Energy with purpose means transforming while performing.

Energy with purpose

BPX Energy:

Delivering synergies

We have been transforming BPX Energy,

our US onshore oil and gas business,

with the purchase of world-class

unconventional assets from BHP.

• The acquisition gave us access to

some of the best basins in the

onshore US, with 487,000 acres of

leasehold across a new position in the

liquids-rich Permian-Delaware basin,

and two positions in the Eagle Ford

and Haynesville basins.

• It positions BP as a top producer in

the region.

Good progress

Since we began operating the assets,

we have delivered synergies of

$240 million in 2019, above our

planned target of $90 million.

Energy with purpose means

transforming while performing.

130 BP Annual Report and Form 20-F 2019

131BP Annual Report and Form 20-F 2019

Financial statements

Consolidated ﬁnancial statements of the BP group

Independent auditor’s reports 132

Group income statement 152

Group statement of comprehensive income 153

Group statement of changes in equity 154

Group balance sheet 155

Group cash ﬂow statement 156

Notes on ﬁnancial statements

1. Signiﬁcant accounting policies 157

2. Non-current assets held for sale 173

3. Business combinations and other

signiﬁcant transactions 174

4. Disposals and impairment 175

5. Segmental analysis 177

6. Revenue from contracts with customers 180

7. Income statement analysis 180

8. Exploration expenditure 181

9. Taxation 181

10. Dividends 184

11. Earnings per share 184

12. Property, plant and equipment 186

13. Capital commitments 187

14. Goodwill 187

15. Intangible assets 188

16. Investments in joint ventures 189

17. Investments in associates 189

18. Other investments 191

19. Inventories 191

20. Trade and other receivables 192

21. Valuation and qualifying accounts 192

22. Trade and other payables 193

23. Provisions 193

24. Pensions and other post-retirement beneﬁts 194

25. Cash and cash equivalents 200

26. Finance debt 200

27. Capital disclosures and net debt 201

28. Leases 202

29. Financial instruments and ﬁnancial 202

risk factors

30. Derivative ﬁnancial instruments 207

31. Called-up share capital 215

32. Capital and reserves 216

33. Contingent liabilities 219

34. Remuneration of senior management 220

and non-executive directors

35. Employee costs and numbers 221

36. Auditor’s remuneration 221

37. Subsidiaries, joint arrangements 222

and associates

38. Condensed consolidating information 223

on certain US subsidiaries

Supplementary information on oil and natural gas (unaudited)

Oil and natural gas exploration 233

and production activities

Movements in estimated net proved reserves 239

Standardized measure of discounted future 254

net cash ﬂows and changes therein relating

to proved oil and gas reserves

Operational and statistical information 257

Parent company ﬁnancial statements of BP p.l.c.

Company balance sheet 260

Company statement of changes in equity 261

Notes on ﬁnancial statements 262

1. Signiﬁcant accounting policies 262

2. Investments 265

3. Receivables 265

4. Pensions 265

5. Payables 269

6. Taxation 269

7. Called-up share capital 270

8. Capital and reserves 270

9. Financial guarantees 271

10. Share-based payments 271

11. Auditor’s remuneration 271

12. Directors’ remuneration 271

13. Employee costs and numbers 272

14. Related undertakings 273

Consolidated financial statements of the BP group

This page does not form part of BP's Annual Report on Form 20-F as filed with the SEC.

132 BP Annual Report and Form 20-F 2019

Independent auditor’s report on the Annual Report and Accounts to the members of BP

p.l.c.

Report on the audit of the financial statements

Opinion

In our opinion:

• The financial statements of BP p.l.c. (the ‘parent company’) and its subsidiaries (the ‘group’) give a true and fair view of the state of the

group’s and of the parent company’s affairs as at 31 December 2019 and of the group’s profit for the year then ended.

• The group financial statements have been properly prepared in accordance with International Financial Reporting Standards (IFRSs) as

adopted by the European Union (EU) and IFRSs as issued by the International Accounting Standards Board (IASB).

• The parent company financial statements have been properly prepared in accordance with United Kingdom generally accepted accounting

practice including Financial Reporting Standard (FRS) 101 ‘Reduced Disclosure Framework'.

• The financial statements have been prepared in accordance with the requirements of the Companies Act 2006 and, as regards the group

financial statements, Article 4 of the IAS Regulation.

We have audited the financial statements of BP p.l.c. which comprise the:

• Group income statement;

• Group statement of comprehensive income;

• Group and parent company statements of changes in equity;

• Group and parent company balance sheets;

• Group cash flow statement;

• Group related Notes 1 to 38 to the financial statements, including a summary of significant accounting policies; and

• Parent company related Notes 1 to 14 to the financial statements, including a summary of significant accounting policies.

The financial reporting framework that has been applied in the preparation of the group financial statements is applicable law and IFRSs as

adopted by the European Union and as issued by the IASB. The financial reporting framework that has been applied in the preparation of the

parent company financial statements is applicable law and United Kingdom Accounting Standards, including FRS 101 “Reduced Disclosure

Framework” (United Kingdom Generally Accepted Accounting Practice).

Basis for opinion

We conducted our audit in accordance with International Standards on Auditing (UK) (ISAs (UK)) and applicable law. Our responsibilities under

those standards are further described in the auditor’s responsibilities for the audit of the financial statements section of our report.

We are independent of the group and the parent company in accordance with the ethical requirements that are relevant to our audit of the

financial statements in the UK, including the Financial Reporting Council’s (the ‘FRC’s’) Ethical Standard as applied to listed public interest

entities, and we have fulfilled our other ethical responsibilities in accordance with these requirements. The non-audit services provided to the

group and parent company for the year are disclosed in note 36 to the financial statements. We confirm that the non-audit services prohibited

by the FRC’s Ethical Standard were not provided to the group or the parent company.

We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our opinion.

Summary of our audit approach

Key audit matters The key audit matters that we identified in the current year are as follows:

• Potential impact of climate change and the energy transition (impacting PP&E, goodwill, intangible assets and

provisions);

• Impairment of upstream oil and gas property, plant and equipment (PP&E) assets;

• Impairment of exploration and appraisal assets (included within 'intangible assets' in the Group balance sheet);

• Accounting for structured commodity transactions (SCTs) within the integrated supply and trading (IST) function,

and the valuation of other level 3 financial instruments (potentially impacting all financial statement accounts, in

particular finance debt);

• IT controls relating to financial systems (potentially impacting all financial statement accounts); and

• Management override of controls (potentially impacting all financial statement accounts).

Changes in our key

audit matters since

the prior year

These key audit matters are consistent with those we identified in the prior year except that:

• This year we identified the potential impact of climate change and the energy transition as a key audit matter, given

the significant increase in focus on this issue by management and by external stakeholders, and the potential impact

on the financial statements as a consequence.

• In our report for the year ended 31 December 2018 we identified the accounting for acquisitions and disposals

within the upstream segment as a key audit matter, in large part as a consequence of the accounting complexities

surrounding the $10.3 billion acquisition of BHP Billiton assets in the US. During the current year, there were no

material acquisitions and there were fewer significant accounting complexities and judgements in the disposal

transactions undertaken by BP. Accordingly, we did not identify this as a key audit matter for 2019.

Materiality

We have set materiality for the current year at $850 million (2018 $750 million) based on profit before tax, profit before

impairment charges and tax, and underlying replacement cost profit before interest and tax.

Scoping

Our scope covered 263 components. Of these, 179 were full-scope audits and the remaining 84 were subject to

specific procedures on certain account balances by component audit teams or the group audit team. These covered

81% of group revenue and 75% of PP&E.

Conclusions relating to going concern, principal risks and viability statement

Going concern

We have reviewed the directors’ statement on page 157 to the financial statements about whether they

considered it appropriate to adopt the going concern basis of accounting in preparing them and their

identification of any material uncertainties to the group’s and company’s ability to continue to do so over a

period of at least 12 months from the date of approval of the financial statements.

We considered as part of our risk assessment the nature of the group, its business model and related

risks including where relevant the impact of Brexit, the requirements of the applicable financial reporting

framework and the system of internal control. We evaluated the directors’ assessment of the group’s

ability to continue as a going concern, including challenging the underlying data and key assumptions

used to make the assessment, and evaluated the directors’ plans for future actions in relation to their

going concern assessment.

We are required to state whether we have anything material to add or draw attention to in relation to that

statement required by Listing Rule 9.8.6R(3) and report if the statement is materially inconsistent with

our knowledge obtained in the audit.

Going concern is the basis of

preparation of the financial

statements that assumes an

entity will remain in operation

for a period of at least 12

months from the date of

approval of the financial

statements.

We confirm that we have nothing

material to report, add or draw

attention to in respect of these

matters.

Principal risks and viability statement

Based solely on reading the directors’ statements and considering whether they were consistent with

the knowledge we obtained in the course of the audit, including the knowledge obtained in the evaluation

of the directors’ assessment of the group’s and the company’s ability to continue as a going concern, we

are required to state whether we have anything material to add or draw attention to in relation to:

• the disclosures on pages 68-71 that describe the principal risks, procedures to identify emerging risks,

and an explanation of how these are being managed or mitigated;

• the directors' confirmation on page 128 that they have carried out a robust assessment of the principal

and emerging risks facing the group, including those that would threaten its business model, future

performance, solvency or liquidity; or

• the directors’ explanation on page 129 as to how they have assessed the prospects of the group, over

what period they have done so and why they consider that period to be appropriate, and their

statement as to whether they have a reasonable expectation that the group will be able to continue in

operation and meet its liabilities as they fall due over the period of their assessment, including any

related disclosures drawing attention to any necessary qualifications or assumptions.

We are also required to report whether the directors’ statement relating to the prospects of the group

required by Listing Rule 9.8.6R(3) is materially inconsistent with our knowledge obtained in the audit.

Viability means the ability of

the company to continue over

the time horizon considered

appropriate by the directors,

which for BP is three years.

We confirm that we have nothing

material to report, add or draw

attention to in respect of these

matters.

Key audit matters

Key audit matters are those matters that, in our professional judgement, were of most significance in our audit of the financial statements of

the current period and include the most significant assessed risks of material misstatement (whether or not due to fraud) that we identified.

These matters included those which had the greatest effect on: the overall audit strategy; the allocation of resources in the audit; and directing

the efforts of the engagement team. All of these matters were considered and discussed with the audit committee as described on page 93.

Throughout the course of our audit we identify risks of material misstatement ('risks'). We consider both the likelihood of a risk and the

potential magnitude of a misstatement in making the assessment. Certain risks are classified as 'significant' or 'higher' depending on their

severity. The category of the risk determines the level of evidence we seek in providing assurance that the associated financial statement item

is not materially misstated.

These matters were addressed in the context of our audit of the financial statements as a whole, and in forming our opinion thereon, and we

do not provide a separate opinion on these matters.

This page does not form part of BP's Annual Report on Form 20-F as filed with the SEC.

BP Annual Report and Form 20-F 2019 133

Potential impact of climate change and the energy transition (impacting PP&E, goodwill, intangible assets and provisions)

Key audit matter description How the scope of our audit responded to the key audit matter

Climate change impacts BP’s business in a number of ways as set

out in the strategic report on pages 2-71 of the Annual Report and

Accounts.

It represents a strategic challenge with its implications becoming

increasingly significant towards 2050 and beyond. Whilst many of

BP’s oil and gas properties and refining assets are long-term in

nature, none are being amortised over a period that extends beyond

this date. At current rates of depreciation, depletion and amortisation

(DD&A), the average life of the upstream PP&E is seven years and the

downstream PP&E is 13 years. Accordingly, the related principal risks

that we have identified for our audit are as follows:

• Forecast assumptions used in assessing the value of assets

within BP’s balance sheet for impairment testing, particularly oil

and gas price assumptions relevant to upstream oil and gas

PP&E assets, may not appropriately reflect changes in supply

and demand due to climate change and the energy transition

(see 'impairment of upstream PP&E' below);

• Recoverability of exploration and appraisal (E&A) assets included

within BP’s balance sheet where the investment required in

order to develop particular projects into producing oil and gas

PP&E assets might not be sanctioned by the board in future due

to climate change considerations or a potential development

may not be considered to be economic due to the impact of

climate change and the energy transition on oil and gas prices

(see 'impairment of exploration and appraisal assets' below)

Management also assessed the following potential risks that could

arise from climate change considerations.

• The carrying value of goodwill may no longer be recoverable and

therefore may need to be impaired;

• The useful economic lives of the group’s PP&E may be

shortened as society moves towards 'net zero' emissions

targets, such that the DD&A charge is materially understated;

• Decommissioning and asset retirement obligations may need to

be brought forward with a resulting increase in the present value

of the associated liabilities; and

• Climate change-related litigation brought against BP, as disclosed

in Note 33 to the financial statements and described on page 320

under legal proceedings, may lead to an outflow of funds

requiring provision in the current year.

The material upstream goodwill balance is recorded and tested at the

segment level. The most significant assumption in the goodwill

impairment test affected by climate change relates to future oil and

gas prices (see 'impairment of upstream PP&E' below). Given the

significant headroom in the goodwill impairment test, management

identified no other assumption that could lead to a material

misstatement of goodwill due to the energy transition and other

climate change factors. Disclosures in relation to sensitivities for

goodwill are included within Note 14 on pages 187-188.

The downstream segment has a goodwill balance at 31 December

2019 of $3.9 billion, of which the most significant element is $2.8

billion relating to the Lubricants business. Notwithstanding the

expected global transition to electric vehicles, management noted

that demand for lubricants is forecast to continue to grow until at

least 2040, underpinning the substantial headroom in the most recent

impairment test as described in Note 14.

As described on pages 70-71 and in Note 1, the impact of potential

changes in DD&A charges, or to decommissioning dates would not

have a material impact on the amounts reported in the current period.

Overall response

We held discussions with management, with Deloitte specialists and

within the Group engagement team to identify the areas where we

felt climate change could have a potential impact on the financial

statements.

We also established a climate change steering committee comprising

a group of senior partners with specific sustainability and technical

audit and accounting expertise within Deloitte to provide an

independent challenge to our key decisions and conclusions with

respect to this area.

Audit procedures in respect of impairment of upstream oil and gas

PP&E assets and exploration and appraisal assets

The audit response related to the two principal risks identified is set

out under the key audit matters for impairment of upstream oil and

gas PP&E assets on pages 135-136 and the impairment of exploration

and appraisal assets on page 137.

Other audit procedures performed

We challenged management’s assertion that the impact of potential

changes in DD&A charges, or to decommissioning dates, would not

have a material impact on the amounts reported in the current period,

by making inquiries of relevant BP personnel outside the finance

function, reviewing internal and external documents and conducting

sensitivity analysis as part of our audit risk assessment procedures.

We obtained third party forecasts of future refined petroleum product

demand for those countries which are included in our group full audit

scope for downstream, under a range of scenarios including

scenarios noted as being consistent with achieving the 2015 COP 21

Paris agreement goal to limit temperature rises to well below 2°C

('Paris 2°C Goal'). These indicated that global demand for such

products was expected to remain significant until at least 2040.

We performed procedures to satisfy ourselves that, other than future

oil and gas price assumptions, there were no other assumptions in

management's goodwill calculations to which reasonably possible

changes could cause goodwill to be materially misstated.

We obtained an understanding of the controls identified by management

as being relevant to ensuring the completeness and accuracy of litigation

and climate change related disclosure within the Annual Report; we

performed procedures to test these controls.

With regard to climate change litigation, we designed procedures

specifically to respond to the risks that provisions could be

understated or that contingent liability disclosures may be omitted or

be inaccurate including:

• Holding discussions with the group general counsel and other

senior BP lawyers regarding climate change matters;

• Conducting a search for climate change litigation and claims

brought against the group; and

• Making written inquiries of, and holding discussions with,

external legal counsel advising BP in relation to climate change

litigation.

We read the other information included in the Annual Report and

considered (a) whether there was any material inconsistency

between the other information and the financial statements; or (b)

whether there was any material inconsistency between the other

information and our understanding of the business based on audit

evidence obtained and conclusions reached in the audit.

The above considerations were a significant focus of management

during the period which led to this being a matter that we

communicated to the audit committee, and which had a significant

effect on the overall audit strategy. We therefore identified this as a

key audit matter.

This page does not form part of BP's Annual Report on Form 20-F as filed with the SEC.

134 BP Annual Report and Form 20-F 2019

Impairment of upstream oil and gas property, plant and equipment (PP&E) assets

Key audit matter description How the scope of our audit responded to the key audit matter

The group balance sheet includes property, plant and equipment (PP&E)

of $133 billion (2018 $135 billion), of which $90 billion (2018 $99 billion)

is oil and gas properties within the upstream segment.

Management announced an approximately $10 billion disposal

programme for 2019 and 2020. As a consequence of this, certain

assets identified for disposal have been assessed for impairment in

the context of their fair value based on the expected disposal

proceeds from third parties, as opposed to their value in use.

The transition to a lower carbon global economy may potentially lead

to a lower oil and gas price scenario in the future due to declining

demand. Management took into account considerations of

uncertainty over the pace of the transition to lower-carbon supply and

demand and the social, political and environmental actions that will

be taken to meet the goals of the Paris climate change agreement

when determining their future oil and gas price assumptions and

revised the future price assumptions downwards when compared

with the prior year assumptions as set out in Note 1 on page 162. As

a consequence, they identified a risk of impairment across all

upstream CGUs.

