Indicate by check mark whether the registrant files or will file annual reports under cover of Form 20-F or Form 40-F:
Form 20-F x Form 40-F ¨
Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(1): ¨
Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(7): ¨
THIS REPORT ON FORM 6-K SHALL BE DEEMED TO BE INCORPORATED BY REFERENCE IN THE PROSPECTUS INCLUDED IN THE REGISTRATION STATEMENT ON FORM F-3 (FILE NOS. 333-254751, 333-254751-01 AND 333-254751-02) OF BP p.l.c., BP CAPITAL MARKETS p.l.c. AND BP CAPITAL MARKETS AMERICA INC.; THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-67206) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-79399) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-103924) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-123482) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-123483) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-131583) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-131584) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-132619) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-146868) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-146870) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-146873) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-173136) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-177423) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-179406) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-186462) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-186463) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-199015) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-200794) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-200795) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-207188) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-207189) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-210316) OF BP p.l.c., THE REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-210318) OF BP p.l.c., REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333-253287) AND REGISTRATION STATEMENT ON FORM S-8 (FILE NO. 333- 254578) OF BP p.l.c., AND TO BE A PART THEREOF FROM THE DATE ON WHICH THIS REPORT IS FURNISHED, TO THE EXTENT NOT SUPERSEDED BY DOCUMENTS OR REPORTS SUBSEQUENTLY FILED OR FURNISHED.
(a)In this Form 6-K, references to the full year 2022 and full year 2021 refer to the full-year periods ended 31 December 2022 and 31 December 2021 respectively. References to the fourth quarter 2022 and fourth quarter 2021 refer to the three-month periods ended 31 December 2022 and 31 December 2021 respectively.
(b)This discussion should be read in conjunction with the consolidated financial statements and related notes provided elsewhere in this Form 6-K and with the information, including the consolidated financial statements and related notes, in bp’s Annual Report on Form 20-F for the year ended 31 December 2021.
Profit (loss) for the period attributable to bp shareholders
10,803
2,326
(2,487)
7,565
Inventory holding (gains) losses*, before tax
1,428
(472)
(1,351)
(3,655)
Taxation charge (credit) on inventory holding gains and losses
(362)
114
332
829
Replacement cost (RC) profit (loss)*
11,869
1,968
(3,506)
4,739
Net (favourable) adverse impact of adjusting items*, before tax
(9,660)
2,985
29,781
8,697
Taxation charge (credit) on adjusting items
2,598
(888)
1,378
(621)
Underlying RC profit*
4,807
4,065
27,653
12,815
Operating cash flow*
13,571
6,116
40,932
23,612
Capital expenditure*
(7,369)
(3,633)
(16,330)
(12,848)
Divestment and other proceeds(a)
614
2,265
3,123
7,632
Net cash issue (repurchase) of shares(b)
(3,240)
(1,725)
(9,996)
(3,151)
Finance debt
46,944
61,176
46,944
61,176
Net debt*(c)
21,422
30,613
21,422
30,613
Profit (loss) for the period attributable to bp shareholders divided by total equity (%)
(3.0)%
8.4%
Return on average capital employed (ROACE)* (%)
30.5%
13.3%
Adjusted earnings before interest, taxation, depreciation and amortization (adjusted EBITDA)*
60,747
37,315
Adjusted earnings before interest, depreciation and amortization (adjusted EBIDA)*
45,695
30,783
Announced dividend per ordinary share (cents per share)
6.610
5.460
24.082
21.630
Profit (loss) per ordinary share (cents)
59.43
11.75
(13.10)
37.57
Profit (loss) per ADS (dollars)
3.57
0.70
(0.79)
2.25
Underlying RC profit per ordinary share* (cents)
26.44
20.53
145.63
63.65
Underlying RC profit per ADS* (dollars)
1.59
1.23
8.74
3.82
(a)Divestment proceeds are disposal proceeds as per the condensed group cash flow statement. See page 5 for more information on divestment and other proceeds.
(b)Full year 2022 excludes the ordinary shares issued as non-cash consideration for the acquisition of the public units of BP Midstream Partners LP. See Note 8 for more information.
(c)See Note 10 for more information.
RC profit (loss), underlying RC profit (loss), net debt, ROACE, adjusted EBITDA, adjusted EBIDA, underlying RC profit per ordinary share and underlying RC profit per ADS are non-GAAP measures. Inventory holding (gains) losses and adjusting items are non-GAAP adjustments.
* For items marked with an asterisk throughout this document, definitions are provided in the Glossary on page 39.
•Profit for the quarter attributable to bp shareholders was $10.8 billion, compared with a loss of $2.2 billion for the third quarter 2022 and a profit of $2.3 billion for the fourth quarter 2021. The profit for the fourth quarter 2022 is adjusted by inventory holding losses net of tax of $1.1 billion and a gain for adjusting items* net of tax of $7.1 billion to derive the underlying replacement cost profit. Adjusting items include favourable fair value accounting effects* of $13.2 billion before tax, primarily due to a decrease in forward gas prices compared to the end of the third quarter.
•Underlying replacement cost profit for the quarter was $4.8 billion, compared with $8.2 billion for the previous quarter. Compared to the third quarter, the result was impacted by a below average gas marketing and trading result after the exceptional result in the third quarter, lower oil and gas realizations, a higher level of refinery turnaround and maintenance activity, and lower marketing margins and seasonally lower volumes. An underlying ETR* of 40% in the fourth quarter brings the full year underlying ETR* to 34%. The underlying replacement cost profit for the fourth quarter 2021 was $4.1 billion.
Finance debt reduced to $46.9 billion; net debt* reduced to $21.4 billion; further $2.75 billion share buyback announced
•Operating cash flow* in the quarter was $13.6 billion, compared with $6.1 billion for the same period of 2021.
•Capital expenditure* in the fourth quarter and full year was $7.4 billion and $16.3 billion respectively. Within this, inorganic spend was $3.5 billion in the fourth quarter and full year, including $3.0 billion for Archaea Energy, net of adjustments, and $0.5 billion for the earlier than expected completion of the acquisition of EDF Energy Services.
•During the fourth quarter, bp completed share buybacks of $3.2 billion. The $2.5 billion share buyback programme announced with the third quarter results was completed on 3 February 2023.
•In the fourth quarter, bp generated surplus cash flow* and intends to execute a $2.75 billion share buyback from surplus cash flow prior to announcing its first-quarter-2023 results. bp has now announced share buybacks from surplus cash flow equivalent to 60% of cumulative surplus cash flow since the start of 2021. See page 34 for the components of our sources of cash and uses of cash in the fourth quarter and full year 2022.
•Finance debt at the end of the quarter was $46.9 billion, compared with $61.2 billion at the end of the fourth quarter 2021. Net debt fell for the eleventh successive quarter to reach $21.4 billion at the end of the fourth quarter. Net debt at the end of fourth quarter 2021 was $30.6 billion.
•A resilient dividend remains bp’s first priority within its disciplined financial frame. It is underpinned by a cash balance point* of $40 per barrel Brent, $11 per barrel RMM and $3 per mmBtu Henry Hub (all 2021 real).
•For the fourth quarter, bp has announced a dividend per ordinary share of 6.610 cents an increase of around 10%. This increase is underpinned by strong underlying performance and supported by the confidence we have in delivering higher adjusted EBITDA* as a result of our updated investment plans.
•bp is committed to maintaining a strong investment grade credit rating, targeting further progress within an 'A' grade credit rating. For 2023 bp intends to allocate 40% of surplus cash flow to further strengthening the balance sheet.
•bp continues to focus on disciplined investment allocation. For 2023 bp expects capital expenditure of $16-18 billion and for 2024-30 now expects capital expenditure in a range of $14-18 billion including inorganic capital expenditure*.
•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.
•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 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 a separate announcement, bp has today provided an update on the significant progress made in executing its transformation to an Integrated Energy Company (IEC) since outlining its new strategy.
•In resilient hydrocarbons bp has accelerated its biogas strategy - part of its bioenergy Transition Growth Engine – completing the acquisition of Archaea Energy a leading US biogas company. Delivering on its focus on cost and efficiency, in 2022 bp delivered its lowest upstream unit production cost* since 2006 and highest upstream plant reliability* on record.
•In convenience and mobility bp continues to make strategic progress, announcing an exclusive agreement in the UK with Marks and Spencer (M&S) to install fast(a) charge points to around 70 of their stores, adding up to 900 charge points within the next two years; and increasing the number of EV charge points by over 65% versus 2021.
•In low carbon energy bp has continued to make rapid progress building its portfolio of green hydrogen* projects, signing memoranda of understanding (MoUs) with both Mauritania and Egypt to explore the potential for large scale green hydrogen developments.
(a)“fast charging” includes rapid charging ≥50kW and ultra-fast charging ≥150kW.
The commentary above contains forward-looking statements and should be read in conjunction with the cautionary statement on page 45.
At 31 December 2021, the group's reportable segments were gas & low carbon energy, oil production & operations, customers & products and Rosneft. The group has ceased to report Rosneft as a separate segment in the group’s financial reporting for 2022. From the first quarter of 2022, the group's reportable segments are gas & low carbon energy, oil production & operations and customers & products. For more information see Note 1 Basis of preparation - Investment in Rosneft. For the period from 1 January 2022 to 27 February 2022, net income from Rosneft is classified as an adjusting item. As the circumstances leading to this classification were not present prior to first quarter 2022 the net income from Rosneft has not been classified as an adjusting item for comparative periods.
In addition to the highlights on page 4:
•Profit attributable to bp shareholders in the fourth quarter was $10.8 billion compared with $2.3 billion in the same period of 2021. Loss attributable to bp shareholders in the full year was $2.5 billion compared with a profit of $7.6 billion in the same period of 2021.
–The increase in the underlying replacement cost profit for both periods reflects higher gas and liquids realizations and higher refining margins, partially offset by higher tax and the absence of bp share of earnings from Rosneft. The fourth quarter result also reflects an adverse impact of turnaround and maintenance activity, and the year a favourable impact of strong trading performance.
–Adjusting items* in the fourth quarter and full year were a favourable pre-tax impact of $9.7 billion and an adverse pre-tax impact of $29.8 billion respectively, compared with an adverse pre-tax impact of $3.0 billion and $8.7 billion in the same periods of 2021.
◦As a result of bp's two nominated directors stepping-down from the Rosneft board on 27 February 2022, bp determined that it no longer meets the criteria set out under IFRS for having "significant influence" over Rosneft. bp therefore no longer equity accounts for its interest in Rosneft from that date, treating it prospectively as a financial asset measured at fair value. Within the full year result, the loss of significant influence and an impairment assessment led to a net pre-tax charge of $24.0 billion classified as an adjusting item, reducing equity by $14.4 billion. 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 in the full year result, reducing equity by $1.2 billion. See Note 1 for further information.
◦Adjusting items for the fourth quarter and full year 2022 also include increases in pre-tax fair value accounting effects* of $13.2 billion and decreases of $3.5 billion respectively, compared with a decreasing pre-tax impact of $0.9 billion and $8.1 billion in the same periods of 2021. 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 fourth quarter also includes net impairment charges of $3.6 billion principally as a result of expected portfolio changes in our oil production & operations segment, the annual review of price assumptions used for investment appraisal and value-in-use impairment testing and the annual review of discount rates used for impairment tests. The full year 2022 also includes a non-taxable gain of $2.0 billion arising from the contribution of bp's Angolan business to Azule Energy.
•The effective tax rate (ETR) on the profit or loss for the fourth quarter and full year was 34% and 109% respectively, compared with 36% and 44% for the same periods in 2021. The ETR on RC profit or loss* for the fourth quarter and full year was 33% and 117% respectively, compared with 38% and 51% for the same periods in 2021. Excluding adjusting items, the underlying ETR* for the fourth quarter and full year was 40% and 34% respectively, compared with 34% and 32% for the same periods a year ago. The higher underlying ETR for the fourth quarter and full year reflects the UK Energy Profits Levy on North Sea profits and the absence of equity-accounted earnings from Rosneft, for the full year this is partly offset by changes in the geographical mix of profits. ETR on RC profit or loss and underlying ETR are non-GAAP measures.
