Indicate by check mark whether the registrant files or will file annual reports under cover of Form 20-F or Form 40-F:
Form 20-F x Form 40-F ¨
Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(1): ¨
Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(7): ¨
THIS REPORT ON FORM 6-K SHALL BE DEEMED TO BE INCORPORATED BY REFERENCE IN THE PROSPECTUS INCLUDED IN THE REGISTRATION STATEMENT ON FORM F-3 (FILE NOS. 333-254751, 333-254751-01 AND 333-254751-02) OF BP p.l.c., BP CAPITAL MARKETS p.l.c. AND BP CAPITAL MARKETS AMERICA INC.; THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-273587) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-67206) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-79399) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-102583) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-103923) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-103924) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-119934) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-123482) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-123483) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-131583) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-131584) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-132619) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-146868) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-146870) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-146873) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-149778) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-173136) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-177423) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-179406) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-186462) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-186463) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-199015) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-200794) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-200795) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-200796) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-207188) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-207189) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-210316) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-210318) OF BP p.l.c., REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-253287) AND REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-254578) OF BP p.l.c., AND TO BE A PART THEREOF FROM THE DATE ON WHICH THIS REPORT IS FURNISHED, TO THE EXTENT NOT SUPERSEDED BY DOCUMENTS OR REPORTS SUBSEQUENTLY FILED OR FURNISHED.
(a)In this Form 6-K, references to the nine months 2023 and nine months 2022 refer to the nine-month periods ended 30 September 2023 and 30 September 2022 respectively. References to the third quarter 2023 and third quarter 2022 refer to the three-month periods ended 30 September 2023 and 30 September 2022 respectively.
(b)This discussion should be read in conjunction with the consolidated financial statements and related notes provided elsewhere in this Form 6-K and with the information, including the consolidated financial statements and related notes, in bp’s Annual Report on Form 20-F for the year ended 31 December 2022.
•Profit for the quarter attributable to bp shareholders was $4.9 billion, compared with $1.8 billion for the second quarter 2023 and a loss of $2.2 billion for the third quarter 2022. The result for the third quarter 2023 is adjusted for inventory holding gains* of $1.2 billion (net of tax) and a net favourable impact of adjusting items* of $0.4 billion (net of tax) to derive the underlying replacement cost profit. Adjusting items include impairments of $1.2 billion and favourable fair value accounting effects* of $1.5 billion.
•Underlying replacement cost profit for the quarter was $3.3 billion, compared with $2.6 billion for the previous quarter. Compared to the second quarter 2023, the result reflects: higher realized refining margins, lower level of refining turnaround activity, a very strong oil trading result, higher oil and gas production, partly offset by a weak gas marketing and trading result. The underlying replacement cost profit for the third quarter 2022 was $8.2 billion.
Operating cash flow* $8.7 billion; finance debt $48.8 billion and net debt* reduced to $22.3 billion
•Operating cash flow in the quarter was $8.7 billion, compared with $8.3 billion for the same period of 2022.
•Capital expenditure* in the third quarter was $3.6 billion, compared with $3.2 billion in the third quarter 2022. bp now expects capital expenditure, including inorganic capital expenditure* to be around $16 billion in 2023.
•During the third quarter, bp completed $2.0 billion of share buybacks. This included $225 million as part of the $675 million programme announced on 7 February 2023 to offset the expected full-year dilution from the vesting of awards under employee share schemes in 2023. bp completed the $675 million buyback programme on 1 September 2023.
•The $1.5 billion share buyback programme announced with the second quarter results was completed on 27 October 2023.
•Finance debt at the end of the quarter was $48.8 billion, compared with $46.6 billion at the end of the third quarter 2022. Net debt was reduced by $1.3 billion to $22.3 billion at the end of the third quarter. Net debt was $22.0 billion at the end of the third quarter 2022.
Further $1.5 billion share buyback within a disciplined financial frame
•A resilient dividend is bp’s first priority within its disciplined financial frame, underpinned by a cash balance point* of around $40 per barrel Brent, $11 per barrel RMM and $3 per mmBtu Henry Hub (all 2021 real).
•For the third quarter, bp has announced a dividend per ordinary share of 7.270 cents.
•bp remains committed to using 60% of 2023 surplus cash flow* for share buybacks, subject to maintaining a strong investment grade credit rating. See page 29 for the components of our sources of cash and uses of cash in the third quarter and nine months 2023.
•bp intends to execute a further $1.5 billion share buyback prior to reporting fourth quarter results.
•In setting the dividend per ordinary share and buyback each quarter, the board will continue to take into account factors including the cumulative level of and outlook for surplus cash flow, the cash balance point and the maintenance of a strong investment grade credit rating.
•bp’s guidance for distributions remains unchanged. Based on bp’s current forecasts, at around $60 per barrel Brent and subject to the board’s discretion each quarter, bp expects to be able to deliver share buybacks of around $4.0 billion per annum, at the lower end of its $14-18 billion capital expenditure range, and have capacity for an annual increase in the dividend per ordinary share of around 4%.
Continued progress in transformation to an integrated energy company
In resilient hydrocarbons, bp has announced the start-up of Tangguh Expansion – the third major project* in 2023 - adding around 3.8mtpa of producing capacity to the existing 7.6mtpa facility. It has safely produced the first commercial cargo. In August, bpx energy successfully brought online 'Bingo', its second central processing facility in the Permian Basin. In September, a regulatory approval was received for the Murlach oil and gas development in the North Sea, a two well redevelopment of the Marnock-Skua field back to the ETAP (Eastern Trough Area Project) hub. bp has accelerated its biogas strategy – part of its bioenergy transition growth* engine - bp’s Archaea Energy announced the start-up of its original Archaea Modular Design (AMD) renewable natural gas plant in Medora, Indiana. In convenience and mobility, bp continued to advance its growth strategy in EV charging and convenience: announcing an agreement in October with Tesla for the future purchase of $100 million of ultra-fast chargers in the US – this is part of the approved $500 million of investment in the US; and expanding its successful strategic convenience partnership with Auchan in Poland, with plans to add more than 100 EasyAuchan stores to its retail network by the end of 2025. In low carbon energy, bp has strengthened its renewables pipeline to 43.9GW net to bp from the rights awarded to develop two offshore wind projects, with total potential generating capacity of 4GW, in the German tender round.
The commentary above contains forward-looking statements and should be read in conjunction with the cautionary statement on page 40.
•Profit attributable to bp shareholders in the third quarter and nine months was $4.9 billion and $14.9 billion respectively, compared with a loss of $2.2 billion and $13.3 billion in the same periods of 2022.
•After adjusting profit attributable to bp shareholders for inventory holding gains* and net impact of adjusting items*, underlying replacement cost profit* for the third quarter and nine months was $3.3 billion and $10.8 billion respectively, compared with $8.2 billion and $22.8 billion for the same periods of 2022. This reduction in underlying replacement cost profit for the third quarter mainly reflects lower oil and gas realizations and a weak gas marketing and trading result. For the nine months, the reduction reflects lower oil and gas realizations; the impact of portfolio changes in oil production & operations; a lower refining and oil trading performance; and a weak gas marketing and trading result in the third quarter.
•Adjusting items in the third quarter and nine months had a net favourable pre-tax impact of $0.5 billion and $3.8 billion respectively, compared with an adverse pre-tax impact of $8.3 billion and $39.4 billion in the same periods of 2022.
•Adjusting items for the third quarter and nine months of 2023 include a favourable impact of pre-tax fair value accounting effects*, relative to management's internal measure of performance, of $1.5 billion and $6.8 billion respectively, compared with an adverse pre-tax impact of $10.1 billion and $16.7 billion in the same periods of 2022. This is primarily due to a decline in the forward price of LNG during the 2023 periods, but an increase in the 2022 comparative periods. Under IFRS, reported earnings include the mark-to-market value of the hedges used to risk-manage LNG contracts, but not of the LNG contracts themselves. The underlying result includes the mark-to-market value of the hedges but also recognizes changes in value of the LNG contracts being risk managed.
•Adjusting items for the nine months 2022 include a pre-tax charge of $24.0 billion relating to bp’s decision to exit its 19.75% shareholding in Rosneft. A further $1.5 billion pre-tax charge relating to bp's decision to exit its other businesses with Rosneft in Russia is also included.
•The effective tax rate (ETR) on the profit or loss before taxation for the third quarter and nine months was 31% and 32% respectively, compared with 200% and -736% for the same periods in 2022. The ETR on RC profit or loss* for the third quarter and nine months was 33% and 32% respectively, compared with 96% and -242% for the same periods in 2022. Excluding adjusting items, the underlying ETR* for the third quarter and nine months was 33% and 39% respectively, compared with 37% and 33% for the same periods a year ago. The lower underlying ETR for the third quarter reflects adjustments in respect of prior periods. The higher underlying ETR for the nine months reflects changes in the geographical mix of profits and the increased impact of the UK Energy Profits Levy. ETR on RC profit or loss and underlying ETR are non-IFRS measures.
•Operating cash flow* for the third quarter and nine months was $8.7 billion and $22.7 billion respectively, compared with $8.3 billion and $27.4 billion for the same periods in 2022 driven by the movements in underlying replacement cost profit and working capital in the periods.
•Capital expenditure* in the third quarter and nine months was $3.6 billion and $11.5 billion respectively, compared with $3.2 billion and $9.0 billion in the same periods of 2022. The nine months 2023 reflected the inorganic $1.1 billion spend on the acquisition of TravelCenters of America in the second quarter 2023.
•Total divestment and other proceeds for the third quarter and nine months were $0.7 billion and $1.5 billion respectively, compared with $0.6 billion and $2.5 billion for the same periods in 2022. Other proceeds for the third quarter and nine months of 2023 were $0.5 billion of proceeds from the sale of a 49% interest in a controlled affiliate holding certain midstream assets onshore US. Other proceeds for the nine months of 2022 were $0.6 billion of proceeds from the disposal of a loan note related to the Alaska divestment.
•Finance debt at the end of the third quarter was $48.8 billion, compared to $49.7 billion at the end of the second quarter 2023 and $46.6 billion at the end of the third quarter 2022. At the end of the third quarter, net debt* was $22.3 billion, compared with $23.7 billion at the end of the second quarter 2023 and $22.0 billion at the end of the third quarter 2022.
