EQS-Adhoc: BP p.l.c.: 3Q23 SEA Part 1 of 1
EQS-Ad-hoc: BP p.l.c. / Key word(s): 9 Month figures
BP p.l.c.: 3Q23 SEA Part 1 of 1
31-Oct-2023 / 08:00 CET/CEST
Disclosure of an inside information acc. to Article 17 MAR of the Regulation (EU) No 596/2014, transmitted by EQS News - a service of EQS Group AG.
The issuer is solely responsible for the content of this announcement.
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FOR IMMEDIATE RELEASE London 31 October 2023 BP p.l.c. Group results Third quarter and nine months 2023
“For a printer friendly version of this announcement please click on the link below to open a PDF version of the announcement”
Performing while transforming
Financial summary Third Second Third Nine Nine quarter quarter quarter months months $ million 2023 2023 2022 2023 2022 Profit (loss) for the period attributable to bp shareholders 4,858 1,792 (2,163) 14,868 (13,290) Inventory holding (gains) losses*, net of tax (1,212) 549 2,186 (211) (2,085) Replacement cost (RC) profit (loss)* 3,646 2,341 23 14,657 (15,375) Net (favourable) adverse impact of adjusting items*, net of tax (353) 248 8,127 (3,812) 38,221 Underlying RC profit* 3,293 2,589 8,150 10,845 22,846 Operating cash flow* 8,747 6,293 8,288 22,662 27,361 Capital expenditure* (3,603) (4,314) (3,194) (11,542) (8,961) Divestment and other proceeds(a) 655 88 606 1,543 2,509 Surplus cash flow* 3,107 (269) 3,496 5,121 14,080 Net issue (repurchase) of shares (2,047) (2,073) (2,876) (6,568) (6,756) Net debt*(b) 22,324 23,660 22,002 22,324 22,002 Adjusted EBITDA* 10,306 9,770 17,407 33,142 47,647 Announced dividend per ordinary share (cents per share) 7.270 7.270 6.006 21.150 17.472 Underlying RC profit per ordinary share* (cents) 19.14 14.77 43.15 61.83 118.61 Underlying RC profit per ADS* (dollars) 1.15 0.89 2.59 3.71 7.12
• Underlying RC profit $3.3bn; Operating cash flow $8.7bn; Net debt reduced to $22.3bn • Further $1.5bn share buyback announced • Delivering resilient hydrocarbons - start up of major project* - Tangguh Expansion; North Sea Murlach project gets regulatory approval; bpx energy brings online 'Bingo' facility • Continued progress to an IEC - first Archaea modular biogas plant; Woodfibre and OMV LNG agreements
This has been a solid quarter supported by strong underlying operational performance demonstrating our continued focus on delivery. Momentum continues to build across our businesses, with recent start-ups including Tangguh Expansion, bpx energy’s 'Bingo' central processing facility and Archaea Energy's first modular biogas plant in Indiana. As we laid out at our investor update in Denver, we remain committed to executing our strategy, expect to grow earnings through this decade, and on track to deliver strong returns for our shareholders. Murray Auchincloss
Chief executive officer (Interim)
Divestment proceeds are disposal proceeds as per the condensed group cash flow statement. See page 3 for more information on other proceeds. See Note 9 for more information.
RC profit (loss), underlying RC profit (loss), surplus cash flow, net debt, adjusted EBITDA, underlying RC profit per ordinary share and underlying RC profit per ADS are non-IFRS measures. Inventory holding (gains) losses and adjusting items are non-IFRS adjustments.
* For items marked with an asterisk throughout this document, definitions are provided in the Glossary on page 31.
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Highlights Underlying replacement cost profit* $3.3 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.
Reported profit for the quarter was $4.9 billion, compared with $1.8 billion for the second quarter 2023. The reported result for the third quarter 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.
Operating cash flow* $8.7 billion and net debt* reduced to $22.3 billion Operating cash flow in the quarter of $8.7 billion includes a working capital* release (after adjusting for inventory holding gains, fair value accounting effects and other adjusting items) of $2.0 billion (see page 27).
Capital expenditure* in the third quarter was $3.6 billion. 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.
Net debt was reduced by $1.3 billion to $22.3 billion at the end of the third quarter. 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.
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.
bp delivered robust operating cash flow in the quarter as we continue to execute against our unchanged financial frame. Net debt reduced by $1.3 billion to $22.3 billion; we are investing with discipline; and we are delivering on our commitment to shareholder distributions, announcing a further $1.5 billion share buyback programme. Kate Thomson
Chief financial officer (Interim)
The commentary above contains forward-looking statements and should be read in conjunction with the cautionary statement on page 37.
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Financial results
In addition to the highlights on page 2:
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 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. 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.
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Analysis of RC profit (loss) before interest and tax and reconciliation to profit (loss) for the period
Third Second Third Nine Nine quarter quarter quarter months months $ million 2023 2023 2022 2023 2022 RC profit (loss) before interest and tax gas low carbon energy 2,275 2,289 (2,956) 11,911 (1,743) oil production operations 3,427 2,568 6,965 9,312 18,033 customers products 1,549 555 2,586 4,784 8,098 other businesses corporate (500) (297) (1,093) (887) (26,840) Of which: other businesses corporate excluding Rosneft (500) (297) (1,093) (887) (2,807) Rosneft — — — — (24,033) Consolidation adjustment – UPII* (57) (30) (21) (109) (8) RC profit (loss) before interest and tax 6,694 5,085 5,481 25,011 (2,460) Finance costs and net Finance expense relating to pensions and other post-retirement benefits (978) (859) (633) (2,622) (1,816) Taxation on a RC basis (1,859) (1,724) (4,646) (7,156) (10,327) Non-controlling interests (211) (161) (179) (576) (772) RC profit (loss) attributable to bp shareholders* 3,646 2,341 23 14,657 (15,375) Inventory holding gains (losses)* 1,593 (732) (2,868) 261 2,779 Taxation (charge) credit on inventory holding gains and losses (381) 183 682 (50) (694) Profit (loss) for the period attributable to bp shareholders 4,858 1,792 (2,163) 14,868 (13,290)Analysis of underlying RC profit (loss) before interest and tax
Third Second Third Nine Nine quarter quarter quarter months months $ million 2023 2023 2022 2023 2022 Underlying RC profit (loss) before interest and tax gas low carbon energy 1,256 2,233 6,240 6,945 12,915 oil production operations 3,136 2,777 5,211 9,232 15,796 customers products 2,055 796 2,725 5,610 8,887 other businesses corporate (303) (170) (405) (769) (865) Of which: other businesses corporate excluding Rosneft (303) (170) (405) (769) (865) Rosneft — — — — — Consolidation adjustment – UPII (57) (30) (21) (109) (8) Underlying RC profit before interest and tax 6,087 5,606 13,750 20,909 36,725 Finance costs and net Finance expense relating to pensions and other post-retirement benefits (882) (740) (565) (2,303) (1,560) Taxation on an underlying RC basis (1,701) (2,116) (4,856) (7,185) (11,547) Non-controlling interests (211) (161) (179) (576) (772) Underlying RC profit attributable to bp shareholders* 3,293 2,589 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 1 for the group and on pages 6-14 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% 1.6See Operational updates on pages 6, 9 and 11. Because of rounding, upstream production may not agree exactly with the sum of gas low carbon energy and oil production operations. Mainly reflecting impact of portfolio changes.