•Operating cash flow* for the fourth quarter and full year 2022 was $13.6 billion and $40.9 billion respectively, compared with $6.1 billion and $23.6 billion for the same periods in 2021 primarily as an outcome of higher underlying profits and working capital movements.
•Capital expenditure* in the fourth quarter and full year 2022 was $7.4 billion and $16.3 billion respectively, compared with $3.6 billion and $12.8 billion in the same periods of 2021, higher as a result of acquisitions completed during the fourth quarter 2022.
•Total divestment and other proceeds for the fourth quarter and full year were $0.6 billion and $3.1 billion respectively, compared with $2.3 billion and $7.6 billion for the same periods in 2021. Other proceeds for the full year 2022 consist of $0.6 billion of proceeds from the disposal of a loan note related to the Alaska divestment. See page 34 for further information.
•Finance debt at the end of the fourth quarter was $46.9 billion, compared to $46.6 billion at the end of the third quarter 2022 and $61.2 billion at the end of the fourth quarter 2021. At the end of the fourth quarter, net debt* was $21.4 billion, compared with $22.0 billion at the end of the third quarter 2022 and $30.6 billion at the end of the fourth quarter 2021.
Analysis of RC profit (loss) before interest and tax and reconciliation to profit (loss) for the period
Fourth
Fourth
quarter
quarter
Year
Year
$ million
2022
2021
2022
2021
RC profit (loss) before interest and tax
gas & low carbon energy
16,439
1,911
14,696
2,133
oil production & operations
1,688
3,212
19,721
10,501
customers & products
771
(426)
8,869
2,208
other businesses & corporate(a)
103
(369)
(26,737)
(348)
Of which:
other businesses & corporate excluding Rosneft
103
(924)
(2,704)
(2,777)
Rosneft
—
555
(24,033)
2,429
Consolidation adjustment – UPII*
147
(7)
139
(67)
19,148
4,321
16,688
14,427
Finance costs and net finance expense relating to pensions and other post-retirement benefits
(818)
(751)
(2,634)
(2,855)
Taxation on a RC basis
(6,103)
(1,350)
(16,430)
(5,911)
Non-controlling interests
(358)
(252)
(1,130)
(922)
RC profit (loss) attributable to bp shareholders*
11,869
1,968
(3,506)
4,739
Inventory holding gains (losses)*
(1,428)
472
1,351
3,655
Taxation (charge) credit on inventory holding gains and losses
362
(114)
(332)
(829)
Profit (loss) for the period attributable to bp shareholders
10,803
2,326
(2,487)
7,565
Analysis of underlying RC profit (loss) before interest and tax
Fourth
Fourth
quarter
quarter
Year
Year
$ million
2022
2021
2022
2021
Underlying RC profit (loss) before interest and tax
gas & low carbon energy
3,148
2,211
16,063
7,528
oil production & operations
4,428
4,024
20,224
10,292
customers & products
1,902
611
10,789
3,252
other businesses & corporate(a)
(306)
210
(1,171)
1,337
Of which:
other businesses & corporate excluding Rosneft
(306)
(535)
(1,171)
(1,383)
Rosneft
—
745
—
2,720
Consolidation adjustment – UPII
147
(7)
139
(67)
9,319
7,049
46,044
22,342
Finance costs and net finance expense relating to pensions and other post-retirement benefits
(649)
(494)
(2,209)
(2,073)
Taxation on an underlying RC basis
(3,505)
(2,238)
(15,052)
(6,532)
Non-controlling interests
(358)
(252)
(1,130)
(922)
Underlying RC profit attributable to bp shareholders*
4,807
4,065
27,653
12,815
Reconciliations of underlying RC profit attributable to bp shareholders to the nearest equivalent IFRS measure are provided on page 3 for the group and on pages 8-17 for the segments.
(a)From first quarter 2022 the results of Rosneft, previously reported as a separate segment, are also included in other businesses & corporate. Comparative information for 2021 has been restated to reflect the changes in reportable segments. For more information see Note 1 Basis of preparation - Investment in Rosneft.
(b)Reflecting higher volumes and lower costs including impact of conversion to equity-accounted entities.
Reserves replacement ratio*
The organic reserves replacement ratio (RRR) on a combined basis of subsidiaries and equity-accounted entities was 20% for the year (2021 50%). The decrease is largely due to price related reserves reductions in our production-sharing agreements*. The announced exit from Russia is treated as a divestment and therefore impacts only total RRR, not organic.
Outlook & Guidance
Macro outlook
•In the first quarter, bp expects oil prices to remain supported by recovering Chinese demand, ongoing uncertainty around the level of Russian exports and low inventory levels.
•bp expects the outlook for global gas prices during the first quarter to remain dependent on weather in the Northern Hemisphere and the pace of Chinese demand recovery.
•bp expects industry refining margins to remain elevated in the first quarter due to sanctioning of Russian crude and product.
1Q23 guidance
•Looking ahead, we expect first-quarter 2023 reported upstream* production to be broadly flat compared to fourth quarter 2022.
•In our customers business, we expect seasonally lower volumes and in Castrol base oil prices to remain high, although lower than the fourth quarter 2022. In refining, we expect margins to remain elevated and a lower level of turnaround activity.
2023 guidance
In addition to the guidance on page 4:
•bp expects both reported and underlying upstream production to be broadly flat compared with 2022. Within this, bp expects underlying production* from oil production & operations to be slightly higher and production from gas & low carbon energy to be lower. bp expects the start-up of Mad Dog Phase 2 in the second quarter of 2023 and first gas from the Tangguh expansion and GTA Phase 1 Tortue projects in the fourth quarter of 2023.
•bp expects the other businesses & corporate underlying annual charge to be in a range of $1.1-1.3 billion for 2023. The charge may vary from quarter to quarter.
•bp expects the depreciation, depletion and amortization to be slightly above 2022.
•The underlying ETR* for 2023 is expected to be around 40% but 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.
•bp expects capital expenditure* of $16-18 billion in 2023 including inorganic capital expenditure*.
•Having realized $15.9 billion of divestment and other proceeds since the second quarter of 2020, bp now expects 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 expects Gulf of Mexico oil spill payments for the year to be around $1.3 billion pre-tax including $1.2 billion pre-tax to be paid during the second quarter.
•Against the authority granted at bp's 2022 annual general meeting to repurchase up to 1.95 billion shares, bp has repurchased 1.11 billion shares.
•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.
The commentary above contains forward-looking statements and should be read in conjunction with the cautionary statement on page 45.
•The replacement cost profit before interest and tax for the fourth quarter and full year was $16,439 million and $14,696 million respectively, compared with $1,911 million and $2,133 million for the same periods in 2021. The fourth quarter and full year is adjusted by a favourable impact of net adjusting items* of $13,291 million and adverse impact of $1,367 million respectively to derive the underlying replacement cost profit, compared with adverse impacts of net adjusting items of $300 million and $5,395 million for the same periods in 2021.
•After adjusting items, the underlying replacement cost profit before interest and tax* for the fourth quarter and full year was $3,148 million and $16,063 million respectively, compared with $2,211 million and $7,528 million for the same periods in 2021. Adjusting items include favourable fair value accounting effects* of $12,502 million for the quarter and an adverse effect of $1,811 million for the full year. The adjusting items for the fourth quarter primarily arose from a significant decrease in forward gas prices during the quarter. 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.
•The underlying replacement cost profit for the fourth quarter, compared with the same period in 2021, reflects higher realizations, partially offset by lower production and a lower gas marketing and trading result. For the full year the result reflects higher realizations, higher production and an exceptional gas marketing and trading result.
Operational update
•Reported production for the quarter was 956mboe/d, 1.8% lower than the same period in 2021. Underlying production* was 2.4% lower, mainly due to base decline in Trinidad.
•Reported production for the full year was 957mboe/d, 4.9% higher than the same period in 2021. Underlying production for the full year was 4.9% higher due to the ramp-up of major projects*.
•Renewables pipeline* at the end of the quarter was 37.2GW (bp net). The renewables pipeline increased by 10.3GW during the quarter due to additions to the renewables pipeline in support of hydrogen in Australia. The renewables pipeline increased by 14.1GW for the full year, primarily as a result of bp and its partner EnBW being awarded a lease option off the east coast of Scotland to develop an offshore wind project (1.45GW bp net) in the first quarter of 2022, net additions to Lightsource bp's pipeline, and the additions to the renewables pipeline in the fourth quarter in support of hydrogen in Australia.
Strategic progress
gas
•On 23 December the government of Indonesia granted a 20-year extension, to 2055, of the Tangguh production-sharing contract* (Tangguh PSC) to bp (40.22% and operator), and its Tangguh PSC partners.
•On 29 November bp announced its Cassia C development offshore Trinidad had safely delivered first gas. Cassia C is bp Trinidad and Tobago’s (bp 70%) first offshore compression platform and its biggest offshore facility.
•On 28 November bp was awarded two exploration blocks in the Mediterranean sea, offshore Egypt by the Egyptian Natural Gas Holding Company. The Northwest Abu Qir Offshore Area (bp 82.75% operator, Wintershall-Dea 17.25%) is located west of the recently awarded North King Mariout block (bp 100%) and north of the Raven field. The Bellatrix-Seti East block (bp 50%, Eni 50% operator) is located west of the Atoll field and North Tabya blocks.
•On 8 December Trinidad's Ministry of Energy and Energy Industries announced that it had reached agreement with the Atlantic LNG shareholders, including bp, on substantial commercial terms for the consolidation of its operations into a single entity which is a key milestone towards unlocking the energy future for Trinidad and Tobago. The new structure is expected to be effective in October 2024 and will enable increased focus on operational efficiency and reliability and underpin future upstream investments.
•On 14 November bp began lifting cargoes of LNG from Mozambique’s first LNG project. bp has a long-term agreement to purchase 100% of the LNG output from the facility that has the capacity to produce up to 3.4 million tonnes of LNG per year.
low carbon energy
•On 8 November and 8 December bp signed memoranda of understanding with the governments of Mauritania and Egypt, respectively to explore the potential for establishing green hydrogen* production facilities in the countries.
•Lightsource bp brought 2.7GW to FID (1.34GW bp net) in full year 2022, an increase of 32% compared with 2.0GW (1.0GW bp net) in 2021, and divested 0.9GW of projects (0.45GW bp net) during the year, resulting in $0.1 billion of gains on disposal recognized in bp's share of equity-accounted earnings.
•On 9 December bp announced it will partner with Shell and Lightsource bp to develop a 148 megawatt-peak solar project in Trinidad and Tobago following approval by the country's government. It is the country’s first commercial-scale renewable energy project.
•On 14 December bp agreed with its Flat Ridge 2 joint venture partner to purchase their 50% ownership in that wind farm. bp now owns 100%, adding an additional 235MW of capacity to bp’s renewable portfolio.
Net (favourable) adverse impact of adjusting items
(13,291)
300
1,367
5,395
Underlying RC profit before interest and tax
3,148
2,211
16,063
7,528
Taxation on an underlying RC basis
(1,163)
(509)
(4,367)
(1,677)
Underlying RC profit before interest
1,985
1,702
11,696
5,851
Fourth
Fourth
quarter
quarter
Year
Year
$ million
2022
2021
2022
2021
Depreciation, depletion and amortization
Total depreciation, depletion and amortization
1,373
1,265
5,008
4,464
Exploration write-offs
Exploration write-offs
(6)
2
2
43
Adjusted EBITDA*(a)
Total adjusted EBITDA
4,515
3,478
21,073
12,035
Capital expenditure*
gas
1,032
928
3,227
3,180
low carbon energy(b)(c)
577
109
1,024
1,561
Total capital expenditure
1,609
1,037
4,251
4,741
(a)A reconciliation to RC profit before interest and tax is provided on page 36.