Accordingly, as required by International Accounting Standard (IAS)

36 'Impairment of Assets', management performed a review of all

the upstream cash generating units (CGUs) for indicators of

impairment and impairment reversal as at 31 December 2019.

Further information has been provided in Note 1.

In large part due to the disposal programme, for the year ended 31

December 2019, BP recorded $5,871 million (2018 $400 million) of

upstream impairment charges and $129 million (2018 $580 million) of

impairment reversals. Through our risk assessment procedures, we

have determined that there are three key estimates in management’s

determination of the level of impairment charge/reversal to record.

These are:

• Oil and gas prices - BP’s oil and gas price assumptions have a

significant impact on CGU impairment assessments and

valuations performed across the portfolio, and are inherently

uncertain. Furthermore, as noted above the estimation of future

oil and gas prices is subject to increased uncertainty, given

climate change and the global energy transition. There is a risk

that management’s oil and gas price assumptions are not

reasonable, leading to a material misstatement. The assumptions

are highly judgemental.

We tested management’s internal controls over the setting of oil and

gas prices, discount rates and reserve estimates, as well as the

controls over the performance of the impairment valuation tests. In

addition, we conducted the following substantive procedures.

Oil and gas prices

• We independently developed a reasonable range of forecasts

based on external data obtained, against which we compared the

company’s future oil and gas price assumptions in order to

challenge whether they are reasonable.

• In developing this range we obtained a variety of reputable third

party forecasts, peer information and market data.

• In challenging management's price assumptions, we considered

the extent to which they and each of the forecast pricing

scenarios obtained from third parties reflect the impact of lower

oil and gas demand due to climate change. We specifically

reviewed third party forecasts stated as being, or interpreted by

us as being, consistent with achieving the Paris 2°C Goal and

considered whether they presented contradictory evidence.

• We reviewed and challenged management’s disclosures

including in relation to the sensitivity of oil and gas price

assumptions to reduced demand scenarios whether due to

climate change or other reasons.

Discount rates

• We independently evaluated BP’s discount rates used in

impairment tests with input from Deloitte valuation specialists.

• We assessed whether country risks and tax adjustments were

appropriately reflected in BP’s discount rates.

Reserves estimates

• We reviewed BP’s reserves estimation methods and policies,

assisted by Deloitte reserves experts.

• We assessed, with the assistance of Deloitte reserves experts,

how these policies had been applied to a sample of internal

reserves estimates.

• We reviewed reports provided by external experts and assessed

their scope of work and findings.

Key observations Key observations in relation to oil and gas price assumptions used in upstream oil and gas PP&E assets

impairment tests, and the recoverability of exploration and appraisal assets including the impacts of climate

change, are set out in the relevant key audit matter below.

Based on the audit evidence obtained both from internal and external legal counsel, we were satisfied with

management’s assertion that no provision should currently be made in respect of climate change litigation.

We reviewed management’s disclosure of the contingent liabilities in respect of these matters and concluded

that the disclosures are appropriate.

We were satisfied with the results of our procedures relating to DD&A charges, goodwill and

decommissioning.

We are satisfied that management’s other disclosures in the Annual Report relating to climate change are

consistent with the financial statements and our understanding of the business.

This page does not form part of BP's Annual Report on Form 20-F as filed with the SEC.

BP Annual Report and Form 20-F 2019 135

Impairment of upstream oil and gas property, plant and equipment (PP&E) assets (continued)

Key audit matter description How the scope of our audit responded to the key audit matter

• Discount rates - Given the long timeframes involved, certain

recoverable amounts of assets are sensitive to the discount rate

applied. There is a risk that discount rates do not reflect the

return required by the market and the risks inherent in the cash

flows being discounted, leading to a material misstatement.

Determination of the appropriate discount rate can be

judgemental.

• Reserves estimates - A key input to impairment assessments

and valuations is the production forecast, in turn closely related

to the group’s reserves estimates and field development

assumptions. CGU-specific estimates are not generally material.

However, material misstatements could arise either from

systematic flaws in reserves estimation policies, or due to flawed

estimates in a particularly material individual impairment test.

We identified and focused on certain individual CGUs with a total

carrying value of $12.3 billion (2018 $21.8 billion) which we

determined would be most at risk of a material impairment as a result

of a reasonably possible change in the key assumptions, particularly

the oil and gas price assumptions. Accordingly, we identified these as

a significant audit risk. We also focused on assets with a further $33.4

billion (2018 $31.5 billion) of combined CGU carrying value which

were less sensitive. We identified these as a higher audit risk as they

would be potentially at risk in aggregate to a material impairment by a

change in such assumptions. Further information regarding these

sensitivities is given in Note 1 to the consolidated financial

statements.

• We assessed the competence, capability and objectivity of BP’s

internal and external reserve experts, through obtaining their

relevant professional qualifications and experience.

• We compared hydrocarbon production forecasts used in

impairment tests to estimates and reports and our

understanding of the life of fields.

• We performed a retrospective review to check for indications of

estimation bias over time.

Other procedures

• We challenged management’s cash generating unit

determination and considered whether there was any

contradictory evidence present.

• We validated that BP’s asset impairment methodology was

appropriate and tested the integrity of impairment models.

• Where relevant, we also assessed management’s historical

forecasting accuracy and whether the estimates had been

determined and applied on a consistent basis across the group.

Since 31 December 2019, the oil price has fallen sharply in large part

due to the impact of the international spread of COVID-19

(Coronavirus) and geopolitical factors. As part of our post balance

sheet audit procedures we considered whether these events provide

evidence of conditions that existed at the balance sheet date.

Key observations Oil and gas prices

The long-term oil and gas price assumptions used to determine recoverable amount through value-in-use

impairment tests are derived from the central case long term price assumption used for investment

appraisal purposes (as set out on page 19) and represent management’s best estimate of future prices as

set out in Note 1. We determined that BP’s oil and gas price assumptions are reasonable when compared

against the range of third party forecasts we identified as being appropriate for the purpose. In forming

this view, we included each forecaster’s 'best case', 'central case' or 'most likely' estimate.

For the purpose of PP&E impairment tests, management is required under IAS 36 to apply its current

'best estimate' of future oil and gas prices.

We observed that, as well as publishing a 'best case', 'central case' or 'most likely' estimate, the majority

of third party price forecasters publish a number of other future scenarios under different plausible

economic assumption sets, and that the price forecasts stated as being or interpreted by us as being

'Paris 2°C Goal' scenarios were the lowest of all scenarios from those forecasters. We observed that for

oil, all the prices in third party 'Paris 2°C Goal' scenarios in our sample were lower than BP’s oil price

assumption from 2023 onwards, and for gas, BP's price assumptions for impairment purposes were

close to the highest 'Paris 2°C Goal' scenario.

While these 'Paris 2°C Goal' scenarios indicate that BP’s price assumptions for impairment purposes are

not consistent with the world being on a path to achieving the Paris 2°C Goal we observed that none of

those third party forecasters described their 'Paris 2°C Goal' scenarios as their 'best case', 'central case'

or “most likely” estimate.

We reviewed the disclosures included in Note 1 to the accounts in respect of price assumptions,

including the sensitivity analysis presented therein. We observed that the second downside sensitivity, in

which prices start 15% lower than the best estimate and gradually reduce to 25% lower than the best

estimate by 2040, is within the range of third party Paris 2°C Goal forecasts both for oil and for gas albeit

towards the upper end for oil.

We are satisfied that the COVID-19 outbreak and the geopolitical factors are both non-adjusting events

and accordingly the recent sharp fall in the oil price is a result of conditions that arose after the balance

sheet date. As such we concluded that management’s future oil and gas price assumptions used in

impairment tests to assess the recoverable amount of assets at the balance sheet date should not be

adjusted.

Discount rates

BP’s post-tax nominal 6% weighted average cost of capital, used as the starting point for setting discount

rates used for impairment testing, was within the independent range calculated by our Deloitte valuation

specialists.

We were also satisfied with the calculation of country risk premia. When the rates were grossed up for

tax as required for impairment testing the rates for a small number of countries fell outside of our

reasonable range but there was an insignificant impact in respect of a small number of CGUs.

Accordingly, we are satisfied with the discount rates used in the impairment testing.

This page does not form part of BP's Annual Report on Form 20-F as filed with the SEC.

136 BP Annual Report and Form 20-F 2019

Key observations We reviewed the disclosures included in Note 1 to the accounts in respect of discount rate assumptions

used and confirmed that they are consistent with the IFRS disclosure requirements.

Reserves estimates

We concluded that the assumptions used to derive the estimates were reasonable.

Impairment of exploration and appraisal assets (included within intangible assets within the Group balance sheet)

Key audit matter description How the scope of our audit responded to the key audit matter

The group capitalizes exploration and appraisal (E&A) expenditure on

a project-by-project basis in line with IFRS 6 'Exploration for and

Evaluation of Mineral Resources'. At the end of 2019, $14 billion

(2018 $16 billion) of E&A expenditure was carried in the group

balance sheet. E&A activity is inherently risky and a significant

proportion of projects fail, requiring the write-off of the related

capitalized costs when the relevant criteria in IFRS 6 and BP’s

accounting policy are met.

There is a significant judgement relating to the risk that certain

capitalized E&A costs are not written off promptly at the appropriate

time, in line with information from, and decisions about E&A

activities, and the impairment requirements of IFRS 6.

Furthermore, similar to upstream PP&E assets discussed above, E&A

assets are also potentially exposed to climate change and the global

energy transition. A greater number of projects may be expected not

to proceed as a consequence of lower forecast future demand, lower

appetite by management and the board to allocate capital to certain

projects, or increased objections from stakeholders to the

development of certain projects. In response, management has

updated its internal controls over its IFRS 6 assessment to reflect the

potential impact that climate change and the energy transition may

have on E&A assets.

In the prior year audit, we had identified this key audit matter as a

significant risk primarily on account of uncertainty arising from the

potential inability of the Company to secure key license extensions

in respect of assets in the Gulf of Mexico and on three licenses in

other regions.

During the current year, and subsequent to the year end,

management have obtained licence extensions in the Gulf of Mexico

and other regions such that we have concluded this no longer

represents a significant audit risk. Nevertheless, given the inherent

uncertainty associated with the development and deployment of

these assets, we still consider this area to be a higher risk.

We obtained an understanding of the group’s E&A impairment

assessment processes and tested management’s internal controls,

including the new control procedures implemented to address

potential climate change considerations.

We performed a licence-by-licence risk assessment of the group’s

E&A balance through to year end, to identify significant carrying

amounts with a current period risk of impairment (e.g. new

information from exploration activities, or imminent licence expiry).

We performed a retrospective review of impairment charges

recorded in the period, and assessed whether impairment charges

were timely.

We reviewed and challenged management’s significant IFRS 6

impairment judgements, having regard to the impairment criteria of

IFRS 6 and BP’s accounting policy. We verified key facts relevant to

significant carrying amounts (by obtaining for example evidence of

future E&A plans and budgets, and evidence of active dialogue with

partners and regulators including negotiations to renew licences or

modify key terms).

We tested the completeness and accuracy of information used in

management’s E&A impairment assessment, by reviewing and

testing key controls over management’s register of E&A licences and

agreeing key aspects of this to underlying support (e.g. licence

documentation); holding meetings and discussions with operational

and finance management; considering adverse changes in

management’s reserves and resource estimates associated with E&A

assets; reviewing correspondence with regulators and joint

arrangement partners; and considering the implications of capital

allocation decisions. When considering capital allocation decision

making, we considered whether the development of any projects

would be inconsistent with the elements of BP’s current strategy

which are designed to ensure it is resilient to the energy transition

and climate change considerations or which would otherwise have a

prohibitively high environmental or social impact for the directors to

sanction the necessary investment.

Key observations We concluded that the key assumptions had been appropriately determined, the judgements management

had made were appropriately supported, and no additional impairments were identified from the work we

performed.

Where E&A costs were carried in respect of projects where licences had previously expired, we obtained

evidence that these licences have been renewed.

We also confirmed management's view that they did not consider that the development of any of their

E&A assets is inconsistent with BP’s current strategy. In that context we particularly considered the

Canadian oil sands assets (see Note 1) and concluded that, given low-carbon extraction technologies

required to optimise the development of these assets are being researched, continuing to carry the

assets was consistent with IFRS6.

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BP Annual Report and Form 20-F 2019 137

Accounting for structured commodity transactions (SCTs) within the integrated supply and trading function (IST), and the valuation

of other level 3 financial instruments, where fraud risks may arise in revenue recognition (potentially impacting all financial

statement accounts, in particular finance debt)

Key audit matter description How the scope of our audit responded to the key audit matter

In the normal course of business, IST enters into a variety of

transactions for delivering value across the group’s supply chain. The

nature of these transactions requires significant audit effort be

directed towards challenging management’s valuation estimates or

the adopted accounting treatment.

Accounting for structured commodity transactions: IST may also

enter into a variety of transactions which we refer to as SCTs. We

generally consider a SCT to be an arrangement having one of the

following features:

a) two or more counterparties with non-standard contractual

terms;

b) multiple commodity-based transactions; and/or

c) contractual arrangements entered into in contemplation of each

other.

SCTs are often long-dated, can have a significant multi-year financial

impact, and may require the use of complex valuation models or

unobservable market inputs when determining their fair value, in

which case they will be classified as level 3 financial instruments

under IFRS 13, Fair Value Measurement.

Accounting for SCTs is often complex and involves significant

judgement, as these transactions often feature multiple elements

that will have a material impact on the presentation and disclosure of

these transactions in the financial statements and on key

performance measures, including in particular classification of

liabilities as finance debt. We have identified the accounting for SCTs

as a significant audit risk.

Level 3 financial instruments: Unlike other financial instruments

whose values or inputs are readily observable and therefore more

easily independently corroborated, there are certain transactions for

which the valuation is inherently more subjective due to the use of

either complex valuation models and/or unobservable inputs. These

instruments are classified as level 3 financial assets or liabilities

under IFRS 13. This degree of subjectivity also gives rise to potential

fraud through management incorporating bias in determining fair

values. Accordingly, we have identified these as a significant audit

risk.

As at 31 December 2019, the group’s total financial assets and

liabilities measured at fair value were $12.5 billion (2018 $12.8 billion)

and $8.8 billion (2018 $8.9 billion), of which level 3 derivative financial

assets were $5.3 billion (2018 $3.6 billion) and level 3 derivative

financial liabilities were $4.4 billion (2018 $3.1 billion).

Accounting for structured commodity transactions:

For structured commodity transactions, we performed audit

procedures to:

• Test controls related to the transactions.

• Develop an understanding of the commercial rationale of the

transactions through review of transaction support documents

and executed agreements, and discussions with management.

• Perform a detailed accounting analysis for a sample of structured

commodity transactions involving significant day 1 profits,

deferred working capital arrangements, offtake arrangements

and/or commitments.

To assess the appropriateness of the accounting treatment of SCTs,

we embedded technical accounting specialists within the audit team.

During the year we identified two new SCTs which were subjected to

our audit procedures listed above. We also reconsidered the SCTs

which were identified during 2018 and which have been subject to

ongoing assessment in 2019.

Other level 3 financial instruments:

To address the complexities associated with auditing the value of

level 3 financial instruments, the engagement team included valuation

specialists having significant quantitative and modelling expertise to

assist in performing our audit procedures. Our valuation audit

procedures included the following control and substantive

procedures:

• We tested the group’s valuation controls including the:

• Model certification control, which is designed to review a

model’s theoretical soundness and the appropriateness of its

valuation methodology; and

• Independent price verification control, which is designed to

review the appropriateness of valuation inputs that are not

observable and are significant to the financial instrument’s

valuation.

We performed substantive valuation testing procedures at interim

and year-end balance sheet dates, including:

• Engaging a Deloitte valuations specialist to develop fair value

estimates, using independently sourced inputs where these

were available, and challenge models to evaluate against

management’s fair value estimates by evaluating whether the

differences between our independent estimates and

management’s estimates were within a reasonable range. In

situations where we utilised management’s inputs, these were

compared to external data sources to ensure they were

reasonable;

• Evaluating management’s valuation methodologies against

standard valuation practice and analysing whether a consistent

framework is applied across the business period over period; and

• Comparing management’s input assumptions against the

expected assumptions of other market participants and

observable market data.

Key observations We reviewed the features of the SCTs and determined that the accounting adopted for each of these was

appropriate and in accordance with IFRS.

We concluded that management’s valuations relating to level 3 instruments were appropriate.

We did not identify any indications of fraudulent misrepresentation of revenue recognition in the

transactions, valuation estimates or accounting entries that we tested.

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138 BP Annual Report and Form 20-F 2019

IT controls relating to financial systems (potentially impacting all financial statement accounts)

Key audit matter description How the scope of our audit responded to the key audit matter

The group’s financial systems environment is complex, with 121

separate systems scoped as being relevant for the group audit.

Due to the reliance on financial systems within the group, IT controls

which support these systems are critical to maintaining an effective

control environment.

We identified IT control deficiencies in two key areas.

User Access Management:

In the prior year, we identified a number of deficiencies relating to

user access management, both within the group and at the

group’s IT service organizations (together ‘access deficiencies’).

Management commenced the implementation of a remediation

programme in the prior year, although this programme extends

into 2020.

