6,940 7,221
============================================== ======= ====== ====== ====== =====
Total group
Profit (loss) before interest and tax
adjusted for fair value accounting effects 2,648 6,273 2,090 19,322 9,582
Impact of fair value accounting effects 516 (110) (234) 56 (108)
Profit (loss) before interest and tax 3,164 6,163 1,856 19,378 9,474
============================================== ======= ====== ====== ====== =====
Readily marketable inventory* (RMI)
31 December 31 December
$ million 2018 2017
=========== =============
RMI at fair value* 4,202 5,661
Paid-up RMI* 1,641 2,688
===================== =========== ===========
Readily marketable inventory (RMI) is oil and oil products
inventory held and price risk-managed by BP's integrated supply and
trading function (IST) which could be sold to generate funds if
required. Paid-up RMI is RMI that BP has paid for.
We believe that disclosing the amounts of RMI and paid-up RMI is
useful to investors as it enables them to better understand and
evaluate the group's inventories and liquidity position by enabling
them to see the level of discretionary inventory held by IST and to
see builds or releases of liquid trading inventory.
See the Glossary on page 32 for a more detailed definition of
RMI. RMI, RMI at fair value, paid-up RMI and unpaid RMI are
non-GAAP measures. A reconciliation of total inventory as reported
on the group balance sheet to paid-up RMI is provided below.
31 December 31 December
$ million 2018 2017
=========== =============
Reconciliation of total inventory to paid-up RMI
Inventories as reported on the group balance sheet
under IFRS 17,988 19,011
Less: (a) inventories that are not oil and oil
products and (b) oil and oil product inventories
that are not risk-managed by IST (14,066) (13,929)
3,922 5,082
Plus: difference between RMI at fair value and
RMI on an IFRS basis 280 579
RMI at fair value 4,202 5,661
Less: unpaid RMI* at fair value (2,561) (2,973)
Paid-up RMI 1,641 2,688
===================================================== ========== ==========
Top of page 31
Working capital* reconciliation
Fourth Third Fourth
quarter quarter quarter Year Year
$ million 2018 2018 2017 2018 2017
======= ======= ======= ======= =========
Movements in inventories and other current
and non-current assets and liabilities
as per condensed group cash flow statement 778 (1,573) (60) (4,763) (3,352)
Adjustments to exclude movements in inventories
and other current and non-current assets
and liabilities for the Gulf of Mexico
oil spill (Note 2) 238 538 413 3,057 5,191
Adjusted for Inventory holding gains (losses)*
(Note 4)
Upstream (12) 1 - (6) 8
Downstream (2,470) 343 719 (862) 758
Working capital release (build) (1,466) (691) 1,072 (2,574) 2,605
================================================== ====== ====== ====== ====== ======
Realizations* and marker prices
Fourth Third Fourth
quarter quarter quarter Year Year
2018 2018 2017 2018 2017
============================================= ======= ======= ======= ===== =======
Average realizations(a)
Liquids* ($/bbl)
US 61.61 65.22 51.50 61.72 46.55
Europe 65.07 73.90 57.92 69.20 52.13
Rest of World 61.42 71.95 59.09 66.68 51.83
BP Average 61.80 69.68 56.16 64.98 49.92
============================================== ======= ======= ======= ===== =====
Natural gas ($/mcf)
US 3.10 2.22 2.28 2.43 2.36
Europe 8.80 7.79 5.56 7.71 5.09
Rest of World 4.77 4.36 3.51 4.37 3.45
BP Average 4.33 3.86 3.23 3.92 3.19
============================================== ======= ======= ======= ===== =====
Total hydrocarbons* ($/boe)
US 42.50 43.20 35.75 41.59 33.47
Europe 61.98 68.54 52.17 64.11 46.09
Rest of World 41.64 45.51 37.27 42.65 35.44
BP Average 42.98 46.14 37.48 43.47 35.38
============================================== ======= ======= ======= ===== =====
Average oil marker prices ($/bbl)
Brent 68.81 75.16 61.26 71.31 54.19
West Texas Intermediate 59.98 69.63 55.23 65.20 50.79
Western Canadian Select 25.31 40.33 38.74 38.27 38.55
Alaska North Slope 69.53 75.26 61.31 71.54 54.43
Mars 64.45 70.79 57.70 66.86 50.65
Urals (NWE - cif) 68.02 73.98 60.17 69.89 52.84
============================================== ======= ======= ======= ===== =====
Average natural gas marker prices
Henry Hub gas price(b) ($/mmBtu) 3.65 2.91 2.93 3.09 3.11
UK Gas - National Balancing Point (p/therm) 65.13 64.46 51.94 60.38 44.95
============================================== ======= ======= ======= ===== =====
(a) Based on sales of consolidated subsidiaries only - this
excludes equity-accounted entities.
