Modelling guidance
The purpose of this page is to collate existing available public information that may assist with the financial modelling of bp. Please also refer to our legal notice.
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Trading conditions update
The trading conditions update is produced in order to provide equal disclosure to all investors and potential investors of current trading conditions.
Content includes the following:
- Current and historic market prices
- Current and historic marker margins
- Rules of thumb for Brent, Henry Hub and RMM
| Operating environment rules of thumb for the full year 2023 | Impact on pre-tax replacement cost operating profit |
|---|---|
| Oil price* Brent +/- $1/bbl |
$340m |
| Natural gas price* Henry Hub +/- $0.10/mmBtu |
$30m |
| Customers & products refining margin RMM +/- $ 1/bbl |
$400m |
*combined indicator for oil production & operations and gas & low carbon energy
Find out more about our trading conditions update
Macro outlook
Below is bp's macro outlook as at 1Q23 results publication on 2 May 2023
- Oil prices: For the second quarter, bp expects oil prices to remain elevated as the recent decision by OPEC+ to restrict production, combined with strengthening Chinese demand, tightens supply/demand balances.
- Gas prices: During the second quarter, bp expects European gas and Asian LNG prices to be supported by recovering Chinese gas demand, re-stocking of European storage capacity and coal-to-gas switching. In the US, Henry Hub gas prices are also expected to find support from coal-to-gas switching in the power sector.
- Refining margins: In the second quarter, bp expects industry refining margins to be lower than the first quarter due to weaker middle distillate margins.
Upcoming quarters guidance
Below is bp's 2Q23 guidance as at 1Q23 results publication on 2 May 2023
- Looking ahead, bp expects second-quarter 2023 reported upstream production to be lower compared to first quarter 2023, in both oil production & operations and gas & low carbon energy, including the effects of seasonal maintenance, with the impact predominantly in higher margin regions.
- In its customers business, bp expects higher marketing margins and seasonally higher volumes compared to the first quarter. In refining, bp expects realized margins to be lower compared to the first quarter, mainly driven by weaker middle distillate margins and narrower North American heavy oil crude differentials. In addition, bp expects a higher level of turnaround activity compared to the first quarter.
Full year guidance
Below is bp's 2023 guidance as at 1Q23 results publication on 2 May 2023
- bp continues to expect 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 continues to expect 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 continues to expect the depreciation, depletion and amortization to be slightly above 2022.
- bp continues to expect the underlying ETR for 2023 to be around 40% but is sensitive to the impact that volatility in the current price environment may have on the geographical mix of the group’s profits and losses.
- Having realized $16.7 billion of divestment and other proceeds since the second quarter of 2020, bp continues to expect divestment and other proceeds of $2-3 billion in 2023 and continues to expect to reach $25 billion of divestment and other proceeds between the second half of 2020 and 2025.
- bp continues to expect Gulf of Mexico oil spill payments for the year to be around $1.3 billion pre-tax including $1.2 billion pre-tax to be paid during the second quarter.
- bp continues to expect capital expenditure of $16-18 billion in 2023 including inorganic capital expenditure.
- bp is committed to maintaining a strong investment grade credit rating, targeting further progress within an 'A' grade credit rating. For 2023 bp continues to intend to allocate 40% of surplus cash flow to further strengthening the balance sheet.
- For 2023 and subject to maintaining a strong investment grade credit rating, bp remains committed to using 60% of surplus cash flow for share buybacks.
- Based on bp’s current forecasts, at around $60 per barrel Brent and subject to the board’s discretion each quarter, bp continues to expect to be able to deliver share buybacks of around $4.0 billion per annum, at the lower end of its $14-18 billion capital expenditure range, and have capacity for an annual increase in the dividend per ordinary share of around 4%.
- 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.
2025 targets and 2030 aims
We now have three years under our belt. We have made good progress on our 2025 targets. And we are increasingly confident - not just in those targets - but in the opportunities presented by the energy transition. Below is a summary of the 2025 targets and 2030 aims for the Group and our three strategic focus areas.