Analysis of RC profit (loss) before interest and tax and reconciliation to profit (loss) for the period
Third
Third
Nine
Nine
quarter
quarter
months
months
$ million
2023
2022
2023
2022
RC profit (loss) before interest and tax
gas & low carbon energy
2,275
(2,956)
11,911
(1,743)
oil production & operations
3,427
6,965
9,312
18,033
customers & products
1,549
2,586
4,784
8,098
other businesses & corporate
(500)
(1,093)
(887)
(26,840)
Of which:
other businesses & corporate excluding Rosneft
(500)
(1,093)
(887)
(2,807)
Rosneft
—
—
—
(24,033)
Consolidation adjustment – UPII*
(57)
(21)
(109)
(8)
6,694
5,481
25,011
(2,460)
Finance costs and net finance expense relating to pensions and other post-retirement benefits
(978)
(633)
(2,622)
(1,816)
Taxation on a RC basis
(1,859)
(4,646)
(7,156)
(10,327)
Non-controlling interests
(211)
(179)
(576)
(772)
RC profit (loss) attributable to bp shareholders*
3,646
23
14,657
(15,375)
Inventory holding gains (losses)*
1,593
(2,868)
261
2,779
Taxation (charge) credit on inventory holding gains and losses
(381)
682
(50)
(694)
Profit (loss) for the period attributable to bp shareholders
4,858
(2,163)
14,868
(13,290)
Analysis of underlying RC profit (loss) before interest and tax
Third
Third
Nine
Nine
quarter
quarter
months
months
$ million
2023
2022
2023
2022
Underlying RC profit (loss) before interest and tax
gas & low carbon energy
1,256
6,240
6,945
12,915
oil production & operations
3,136
5,211
9,232
15,796
customers & products
2,055
2,725
5,610
8,887
other businesses & corporate
(303)
(405)
(769)
(865)
Of which:
other businesses & corporate excluding Rosneft
(303)
(405)
(769)
(865)
Rosneft
—
—
—
—
Consolidation adjustment – UPII
(57)
(21)
(109)
(8)
6,087
13,750
20,909
36,725
Finance costs and net finance expense relating to pensions and other post-retirement benefits
(882)
(565)
(2,303)
(1,560)
Taxation on an underlying RC basis
(1,701)
(4,856)
(7,185)
(11,547)
Non-controlling interests
(211)
(179)
(576)
(772)
Underlying RC profit attributable to bp shareholders*
3,293
8,150
10,845
22,846
Reconciliations of underlying RC profit attributable to bp shareholders to the nearest equivalent IFRS measure are provided on page 3 for the group and on pages 8-16 for the segments.
Operating Metrics
Operating metrics
Nine months 2023
vs Nine months 2022
Tier 1 and tier 2 process safety events*
29
-7
Reported recordable injury frequency*
0.255
+31.8%
upstream* production(a) (mboe/d)
2,310
+2.7%
upstream unit production costs*(b) ($/boe)
5.88
-5.9%
bp-operated upstream plant reliability*
95.7%
-0.1
bp-operated refining availability*(a)
96.0%
1.6
(a)See Operational updates on pages 8, 11 and 13. Because of rounding, upstream production may not agree exactly with the sum of gas & low carbon energy and oil production & operations.
•bp expects oil prices to be supported by OPEC+ production restrictions and the continued demand rebound;
•European gas and Asian LNG prices will be driven by weather, demand recovery in Europe and China and ongoing geopolitical tension. In the US, weather is also a risk factor, but higher than normal storage levels and higher production should help to dampen volatility; and
•bp expects industry refining margins to be significantly lower than the third quarter.
4Q23 guidance
•Looking ahead, we expect fourth-quarter 2023 reported upstream* production to be broadly flat compared to third-quarter 2023.
•In its customers business, bp expects seasonally lower volumes with marketing margins to remain sensitive to movements in the cost of supply. In refining, we expect significantly lower realized refining margins and a higher level of turnaround activity in the fourth quarter.
2023 guidance
In addition to the guidance on page 4:
•bp expects both reported and underlying upstream production to be higher compared with 2022. Within this, bp expects underlying production from oil production & operations to be higher and production from gas & low carbon energy to be slightly lower. bp continues to expect four major project start-ups during 2023.
•bp expects the other businesses & corporate underlying annual charge to be at the lower end of the range $1.1-1.3 billion for 2023. The charge may vary from quarter to quarter.
•bp continues to expect the depreciation, depletion and amortization to be slightly above 2022.
•bp continues to expect the underlying ETR* for 2023 to be around 40% but it is sensitive to the impact that volatility in the current price environment may have on the geographical mix of the group’s profits and losses.
•Having realized $17.5 billion of divestment and other proceeds since the second quarter of 2020, bp continues to expect divestment and other proceeds of $2-3 billion in 2023 and continues to expect to reach $25 billion of divestment and other proceeds between the second half of 2020 and 2025.
•bp continues to expect Gulf of Mexico oil spill payments for the year to be around $1.3 billion pre-tax including the $1.2 billion pre-tax payment made during the second quarter.
•bp now expects capital expenditure* of around $16 billion in 2023 including inorganic capital expenditure*.
•bp is committed to maintaining a strong investment grade credit rating, targeting further progress within an 'A' grade credit rating. For 2023 bp continues to intend to allocate 40% of surplus cash flow* to further strengthen the balance sheet.
•For 2023 and subject to maintaining a strong investment grade credit rating, bp remains committed to using 60% of surplus cash flow for share buybacks.
•In setting the dividend per ordinary share and buyback each quarter, the board will continue to take into account factors including the cumulative level of and outlook for surplus cash flow, the cash balance point* and the maintenance of a strong investment grade credit rating.
•Based on bp’s current forecasts, at around $60 per barrel Brent and subject to the board’s discretion each quarter, bp continues to expect to be able to deliver share buybacks of around $4.0 billion per annum, at the lower end of its $14-18 billion capital expenditure range, and have capacity for an annual increase in the dividend per ordinary share of around 4%.
The commentary above contains forward-looking statements and should be read in conjunction with the cautionary statement on page 40.
•The replacement cost (RC) profit before interest and tax for the third quarter and nine months was $2,275 million and $11,911 million respectively, compared with a loss of $2,956 million and $1,743 million for the same periods in 2022. The third quarter and nine months are adjusted by a favourable impact of net adjusting items* of $1,019 million and $4,966 million respectively, compared with an adverse impact of net adjusting items of $9,196 million and $14,658 million for the same periods in 2022. Adjusting items include impacts of fair value accounting effects*, relative to management's internal measure of performance, which are a favourable impact of $1,816 million and $6,972 million for the third quarter and nine months in 2023 and an adverse impact of $9,224 million and $14,313 million for the same periods in 2022. Under IFRS, reported earnings include the mark-to-market value of the hedges used to risk-manage LNG contracts, but not of the LNG contracts themselves. The underlying result includes the mark-to-market value of the hedges but also recognizes changes in value of the LNG contracts being risk managed, which decreased as forward prices fell during the nine months. Adjusting items also include a net impairment charge of $224 million and $1,284 million respectively, compared with net charges of $6 million and $523 million for the same periods in 2022.
•After adjusting RC profit before interest and tax for adjusting items, the underlying RC profit before interest and tax* for the third quarter and nine months was $1,256 million and $6,945 million respectively, compared with $6,240 million and $12,915 million for the same periods in 2022.
•The underlying RC profit for the third quarter and nine months, compared with the same periods in 2022, both reflect lower realizations, a higher depreciation, depletion and amortization charge, and a weak gas marketing and trading result in the third quarter.
Operational update
•Reported production for the quarter was 946mboe/d, 3.6% lower than the same period in 2022. Underlying production* was 2.6% lower, mainly due to base decline and increased planned maintenance offset by major project* delivery.
•Reported production for the nine months was 940mboe/d, 1.8% lower than the same period in 2022. Underlying production was 2.2% lower, mainly due to base decline partly offset by major project delivery.
•Renewables pipeline* at the end of the quarter was 43.9GW (bp net), including 17.7GW bp net share of Lightsource bp's (LSbp's) pipeline. The renewables pipeline increased by 6.7GW during the nine months due to bp being awarded the rights to develop two North Sea offshore wind projects in Germany (4GW) and increases to LSbp's pipeline. In addition, there is over 13GW (bp net) of early stage opportunities in LSbp's hopper.
Strategic progress
gas
•On 19 October bp, on behalf of the Tangguh production-sharing contract* partners (bp 40.22% operator), announced that the first cargo of liquefied natural gas (LNG) produced by the new third liquefaction train at the Tangguh LNG facility, in Papua Barat, Indonesia, has safely been loaded and sailed. The start-up of Tangguh Train 3 will add 3.8 million tonnes per annum (mtpa) of gross LNG production capacity to the existing facility, bringing total plant capacity to 11.4mtpa gross.
•On 26 September bp announced that a bp and Shell joint venture (bp 50%, Shell 50%) had been awarded three deepwater exploration blocks off Trinidad's east coast.
•bp continues to work towards its aim of building an LNG portfolio of 30 million tonnes per year (mpta) by 2030:
◦On July 28, bp and OMV announced the signing of a long-term agreement to supply of up to 1mtpa of LNG for 10 years from 2026. This builds on bp in May 2023 agreeing 2bcm per year of regasification capacity for 20 years at the Gate terminal in Rotterdam.
◦On 5 September, bp announced its third long-term LNG offtake contract from Woodfibre’s British Columbia LNG facility with firm offtake totalling 1.95mtpa and any additional production on a flexible offtake basis.
low carbon energy
•Hydrogen and CCS
◦On 13 October the Midwest Alliance for Clean Hydrogen (MachH2), of which bp is a member, announced it has been selected by the U.S. Department of Energy’s Office of Clean Energy Demonstrations to develop a Regional Clean Hydrogen Hub. Under the proposals, it would include blue hydrogen* production at or near bp’s Whiting refinery and a potential hydrogen mobility corridor across Indiana and neighbouring states.
◦Hydrogen pipeline* at the end of the third quarter was 2.9mtpa, an increase of 1.1mtpa compared with the start of the year.