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Outlook Guidance
Macro outlook
In the fourth quarter:
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 2:
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%.Adjusted EBITDA* aims(a)
bp has increased its 2030 Adjusted EBITDA aims for resilient hydrocarbons and group by $2 billion to a range of $41-44 billion and $53-58 billion respectively. Brent $70/bbl 2021 real, at bp planning assumptions, and at the upper end of the respective expected capital expenditure* ranges.The commentary above contains forward-looking statements and should be read in conjunction with the cautionary statement on page 37.
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gas low carbon energy*
Financial results
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.
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gas low carbon energy (continued)
Third Second Third Nine Nine quarter quarter quarter months months $ million 2023 2023 2022 2023 2022 Profit (loss) before interest and tax 2,275 2,289 (2,970) 11,912 (1,741) Inventory holding (gains) losses* — — 14 (1) (2) RC profit (loss) before interest and tax 2,275 2,289 (2,956) 11,911 (1,743) Net (favourable) adverse impact of adjusting items (1,019) (56) 9,196 (4,966) 14,658 Underlying RC profit before interest and tax 1,256 2,233 6,240 6,945 12,915 Taxation on an underlying RC basis (448) (575) (1,478) (1,984) (3,204) Underlying RC profit before interest 808 1,658 4,762 4,961 9,711Third Second Third Nine Nine quarter quarter quarter months months $ million 2023 2023 2022 2023 2022 Depreciation, depletion and amortization Total depreciation, depletion and amortization 1,543 1,407 1,177 4,390 3,635 Exploration write-offs Exploration write-offs 15 (1) 10 13 8 Adjusted EBITDA* Total adjusted EBITDA 2,814 3,639 7,427 11,348 16,558 Capital expenditure* gas 833 697 872 2,177 2,195 low carbon energy 222 190 86 778 447 Total capital expenditure 1,055 887 958 2,955 2,642
Third Second Third Nine Nine quarter quarter quarter months months 2023 2023 2022 2023 2022 Production (net of royalties)(a) Liquids* (mb/d) 106 103 117 107 117 Natural gas (mmcf/d) 4,875 4,641 5,011 4,826 4,873 Total hydrocarbons* (mboe/d) 946 903 981 940 957 Average realizations*(b) Liquids ($/bbl) 76.69 73.57 88.03 76.51 92.93 Natural gas ($/mcf) 5.38 5.53 9.85 6.11 8.74 Total hydrocarbons* ($/boe) 36.82 36.96 60.80 40.23 55.91
Includes bp’s share of production of equity-accounted entities in the gas low carbon energy segment. Realizations are based on sales by consolidated subsidiaries only – this excludes equity-accounted entities.
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gas low carbon energy (continued)
30 September 30 June 30 September low carbon energy(c) 2023 2023 2022 Renewables (bp net, GW) Installed renewables capacity* 2.5 2.4 2.0 Developed renewables to FID* 6.1 6.1 4.6 Renewables pipeline 43.9 39.6 26.9 of which by geographical area: Renewables pipeline – Americas 18.4 17.8 17.5 Renewables pipeline – Asia Pacific(d) 12.1 12.2 1.7 Renewables pipeline – Europe 13.4 9.5 7.6 Renewables pipeline – Other — 0.1 0.1 of which by technology: Renewables pipeline – offshore wind 9.3 5.3 5.2 Renewables pipeline – onshore wind 6.1 6.3 — Renewables pipeline – solar 28.5 28.1 21.7 Total Developed renewables to FID and Renewables pipeline 50.0 45.7 31.5Because of rounding, some totals may not agree exactly with the sum of their component parts. 30 September 2023 and 30 June 2023 include 10.3GW of onshore wind and solar pipeline in support of hydrogen.
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oil production operations
Financial results
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 Second Third Nine Nine quarter quarter quarter months months $ million 2023 2023 2022 2023 2022 Profit before interest and tax 3,426 2,568 6,966 9,312 18,028 Inventory holding (gains) losses* 1 — (1) — 5 RC profit before interest and tax 3,427 2,568 6,965 9,312 18,033 Net (favourable) adverse impact of adjusting items (291) 209 (1,754) (80) (2,237) Underlying RC profit before interest and tax 3,136 2,777 5,211 9,232 15,796 Taxation on an underlying RC basis (1,386) (1,413) (2,921) (4,565) (7,128) Underlying RC profit before interest 1,750 1,364 2,290 4,667 8,668
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oil production operations (continued)
Third Second Third Nine Nine quarter quarter quarter months months $ million 2023 2023 2022 2023 2022 Depreciation, depletion and amortization Total depreciation, depletion and amortization 1,432 1,370 1,381 4,129 4,181 Exploration write-offs Exploration write-offs 59 242 180 352 310 Adjusted EBITDA* Total adjusted EBITDA 4,627 4,389 6,772 13,713 20,287 Capital expenditure* Total capital expenditure 1,644 1,478 1,386 4,642 3,848Third Second Third Nine Nine quarter quarter quarter months months 2023 2023 2022 2023 2022 Production (net of royalties)(a) Liquids* (mb/d) 1,011 1,000 959 1,005 947 Natural gas (mmcf/d) 2,155 2,140 2,075 2,118 2,001 Total hydrocarbons* (mboe/d) 1,382 1,369 1,317 1,371 1,292 Average realizations*(b) Liquids ($/bbl) 71.10 69.19 93.14 70.65 92.35 Natural gas(c) ($/mcf) 3.44 3.23 12.12 4.37 10.54 Total hydrocarbons*(c) ($/boe) 56.76 54.57 86.83 57.86 84.57
Includes bp’s share of production of equity-accounted entities in the oil production operations segment. Realizations are based on sales by consolidated subsidiaries only – this excludes equity-accounted entities. 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.