(b)Full year 2021 includes $712 million in respect of the remaining payment to Equinor for our investment in our strategic US offshore wind partnership and $326 million as a lease option fee deposit paid to The Crown Estate in connection with our participation in the UK Round 4 Offshore Wind Leasing together with our partner EnBW.
(c)Fourth quarter and full year 2022 include $504 million in respect of the acquisition of EDF Energy Services. Power trading is reported under low carbon energy.
Fourth
Fourth
quarter
quarter
Year
Year
2022
2021
2022
2021
Production (net of royalties)(d)
Liquids* (mb/d)
121
122
118
113
Natural gas (mmcf/d)
4,844
4,941
4,866
4,632
Total hydrocarbons* (mboe/d)
956
974
957
912
Of which equity-accounted entities:
Liquids (mb/d)
2
3
2
3
Natural gas (mmcf/d)
—
—
—
—
Total hydrocarbons (mboe/d)
2
3
2
3
Average realizations*(e)
Liquids ($/bbl)
80.50
71.63
89.86
63.60
Natural gas ($/mcf)
9.40
6.94
8.91
5.11
Total hydrocarbons* ($/boe)
57.60
43.68
56.34
33.75
(d)Includes bp’s share of production of equity-accounted entities in the gas & low carbon energy segment.
(e)Realizations are based on sales by consolidated subsidiaries only – this excludes equity-accounted entities.
•The replacement cost profit before interest and tax for the fourth quarter and full year was $1,688 million and $19,721 million respectively, compared with $3,212 million and $10,501 million for the same periods in 2021. The fourth quarter and full year is adjusted by an adverse impact of net adjusting items* of $2,740 million and $503 million respectively to derive the underlying replacement cost profit, compared with an adverse impact of net adjusting items of $812 million and a favourable impact of $209 million for the same periods in 2021. Adjusting items in the fourth quarter principally relate to impairments as a result of expected portfolio changes. See Note 4 and page 32 for more information.
•After adjusting items, the underlying replacement cost profit before interest and tax* for the fourth quarter and full year was $4,428 million and $20,224 million respectively, compared with $4,024 million and $10,292 million for the same periods in 2021.
•The underlying replacement cost profit for the fourth quarter compared to the same quarter in 2021, reflects higher oil and gas realizations, partly offset by the impact of portfolio changes. For the full year the result reflects primarily higher realizations.
Operational update
•Reported production for the quarter was 1,309mboe/d, 3.6% lower than the fourth quarter of 2021. Underlying production* for the quarter was flat compared with the fourth quarter of 2021.
•Reported production for the full year was 1,297mboe/d, 0.8% lower than the same period of 2021. Underlying production for the full year was 2.1% higher compared with the same period of 2021 reflecting bpx energy performance, major projects* and reduced weather impacts in the US Gulf of Mexico partly offset by base performance.
•Progressed operational performance in upstream* in 2022, delivering the highest bp-operated hydrocarbon plant reliability* on record at 96%.
Strategic Progress
•On 16 December bp was awarded operatorship of the Bumerangue block, in the Santos Pre Salt Basin, in Brazil.
•On 7 November the National Agency for Petroleum, Gas and Biofuels (ANPG), ExxonMobil Angola and the Angola Block 15 partners announced a new discovery at the Bavuca South-1 exploration well. Azule Energy, the bp and ENI 50:50 joint venture, owns 42% of block 15.
•In the Permian, methane flaring intensity averaged <0.5% in 2022, the lowest recorded in BPX Energy.
Fourth
Fourth
quarter
quarter
Year
Year
$ million
2022
2021
2022
2021
Profit before interest and tax
1,686
3,212
19,714
10,509
Inventory holding (gains) losses*
2
—
7
(8)
RC profit before interest and tax
1,688
3,212
19,721
10,501
Net (favourable) adverse impact of adjusting items
(a)A reconciliation to RC profit before interest and tax is provided on page 36.
Fourth
Fourth
quarter
quarter
Year
Year
2022
2021
2022
2021
Production (net of royalties)(b)
Liquids* (mb/d)
966
1,004
952
978
Natural gas (mmcf/d)
1,989
2,053
1,998
1,903
Total hydrocarbons* (mboe/d)
1,309
1,358
1,297
1,307
Of which equity-accounted entities:
Liquids (mb/d)
246
140
176
140
Natural gas (mmcf/d)
426
471
436
468
Total hydrocarbons (mboe/d)
320
221
251
221
Average realizations*(c)
Liquids ($/bbl)
80.43
71.07
89.62
62.57
Natural gas(d) ($/mcf)
10.20
8.73
10.46
5.49
Total hydrocarbons(d) ($/boe)
74.60
66.19
82.23
55.65
(b)Includes bp’s share of production of equity-accounted entities in the oil production & operations segment. Full year 2022, fourth quarter and full year 2021 include bp’s share of production of Russia joint ventures.
(c)Realizations are based on sales by consolidated subsidiaries only – this excludes equity-accounted entities.
(d)Realizations calculation methodology has been changed to reflect gas price fluctuations within the North Sea region. All comparatives are restated. There is no impact on financial results.
•The replacement cost profit before interest and tax for the fourth quarter and full year was $771 million and $8,869 million respectively, compared with a loss of $426 million and a profit of $2,208 million for the same periods in 2021. The fourth quarter and full year is adjusted by an adverse impact of net adjusting items* of $1,131 million and $1,920 million respectively to derive the underlying replacement cost profit, mainly relating to impairment charges (see Note 4), compared with an adverse impact of net adjusting items of $1,037 million and $1,044 million for the same periods in 2021.
•After adjusting items, the underlying replacement cost profit before interest and tax* for the fourth quarter and full year was $1,902 million and $10,789 million respectively, compared with a profit of $611 million and $3,252 million for the same periods in 2021.
•The customers & products result for the fourth quarter and full year were higher than the same periods in 2021. This reflects a stronger performance in refining and oil trading.
•customers – the convenience and mobility results, excluding Castrol, for the fourth quarter and full year were higher compared with the same periods in 2021. The benefits of a stronger convenience, retail fuels and aviation performance were partially offset by inflationary cost pressures. The full year result also included higher midstream performance, including biofuels, and adverse foreign exchange impacts.
Castrol results for the fourth quarter and full year were lower than the same periods in 2021, due to higher input costs, ongoing COVID restrictions, notably in China, and adverse foreign exchange impacts.
•products – the products results for the fourth quarter and full year were higher compared with the same periods in 2021. In refining, the fourth quarter and full year results benefited from higher realized margins, partially offset by higher energy costs, and turnaround and maintenance activity. In oil trading the fourth quarter and full year results were higher compared to the same period in 2021. The full year result benefited from an exceptionally strong oil trading performance in the first half of 2022.
Operational update
•Utilization for the full year was similar to 2021, however the fourth quarter was lower compared to the same period in 2021, primarily due to the bp-Husky Toledo refinery shutdown and a higher level of maintenance activity. bp-operated refining availability* for the fourth quarter and full year was 95.0% and 94.5% respectively, compared with 95.4% and 94.8% for the same periods in 2021.
Strategic progress
•Strategic convenience sites* grew to 2,400, an increase of more than 250 compared to 2021.
•In December, bp announced an exclusive agreement in the UK with its convenience partner M&S for bp pulse to install fast(a) charge points in around 70 of their stores, with initial ambition to add up to 900 charge points within the next two years. This follows bp’s announcement in October that its strategic partnership with REWE in Germany has been expanded to include the installation of fast(a) charge points at up to 180 of their sites.
•EV charge points* installed and energy sold grew by more than 65% and around 150% respectively, compared to 2021, with charge points now at around 22,000. In addition, we continued to build momentum in fleets. In October, bp announced plans to establish a bp pulse Gigahub network, a series of large, EV fast(a) charging hubs designed to serve ride-hail and taxi fleets, near US airports and high-demand locations, with an initial location near Los Angeles Airport in collaboration with Hertz.
•In November, Castrol announced an investment in Ki Mobility solutions (KMS) to create a co-branded service and maintenance network in India, supported by KMS’s digitally integrated multi-brand service platform. The investment supports Castrol's aim to grow its presence in service and maintenance for both EV and non-EV vehicles.
•In December, bp completed its purchase of Archaea Energy Inc., a leading provider of renewable natural gas, marking a milestone in the growth of bp’s strategic bioenergy business. Bioenergy is one of five strategic transition growth engines that bp intends to grow rapidly through this decade.
•In November, bp announced its Cherry Point refinery in the US had doubled its renewable diesel production capacity compared to the fourth quarter in 2021. The refinery now has the capability to co-process more than 7,000 barrels a day of renewable diesel.
•Following a fire at the bp-Husky Toledo refinery in Ohio, US, the refinery remains shut down. bp continues to work with Cenovus Energy, its partner in the facility, on the announced sale of bp’s 50% interest in the refinery to Cenovus Energy.
(•)“fast charging” includes rapid charging ≥50kW and ultra-fast charging ≥150kW.
(e)The RMM in the quarter is calculated based on bp’s current refinery portfolio. On a comparative basis, the fourth quarter and full year 2021 RMM would be $15.3/bbl and $13.6/bbl respectively.
Other businesses & corporate comprises innovation & engineering, bp ventures, Launchpad, regions, corporates & solutions, our corporate activities & functions and any residual costs of the Gulf of Mexico oil spill. From first quarter 2022 the results of Rosneft, previously reported as a separate segment, are also included in other businesses & corporate. Comparative information for 2021 has been restated to reflect the changes in reportable segments. For more information see Note 1 Basis of Preparation - Investment in Rosneft.
Financial results
•The replacement cost result before interest and tax for the fourth quarter and full year was a profit of $103 million and a loss of $26,737 million respectively, compared with a loss of $369 million and $348 million for the same periods in 2021. The fourth quarter and full year is adjusted by a favourable impact of net adjusting items* of $409 million and an adverse impact of $25,566 million respectively to derive the underlying replacement cost profit, compared with an adverse impact of net adjusting items of $579 million and $1,685 million for the same periods in 2021. The adjusting items for the full year of 2022 mainly relate to Rosneft. Fair value accounting effects* for the fourth quarter and full year had a favourable impact of $515 million and an adverse impact of $1,381 million respectively, compared with an adverse impact of $212 million and $849 million for the same periods in 2021.
•After adjusting items, the underlying replacement cost loss before interest and tax* for the fourth quarter and full year was $306 million and $1,171 million respectively, compared with a profit of $210 million and $1,337 million for the same periods in 2021.
•For other businesses & corporate excluding Rosneft, after excluding adjusting items, the underlying replacement cost loss before interest and tax for the fourth quarter and full year was $306 million and $1,171 million respectively, compared with $535 million and $1,383 million for the same periods in 2021.
Fourth
Fourth
quarter
quarter
Year
Year
$ million
2022
2021
2022
2021
Profit (loss) before interest and tax
103
(301)
(26,737)
(89)
Inventory holding (gains) losses*
—
(68)
—
(259)
RC profit (loss) before interest and tax
103
(369)
(26,737)
(348)
Net (favourable) adverse impact of adjusting items(a)
(409)
579
25,566
1,685
Underlying RC profit (loss) before interest and tax
(306)
210
(1,171)
1,337
Taxation on an underlying RC basis
43
55
439
25
Underlying RC profit (loss) before interest
(263)
265
(732)
1,362
(a)Includes fair value accounting effects relating to the hybrid bonds that were issued on 17 June 2020. See page 40 for more information.
other businesses & corporate (excluding Rosneft)
Strategic progress
•We have taken the decision to no longer seek new companies for bp's Launchpad accelerator, with our focus now to scale and build businesses within our 5 transition growth engines - bioenergy, convenience, EV charging, renewables and hydrogen.