•Offshore wind
◦bp and its partner Equinor continue to work on options for their US offshore wind projects to mitigate the effect of inflationary pressures and permitting delays. A filing on 7 June with the New York Public Services Commission (PSC) requesting to renegotiate the power purchase agreements associated with three wind farms off the coast of New York (Empire Wind 1 and 2, Beacon Wind 1) was rejected on 12 October. Equinor and bp are assessing the impact of the decision on these projects and future development plans. We have recognized a pre-tax impairment charge of $540 million in the third quarter related to these assets. The pre-tax charge is recorded through equity-accounted earnings and is classified as an 'other' adjusting item.
•The replacement cost (RC) profit before interest and tax for the third quarter and nine months was $3,427 million and $9,312 million respectively, compared with $6,965 million and $18,033 million for the same periods in 2022. The third quarter and nine months are adjusted by a favourable impact of net adjusting items* of $291 million and $80 million respectively, compared with a favourable impact of net adjusting items of $1,754 million and $2,237 million for the same periods in 2022.
•After adjusting items, the underlying RC profit before interest and tax* for the third quarter and nine months was $3,136 million and $9,232 million respectively, compared with $5,211 million and $15,796 million for the same periods in 2022.
•The underlying RC profit for the third quarter and nine months compared to the same periods in 2022, reflects lower realizations, and the impact of portfolio changes, partly offset by higher volumes.
Operational update
•Reported production for the quarter was 1,382mboe/d, 5.0% higher than the third quarter of 2022. Underlying production* for the quarter was 5.1% higher compared with the third quarter of 2022 reflecting reduced seasonal maintenance, major projects* and bpx energy performance.
•Reported production for the nine months was 1,371mboe/d, 6.1% higher than the same period of 2022. Underlying production for the nine months was 5.6% higher compared with the same period of 2022 reflecting bpx energy performance, reduced seasonal maintenance and major projects.
Strategic Progress
•In August bpx energy successfully brought online 'Bingo', its second central processing facility in the Permian Basin. It is a low-emission, electrified facility that will enable further production growth for bpx energy in the basin (bp 100% operator).
•During the third quarter the Azeri Central East (ACE) platform topsides were safely installed in the field. This is the 9th and most automated platform installed in the giant Azeri Chirag Gunashli (ACG) field with approximately 90,000 barrels a day installed capacity (bp 30.37% operator).
•Regulatory approval was received on 8 September 2023 for the Murlach oil and gas development in the North Sea, a two well redevelopment of the Marnock-Skua field back to the ETAP (Eastern Trough Area Project) hub (bp 80% operator).
•In September, bp and its coventurers in the Clair joint venture, made the final investment decision to proceed with the construction and operation of the Shetland Crossover Pipeline, reinforcing the gas export network and supporting UK security of supply (bp 45% operator).
•Moving forward with concept selection for a bp-operated Tiber development project in the Gulf of Mexico.
Third
Third
Nine
Nine
quarter
quarter
months
months
$ million
2023
2022
2023
2022
Profit before interest and tax
3,426
6,966
9,312
18,028
Inventory holding (gains) losses*
1
(1)
—
5
RC profit before interest and tax
3,427
6,965
9,312
18,033
Net (favourable) adverse impact of adjusting items
(a)A reconciliation to RC profit before interest and tax is provided on page 31.
Third
Third
Nine
Nine
quarter
quarter
months
months
2023
2022
2023
2022
Production (net of royalties)(b)
Liquids* (mb/d)
1,011
959
1,005
947
Natural gas (mmcf/d)
2,155
2,075
2,118
2,001
Total hydrocarbons* (mboe/d)
1,382
1,317
1,371
1,292
Of which equity-accounted entities:
Liquids (mb/d)
266
211
271
152
Natural gas (mmcf/d)
453
446
439
440
Total hydrocarbons (mboe/d)
344
288
346
228
Average realizations*(c)
Liquids ($/bbl)
71.10
93.14
70.65
92.35
Natural gas(d) ($/mcf)
3.44
12.12
4.37
10.54
Total hydrocarbons(d) ($/boe)
56.76
86.83
57.86
84.57
(b)Includes bp’s share of production of equity-accounted entities in the oil production & operations segment. Nine months 2022 includes bp’s share of production of Russia joint ventures.
(c)Realizations are based on sales by consolidated subsidiaries only – this excludes equity-accounted entities.
(d)Realizations calculation methodology has been changed to reflect gas price fluctuations within the North Sea region. Third quarter 2022 and nine months 2022 were restated. There is no impact on financial results.
•The replacement cost (RC) profit before interest and tax for the third quarter and nine months was $1,549 million and $4,784 million respectively, compared with $2,586 million and $8,098 million for the same periods in 2022. The third quarter and nine months are adjusted by an adverse impact of net adjusting items* of $506 million and $826 million respectively, compared with an adverse impact of net adjusting items of $139 million and $789 million for the same periods in 2022. Adjusting items include impacts of fair value accounting effects*, relative to management's internal measure of performance, which are an adverse impact of $198 million for the quarter and $230 million for the nine months in 2023, compared with an adverse impact of $59 million and $498 million for the same periods in 2022.
•After adjusting items, the underlying RC profit before interest and tax* for the third quarter and nine months was $2,055 million and $5,610 million respectively, compared with $2,725 million and $8,887 million for the same periods in 2022.
•The customers & products result for the third quarter was lower than the same period in 2022, with lower results in both customers and refining. The result for the nine months was significantly lower than the same period in 2022, primarily reflecting a lower refining and oil trading performance.
•customers – the convenience and mobility results, excluding Castrol, for the third quarter and nine months were lower than the same periods in 2022. In the third quarter, the benefits of a strong convenience performance and higher volumes were more than offset by a weaker retail performance, compared with the same period last year, which had benefited from higher margins as a result of falling cost of supply. In addition, the result included higher costs, including increased expenditure in our transition growth* engines, inflationary impacts and increased depreciation.
Castrol result for the third quarter was higher than the same period in 2022, primarily due to higher margins. The result for the nine months was lower, with higher margins more than offset by higher costs and adverse foreign exchange impacts.
•products – the products results for the third quarter and nine months were lower compared with the same periods in 2022, primarily due to lower industry refining margins. In refining, the result for the third quarter reflected lower realized refining margins, including the impact of narrower North American heavy crude differentials, and lower commercial optimization opportunities compared to the strong performance in the same period last year. This was partially offset by lower maintenance activity. In addition, the result for the nine months was impacted by higher turnaround activity. The oil trading contribution for the third quarter was very strong compared to the average result in the same period last year. The result for the nine months however was lower, as the first half of 2022 benefited from an exceptionally strong oil trading performance.
Operational update
•bp-operated refining availability* for the third quarter and nine months was 96.3% and 96.0% respectively, higher compared with 94.3% and 94.4% for the same periods in 2022.
Strategic progress
•In support of bp’s convenience transition growth engine delivery, bp signed an agreement in August with Auchan to extend its successful strategic convenience partnership in Poland, with plans to add more than 100 EasyAuchan stores to its retail network by the end of 2025. In addition, in September, bp strengthened its BPme Rewards loyalty scheme with the launch of loyalty pricing, giving customers exclusive discounts on retail store products at around 300 bp company-owned retail sites across the UK.
•In August, bp announced it had approved $500 million of investment in the US to begin building its EV network over the next two to three years. As part of this investment, in October, bp announced it had entered into an agreement with Tesla for the future purchase of $100 million of ultra-fast chargers.
•In September, bp pulse, The EV Network and NEC Group, launched the UK’s largest public EV charging hub at the NEC campus in Birmingham, UK. The new Gigahub™ at the NEC boasts 30 ultra-fast 150KW and 150 fast 7kW charge points enabling 180 EVs to charge simultaneously.
•In September, Castrol opened the Castrol Americas Technology Center, in Wayne, New Jersey. This is a 12,000 square foot, state-of-the-art laboratory to develop and test fluids for electric vehicles, engine and driveline oils and industrial lubricants.
•In October, bp’s Archaea Energy announced the official start-up of its original Archaea Modular Design (AMD) renewable natural gas plant in Medora, Indiana, located next to a landfill site owned by Rumpke Waste and Recycling.
bp average refining marker margin (RMM)(d) ($/bbl)
31.8
35.5
28.2
33.4
(d)The RMM in the quarter is calculated based on bp’s current refinery portfolio. On a comparative basis, the third quarter and nine months 2022 RMM would be $35.4/bbl and $33.4/bbl respectively.
Other businesses & corporate comprises innovation & engineering, bp ventures, Launchpad, regions, corporates & solutions, our corporate activities & functions and any residual costs of the Gulf of Mexico oil spill. It also includes Rosneft results up to 27 February 2022.
Financial results
•The replacement cost (RC) loss before interest and tax for the third quarter and nine months was $500 million and $887 million respectively, compared with a loss of $1,093 million and $26,840 million for the same periods in 2022. The third quarter and nine months are adjusted by an adverse impact of net adjusting items* of $197 million and $118 million respectively, compared with an adverse impact of net adjusting items of $688 million and $25,975 million for the same periods in 2022. Adjusting items include impacts of fair value accounting effects* which are an adverse impact of $146 million for the quarter and a favourable impact of $51 million for the nine months in 2023, an adverse impact of $785 million and $1,896 million for the same periods in 2022. The adjusting items for the nine months in 2022 mainly relate to Rosneft.
•After adjusting RC loss for net adjusting items, the underlying RC loss before interest and tax* for the third quarter and nine months was $303 million and $769 million respectively, compared with a loss of $405 million and $865 million for the same periods in 2022.
Strategic progress
•In August bp ventures invested $5 million in Advanced Ionics, a company developing a new category of hydrogen electrolyzers, supporting the expansion of green hydrogen* production.
•In August bp ventures announced that it had invested $5 million in Dynamon, which provides advanced data analytics and AI tools helping the road transport industry maximize sustainability.
•In July bp ventures invested $30 million in Electric Hydrogen, a company which is developing high efficiency and lower cost electrolyzers with the aim of delivering its first 100MW product in 2024.