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customers products
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.
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customers products (continued)
Third Second Third Nine Nine quarter quarter quarter months months $ million 2023 2023 2022 2023 2022 Profit (loss) before interest and tax 3,143 (177) (269) 5,044 10,880 Inventory holding (gains) losses* (1,594) 732 2,855 (260) (2,782) RC profit before interest and tax 1,549 555 2,586 4,784 8,098 Net (favourable) adverse impact of adjusting items 506 241 139 826 789 Underlying RC profit before interest and tax 2,055 796 2,725 5,610 8,887 Of which:(a) customers – convenience mobility 670 701 1,137 1,762 2,338 Castrol – included in customers 185 171 151 517 630 products – refining trading 1,385 95 1,588 3,848 6,549 Taxation on an underlying RC basis (167) (271) (725) (1,215) (1,908) Underlying RC profit before interest 1,888 525 2,000 4,395 6,979A reconciliation to RC profit before interest and tax by business is provided on page 29.
Third Second Third Nine Nine quarter quarter quarter months months $ million 2023 2023 2022 2023 2022 Adjusted EBITDA*(b) customers – convenience mobility 1,151 1,149 1,448 3,032 3,290 Castrol – included in customers 228 213 187 641 743 products – refining trading 1,819 541 1,974 5,184 7,726 2,970 1,690 3,422 8,216 11,016 Depreciation, depletion and amortization Total depreciation, depletion and amortization 915 894 697 2,606 2,129 Capital expenditure* customers – convenience mobility 435 1,452 404 2,345 1,085 Castrol – included in customers 60 44 42 172 137 products – refining trading 367 406 309 1,305 1,018 Total capital expenditure 802 1,858 713 3,650 2,103
A reconciliation to RC profit before interest and tax by business is provided on page 29.
Retail(c) Third Second Third Nine Nine quarter quarter quarter months months 2023 2023 2022 2023 2022 bp retail sites* – total (#) 21,150 21,100 20,550 21,150 20,550 Strategic convenience sites* 2,750 2,750 2,250 2,750 2,250
Reported to the nearest 50.
Marketing sales of refined products (mb/d) Third Second Third Nine Nine quarter quarter quarter months months 2023 2023 2022 2023 2022 US 1,280 1,275 1,143 1,212 1,140 Europe 1,093 1,056 1,098 1,041 1,005 Rest of World 474 472 451 469 454 2,847 2,803 2,692 2,722 2,599 Trading/supply sales of refined products 392 353 355 359 359 Total sales volume of refined products 3,239 3,156 3,047 3,081 2,958
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customers products (continued)
Refining marker margin* Third Second Third Nine Nine quarter quarter quarter months months 2023 2023 2022 2023 2022 bp average refining marker margin (RMM)(d) ($/bbl) 31.8 24.7 35.5 28.2 33.4The 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.
Refinery throughputs (mb/d) Third Second Third Nine Nine quarter quarter quarter months months 2023 2023 2022 2023 2022 US 690 638 703 671 700 Europe 760 726 809 773 818 Rest of World — — — — 29 Total refinery throughputs 1,450 1,364 1,512 1,444 1,547 bp-operated refining availability* (%) 96.3 95.7 94.3 96.0 94.4
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other businesses corporate
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 Second Third Nine Nine quarter quarter quarter months months $ million 2023 2023 2022 2023 2022 Profit (loss) before interest and tax (500) (297) (1,093) (887) (26,840) Inventory holding (gains) losses* — — — — — RC profit (loss) before interest and tax (500) (297) (1,093) (887) (26,840) Net (favourable) adverse impact of adjusting items(a) 197 127 688 118 25,975 Underlying RC profit (loss) before interest and tax (303) (170) (405) (769) (865) Taxation on an underlying RC basis 162 10 206 201 396 Underlying RC profit (loss) before interest (141) (160) (199) (568) (469)Includes fair value accounting effects relating to the hybrid bonds that were issued on 17 June 2020. See page 32 for more information.