During our 2019 audit we identified a number of additional

deficiencies relating to user access management in the IT

environment as a result of new systems in scope, the control of

highly privileged finance access and the management of

segregation of duties.

The access deficiencies identified increase the risk that individuals

across BP had inappropriate access during the period. This results in

an increased risk that data and reports from the affected systems

are not reliable. The access deficiencies impact all components

within the scope of our group audit.

Management remediated some of the deficiencies during 2019. For

the remaining deficiencies, management implemented mitigating

controls to confirm that no inappropriate access had been exploited.

Change Management:

A new change management process and change control ticketing

system, ServiceNow, was implemented for 2019. Following the change

in process and tool a number of deficiencies were identified by Deloitte

and by management around the consistent implementation of the

minimum change management controls.

The change management deficiencies identified increase the risk of

inappropriate or untested changes being made which could negatively

impact the way a system operates and accordingly, the ongoing integrity

of the controls, reports and data within key financial systems.

In responding to the identified deficiencies management have

implemented retrospective approvals for all exceptions identified.

Management also performed a full review of all changes made to all

systems in the scope of our group audit to ensure all changes were

appropriate and that change management controls were documented.

In addition management established a programme to remediate all the

identified deficiencies.

The change management issues identified impact all components

within the scope of our group audit.

Both the user access management controls and the controls over the

management of system change are pervasive to the group’s operations

and accordingly the level of risk ascribed to our work in this area is

dependent on the nature and complexity of the control itself and the

risks addressed by the control.

We obtained an understanding of management’s processes and

relevant financial systems, and tested the associated general IT

controls and automated business controls. We also tested the

integrity of key reports. This testing led us to identify a number of

deficiencies, notably in relation to user access and change

management.

User Access Management:

In responding to the identified deficiencies in user access, our IT

audit specialists performed procedures to:

• Test the controls that management has implemented or re-

designed in order to remediate the deficiencies;

• Assess and test the mitigating controls that management

identified, including directly testing those controls operated by IT

service organizations; and

• Determine the impact that utilizing inappropriate levels of access

could feasibly have had on the affected systems including

assessing the likelihood of inappropriate user access impacting

the financial statements, and test controls implemented by

management to identify instances of the use of inappropriate

access.

Change Management:

In responding to the identified deficiencies our IT audit specialists

performed independent testing over:

• The mitigating controls performed by management; and

• Key automated business controls and the logic and accuracy of key

reports to ensure no changes had impacted their effectiveness.

These procedures were designed to address the likelihood and

impact of inappropriate or untested changes being implemented.

Key observations Our testing confirmed that the remediated controls were operating effectively.

Our testing of the mitigating controls management performed, alongside our independent testing to

demonstrate whether the access and change management deficiencies were exploited during the year, did

not identify instances of inappropriate access usage or change implementation.

Accordingly, we were satisfied with the results of the remediation to date and the mitigation such that we

continued to adopt an audit approach which places reliance on the operating effectiveness of financial

controls. Under our methodology, this enables us to apply lower sample sizes in our substantive testing.

Management continues to work to remediate fully the access and change management deficiencies

identified.

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BP Annual Report and Form 20-F 2019 139

Management override of controls (potentially impacting all financial statement accounts)

Key audit matter description How the scope of our audit responded to the key audit matter

We conducted an assessment of the fraud risks arising from

management override of controls by considering potential areas

where the group’s financial statements could be manipulated,

including:

• Inappropriate accounting estimates and judgements; and

• Accounting for significant unusual transactions arising from

changes to the business.

In performing this assessment we considered pressures or

incentives to achieve certain IFRS or non-GAAP measures due to the

remuneration arrangements of people in Financial Reporting

Oversight Roles (FRORs), including management and senior

executives.

During our 2018 audit we identified control deficiencies relating to the

posting of accounting journal entries at the components where

testing was performed. These control deficiencies remain as of the

end of 2019 and extended to other components where testing was

performed. There were also other changes to BP’s processes for the

posting of certain journals which created further deficiencies. As in

the previous year, management directed us to other compensating

controls which they considered to mitigate the risks, which we

subsequently tested. Management has initiated a remediation

programme which will extend into 2020.

This had a significant bearing again this year on the allocation of

resources in the audit, and the direction of effort of the audit team

globally and was a matter we discussed with the audit committee.

Accordingly, we identified this as a key audit matter.

We tested the relevant primary and, where necessary, compensating

controls that management identified as responding to the risk of

fraudulent journal entries.

In addition, we:

• Made inquiries of individuals involved in the financial reporting

process about inappropriate or unusual activity relating to the

processing of journal entries and other adjustments.

• Identified and tested relevant entity-level controls, in particular

those related to the BP Code of Conduct, whistleblowing (BP

OpenTalk) and controls monitoring financial reporting processes

and financial results.

• Used our data analytics tools to select journal entries and other

adjustments made at the end of a reporting period or otherwise

having characteristics which are associated with common fraud

schemes for testing.

• Tested journal entries and other adjustments recorded in the

general ledger throughout the period, with a particular focus on

adjustments that occur late in the financial close process.

We have reviewed accounting estimates for bias and evaluated

whether the circumstances producing the bias, if any, represent a risk

of material misstatement due to fraud. A number of the most

significant estimates are covered by the other Key Audit Matters set

out above. This assessment included:

• Evaluating whether the judgements and decisions made by

management in making the accounting estimates included in the

financial statements, even if they are individually reasonable,

indicate a possible bias on the part of BP's management that

may represent a risk of material misstatement due to fraud; and

• Performing a retrospective review of management judgements

and assumptions related to significant accounting estimates

reflected in the financial statements of the prior year.

We considered whether there were any significant transactions that

are outside the normal course of business, or that otherwise appear

to be unusual due to their nature, timing or size.

The risks and responses to the revenue recognition risks within the

integrated supply and trading function are set out on page 138.

Key observations The nature of the identified deficiencies over journal entry controls varies from business to business, so

there is no single root cause. Management identified compensating controls to mitigate the risk

associated with the design deficiencies identified. These included low-level analytical reviews, controls

over closing balances, period-end analytical review controls and certain automated business controls. Our

testing of these compensating controls concluded they were, in combination, appropriately designed and

implemented and that they were operating effectively for the year.

Our substantive testing of journal entries and other adjustments, selected through the use of our data

analytics tools, did not identify any inappropriate items.

We did not identify evidence of overall bias or any significant and unusual transactions for which the

business rationale (or the lack thereof) of the transaction suggested that it may have been entered into to

engage in fraudulent financial reporting or to conceal misappropriation of assets.

Management is continuing to design and implement appropriate process level controls over journal

entries in 2020.

Our application of materiality

We define materiality as the magnitude of misstatement in the financial statements that makes it probable that the economic decisions of a

reasonably knowledgeable person would be changed or influenced. We use materiality both in planning the scope of our audit work and in

evaluating the results of our work.

Based on our professional judgement, we determined materiality for the financial statements as a whole as follows:

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140 BP Annual Report and Form 20-F 2019

Group financial statements Parent company financial statements

Materiality Materiality has been set at $850 million for the current

year. In 2018, we used a materiality of $750 million. The

increase is partly due to BP’s financial performance in

2019 and also the fact that our 2018 materiality level

reflected some conservatism in our first year as auditor.

Materiality has been set at $1,200 million for the

current year. (2018 $1,200 million)

Basis for determining

materiality

We considered a number of metrics when determining

group materiality, including profit before taxation, profit

before impairment charges and taxation and underlying

replacement cost profit before interest and taxation.

Our selected materiality figure represents 10.3% of

profit before taxation, 5.7% of profit before impairment

charges and taxation, and 5.0% of underlying

replacement cost profit before interest and taxation. In

2018, we determined materiality to be $750m which

represented 4.5% of profit before taxation and 3.2% of

underlying replacement cost profit before interest and

taxation. The significant impairment charges of

$6,847m recognized in 2019 caused us to place more

emphasis on profit before impairment charges and

taxation in our determination of materiality this year.

We determined materiality for our audit of the

standalone parent using 1% (2018 1%) of net assets.

Rationale for the

benchmark applied

We conducted an assessment of which line items are

the most important to investors and analysts by

reviewing analyst reports and BP's communications to

shareholders and lenders, as well as the

communications of peer companies. This assessment

resulted in us selecting the financial statement line

items above.

Profit before tax is the benchmark ordinarily considered

by us when auditing listed entities. It provides

comparability against other companies across all

sectors, but has limitations when auditing companies

whose earnings are strongly correlated to commodity

prices, which can be volatile from one period to the

next, and therefore may not be representative of the

volume of transactions and the overall size of the

business in the year, or where the impact of price

volatility may result in material impairment charges or

reversals in a particular year. The significant impairment

charges recognized in 2019 caused us to place more

emphasis on profit before impairment charges and

taxation this year.

Whilst not a GAAP measure, underlying replacement

cost profit before interest and tax is one of the key

metrics communicated by management in BP's results

announcements. It excludes some of the volatility

arising from changes in crude oil, gas and product

prices as well as non-operating items.

The materiality determined for the standalone parent

company financial statements exceeds the group

materiality as it is determined on a different basis given

the nature of the parent company operations. As the

company is non…trading and operates primarily as a

holding company, we believe the net asset position is

the most appropriate benchmark to use.

Where there were balances and transactions within the

parent company accounts that were within the scope

of the audit of the group financial statements, our

procedures were undertaken using the lower

materiality level applying to the group audit

components. It was only for the purposes of testing

balances not relevant to the group audit, such as

intercompany investment balances, that the higher

level of materiality applied in practice.

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BP Annual Report and Form 20-F 2019 141

Performance materiality

We set performance materiality at a level lower than materiality to reduce the probability that, in aggregate, uncorrected and undetected

misstatements exceed the materiality for the financial statements as a whole. Group performance materiality was set at 60% of group

materiality for the 2019 audit (2018 50%). The increase was due to performance materiality being set at a conservative level for 2018, given it

was our first year as auditor, and to reflect our increased knowledge of the business.

Error reporting threshold

We agreed with the audit committee that we would report to the committee all audit differences in excess of $35 million (2018 $25 million), as

well as differences below that threshold that, in our view, warranted reporting on qualitative grounds. We also report to the audit committee on

disclosure matters that we identified when assessing the overall presentation of the financial statements.

An overview of the scope of our audit

Identification and scoping of components

As a result of the highly disaggregated nature of the group, with operations in over 70 countries through approximately 1,000 components, a

significant portion of our audit planning effort was ensuring that the scope of our work is appropriate in addressing the identified risks of

material misstatement.

The factors that we considered when assessing the scope of the BP audit, and the level of work to be performed at the components that are

in scope for group reporting purposes, included the following:

• The financial significance of an operating unit to BP’s revenue and profit before tax, or PP&E, including consideration of the financial

significance of specific account balances or transactions.

• The significance of specific risks relating to an operating unit, history of unusual or complex transactions, identification of significant audit

issues or the potential for, or a history of, material misstatements.

• The effectiveness of the control environment and monitoring activities, including entity-level controls.

• The findings, observations and audit differences that we noted as a result of our 2018 audit engagement.

Our audit approach was generally to place reliance on management’s controls over financial reporting.

To ensure we were able to obtain sufficient, appropriate audit evidence for the purposes of our audit of the financial statements, we performed

full scope audit procedures for 179 reporting consolidation units ('cons units' or components) (2018 108) which were selected based on their

size or risk characteristics. The primary reason for the change in scope is a change in our approach to the global audit of the IST function. We

also added to our full scope audit components for 2019 the new businesses acquired in onshore US in 2018 from BHP. Our full-scope audits are

in the UK, US, Azerbaijan, Germany and Singapore. One of the full-scope cons units includes the investment in Rosneft, a material associate

not controlled by BP.

In addition, component teams performed audit procedures on specified account balances for 55 cons units (2018 16) also covering operations

in Angola, Alaska, Trinidad & Tobago and Australia. The group engagement team performed audit procedures on specified account balances by

segment teams to component materiality, with certain additional specific procedures performed by component teams, covering an additional

29 cons units (2018 12).

In our assessment of the residual balances, we have considered in particular the risk that there could be a material misstatement within the

large number of geographically dispersed businesses, in particular within the downstream segment. This assessment included use of our

analytic tools to interrogate data, preparation of trend analysis and comparison of business performance to market benchmark prices. We

concluded that through this additional risk assessment, we have reduced the audit risk of such a misstatement arising to a sufficiently low

level.

The remaining components are not significant individually and include many small, low risk components and balances. On average, they each

represent 0.03% of group revenue (2018 0.06%) and 0.03% of property, plant and equipment (2018 0.08%). For these components, we

performed other procedures, including conducting analytical review procedures, making inquiries, and evaluating and testing management's

group-wide controls across a range of locations and segments in order to address the risk of residual misstatement on a segment-wide and

component basis.

Working with other auditors

The group audit team provides direct oversight, review, and coordination of our component audit teams. The group audit team interacted

regularly with the compnent Deloitte teams during each stage of the audit, were responsible for the scope and direction of the audit process

and reviewed key working papers. We maintained continuous and open dialogue with our component teams in addition to holding formal

meetings quarterly to ensure that we were fully aware of their progress and results of their procedures.

The senior statutory auditor and other group audit partners and staff conducted visits to meet with the component teams responsible for all of

the full scope locations during the year as well as Egypt, Trinidad & Tobago, and key Global Business Services (GBS) accounting locations. These

visits included attending planning meetings, discussing the audit approach and any issues arising from the component team's work, meetings

with local management, and reviewing key audit working papers on higher and significant-risk areas to drive a consistent and high-quality audit.

In addition, a global audit planning meeting was held in London for two days in July led by the senior statutory auditor and involving the group

audit team, partners and staff from all full scope component teams, audit teams responsible for testing at key GBS locations, senior

management from BP, and the audit committee chairman.

We were provided with direct access to Rosneft's auditor in order to evaluate their audit work on the financial statements of Rosneft, used as

the basis for BP's equity accounting. We held meetings with Rosneft's auditor throughout the year, issued audit instructions to them, reviewed

their written clearance reports responding to these instructions and, through our direct access, were able to exercise appropriate supervision

and oversight of their audit work. We also tested directly BP's procedures and controls over its accounting for the investment in Rosneft.

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142 BP Annual Report and Form 20-F 2019

Other information

The directors are responsible for the other information. The other information comprises the information included

in the annual report, other than the financial statements and our auditor’s report thereon.

Our opinion on the financial statements does not cover the other information and, except to the extent otherwise

explicitly stated in our report, we do not express any form of assurance conclusion thereon.

In connection with our audit of the financial statements, our responsibility is to read the other information and, in

doing so, consider whether the other information is materially inconsistent with the financial statements or our

knowledge obtained in the audit or otherwise appears to be materially misstated.

If we identify such material inconsistencies or apparent material misstatements, we are required to determine

whether there is a material misstatement in the financial statements or a material misstatement of the other

information. If, based on the work we have performed, we conclude that there is a material misstatement of this

other information, we are required to report that fact.

In this context, matters that we are specifically required to report to you as uncorrected material misstatements

of the other information include where we conclude that:

• Fair, balanced and understandable - the statement given by the directors that they consider the annual report

and financial statements taken as a whole is fair, balanced and understandable and provides the information

necessary for shareholders to assess the group’s position and performance, business model and strategy, is

materially inconsistent with our knowledge obtained in the audit; or

• Audit committee reporting - the section describing the work of the audit committee does not appropriately

address matters communicated by us to the audit committee; or

• Directors’ statement of compliance with the UK Corporate Governance Code - the parts of the directors’

statement required under the Listing Rules relating to the company’s compliance with the UK Corporate

Governance Code containing provisions specified for review by the auditor in accordance with Listing Rule

9.8.10R(2) do not properly disclose a departure from a relevant provision of the UK Corporate Governance

Code.

We have nothing to

report in respect of

these matters.

Responsibilities of directors

As explained more fully in the directors’ responsibilities statement, the directors are responsible for the preparation of the financial statements

and for being satisfied that they give a true and fair view, and for such internal control as the directors determine is necessary to enable the

preparation of financial statements that are free from material misstatement, whether due to fraud or error.

In preparing the financial statements, the directors are responsible for assessing the group’s and the parent company’s ability to continue as a

going concern, disclosing as applicable, matters related to going concern and using the going concern basis of accounting unless the directors

either intend to liquidate the group or the parent company or to cease operations, or have no realistic alternative but to do so.

Auditor’s responsibilities for the audit of the financial statements

Our objectives are to obtain reasonable assurance about whether the financial statements as a whole are free from material misstatement,

whether due to fraud or error, and to issue an auditor’s report that includes our opinion. Reasonable assurance is a high level of assurance, but

is not a guarantee that an audit conducted in accordance with ISAs (UK) will always detect a material misstatement when it exists.

Misstatements can arise from fraud or error and are considered material if, individually or in the aggregate, they could reasonably be expected

to influence the economic decisions of users taken on the basis of these financial statements.

Details of the extent to which the audit was considered capable of detecting irregularities, including fraud and non-compliance with laws and

regulations are set out below.

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BP Annual Report and Form 20-F 2019 143

A further description of our responsibilities for the audit of the financial statements is located on the FRC’s website at: frc.org.uk/

auditorsresponsibilities. This description forms part of our auditor’s report.

Extent to which the audit was considered capable of detecting irregularities, including fraud

We identify and assess the risks of material misstatement of the financial statements, whether due to fraud or error, and then design and

perform audit procedures responsive to those risks, including obtaining audit evidence that is sufficient and appropriate to provide a basis for

our opinion.