Third
Third
Nine
Nine
quarter
quarter
months
months
$ million
2023
2022
2023
2022
Profit (loss) before interest and tax
(500)
(1,093)
(887)
(26,840)
Inventory holding (gains) losses*
—
—
—
—
RC profit (loss) before interest and tax
(500)
(1,093)
(887)
(26,840)
Net (favourable) adverse impact of adjusting items(a)
197
688
118
25,975
Underlying RC profit (loss) before interest and tax
(303)
(405)
(769)
(865)
Taxation on an underlying RC basis
162
206
201
396
Underlying RC profit (loss) before interest
(141)
(199)
(568)
(469)
(a)Includes fair value accounting effects relating to the hybrid bonds that were issued on 17 June 2020. See page 35 for more information.
other businesses & corporate (excluding Rosneft)
Third
Third
Nine
Nine
quarter
quarter
months
months
$ million
2023
2022
2023
2022
Profit (loss) before interest and tax
(500)
(1,093)
(887)
(2,807)
Inventory holding (gains) losses*
—
—
—
—
RC profit (loss) before interest and tax
(500)
(1,093)
(887)
(2,807)
Net (favourable) adverse impact of adjusting items
197
688
118
1,942
Underlying RC profit (loss) before interest and tax
(303)
(405)
(769)
(865)
Taxation on an underlying RC basis
162
206
201
396
Underlying RC profit (loss) before interest
(141)
(199)
(568)
(469)
other businesses & corporate (Rosneft)
Third
Third
Nine
Nine
quarter
quarter
months
months
$ million
2023
2022
2023
2022
Profit (loss) before interest and tax
—
—
—
(24,033)
Inventory holding (gains) losses*
—
—
—
—
RC profit (loss) before interest and tax
—
—
—
(24,033)
Net (favourable) adverse impact of adjusting items
—
—
—
24,033
Underlying RC profit (loss) before interest and tax
Items that may be reclassified subsequently to profit or loss
Currency translation differences(a)
(590)
(1,725)
(126)
(5,928)
Exchange (gains) losses on translation of foreign operations reclassified to gain or loss on sale of businesses and fixed assets(b)
(2)
—
(2)
10,791
Cash flow hedges and costs of hedging
(56)
(142)
434
179
Share of items relating to equity-accounted entities, net of tax
25
(134)
(205)
10
Income tax relating to items that may be reclassified
(69)
(54)
(74)
(226)
(692)
(2,055)
27
4,826
Items that will not be reclassified to profit or loss
Remeasurements of the net pension and other post-retirement benefit liability or asset
(111)
112
(1,053)
1,848
Cash flow hedges that will subsequently be transferred to the balance sheet
(1)
(1)
(1)
(5)
Income tax relating to items that will not be reclassified
57
19
388
(470)
(55)
130
(666)
1,373
Other comprehensive income
(747)
(1,925)
(639)
6,199
Total comprehensive income
4,322
(3,909)
14,805
(6,319)
Attributable to
bp shareholders
4,140
(4,042)
14,241
(6,978)
Non-controlling interests
182
133
564
659
4,322
(3,909)
14,805
(6,319)
(a)Third quarter 2022 is principally affected by movements in the Pound Sterling against the US dollar. Nine months 2022 is principally affected by movements in the Russian rouble and Pound Sterling against the US dollar.
(b)Nine months 2022 predominantly relates to the loss of significant influence over Rosneft.
Transactions involving non-controlling interests, net of tax
363
—
(86)
277
At 30 September 2023
72,418
13,497
1,761
87,676
bp shareholders’
Non-controlling interests
Total
$ million
equity(a)
Hybrid bonds
Other interest
equity
At 1 January 2022
75,463
13,041
1,935
90,439
Total comprehensive income
(6,978)
383
276
(6,319)
Dividends
(3,267)
—
(194)
(3,461)
Issue of ordinary share capital(b)
820
—
—
820
Repurchase of ordinary share capital
(7,988)
—
—
(7,988)
Share-based payments, net of tax
631
—
—
631
Issue of perpetual hybrid bonds
(3)
325
—
322
Payments on perpetual hybrid bonds
15
(462)
—
(447)
Transactions involving non-controlling interests, net of tax
(512)
—
(152)
(664)
At 30 September 2022
58,181
13,287
1,865
73,333
(a)In 2022 $9.2 billion of the opening foreign currency translation reserve has been moved to the profit and loss account reserve as a result of bp's decision to exit its shareholding in Rosneft and its other businesses with Rosneft in Russia.
(b)Relates to ordinary shares issued as non-cash consideration for the acquisition of the public units of BP Midstream Partners LP.
The interim financial information included in this report has been prepared in accordance with IAS 34 'Interim Financial Reporting'.
The results for the interim periods are unaudited and, in the opinion of management, include all adjustments necessary for a fair presentation of the results for each period. All such adjustments are of a normal recurring nature. This report should be read in conjunction with the consolidated financial statements and related notes for the year ended 31 December 2022 included in BP Annual Report and Form 20-F 2022.
The directors consider it appropriate to adopt the going concern basis of accounting in preparing these interim financial statements. bp prepares its consolidated financial statements included within BP Annual Report and Form 20-F on the basis of International Financial Reporting Standards (IFRS) as issued by the International Accounting Standards Board (IASB), IFRS as adopted by the UK, and European Union (EU), and in accordance with the provisions of the UK Companies Act 2006 as applicable to companies reporting under international accounting standards. IFRS as adopted by the UK does not differ from IFRS as adopted by the EU except for the Pillar Two amendments noted below. IFRS as adopted by the UK and EU differ 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 2023 which are the same as those used in preparing BP Annual Report and Form 20-F 2022.
In May 2023 the IASB issued International Tax Reform – Pillar Two Model Rules - Amendments to IAS 12 Income Taxes to clarify the application of IAS 12 to tax legislation enacted or substantively enacted to implement Pillar Two of the Organisation for Economic Co-operation and Development’s Base Erosion and Profit Shifting project, which aims to address the tax challenges arising from the digitalisation of the economy. The amendments include a mandatory temporary exception from accounting for deferred tax on such tax law. The amendments were adopted by the UK in July and are yet to be adopted by the EU, however no impact is expected on the financial statements for 2023.
In July 2023 the UK government enacted legislation to implement the Pillar Two rules. The legislation is effective for bp from 1 January 2024 and includes an income inclusion rule and a domestic minimum tax, which together are designed to ensure a minimum effective tax rate of 15% in each country in which the group operates. Similar legislation is being enacted by other governments around the world. As a result of the amendments to IAS 12, no impact is expected on the financial statements in 2023, and work is ongoing to assess the potential impact in the 2024 financial statements.
There are no other new or amended standards or interpretations adopted from 1 January 2023 onwards, including IFRS 17 'Insurance Contracts,' that have a significant impact on the financial information.
Significant accounting judgements and estimates
bp's significant accounting judgements and estimates were disclosed in BP Annual Report and Form 20-F 2022. These have been subsequently considered at the end of each quarter to determine if any changes were required to those judgements and estimates. No significant changes were identified.
Investment in Rosneft
Since the first quarter 2022, bp accounts for its interest in Rosneft and its other businesses with Rosneft within Russia, as financial assets measured at fair value within ‘Other investments’. It is considered by management that any measure of fair value, other than nil, would be subject to such high measurement uncertainty that no estimate would provide useful information even if it were accompanied by a description of the estimate made in producing it and an explanation of the uncertainties that affect the estimate. Accordingly, it is not currently possible to estimate any carrying value other than zero when determining the measurement of the interest in Rosneft and the other businesses with Rosneft within Russia as at 30 September 2023.
There were no assets or liabilities classified as held for sale at 30 September 2023.
Note 3. Impairment and losses on sale of businesses and fixed assets
Net impairment charges and losses on sale of businesses and fixed assets for the third quarter and nine months were $542 million and $1,899 million respectively, compared with net charges of $417 million and $26,893 million for the same periods in 2022 and include net impairment charges for the third quarter and nine months of $612 million and $1,779 million respectively, compared with net impairment reversals of $11 million and charges of $14,777 million for the same periods in 2022.
Third quarter and nine months of 2023 impairments includes a net impairment charge of $224 million and $1,284 million respectively, compared with net charges of $6 million and $523 million for the same periods in 2022 in the gas & low carbon energy segment. A further $540 million pre-tax impairment charge relating to our offshore US wind assets has been recognised in the third quarter 2023 through equity-accounted earnings.
The impairment charge and the loss on sale of businesses and fixed assets for 2022 mainly relates to bp's investment in Rosneft, which has been reported in other businesses and corporate.
Note 4. Analysis of replacement cost profit (loss) before interest and tax and reconciliation to profit (loss) before taxation
Third
Third
Nine
Nine
quarter
quarter
months
months
$ million
2023
2022
2023
2022
gas & low carbon energy
2,275
(2,956)
11,911
(1,743)
oil production & operations
3,427
6,965
9,312
18,033
customers & products
1,549
2,586
4,784
8,098
other businesses & corporate
(500)
(1,093)
(887)
(26,840)
6,751
5,502
25,120
(2,452)
Consolidation adjustment – UPII*
(57)
(21)
(109)
(8)
6,694
5,481
25,011
(2,460)
Inventory holding gains (losses)*
gas & low carbon energy
—
(14)
1
2
oil production & operations
(1)
1
—
(5)
customers & products
1,594
(2,855)
260
2,782
Profit (loss) before interest and tax
8,287
2,613
25,272
319
Finance costs
1,039
649
2,802
1,869
Net finance expense/(income) relating to pensions and other post-retirement benefits
Total depreciation, depletion and amortization by segment
gas & low carbon energy
1,543
1,177
4,390
3,635
oil production & operations
1,432
1,381
4,129
4,181
customers & products
915
697
2,606
2,129
other businesses & corporate
255
212
743
659
4,145
3,467
11,868
10,604
Total depreciation, depletion and amortization by geographical area
US
1,479
1,180
4,071
3,422
Non-US
2,666
2,287
7,797
7,182
4,145
3,467
11,868
10,604
Note 7. Earnings per share and shares in issue
Basic earnings per ordinary share (EpS) amounts are calculated by dividing the profit (loss) for the period attributable to ordinary shareholders by the weighted average number of ordinary shares outstanding during the period. Against the authority granted at bp's 2022 annual general meeting, 331 million ordinary shares repurchased for cancellation were settled during the third quarter 2023 for a total cost of $2,047 million. A further 92 million ordinary shares were repurchased between the end of the reporting period and the date when the financial statements are authorised for issue for a total cost of $595 million. This amount has been accrued at 30 September 2023. The number of shares in issue is reduced when shares are repurchased, but is not reduced in respect of the period-end commitment to repurchase shares subsequent to the end of the period.