other businesses corporate (excluding Rosneft)
Third Second Third Nine Nine quarter quarter quarter months months $ million 2023 2023 2022 2023 2022 Profit (loss) before interest and tax (500) (297) (1,093) (887) (2,807) Inventory holding (gains) losses* — — — — — RC profit (loss) before interest and tax (500) (297) (1,093) (887) (2,807) Net (favourable) adverse impact of adjusting items 197 127 688 118 1,942 Underlying RC profit (loss) before interest and tax (303) (170) (405) (769) (865) Taxation on an underlying RC basis 162 10 206 201 396 Underlying RC profit (loss) before interest (141) (160) (199) (568) (469)other businesses corporate (Rosneft)
Third Second Third Nine Nine quarter quarter quarter months months $ million 2023 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 — — — — — Taxation on an underlying RC basis — — — — — Underlying RC profit (loss) before interest — — — — —
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Financial statements
Group income statement
Third Second Third Nine Nine quarter quarter quarter months months $ million 2023 2023 2022 2023 2022 Sales and other operating revenues (Note 5) 53,269 48,538 55,011 157,989 172,135 Earnings from joint ventures – after interest and tax (198) 360 498 357 939 Earnings from associates – after interest and tax 271 231 275 675 1,273 Interest and other income 410 378 159 1,036 495 Gains on sale of businesses and fixed assets 264 (28) 1,866 389 3,693 Total revenues and other income 54,016 49,479 57,809 160,446 178,535 Purchases 29,951 29,172 39,993 88,245 106,942 Production and manufacturing expenses 6,080 6,231 7,193 19,293 21,769 Production and similar taxes 456 404 639 1,334 1,768 Depreciation, depletion and amortization (Note 6) 4,145 3,923 3,467 11,868 10,604 Net impairment and losses on sale of businesses and fixed assets (Note 3) 542 1,269 417 1,899 26,893 Exploration expense 97 293 225 496 445 Distribution and administration expenses 4,458 3,834 3,262 12,039 9,795 Profit (loss) before interest and taxation 8,287 4,353 2,613 25,272 319 Finance costs 1,039 920 649 2,802 1,869 Net finance (income) expense relating to pensions and other post-retirement benefits (61) (61) (16) (180) (53) Profit (loss) before taxation 7,309 3,494 1,980 22,650 (1,497) Taxation 2,240 1,541 3,964 7,206 11,021 Profit (loss) for the period 5,069 1,953 (1,984) 15,444 (12,518) Attributable to bp shareholders 4,858 1,792 (2,163) 14,868 (13,290) Non-controlling interests 211 161 179 576 772 5,069 1,953 (1,984) 15,444 (12,518) Earnings per share (Note 7) Profit (loss) for the period attributable to bp shareholders Per ordinary share (cents) Basic 28.24 10.22 (11.45) 84.77 (69.01) Diluted 27.59 10.01 (11.45) 82.99 (69.01) Per ADS (dollars) Basic 1.69 0.61 (0.69) 5.09 (4.14) Diluted 1.66 0.60 (0.69) 4.98 (4.14)
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Condensed group statement of comprehensive income
Third Second Third Nine Nine quarter quarter quarter months months $ million 2023 2023 2022 2023 2022 Profit (loss) for the period 5,069 1,953 (1,984) 15,444 (12,518) Other comprehensive income Items that may be reclassified subsequently to profit or loss Currency translation differences(a) (590) 11 (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) (56) (142) 434 179 Share of items relating to equity-accounted entities, net of tax 25 (27) (134) (205) 10 Income tax relating to items that may be reclassified (69) 71 (54) (74) (226) (692) (1) (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) (855) 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 57 308 19 388 (470) (55) (547) 130 (666) 1,373 Other comprehensive income (747) (548) (1,925) (639) 6,199 Total comprehensive income 4,322 1,405 (3,909) 14,805 (6,319) Attributable to bp shareholders 4,140 1,240 (4,042) 14,241 (6,978) Non-controlling interests 182 165 133 564 659 4,322 1,405 (3,909) 14,805 (6,319)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. Nine months 2022 predominantly relates to the loss of significant influence over Rosneft.
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Condensed group statement of changes in equity
bp shareholders’ Non-controlling interests Total $ million Hybrid bonds Other interest At 1 January 2023 67,553 13,390 2,047 82,990 Total comprehensive income 14,241 438 126 14,805 Dividends (3,598) — (326) (3,924) Repurchase of ordinary share capital (6,666) — — (6,666) Share-based payments, net of tax 531 — — 531 Issue of perpetual hybrid bonds (1) 163 — 162 Payments on perpetual hybrid bonds (5) (494) — (499) 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 (a) Hybrid bonds Other interest 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 73,333In 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. Relates to ordinary shares issued as non-cash consideration for the acquisition of the public units of BP Midstream Partners LP.
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Group balance sheet
30 September 31 December $ million 2023 2022 Non-current assets Property, plant and equipment 107,163 106,044 12,283 11,960 Intangible assets 9,997 10,200 Investments in joint ventures 12,635 12,400 Investments in associates 7,954 8,201 Other investments 2,337 2,670 Fixed assets 152,369 151,475 Loans 1,656 1,271 Trade and other receivables 1,066 1,092 Derivative financial instruments 9,495 12,841 Prepayments 600 576 Deferred tax assets 3,470 3,908 Defined benefit pension plan surpluses 8,173 9,269 176,829 180,432 Current assets Loans 363 315 Inventories 25,671 28,081 Trade and other receivables 31,558 34,010 Derivative financial instruments 12,950 11,554 Prepayments 1,333 2,092 Current tax receivable 674 621 Other investments 932 578 Cash and cash equivalents 29,926 29,195 103,407 106,446 Assets classified as held for sale (Note 2) — 1,242 103,407 107,688 Total assets 280,236 288,120 Current liabilities Trade and other payables 60,440 63,984 Derivative financial instruments 6,542 12,618 Accruals 5,958 6,398 Lease liabilities 2,536 2,102 Finance debt 2,872 3,198 Current tax payable 3,054 4,065 Provisions 4,193 6,332 85,595 98,697 Liabilities directly associated with assets classified as held for sale (Note 2) — 321 85,595 99,018 Non-current liabilities Other payables 9,465 10,387 Derivative financial instruments 11,409 13,537 Accruals 1,273 1,233 Lease liabilities 8,343 6,447 Finance debt 45,938 43,746 Deferred tax liabilities 10,293 10,526 Provisions 15,497 14,992 Defined benefit pension plan and other post-retirement benefit plan deficits 4,747 5,244 106,965 106,112 Total liabilities 192,560 205,130 Net assets 87,676 82,990 bp shareholders’ equity 72,418 67,553 Non-controlling interests 15,258 15,437 Total equity 87,676 82,990
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Condensed group cash flow statement