Identifying and assessing potential risks related to irregularities

In identifying and assessing risks of material misstatement in respect of irregularities, including fraud and non-compliance with laws and

regulations, we considered the following:

• Our meetings throughout the year with the Group Head of Ethics and Compliance and reviews of BP’s internal ethics and compliance

reporting summaries, including those concerning investigations;

• Enquiries of management, internal audit, and the audit committee, including obtaining and reviewing supporting documentation, concerning

the Group’s policies and procedures relating to:

– identifying, evaluating and complying with laws and regulations and whether they were aware of any instances of non-compliance

– detecting and responding to the risks of fraud and whether they have knowledge of any actual, suspected or alleged fraud; and

– the internal controls established to mitigate risks related to fraud or non-compliance with laws and regulations;

• The group’s remuneration policies, key drivers for remuneration and bonus levels; and

• Discussions among the engagement team regarding how and where fraud might occur in the financial statements and any potential

indicators of fraud. The engagement team includes audit partners and staff who have extensive experience of working with companies in the

same sectors as BP operates, and this experience was relevant to the discussion about where fraud risks may arise. The discussions also

involved fraud experts from Deloitte's forensic accounting function in the Financial Advisory service line, who advised the engagement team

of fraud schemes that had arisen in similar sectors and industries and participated in the initial fraud risk assessment discussions.

In common with all audits under ISAs (UK), we are also required to perform specific procedures to respond to the risk of management

override.

We also obtained an understanding of the legal and regulatory framework that the group operates in, focusing on provisions of those laws and

regulations that had a direct effect on the determination of material amounts and disclosures in the financial statements. The key laws and

regulations we considered in this context included the UK Companies Act, UK Corporate Governance Code, IFRS as issued by the IASB and

adopted by the EU, FRS 101, US Securities Exchange Act 1934 and relevant SEC regulations, as well as laws and regulations prevailing in each

country in which we identified a full-scope component.

In addition, we considered provisions of other laws and regulations that do not have a direct effect on the financial statements but compliance

with which may be fundamental to the group’s ability to operate or to avoid a material penalty. These included the group’s operating licences,

environmental regulations etc.

Audit response to risks identified

As a result of performing the above, we did not identify any key audit matters related to the potential risk of fraud or non-compliance with laws

and regulations. We did identify two key audit matters relating to fraud risks, as described above, being the accounting for SCTs and Level 3

instruments within IST, and management override of controls. The key audit matters section of our report explains the matters in more detail

and also describes the specific procedures we performed in response to those key audit matters.

In addition to the above, our procedures to respond to risks identified included the following:

• Reviewing the financial statement disclosures and testing to supporting documentation to assess compliance with provisions of relevant

laws and regulations described as having a direct effect on the financial statements;

• Enquiring of management, the audit committee, and both internal and external legal counsel concerning actual and potential litigation and

claims;

• Performing analytical procedures to identify any unusual or unexpected relationships that may indicate risks of material misstatement due to

fraud;

• Reading minutes of meetings of those charged with governance, reviewing internal audit reports and reviewing correspondence with

relevant tax authorities including HMRC and IRS; and

• In addressing the risk of fraud through management override of controls, testing the appropriateness of journal entries and other

adjustments; assessing whether the judgements made in making accounting estimates are indicative of a potential bias; and evaluating the

business rationale of any significant transactions that are unusual or outside the normal course of business.

We also communicated relevant identified laws and regulations and potential fraud risks to all engagement team members including internal

specialists and significant component audit teams, and remained alert to any indications of fraud or non-compliance with laws and regulations

throughout the audit.

This page does not form part of BP's Annual Report on Form 20-F as filed with the SEC.

144 BP Annual Report and Form 20-F 2019

Report on other legal and regulatory requirements

Opinions on other matters prescribed by the Companies Act 2006

In our opinion the part of the directors’ remuneration report to be audited has been properly prepared in accordance with the Companies Act

2006.

In our opinion, based on the work undertaken in the course of the audit:

• The information given in the strategic report and the directors’ report for the financial year for which the financial statements are prepared

is consistent with the financial statements; and

• The strategic report and the directors’ report have been prepared in accordance with applicable legal requirements.

In the light of the knowledge and understanding of the group and the parent company and their environment obtained in the course of the

audit, we have not identified any material misstatements in the strategic report or the directors’ report.

Matters on which we are required to report by exception

Adequacy of explanations received and accounting records

Under the Companies Act 2006 we are required to report to you if, in our opinion:

• We have not received all the information and explanations we require for our audit; or

• Adequate accounting records have not been kept by the parent company, or returns adequate for our audit

have not been received from branches not visited by us; or

• The parent company financial statements are not in agreement with the accounting records and returns.

We have nothing to

report in respect of

these matters.

Directors’ remuneration

Under the Companies Act 2006 we are also required to report if in our opinion certain disclosures of directors’

remuneration have not been made or the part of the directors’ remuneration report to be audited is not in

agreement with the accounting records and returns.

We have nothing to

report in respect of

these matters.

Other matters

Auditor tenure

The board appointed Deloitte as the company's auditor with effect from 29 March 2018 to fill the vacancy arising from the resignation of the

previous auditor. On 21 May 2019, shareholders resolved at the annual general meeting to reappoint Deloitte as auditor from the conclusion of

the meeting until the conclusion of the annual general meeting to be held in 2020 and authorized the directors to set the audit fees.

The first accounting period we audited was the 12 month period ended 31 December 2018. In 2017, we commenced our audit planning

procedures. The period of total uninterrupted engagement including previous renewals and reappointments of the firm is accordingly two years.

Consistency of the audit report with the additional report to the audit committee

Our audit opinion is consistent with the additional report to the audit committee we are required to provide in accordance with ISAs (UK).

Use of our report

This report is made solely to the company’s members, as a body, in accordance with Chapter 3 of Part 16 of the Companies Act 2006. Our

audit work has been undertaken so that we might state to the company’s members those matters we are required to state to them in an

auditor’s report and for no other purpose. To the fullest extent permitted by law, we do not accept or assume responsibility to anyone other

than the company and the company’s members as a body, for our audit work, for this report, or for the opinions we have formed.

Douglas King FCA (Senior statutory auditor)

For and on behalf of Deloitte LLP

Statutory Auditor

London, United Kingdom

18†March†2020

This page does not form part of BP's Annual Report on Form 20-F as filed with the SEC.

BP Annual Report and Form 20-F 2019 145

Consolidated financial statements of the BP group

Report of Independent Registered Public Accounting Firm

To the shareholders and board of directors of BP p.l.c.

Opinion on the financial statements

We have audited the accompanying consolidated group balance sheets of BP p.l.c. (the company) and subsidiaries (together the group) as at

31†December†2019 and 2018, and the related consolidated group income statements, group statements of comprehensive income, group

statements of changes in equity, and group cash flow statements, for each of the two years in the period ended 31†December†2019, and the

related notes as well as the legal proceedings described on pages 319-320 (collectively referred to as the 'group financial statements'). In our

opinion, the group financial statements present fairly, in all material respects, the financial position of the group as at 31†December†2019 and

2018, and the results of its operations and its cash flows for each of the two years in the period ended 31†December†2019, in conformity with

International Financial Reporting Standards (IFRS) as adopted by the European Union and IFRS as issued by the International Accounting

Standards Board.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the

group's internal control over financial reporting as of 31†December†2019, based on criteria established in the UK Financial Reporting Council’s

Guidance on Risk Management, Internal Control and Related Financial and Business Reporting relating to internal control over financial

reporting and our report dated 18†March†2020 expressed an unqualified opinion on the group's internal control over financial reporting.

Basis for opinion

These financial statements are the responsibility of the group's management. Our responsibility is to express an opinion on the group's

financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with

respect to the group in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and

Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to

obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our

audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud,

and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts

and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made

by management, as well as evaluating the overall presentation of the financial statements. We believe that our audit provides a reasonable

basis for our opinion.

Critical Audit Matters

The critical audit matters communicated below are matters arising from the current-period audit of the group financial statements that were

communicated or required to be communicated to the audit committee and that (1) relate to accounts or disclosures that are material to the

group financial statements and (2) involved especially challenging, subjective, or complex judgments. The communication of critical audit

matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical

audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.

Throughout the course of our audit we identify risks of material misstatement ('risks'). We consider both the likelihood of a risk and the

potential magnitude of a misstatement in making the assessment. Certain risks are classified as 'significant' or 'higher' depending on their

severity. The category of the risk determines the level of evidence we seek in providing assurance that the associated financial statement item

is not materially misstated.

Impairment of upstream oil and gas property, plant and equipment (PP&E) assets - Notes 1 and 12 to the financial statements

Critical Audit Matter Description

The group balance sheet includes property, plant and equipment (PP&E) of $133 billion, of which $90 billion is oil and gas properties within the

upstream segment.

Management announced an approximately $10 billion disposal programme for 2019 and 2020. As a consequence of this, certain assets

identified for disposal have been assessed for impairment in the context of their fair value based on the expected disposal proceeds from third

parties, as opposed to their value in use.

The transition to a lower carbon global economy may potentially lead to a lower oil and gas price scenario in the future due to declining

demand. Management took into account considerations of uncertainty over the pace of the transition to lower-carbon supply and demand and

the social, political and environmental actions that will be taken to meet the goals of the Paris climate change agreement when determining

their future oil and gas price assumptions and revised the future price assumptions downwards when compared with the prior year

assumptions as set out in Note 1 on page 162. As a consequence, they identified a risk of impairment across all upstream CGUs.

Accordingly, as required by International Accounting Standard (IAS) 36 'Impairment of Assets', management performed a review of all the

upstream cash generating units (CGUs) for indicators of impairment and impairment reversal as at 31 December 2019. Further information has

been provided in Note 1.

In large part due to the disposal programme, for the year ended 31 December 2019 BP recorded $5,871 million of upstream impairment

charges and $129 million of impairment reversals. Through our risk assessment procedures, we have determined that there are three key

estimates in management’s determination of the level of impairment charge/reversal to record. These are:

a. Oil and gas prices - BP’s oil and gas price assumptions have a significant impact on CGU impairment assessments and valuations

performed across the portfolio, and are inherently uncertain. Furthermore, as noted above the estimation of future oil and gas prices is

subject to increased uncertainty, given climate change and the global energy transition. There is a risk that management’s oil and gas

price assumptions are not reasonable, leading to a material misstatement. The assumptions are highly judgemental.

b.Discount rates - Given the long timeframes involved, certain recoverable amounts of assets are sensitive to the discount rate applied.

There is a risk that discount rates do not reflect the return required by the market and the risks inherent in the cash flows being

discounted, leading to a material misstatement. Determination of the appropriate discount rate can be judgemental.

c. Reserves estimates - A key input to impairment assessments and valuations is the production forecast, in turn closely related to the

group’s reserves estimates and field development assumptions. CGU-specific estimates are not generally material. However, material

146 BP Annual Report and Form 20-F 2019

misstatements could arise either from systematic flaws in reserves estimation policies, or due to flawed estimates in a particularly

material individual impairment test.

We identified and focused on certain individual CGUs with a total carrying value of $12.3 billion which we determined would be most at risk of

a material impairment as a result of a reasonably possible change in the key assumptions, particularly the oil and gas price assumptions.

Accordingly, we identified these as a significant audit risk. We also focused on assets with a further $33.4 billion of combined CGU carrying

value which were less sensitive. We identified these as a higher audit risk as they would be potentially at risk in aggregate to a material

impairment by a change in such assumptions. Further information regarding these sensitivities is given in Note 1 to the consolidated financial

statements.

How the Critical Audit Matter was addressed in the Audit

We tested management’s internal controls over the setting of oil and gas prices, discount rates and reserve estimates, as well as the

controls over the performance of the impairment valuation tests. In addition, we conducted the following substantive procedures.

Oil and gas prices

• We independently developed a reasonable range of forecasts based on external data obtained, against which we compared the company’s

future oil and gas price assumptions in order to challenge whether they are reasonable.

• In developing this range we obtained a variety of reputable third party forecasts, peer information and market data.

• In challenging management's price assumptions, we considered the extent to which they and each of the forecast pricing scenarios

obtained from third parties reflect the impact of lower oil and gas demand due to climate change. We specifically reviewed third party

forecasts stated as being, or interpreted by us as being, consistent with achieving the 2015 COP 21 Paris agreement goal to limit

temperature rises to well below 2°C (Paris 2°C Goal).

• We reviewed and challenged management’s disclosures including in relation to the sensitivity of oil and gas price assumptions to reduced

demand scenarios whether due to climate change or other reasons.

Discount rates

• We independently evaluated BP’s discount rates used in impairment tests with input from Deloitte valuation specialists.

• We assessed whether country risks and tax adjustments were appropriately reflected in BP’s discount rates.

Reserves estimates

• We reviewed BP’s reserves estimation methods and policies, assisted by Deloitte reserves experts.

• We assessed, with the assistance of Deloitte reserves experts, how these policies had been applied to a sample of internal reserves

estimates.

• We reviewed reports provided by external experts and assessed their scope of work and findings.

• We assessed the competence, capability and objectivity of BP’s internal and external reserve experts, through obtaining their relevant

professional qualifications and experience.

• We compared hydrocarbon production forecasts used in impairment tests to estimates and reports and our understanding of the life of

fields.

• We performed a retrospective review to check for indications of estimation bias over time.

Other procedures

• We challenged management’s CGU determination, and considered whether there was any contradictory evidence present.

• We validated that BP’s asset impairment methodology was appropriate and tested the integrity of impairment models.

• Where relevant, we also assessed management’s historical forecasting accuracy and whether the estimates had been determined and

applied on a consistent basis across the group.

Since 31 December 2019, the oil price has fallen sharply in large part due to the impact of the international spread of COVID-19 (Coronavirus)

and geopolitical factors. As part of our post balance sheet audit procedures we considered whether these events provide evidence of

conditions that existed at the balance sheet date.

Impairment of exploration and appraisal assets (included within 'intangible assets' within the group balance sheet) - Notes 1 and 15

to the financial statements

Critical Audit Matter Description

The group capitalizes exploration and appraisal (E&A) expenditure on a project-by-project basis in line with IFRS 6 'Exploration for and

Evaluation of Mineral Resources'. At the end of 2019, $14 billion of E&A expenditure was carried in the group balance sheet. E&A activity is

inherently risky and a significant proportion of projects fail, requiring the write-off of the related capitalized costs when the relevant criteria

in IFRS 6 and BP’s accounting policy are met.

There is a significant judgement relating to the risk that certain capitalized E&A costs are not written off promptly at the appropriate time,

in line with information from, and decisions about, E&A activities and the impairment requirements of IFRS 6.

Furthermore, similar to upstream PP&E assets discussed above, E&A assets are also potentially exposed to climate change and the global

energy transition. A greater number of projects may be expected not to proceed as a consequence of lower forecast future demand, lower

appetite by management and the board to allocate capital to certain projects, or increased objections from stakeholders to the

development of certain projects.

During the current year, and subsequent to the year end, management have obtained license extensions in the Gulf of Mexico and other

regions where licenses had previously expired such that we have concluded this does not represent a significant audit risk. Nevertheless,

given the inherent uncertainty associated with the development and deployment of these assets, we still consider this area to be a higher

risk.

How the Critical Audit Matter was addressed in the Audit

We obtained an understanding of the group’s E&A impairment assessment processes and tested management’s internal controls,

BP Annual Report and Form 20-F 2019 147

including the controls addressing potential climate change considerations.

We performed a licence-by-licence risk assessment of the group’s E&A balance through to year end, to identify significant carrying

amounts with a current period risk of impairment (e.g. new information from exploration activities, or imminent licence expiry).

We performed a retrospective review of impairment charges recorded in the period, and assessed whether impairment charges were

timely.

We reviewed and challenged management’s significant IFRS 6 impairment judgements, having regard to the impairment criteria of IFRS 6

and BP’s accounting policy. We verified key facts relevant to significant carrying amounts (by obtaining for example evidence of future E&A

plans and budgets, and evidence of active dialogue with partners and regulators including negotiations to renew licences or modify key

terms).

We tested the completeness and accuracy of information used in management’s E&A impairment assessment, by reviewing and testing

key controls over management’s register of E&A licences and agreeing key aspects of this to underlying support (e.g. licence

documentation); holding meetings and discussions with operational and finance management; considering adverse changes in

management’s reserves and resource estimates associated with E&A assets; reviewing correspondence with regulators and joint

arrangement partners; and considering the implications of capital allocation decisions. When considering capital allocation decision making,

we considered whether the development of any projects would be inconsistent with the elements of BP’s current strategy which are

designed to ensure it is resilient to the energy transition and climate change considerations or which would otherwise have a prohibitively

high environmental or social impact for the directors to sanction the necessary investment.

Accounting for structured commodity transactions (SCTs) within the integrated supply and trading function (IST), and the

valuation of other level 3 financial instruments, where fraud risks may arise in revenue recognition (potentially impacting all

financial statement accounts, in particular finance debt) - Notes 1, 20, 22, 29 and 30 to the financial statements

Critical Audit Matter Description

In the normal course of business, IST enters into a variety of transactions for delivering value across the group’s supply chain. The nature of

these transactions requires significant audit effort be directed towards challenging management’s valuation estimates or the adopted

accounting treatment.