The calculation of EpS is performed separately for each discrete quarterly period, and for the year-to-date period. As a result, the sum of the discrete quarterly EpS amounts in any particular year-to-date period may not be equal to the EpS amount for the year-to-date period.
For the diluted EpS calculation the weighted average number of shares outstanding during the period is adjusted for the number of shares that are potentially issuable in connection with employee share-based payment plans using the treasury stock method.
Third
Third
Nine
Nine
quarter
quarter
months
months
$ million
2023
2022
2023
2022
Results for the period
Profit (loss) for the period attributable to bp shareholders
4,858
(2,163)
14,868
(13,290)
Less: preference dividend
—
—
1
1
Profit (loss) attributable to bp ordinary shareholders
4,858
(2,163)
14,867
(13,291)
Number of shares (thousand)(a)(b)
Basic weighted average number of shares outstanding
17,204,488
18,885,725
17,537,170
19,260,486
ADS equivalent(c)
2,867,414
3,147,620
2,922,861
3,210,081
Weighted average number of shares outstanding used to calculate diluted earnings per share
17,609,601
18,885,725
17,914,383
19,260,486
ADS equivalent(c)
2,934,933
3,147,620
2,985,730
3,210,081
Shares in issue at period-end
17,061,004
18,566,848
17,061,004
18,566,848
ADS equivalent(c)
2,843,500
3,094,474
2,843,500
3,094,474
(a)Excludes treasury shares and includes certain shares that will be issued in the future under employee share-based payment plans.
(b)If the inclusion of potentially issuable shares would decrease loss per share, the potentially issuable shares are excluded from the weighted average number of shares outstanding used to calculate diluted earnings per share. The numbers of potentially issuable shares that have been excluded from the calculation for the third quarter 2022 and nine months 2022 are 274,005 thousand (ADS equivalent 45,668 thousand) and 217,311 thousand (ADS equivalent 36,218 thousand).
(c)One ADS is equivalent to six ordinary shares.
Issued ordinary share capital as at 30 September 2023 comprised 17,119,221,814 ordinary shares (31 December 2022 18,157,211,814 ordinary shares). This includes shares held in trust to settle future employee share plan obligations and excludes 932,744,378 ordinary shares which have been bought back and are held in treasury by BP (31 December 2022 940,571,303 ordinary shares).
BP today announced an interim dividend of 7.270 cents per ordinary share which is expected to be paid on 19 December 2023 to ordinary shareholders and American Depositary Share (ADS) holders on the register on 10 November 2023. The ex-dividend date will be 9 November 2023. The corresponding amount in sterling is due to be announced on 6 December 2023, calculated based on the average of the market exchange rates over three dealing days between 30 November 2023 and 4 December 2023. Holders of ADSs are expected to receive $0.43620 per ADS (less applicable fees). The board has decided not to offer a scrip dividend alternative in respect of the third quarter 2023 dividend. Ordinary shareholders and ADS holders (subject to certain exceptions) will be able to participate in a dividend reinvestment programme. Details of the third quarter dividend and timetable are available at bp.com/dividends and further details of the dividend reinvestment programmes are available at bp.com/drip.
Third
Third
Nine
Nine
quarter
quarter
months
months
2023
2022
2023
2022
Dividends paid per ordinary share
cents
7.270
6.006
20.490
16.926
pence
5.732
5.168
16.592
13.683
Dividends paid per ADS (cents)
43.62
36.04
122.94
101.56
Note 9. Net debt
Net debt*
30 September
30 September
31 December
$ million
2023
2022
2022
Finance debt(a)
48,810
46,560
46,944
Fair value (asset) liability of hedges related to finance debt(b)
3,440
4,746
3,673
52,250
51,306
50,617
Less: cash and cash equivalents
29,926
29,304
29,195
Net debt(c)
22,324
22,002
21,422
Total equity
87,676
73,333
82,990
Gearing*
20.3%
23.1%
20.5%
(a)The fair value of finance debt at 30 September 2023 was $43,387 million (30 September 2022 $41,414 million, 31 December 2022 $42,590 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 $102 million at 30 September 2023 (third quarter 2022 liability of $116 million, fourth quarter 2022 liability of $91 million) are not included in the calculation of net debt shown above as hedge accounting is not applied for these instruments.
(c)Net debt does not include accrued interest, which is reported within other receivables and other payables on the balance sheet and for which the associated cash flows are presented as operating cash flows in the group cash flow statement.
In the third quarter the group bought back $nil equivalent of finance debt (third quarter 2022 $2.9 billion). As part of actively managing its debt portfolio, year to date the group has bought back a total of $1.7 billion equivalent of finance debt ($7.4 billion for the comparative period in 2022). Derivatives associated with non-US dollar debt bought back were also terminated. These transactions have no significant impact on net debt or gearing.
Note 10. Statutory accounts
The financial information shown in this publication, which was approved by the Board of Directors on 30 October 2023, is unaudited and does not constitute statutory financial statements. Audited financial information will be published in BP Annual Report and Form 20-F 2023.
Net impairment and losses on sale of businesses and fixed assets(a)
(224)
(6)
(1,284)
(523)
Environmental and other provisions
—
—
—
—
Restructuring, integration and rationalization costs
(1)
—
—
5
Fair value accounting effects(b)(c)
1,816
(9,224)
6,972
(14,313)
Other(d)
(572)
31
(738)
161
1,019
(9,196)
4,966
(14,658)
oil production & operations
Gains on sale of businesses and fixed assets(e)
246
1,851
352
3,378
Net impairment and losses on sale of businesses and fixed assets
(52)
(326)
(184)
(1,262)
Environmental and other provisions
99
244
6
98
Restructuring, integration and rationalization costs
—
3
(1)
(14)
Fair value accounting effects
—
—
—
—
Other
(2)
(18)
(93)
37
291
1,754
80
2,237
customers & products
Gains on sale of businesses and fixed assets
18
10
21
302
Net impairment and losses on sale of businesses and fixed assets
(242)
(85)
(361)
(532)
Environmental and other provisions
—
(1)
(11)
(36)
Restructuring, integration and rationalization costs
1
(4)
—
6
Fair value accounting effects(c)
(198)
(59)
(230)
(498)
Other
(85)
—
(245)
(31)
(506)
(139)
(826)
(789)
other businesses & corporate
Gains on sale of businesses and fixed assets
—
1
—
—
Net impairment and losses on sale of businesses and fixed assets
(23)
—
(60)
(16)
Environmental and other provisions
(8)
67
(39)
(25)
Restructuring, integration and rationalization costs
(3)
6
(13)
16
Fair value accounting effects(c)
(146)
(785)
51
(1,896)
Rosneft
—
—
—
(24,033)
Gulf of Mexico oil spill
(19)
(21)
(46)
(61)
Other
2
44
(11)
40
(197)
(688)
(118)
(25,975)
Total before interest and taxation
607
(8,269)
4,102
(39,185)
Finance costs(f)
(96)
(68)
(319)
(256)
Total before taxation
511
(8,337)
3,783
(39,441)
Taxation on adjusting items(g)
(158)
988
(203)
1,998
Taxation – tax rate change effect of UK energy profits levy(h)
—
(778)
232
(778)
Total after taxation for period(i)
353
(8,127)
3,812
(38,221)
(a)See Note 3 for further information.
(b)Under IFRS bp marks-to-market the value of the hedges used to risk-manage LNG contracts, but not the contracts themselves, resulting in a mismatch in accounting treatment. The fair value accounting effect includes the change in value of LNG contracts that are being risk managed, and the underlying result reflects how bp risk-manages its LNG contracts.
(c)For further information, including the nature of fair value accounting effects reported in each segment, see pages 5, 8 and 35.
(d)Third quarter and nine months 2023 include a $540 million impairment charge recognized through equity-accounted earnings relating to US offshore wind projects.
(e)Third quarter and nine months 2022 include a non-taxable gain of $1,951 million arising from the contribution of bp's Angolan business to Azule Energy. Nine months 2022 also includes gains of $904 million related to the deemed disposal of 12% of the group's interest in Aker BP, an associate of bp, following completion of Aker BP's acquisition of Lundin Energy, and $361 million in relation to the disposal of the group's interest in the Rumaila field in Iraq to Basra Energy Company, an associate of bp.
(f)Includes the unwinding of discounting effects relating to Gulf of Mexico oil spill payables, the income statement impact associated with
the buyback of finance debt (see Note 9 for further information) and temporary valuation differences associated with the group’s interest rate and foreign currency exchange risk management of finance debt.
(g)Includes certain foreign exchange effects on tax as adjusting items. These amounts represent the impact of: (i) foreign exchange on deferred tax balances arising from the conversion of local currency tax base amounts into functional currency, and (ii) taxable gains and losses from the retranslation of US dollar-denominated intra-group loans to local currency.
(h)Nine months 2023 includes a revision to the deferred tax impact of the introduction of the UK Energy Profits Levy (EPL) on temporary differences existing at 31 December 2022 that are expected to unwind over the period 1 January 2023 to 31 March 2028. The EPL increases the headline rate of tax to 75% and applies to taxable profits from bp’s North Sea business made from 1 January 2023 until 31 March 2028. Third quarter and nine months 2022 included the deferred tax impact of the introduction of the original UK EPL on existing
temporary differences unwinding over the period 1 October 2022 to 31 December 2025. The original levy increased the headline rate of tax from 40% to 65% on profits from bp’s North Sea business made from 26 May 2022 until 31 December 2025.
(i)Third quarter and nine months 2023 include a $43 million charge and a $121 million charge respectively for the EU Solidarity Contribution.
Net debt including leases
Net debt including leases*
30 September
30 September
$ million
2023
2022
Net debt
22,324
22,002
Lease liabilities
10,879
7,895
Net partner (receivable) payable for leases entered into on behalf of joint operations
(124)
22
Net debt including leases
33,079
29,919
Total equity
87,676
73,333
Gearing including leases*
27.4%
29.0%
Gulf of Mexico oil spill
30 September
31 December
$ million
2023
2022
Gulf of Mexico oil spill payables and provisions
(8,639)
(9,566)
Of which - current
(1,122)
(1,216)
Deferred tax asset
1,306
1,444
During the second quarter pre-tax payments of $1,204 million were made relating to the 2016 consent decree and settlement agreement with the United States and the five Gulf coast states. Payables and provisions presented in the table above reflect the latest estimate for the remaining costs associated with the Gulf of Mexico oil spill. Where amounts have been provided on an estimated basis, the amounts ultimately payable may differ from the amounts provided and the timing of payments is uncertain. Further information relating to the Gulf of Mexico oil spill, including information on the nature and expected timing of payments relating to provisions and other payables, is provided in BP Annual Report and Form 20-F 2022 - Financial statements - Notes 7, 22, 23, 29, and 33.