Third Second Third Nine Nine quarter quarter quarter months months $ million 2023 2023 2022 2023 2022 Operating activities Profit (loss) before taxation 7,309 3,494 1,980 22,650 (1,497) Adjustments to reconcile profit (loss) before taxation to net cash provided by operating activities Depreciation, depletion and amortization and exploration expenditure written off 4,219 4,164 3,657 12,233 10,922 Net impairment and (gain) loss on sale of businesses and fixed assets 278 1,297 (1,449) 1,510 23,200 Earnings from equity-accounted entities, less dividends received 421 (31) (391) 391 (1,412) Net charge for interest and other finance expense, less net interest paid 136 102 72 301 210 Share-based payments 298 243 251 519 629 Net operating charge for pensions and other post-retirement benefits, less contributions and benefit payments for unfunded plans (40) (47) (15) (130) (197) Net charge for provisions, less payments (342) (221) 173 (1,662) 1,453 Movements in inventories and other current and non-current assets and liabilities (783) (742) 6,764 (5,280) 577 Income taxes paid (2,749) (1,966) (2,754) (7,870) (6,524) Net cash provided by operating activities 8,747 6,293 8,288 22,662 27,361 Investing activities Expenditure on property, plant and equipment, intangible and other assets (3,456) (3,453) (3,105) (10,038) (8,373) Acquisitions, net of cash acquired (9) (804) (3) (761) (8) Investment in joint ventures (102) (50) (40) (692) (493) Investment in associates (36) (7) (46) (51) (87) Total cash capital expenditure (3,603) (4,314) (3,194) (11,542) (8,961) Proceeds from disposal of fixed assets 59 28 12 102 682 Proceeds from disposal of businesses, net of cash disposed 79 60 594 924 1,254 Proceeds from loan repayments 12 21 15 39 60 Cash provided from investing activities 150 109 621 1,065 1,996 Net cash used in investing activities (3,453) (4,205) (2,573) (10,477) (6,965) Financing activities Net issue (repurchase) of shares (Note 7) (2,047) (2,073) (2,876) (6,568) (6,756) Lease liability payments (663) (620) (478) (1,838) (1,448) Proceeds from long-term financing 8 3,643 1 6,046 2,003 Repayments of long-term financing (264) (2,828) (4,035) (3,891) (9,500) Net increase (decrease) in short-term debt (71) (348) (618) (948) (1,582) Issue of perpetual hybrid bonds 30 87 194 162 322 Payments relating to perpetual hybrid bonds (258) (250) (180) (744) (489) Payments relating to transactions involving non-controlling interests (Other interest) — — (2) (180) (8) Receipts relating to transactions involving non-controlling interests (Other interest) 527 2 3 536 10 Dividends paid - bp shareholders (1,249) (1,153) (1,140) (3,585) (3,270) - non-controlling interests (191) (67) (66) (326) (194) Net cash provided by (used in) financing activities (4,178) (3,607) (9,197) (11,336) (20,912) Currency translation differences relating to cash and cash equivalents (104) — (322) (118) (861) Increase (decrease) in cash and cash equivalents 1,012 (1,519) (3,804) 731 (1,377) Cash and cash equivalents at beginning of period 28,914 30,433 33,108 29,195 30,681 Cash and cash equivalents at end of period 29,926 28,914 29,304 29,926 29,304
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Notes
Note 1. Basis of preparation
The interim financial information included in this report has been prepared in accordance with IAS 34 'Interim Financial Reporting'.
The results for the interim periods are unaudited and, in the opinion of management, include all adjustments necessary for a fair presentation of the results for each period. All such adjustments are of a normal recurring nature. This report should be read in conjunction with the consolidated financial statements and related notes for the year ended 31 December 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.
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Note 2. Non-current assets held for sale
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 Second Third Nine Nine quarter quarter quarter months months $ million 2023 2023 2022 2023 2022 gas low carbon energy 2,275 2,289 (2,956) 11,911 (1,743) oil production operations 3,427 2,568 6,965 9,312 18,033 customers products 1,549 555 2,586 4,784 8,098 other businesses corporate (500) (297) (1,093) (887) (26,840) 6,751 5,115 5,502 25,120 (2,452) Consolidation adjustment – UPII* (57) (30) (21) (109) (8) RC profit (loss) before interest and tax 6,694 5,085 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 (732) (2,855) 260 2,782 Profit (loss) before interest and tax 8,287 4,353 2,613 25,272 319 Finance costs 1,039 920 649 2,802 1,869 Net finance expense/(income) relating to pensions and other post-retirement benefits (61) (61) (16) (180) (53) Profit (loss) before taxation 7,309 3,494 1,980 22,650 (1,497) RC profit (loss) before interest and tax* US 1,467 2,244 3,954 6,786 9,553 Non-US 5,227 2,841 1,527 18,225 (12,013) 6,694 5,085 5,481 25,011 (2,460)
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Note 5. Sales and other operating revenues
Third Second Third Nine Nine quarter quarter quarter months months $ million 2023 2023 2022 2023 2022 By segment gas low carbon energy 10,313 10,428 8,053 38,627 29,462 oil production operations 6,225 5,777 8,599 18,155 26,261 customers products 42,908 38,051 47,831 119,841 145,551 other businesses corporate 672 590 552 2,000 1,520 60,118 54,846 65,035 178,623 202,794 Less: sales and other operating revenues between segments gas low carbon energy 367 840 2,785 1,743 6,354 oil production operations 5,747 5,236 7,589 17,244 23,378 customers products 508 (180) (276) 472 808 other businesses corporate 227 412 (74) 1,175 119 6,849 6,308 10,024 20,634 30,659 External sales and other operating revenues gas low carbon energy 9,946 9,588 5,268 36,884 23,108 oil production operations 478 541 1,010 911 2,883 customers products 42,400 38,231 48,107 119,369 144,743 other businesses corporate 445 178 626 825 1,401 Total sales and other operating revenues 53,269 48,538 55,011 157,989 172,135 By geographical area US 22,032 20,065 22,451 61,257 68,934 Non-US 43,382 38,492 45,111 128,224 142,239 65,414 58,557 67,562 189,481 211,173 Less: sales and other operating revenues between areas 12,145 10,019 12,551 31,492 39,038 53,269 48,538 55,011 157,989 172,135 Revenues from contracts with customers Sales and other operating revenues include the following in relation to revenues from contracts with customers: Crude oil 496 520 1,322 1,653 5,500 Oil products 35,486 31,218 40,036 96,845 115,054 Natural gas, LNG and NGLs 6,396 5,841 11,106 21,881 30,730 Non-oil products and other revenues from contracts with customers 2,765 2,750 2,267 7,387 6,437 Revenue from contracts with customers 45,143 40,329 54,731 127,766 157,721 Other operating revenues(a) 8,126 8,209 280 30,223 14,414 Total sales and other operating revenues 53,269 48,538 55,011 157,989 172,135Principally relates to commodity derivative transactions including sales of bp own production in trading books.