Accounting for structured commodity transactions:

IST may also enter into a variety of transactions which we refer to as SCTs. We generally consider a SCT to be an arrangement having one of

the following features:

• Two or more counterparties with non-standard contractual terms;

• Multiple commodity-based transactions; and/or

• Contractual arrangements entered into in contemplation of each other.

SCTs are often long-dated, can have a significant multi-year financial impact, and may require the use of complex valuation models or

unobservable inputs when determining their fair value, in which case they will be classified as level 3 financial instruments under IFRS 13,

‘Fair Value Measurement’.

Accounting for SCTs is often complex and involves significant judgement, as these transactions often feature multiple elements that will

have a material impact on the presentation and disclosure of these transactions in the financial statements and on key performance

measures, including in particular classification of liabilities as finance debt. We have identified the accounting for SCTs as a significant audit

risk.

Level 3 financial instruments:

Unlike other financial instruments whose values or inputs are readily observable and therefore more easily independently corroborated, there

are certain transactions for which the valuation is inherently more subjective due to the use of either complex valuation models and/or

unobservable inputs. These instruments are classified as level 3 financial assets or liabilities under IFRS 13. This degree of subjectivity also

gives rise to potential fraud through management incorporating bias in determining fair values. Accordingly, we have identified these as a

significant audit risk.

As at 31 December 2019, the group’s total financial assets and liabilities measured at fair value were $12.5 billion and $8.8 billion, of which

level 3 derivative financial assets were $5.3 billion and level 3 derivative financial liabilities were $4.4 billion.

How the Critical Audit Matter was addressed in the Audit

Accounting for SCTs

For structured commodity transactions, we performed audit procedures to:

• Test controls related to the accounting for complex transactions.

• Develop an understanding of the commercial rationale of the transactions through review of transaction support documents and executed

agreements, and discussions with management.

• Perform a detailed accounting analysis for a sample of structured commodity transactions involving significant day one profits, deferred

working capital arrangements, offtake arrangements and/or commitments.

To assess the appropriateness of the accounting treatment of SCTs, we embedded technical accounting specialists within the audit team.

During the year we identified two new SCTs which were subjected to our audit procedures listed above. We also reconsidered the SCTs which

were identified during 2018 and which have been subject to ongoing assessment in 2019.

Other level 3 financial instruments:

To address the complexities associated with auditing the value of level 3 financial instruments, the engagement team included valuation

specialists having significant quantitative and modelling expertise to assist in performing our audit procedures. Our valuation audit procedures

included the following control and substantive procedures:

• We tested the group’s valuation controls including the:

148 BP Annual Report and Form 20-F 2019

– Model certification control, which is designed to review a model’s theoretical soundness and the appropriateness of its valuation

methodology; and

– Independent price verification control, which is designed to review the appropriateness of valuation inputs that are not observable

and are significant to the financial instrument’s valuation.

• We performed substantive valuation testing procedures at interim and year-end balance sheet date, including:

– Engaging a Deloitte valuations specialist to develop fair value estimates, using independently sourced inputs where these were

available, and challenge models to evaluate against management’s fair value estimates by evaluating whether the differences

between our independent estimates and management’s estimates were within a reasonable range. In situations where we utilised

management’s inputs, these were compared to external data sources to ensure they were reasonable;

– Evaluating management’s valuation methodologies against standard valuation practice and analysing whether a consistent framework

is applied across the business period over period; and

– Comparing management’s input assumptions against the expected assumptions of other market participants and observable market

data.

/s/ Deloitte LLP

London

United Kingdom

18†March†2020

The first accounting period we audited was the 12 months ended 31 December 2018. In 2017, we commenced our audit planning procedures.

BP Annual Report and Form 20-F 2019 149

Consolidated financial statements of the BP group

Report of Independent Registered Public Accounting Firm

To the shareholders and board of directors of BP p.l.c.

Opinion on internal control over financial reporting

We have audited the internal control over financial reporting of BP p.l.c. and subsidiaries (the Company) as at 31†December†2019, based on the

criteria established in the UK Financial Reporting Council’s Guidance on Risk Management, Internal Control and Related Financial and Business

Reporting relating to internal control over financial reporting (UK FRC Guidance). In our opinion, the Company maintained, in all material

respects, effective internal control over financial reporting as of 31†December†2019, based on the criteria established in the UK FRC Guidance.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the

consolidated financial statements as at and for the year ended 31†December†2019, of the Company and our report dated 18†March†2020,

expressed an unqualified opinion on those financial statements.

Basis for opinion

The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the

effectiveness of internal control over financial reporting, included in the accompanying Management’s report on internal control over financial

reporting. Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit. We are a

public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the

U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain

reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit

included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and

evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we

considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and limitations of internal control over financial reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial

reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A

company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in

reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance

that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting

principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and

directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or

disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any

evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or

that the degree of compliance with the policies or procedures may deteriorate.

/s/ Deloitte LLP

London, United Kingdom

18†March†2020

150 BP Annual Report and Form 20-F 2019

Consolidated financial statements of the BP group

Report of Independent Registered Public Accounting Firm

To the shareholders and board of directors of BP p.l.c.

Opinion on the financial statements

We have audited the accompanying group balance sheet of BP p.l.c. (the Company) as of 31 December 2017, and the related group income

statement, group statement of comprehensive income, group statement of changes in equity and group cash flow statement for the period

ended 31 December 2017, and the related notes (collectively referred to as the "group financial statements"). In our opinion, the group financial

statements present fairly, in all material respects, the financial position of BP p.l.c. at 31 December 2017 and the results of its operations and

its cash flows for the period ended 31 December 2017, in conformity with International Financial Reporting Standards (IFRS) as adopted by the

European Union and IFRS as issued by the International Accounting Standards Board.

Basis for opinion

These financial statements are the responsibility of BP p.l.c.'s management. Our responsibility is to express an opinion on these financial

statements based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to

BP p.l.c. in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange

Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain

reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audit

included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and

performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and

disclosures in the financial statements. Our audit also included evaluating the accounting principles used and significant estimates made by

management, as well as evaluating the overall presentation of the financial statements. We believe that our audit provides a reasonable basis

for our opinion.

/s/ Ernstƒ& Young LLP

We served as the Company's auditor from 1909 to 2018.

London, United Kingdom

29 March 2018

Note that the report set out above is included for the purposes of BP p.l.c.’s Annual Report on Form 20-F for 2019 only and does not form part

of BP p.l.c.’s Annual Report and Accounts for 2017.

1. The maintenance and integrity of the BP p.l.c. web site is the responsibility of BP p.l.c.; the work carried out by the auditors does not

involve consideration of these matters and, accordingly, the auditors accept no responsibility for any changes that may have occurred to

the financial statements since they were initially presented on the web site.

2. Legislation in the United Kingdom governing the preparation and dissemination of financial statements may differ from legislation in other

jurisdictions.

BP Annual Report and Form 20-F 2019 151

Group income statement

For the year ended 31 December $ million

Note 2019 2018 2017

Sales and other operating revenues 5 278,397 298,756 240,208

Earnings from joint ventures – after interest and tax 16 576 897 1,177

Earnings from associates – after interest and tax 17 2,681 2,856 1,330

Interest and other income 7 769 773 657

Gains on sale of businesses and fixed assets 4 193 456 1,210

Total revenues and other income 282,616 303,738 244,582

Purchases 19 209,672 229,878 179,716

Production and manufacturing expenses 21,815 23,005 24,229

Production and similar taxes 5 1,547 1,536 1,775

Depreciation, depletion and amortization 5 17,780 15,457 15,584

Impairment and losses on sale of businesses and fixed assets 4 8,075 860 1,216

Exploration expense 8 964 1,445 2,080

Distribution and administration expenses 11,057 12,179 10,508

Profit before interest and taxation 11,706 19,378 9,474

Finance costs 7 3,489 2,528 2,074

Net finance expense relating to pensions and other post-retirement benefits 24 63 127 220

Profit before taxation 8,154 16,723 7,180

Taxation 9 3,964 7,145 3,712

Profit for the year 4,190 9,578 3,468

Attributable to

BP shareholders 4,026 9,383 3,389

Non-controlling interests 164 195 79

4,190 9,578 3,468

Earnings per share

Profit for the year attributable to BP shareholders

Per ordinary share (cents)

Basic 11 19.84 46.98 17.20

Diluted 11 19.73 46.67 17.10

Per ADS (dollars)

Basic 11 1.19 2.82 1.03

Diluted 11 1.18 2.80 1.03

152 BP Annual Report and Form 20-F 2019

Group statement of comprehensive income

For the year ended 31 December $ million

Note 2019 2018 2017

Profit for the year 4,190 9,578 3,468

Other comprehensive income

Items that may be reclassified subsequently to profit or loss

Currency translation differences 1,538 (3,771) 1,986

Exchange (gains) losses on translation of foreign operations reclassified to gain or loss

on sale of businesses and fixed assets

880 — (120)

Available-for-sale investments — — 14

Cash flow hedges marked to market 30 (100) (126) 197

Cash flow hedges reclassified to the income statement 30 106 120 116

Cash flow hedges reclassified to the balance sheet 30 — — 112

Costs of hedging marked to market 30 (4) (244) —

Costs of hedging reclassified to the income statement 30 57 58 —

Share of items relating to equity-accounted entities, net of tax 16, 17 82 417 564

Income tax relating to items that may be reclassified 9 (70) 4 (196)

2,489 (3,542) 2,673

Items that will not be reclassified to profit or loss

Remeasurements of the net pension and other post-retirement benefit liability or asset 24 328 2,317 3,646

Cash flow hedges that will subsequently be transferred to the balance sheet 30 (3) (37) —

Income tax relating to items that will not be reclassified 9 (157) (718) (1,303)

168 1,562 2,343

Other comprehensive income 2,657 (1,980) 5,016

Total comprehensive income 6,847 7,598 8,484

Attributable to

BP shareholders 6,674 7,444 8,353

Non-controlling interests 173 154 131

6,847 7,598 8,484

See Note 32 for further information.

BP Annual Report and Form 20-F 2019 153

Group statement of changes in equity

$ million

capital and

capital

reserves

Treasury

Foreign

currency

translation

reserve

Fair value

reserves

Profit and

loss

account

shareholders'

equity

Non-

controlling

interests Total equity

At 31 December 2018 46,352 (15,767) (8,902) (987) 78,748 99,444 2,104 101,548

Adjustment on adoption of IFRS 16, net of tax — — — — (329) (329) (1) (330)

At 1 January 2019 46,352 (15,767) (8,902) (987) 78,419 99,115 2,103 101,218

Profit for the year — — — — 4,026 4,026 164 4,190

Other comprehensive income — — 2,407 52 189 2,648 9 2,657

Total comprehensive income — — 2,407 52 4,215 6,674 173 6,847

Dividends

— — — — (6,929) (6,929) (213) (7,142)

Cash flow hedges transferred to the balance

sheet, net of tax

— — — 23 — 23 — 23

Repurchase of ordinary share capital — — — — (1,511) (1,511) — (1,511)

Share-based payments, net of tax 173 1,355 — — (809) 719 — 719

Share of equity-accounted entities’ changes in

equity, net of tax

— — — — 5 5 — 5

Transactions involving non-controlling interests,

net of tax

— — — — 316 316 233 549

At 31 December 2019 46,525 (14,412) (6,495) (912) 73,706 98,412 2,296 100,708

At 31 December 2017 46,122 (16,958) (5,156) (743) 75,226 98,491 1,913 100,404

Adjustment on adoption of IFRS 9, net of tax — — — (54) (126) (180) — (180)

At 1 January 2018 46,122 (16,958) (5,156) (797) 75,100 98,311 1,913 100,224

Profit for the year — — — — 9,383 9,383 195 9,578

Other comprehensive income — — (3,746) (216) 2,023 (1,939) (41) (1,980)

Total comprehensive income — — (3,746) (216) 11,406 7,444 154 7,598

Dividends

— — — — (6,699) (6,699) (170) (6,869)

Cash flow hedges transferred to the balance

sheet, net of tax

— — — 26 — 26 — 26

Repurchase of ordinary share capital — — — — (355) (355) — (355)

Share-based payments, net of tax 230 1,191 — — (718) 703 — 703

Share of equity-accounted entities’ changes in

equity, net of tax

— — — — 14 14 — 14

Transactions involving non-controlling interests,

net of tax

— — — — — — 207 207

At 31 December 2018 46,352 (15,767) (8,902) (987) 78,748 99,444 2,104 101,548

At 1 January 2017 46,122 (18,443) (6,878) (1,153) 75,638 95,286 1,557 96,843

Profit for the year — — — — 3,389 3,389 79 3,468

Other comprehensive income — — 1,722 410 2,832 4,964 52 5,016

Total comprehensive income — — 1,722 410 6,221 8,353 131 8,484

Dividends

— — — — (6,153) (6,153) (141) (6,294)

Repurchases of ordinary share capital — — — — (343) (343) — (343)

Share-based payments, net of tax — 1,485 — — (798) 687 — 687

Share of equity-accounted entities’ changes in

equity, net of tax

— — — — 215 215 — 215

Transactions involving non-controlling interests,

net of tax

— — — — 446 446 366 812

At 31 December 2017 46,122 (16,958) (5,156) (743) 75,226 98,491 1,913 100,404

See Note 32 for further information.

See Note 10 for further information.

154 BP Annual Report and Form 20-F 2019

Group balance sheet

At 31†December $ million

Note 2019 2018

Non-current assets

Property, plant and equipment 12 132,642 135,261

Goodwill 14 11,868 12,204

Intangible assets 15 15,539 17,284

Investments in joint ventures 16 9,991 8,647

Investments in associates 17 20,334 17,673

Other investments 18 1,276 1,341

Fixed assets 191,650 192,410

Loans 630 637

Trade and other receivables 20 2,147 1,834

Derivative financial instruments 30 6,314 5,145

Prepayments 781 1,179

Deferred tax assets 9 4,560 3,706

Defined benefit pension plan surpluses 24 7,053 5,955

213,135 210,866

Current assets

Loans 339 326

Inventories 19 20,880 17,988

Trade and other receivables 20 24,442 24,478

Derivative financial instruments 30 4,153 3,846

Prepayments 857 963

Current tax receivable 1,282 1,019

Other investments 18 169 222

Cash and cash equivalents 25 22,472 22,468

74,594 71,310

Assets classified as held for sale 2 7,465 —

82,059 71,310

Total assets 295,194 282,176

Current liabilities

Trade and other payables 22 46,829 46,265

Derivative financial instruments 30 3,261 3,308

Accruals 5,066 4,626

Lease liabilities 28 2,067 44

Finance debt

26 10,487 9,329

Current tax payable 2,039 2,101

Provisions 23 2,453 2,564

72,202 68,237

Liabilities directly associated with assets classified as held for sale 2 1,393 —

73,595 68,237

Non-current liabilities

Other payables 22 12,626 13,830

Derivative financial instruments 30 5,537 5,625

Accruals 996 575

Lease liabilities 28 7,655 623

Finance debt

26 57,237 55,803

Deferred tax liabilities 9 9,750 9,812

Provisions 23 18,498 17,732

Defined benefit pension plan and other post-retirement benefit plan deficits 24 8,592 8,391

120,891 112,391

Total liabilities 194,486 180,628

Net assets 100,708 101,548

Equity

BP shareholders’ equity 32 98,412 99,444

Non-controlling interests 32 2,296 2,104

Total equity 32 100,708 101,548

Finance debt on the comparative balance sheet has been re-presented to align with the current period. See Note 1 for further information.

Helge Lund Chairman

B Looney Chief executive officer

18†March†2020

BP Annual Report and Form 20-F 2019 155

Group cash flow statement

For the year ended 31 December $ million

Note 2019 2018 2017

Operating activities

Profit before taxation 8,154 16,723 7,180

Adjustments to reconcile profit before taxation to net cash provided by operating

activities

Exploration expenditure written off 8 631 1,085 1,603

Depreciation, depletion and amortization 5 17,780 15,457 15,584

Impairment and (gain) loss on sale of businesses and fixed assets 4 7,882 404 6

Earnings from joint ventures and associates (3,257) (3,753) (2,507)

Dividends received from joint ventures and associates 1,962 1,535 1,253

Interest receivable (441) (468) (304)

Interest received 416 348 375

Finance costs 7 3,489 2,528 2,074

Interest paid (2,870) (1,928) (1,572)

Net finance expense relating to pensions and other post-retirement benefits 24 63 127 220

Share-based payments 730 690 661

Net operating charge for pensions and other post-retirement benefits, less

contributions and benefit payments for unfunded plans

24 (238) (386) (394)

Net charge for provisions, less payments (176) 986 2,106

(Increase) decrease in inventories (3,406) 672 (848)

(Increase) decrease in other current and non-current assets (2,335) (2,858) (4,848)

Increase (decrease) in other current and non-current liabilities 2,823 (2,577) 2,344

Income taxes paid (5,437) (5,712) (4,002)

Net cash provided by operating activities 25,770 22,873 18,931

Investing activities

Expenditure on property, plant and equipment, intangible and other assets (15,418) (16,707) (16,562)

Acquisitions, net of cash acquired 3 (3,562) (6,986) (327)

Investment in joint ventures (137) (382) (50)

Investment in associates (304) (1,013) (901)

Total cash capital expenditure (19,421) (25,088) (17,840)

Proceeds from disposals of fixed assets 4 500 940 2,936

Proceeds from disposals of businesses, net of cash disposed 4 1,701 1,911 478

Proceeds from loan repayments 246 666 349

Net cash used in investing activities (16,974) (21,571) (14,077)

Financing activities

Repurchase of shares (1,511) (355) (343)

Lease liability payments (2,372) (35) (45)

Proceeds from long-term financing 8,597 9,038 8,712

Repayments of long-term financing (7,118) (7,175) (6,231)

Net increase (decrease) in short-term debt 180 1,317 (158)

Net increase (decrease) in non-controlling interests 566 — 1,063

Dividends paid

BP shareholders 10 (6,946) (6,699) (6,153)

Non-controlling interests (213) (170) (141)

Net cash provided by (used in) financing activities (8,817) (4,079) (3,296)

Currency translation differences relating to cash and cash equivalents 25 (330) 544

Increase (decrease) in cash and cash equivalents 4 (3,107) 2,102

Cash and cash equivalents at beginning of year 22,468 25,575 23,484

Cash and cash equivalents at end of year 22,472 22,468 25,586

The presentation of financing cash flows for the comparative periods have been amended to align with the current period. See Note 1 for further information.