•In December, bp ventures made a $20-million AUD investment in 5B Holdings Pty Ltd, an Australian renewable company with technology that enables rapid deployment of solar power at scale.
•On 2 February 2023, bp and Chubu Electric signed a memorandum of understanding to explore opportunities for decarbonisation in Japan and the wider Asia region, including plans for a feasibility study for a carbon capture, utilization, and storage (CCUS) hub in the Nagoya port area.
Fourth
Fourth
quarter
quarter
Year
Year
$ million
2022
2021
2022
2021
Profit (loss) before interest and tax
103
(924)
(2,704)
(2,777)
Inventory holding (gains) losses*
—
—
—
—
RC profit (loss) before interest and tax
103
(924)
(2,704)
(2,777)
Net (favourable) adverse impact of adjusting items
(409)
389
1,533
1,394
Underlying RC profit (loss) before interest and tax
Items that may be reclassified subsequently to profit or loss
Currency translation differences(a)
2,142
(619)
(3,786)
(921)
Exchange (gains) losses on translation of foreign operations reclassified to gain or loss on sale of businesses and fixed assets(b)
(32)
36
10,759
36
Cash flow hedges and costs of hedging
584
408
763
(259)
Share of items relating to equity-accounted entities, net of tax
392
104
402
44
Income tax relating to items that may be reclassified
(108)
(24)
(334)
65
2,978
(95)
7,804
(1,035)
Items that will not be reclassified to profit or loss
Remeasurements of the net pension and other post-retirement benefit liability or asset(c)
(1,508)
1,306
340
4,416
Cash flow hedges that will subsequently be transferred to the balance sheet
1
—
(4)
1
Income tax relating to items that will not be reclassified
538
(434)
68
(1,317)
(969)
872
404
3,100
Other comprehensive income
2,009
777
8,208
2,065
Total comprehensive income
13,170
3,355
6,851
10,552
Attributable to
bp shareholders
12,760
3,095
5,782
9,654
Non-controlling interests
410
260
1,069
898
13,170
3,355
6,851
10,552
(a)Fourth quarter 2022 is principally affected by movements in the Pound Sterling against the US dollar. Full year 2022 is principally affected by movements in the Russian rouble and Pound Sterling against the US dollar.
(b)See Note 1 Basis of preparation - Investment in Rosneft.
(c)See Note 1 Basis of preparation - Pensions and other post-retirement benefits for further information.
Cash flow hedges transferred to the balance sheet, net of tax
1
—
—
1
Issue of ordinary share capital(b)
820
—
—
820
Repurchase of ordinary share capital
(10,493)
—
—
(10,493)
Share-based payments, net of tax
847
—
—
847
Issue of perpetual hybrid bonds
(4)
374
—
370
Payments on perpetual hybrid bonds
15
(544)
—
(529)
Transactions involving non-controlling interests, net of tax
(513)
—
(144)
(657)
At 31 December 2022
67,553
13,390
2,047
82,990
bp shareholders’
Non-controlling interests
Total
$ million
equity
Hybrid bonds
Other interest
equity
At 1 January 2021
71,250
12,076
2,242
85,568
Total comprehensive income
9,654
507
391
10,552
Dividends
(4,316)
—
(311)
(4,627)
Cash flow hedges transferred to the balance sheet, net of tax
(10)
—
—
(10)
Repurchase of ordinary share capital
(3,151)
—
—
(3,151)
Share-based payments, net of tax
632
—
—
632
Share of equity-accounted entities’ changes in equity, net of tax
556
—
—
556
Issue of perpetual hybrid bonds
(26)
950
—
924
Payments on perpetual hybrid bonds
(7)
(492)
—
(499)
Transactions involving non-controlling interests, net of tax
881
—
(387)
494
At 31 December 2021
75,463
13,041
1,935
90,439
(a)In 2022 $9.2 billion of the opening foreign currency translation reserve has been moved to the profit and loss account reserve as a result of bp's decision to exit its shareholding in Rosneft and its other businesses with Rosneft in Russia. For more information see Note 1.
(b)Relates to ordinary shares issued as non-cash consideration for the acquisition of the public units of BP Midstream Partners LP.
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 2021 included in BP Annual Report and Form 20-F 2021.
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. 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 2022 which are the same as those used in preparing BP Annual Report and Form 20-F 2021. There are no new or amended standards or interpretations adopted from 1 January 2022 onwards 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 2021. These have been subsequently considered at the end of each quarter to determine if any changes were required to those judgements and estimates.
Impairment testing assumptions
The group’s value-in-use impairment testing price assumptions for Brent oil and Henry Hub gas were revised during the fourth quarter from those disclosed in the BP Annual Report and Form 20-F 2021. Prices disclosed are in real 2021 terms. The Brent oil assumption up to 2030 was increased to $70 per barrel to reflect near term supply constraints before steadily declining to $45 per barrel by 2050 continuing to reflect the assumption that as the energy system decarbonises, falling oil demand will cause oil prices to decline. The price assumptions for Henry Hub gas up to 2035 and up to 2050 were increased to $4 per mmBtu and $3.50 per mmBtu respectively to reflect the increased demand for US gas production to offset reducing Russian gas flows. A summary of the group’s price assumptions for value-in-use impairment testing, in real 2021 terms, is provided below:
2023
2025
2030
2040
2050
Brent oil ($/bbl)
77
70
70
59
45
Henry Hub gas ($/mmBtu)
4.00
4.00
4.00
3.50
3.50
The post-tax discount rates used for value-in-use impairment testing of assets other than low carbon energy assets was increased to 7% (31 December 2021: 6%) reflecting rising costs of capital.
Provisions
The nominal risk-free discount rate applied to provisions is reviewed on a quarterly basis. The discount rate applied to the group's provisions was revised to 3.5% in the fourth quarter (31 December 2021 2.0%) to reflect increasing US Treasury yields. The principal impact of this rate increase was a $2.1 billion decrease in the decommissioning provision with a corresponding decrease in the carrying amount of property, plant and equipment of $1.6 billion in the fourth quarter.
Pensions and other post-retirement benefits
The group's defined benefit plans are reviewed quarterly to determine any changes to the fair value of the plan assets or present value of the defined benefit obligations. As a result of the review during the fourth quarter of 2022, the group's total net defined benefit plan surplus as at 31 December 2022 is $4.0 billion, compared to a surplus of $4.1 billion at 31 December 2021. The movement for the year principally reflects net actuarial gains reported in other comprehensive income arising from significant increases in the UK, US and Eurozone discount rates largely offset by negative asset performance. The current environment is likely to continue to affect the values of the plan assets and obligations resulting in potential volatility in the amount of the net defined benefit pension plan surplus/deficit recognized.
Investment in Rosneft
On 27 February 2022, bp announced it will exit its shareholding in Rosneft and bp's two nominated Rosneft directors both stepped down from Rosneft's board. As a result, the significant judgement on significant influence over Rosneft was reassessed and a new significant estimate was identified for the fair value of bp's equity investment in Rosneft. From that date, bp accounts for its interest in Rosneft as a financial asset measured at fair value within ‘Other investments’. Russia has implemented a number of counter-sanctions including restrictions on the divestment from Russian assets by foreign investors. Further, bp is not able to sell its Rosneft shares on the Moscow Stock Exchange and is unable to ascribe probabilities to possible outcomes of any exit process. As a result, it is considered 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 as at 31 December 2022.
Note 1. Basis of preparation (continued)
During the year ended 31 December 2022, Rosneft held shareholders meetings to approve resolutions to pay dividends. bp did not participate in those meetings. In line with the resolutions, bp would be entitled to dividend income. Russia has imposed restrictions on the payments of dividends to certain foreign shareholders, including those based in the UK, requiring such dividends to be paid in roubles into restricted bank accounts and a requirement for approval of the Russian government for transfers from any such bank accounts out of Russia. Given the restrictions applicable to such accounts, management considers that the criteria for recognising any dividend income from Rosneft for the year ended 31 December 2022 have not been met.
As a result of bp's decision to exit its shareholding in Rosneft in the first quarter 2022, the group has ceased to report Rosneft as a separate segment in its financial reporting for 2022. Rosneft results up to 27 February 2022 are included within other businesses & corporate (OB&C), and 2021 comparatives have been restated to include the Rosneft segment as per the table below.
OB&C (as previously reported)
Rosneft (as previously reported)
OB&C restated
OB&C (as previously reported)
Rosneft (as previously reported)
OB&C restated
Fourth
Fourth
Fourth
quarter
quarter
quarter
Year
Year
Year
$ million
2021
2021
2021
2021
2021
2021
Profit (loss) before interest and tax
(924)
623
(301)
(2,777)
2,688
(89)
Inventory holding (gains) losses*
—
(68)
(68)
—
(259)
(259)
RC profit (loss) before interest and tax
(924)
555
(369)
(2,777)
2,429
(348)
Net (favourable) adverse impact of adjusting items
389
190
579
1,394
291
1,685
Underlying RC profit (loss) before interest and tax
(535)
745
210
(1,383)
2,720
1,337
Taxation on an underlying RC basis
128
(73)
55
294
(269)
25
Underlying RC profit (loss) before interest
(407)
672
265
(1,089)
2,451
1,362
Since the first quarter 2022, bp has also determined that its other businesses with Rosneft within Russia, which are included in the oil production & operations segment also have a fair value of nil and are subject to similar sanctions and restrictions with respect to the receipt of dividends as described above. Management considers that the criteria for recognising dividend income from other businesses with Rosneft within Russia that declared a dividend in the fourth quarter 2022 have not been met.
The total pre-tax charge for the year to 31 December 2022 relating to bp’s investment in Rosneft and other businesses with Rosneft in Russia is $25,520 million.
Note 2. Business combinations
The group undertook a number of business combinations during 2022. For the fourth quarter and full year 2022, total consideration paid in cash amounted to $3,663 million and $3,671 million respectively, offset by cash acquired of $141 million.
Archaea Energy
On 28 December 2022, bp acquired 100% of the issued common stock of Archaea Energy Inc. a leading producer of renewable natural gas (RNG) in the US, that was listed on the New York Stock Exchange.
The acquisition expands bp’s presence in the US biogas industry, enhancing its ability to support customers’ decarbonization goals and progressing its aim to reduce the average lifecycle carbon intensity of the energy products it sells.
The total cash consideration for the transaction, all paid at completion, was $3,137 million.
The transaction has been accounted for as a business combination using the acquisition method. The provisional fair values of the identifiable assets and liabilities acquired, as at the date of acquisition, are shown in the table below. The goodwill recognized reflects the part of the project development pipeline that did not qualify for separate recognition at the acquisition date and goodwill arising from recognition of deferred tax liabilities on fair value uplifts. The goodwill balance is not expected to be deductible for tax purposes.
The transaction included a step acquisition of the Mavrix LLC joint venture, which bp and Archaea Energy each held a 50% interest in prior to this transaction. The fair value of bp’s interest in Mavrix LLC immediately before the acquisition date was $373 million and the gain recognized in ‘Interest and other income’ as a result of remeasuring this interest to fair value was $267 million.
Fair value of previously held interest in Mavrix LLC
373
As the transaction completed shortly prior to the end of the reporting period, the acquisition-date fair values of the assets and liabilities acquired are provisional. As we gain further understanding of the acquired assets and development pipeline, these fair values may be subsequently adjusted, including goodwill.
An analysis of the cash flows relating to the acquisition included within the cash flow statement for the full year 2022 is provided below.