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Note 6. Depreciation, depletion and amortization
Third Second Third Nine Nine quarter quarter quarter months months $ million 2023 2023 2022 2023 2022 Total depreciation, depletion and amortization by segment gas low carbon energy 1,543 1,407 1,177 4,390 3,635 oil production operations 1,432 1,370 1,381 4,129 4,181 customers products 915 894 697 2,606 2,129 other businesses corporate 255 252 212 743 659 4,145 3,923 3,467 11,868 10,604 Total depreciation, depletion and amortization by geographical area US 1,479 1,338 1,180 4,071 3,422 Non-US 2,666 2,585 2,287 7,797 7,182 4,145 3,923 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 Second Third Nine Nine quarter quarter quarter months months $ million 2023 2023 2022 2023 2022 Results for the period Profit (loss) for the period attributable to bp shareholders 4,858 1,792 (2,163) 14,868 (13,290) Less: preference dividend — 1 — 1 1 Profit (loss) attributable to bp ordinary shareholders 4,858 1,791 (2,163) 14,867 (13,291) Number of shares (thousand)(a)(b) Basic weighted average number of shares outstanding 17,204,488 17,523,778 18,885,725 17,537,170 19,260,486 ADS equivalent(c) 2,867,414 2,920,629 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 17,900,984 18,885,725 17,914,383 19,260,486 ADS equivalent(c) 2,934,933 2,983,497 3,147,620 2,985,730 3,210,081 Shares in issue at period-end 17,061,004 17,379,366 18,566,848 17,061,004 18,566,848 ADS equivalent(c) 2,843,500 2,896,561 3,094,474 2,843,500 3,094,474Excludes treasury shares and includes certain shares that will be issued in the future under employee share-based payment plans. 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). One ADS is equivalent to six ordinary shares.
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Note 8. Dividends
Dividends payable
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 Second Third Nine Nine quarter quarter quarter months months 2023 2023 2022 2023 2022 Dividends paid per ordinary share cents 7.270 6.610 6.006 20.490 16.926 pence 5.732 5.309 5.168 16.592 13.683 Dividends paid per ADS (cents) 43.62 39.66 36.04 122.94 101.56
Note 9. Net debt
Net debt* 30 September 30 June 30 September $ million 2023 2023 2022 Finance debt(a) 48,810 49,738 46,560 Fair value (asset) liability of hedges related to finance debt(b) 3,440 2,836 4,746 52,250 52,574 51,306 Less: cash and cash equivalents 29,926 28,914 29,304 Net debt(c) 22,324 23,660 22,002 Total equity 87,676 85,603 73,333 Gearing* 20.3% 21.7% 23.1% The fair value of finance debt at 30 September 2023 was $43,387 million (30 June 2023 $45,580 million, 30 September 2022 $41,414 million). 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 (second quarter 2023 liability of $98 million and third quarter 2022 liability of $116 million) are not included in the calculation of net debt shown above as hedge accounting is not applied for these instruments. 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 (second quarter 2023 $1.7 billion, 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. BP Annual Report and Form 20-F 2022 has been filed with the Registrar of Companies in England and Wales. The report of the auditor on those accounts was unqualified, did not include a reference to any matters to which the auditor drew attention by way of emphasis without qualifying the report and did not contain a statement under section 498(2) or section 498(3) of the UK Companies Act 2006.
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Additional information
Capital expenditure*
Third Second Third Nine Nine quarter quarter quarter months months $ million 2023 2023 2022 2023 2022 Capital expenditure Organic capital expenditure* 3,597 3,233 3,191 10,325 8,609 Inorganic capital expenditure*(a) 6 1,081 3 1,217 352 3,603 4,314 3,194 11,542 8,961Third Second Third Nine Nine quarter quarter quarter months months $ million 2023 2023 2022 2023 2022 Capital expenditure by segment gas low carbon energy 1,055 887 958 2,955 2,642 oil production operations 1,644 1,478 1,386 4,642 3,848 customers products(a) 802 1,858 713 3,650 2,103 other businesses corporate 102 91 137 295 368 3,603 4,314 3,194 11,542 8,961 Capital expenditure by geographical area US 1,583 2,661 1,377 5,941 3,727 Non-US 2,020 1,653 1,817 5,601 5,234 3,603 4,314 3,194 11,542 8,961 Second quarter and nine months 2023 include $1.1 billion, net of adjustments, in respect of the TravelCenters of America acquisition.