156 BP Annual Report and Form 20-F 2019

Notes on financial statements

BP Annual Report and Form 20-F 2019 157

1. Significant accounting policies, judgements, estimates and assumptions

Authorization of financial statements and statement of compliance with International Financial Reporting Standards

The consolidated financial statements of BP p.l.c and its subsidiaries (collectively referred to as BP or the group) for the year ended

31†December†2019 were approved and signed by the chief executive officer and chairman on 18†March†2020 having been duly authorized to do

so by the board of directors. BP p.l.c. is a public limited company incorporated and domiciled in England and Wales. The consolidated financial

statements have been prepared in accordance with International Financial Reporting Standards (IFRS) as issued by the International Accounting

Standards Board (IASB), IFRS as adopted by the European Union (EU) and in accordance with the provisions of the UK Companies Act 2006 as

applicable to companies reporting under IFRS. IFRS as adopted by the EU differs in certain respects from IFRS as issued by the IASB. The

differences have no impact on the group’s consolidated financial statements for the years presented. The significant accounting policies and

accounting judgements, estimates and assumptions of the group are set out below.

Basis of preparation

The consolidated financial statements have been prepared on a going concern basis and in accordance with IFRS and IFRS Interpretations

Committee (IFRIC) interpretations issued and effective for the year ended 31†December†2019. The accounting policies that follow have been

consistently applied to all years presented, except where otherwise indicated.

The consolidated financial statements are presented in US dollars and all values are rounded to the nearest million dollars ($ million), except

where otherwise indicated.

Significant accounting policies: use of judgements, estimates and assumptions

Inherent in the application of many of the accounting policies used in preparing the consolidated financial statements is the need for BP

management to make judgements, estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of

contingent assets and liabilities, and the reported amounts of revenues and expenses. Actual outcomes could differ from the estimates and

assumptions used. The accounting judgements and estimates that have a significant impact on the results of the group are set out in boxed

text below, and should be read in conjunction with the information provided in the Notes on financial statements. The areas requiring the most

significant judgement and estimation in the preparation of the consolidated financial statements are: accounting for the investment in Rosneft;

exploration and appraisal intangible assets; the recoverability of asset carrying values, including the estimation of reserves; derivative financial

instruments; provisions and contingencies; and pensions and other post-retirement benefits. Where an estimate has a significant risk of

resulting in a material adjustment to the carrying amounts of assets and liabilities within the next financial year this is specifically noted within

the boxed text. The group does not consider income taxes to represent a significant estimate or judgement for 2019, see Income taxes for

more information.

Basis of consolidation

The group financial statements consolidate the financial statements of BP p.l.c. and its subsidiaries drawn up to 31†December each year.

Subsidiaries are consolidated from the date of their acquisition, being the date on which the group obtains control, and continue to be

consolidated until the date that control ceases. The financial statements of subsidiaries are prepared for the same reporting year as the parent

company, using consistent accounting policies. Intra-group balances and transactions, including unrealized profits arising from intra-group

transactions, have been eliminated. Unrealized losses are eliminated unless the transaction provides evidence of an impairment of the asset

transferred. Non-controlling interests represent the equity in subsidiaries that is not attributable, directly or indirectly, to BP shareholders.

Interests in other entities

Business combinations and goodwill

Business combinations are accounted for using the acquisition method. The identifiable assets acquired and liabilities assumed are recognized

at their fair values at the acquisition date.

Goodwill is initially measured as the excess of the aggregate of the consideration transferred, the amount recognized for any non-controlling

interest and the acquisition-date fair values of any previously held interest in the acquiree over the fair value of the identifiable assets acquired

and liabilities assumed at the acquisition date. The amount recognized for any non-controlling interest is measured at the present ownership's

proportionate share in the recognized amounts of the acquiree’s identifiable net assets. At the acquisition date, any goodwill acquired is

allocated to each of the cash-generating units, or groups of cash-generating units, expected to benefit from the combination’s synergies.

Following initial recognition, goodwill is measured at cost less any accumulated impairment losses. Goodwill arising on business combinations

prior to 1†January 2003 is stated at the previous carrying amount under UK generally accepted accounting practice, less subsequent

impairments. See Note 14 for further information.

Goodwill may arise upon investments in joint ventures and associates, being the surplus of the cost of investment over the group’s share of

the net fair value of the identifiable assets and liabilities. Any such goodwill is recorded within the corresponding investment in joint ventures

and associates.

Goodwill may also arise upon acquisition of interests in joint operations that meet the definition of a business. The amount of goodwill

separately recognized is the excess of the consideration transferred over the group's share of the net fair value of the identifiable assets and

liabilities.

Interests in joint arrangements

The results, assets and liabilities of joint ventures are incorporated in these consolidated financial statements using the equity method of

accounting as described below.

Certain of the group’s activities, particularly in the Upstream segment, are conducted through joint operations. BP recognizes, on a line-by-line

basis in the consolidated financial statements, its share of the assets, liabilities and expenses of these joint operations incurred jointly with the

other partners, along with the group’s income from the sale of its share of the output and any liabilities and expenses that the group has

incurred in relation to the joint operation.

1. Significant accounting policies, judgements, estimates and assumptions – continued

Interests in associates

The results, assets and liabilities of associates are incorporated in these consolidated financial statements using the equity method of

accounting as described below.

Significant judgement: investment in Rosneft

Judgement is required in assessing the level of control or influence over another entity in which the group holds an interest. For BP, the

judgement that the group has significant influence over Rosneft Oil Company (Rosneft), a Russian oil and gas company is significant. As a

consequence of this judgement, BP uses the equity method of accounting for its investment and BP's share of Rosneft's oil and natural gas

reserves is included in the group's estimated net proved reserves of equity-accounted entities. If significant influence was not present, the

investment would be accounted for as an investment in an equity instrument measured at fair value as described under 'Financial assets'

below and no share of Rosneft's oil and natural gas reserves would be reported.

Significant influence is defined in IFRS as the power to participate in the financial and operating policy decisions of the investee but is not

control or joint control of those policies. Significant influence is presumed when an entity owns 20% or more of the voting power of the

investee. Significant influence is presumed not to be present when an entity owns less than 20% of the voting power of the investee.

BP owns 19.75% of the voting shares of Rosneft. The Russian federal government, through its investment company JSC Rosneftegaz,

owned 50% plus one share of the voting shares of Rosneft at 31†December 2019. IFRS identifies several indicators that may provide

evidence of significant influence, including representation on the board of directors of the investee and participation in policy-making

processes. BP’s group chief executive, as at 31 December 2019, Bob Dudley, has been a member of the board of directors of Rosneft since

2013 and remains one of BP's nominated directors following his resignation as BP's group chief executive. He is also chairman of the

Rosneft board’s Strategic Planning Committee. A second BP-nominated director, Guillermo Quintero, has been a member of the Rosneft

board and its HR and Remuneration Committee since 2015. BP also holds the voting rights at general meetings of shareholders conferred by

its 19.75% stake in Rosneft. BP's management consider, therefore, that the group has significant influence over Rosneft, as defined by IFRS.

The equity method of accounting

Under the equity method, an investment is carried on the balance sheet at cost plus post-acquisition changes in the group’s share of net

assets of the entity, less distributions received and less any impairment in value of the investment. Loans advanced to equity-accounted

entities that have the characteristics of equity financing are also included in the investment on the group balance sheet. The group income

statement reflects the group’s share of the results after tax of the equity-accounted entity, adjusted to account for depreciation, amortization

and any impairment of the equity-accounted entity’s assets based on their fair values at the date of acquisition. The group statement of

comprehensive income includes the group’s share of the equity-accounted entity’s other comprehensive income. The group’s share of amounts

recognized directly in equity by an equity-accounted entity is recognized in the group’s statement of changes in equity.

Financial statements of equity-accounted entities are prepared for the same reporting year as the group. Where material differences arise in the

accounting policies used by the equity-accounted entity and those used by BP, adjustments are made to those financial statements to bring the

accounting policies used into line with those of the group.

Unrealized gains on transactions between the group and its equity-accounted entities are eliminated to the extent of the group’s interest in the

equity-accounted entity.

The group assesses investments in equity-accounted entities for impairment whenever there is objective evidence that the investment is

impaired. If any such objective evidence of impairment exists, the carrying amount of the investment is compared with its recoverable amount,

being the higher of its fair value less costs of disposal and value in use. If the carrying amount exceeds the recoverable amount, the

investment is written down to its recoverable amount.

Segmental reporting

The group’s operating segments are established on the basis of those components of the group that are evaluated regularly by the group chief

executive, BP’s chief operating decision maker, in deciding how to allocate resources and in assessing performance.

The accounting policies of the operating segments are the same as the group’s accounting policies described in this note, except that IFRS

requires that the measure of profit or loss disclosed for each operating segment is the measure that is provided regularly to the chief operating

decision maker. For BP, this measure of profit or loss is replacement cost profit before interest and tax which reflects the replacement cost of

inventories sold in the period and is arrived at by excluding inventory holding gains and losses from profit. Replacement cost profit for the

group is not a recognized measure under IFRS. For further information see Note 5.

Foreign currency translation

In individual subsidiaries, joint ventures and associates, transactions in foreign currencies are initially recorded in the functional currency of

those entities at the spot exchange rate on the date of the transaction. Monetary assets and liabilities denominated in foreign currencies are

retranslated into the functional currency at the spot exchange rate on the balance sheet date. Any resulting exchange differences are included

in the income statement, unless hedge accounting is applied. Non-monetary assets and liabilities, other than those measured at fair value, are

not retranslated subsequent to initial recognition.

In the consolidated financial statements, the assets and liabilities of non-US dollar functional currency subsidiaries, joint ventures, associates,

and related goodwill, are translated into US dollars at the spot exchange rate on the balance sheet date. The results and cash flows of non-US

dollar functional currency subsidiaries, joint ventures and associates are translated into US dollars using average rates of exchange. In the

consolidated financial statements, exchange adjustments arising when the opening net assets and the profits for the year retained by non-US

dollar functional currency subsidiaries, joint ventures and associates are translated into US dollars are recognized in a separate component of

equity and reported in other comprehensive income. Exchange gains and losses arising on long-term intra-group foreign currency borrowings

used to finance the group’s non-US dollar investments are also reported in other comprehensive income if the borrowings form part of the net

investment in the subsidiary, joint venture or associate. On disposal or for certain partial disposals of a non-US dollar functional currency

subsidiary, joint venture or associate, the related accumulated exchange gains and losses recognized in equity are reclassified from equity to

the income statement.

158 BP Annual Report and Form 20-F 2019

1. Significant accounting policies, judgements, estimates and assumptions – continued

Non-current assets held for sale

Non-current assets and disposal groups classified as held for sale are measured at the lower of carrying amount and fair value less costs to

sell.

Significant non-current assets and disposal groups are classified as held for sale if their carrying amounts will be recovered through a sale

transaction rather than through continuing use. This condition is regarded as met only when the sale is highly probable and the asset or

disposal group is available for immediate sale in its present condition subject only to terms that are usual and customary for sales of such

assets. Management must be committed to the sale, which should be expected to qualify for recognition as a completed sale within one year

from the date of classification as held for sale, and actions required to complete the plan of sale should indicate that it is unlikely that

significant changes to the plan will be made or that the plan will be withdrawn.

Property, plant and equipment and intangible assets are not depreciated or amortized once classified as held for sale.

Intangible assets

Intangible assets, other than goodwill, include expenditure on the exploration for and evaluation of oil and natural gas resources, computer

software, patents, licences and trademarks and are stated at the amount initially recognized, less accumulated amortization and accumulated

impairment losses.

Intangible assets are carried initially at cost unless acquired as part of a business combination. Any such asset is measured at fair value at the

date of the business combination and is recognized separately from goodwill if the asset is separable or arises from contractual or other legal

rights.

Intangible assets with a finite life, other than capitalized exploration and appraisal costs as described below, are amortized on a straight-line

basis over their expected useful lives. For patents, licences and trademarks, expected useful life is the shorter of the duration of the legal

agreement and economic useful life, and can range from three to fifteen years. Computer software costs generally have a useful life of three to

five years.

The expected useful lives of assets and the amortization method are reviewed on an annual basis and, if necessary, changes in useful lives or

the amortization method are accounted for prospectively.

Oil and natural gas exploration, appraisal and development expenditure

Oil and natural gas exploration, appraisal and development expenditure is accounted for using the principles of the successful efforts method

of accounting as described below.

Licence and property acquisition costs

Exploration licence and leasehold property acquisition costs are capitalized within intangible assets and are reviewed at each reporting date to

confirm that there is no indication that the carrying amount exceeds the recoverable amount. This review includes confirming that exploration

drilling is still under way or planned or that it has been determined, or work is under way to determine, that the discovery is economically viable

based on a range of technical and commercial considerations, and sufficient progress is being made on establishing development plans and

timing. If no future activity is planned, the remaining balance of the licence and property acquisition costs is written off. Lower value licences

are pooled and amortized on a straight-line basis over the estimated period of exploration. Upon internal approval for development and

recognition of proved reserves of oil and natural gas, the relevant expenditure is transferred to property, plant and equipment.

Exploration and appraisal expenditure

Geological and geophysical exploration costs are recognized as an expense as incurred. Costs directly associated with an exploration well are

initially capitalized as an intangible asset until the drilling of the well is complete and the results have been evaluated. These costs include

employee remuneration, materials and fuel used, rig costs and payments made to contractors. If potentially commercial quantities of

hydrocarbons are not found, the exploration well costs are written off. If hydrocarbons are found and, subject to further appraisal activity, are

likely to be capable of commercial development, the costs continue to be carried as an asset. If it is determined that development will not

occur then the costs are expensed.

Costs directly associated with appraisal activity undertaken to determine the size, characteristics and commercial potential of a reservoir

following the initial discovery of hydrocarbons, including the costs of appraisal wells where hydrocarbons were not found, are initially

capitalized as an intangible asset. Upon internal approval for development and recognition of proved reserves, the relevant expenditure is

transferred to property, plant and equipment.

The determination of whether potentially economic oil and natural gas reserves have been discovered by an exploration well is usually made

within one year of well completion, but can take longer, depending on the complexity of the geological structure. Exploration wells that

discover potentially economic quantities of oil and natural gas and are in areas where major capital expenditure (e.g. an offshore platform or a

pipeline) would be required before production could begin, and where the economic viability of that major capital expenditure depends on the

successful completion of further exploration or appraisal work in the area, remain capitalized on the balance sheet as long as such work is

under way or firmly planned.

Development expenditure

Expenditure on the construction, installation and completion of infrastructure facilities such as platforms, pipelines and the drilling of

development wells, including service and unsuccessful development or delineation wells, is capitalized within property, plant and equipment

and is depreciated from the commencement of production as described below in the accounting policy for property, plant and equipment.

BP Annual Report and Form 20-F 2019 159

1. Significant accounting policies, judgements, estimates and assumptions – continued

Significant judgement: exploration and appraisal intangible assets

Judgement is required to determine whether it is appropriate to continue to carry costs associated with exploration wells and exploratory-

type stratigraphic test wells on the balance sheet. This includes costs relating to exploration licences or leasehold property acquisitions. It is

not unusual to have such costs remaining suspended on the balance sheet for several years while additional appraisal drilling and seismic

work on the potential oil and natural gas field is performed or while the optimum development plans and timing are established.The costs are

carried based on the current regulatory and political environment or any known changes to that environment. All such carried costs are

subject to regular technical, commercial and management review on at least an annual basis to confirm the continued intent to develop, or

otherwise extract value from, the discovery. Where this is no longer the case, the costs are immediately expensed.

In scenarios where the expected time horizon for establishing the development plan is lengthy or uncertain, greater judgement is required. BP

is in the exploration and appraisal phase in certain Canadian oil sands assets that require further advancement of low-carbon extraction technology

in order to achieve optimum development. Sufficient technological progress is expected to be achieved and therefore BP continues to carry the

capitalized costs on its balance sheet.

The judgement disclosed in prior years in relation to expiring leases in the Gulf of Mexico is no longer considered to be significant following

recent agreement of lease extensions with the US Bureau of Safety and Environmental Enforcement.