Year
$ million
2022
Transaction costs of the acquisition (included in cash flows from operating activities)
56
Cash consideration paid, net of cash acquired (included in cash flows from investing activities)
3,030
Total net cash outflow for the acquisition
3,086
Settlement of acquired debt and warrants liabilities immediately after completion (included in cash flows from financing activities)
1,044
Total net cash outflow related to the acquisition
4,130
The revenues and profit before tax generated by the acquired activities from the date of acquisition to 31 December 2022 were immaterial. If the business combination had taken place on 1 January 2022, it is estimated that the acquired activities would have generated revenues of $370 million and losses before tax of $169 million.
Other acquisitions
The fair value of the net assets (including goodwill) recognized from other business combinations in the fourth quarter and full year was $611 million. This principally related to the acquisitions of the Flat Ridge 2 wind farm and EDF Energy Services in North America.
The carrying amount of assets classified as held for sale at 31 December 2022 is $1,242 million, with associated liabilities of $321 million. These relate to the transactions described below.
On 7 September 2022, bp announced that it had agreed to sell its upstream business in Algeria to Eni. Completion is subject to customary governmental and other approvals. Assets of $511 million and associated liabilities of $48 million have been classified as held for sale in the group balance sheet at 31 December 2022.
On 8 August 2022, bp announced an agreement to sell its 50% interest in the bp-Husky Toledo refinery in Ohio US, to Cenovus Energy, its partner in the facility. Following a fire at the refinery, it has been shut down since 20 September 2022. Assets of $731 million and associated liabilities of $273 million have been classified as held for sale in the group balance sheet at 31 December 2022.
Note 4. Impairment and losses on sale of businesses and fixed assets(a)
Net impairment reversals and losses on sale of businesses and fixed assets for the fourth quarter were a charge of $3,629 million and net impairment charges and losses on sale of businesses and fixed assets for the full year were $30,522 million, compared with net charges of $1,223 million and reversals of $1,121 million for the same periods in 2021 and include net impairment charges for the quarter of $3,564 million and for the full year of $18,341 million, compared with net charges of $1,137 million and reversals of $1,351 million for the same periods in 2021.
gas & low carbon energy segment
In the gas & low carbon energy segment there was a net impairment reversal of $1,111 million and $588 million for the fourth quarter and full year respectively, compared with net reversals of $553 million and $1,504 million for the same periods in 2021 respectively.
oil production & operations segment
In the oil production & operations segment there was a net impairment charge of $3,251 million and $3,587 million for the fourth quarter and full year respectively, compared with net charges of $790 million and reversals of $862 million for the same periods in 2021.
Impairment charges in the fourth quarter principally relate to expected portfolio changes with recoverable amounts of those cash generating units based on their fair value less costs to sell.
Impairment charges for the year ended 31 December 2022 included charges related to the decision to exit other businesses with Rosneft within Russia.
customers and products
In the customer and products segment there was a net impairment charge of $1,380 million and $1,806 million for the fourth quarter and full year 2022 respectively compared with net charges of $885 million and $949 million for the same periods in 2021. 2022 impairment charges principally relate to changes in long-term economic assumptions in the Products business and announced portfolio changes. The recoverable amounts of the cash generating units were based on value-in-use calculations.
other businesses and corporate
In the other businesses and corporate segment there was an impairment charge of $44 million and $13,536 million for the fourth quarter and full year respectively, compared with net impairment charges of $15 million and $66 million for the same periods in 2021.
The impairment charge and the loss on sale of businesses and fixed assets for the year mainly relates to bp's investment in Rosneft - see Note 1.
Note 5. Analysis of replacement cost profit (loss) before interest and tax and reconciliation to profit (loss) before taxation
Fourth
Fourth
quarter
quarter
Year
Year
$ million
2022
2021
2022
2021
gas & low carbon energy
16,439
1,911
14,696
2,133
oil production & operations
1,688
3,212
19,721
10,501
customers & products
771
(426)
8,869
2,208
other businesses & corporate(a)
103
(369)
(26,737)
(348)
19,001
4,328
16,549
14,494
Consolidation adjustment – UPII*
147
(7)
139
(67)
19,148
4,321
16,688
14,427
Inventory holding gains (losses)*
gas & low carbon energy
(10)
(8)
(8)
33
oil production & operations
(2)
—
(7)
8
customers & products
(1,416)
412
1,366
3,355
other businesses & corporate(a)
—
68
—
259
Profit (loss) before interest and tax
17,720
4,793
18,039
18,082
Finance costs
834
759
2,703
2,857
Net finance expense/(income) relating to pensions and other post-retirement benefits
(16)
(8)
(69)
(2)
Profit (loss) before taxation
16,902
4,042
15,405
15,227
RC profit (loss) before interest and tax*
US
1,404
959
10,957
5,785
Non-US
17,744
3,362
5,731
8,642
19,148
4,321
16,688
14,427
(a)From first quarter 2022 the results of Rosneft, previously reported as a separate segment, are also included in other businesses & corporate. Comparative information for 2021 has been restated to reflect the changes in reportable segments. For more information see Note 1 Basis of preparation - Investment in Rosneft.
Total depreciation, depletion and amortization by segment
gas & low carbon energy
1,373
1,265
5,008
4,464
oil production & operations
1,383
1,628
5,564
6,528
customers & products
741
754
2,870
3,000
other businesses & corporate
217
216
876
813
3,714
3,863
14,318
14,805
Total depreciation, depletion and amortization by geographical area
US
1,202
1,209
4,624
4,697
Non-US
2,512
2,654
9,694
10,108
3,714
3,863
14,318
14,805
Note 8. Earnings per share and shares in issue
Basic earnings per ordinary share (EpS) amounts are calculated by dividing the profit (loss) for the period attributable to ordinary shareholders by the weighted average number of ordinary shares outstanding during the period. Against the authority granted at bp's 2022 annual general meeting, 586 million ordinary shares repurchased for cancellation were settled during the fourth quarter 2022 for a total cost of $3,240 million. This brings the total number of shares repurchased and settled in the full year to 1,900 million for a total cost of $9,996 million. A further 84 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 $497 million which has been accrued at 31 December 2022. 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.
165 million new ordinary shares were issued in April 2022 as non-cash consideration for the acquisition of the public units of BP Midstream Partners LP.
The calculation of EpS is performed separately for each discrete quarterly period, and for the year-to-date period. As a result, the sum of the discrete quarterly EpS amounts in any particular year-to-date period may not be equal to the EpS amount for the year-to-date period.
For the diluted EpS calculation the weighted average number of shares outstanding during the period is adjusted for the number of shares that are potentially issuable in connection with employee share-based payment plans using the treasury stock method.
Fourth
Fourth
quarter
quarter
Year
Year
$ million
2022
2021
2022
2021
Results for the period
Profit (loss) for the period attributable to bp shareholders
10,803
2,326
(2,487)
7,565
Less: preference dividend
—
—
1
2
Profit (loss) attributable to bp ordinary shareholders
10,803
2,326
(2,488)
7,563
Number of shares (thousand)(a)(b)
Basic weighted average number of shares outstanding
18,178,821
19,800,620
18,987,936
20,128,862
ADS equivalent(c)
3,029,803
3,300,103
3,164,656
3,354,810
Weighted average number of shares outstanding used to calculate diluted earnings per share
18,509,421
19,947,023
18,987,936
20,260,388
ADS equivalent(c)
3,084,903
3,324,503
3,164,656
3,376,731
Shares in issue at period-end
17,974,112
19,642,221
17,974,112
19,642,221
ADS equivalent(c)
2,995,685
3,273,703
2,995,685
3,273,703
(a)Excludes treasury shares and includes certain shares that will be issued in the future under employee share-based payment plans.
(b)If the inclusion of potentially issuable shares would decrease loss per share, the potentially issuable shares are excluded from the weighted average number of shares outstanding used to calculate diluted earnings per share. The numbers of potentially issuable shares that have been excluded from the calculation for the full year 2022 are 242,289 thousand (ADS equivalent 40,381 thousand).
(c)One ADS is equivalent to six ordinary shares.
Issued ordinary share capital as at 31 December 2022 comprised 18,157,211,814 ordinary shares (31 December 2021 19,740,881,309 ordinary shares). This includes shares held in trust to settle future employee share plan obligations and excludes 940,571,303 ordinary shares which have been bought back and are held in treasury by BP (31 December 2021 1,037,200,510 ordinary shares).
BP today announced an interim dividend of 6.610 cents per ordinary share which is expected to be paid on 31 March 2023 to ordinary shareholders and American Depositary Share (ADS) holders on the register on 17 February 2023. The ex-dividend date will be 16 February 2023. The corresponding amount in sterling is due to be announced on 14 March 2023, calculated based on the average of the market exchange rates over three dealing days between 8 March 2023 and 10 March 2023. Holders of ADSs are expected to receive $0.39660 per ADS (less applicable fees). The board has decided not to offer a scrip dividend alternative in respect of the fourth quarter 2022 dividend. Ordinary shareholders and ADS holders (subject to certain exceptions) will be able to participate in a dividend reinvestment programme. Details of the fourth quarter dividend and timetable are available at bp.com/dividends and further details of the dividend reinvestment programmes are available at bp.com/drip.
Fourth
Fourth
quarter
quarter
Year
Year
2022
2021
2022
2021
Dividends paid per ordinary share
cents
6.006
5.460
22.932
21.420
pence
4.940
4.105
18.624
15.538
Dividends paid per ADS (cents)
36.04
32.76
137.59
128.52
Note 10. Net debt
Net debt*
Fourth
Fourth
quarter
quarter
Year
Year
$ million
2022
2021
2022
2021
Finance debt(a)
46,944
61,176
46,944
61,176
Fair value (asset) liability of hedges related to finance debt(b)
3,673
118
3,673
118
50,617
61,294
50,617
61,294
Less: cash and cash equivalents
29,195
30,681
29,195
30,681
Net debt(c)
21,422
30,613
21,422
30,613
Total equity
82,990
90,439
82,990
90,439
Gearing*
20.5%
25.3%
20.5%
25.3%
(a)The fair value of finance debt at 31 December 2022 was $42,590 million (31 December 2021 $62,946 million).
(b)Derivative financial instruments entered into for the purpose of managing interest rate and foreign currency exchange risk associated with net debt with a fair value liability position of $91 million at 31 December 2022 (fourth quarter 2021 liability of $166 million) are not included in the calculation of net debt shown above as hedge accounting is not applied for these instruments.
(c)Net debt does not include accrued interest, which is reported within other receivables and other payables on the balance sheet and for which the associated cash flows are presented as operating cash flows in the group cash flow statement.
As part of actively managing its debt portfolio, year to date the group has bought back a total of $7.4 billion of finance debt ($11.0 billion equivalent for the comparative period in 2021, fourth quarter 2022 $nil, fourth quarter 2021 $2.9 billion) consisting entirely of US dollar bonds. Derivatives associated with non-US dollar debt bought back in relevant comparative periods were also terminated. These transactions have no significant impact on net debt or gearing.
Note 11. Statutory accounts
The financial information shown in this publication, which was approved by the Board of Directors on 6 February 2023, is unaudited and does not constitute statutory financial statements. Audited financial information will be published in BP Annual Report and Form 20-F 2022.