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Adjusting items*
Third Second Third Nine Nine quarter quarter quarter months months $ million 2023 2023 2022 2023 2022 gas low carbon energy Gains on sale of businesses and fixed assets — 1 3 16 12 Net impairment and losses on sale of businesses and fixed assets(a) (224) (1,058) (6) (1,284) (523) Environmental and other provisions — — — — — Restructuring, integration and rationalization costs (1) 1 — — 5 Fair value accounting effects(b)(c) 1,816 1,222 (9,224) 6,972 (14,313) Other(d) (572) (110) 31 (738) 161 1,019 56 (9,196) 4,966 (14,658) oil production operations Gains on sale of businesses and fixed assets(e) 246 (31) 1,851 352 3,378 Net impairment and losses on sale of businesses and fixed assets (52) (140) (326) (184) (1,262) Environmental and other provisions 99 (44) 244 6 98 Restructuring, integration and rationalization costs — (1) 3 (1) (14) Fair value accounting effects — — — — — Other (2) 7 (18) (93) 37 291 (209) 1,754 80 2,237 customers products Gains on sale of businesses and fixed assets 18 2 10 21 302 Net impairment and losses on sale of businesses and fixed assets (242) (36) (85) (361) (532) Environmental and other provisions — (1) (1) (11) (36) Restructuring, integration and rationalization costs 1 1 (4) — 6 Fair value accounting effects(c) (198) (109) (59) (230) (498) Other (85) (98) — (245) (31) (506) (241) (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) (31) — (60) (16) Environmental and other provisions (8) (17) 67 (39) (25) Restructuring, integration and rationalization costs (3) — 6 (13) 16 Fair value accounting effects(c) (146) (48) (785) 51 (1,896) Rosneft — — — — (24,033) Gulf of Mexico oil spill (19) (18) (21) (46) (61) Other 2 (13) 44 (11) 40 (197) (127) (688) (118) (25,975) Total before interest and taxation 607 (521) (8,269) 4,102 (39,185) Finance costs(f) (96) (119) (68) (319) (256) Total before taxation 511 (640) (8,337) 3,783 (39,441) Taxation on adjusting items(g) (158) 160 988 (203) 1,998 Taxation – tax rate change effect of UK energy profits levy(h) — 232 (778) 232 (778) Total after taxation for period(i) 353 (248) (8,127) 3,812 (38,221) See Note 3 for further information. 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. For further information, including the nature of fair value accounting effects reported in each segment, see pages 3, 6 and 32. Third quarter and nine months 2023 include a $540 million impairment charge recognized through equity-accounted earnings relating to US offshore wind projects. 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. Includes the unwinding of discounting effects relating to Gulf of Mexico oil spill payables, the income statement impact associated withthe 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.
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. Second quarter and nine months 2023 include 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.
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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.
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 June 30 September $ million 2023 2023 2022 Net debt 22,324 23,660 22,002 Lease liabilities 10,879 10,961 7,895 Net partner (receivable) payable for leases entered into on behalf of joint operations (124) (136) 22 Net debt including leases 33,079 34,485 29,919 Total equity 87,676 85,603 73,333 Gearing including leases* 27.4% 28.7% 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 1,444During 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.
Working capital* reconciliation
Third Second Third Nine Nine quarter quarter quarter months months $ million 2023 2023 2022 2023 2022 Movements in inventories and other current and non-current assets and liabilities as per condensed group cash flow statement(a) (783) (742) 6,764 (5,280) 577 Adjusted for inventory holding gains (losses)* (Note 4) 1,593 (732) (2,868) 261 2,779 Adjusted for fair value accounting effects relating to subsidiaries 1,443 1,053 (10,068) 6,738 (16,561) Other adjusting items(b) (300) 558 645 (1,040) 2,094 Working capital release (build) after adjusting for net inventory gains (losses), fair value accounting effects and other adjusting items 1,953 137 (5,527) 679 (11,111) The movement in working capital includes outflows relating to the Gulf of Mexico oil spill on a pre-tax basis of $6 million and $1,222 million in the third quarter and nine months of 2023 respectively. For the same periods in 2022 the amount was an outflow of $29 million and $1,285 million respectively. Other adjusting items relate to the non-cash movement of US emissions obligations carried as a provision that will be settled by allowances held as inventory.
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Surplus cash flow* reconciliation
Third Second Third Nine Nine quarter quarter quarter months months $ million 2023 2023 2022 2023 2022 Sources: Net cash provided by operating activities 8,747 6,293 8,288 22,662 27,361 Cash provided from investing activities 150 109 621 1,065 1,996 Other(a) 503 (42) (31) 402 454 Cash inflow 9,400 6,360 8,878 24,129 29,811 Uses: Lease liability payments (663) (620) (478) (1,838) (1,448) Payments on perpetual hybrid bonds (258) (250) (180) (744) (489) Dividends paid – BP shareholders (1,249) (1,153) (1,140) (3,585) (3,270) – non-controlling interests (191) (67) (66) (326) (194) Total capital expenditure* (3,603) (4,314) (3,194) (11,542) (8,961) Net repurchase of shares relating to employee share schemes (225) (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) Cash outflow (6,293) (6,629) (5,382) (19,008) (15,731) Surplus cash flow 3,107 (269) 3,496 5,121 14,080 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.
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Adjusted earnings before interest, taxation, depreciation and amortization (adjusted EBITDA)*
Third Second Third Nine Nine quarter quarter quarter months months $ million 2023 2023 2022 2023 2022 Profit (loss) for the period 5,069 1,953 (1,984) 15,444 (12,518) Finance costs 1,039 920 649 2,802 1,869 Net finance (income) expense relating to pensions and other post-retirement benefits (61) (61) (16) (180) (53) Taxation 2,240 1,541 3,964 7,206 11,021 Profit before interest and tax 8,287 4,353 2,613 25,272 319 Inventory holding (gains) losses*, before tax (1,593) 732 2,868 (261) (2,779) RC profit (loss) before interest and tax 6,694 5,085 5,481 25,011 (2,460) Net (favourable) adverse impact of adjusting items*, before interest and tax (607) 521 8,269 (4,102) 39,185 Underlying RC profit before interest and tax 6,087 5,606 13,750 20,909 36,725 Add back: Depreciation, depletion and amortization 4,145 3,923 3,467 11,868 10,604 Exploration expenditure written off 74 241 190 365 318 Adjusted EBITDA 10,306 9,770 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 Second Third Nine Nine quarter quarter quarter months months $ million 2023 2023 2022 2023 2022 RC profit before interest and tax for customers products 1,549 555 2,586 4,784 8,098 Less: Adjusting items* gains (charges) (506) (241) (139) (826) (789) Underlying RC profit before interest and tax for customers products 2,055 796 2,725 5,610 8,887 By business: customers – convenience mobility 670 701 1,137 1,762 2,338 Castrol – included in customers 185 171 151 517 630 products – refining trading 1,385 95 1,588 3,848 6,549 Add back: Depreciation, depletion and amortization 915 894 697 2,606 2,129 By business: customers – convenience mobility 481 448 311 1,270 952 Castrol – included in customers 43 42 36 124 113 products – refining trading 434 446 386 1,336 1,177 Adjusted EBITDA for customers products 2,970 1,690 3,422 8,216 11,016 By business: customers – convenience mobility 1,151 1,149 1,448 3,032 3,290 Castrol – included in customers 228 213 187 641 743 products – refining trading 1,819 541 1,974 5,184 7,726