Surplus cash flow* components
Third
Third
Nine
Nine
quarter
quarter
months
months
$ million
2023
2022
2023
2022
Sources:
Net cash provided by operating activities
8,747
8,288
22,662
27,361
Cash provided from investing activities
150
621
1,065
1,996
Other(a)
503
(31)
402
454
9,400
8,878
24,129
29,811
Uses:
Lease liability payments
(663)
(478)
(1,838)
(1,448)
Payments on perpetual hybrid bonds
(258)
(180)
(744)
(489)
Dividends paid – BP shareholders
(1,249)
(1,140)
(3,585)
(3,270)
– non-controlling interests
(191)
(66)
(326)
(194)
Total capital expenditure*
(3,603)
(3,194)
(11,542)
(8,961)
Net repurchase of shares relating to employee share schemes
(225)
—
(675)
(500)
Payments relating to transactions involving non-controlling interests
—
(2)
(180)
(8)
Currency translation differences relating to cash and cash equivalents
(104)
(322)
(118)
(861)
(6,293)
(5,382)
(19,008)
(15,731)
(a)Other includes adjustments for net operating cash received or paid which is held on behalf of third parties for medium-term deferred payment and prior periods have been adjusted accordingly. Third quarter and nine months 2023 include $517 million of proceeds from the sale of a 49% interest in a controlled affiliate holding certain midstream assets onshore US. Nine months 2022 includes $573 million of proceeds from the disposal of a loan note related to the Alaska divestment. The cash was received in the fourth quarter 2021, was reported as a financing cash flow and was not included in other proceeds at the time due to potential recourse from the counterparty. The proceeds were recognized as the potential recourse reduces and by end second quarter 2022 all were recognized.
Adjusted earnings before interest, taxation, depreciation and amortization (adjusted EBITDA)*
Third
Third
Nine
Nine
quarter
quarter
months
months
$ million
2023
2022
2023
2022
Profit (loss) for the period
5,069
(1,984)
15,444
(12,518)
Finance costs
1,039
649
2,802
1,869
Net finance (income) expense relating to pensions and other post-retirement benefits
(61)
(16)
(180)
(53)
Taxation
2,240
3,964
7,206
11,021
Profit before interest and tax
8,287
2,613
25,272
319
Inventory holding (gains) losses*, before tax
(1,593)
2,868
(261)
(2,779)
6,694
5,481
25,011
(2,460)
Net (favourable) adverse impact of adjusting items*, before interest and tax
(607)
8,269
(4,102)
39,185
6,087
13,750
20,909
36,725
Add back:
Depreciation, depletion and amortization
4,145
3,467
11,868
10,604
Exploration expenditure written off
74
190
365
318
Adjusted EBITDA
10,306
17,407
33,142
47,647
Reconciliation of customers & products RC profit before interest and tax to underlying RC profit before interest and tax* to adjusted EBITDA* by business
Third
Third
Nine
Nine
quarter
quarter
months
months
$ million
2023
2022
2023
2022
RC profit before interest and tax for customers & products
1,549
2,586
4,784
8,098
Less: Adjusting items* gains (charges)
(506)
(139)
(826)
(789)
Underlying RC profit before interest and tax for customers & products
2,055
2,725
5,610
8,887
By business:
customers – convenience & mobility
670
1,137
1,762
2,338
Castrol – included in customers
185
151
517
630
products – refining & trading
1,385
1,588
3,848
6,549
Add back: Depreciation, depletion and amortization
(a)Based on sales of consolidated subsidiaries only – this excludes equity-accounted entities.
(b)Realizations calculation methodology has been changed to reflect gas price fluctuations within the North Sea region. Third quarter 2022 and nine months 2022 were restated. There is no impact on financial results.
For a full discussion of the group’s material legal proceedings, see pages 258-259 of bp Annual Report and Form 20-F 2022 and page 35 of BP p.l.c. Group results second quarter and half-year 2023 results announcement. The following discussion sets out the material developments in the group’s material legal proceedings in the period following the second quarter and half-year 2023 results announcement.
Louisiana Coastal restoration
Six coastal parishes and the State of Louisiana have filed over 40 separate lawsuits in state courts in Louisiana against various oil and gas companies seeking damages for coastal erosion. bp entities are defendants in 17 of these cases. The lawsuits allege that the defendants' historical operations in oil and gas fields within the Louisiana onshore coastal zone failed to comply with state permits and/or were conducted without the required coastal use permits. The scope and scale of plaintiffs’ damages demands are significant and unprecedented, including substantial remediation costs and the claimed costs for restoring coastal wetlands allegedly impacted by oil and gas field operations.
Defendants removed all of these lawsuits to federal court and the removals were contested by plaintiffs, eventually resulting in a decision from the US Fifth Circuit Court of Appeals rejecting defendants’ “federal officer” jurisdiction removal in the lead test case. Defendants’ petition for writ of certiorari to the US Supreme Court seeking review of the US Fifth Circuit’s decision was denied in early 2023. On remand from the US District Court, the state court in the case of Cameron Parish v. Auster et al. has established a November 2023 trial date. bp is the lead defendant in Auster. A subset of the removed cases remain in federal court pending further Fifth Circuit rulings on a related “federal officer” removal jurisdiction theory.
In addition, four private landowners have filed separate claims in the state courts in Jefferson and Plaquemines Parishes of Louisiana for restoration damages related to alleged impacts to their marshlands associated with historic oil field operations. bp entities are defendants in two of these private landowner cases.
With the exception of the Auster case, which is nearing completion of the expert discovery stage and final pre-trial activity, all of the other remanded cases remain at early stages in the litigation. While it is not possible to predict the outcomes of these novel legal actions, bp believes that it has valid defences, and it intends to defend such actions vigorously.
Glossary
Non-IFRS 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-IFRS measures are sometimes referred to as alternative performance measures.
Adjusted EBITDA is a non-IFRS measure presented for bp's operating segments and is defined as replacement cost (RC) profit before interest and tax, excluding net adjusting items* before interest and tax, and adding back depreciation, depletion and amortization and exploration write-offs (net of adjusting items). Adjusted EBITDA by business is a further analysis of adjusted EBITDA for the customers & products businesses. bp believes it is helpful to disclose adjusted EBITDA by operating segment and by business because it reflects how the segments measure underlying business delivery. The nearest equivalent measure on an IFRS basis for the segment is RC profit or loss before interest and tax, which is bp's measure of profit or loss that is required to be disclosed for each operating segment under IFRS. A reconciliation to IFRS information is provided on pages 30-31 for the segments.
Adjusted EBITDA for the group is defined as profit or loss for the period, adjusting for finance costs and net finance (income) or expense relating to pensions and other post-retirement benefits and taxation, inventory holding gains or losses before tax, net adjusting items before interest and tax, and adding back depreciation, depletion and amortization (pre-tax) and exploration expenditure written-off (net of adjusting items, pre-tax). The nearest equivalent measure on an IFRS basis for the group is profit or loss for the period. A reconciliation to IFRS information is provided on page 30 for the group.
Adjusting items are items that bp discloses separately because it considers such disclosures to be meaningful and relevant to investors. They are items that management considers to be important to period-on-period analysis of the group's results and are disclosed in order to enable investors to better understand and evaluate the group’s reported financial performance. Adjusting items include gains and losses on the sale of businesses and fixed assets, impairments, environmental and other provisions, restructuring, integration and rationalization costs, fair value accounting effects, financial impacts relating to Rosneft for the 2022 financial reporting period and costs relating to the Gulf of Mexico oil spill and other items. Adjusting items within equity-accounted earnings are reported net of incremental income tax reported by the equity-accounted entity. Adjusting items are used as a reconciling adjustment to derive underlying RC profit or loss and related underlying measures which are non-IFRS measures. An analysis of adjusting items by segment and type is shown on page 28.
Blue hydrogen – Hydrogen made from natural gas in combination with carbon capture and storage (CCS).
Capital expenditure is total cash capital expenditure as stated in the condensed group cash flow statement. Capital expenditure for the operating segments, gas & low carbon energy businesses and customers & products businesses is presented on the same basis.
Cash balance point is defined as the implied Brent oil price 2021 real to balance bp’s sources and uses of cash assuming an average bp refining marker margin around $11/bbl and Henry Hub at $3/mmBtu in 2021 real terms.
Consolidation adjustment – UPII is unrealized profit in inventory arising on inter-segment transactions.
Developed renewables to final investment decision (FID) – Total generating capacity for assets developed to FID by all entities where bp has an equity share (proportionate to equity share). If asset is subsequently sold bp will continue to record capacity as developed to FID. If bp equity share increases developed capacity to FID will increase proportionately to share increase for any assets where bp held equity at the point of FID.
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-IFRS measure. The ETR on RC profit or loss is calculated by dividing taxation on a RC basis by RC profit or loss before tax. Taxation on a RC basis for the group is calculated as taxation as stated on the group income statement adjusted for taxation on inventory holding gains and losses. 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. Taxation on a RC basis and ETR on RC profit or loss are non-IFRS measures. The nearest equivalent measure on an IFRS basis is the ETR on profit or loss for the period. A reconciliation to IFRS information is provided on page 32.
Electric vehicle charge points / EV charge points are defined as the number of connectors on a charging device, operated by either bp or a bp joint venture.
Fair value accounting effects are non-IFRS 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. Fair value accounting effects are included within adjusting items. They relate to certain of the group's commodity, interest rate and currency risk exposures as detailed below. Other than as noted below, the fair value accounting effects described are reported in both the gas & low carbon energy and customer & products segments.
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, other than net realizable value provisions, 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, liquefied natural gas (LNG) and certain gas and power contracts 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. 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.
These include:
•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.
•Fair value accounting effects also 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, which is reported in the gas and low carbon energy segment, represents the change in value of LNG contacts that are being risk managed and which is reflected in the underlying result, but not in reported earnings. Management believes that this gives a better representation of performance in each period.