Net impairment and losses on sale of businesses and fixed assets(b)
1,111
553
588
1,503
Environmental and other provisions
—
—
—
—
Restructuring, integration and rationalization costs
3
(4)
8
(33)
Fair value accounting effects(c)(d)
12,502
(790)
(1,811)
(7,662)
Other
(358)
(59)
(197)
(237)
13,291
(300)
(1,367)
(5,395)
oil production & operations
Gains on sale of businesses and fixed assets(e)
68
224
3,446
869
Net impairment and losses on sale of businesses and fixed assets(b)
(3,246)
(799)
(4,508)
776
Environmental and other provisions(f)
420
(235)
518
(1,144)
Restructuring, integration and rationalization costs
3
(2)
(11)
(92)
Fair value accounting effects
—
—
—
—
Other
15
—
52
(200)
(2,740)
(812)
(503)
209
customers & products
Gains on sale of businesses and fixed assets
72
62
374
(52)
Net impairment and losses on sale of businesses and fixed assets(b)
(1,451)
(961)
(1,983)
(1,097)
Environmental and other provisions
(65)
(102)
(101)
(111)
Restructuring, integration and rationalization costs
12
24
18
(11)
Fair value accounting effects(d)
189
146
(309)
436
Other(g)
112
(206)
81
(209)
(1,131)
(1,037)
(1,920)
(1,044)
other businesses & corporate(h)
Gains on sale of businesses and fixed assets
1
—
1
—
Net impairment and losses on sale of businesses and fixed assets
(1)
(9)
(17)
(59)
Environmental and other provisions
(67)
(144)
(92)
(281)
Restructuring, integration and rationalization costs
3
(2)
19
(113)
Fair value accounting effects(d)
515
(212)
(1,381)
(849)
Rosneft(h)
—
(190)
(24,033)
(291)
Gulf of Mexico oil spill
(23)
(24)
(84)
(70)
Other
(19)
2
21
(22)
409
(579)
(25,566)
(1,685)
Total before interest and taxation
9,829
(2,728)
(29,356)
(7,915)
Finance costs(i)
(169)
(257)
(425)
(782)
Total before taxation
9,660
(2,985)
(29,781)
(8,697)
Taxation on adjusting items(j)
(1,542)
888
456
621
Taxation – tax rate change effect of UK energy profits levy(k)
(1,056)
—
(1,834)
—
Total after taxation for period(l)
7,062
(2,097)
(31,159)
(8,076)
(a)Full year 2021 relates to a gain from the divestment of a 20% stake in Oman Block 61.
(b)See Note 4 for further information.
(c)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.
(d)For further information, including the nature of fair value accounting effects reported in each segment, see pages 5, 8 and 40.
(e)Full year 2022 includes a non-taxable gain of $1,951 million arising from the contribution of bp's Angolan business to Azule Energy and gains of $904 million related to the deemed disposal of 12% of the group's interest in Aker BP, an associate of bp, following completion of Aker BP's acquisition of Lundin Energy, and $361 million in relation to the disposal of the group's interest in the Rumaila field in Iraq to Basra Energy Company, an associate of bp.
(f)Full year 2021 includes adjustments relating to the change in discount rate on retained decommissioning provisions and the recognition of a decommissioning provision in relation to certain assets previously sold to a third party where the decommissioning obligation transferred may revert to bp due to the financial condition of the current owner. 2022 includes a provision reversal relating to the change in discount rate on retained decommissioning provisions.
(g)Fourth quarter and full year 2021 include amounts arising in relation to the amendment of the timing of recognition of certain customer incentives in our customers business.
(h)From first quarter 2022 the results of Rosneft, previously reported as a separate segment, are also included in other businesses & corporate. Comparative information for 2021 has been restated to reflect the changes in reportable segments. For more information see Note 1 Basis of preparation - Investment in Rosneft.
(i)Includes the unwinding of discounting effects relating to Gulf of Mexico oil spill payables, the income statement impact associated with the buyback of finance debt (see Note 10 for further information) and temporary valuation differences associated with the group’s interest rate and foreign currency exchange risk management of finance debt.
(j)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.
(k)Fourth quarter and full year 2022 include the deferred tax impact of the UK Energy Profits Levy (EPL) on existing temporary differences unwinding over the period 1 January 2023 to 31 March 2028. The revised EPL substantively enacted in the fourth quarter 2022 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. The original UK EPL enacted in the third quarter increased the headline rate of tax to 65% on taxable profits between 26 May 2022 and 31 December 2025. The revised EPL supersedes the original EPL from 1 January 2023.
(l)Fourth quarter and full year 2022 include a $505-million charge in respect of the EU Solidarity Contribution.
Net debt including leases
Net debt including leases*
Fourth
Fourth
quarter
quarter
Year
Year
$ million
2022
2021
2022
2021
Net debt
21,422
30,613
21,422
30,613
Lease liabilities
8,549
8,611
8,549
8,611
Net partner (receivable) payable for leases entered into on behalf of joint operations
19
187
19
187
Net debt including leases
29,990
39,411
29,990
39,411
Total equity
82,990
90,439
82,990
90,439
Gearing including leases*
26.5%
30.4%
26.5%
30.4%
Gulf of Mexico oil spill
31 December
31 December
$ million
2022
2021
Gulf of Mexico oil spill payables and provisions
(9,566)
(10,433)
Of which - current
(1,216)
(1,279)
Deferred tax asset
1,444
3,959
During the second quarter pre-tax payments of $1,204 million were made relating to the 2016 consent decree and settlement agreement with the United States and the five Gulf coast states. Payables and provisions presented in the table above reflect the latest estimate for the remaining costs associated with the Gulf of Mexico oil spill. Where amounts have been provided on an estimated basis, the amounts ultimately payable may differ from the amounts provided and the timing of payments is uncertain. Further information relating to the Gulf of Mexico oil spill, including information on the nature and expected timing of payments relating to provisions and other payables, is provided in BP Annual Report and Form 20-F 2021 - Financial statements - Notes 6, 8, 19, 21, 22, 28, and 32.
Receipts relating to transactions involving non-controlling interests
1
12
11
683
14,193
8,429
44,133
31,449
Uses:
Lease liability payments
(513)
(502)
(1,961)
(2,082)
Payments on perpetual hybrid bonds
(219)
(100)
(708)
(538)
Dividends paid – BP shareholders
(1,088)
(1,077)
(4,358)
(4,304)
– non-controlling interests
(100)
(66)
(294)
(311)
Total capital expenditure*
(7,369)
(3,633)
(16,330)
(12,848)
Net repurchase of shares relating to employee share schemes
—
—
(500)
(500)
Payments relating to transactions involving non-controlling interests
(1)
—
(9)
(560)
Currency translation differences relating to cash and cash equivalents
177
(58)
(684)
(269)
(9,113)
(5,436)
(24,844)
(21,412)
(a)Other proceeds for the year 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, 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 have been recognized as the potential recourse reduces and by end second quarter 2022 all proceeds were recognized.
Adjusted earnings before interest, taxation, depreciation and amortization (adjusted EBITDA)*
Year
Year
$ million
2022
2021
Profit (loss) for the period
(1,357)
8,487
Finance costs
2,703
2,857
Net finance (income) expense relating to pensions and other post-retirement benefits
(69)
(2)
Taxation
16,762
6,740
Profit before interest and tax
18,039
18,082
Inventory holding (gains) losses*, before tax
(1,351)
(3,655)
16,688
14,427
Net (favourable) adverse impact of adjusting items*, before interest and tax
Adjusted earnings before interest, depreciation and amortization (adjusted EBIDA)*
Year
Year
$ million
2022
2021
Profit (loss) for the period
(1,357)
8,487
Finance costs
2,703
2,857
Net finance (income) expense relating to pensions and other post-retirement benefits
(69)
(2)
Taxation
16,762
6,740
Profit before interest and tax
18,039
18,082
Inventory holding (gains) losses*, before tax
(1,351)
(3,655)
16,688
14,427
Net (favourable) adverse impact of adjusting items*, before interest and tax
29,356
7,915
46,044
22,342
Taxation on an underlying RC basis(a)
(15,052)
(6,532)
30,992
15,810
Add back:
Depreciation, depletion and amortization
14,318
14,805
Exploration expenditure written off
385
168
Adjusted EBIDA
45,695
30,783
(a)A definition for taxation on an underlying RC basis is included under Underlying ETR in the glossary on page 43.
Return on average capital employed (ROACE)*
Year
Year
$ million
2022
2021
Profit (loss) for the year attributable to bp shareholders
(2,487)
7,565
Inventory holding (gains) losses*, before tax
(1,351)
(3,655)
Taxation charge (credit) on inventory holding gains and losses
332
829
Net (favourable) adverse impact of adjusting items*, before tax
29,781
8,697
Taxation charge (credit) on adjusting items
1,378
(621)
Underlying replacement cost (RC) profit*
27,653
12,815
Interest expense(a)
1,632
1,322
Taxation on interest expense
(296)
(195)
Non-controlling interests
1,130
922
30,119
14,864
Total equity
82,990
90,439
Finance debt
46,944
61,176
Capital employed
129,934
151,615
Less: Goodwill
11,960
12,373
Cash and cash equivalents
29,195
30,681
88,779
108,561
Average capital employed (excluding goodwill and cash and cash equivalents)
98,670
111,601
ROACE
30.5
%
13.3
%
(a)Finance costs, as reported in the Group income statement, were $2,703 million (2021 $2,857 million). Interest expense which totals $1,632 million (2021 $1,322 million) on a pre-tax basis is finance costs excluding lease interest of $257 million (2021 $306 million), unwinding of discount on provisions and other payables of $808 million (2021 $890 million) and other adjusting items related to finance costs of $6 million (2021 $339 million). Interest expense included above is calculated on a post-tax basis.
Reconciliation of customers & products RC profit before interest and tax to underlying RC profit before interest and tax* to adjusted EBITDA* by business
Fourth
Fourth
quarter
quarter
Year
Year
$ million
2022
2021
2022
2021
RC profit before interest and tax for customers & products
771
(426)
8,869
2,208
Less: Adjusting items* gains (charges)
(1,131)
(1,037)
(1,920)
(1,044)
Underlying RC profit before interest and tax for customers & products
1,902
611
10,789
3,252
By business:
customers – convenience & mobility
628
637
2,966
3,052
Castrol – included in customers
70
207
700
1,037
products – refining & trading
1,274
(26)
7,823
200
Add back: Depreciation, depletion and amortization
741
754
2,870
3,000
By business:
customers – convenience & mobility
334
329
1,286
1,306
Castrol – included in customers
40
36
153
150
products – refining & trading
407
425
1,584
1,694
Adjusted EBITDA for customers & products
2,643
1,365
13,659
6,252
By business:
customers – convenience & mobility
962
966
4,252
4,358
Castrol – included in customers
110
243
853
1,187
products – refining & trading
1,681
399
9,407
1,894
Reconciliation of RC profit before interest and tax to adjusted EBITDA*
Fourth
Fourth
quarter
quarter
Year
Year
$ million
2022
2021
2022
2021
gas & low carbon energy
RC profit before interest and tax
16,439
1,911
14,696
2,133
Less: Net favourable (adverse) impact of adjusting items*
13,291
(300)
(1,367)
(5,395)
Underlying RC profit before interest and tax*
3,148
2,211
16,063
7,528
Add back: Depreciation, depletion and amortization
1,373
1,265
5,008
4,464
Exploration write-offs
(6)
2
2
43
Adjusted EBITDA
4,515
3,478
21,073
12,035
oil production & operations
RC profit before interest and tax
1,688
3,212
19,721
10,501
Less: Net favourable (adverse) impact of adjusting items
(2,740)
(812)
(503)
209
Underlying RC profit before interest and tax
4,428
4,024
20,224
10,292
Add back: Depreciation, depletion and amortization
(a)Based on sales of consolidated subsidiaries only – this excludes equity-accounted entities.
(b)Realizations calculation methodology has been changed to reflect gas price fluctuations within the North Sea region. All comparatives are restated. There is no impact on financial results.
For a full discussion of the group’s material legal proceedings, see pages 248-249 of bp Annual Report and Form 20-F 2021.
Glossary
Non-GAAP measures are provided for investors because they are closely tracked by management to evaluate bp’s operating performance and to make financial, strategic and operating decisions. Non-GAAP measures are sometimes referred to as alternative performance measures.