(b) Henry Hub First of Month Index.
Exchange rates
Fourth Third Fourth
quarter quarter quarter Year Year
2018 2018 2017 2018 2017
======= ======= ======= ===== =======
$/GBP average rate for the period 1.29 1.30 1.33 1.33 1.29
$/GBP period-end rate 1.27 1.31 1.34 1.27 1.34
$/EUR average rate for the period 1.14 1.16 1.18 1.18 1.13
$/EUR period-end rate 1.14 1.17 1.19 1.14 1.19
Rouble/$ average rate for the period 66.48 65.54 58.46 62.73 58.36
Rouble/$ period-end rate 69.57 65.76 57.60 69.57 57.60
======================================= ======= ======= ======= ===== =====
Top of page 32
Legal proceedings
The following discussion sets out the material developments in
the group's material legal proceedings during the recent period.
For a full discussion of the group's material legal proceedings,
see pages 270-273 of BP Annual Report and Form 20-F 2017, and page
34 of BP p.l.c. Group results second quarter and half-year
2018.
Other legal proceedings
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. BP filed a Petition for Review to the Oregon
Supreme Court. On 8 November 2018 the Oregon Supreme Court denied
BP's petition for review. BP intends to appeal to the United States
Supreme Court.
Glossary
Non-GAAP measures are provided for investors because they are
closely tracked by management to evaluate BP's operating
performance and to make financial, strategic and operating
decisions. Non-GAAP measures are sometimes referred to as
alternative performance measures.
Capital expenditure is total cash capital expenditure as stated
in the condensed group cash flow statement.
Consolidation adjustment - UPII is unrealized profit in
inventory arising on inter-segment transactions.
Divestment proceeds are disposal proceeds as per the condensed
group cash flow statement.
Effective tax rate (ETR) on replacement cost (RC) profit or loss
is a non-GAAP measure. The ETR on RC profit or loss is calculated
by dividing taxation on a RC basis by RC profit or loss before tax.
Information on RC profit or loss is provided below. BP believes it
is helpful to disclose the ETR on RC profit or loss because this
measure excludes the impact of price changes on the replacement of
inventories and allows for more meaningful comparisons between
reporting periods. The nearest equivalent measure on an IFRS basis
is the ETR on profit or loss for the period.
Fair value accounting effects are non-GAAP adjustments to our
IFRS profit (loss). They reflect the difference between the way BP
manages the economic exposure and internally measures performance
of certain activities and the way those activities are measured
under IFRS. Further information on fair value accounting effects is
provided on page 29.
Free cash flow is operating cash flow less net cash used in
investing activities, as presented in the condensed group cash flow
statement.
Gearing - See Net debt and net debt ratio definition.
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 27.
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.
Top of page 33
Glossary (continued)
Net debt and net debt ratio are non-GAAP measures. Net debt is
calculated as gross 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. The net debt ratio is
defined as the ratio of net debt to the total of net debt plus
shareholders' equity. All components of equity are included in the
denominator of the calculation. BP believes these measures provide
useful information to investors. Net debt enables investors to see
the economic effect of gross debt, related hedges and cash and cash
equivalents in total. The net debt ratio enables investors to see
how significant net debt is relative to equity from shareholders.
The derivatives are reported on the balance sheet within the
headings 'Derivative financial instruments'. The nearest equivalent
GAAP measures on an IFRS basis are gross debt and gross debt ratio.
A reconciliation of gross debt to net debt is provided on page
25.
We are unable to present reconciliations of forward-looking
information for net debt ratio to gross 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.
Net wind generation capacity is the sum of the rated capacities
of the assets/turbines that have entered into commercial operation,
including BP's share of equity-accounted entities.
Non-operating items are charges and credits included in the
financial statements that BP discloses separately because it
considers such disclosures to be meaningful and relevant to
investors. They are items that management considers not to be part
of underlying business operations and are disclosed in order to
enable investors better to understand and evaluate the group's
reported financial performance. Non-operating items within
equity-accounted earnings are reported net of incremental income
tax reported by the equity-accounted entity. An analysis of
non-operating items by region is shown on pages 7, 9 and 11, and by
segment and type is shown on page 28.