Furthermore, the fair values of derivative instruments used to risk manage certain other oil, gas, power and other contracts, are deferred to match with the underlying exposure. The commodity contracts for business requirements are accounted for on an accruals basis.
In addition, fair value accounting effects include changes in the fair value of derivatives entered into by the group to manage currency exposure and interest rate risks relating to hybrid bonds to their respective first call periods. The hybrid bonds which were issued on 17 June 2020 are classified as equity instruments and were recorded in the balance sheet at that date at their USD equivalent issued value. Under IFRS these equity instruments are not remeasured from period to period, and do not qualify for application of hedge accounting. The derivative instruments relating to the hybrid bonds, however, are required to be recorded at fair value with mark to market gains and losses recognized in the income statement. Therefore, measurement differences in relation to the recognition of gains and losses occur. The fair value accounting effect, which is reported in the other businesses & corporate segment, eliminates the fair value gains and losses of these derivative financial instruments that are recognized in the income statement. We believe that this gives a better representation of performance, by more appropriately reflecting the economic effect of these risk management activities, in each period.
Gas & low carbon energy segment comprises our gas and low carbon businesses. Our gas business includes regions with upstream activities that predominantly produce natural gas, integrated gas and power, and gas trading. Our low carbon business includes solar, offshore and onshore wind, hydrogen and CCS and power trading. Power trading includes trading of both renewable and non-renewable power.
Gearing and net debt are non-IFRS measures. Net debt is calculated as finance debt, as shown in the balance sheet, plus the fair value of associated derivative financial instruments that are used to hedge foreign currency exchange and interest rate risks relating to finance debt, for which hedge accounting is applied, less cash and cash equivalents. Net debt does not include accrued interest, which is reported within other receivables and other payables on the balance sheet and for which the associated cash flows are presented as operating cash flows in the group cash flow statement. Gearing is defined as the ratio of net debt to the total of net debt plus total equity. bp believes these measures provide useful information to investors. Net debt enables investors to see the economic effect of finance debt, related hedges and cash and cash equivalents in total. Gearing enables investors to see how significant net debt is relative to total equity. The derivatives are reported on the balance sheet within the headings ‘Derivative financial instruments’. The nearest equivalent measures on an IFRS basis are finance debt and finance debt ratio. A reconciliation of finance debt to net debt is provided on page 26.
We are unable to present reconciliations of forward-looking information for net debt or gearing to finance debt and total equity, because without unreasonable efforts, we are unable to forecast accurately certain adjusting items required to present a meaningful comparable IFRS 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 an IFRS estimate.
Gearing including leases and net debt including leases are non-IFRS measures. Net debt including leases is calculated as net debt plus lease liabilities, less the net amount of partner receivables and payables relating to leases entered into on behalf of joint operations. Gearing including leases is defined as the ratio of net debt including leases to the total of net debt including leases plus total equity. bp believes these measures provide useful information to investors as they enable investors to understand the impact of the group’s lease portfolio on net debt and gearing. The nearest equivalent measures on an IFRS basis are finance debt and finance debt ratio. A reconciliation of finance debt to net debt including leases is provided on page 29.
Green hydrogen – Hydrogen produced by electrolysis of water using renewable power.
Hydrocarbons – Liquids and natural gas. Natural gas is converted to oil equivalent at 5.8 billion cubic feet = 1 million barrels.
Hydrogen pipeline – Hydrogen projects which have not been developed to final investment decision (FID) but which have advanced to the concept development stage.
Inorganic capital expenditure is a subset of capital expenditure on a cash basis and a non-IFRS 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. The nearest equivalent measure on an IFRS basis is capital expenditure on a cash basis. Further information and a reconciliation to IFRS information is provided on page 27.
Installed renewables capacity is bp's share of capacity for operating assets owned by entities where bp has an equity share.
Inventory holding gains and losses are non-IFRS adjustments to our IFRS profit (loss) and represent:
a.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 of inventories other than for trading inventories, 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 as inventory holding gains and losses 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; and
b.an adjustment relating to certain trading inventories that are not price risk managed which relate to a minimum inventory volume that is required to be held to maintain underlying business activities. This adjustment represents the movement in fair value of the inventories due to prices, on a grade by grade basis, during the period. This is calculated from each operation’s inventory management system on a monthly basis using the discrete monthly movement in market prices for these inventories.
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 that are price risk-managed. See Replacement cost (RC) profit or loss definition below.
Liquids – Liquids comprises crude oil, condensate and natural gas liquids. For the oil production & operations segment, it also includes bitumen.
Low carbon activity – An activity relating to low carbon including: renewable electricity; bioenergy; electric vehicles and other future mobility solutions; trading and marketing low carbon products; blue or green hydrogen and carbon capture, use and storage (CCUS).
Note that, while there is some overlap of activities, these terms do not mean the same as bp’s strategic focus area of low carbon energy or our low carbon energy sub-segment, reported within the gas & low carbon energy segment.
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.
Operating cash flow is net cash provided by (used in) operating activities as stated in the condensed group cash flow statement.
Organic capital expenditure is a non-IFRS measure. Organic capital expenditure comprises capital expenditure on a cash basis 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. The nearest equivalent measure on an IFRS basis is capital expenditure on a cash basis and a reconciliation to IFRS 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 IFRS estimate.
Production-sharing agreement/contract (PSA/PSC) is an arrangement through which an oil and gas company bears the risks and costs of exploration, development and production. In return, if exploration is successful, the oil company receives entitlement to variable physical volumes of hydrocarbons, representing recovery of the costs incurred and a stipulated share of the production remaining after such cost recovery.
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. For the gas & low carbon energy and oil production & operations segments, realizations include transfers between businesses.
Refining availability represents Solomon Associates’ operational availability for bp-operated refineries, which is defined as the percentage of the year that a unit is available for processing after subtracting the annualized time lost due to turnaround activity and all planned mechanical, process and regulatory downtime.
The Refining marker margin (RMM) is the average of regional indicator margins weighted for bp’s crude refining capacity in each region. Each regional marker margin is based on product yields and a marker crude oil deemed appropriate for the region. The regional indicator margins may not be representative of the margins achieved by bp in any period because of bp’s particular refinery configurations and crude and product slate.
Renewables pipeline – Renewable projects satisfying the following criteria until the point they can be considered developed to final investment decision (FID): Site based projects that have obtained land exclusivity rights, or for power purchase agreement based projects an offer has been made to the counterparty, or for auction projects pre-qualification criteria has been met, or for acquisition projects post a binding offer being accepted.
Replacement cost (RC) profit or loss / RC profit or loss attributable to bp shareholders reflects the replacement cost of inventories sold in the period and is calculated as profit or loss attributable to bp shareholders, adjusting for inventory holding gains and losses (net of tax). RC profit or loss for the group is not a recognized IFRS 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 IFRS information is provided on page 3. RC profit or loss before interest and tax is bp's measure of profit or loss that is required to be disclosed for each operating segment under IFRS.
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. Reported incidents are investigated throughout the year and as a result there may be changes in previously reported incidents. Therefore comparative movements are calculated against internal data reflecting the final outcomes of such investigations, rather than the previously reported comparative period, as this this represents a more up to date reflection of the safety environment.
Retail sites include sites operated by dealers, jobbers, franchisees or brand licensees or joint venture (JV) partners, under the bp brand. These may move to and from the bp brand as their fuel supply agreement or brand licence agreement expires and are renegotiated in the normal course of business. Retail sites are primarily branded bp, ARCO, Amoco, Aral and Thorntons, and also includes sites in India through our Jio-bp JV.
Solomon availability – See Refining availability definition.
Strategic convenience sites are retail sites, within the bp portfolio, which sell bp-branded vehicle energy (e.g. bp, Aral, Arco, Amoco, Thorntons, TravelCenters of America and bp pulse) and either carry one of the strategic convenience brands (e.g. M&S, Rewe to Go) or a differentiated convenience offer. To be considered a strategic convenience site, the convenience offer should have a demonstrable level of differentiation in the market in which it operates. Strategic convenience site count includes sites under a pilot phase.
Surplus cash flow does not represent the residual cash flow available for discretionary expenditures. It is a non-IFRS financial measure that should be considered in addition to, not as a substitute for or superior to, net cash provided by operating activities, reported in accordance with IFRS. bp believes it is helpful to disclose the surplus cash flow because this measure forms part of bp's financial frame.
Surplus cash flow refers to the net surplus of sources of cash over uses of cash, after reaching the $35 billion net debt target. Sources of cash include net cash provided by operating activities, cash provided from investing activities and cash receipts relating to transactions involving non-controlling interests. Uses of cash include lease liability payments, payments on perpetual hybrid bond, dividends paid, cash capital expenditure, the cash cost of share buybacks to offset the dilution from vesting of awards under employee share schemes, cash payments relating to transactions involving non-controlling interests and currency translation differences relating to cash and cash equivalents as presented on the condensed group cash flow statement.
For the nine months of 2022, the sources of cash includes other proceeds related to the proceeds from the disposal of a loan note related to the Alaska divestment. The cash was received in the fourth quarter 2021, was reported as a financing cash flow and was not included in other proceeds at the time due to potential recourse from the counterparty. The proceeds are being recognized as the potential recourse reduces. See page 29 for the components of our sources of cash and uses of cash.
Technical service contract (TSC) – Technical service contract is an arrangement through which an oil and gas company bears the risks and costs of exploration, development and production. In return, the oil and gas company receives entitlement to variable physical volumes of hydrocarbons, representing recovery of the costs incurred and a profit margin which reflects incremental production added to the oilfield.
Tier 1 and tier 2 process safety events – Tier 1 events are losses of primary containment from a process of greatest consequence – causing harm to a member of the workforce, damage to equipment from a fire or explosion, a community impact or exceeding defined quantities. Tier 2 events are those of lesser consequence. These represent reported incidents occurring within bp’s operational HSSE reporting boundary. That boundary includes bp’s own operated facilities and certain other locations or situations. Reported process safety events are investigated throughout the year and as a result there may be changes in previously reported events. Therefore comparative movements are calculated against internal data reflecting the final outcomes of such investigations, rather than the previously reported comparative period, as this this represents a more up to date reflection of the safety environment.
Transition growth – Activities, represented by a set of transition growth engines, that transition bp toward its objective to be an Integrated Energy Company, and that comprise our low carbon activity* alongside other businesses that support transition, such as our power trading & marketing business and convenience.