Adjusted EBIDA is a non-GAAP measure and 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 taxation on an underlying RC basis, and adding back depreciation, depletion and amortization (pre-tax) and exploration expenditure written-off (net of adjusting items, pre-tax). bp believes that adjusted EBIDA 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. The nearest equivalent measure on an IFRS basis is profit or loss for the period. A reconciliation of profit or loss for the period to adjusted EBIDA is provided on page 35.
Adjusted EBITDA is a non-GAAP 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.
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 GAAP information is provided on page 34 for the group and page 36 for the segments.
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-GAAP measures. An analysis of adjusting items by segment and type is shown on page 32.
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 and customers & products businesses is presented on the same basis.
Cash balance point is defined as the implied Brent oil price 2021 real to balance bp’s sources and uses of cash assuming an average bp refining marker margin around $11/bbl and Henry Hub at $3/mmBtu in 2021 real terms.
Consolidation adjustment – UPII is unrealized profit in inventory arising on inter-segment transactions.
Developed renewables to final investment decision (FID) – Total generating capacity for assets developed to FID by all entities where bp has an equity share (proportionate to equity share). If asset is subsequently sold bp will continue to record capacity as developed to FID. If bp equity share increases developed capacity to FID will increase proportionately to share increase for any assets where bp held equity at the point of FID.
Divestment proceeds are disposal proceeds as per the condensed group cash flow statement.
Effective tax rate (ETR) on replacement cost (RC) profit or loss is a non-GAAP measure. The ETR on RC profit or loss is calculated by dividing taxation on a RC basis by RC profit or loss before tax. 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-GAAP measures. The nearest equivalent measure on an IFRS basis is the ETR on profit or loss for the period. A reconciliation to GAAP information is provided on page 37.
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.
Emissions from the carbon in its oil and gas production: bp's aim to reach net zero CO2 emissions, in accordance with bp's Aim 2, from the carbon in our oil and gas production, in respect of the estimated CO2 emissions from the combustion of upstream production of crude oil, natural gas and natural gas liquids on a bp equity share basis based on bp's net share of production, excluding bp's share of Rosneft production and assuming that all produced volumes undergo full stoichiometric combustion to CO2. Aim 2 is bp's Scope 3 aim and relates to Scope 3, category 11 emissions. Any interim target or aim in respect of bp's Aim 2 is defined in terms of absolute reductions relative to the baseline year of 2019.
Fair value accounting effects are non-GAAP adjustments to our IFRS profit (loss). They reflect the difference between the way bp manages the economic exposure and internally measures performance of certain activities and the way those activities are measured under IFRS. Fair value accounting effects are included within adjusting items. They relate to certain of the group's commodity, interest rate and currency risk exposures as detailed below. Other than as noted below, the fair value accounting effects described are reported in both the gas & low carbon energy and customer & products segments.
bp uses derivative instruments to manage the economic exposure relating to inventories above normal operating requirements of crude oil, natural gas and petroleum products. Under IFRS, these inventories are recorded at historical cost. The related derivative instruments, however, are required to be recorded at fair value with gains and losses recognized in the income statement. This is because hedge accounting is either not permitted or not followed, principally due to the impracticality of effectiveness-testing requirements. Therefore, measurement differences in relation to recognition of gains and losses occur. Gains and losses on these inventories, other than net realizable value provisions, are not recognized until the commodity is sold in a subsequent accounting period. Gains and losses on the related derivative commodity contracts are recognized in the income statement, from the time the derivative commodity contract is entered into, on a fair value basis using forward prices consistent with the contract maturity.
bp enters into physical commodity contracts to meet certain business requirements, such as the purchase of crude for a refinery or the sale of bp’s gas production. Under IFRS these physical contracts are treated as derivatives and are required to be fair valued when they are managed as part of a larger portfolio of similar transactions. Gains and losses arising are recognized in the income statement from the time the derivative commodity contract is entered into.
IFRS require that inventory held for trading is recorded at its fair value using period-end spot prices, whereas any related derivative commodity instruments are required to be recorded at values based on forward prices consistent with the contract maturity. Depending on market conditions, these forward prices can be either higher or lower than spot prices, resulting in measurement differences.
bp enters into contracts for pipelines and other transportation, storage capacity, oil and gas processing, liquefied natural gas (LNG) and certain gas and power contracts that, under IFRS, are recorded on an accruals basis. These contracts are risk-managed using a variety of derivative instruments that are fair valued under IFRS. This results in measurement differences in relation to recognition of gains and losses.
The way that bp manages the economic exposures described above, and measures performance internally, differs from the way these activities are measured under IFRS. bp calculates this difference for consolidated entities by comparing the IFRS result with management’s internal measure of performance. We believe that disclosing management’s estimate of this difference provides useful information for investors because it enables investors to see the economic effect of these activities as a whole.
These include:
•Under management’s internal measure of performance the inventory, transportation and capacity contracts in question are valued based on fair value using relevant forward prices prevailing at the end of the period.
•Fair value accounting effects also include changes in the fair value of the near-term portions of LNG contracts that fall within bp’s risk management framework. LNG contracts are not considered derivatives, because there is insufficient market liquidity, and they are therefore accrual accounted under IFRS. However, oil and natural gas derivative financial instruments used to risk manage the near-term portions of the LNG contracts are fair valued under IFRS. The fair value accounting effect, which is reported in the gas and low carbon energy segment, represents the change in value of LNG contacts that are being risk managed and which is reflected in the underlying result, but not in reported earnings. Management believes that this gives a better representation of performance in each period.
Furthermore, the fair values of derivative instruments used to risk manage certain other oil, gas, power and other contracts, are deferred to match with the underlying exposure. The commodity contracts for business requirements are accounted for on an accruals basis.
In addition, fair value accounting effects include changes in the fair value of derivatives entered into by the group to manage currency exposure and interest rate risks relating to hybrid bonds to their respective first call periods. The hybrid bonds which were issued on 17 June 2020 are classified as equity instruments and were recorded in the balance sheet at that date at their USD equivalent issued value. Under IFRS these equity instruments are not remeasured from period to period, and do not qualify for application of hedge accounting. The derivative instruments relating to the hybrid bonds, however, are required to be recorded at fair value with mark to market gains and losses recognized in the income statement. Therefore, measurement differences in relation to the recognition of gains and losses occur. The fair value accounting effect, which is reported in the other businesses & corporate segment, eliminates the fair value gains and losses of these derivative financial instruments that are recognized in the income statement. We believe that this gives a better representation of performance, by more appropriately reflecting the economic effect of these risk management activities, in each period.
Gas & low carbon energy segment comprises our gas and low carbon businesses. Our gas business includes regions with upstream activities that predominantly produce natural gas, integrated gas and power, and gas trading. Our low carbon business includes solar, offshore and onshore wind, hydrogen and CCS, power trading and our share in bp Bunge Bioenergia. Power trading includes trading of both renewable and non-renewable power.
Gearing and net debt are non-GAAP measures. Net debt is calculated as finance debt, as shown in the balance sheet, plus the fair value of associated derivative financial instruments that are used to hedge foreign currency exchange and interest rate risks relating to finance debt, for which hedge accounting is applied, less cash and cash equivalents. 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 GAAP measures on an IFRS basis are finance debt and finance debt ratio. A reconciliation of finance debt to net debt is provided on page 30.
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 GAAP forward-looking financial measure. These items include fair value asset (liability) of hedges related to finance debt and cash and cash equivalents, that are difficult to predict in advance in order to include in a GAAP estimate.
Gearing including leases and net debt including leases are non-GAAP 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 GAAP 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 33.
Green hydrogen – Hydrogen made from solar, wind and hydro-electricity.
Hydrocarbons – Liquids and natural gas. Natural gas is converted to oil equivalent at 5.8 billion cubic feet = 1 million barrels.
Inorganic capital expenditure is a subset of capital expenditure on a cash basis and a non-GAAP measure. Inorganic capital expenditure comprises consideration in business combinations and certain other significant investments made by the group. It is reported on a cash basis. bp believes that this measure provides useful information as it allows investors to understand how bp’s management invests funds in projects which expand the group’s activities through acquisition. The nearest equivalent measure on an IFRS basis is capital expenditure on a cash basis. Further information and a reconciliation to GAAP information is provided on page 31.
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-GAAP adjustments to our IFRS profit (loss) and represent:
a.the difference between the cost of sales calculated using the replacement cost of inventory and the cost of sales calculated on the first-in first-out (FIFO) method after adjusting for any changes in provisions where the net realizable value of the inventory is lower than its cost. Under the FIFO method, which we use for IFRS reporting of inventories other than for trading inventories, the cost of inventory charged to the income statement is based on its historical cost of purchase or manufacture, rather than its replacement cost. In volatile energy markets, this can have a significant distorting effect on reported income. The amounts disclosed as inventory holding gains and losses represent the difference between the charge to the income statement for inventory on a FIFO basis (after adjusting for any related movements in net realizable value provisions) and the charge that would have arisen based on the replacement cost of inventory. For this purpose, the replacement cost of inventory is calculated using data from each operation’s production and manufacturing system, either on a monthly basis, or separately for each transaction where the system allows this approach; and
b.an adjustment relating to certain trading inventories that are not price risk managed which relate to a minimum inventory volume that is required to be held to maintain underlying business activities. This adjustment represents the movement in fair value of the inventories due to prices, on a grade by grade basis, during the period. This is calculated from each operation’s inventory management system on a monthly basis using the discrete monthly movement in market prices for these inventories.
The amounts disclosed are not separately reflected in the financial statements as a gain or loss. No adjustment is made in respect of the cost of inventories held as part of a trading position and certain other temporary inventory positions that are price risk-managed. See Replacement cost (RC) profit or loss definition below.
Liquids – Liquids comprises crude oil, condensate and natural gas liquids. For the oil production & operations segment, it also includes bitumen.
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-GAAP 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 GAAP information is provided on page 31.
We are unable to present reconciliations of forward-looking information for organic capital expenditure to total cash capital expenditure, because without unreasonable efforts, we are unable to forecast accurately the adjusting item, inorganic capital expenditure, that is difficult to predict in advance in order to derive the nearest GAAP estimate.
Production-sharing agreement/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 PPA 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 GAAP measure. bp believes this measure is useful to illustrate to investors the fact that crude oil and product prices can vary significantly from period to period and that the impact on our reported result under IFRS can be significant. Inventory holding gains and losses vary from period to period due to changes in prices as well as changes in underlying inventory levels. In order for investors to understand the operating performance of the group excluding the impact of price changes on the replacement of inventories, and to make comparisons of operating performance between reporting periods, bp’s management believes it is helpful to disclose this measure. The nearest equivalent measure on an IFRS basis is profit or loss attributable to bp shareholders. A reconciliation to GAAP information is provided on page 3. RC profit or loss before interest and tax is 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.
Reserves replacement ratio – the extent to which the year’s production has been replaced by proved reserves added to our reserve base. The ratio is expressed in oil-equivalent terms and includes changes resulting from discoveries, improved recovery and extensions and revisions to previous estimates, but excludes changes resulting from acquisitions and disposals.
Retail sites include sites operated by dealers, jobbers, franchisees or brand licensees or joint venture (JV) partners, under the bp brand. These may move to and from the bp brand as their fuel supply agreement or brand licence agreement expires and are renegotiated in the normal course of business. Retail sites are primarily branded bp, ARCO, Amoco, Aral and Thorntons, and also includes sites in India through our Jio-bp JV.
Retail sites in growth markets are retail sites that are either bp branded or co-branded with our partners in China, Mexico and Indonesia and also include sites in India through our Jio-bp JV.