Operating cash flow is net cash provided by (used in) operating
activities as stated in the condensed group cash flow statement.
When used in the context of a segment rather than the group, the
terms refer to the segment's share thereof.
Operating cash flow excluding working capital change is a
non-GAAP measure. It is operating cash flow excluding Gulf of
Mexico oil spill payments less change in working capital adjusted
for inventory holding gains/losses (see below). BP believes
operating cash flow excluding working capital change is a useful
measure as it allows for more meaningful comparisons between
reporting periods. The nearest equivalent measure on an IFRS basis
is net cash provided by operating activities.
Operating cash flow excluding Gulf of Mexico oil spill payments
is a non-GAAP measure. It is calculated by excluding post-tax
operating cash flows relating to the Gulf of Mexico oil spill as
reported in Note 2 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 27.
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 30.
Realizations are the result of dividing revenue generated from
hydrocarbon sales, excluding revenue generated from purchases made
for resale and royalty volumes, by revenue generating hydrocarbon
production volumes. Revenue generating hydrocarbon production
reflects the BP share of production as adjusted for any production
which does not generate revenue. Adjustments may include losses due
to shrinkage, amounts consumed during processing, and contractual
or regulatory host committed volumes such as royalties.
Refining availability represents Solomon Associates' operational
availability, 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.
Top of page 34
Glossary (continued)
The Refining marker margin (RMM) is the average of regional
indicator margins weighted for BP's crude refining capacity in each
region. Each regional marker margin is based on product yields and
a marker crude oil deemed appropriate for the region. The regional
indicator margins may not be representative of the margins achieved
by BP in any period because of BP's particular refinery
configurations and crude and product slate.
Replacement cost (RC) profit or loss reflects the replacement
cost of inventories sold in the period and is arrived at by
excluding inventory holding gains and losses from profit or loss.
RC profit or loss for the group is not a recognized GAAP measure.
BP believes this measure is useful to illustrate to investors the
fact that crude oil and product prices can vary significantly from
period to period and that the impact on our reported result under
IFRS can be significant. Inventory holding gains and losses vary
from period to period due to changes in prices as well as changes
in underlying inventory levels. In order for investors to
understand the operating performance of the group excluding the
impact of price changes on the replacement of inventories, and to
make comparisons of operating performance between reporting
periods, BP's management believes it is helpful to disclose this
measure. The nearest equivalent measure on an IFRS basis is profit
or loss attributable to BP shareholders. A reconciliation to GAAP
information is provided on page 1. RC profit or loss before
interest and tax is the measure of profit or loss that is required
to be disclosed for each operating segment under IFRS.
RC profit or loss per share is a non-GAAP measure. Earnings per
share is defined in Note 8. RC profit or loss per share is
calculated using the same denominator. The numerator used is RC
profit or loss attributable to BP shareholders rather than profit
or loss attributable to BP shareholders. BP believes it is helpful
to disclose the RC profit or loss per share because this measure
excludes the impact of price changes on the replacement of
inventories and allows for more meaningful comparisons between
reporting periods. The nearest equivalent measure on an IFRS basis
is basic earnings per share based on profit or loss for the period
attributable to BP shareholders.
Reported recordable injury frequency measures the number of
reported work-related employee and contractor incidents that result
in a fatality or injury per 200,000 hours worked. This represents
reported incidents occurring within BP's operational HSSE reporting
boundary. That boundary includes BP's own operated facilities and
certain other locations or situations.
Reserves replacement ratio is the extent to which the year's
production has been replaced by proved reserves added to our
reserve base. The ratio is expressed in oil-equivalent terms and
includes changes resulting from discoveries, improved recovery and
extensions and revisions to previous estimates, but excludes
changes resulting from acquisitions and disposals. The reserves
replacement ratio will be reported in BP Annual Report and Form
20-F 2018.
Return on average capital employed (ROACE) is a non-GAAP measure
and is underlying replacement cost profit, after adding back
non-controlling interest and interest expense net of tax (for 2017
interest expense was net of notional tax at an assumed 35%),
divided by average capital employed, excluding cash and cash
equivalents and goodwill. Interest expense is finance costs
excluding the unwinding of the discount on provisions and other
payables, and for full year 2018 interest expense was $1,779
million (2017 $1,421 million) before tax. BP believes it is helpful
to disclose the ROACE because this measure gives an indication of
the company's capital efficiency. The nearest GAAP measures of the
numerator and denominator are profit or loss for the period
attributable to BP shareholders and average capital employed
respectively.