Underlying effective tax rate (ETR) is a non-IFRS 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 for the group is calculated as taxation as stated on the group income statement adjusted for taxation on inventory holding gains and losses and total taxation on adjusting items. Information on underlying RC profit or loss is provided below. Taxation on an underlying RC basis presented for the operating segments is calculated through an allocation of taxation on an underlying RC basis to each segment. 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. Taxation on an underlying RC basis and underlying ETR are non-IFRS measures. 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 IFRS forward-looking financial measure. These items include the taxation on inventory holding gains and losses and adjusting items, that are difficult to predict in advance in order to include in an IFRS estimate. A reconciliation to IFRS information is provided on page 32.
Underlying production – 2023 underlying production, when compared with 2022, is production after adjusting for acquisitions and divestments, curtailments, and entitlement impacts in our production-sharing agreements/contracts and technical service contract*.
Underlying RC profit or loss / underlying RC profit or loss attributable to bp shareholders is a non-IFRS measure and is RC profit or loss* (as defined on page 37) after excluding net adjusting items and related taxation. See page 28 for additional information on the adjusting items that are used to arrive at underlying RC profit or loss in order to enable a full understanding of the items and their financial impact.
Underlying RC profit or loss before interest and tax for the operating segments or customers & products businesses is calculated as RC profit or loss (as defined above) including profit or loss attributable to non-controlling interests before interest and tax for the operating segments and excluding net adjusting items for the respective operating segment or business.
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 adjusting items. 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 and businesses is RC profit or loss before interest and taxation. A reconciliation to IFRS information is provided on page 3 for the group and pages 8-16 for the segments.
Underlying RC profit or loss per share / underlying RC profit or loss per ADS is a non-IFRS measure. Earnings per share is defined in Note 7. Underlying RC profit or loss per ordinary share is calculated using the same denominator as earnings per share as defined in the consolidated financial statements. The numerator used is underlying RC profit or loss attributable to bp shareholders rather than profit or loss attributable to bp shareholders. Underlying RC profit or loss per ADS is calculated as outlined above for underlying RC profit or loss per share except the denominator is adjusted to reflect one ADS equivalent to six ordinary shares. bp believes it is helpful to disclose the underlying RC profit or loss per ordinary share and per ADS because these measures may help investors to understand and evaluate, in the same manner as management, the underlying trends in bp’s operational performance on a comparable basis, period on period. The nearest equivalent measure on an IFRS basis is basic earnings per share based on profit or loss for the period attributable to bp shareholders. A reconciliation to IFRS information is provided on page 31.
upstream includes oil and natural gas field development and production within the gas & low carbon energy and oil production & operations segments.
upstream/hydrocarbon plant reliability (bp-operated) is calculated taking 100% less the ratio of total unplanned plant deferrals divided by installed production capacity, excluding non-operated assets and bpx energy. 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.
Trade marks
Trade marks of the bp group appear throughout this announcement. They include:
In order to utilize the ‘safe harbor’ provisions of the United States Private Securities Litigation Reform Act of 1995 (the ‘PSLRA’) and the general doctrine of cautionary statements, bp is providing the following cautionary statement:
The discussion in this results announcement contains certain forecasts, projections and forward-looking statements - that is, statements related to future, not past events and circumstances - with respect to the financial condition, results of operations and businesses of bp and certain of the plans and objectives of bp with respect to these items. These statements may generally, but not always, be identified by the use of words such as ‘will’, ‘expects’, ‘is expected to’, ‘aims’, ‘should’, ‘may’, ‘objective’, ‘is likely to’, ‘intends’, ‘believes’, ‘anticipates’, ‘plans’, ‘we see’ or similar expressions.
In particular, the following, among other statements, are all forward looking in nature: plans, expectations and assumptions regarding oil and gas demand, supply, prices or volatility; expectations regarding reserves; expectations regarding production; expectations regarding bp’s customers & products business; expectations regarding refining margins; expectations regarding turnaround and maintenance activity; expectations regarding financial performance, results of operations and cash flows; expectations regarding future project start-ups; expectations with regards to bp’s transformation to an IEC; price assumptions used in accounting estimates; bp’s plans and expectations regarding the amount and timing of share buybacks and dividends; plans and expectations regarding bp’s credit rating, including in respect of maintaining a strong investment grade credit rating; plans and expectations regarding the allocation of surplus cash flow to share buybacks and strengthening the balance sheet; plans and expectations with respect to the total depreciation, depletion and amortization and the other businesses & corporate underlying annual charge for 2023; plans and expectations regarding bp’s development of its LNG portfolio; plans and expectations regarding investments, collaborations and partnerships in electric vehicle (EV) charging infrastructure; plans and expectations related to bp’s transition growth engines of bioenergy, convenience, EV charging, renewables and power, and hydrogen; expectations relating to bp’s development of its wind pipeline; plans and expectations regarding the amount or timing of payments related to divestment and other proceeds, and the timing, quantum and nature of certain acquisitions and divestments; expectations regarding the underlying effective tax rate for 2023; expectations regarding the timing and amount of future payments relating to the Gulf of Mexico oil spill; plans and expectations regarding capital expenditure; expectations regarding greenhouse gas emissions; expectations regarding legal proceedings, including those related to the Louisiana coastal restoration and climate change; plans and expectations regarding bp-operated projects and ventures, and its projects, joint ventures, partnerships and agreements with commercial entities and other third party partners, including those related to Advanced Ionics, Dynamon, Electric Hydrogen, Midwest Alliance for Clean Hydrogen and Auchan.
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 or outcomes, may differ materially from those expressed in such statements, depending on a variety of factors, including: the extent and duration of the impact of current market conditions including the volatility of oil prices, the effects of bp’s plan to exit its shareholding in Rosneft and other investments in Russia, the impact of COVID-19, overall global economic and business conditions impacting bp’s business and demand for bp’s products as well as the specific factors identified in the discussions accompanying such forward-looking statements; changes in consumer preferences and societal expectations; the pace of development and adoption of alternative energy solutions; developments in policy, law, regulation, technology and markets, including societal and investor sentiment related to the issue of climate change; the receipt of relevant third party and/or regulatory approvals; the timing and level of maintenance and/or turnaround activity; the timing and volume of refinery additions and outages; the timing of bringing new fields onstream; the timing, quantum and nature of certain acquisitions and divestments; future levels of industry product supply, demand and pricing, including supply growth in North America and continued base oil and additive supply shortages; OPEC+ quota restrictions; PSA and TSC 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 and policies, including related to climate change; changes in social attitudes and customer preferences; 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; bp’s access to future credit resources; business disruption and crisis management; the impact on bp’s reputation of ethical misconduct and non-compliance with regulatory obligations; trading losses; major uninsured losses; the possibility that international sanctions or other steps taken by any competent authorities or any other relevant persons may impact or limit bp’s ability to sell its interests in Rosneft, or the price for which it could sell such interests; 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 those factors discussed under “Principal risks and uncertainties” in bp’s Report on Form 6-K regarding results for the six-month period ended 30 June 2023 as filed with the US Securities and Exchange Commission (the “SEC”) as well as those factors discussed under “Risk factors” in bp’s Annual Report and Form 20-F 2022 as filed with the SEC.
The following table shows the unaudited consolidated capitalization and indebtedness of the BP group as of 30 September 2023. The following amounts were extracted from the unaudited consolidated interim financial statement prepared in accordance with IAS 34.
Capitalization and indebtedness
30 September
$ million
2023
Share capital and reserves
Capital shares (1-2)
4,531
Paid-in surplus (3)
16,258
Merger reserve (3)
27,206
Treasury shares
(11,226)
Cash flow hedge reserve
161
Costs of hedging reserve
(90)
Foreign currency translation reserve
(2,731)
Profit and loss account
38,309
BP shareholders' equity
72,418
Hybrid bonds
13,497
Other interest
1,761
Equity attributable to non-controlling interests
15,258
Total equity
87,676
Finance debt and lease liabilities (4-6)
Lease liabilities due within one year
2,536
Finance debt due within one year
2,872
Lease liabilities due after more than one year
8,343
Finance debt due after more than one year
45,938
Total finance debt and lease liabilities
59,689
Total (7)(8)
147,365
1.Issued share capital as of 30 September 2023 comprised 17,119,221,814 ordinary shares, par value US$0.25 per share, and 12,706,252 preference shares, par value £1 per share. This excludes 932,744,378 ordinary shares which have been bought back and are held in treasury by BP. These shares are not taken into consideration in relation to the payment of dividends and voting at shareholders’ meetings.
2.Capital shares represent the ordinary and preference shares of BP which have been issued and are fully paid.
3.Paid-in surplus and merger reserve represent additional paid-in capital of BP which cannot normally be returned to shareholders.
4.Finance debt and lease liabilities recorded in currencies other than US dollars has been translated into US dollars at the relevant exchange rates existing on 30 September 2023.
5.Finance debt and lease liabilities presented in the table above consists of borrowings and obligations under leases. This includes one hundred percent of lease liabilities for joint operations where BP is the only party with the legal obligation to make lease payments to the lessor. Other contractual obligations are not presented in the table above – see BP Annual Report and Form 20-F 2022 – Liquidity and capital resources for further information.
6.At 30 September 2023, the parent company, BP p.l.c. had issued guarantees totalling $48,791 million relating to group finance debt issued by subsidiaries. Thus 99% of the group’s finance debt had been guaranteed by BP p.l.c. In addition, BP p.l.c. guarantees $11.9 billion of perpetual subordinated hybrid bonds issued by a subsidiary. At 30 September 2023, $199 million of finance debt was secured by the pledging of assets. The remainder of finance debt was unsecured.
7.At 30 September 2023, the group had issued third-party guarantees under which amounts outstanding, incremental to amounts recognized on the group balance sheet, were $1,630 million in respect of the borrowings of equity-accounted entities and $532 million in respect of the borrowings of other third parties.
8.Total capitalisation and indebtedness includes non-controlling interests of $15,258 million at 30 September 2023 which includes $12.0 billion related to perpetual hybrid bonds issued on 17 June 2020 and $1.5 billion related to perpetual subordinated hybrid securities issued by a group subsidiary since the second half of 2021.
9.There has been no material change since 30 September 2023 in the consolidated capitalization and indebtedness of BP.
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