Return on average capital employed (ROACE) is a non-GAAP measure and is defined as underlying replacement cost profit, which is defined as profit or loss attributable to bp shareholders adjusted for inventory holding gains and losses, adjusting items and related taxation on inventory holding gains and losses and adjusting items total taxation, after adding back non-controlling interest and interest expense net of tax, divided by the average of the beginning and ending balances of total equity plus finance debt, excluding cash and cash equivalents and goodwill as presented on the group balance sheet over the periods presented. Interest expense before tax is finance costs as presented on the group income statement, excluding lease interest, the unwinding of the discount on provisions and other payables and other adjusting items reported in finance costs. bp believes it is helpful to disclose the ROACE because this measure gives an indication of the company's capital efficiency. The nearest GAAP measures of the numerator and denominator are profit or loss for the period attributable to bp shareholders and total equity respectively. The reconciliation of the numerator and denominator is provided on page 35
Solomon availability – See Refining availability definition.
Strategic convenience sites are retail sites, within the bp portfolio, which sell bp-branded vehicle energy (e.g. bp, Aral, Arco, Amoco, Thorntons and Pulse) and either carry one of the strategic convenience brands (e.g. M&S, Rewe to Go) or a differentiated convenience offer. To be considered a strategic convenience site, the convenience offer should have a demonstrable level of differentiation in the market in which it operates. Strategic convenience site count includes sites under a pilot phase.
Surplus cash flow does not represent the residual cash flow available for discretionary expenditures. It is a non-GAAP 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 full year 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 34 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.
Underlying effective tax rate (ETR) is a non-GAAP measure. The underlying ETR is calculated by dividing taxation on an underlying replacement cost (RC) basis by underlying RC profit or loss before tax. Taxation on an underlying RC basis 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-GAAP 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 GAAP 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 a GAAP estimate. A reconciliation to GAAP information is provided on page 37.
Underlying production – 2022 underlying production, when compared with 2021, 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-GAAP measure and is RC profit or loss* (as defined on page 42) after excluding net adjusting items and related taxation. See page 32 for additional information on the adjusting items that are used to arrive at underlying RC profit or loss in order to enable a full understanding of the items and their financial impact.
Underlying RC profit or loss before interest and tax for the operating segments or customers & products businesses is calculated as RC profit or loss (as defined above) including profit or loss attributable to non-controlling interests before interest and tax for the operating segments and excluding net adjusting items for the respective operating segment or business.
bp believes that underlying RC profit or loss is a useful measure for investors because it is a measure closely tracked by management to evaluate bp’s operating performance and to make financial, strategic and operating decisions and because it may help investors to understand and evaluate, in the same manner as management, the underlying trends in bp’s operational performance on a comparable basis, period on period, by adjusting for the effects of these adjusting items. The nearest equivalent measure on an IFRS basis for the group is profit or loss attributable to bp shareholders. The nearest equivalent measure on an IFRS basis for segments and businesses is RC profit or loss before interest and taxation. A reconciliation to GAAP information is provided on page 3 for the group and pages 8-17 for the segments.
Underlying RC profit or loss per share / underlying RC profit or loss per ADS is a non-GAAP measure. Earnings per share is defined in Note 8. Underlying RC profit or loss per ordinary share is calculated using the same denominator as earnings per share as defined in the consolidated financial statements. The numerator used is underlying RC profit or loss attributable to bp shareholders rather than profit or loss attributable to bp shareholders. Underlying RC profit or loss per ADS is calculated as outlined above for underlying RC profit or loss per share except the denominator is adjusted to reflect one ADS equivalent to six ordinary shares. bp believes it is helpful to disclose the underlying RC profit or loss per ordinary share and per ADS because these measures may help investors to understand and evaluate, in the same manner as management, the underlying trends in bp’s operational performance on a comparable basis, period on period. The nearest equivalent measure on an IFRS basis is basic earnings per share based on profit or loss for the period attributable to bp shareholders. A reconciliation to GAAP information is provided on page 37.
upstream includes oil and natural gas field development and production within the gas & low carbon energy and oil production & operations segments.
upstream/hydrocarbon plant reliability (bp-operated) is calculated taking 100% less the ratio of total unplanned plant deferrals divided by installed production capacity, excluding non-operated assets and bpx energy. Unplanned plant deferrals are associated with the topside plant and where applicable the subsea equipment (excluding wells and reservoir). Unplanned plant deferrals include breakdowns, which does not include Gulf of Mexico weather related downtime.
upstream unit production cost is calculated as production cost divided by units of production. Production cost does not include ad valorem and severance taxes. Units of production are barrels for liquids and thousands of cubic feet for gas. Amounts disclosed are for bp subsidiaries only and do not include bp’s share of equity-accounted entities.
Trade marks
Trade marks of the bp group appear throughout this announcement. They include:
In order to utilize the ‘safe harbor’ provisions of the United States Private Securities Litigation Reform Act of 1995 (the ‘PSLRA’) and the general doctrine of cautionary statements, bp is providing the following cautionary statement:
The discussion in this results announcement contains certain forecasts, projections and forward-looking statements - that is, statements related to future, not past events and circumstances - with respect to the financial condition, results of operations and businesses of bp and certain of the plans and objectives of bp with respect to these items. These statements may generally, but not always, be identified by the use of words such as ‘will’, ‘expects’, ‘is expected to’, ‘aims’, ‘should’, ‘may’, ‘objective’, ‘is likely to’, ‘intends’, ‘believes’, ‘anticipates’, ‘plans’, ‘we see’ or similar expressions.
In particular, the following, among other statements, are all forward looking in nature: plans, expectations and assumptions regarding oil and gas demand, supply, prices or volatility; expectations regarding upstream production and bp’s customers & products business; expectations regarding refining margins; expectations regarding production from oil production and operations, gas and low carbon energy; expectations regarding bp’s business, financial performance, results of operations and cash flows; expectations regarding future project start-ups; expectations with regards to bp’s transformation to an IEC; expectations regarding price assumptions used in accounting estimates; bp’s plans and expectations regarding the amount and timing of share buybacks and quarterly and interim 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 regarding bp’s exit of its shareholding in Rosneft and other investments in Russia; plans and expectations with respect to the total depreciation, depletion and amortization and business and corporate underlying annual charge for 2023; plans and expectations regarding the factors taken into account in setting the dividend per ordinary share and buyback each quarter; plans and expectations regarding investments, collaborations and partnerships in charging infrastructure; plans related to bp’s Launchpad accelerator; plans and expectations related to bp’s transition growth engines of bioenergy, convenience, EV charging, renewables and hydrogen; plans and expectations regarding divestments, including the amount and timing of proceeds; plans and expectations regarding bp’s renewable energy business; 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; expectations regarding bp’s defined benefit pension plans; plans and expectations regarding capital expenditure, including that capital expenditure will be around $16-18 billion in 2023; plans and expectations regarding bp’s work in the biogas industry; plans and expectations regarding projects, joint ventures and other partnerships and agreements, including partnerships and other collaborations with M&S, Mauritania, Egypt, REWE, Hertz, Chubu Electric and KMS as well as plans and expectations regarding the Mad Dog Phase 2 project in the Gulf of Mexico, the Tangguh expansion in Indonesia, operations in Trinidad and Tobago and Mozambique, the partnership with Shell and Lightsource bp to develop a solar project in Trinidad and Tobago, GTA Phase 1 Tortue projects, bp ventures’ investments in 5B Holdings Pty Ltd, the sale of its interest in the bp-Husky Toledo refinery to Cenovus Energy and related operational impacts, the sale of bp’s upstream business in Algeria to Eni and the development of EV charge points.
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 or actions taken by any competent authorities or any other relevant persons may impact Rosneft’s business or outlook, bp’s ability to sell its interests in Rosneft, or the price for which bp 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 other factors discussed elsewhere in this report, as well as those factors discussed under “Risk factors” in bp’s Annual Report and Form 20-F 2021 as filed with the US Securities and Exchange Commission 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 2022 as filed with the US Securities and Exchange Commission.
The following table shows the unaudited consolidated capitalization and indebtedness of the BP group as of 31 December 2022 in
accordance with IFRS:
Capitalization and indebtedness
31 December
$ million
2022
Share capital and reserves
Capital shares (1-2)
4,795
Paid-in surplus (3)
15,872
Merger reserve (3)
27,206
Treasury shares
(12,153)
Cash flow hedge reserve
(183)
Costs of hedging reserve
(73)
Foreign currency translation reserve (4)
(2,643)
Profit and loss account (4)
34,732
BP shareholders' equity
67,553
Hybrid bonds
13,390
Other interest
2,047
Equity attributable to non-controlling interests
15,437
Total equity
82,990
Finance debt and lease liabilities (5-7)
Lease liabilities due within one year
2,102
Finance debt due within one year
3,198
Lease liabilities due after more than one year
6,447
Finance debt due after more than one year
43,746
Total finance debt and lease liabilities
55,493
Total (8)(9)
138,483
1.Issued share capital as of 31 December 2022 comprised 18,157,211,814 ordinary shares, par value US$0.25 per share, and 12,706,252 preference shares, par value £1 per share. This excludes 940,571,303 ordinary shares which have been bought back and are held in treasury by BP. These shares are not taken into consideration in relation to the payment of dividends and voting at shareholders’ meetings.
2.Capital shares represent the ordinary and preference shares of BP which have been issued and are fully paid.
3.Paid-in surplus and merger reserve represent additional paid-in capital of BP which cannot normally be returned to shareholders.
4.In the full year 2022 $9.2 billion of the opening foreign currency translation reserve has been moved to 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. For more information see Note 1.
5.Finance debt and lease liabilities recorded in currencies other than US dollars has been translated into US dollars at the relevant exchange rates existing on 31 December 2022.
6.Finance debt and lease liabilities presented in the table above consists of borrowings and obligations under leases. This includes one hundred percent of lease liabilities for joint operations where BP is the only party with the legal obligation to make lease payments to the lessor. Other contractual obligations are not presented in the table above – see BP Annual Report and Form 20-F 2021 – Liquidity and capital resources for further information.
7.At 31 December 2022, the parent company, BP p.l.c. had issued guarantees totalling $46,654 million relating to group finance debt issued by subsidiaries. Thus 99% of the group’s finance debt had been guaranteed by BP p.l.c. In addition, BP p.l.c. guarantees $11.9 billion of perpetual subordinated hybrid bonds issued by a subsidiary. At 31 December 2022 $189 million of finance debt was secured by the pledging of assets. The remainder of finance debt was unsecured.
8.At 31 December 2022 the group had issued third-party guarantees under which amounts outstanding, incremental to amounts recognized on the group balance sheet, were $1,701 million in respect of the borrowings of equity-accounted entities and $557 million in respect of the borrowings of other third parties.
9.Total capitalisation and indebtedness includes non-controlling interests of $15,437 million at 31 December 2022 which includes $12.0 billion related to perpetual hybrid bonds issued on 17 June 2020 and $1.3 billion related to perpetual subordinated hybrid securities issued by a group subsidiary since the second half of 2021.
10.There has been no material change since 31 December 2022 in the consolidated capitalization and indebtedness of BP.
On 7 February, bp announced that it aims to increase investment in its transition growth engines (TGEs) bioenergy, convenience, EV charging, renewables and hydrogen by up to $1 billion a year on average, or up to a cumulative additional $8 billion to 2030. bp’s investment in its TGEs is now expected to reach $7-9 billion a year in 2030 – with cumulative investment over 2023-2030 around $55-65 billion. bp's investment in TGEs is expected to be $6-8 billion in 2025.
bp also announced that it aims to increase investment into resilient high-quality oil and gas projects – again by an average of up to $1 billion a year, or up to a cumulative $8 billion to 2030.
As a result of these changes, bp anticipates its oil and gas production will be around 2.3 million barrels of oil equivalent a day (mmboe/d) in 2025 and aims for it to be around 2.0mmboe/d in 2030. This 2030 production would be around 25% lower than bp's production in 2019, excluding production from Rosneft, compared to bp's previous expectation of a reduction of around 40%. bp correspondingly now aims for a fall of 20% to 30% in emissions from the carbon in its oil and gas production* in 2030 compared to a 2019 baseline, lower than the previous aim of 35-40%.
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