Solomon availability - See Refining availability definition.
Tier 1 process safety events are losses of primary containment
from a process of greatest consequence - causing harm to a member
of the workforce, costly damage to equipment or exceeding defined
quantities. 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.
Underlying effective tax rate (ETR) is a non-GAAP measure. The
underlying ETR is calculated by dividing taxation on an underlying
replacement cost (RC) basis by underlying RC profit or loss before
tax. Taxation on an underlying RC basis is taxation on a RC basis
for the period adjusted for taxation on non-operating items and
fair value accounting effects. Information on underlying RC profit
or loss is provided below. BP believes it is helpful to disclose
the underlying ETR because this measure may help investors to
understand and evaluate, in the same manner as management, the
underlying trends in BP's operational performance on a comparable
basis, period on period. The nearest equivalent measure on an IFRS
basis is the ETR on profit or loss for the period.
We are unable to present reconciliations of forward-looking
information for underlying ETR to ETR on profit or loss for the
period, because without unreasonable efforts, we are unable to
forecast accurately certain adjusting items required to present a
meaningful comparable GAAP forward-looking financial measure. These
items include the taxation on inventory holding gains and losses,
non-operating items and fair value accounting effects, that are
difficult to predict in advance in order to include in a GAAP
estimate.
Underlying production is production after adjusting for
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 28 and 29 for additional information on the non-operating
items and fair value accounting effects that are used to arrive at
underlying RC profit or loss in order to enable a full
understanding of the events and their financial impact. BP believes
that underlying RC profit or loss is a useful measure for investors
because it is a measure closely tracked by management to evaluate
BP's operating performance and to make financial, strategic and
operating decisions and because it may help investors to understand
and evaluate, in the same manner as management, the underlying
trends in BP's operational performance on a comparable basis,
period on period, by adjusting for the effects of these
non-operating items and fair value accounting effects. The nearest
equivalent measure on an IFRS basis for the group is profit or loss
attributable to BP shareholders. The nearest equivalent measure on
an IFRS basis for segments is RC profit or loss before interest and
taxation. A reconciliation to GAAP information is provided on page
1.
Top of page 35
Glossary (continued)
Underlying RC profit or loss per share is a non-GAAP measure.
Earnings per share is defined in Note 8. Underlying RC profit or
loss per share is calculated using the same denominator. The
numerator used is underlying RC profit or loss attributable to BP
shareholders rather than profit or loss attributable to BP
shareholders. BP believes it is helpful to disclose the underlying
RC profit or loss per share because this measure may help investors
to understand and evaluate, in the same manner as management, the
underlying trends in BP's operational performance on a comparable
basis, period on period. The nearest equivalent measure on an IFRS
basis is basic earnings per share based on profit or loss for the
period attributable to BP shareholders.
Upstream operating efficiency is calculated as production for
BP-operated sites, excluding US Lower 48 and adjusted for certain
items including entitlement impacts in our production-sharing
agreements divided by installed production capacity for BP-operated
sites, excluding US Lower 48. Installed production capacity is the
agreed rate achievable (measured at the export end of the system)
when the installed production system (reservoir, wells, plant and
export) is fully optimized and operated at full rate with no
planned or unplanned deferrals.
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.
Wellwork is activities undertaken on previously completed wells
with the primary objective to restore or increase production.
Working capital - Change in working capital is movements in
inventories and other current and non-current assets and
liabilities as reported in the condensed group cash flow statement.
Change in working capital adjusted for inventory holding
gains/losses is a non-GAAP measure. It is calculated by adjusting
for inventory holding gains/losses reported in the period and this
therefore represents what would have been reported as movements in
inventories and other current and non-current assets and
liabilities, if the starting point in determining net cash provided
by operating activities had been replacement cost profit rather
than profit for the period. The nearest equivalent measure on an
IFRS basis for this is movements in inventories and other current
and non-current assets and liabilities. In the context of
describing operating cash flow excluding Gulf of Mexico oil spill
payments, change in working capital also excludes movements in
inventories and other current and non-current assets and
liabilities relating to the Gulf of Mexico oil spill. See page 31
for further details.
BP utilizes various arrangements in order to manage its working
capital including discounting of receivables and, in the supply and
trading business, the active management of supplier payment terms,
inventory and collateral.