All references to $70/bbl in the below tables refer to Brent 2021 real.
| EBITDA ($bn) | 2021 | 2022 | 2025 | 2030 |
|---|---|---|---|---|
| $71/bbl | $103/bbl | $70/bbl | $70/bbl | |
| Resilient hydrocarbons | 30.6 | 56.9 | 40-42 | 39-42 |
| Convenience and mobility | 4.4 | 4.3 | ~7 | 9-11 |
| Low carbon energy | Growth phase | 2-3 | ||
| Group | 34.4 | 60.7 | 46-49 | 51-56 |
| Of which: Transition growth engines | 3-4 | 10-12 | ||
| Investor proposition targets | 2021 | 2022 | 2025 | 2030 |
|---|---|---|---|---|
| $71/bbl | $103/bbl | $70/bbl | $70/bbl | |
| EBIDA per share growth (%), CAGR | >12 | |||
| ROACE (%) | 13.3 | 30.5 | >18 | >18 |
| Capital expenditure in transition (%) | ~19 | ~30 | >40 | ~50 |
| Other guidance | 2021 | 2022 | 2025 | 2030 |
|---|---|---|---|---|
| $71/bbl | $103/bbl | $70/bbl | $70/bbl | |
| Capital expenditure ($bn) | 12.8 | 16.3 | 14-18 | 14-18 |
| Of which: Transition growth engines | 2.4 | 4.9 | 6-8 | 7-9 |
| Divestment proceeds - cumulative since 2H20 ($bn) | 7.6 | 15.9 | 25 |
| Resilient hydrocarbons (RHC) | ||||
|---|---|---|---|---|
| Investing more in today's oil and gas system, growing EBITDA through the decade | ||||
| 2021 | 2022 | 2025 | 2030 | |
| $71/bbl | $103/bbl | $70/bbl | $70/bbl | |
| RHC EBITDA ($bn) | 30.6 | 56.9 | 40-42 | 39-42 |
| RHC capital expenditure ($bn) | 9.1 | 13.0 | 9-11 | 8-10 |
| Oil and gas production (mmboed) |
2.2 | 2.3 | ~2.3 | ~2.0 |
| Unit production costs ($/boe) | ~7 | ~6 | ~6 | |
| LNG portfolio (mtpa) | 18 | 19 | 25 | 30 |
| Biofuels production (mbd) | 26 | 27 | ~50 | ~100 |
| Biogas supply volumes (mboed) | 9 | 12 | ~40 | ~70 |
| Bioenergy EBITDA ($bn) | ~2 | >4 | ||
| Bioenergy expected returns (%) | >15 | |||
| Bioenergy cumulative capex (2023-30) ($bn) | ~15 | |||
| Convenience and mobility (C&M) | ||||
|---|---|---|---|---|
| Aim to double EBITDA to $9-11bn by 2030 with returns of 15-20% | ||||
| 2021 | 2022 | 2025 | 2030 | |
| C&M EBITDA (bn) | 4.4 | 4.3 | 7 | 9-11 |
| C&M captital expenditure ($bn) | 1.6 | 1.8 | 2-3 | 3-4 |
| Customer touchpoints per day (million) | >12 | ~12 | >15 | >20 |
| Strategic convenience sites | 2,150 | 2,400 | ~3,000 | ~3,500 |
| EV charge points (000) | ~13 | ~22 | >40 | >100 |
| Rapid and ultra fast charging points as a % of total (%) | ~50 | >60 | ~90 | |
| EV charging installed capacity (GW) | ~10 | |||
| EV charging energy sales (TWh) | ~15 | |||
| C&M expected returns (%) | 15-20 | |||
| Convenience and EV charging expected returns (%) | >15 | |||
| Convenience and EV charging EBITDA ($bn) | >1.5 | >4 | ||
| EV charging EBITDA ($bn) | ~2 | |||
| Convenience gross margin growth (%), constant fx, CAGR (2022-30) | ~10 | |||
| Low carbon energy (LCE) | ||||
|---|---|---|---|---|
| Aim to grow EBITDA to $2-3bn by 2030 | ||||
| 2021 | 2022 | 2025 | 2030 | |
| LCE EBITDA ($bn) | Growth phase | 2-3 | ||
| LCE capital expenditure ($bn) | 1.3 | 1.0 | 3-5 | 3-5 |
| Hydrogen production (mpta net) | 0.5-0.7 | |||
| Renewables (GW net developed to FID) | 4.4 | 5.8 | 20 | 50 |
| Renewables (GW net installed) | 1.9 | 2.2 | ~10 | |
| Hydrogen expected returns (unlevered) | Double digit | |||
| Renewables expected returns - (unlevered) (%) | 6-8 | |||