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Realizations* and marker prices
Third Second Third Nine Nine quarter quarter quarter months months 2023 2023 2022 2023 2022 Average realizations(a) Liquids* ($/bbl) US 63.95 60.53 82.23 62.44 81.05 Europe 90.76 75.14 94.21 80.59 104.12 Rest of World 78.34 79.35 101.82 80.05 98.93 BP Average 71.85 69.76 92.44 71.40 92.42 Natural gas ($/mcf) US 2.24 1.58 7.25 2.09 5.88 Europe(b) 11.22 12.46 36.72 17.20 32.73 Rest of World 5.38 5.53 9.85 6.11 8.74 BP Average(b) 4.88 4.91 10.41 5.66 9.18 Total hydrocarbons* ($/boe) US 45.39 40.84 66.82 43.77 63.19 Europe(b) 80.61 74.20 137.66 87.43 134.42 Rest of World 45.61 45.97 71.19 48.73 68.34 BP Average(b) 47.28 46.27 74.08 49.47 71.17 Average oil marker prices ($/bbl) Brent 86.75 78.05 100.84 82.07 105.51 West Texas Intermediate 82.54 73.56 91.63 77.36 98.46 Western Canadian Select 65.42 60.07 69.02 60.72 79.72 Alaska North Slope 87.95 78.26 98.84 81.74 102.34 Mars 82.99 73.17 89.54 76.80 96.01 Urals (NWE – cif) 73.62 54.56 71.24 58.20 78.58 Average natural gas marker prices Henry Hub gas price(c)($/mmBtu) 2.54 2.09 8.20 2.69 6.78 UK Gas – National Balancing Point (p/therm) 82.04 83.18 281.01 99.01 216.37 Based on sales of consolidated subsidiaries only – this excludes equity-accounted entities. 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. Henry Hub First of Month Index.
Exchange rates
Third Second Third Nine Nine quarter quarter quarter months months 2023 2023 2022 2023 2022 $/£ average rate for the period 1.27 1.25 1.18 1.24 1.25 $/£ period-end rate 1.22 1.26 1.12 1.22 1.12 $/€ average rate for the period 1.09 1.09 1.01 1.08 1.06 $/€ period-end rate 1.06 1.09 0.98 1.06 0.98 $/AUD average rate for the period 0.65 0.67 0.68 0.67 0.71 $/AUD period-end rate 0.64 0.66 0.65 0.64 0.65
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Legal proceedings
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 page 29 for the customers products businesses.
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 29 for the group.
We are unable to present reconciliations of forward-looking information for adjusted EBITDA for the group or resilient hydrocarbons, because without unreasonable efforts, we are unable to forecast accurately certain adjusting items required to calculate a meaningful comparable IFRS forward-looking financial measure. These items include inventory holding gains or losses, adjusting items and exploration expenditure written off that are difficult to predict in advance in order to include in an IFRS estimate.
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 26.
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.
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Glossary (continued)
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.
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
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Glossary (continued)
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 24.
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 27.
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 25.
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:
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 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.
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Glossary (continued)
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 25.
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 1. 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 , ARCO, Amoco, Aral and Thorntons, and also includes sites in India through our Jio-bp JV.
Solomon availability – See Refining availability definition.
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Glossary (continued)
Strategic convenience sites are retail sites, within the bp portfolio, which sell bp-branded vehicle energy (e.g. , Aral, Arco, Amoco, Thorntons, TravelCenters of America and bp pulse) and either carry one of the strategic convenience brands (e.g. M, 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 28 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.
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 34) after excluding net adjusting items and related taxation. See page 26 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.
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Glossary (continued)
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 1 for the group and pages 6-14 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.
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.
Working capital is movements in inventories and other current and non-current assets and liabilities as reported in the condensed group cash flow statement.
Change in working capital adjusted for inventory holding gains/losses, fair value accounting effects relating to subsidiaries and other adjusting items is a non-IFRS measure. It is calculated by adjusting for inventory holding gains/losses reported in the period; fair value accounting effects relating to subsidiaries reported within adjusting items for the period; and other adjusting items relating to the non-cash movement of US emissions obligations carried as a provision that will be settled by allowances held as inventory. This represents what would have been reported as movements in inventories and other current and non-current assets and liabilities, if the starting point in determining net cash provided by operating activities had been underlying replacement cost profit rather than profit for the period. The nearest equivalent measure on an IFRS basis for this is movements in inventories and other current and non-current assets and liabilities.
bp utilizes various arrangements in order to manage its working capital including discounting of receivables and, in the supply and trading business, the active management of supplier payment terms, inventory and collateral.
Trade marks
Trade marks of the bp group appear throughout this announcement. They include:
, Amoco, Aral, bp pulse, Castrol and Thorntons
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Cautionary statement
In order to utilize the ‘safe harbor’ provisions of the United States Private Securities Litigation Reform Act of 1995 (the ‘PSLRA’) and the general doctrine of cautionary statements, bp is providing the following cautionary statement:
The discussion in this results announcement contains certain forecasts, projections and forward-looking statements - that is, statements related to future, not past events and circumstances - with respect to the financial condition, results of operations and businesses of bp and certain of the plans and objectives of bp with respect to these items. These statements may generally, but not always, be identified by the use of words such as ‘will’, ‘expects’, ‘is expected to’, ‘aims’, ‘should’, ‘may’, ‘objective’, ‘is likely to’, ‘intends’, ‘believes’, ‘anticipates’, ‘plans’, ‘we see’ or similar expressions.
In particular, the following, among other statements, are all forward looking in nature: 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, and Adjusted EBITDA; 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.
This announcement contains inside information. The person responsible for arranging the release of this announcement on behalf of BP p.l.c. is Ben Mathews, Company Secretary.
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Contacts
London Houston Press Office David Nicholas Megan Baldino +44 (0) 7831 095541 +1 907 529 9029 Investor Relations Craig Marshall Graham Collins bp.com/investors +44 (0) 203 401 5592 +1 832 753 5116
BP p.l.c.’s LEI Code 213800LH1BZH3D16G760
End of Inside Information
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