The carrying amount of capitalized costs is included in Note 8.

Property, plant and equipment

Property, plant and equipment owned by the group is stated at cost, less accumulated depreciation and accumulated impairment losses. The

initial cost of an asset comprises its purchase price or construction cost, any costs directly attributable to bringing the asset into the location

and condition necessary for it to be capable of operating in the manner intended by management, the initial estimate of any decommissioning

obligation, if any, and, for assets that necessarily take a substantial period of time to get ready for their intended use, directly attributable

general or specific finance costs. The purchase price or construction cost is the aggregate amount paid and the fair value of any other

consideration given to acquire the asset.

Expenditure on major maintenance refits or repairs comprises the cost of replacement assets or parts of assets, inspection costs and overhaul

costs. Where an asset or part of an asset that was separately depreciated is replaced and it is probable that future economic benefits

associated with the item will flow to the group, the expenditure is capitalized and the carrying amount of the replaced asset is derecognized.

Inspection costs associated with major maintenance programmes are capitalized and amortized over the period to the next inspection.

Overhaul costs for major maintenance programmes, and all other maintenance costs are expensed as incurred.

Oil and natural gas properties, including certain related pipelines, are depreciated using a unit-of-production method. The cost of producing

wells is amortized over proved developed reserves. Licence acquisition, common facilities and future decommissioning costs are amortized

over total proved reserves. The unit-of-production rate for the depreciation of common facilities takes into account expenditures incurred to

date, together with estimated future capital expenditure expected to be incurred relating to as yet undeveloped reserves expected to be

processed through these common facilities. Information on the carrying amounts of the group’s oil and natural gas properties, together with

the amounts recognized in the income statement as depreciation, depletion and amortization is contained in Note 12 and Note 5 respectively.

Estimates of oil and natural gas reserves determined by applying US Securities and Exchange Commission regulations including the

determination of prices using 12-month historical data are used to calculate depreciation, depletion and amortization charges for the group’s oil

and gas properties. Therefore, the charges are not dependent on management forecasts of future oil and gas prices. The impact of changes in

estimated proved reserves is dealt with prospectively by amortizing the remaining carrying value of the asset over the expected future

production. Management does not believe that a reasonably possible change in the economic environment would result in a material change to

the depreciation and amortization charge for other classes of assets.

The estimation of oil and natural gas reserves and BP’s process to manage reserves bookings is described in Supplementary information on oil

and natural gas on page 232, which is unaudited. Details on BP’s proved reserves and production compliance and governance processes are

provided on page 286. The 2019 movements in proved reserves are reflected in the tables showing movements in oil and natural gas reserves

by region in Supplementary information on oil and natural gas (unaudited) on page 232.

Other property, plant and equipment is depreciated on a straight-line basis over its expected useful life. The typical useful lives of the group’s

other property, plant and equipment are as follows:

Land improvements 15†to†25†years

Buildings 20†to†50†years

Refineries 20†to†30†years

Petrochemicals plants 20 to 30 years

Pipelines 10 to 50 years

Service stations 15 years

Office equipment 3 to 7 years

Fixtures and fittings 5 to 15 years

The expected useful lives and depreciation method of property, plant and equipment are reviewed on an annual basis and, if necessary,

changes in useful lives or the depreciation method are accounted for prospectively.

An item of property, plant and equipment is derecognized upon disposal or when no future economic benefits are expected to arise from the

continued use of the asset. Any gain or loss arising on derecognition of the asset (calculated as the difference between the net disposal

proceeds and the carrying amount of the item) is included in the income statement in the period in which the item is derecognized.

160 BP Annual Report and Form 20-F 2019

1. Significant accounting policies, judgements, estimates and assumptions – continued

Impairment of property, plant and equipment, intangible assets, and goodwill

The group assesses assets or groups of assets, called cash-generating units (CGUs), for impairment whenever events or changes in

circumstances indicate that the carrying amount of an asset or CGU may not be recoverable; for example, changes in the group’s business

plans, changes in the group’s assumptions about commodity prices, low plant utilization, evidence of physical damage or, for oil and gas

assets, significant downward revisions of estimated reserves or increases in estimated future development expenditure or decommissioning

costs. If any such indication of impairment exists, the group makes an estimate of the asset’s or CGU’s recoverable amount. Individual assets

are grouped into CGUs for impairment assessment purposes at the lowest level at which there are identifiable cash flows that are largely

independent of the cash flows of other groups of assets. A CGU’s recoverable amount is the higher of its fair value less costs of disposal and

its value in use. If it is probable that the value of the CGU will be primarily recovered through a disposal transaction, the expected disposal

proceeds are considered in determining the recoverable amount. Where the carrying amount of a CGU exceeds its recoverable amount, the

CGU is considered impaired and is written down to its recoverable amount.

The business segment plans, which are approved on an annual basis by senior management, are the primary source of information for the

determination of value in use. They contain forecasts for oil and natural gas production, refinery throughputs, sales volumes for various types of

refined products (e.g. gasoline and lubricants), revenues, costs and capital expenditure. As an initial step in the preparation of these plans,

various assumptions regarding market conditions, such as oil prices, natural gas prices, refining margins, refined product margins and cost

inflation rates are set by senior management. These assumptions take account of existing prices, global supply-demand equilibrium for oil and

natural gas, other macroeconomic factors and historical trends and variability. In assessing value in use, the estimated future cash flows are

adjusted for the risks specific to the asset group that are not reflected in the discount rate and are discounted to their present value typically

using a pre-tax discount rate that reflects current market assessments of the time value of money.

Fair value less costs of disposal is the price that would be received to sell the asset in an orderly transaction between market participants and

does not reflect the effects of factors that may be specific to the group and not applicable to entities in general. In limited circumstances

where recent market transactions are not available for reference, discounted cash flow techniques are applied. Where discounted cash flow

analyses are used to calculate fair value less costs of disposal, estimates are made about the assumptions market participants would use

when pricing the asset, CGU or group of CGUs containing goodwill and the test is performed on a post-tax basis.

An assessment is made at each reporting date as to whether there is any indication that previously recognized impairment losses may no

longer exist or may have decreased. If such an indication exists, the recoverable amount is estimated. A previously recognized impairment loss

is reversed only if there has been a change in the estimates used to determine the asset’s recoverable amount since the last impairment loss

was recognized. If that is the case, the carrying amount of the asset is increased to the lower of its recoverable amount and the carrying

amount that would have been determined, net of depreciation, had no impairment loss been recognized for the asset in prior years.

Impairment reversals are recognized in profit or loss. After a reversal, the depreciation charge is adjusted in future periods to allocate the

asset’s revised carrying amount, less any residual value, on a systematic basis over its remaining useful life.

Goodwill is reviewed for impairment annually or more frequently if events or changes in circumstances indicate the recoverable amount of the

group of CGUs to which the goodwill relates should be assessed. In assessing whether goodwill has been impaired, the carrying amount of

the group of CGUs to which goodwill has been allocated is compared with its recoverable amount. Where the recoverable amount of the group

of CGUs is less than the carrying amount (including goodwill), an impairment loss is recognized. An impairment loss recognized for goodwill is

not reversed in a subsequent period.

BP Annual Report and Form 20-F 2019 161

1. Significant accounting policies, judgements, estimates and assumptions – continued

Significant judgements and estimates: recoverability of asset carrying values

Determination as to whether, and by how much, an asset, CGU, or group of CGUs containing goodwill is impaired involves management

estimates on highly uncertain matters such as the effects of inflation and deflation on operating expenses, discount rates, production

profiles, reserves and resources, and future commodity prices, including the outlook for global or regional market supply-and-demand

conditions for crude oil, natural gas and refined products. Judgement is required when determining the appropriate grouping of assets into a

CGU or the appropriate grouping of CGUs for impairment testing purposes. For example, individual oil and gas properties may form separate

CGUs whilst certain oil and gas properties with shared infrastructure may be grouped together to form a single CGU. Alternative groupings of

assets or CGUs may result in a different outcome from impairment testing. See Note 14 for details on how these groupings have been

determined in relation to the impairment testing of goodwill.

As disclosed above, the recoverable amount of an asset is the higher of its value in use and its fair value less costs of disposal. Fair value less

costs of disposal may be determined based on expected sales proceeds or similar recent market transaction data.

Details of impairment charges and reversals recognized in the income statement are provided in Note 4 and details on the carrying amounts

of assets are shown in Note 12, Note 14 and Note 15.

The estimates for assumptions made in impairment tests in 2019 relating to discount rates and oil and gas properties are discussed below.

Changes in the economic environment or other facts and circumstances may necessitate revisions to these assumptions and could result in

a material change to the carrying values of the group's assets within the next financial year.

Discount rates

For discounted cash flow calculations, future cash flows are adjusted for risks specific to the CGU. Value-in-use calculations are typically

discounted using a pre-tax discount rate based upon the cost of funding the group derived from an established model, adjusted to a pre-tax

basis and incorporating a market participant capital structure. Fair value less costs of disposal calculations use the post-tax discount rate.

The discount rates applied in impairment tests are reassessed each year. In 2019 the post-tax discount rate was 6% (2018 6%) and the pre-

tax discount rate typically ranged from 7% to 13% (2018 9%) depending on the applicable tax rate in the geographic location of the CGU.

Where the CGU is located in a country that is judged to be higher risk an additional premium of 1% to 4% was added to the discount rates

(2018 2%). The judgement of classifying a country as higher risk and the applicable premium takes into account various economic and

geopolitical factors.

Oil and natural gas properties

For oil and natural gas properties, expected future cash flows are estimated using management’s best estimate of future oil and natural gas

prices and production and reserves volumes. The estimated future level of production in all impairment tests is based on assumptions about

future commodity prices, production and development costs, field decline rates, current fiscal regimes and other factors.

The recoverable amount of oil and gas properties is primarily sensitive to changes in the oil and gas price assumptions. Further sensitivity analysis

may be performed if a specific oil and gas property is identified to have low headroom above its carrying amount. In 2019, the group identified

oil and gas properties with carrying amounts totalling $25,092 million (2018 $22,000 million) where the headroom, as at the dates of the last

impairment test performed on those assets, was less than or equal to 20% of the carrying value, including $1,256 million (2018 $1,345 million)

in relation to equity-accounted entities. A change in the discount rate, reserves, resources or the oil and gas price assumptions in the next

financial year may result in the recoverable amount of one or more of these assets falling below the current carrying amount.

The recoverability of intangible exploration and appraisal expenditure is covered under Oil and natural gas exploration, appraisal and

development expenditure above.

Oil and natural gas prices

The long-term price assumptions used for investment appraisal are recommended by the group chief economist after considering a range of

external price, and supply and demand forecasts under various energy transition scenarios. They are reviewed and approved by

management. As a result of the current uncertainty over the pace of transition to lower-carbon supply and demand and the social, political

and environmental actions that will be taken to meet the goals of the Paris climate change agreement, the forecasts and scenarios

considered include those where those goals are met as well as those where they are not met. The assumptions below represent

management’s best estimate of future prices; they do not reflect a specific scenario and sit within the range of the external forecasts

considered.

The long-term price assumptions used to determine recoverable amount based on value-in-use impairments tests are derived from the

central case investment appraisal assumptions (see page 19) of $70 per barrel for Brent and $4 per mmBtu for Henry Hub gas, both in 2015

prices (2018 $75 per barrel and $4 per mmBtu respectively, in 2015 prices). These long-term prices are applied from 2025 and 2032

respectively (2018 both from 2024) and continue to be inflated for the remaining life of the asset.

The price assumptions used over the periods to 2025 and 2032 have been set such that there is a linear progression from our best estimate

of 2020 prices, which were set by reference to 2019 average prices, to the long-term assumptions.

The majority of BP’s reserves and resources that support the carrying value of the group’s oil and gas properties are expected to be produced

over the next 10 years. Average prices (in real 2015 terms) used to estimate cash flows over this period are $67 per barrel for Brent and $3.1

per mmBtu for Henry Hub gas.

Oil prices fell 10% in 2019 from 2018 due to trade tensions, a macroeconomic downturn, and a slight slowdown in oil demand. OPEC+

production restraint, unplanned outages, and sanctions on Venezuela and Iran kept prices from falling further. BP's long-term assumption for

oil prices is higher than the 2019 price average, based on the judgement that current price levels would not encourage sufficient investment

to meet global oil demand sustainably in the longer term, especially given the financial requirements of key low-cost oil producing

economies.

US gas prices dropped by around 15% in 2019 compared to 2018. After an initial spike in January, they remained relatively low for much of

the year due to a combination of strong associated gas production growth, and storage levels coming back to normal. US gas demand

growth was much lower than the exceptional increase in 2018, while LNG exports continued to expand. BP's long-term price assumption for

US gas is higher than recent market prices due to forecast rising domestic demand, rapidly increasing pipeline and LNG exports, and lowest

cost resources being absorbed leading to production of more expensive gas, as well as requiring increased investment in infrastructure.

162 BP Annual Report and Form 20-F 2019

1. Significant accounting policies, judgements, estimates and assumptions – continued

Management tested the impact of a reduction in prices of 15% against the best estimate for Brent oil and Henry Hub gas in all future years.

These price reductions in isolation could indicatively lead to a reduction in the carrying amount of BP’s oil and gas properties in the range of

$2-3 billion, which is approximately 1-2% of the net book value of property, plant and equipment as at 31 December 2019.

Management also tested the impact of a scenario where Brent oil and Henry Hub gas prices start 15% lower than the best estimate and

gradually reduce to 25% lower than the best estimate by 2040. Although this is not considered to be a reasonably possible change in the

long-term assumptions within the next financial year, it reflects the inherent uncertainty in forecasting long-term prices. These price

reductions in isolation could indicatively lead to a reduction in the carrying amount of BP’s oil and gas properties in the range of $4-5 billion

which is approximately 3-4% of the net book value of property, plant and equipment as at 31 December 2019. Additionally, such a price

reduction does not indicate a reduction in the carrying amount of the Upstream goodwill balance.

These sensitivity analyses do not, however, represent management’s best estimate of any impairments that might be recognized as they do

not fully incorporate consequential changes that may arise, such as reductions in costs and changes to business plans, phasing of

development, levels of reserves and resources, and production volumes. As the extent of a price reduction increases, the more likely it is that

costs would decrease across the industry. The above sensitivity analyses therefore do not reflect a linear relationship between price and

value that can be extrapolated. Past experience of performing impairment tests suggests that any impairment arising from such price

reductions is likely to be lower once all these factors are taken into consideration. The interdependency of these inputs and risk factors plus

the diverse characteristics of our oil and gas properties limits the practicability of estimating the probability or extent to which the overall

recoverable amount is impacted by changes to the price assumptions.

The decline in oil and natural gas prices in the first quarter of 2020 is not expected to materially impact the recoverable amount of the group’s

oil and natural gas properties.

Oil and natural gas reserves

In addition to oil and natural gas prices, significant technical and commercial assessments are required to determine the group’s estimated oil

and natural gas reserves. Reserves estimates are regularly reviewed and updated. Factors such as the availability of geological and

engineering data, reservoir performance data, acquisition and divestment activity and drilling of new wells all impact on the determination of

the group’s estimates of its oil and natural gas reserves. BP bases its proved reserves estimates on the requirement of reasonable certainty

with rigorous technical and commercial assessments based on conventional industry practice and regulatory requirements.

Reserves assumptions for value-in-use tests reflect the reserves and resources that management currently intend to develop. The

recoverable amount of oil and gas properties is determined using a combination of inputs including reserves, resources and production

volumes. Risk factors may be applied to reserves and resources which do not meet the criteria to be treated as proved.†

Goodwill

Irrespective of whether there is any indication of impairment, BP is required to test annually for impairment of goodwill acquired in business

combinations. The group carries goodwill of approximately $11.9 billion on its balance sheet (2018 $12.2 billion), principally relating to the

Atlantic Richfield, Burmah Castrol, Devon Energy and Reliance transactions. Sensitivities and additional information relating to impairment

testing of goodwill in the Upstream segment are provided in Note 14.

Inventories

Inventories, other than inventories held for short-term trading purposes, are stated at the lower of cost and net realizable value. Cost is

determined by the first-in first-out method and comprises direct purchase costs, cost of production, transportation and manufacturing

expenses. Net realizable value is determined by reference to prices existing at the balance sheet date, adjusted where the sale of inventories

after the reporting period gives evidence about their net realizable value at the end of the period.

Inventories held for short-term trading purposes are stated at fair value less costs to sell and any changes in fair value are recognized in the

income statement.

Supplies are valued at the lower of cost on a weighted average basis and net realizable value.

Leases

Agreements that convey the right to control the use of an identified asset for a period of time in exchange for consideration are accounted for

as leases. The right to control is conveyed if BP has both the right to obtain substantially all of the economic benefits from, and the right to

direct the use of, the identified asset throughout the period of use. An asset is identified if it is explicitly or implicitly specified by the

agreement and any substitution rights held by the lessor over the asset are not considered substantive.

Agreements that convey the right to control the use of an intangible asset including rights to explore for or use hydrocarbons are not accounted

for as leases. See significant accounting policy: intangible assets.

A lease liability is recognized on the balance sheet on the lease commencement date at the present value of future lease payments over the

lease term. The discount rate applied is the rate implicit in the lease if readily determinable, otherwise an incremental borrowing rate is used.