Top of page 36
Cautionary statement
In order to utilize the 'safe harbor' provisions of the United
States Private Securities Litigation Reform Act of 1995 (the
'PSLRA') and the general doctrine of cautionary statements, BP is
providing the following cautionary statement: The discussion in
this results announcement contains certain forecasts, projections
and forward-looking statements - that is, statements related to
future, not past events and circumstances - with respect to the
financial condition, results of operations and businesses of BP and
certain of the plans and objectives of BP with respect to these
items. These statements may generally, but not always, be
identified by the use of words such as 'will', 'expects', 'is
expected to', 'aims', 'should', 'may', 'objective', 'is likely to',
'intends', 'believes', 'anticipates', 'plans', 'we see' or similar
expressions. In particular, the following, among other statements,
are all forward looking in nature: expectations regarding the
expected quarterly dividend payment and timing of such payment;
expectations regarding BP's strategy and its impact on BP and its
shareholders; plans and expectations regarding share buybacks,
including to offset the impact of dilution from the scrip
programme; expectations regarding the underlying effective tax rate
in 2019; expectations for cash flow growth to underpin the balance
sheet; expectations regarding 2019 organic capital expenditure and
depreciation, depletion and amortization charges; plans and
expectations with respect to gearing; plans and expectations to
complete more than $10 billion divestments over the next two years;
expectations regarding Upstream full-year 2019 underlying and
reported production and first-quarter 2019 reported production;
expectations regarding Downstream first-quarter 2019 refining
margins, and narrower discounts for North American heavy crude oil;
expectations regarding the transfer of licences to LLC
Yermakneftegaz; plans and expectations regarding BP's wind energy
business; expectations regarding Other businesses and corporate
2019 average quarterly charges; plans and expectations regarding
Lightsource BP, including to enter Brazil and to provide power to
AB InBev's manufacturing plants in the UK; plans and expectations
regarding BP's acquisition of onshore-US oil and gas assets from
BHP, including expectations regarding the timing of purchase price
payments; plans and expectations regarding legal and trial
proceedings including to appeal the decision in the Scharfstein v.
BP West Coast Products, LLC lawsuit; and expectations with respect
to the timing and amount of future payments relating to the Gulf of
Mexico oil spill including payments for full-year 2019 and 2012 PSC
settlement payments. 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 projects onstream; the timing, quantum and nature of
certain acquisitions and divestments; future levels of industry
product supply, demand and pricing, including supply growth in
North America; OPEC quota restrictions; PSA effects; operational
and safety problems; potential lapses in product quality; economic
and financial market conditions generally or in various countries
and regions; political stability and economic growth in relevant
areas of the world; changes in laws and governmental regulations;
regulatory or legal actions including the types of enforcement
action pursued and the nature of remedies sought or imposed; the
actions of prosecutors, regulatory authorities and courts; delays
in the processes for resolving claims; amounts ultimately payable
and timing of payments relating to the Gulf of Mexico oil spill;
exchange rate fluctuations; development and use of new technology;
recruitment and retention of a skilled workforce; the success or
otherwise of partnering; the actions of competitors, trading
partners, contractors, subcontractors, creditors, rating agencies
and others; our access to future credit resources; business
disruption and crisis management; the impact on our reputation of
ethical misconduct and non-compliance with regulatory obligations;
trading losses; major uninsured losses; decisions by Rosneft's
management and board of directors; the actions of contractors;
natural disasters and adverse weather conditions; changes in public
expectations and other changes to business conditions; wars and
acts of terrorism; cyber-attacks or sabotage; and other factors
discussed elsewhere in this report, under "Principal risks and
uncertainties" in our Form 6-K for the period ended 30 June 2018
and "Risk factors" in BP Annual Report and Form 20-F 2017 as filed
with the US Securities and Exchange Commission.
Contacts
London Houston
Press Office David Nicholas Brett Clanton
+44 (0)20 7496 4708 +1 281 366 8346
Investor Relations Craig Marshall Brian Sullivan
bp.com/investors +44 (0)20 7496 4962 +1 281 892 3421
BP p.l.c.'s LEI Code 213800LH1BZH3D16G760
This information is provided by RNS, the news service of the
London Stock Exchange. RNS is approved by the Financial Conduct
Authority to act as a Primary Information Provider in the United
Kingdom. Terms and conditions relating to the use and distribution
of this information may apply. For further information, please
contact rns@lseg.com or visit www.rns.com.
END
FR CKQDQCBKDFBK
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February 05, 2019 02:00 ET (07:00 GMT)
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