The incremental borrowing rate is determined based on factors such as the group’s cost of borrowing, lessee legal entity credit risk, currency

and lease term. The lease term is the non-cancellable period of a lease together with any periods covered by an extension option that BP is

reasonably certain to exercise, or periods covered by a termination option that BP is reasonably certain not to exercise. The future lease

payments included in the present value calculation are any fixed payments, payments that vary depending on an index or rate, payments due

for the reasonably certain exercise of options and expected residual value guarantee payments.

Payments that vary based on factors other than an index or a rate such as usage, sales volumes or revenues are not included in the present

value calculation and are recognized in the income statement. The lease liability is recognized on an amortized cost basis with interest expense

recognized in the income statement over the lease term, except for where capitalized as exploration, appraisal or development expenditure.

The right-of-use asset is recognized on the balance sheet as property, plant and equipment at a value equivalent to the initial measurement of

the lease liability adjusted for lease prepayments, lease incentives, initial direct costs and any restoration obligations. The right-of-use asset is

depreciated typically on a straight-line basis over the lease term. The depreciation charge is recognized in the income statement except for

where capitalized as exploration, appraisal or development expenditure. Right-of-use assets are assessed for impairment in line with the

accounting policy for impairment of property, plant and equipment, intangible assets, and goodwill.

Agreements may include both lease and non-lease components. Payments for lease and non-lease components are allocated on a relative

stand-alone selling price basis except for leases of retail service stations where the group has elected not to separate non-lease payments

from the calculation of the lease liability and right-of-use asset.

BP Annual Report and Form 20-F 2019 163

1. Significant accounting policies, judgements, estimates and assumptions – continued

If the lease term at commencement of the agreement is less than 12 months, a lease liability and right-of-use asset are not recognized, and a

lease expense is recognized in the income statement on a straight-line basis.

If a significant event or change in circumstances, within the control of BP, arises that affects the reasonably certain lease term or there are

changes to the lease payments, the present value of the lease liability is remeasured using the revised term and payments, with the right-of-

use asset adjusted by an equivalent amount.

Modifications to a lease agreement beyond the original terms and conditions are accounted for as a re-measurement of the lease liability with

a corresponding adjustment to the right-of-use asset. Any gain or loss on modification is recognized in the income statement. Modifications

that increase the scope of the lease at a price commensurate with the stand-alone selling price are accounted for as a separate new lease.

The group recognizes the full lease liability, rather than its working interest share, for leases entered into on behalf of a joint operation if the

group has the primary responsibility for making the lease payments. In such cases, BP’s working interest share of the right-of-use asset is

recognized if it is jointly controlled by the group and the other joint operators, and a receivable is recognized for the share of the asset

transferred to the other joint operators. If BP is a non-operator, a payable to the operator is recognized if they have the primary responsibility for

making the lease payments and BP has joint control over the right-of-use asset, otherwise no balances are recognized.

As noted in ‘Impact of new International Financial Reporting Standards - IFRS 16 ‘Leases’, BP elected to apply the ‘modified retrospective’

transition approach on adoption of IFRS 16. Under this approach, comparative periods’ financial information is not restated. The accounting

policy applicable for leases in the comparative periods only is disclosed in the following paragraphs.

Agreements under which payments are made to owners in return for the right to use a specific asset are accounted for as leases. Leases that

transfer substantially all the risks and rewards of ownership are recognized as finance leases. All other leases are accounted for as operating

leases.

Finance leases are capitalized at the commencement of the lease term at the fair value of the leased item or, if lower, at the present value of

the minimum lease payments. Finance charges are allocated to each period so as to achieve a constant rate of interest on the remaining

balance of the liability and are charged directly against income. Capitalized leased assets are depreciated over the shorter of the estimated

useful life of the asset or the lease term. Operating lease payments are recognized as an expense on a straight-line basis over the lease term

except where capitalized as exploration or appraisal expenditure. See significant accounting policy: Exploration and appraisal expenditure.

Financial assets

Financial assets are recognized initially at fair value, normally being the transaction price. In the case of financial assets not at fair value through

profit or loss, directly attributable transaction costs are also included. The subsequent measurement of financial assets depends on their

classification, as set out below. The group derecognizes financial assets when the contractual rights to the cash flows expire or the rights to

receive cash flows have been transferred to a third party along with either substantially all of the risks and rewards or control of the asset. This

includes the derecognition of receivables for which discounting arrangements are entered into.

The group classifies its financial asset debt instruments as measured at amortized cost, fair value through other comprehensive income or fair

value through profit or loss. The classification depends on the business model for managing the financial assets and the contractual cash flow

characteristics of the financial asset.

Financial assets measured at amortized cost

Financial assets are classified as measured at amortized cost when they are held in a business model the objective of which is to collect

contractual cash flows and the contractual cash flows represent solely payments of principal and interest. Such assets are carried at amortized

cost using the effective interest method if the time value of money is significant. Gains and losses are recognized in profit or loss when the

assets are derecognized or impaired and when interest is recognized using the effective interest method. This category of financial assets

includes trade and other receivables.

Financial assets measured at fair value through other comprehensive income

Financial assets are classified as measured at fair value through other comprehensive income when they are held in a business model the

objective of which is both to collect contractual cash flows and sell the financial assets, and the contractual cash flows represent solely

payments of principal and interest. The group does not have any financial assets classified in this category.

Financial assets measured at fair value through profit or loss

Financial assets are classified as measured at fair value through profit or loss when the asset does not meet the criteria to be measured at

amortized cost or fair value through other comprehensive income. Such assets are carried on the balance sheet at fair value with gains or

losses recognized in the income statement. Derivatives, other than those designated as effective hedging instruments, are included in this

category.

Investments in equity instruments

Investments in equity instruments are subsequently measured at fair value through profit or loss unless an election is made on an instrument-

by-instrument basis to recognise fair value gains and losses in other comprehensive income. The group does not have any investments for

which this election has been made.

Derivatives designated as hedging instruments in an effective hedge

Derivatives designated as hedging instruments in an effective hedge are carried on the balance sheet at fair value. The treatment of gains and

losses arising from revaluation is described below in the accounting policy for derivative financial instruments and hedging activities.

Cash equivalents

Cash equivalents are short-term highly liquid investments that are readily convertible to known amounts of cash, are subject to insignificant risk

of changes in value and generally have a maturity of three months or less from the date of acquisition. Cash equivalents are classified as

financial assets measured at amortized cost or, in the case of certain money market funds, fair value through profit or loss.

164 BP Annual Report and Form 20-F 2019

1. Significant accounting policies, judgements, estimates and assumptions – continued

Impairment of financial assets measured at amortized cost

The group assesses on a forward-looking basis the expected credit losses associated with financial assets classified as measured at amortized

cost at each balance sheet date. Expected credit losses are measured based on the maximum contractual period over which the group is

exposed to credit risk. As lifetime expected credit losses are recognized for trade receivables and the tenor of substantially all of other in-scope

financial assets is less than 12 months there is no significant difference between the measurement of 12-month and lifetime expected credit

losses for the group. The measurement of expected credit losses is a function of the probability of default, loss given default and exposure at

default. The expected credit loss is estimated as the difference between the asset’s carrying amount and the present value of the future cash

flows the group expects to receive discounted at the financial asset’s original effective interest rate. The carrying amount of the asset is

adjusted, with the amount of the impairment gain or loss recognized in the income statement.

A financial asset or group of financial assets classified as measured at amortized cost is considered to be credit-impaired if there is reasonable

and supportable evidence that one or more events that have a detrimental impact on the estimated future cash flows of the financial asset (or

group of financial assets) have occurred. Financial assets are written off where the group has no reasonable expectation of recovering amounts

due.

Financial liabilities

The measurement of financial liabilities depends on their classification, as follows:

Financial liabilities measured at fair value through profit or loss

Financial liabilities that meet the definition of held for trading are classified as measured at fair value through profit or loss. Such liabilities are

carried on the balance sheet at fair value with gains or losses recognized in the income statement. Derivatives, other than those designated as

effective hedging instruments, are included in this category.

Derivatives designated as hedging instruments in an effective hedge

Derivatives designated as hedging instruments in an effective hedge are carried on the balance sheet at fair value. The treatment of gains and

losses arising from revaluation is described below in the accounting policy for derivative financial instruments and hedging activities.

Financial liabilities measured at amortized cost

All other financial liabilities are initially recognized at fair value, net of directly attributable transaction costs. For interest-bearing loans and

borrowings this is typically equivalent to the fair value of the proceeds received, net of issue costs associated with the borrowing.

After initial recognition, other financial liabilities are subsequently measured at amortized cost using the effective interest method. Amortized

cost is calculated by taking into account any issue costs and any discount or premium on settlement. Gains and losses arising on the

repurchase, settlement or cancellation of liabilities are recognized in interest and other income and finance costs respectively.

This category of financial liabilities includes trade and other payables and finance debt.

The group’s trade payables include some supplier arrangements that utilize letter of credit facilities (see Note 29 - Liquidity risk for further

information). The group assesses the payables subject to these arrangements to determine whether they should continue to be classified as

trade payables and give rise to operating cash flows or finance debt and financing cash flows. The criteria used in making this assessment

include the payment terms for the†amount due relative to terms commonly seen in the markets in which BP operates. Liabilities subject to

these arrangements with payment terms of up to approximately 60 days are generally considered to be trade payables and give rise to

operating cash flows.††

Derivative financial instruments and hedging activities

The group uses derivative financial instruments to manage certain exposures to fluctuations in foreign currency exchange rates, interest rates

and commodity prices, as well as for trading purposes. These derivative financial instruments are recognized initially at fair value on the date on

which a derivative contract is entered into and subsequently remeasured at fair value. Derivatives are carried as assets when the fair value is

positive and as liabilities when the fair value is negative.

Contracts to buy or sell a non-financial item (for example, oil, oil products, gas or power) that can be settled net in cash, with the exception of

contracts that were entered into and continue to be held for the purpose of the receipt or delivery of a non-financial item in accordance with

the group’s expected purchase, sale or usage requirements, are accounted for as financial instruments. Gains or losses arising from changes in

the fair value of derivatives that are not designated as effective hedging instruments are recognized in the income statement.

If, at inception of a contract, the valuation cannot be supported by observable market data, any gain or loss determined by the valuation

methodology is not recognized in the income statement but is deferred on the balance sheet and is commonly known as ‘day-one gain or loss’.

This deferred gain or loss is recognized in the income statement over the life of the contract until substantially all the remaining contract term

can be valued using observable market data at which point any remaining deferred gain or loss is recognized in the income statement.

Changes in valuation subsequent to the initial valuation at inception of a contract are recognized immediately in the income statement.

For the purpose of hedge accounting, hedges are classified as:

• Fair value hedges when hedging exposure to changes in the fair value of a recognized asset or liability.

• Cash flow hedges when hedging exposure to variability in cash flows that is attributable to either a particular risk associated with a

recognized asset or liability or a highly probable forecast transaction.

Hedge relationships are formally designated and documented at inception, together with the risk management objective and strategy for

undertaking the hedge. The documentation includes identification of the hedging instrument, the hedged item or transaction, the nature of the

risk being hedged, the existence at inception of an economic relationship and subsequent measurement of the hedging instrument's

effectiveness in offsetting the exposure to changes in the hedged item’s fair value or cash flows attributable to the hedged risk, the hedge

ratio and sources of hedge ineffectiveness. Hedges meeting the criteria for hedge accounting are accounted for as follows:

BP Annual Report and Form 20-F 2019 165

1. Significant accounting policies, judgements, estimates and assumptions – continued

Fair value hedges

The change in fair value of a hedging derivative is recognized in profit or loss. The change in the fair value of the hedged item attributable to the

risk being hedged is recorded as part of the carrying value of the hedged item and is also recognized in profit or loss, where it offsets. The

group applies fair value hedge accounting when hedging interest rate risk and certain currency risks on fixed rate finance debt.

Fair value hedge accounting is discontinued only when the hedging relationship or a part thereof ceases to meet the qualifying criteria. This

includes when the risk management objective changes or when the hedging instrument is sold, terminated or exercised. The accumulated

adjustment to the carrying amount of a hedged item at such time is then amortized prospectively to profit or loss as finance interest expense

over the hedged item's remaining period to maturity.

Cash flow hedges

The effective portion of the gain or loss on a cash flow hedging instrument is reported in other comprehensive income, while the ineffective

portion is recognized in profit or loss. Amounts reported in other comprehensive income are reclassified to the income statement when the

hedged transaction affects profit or loss.

Where the hedged item is a highly probably forecast transaction that results in the recognition of a non-financial asset or liability, such as a

forecast foreign currency transaction for the purchase of property, plant and equipment, the amounts recognized within other comprehensive

income are transferred to the initial carrying amount of the non-financial asset or liability. Where the hedged item is an equity investment, the

amounts recognized in other comprehensive income remain in the separate component of equity until the hedged cash flows affect profit or

loss. Where the hedged item is recognized directly in profit or loss, the amounts recognized in other comprehensive income are reclassified to

production and manufacturing expenses or sales and other operating revenues as appropriate.

Cash flow hedge accounting is discontinued only when the hedging relationship or a part thereof ceases to meet the qualifying criteria. This

includes when the designated hedged forecast transaction or part thereof is no longer considered to be highly probable to occur, or when the

hedging instrument is sold, terminated or exercised without replacement or rollover. When cash flow hedge accounting is discontinued

amounts previously recognized within other comprehensive income remain in equity until the forecast transaction occurs and are reclassified

to profit or loss or transferred to the initial carrying amount of a non-financial asset or liability as above. If the forecast transaction is no longer

expected to occur, amounts previously recognized within other comprehensive income will be immediately reclassified to profit or loss.

Costs of hedging

The foreign currency basis spread of cross-currency interest rate swaps are excluded from hedge designations and accounted for as costs of

hedging. Changes in fair value of the foreign currency basis spread are recognized in other comprehensive income to the extent that they

relate to the hedged item. For time-period related hedged items, the amount recognized in other comprehensive income is amortized to profit

or loss on a straight line basis over the term of the hedging relationship.

Fair value measurement

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants.

The group categorizes assets and liabilities measured at fair value into one of three levels depending on the ability to observe inputs employed

in their measurement. Level 1 inputs are quoted prices in active markets for identical assets or liabilities. Level 2 inputs are inputs that are

observable, either directly or indirectly, other than quoted prices included within level 1 for the asset or liability. Level 3 inputs are unobservable

inputs for the asset or liability reflecting significant modifications to observable related market data or BP’s assumptions about pricing by

market participants.

Significant estimate and judgement: derivative financial instruments

In some cases the fair values of derivatives are estimated using internal models due to the absence of quoted prices or other observable,

market-corroborated data. This primarily applies to the group’s longer-term derivative contracts. The majority of these contracts are valued

using models with inputs that include price curves for each of the different products that are built up from available active market pricing data

(including volatility and correlation) and modelled using the maximum available external information. Additionally, where limited data exists for

certain products, prices are determined using historical and long-term pricing relationships. The use of alternative assumptions or valuation

methodologies may result in significantly different values for these derivatives. A reasonably possible change in the price assumptions used

in the models relating to index price would not have a material impact on net assets and the Group income statement primarily as a result of

offsetting movements between derivative assets and liabilities. For more information, including the carrying amounts of level 3 derivatives,

see Note 30.

In some cases, judgement is required to determine whether contracts to buy or sell commodities meet the definition of a derivative. In

particular longer -term contracts to buy and sell LNG are not considered to meet the definition as they are not considered capable of being

net settled due to a lack of liquidity in the LNG market and so are accounted for on an accruals basis, rather than as a derivative.

Offsetting of financial assets and liabilities

Financial assets and liabilities are presented gross in the balance sheet unless both of the following criteria are met: the group currently has a

legally enforceable right to set off the recognized amounts; and the group intends to either settle on a net basis or realize the asset and settle

the liability simultaneously. A right of set off is the group’s legal right to settle an amount payable to a creditor by applying against it an amount

receivable from the same counterparty. The relevant legal jurisdiction and laws applicable to the relationships between the parties are

considered when assessing whether a current legally enforceable right to set off exists.

Provisions and contingencies

Provisions are recognized when the group has a present legal or constructive obligation as a result of a past event, it is probable that an

outflow of resources embodying economic benefits will be required to settle the obligation and a reliable estimate can be made of the amount

of the obligation. Where appropriate, the future cash flow estimates are adjusted to reflect risks specific to the liability.

If the effect of the time value of money is material, provisions are determined by discounting the expected future cash flows at a pre-tax risk-

free rate that reflects current market assessments of the time value of money. Where discounting is used, the increase in the provision due to

the passage of time is recognized within finance costs. Provisions are discounted using a nominal discount rate of 2.5% (2018 3.0%).

Provisions are split between amounts expected to be settled within 12 months of the balance sheet date (current) and amounts expected to be

settled later (non-current).

166 BP Annual Report and Form 20-F 2019

1. Significant accounting policies, judgements, estimates and assumptions – continued

Contingent liabilities are possible obligations whose existence will only be confirmed by future events not wholly within the control of the

group, or present obligations where it is not probable that an outflow of resources will be required or the amount of the obligation cannot be

measured with sufficient reliability. Contingent liabilities are not recognized in the consolidated financial statements but are disclosed unless

the possibility of an outflow of economic resources is considered remote.

Decommissioning

Liabilities for decommissioning costs are recognized when the group has an obligation to plug and abandon a well, dismantle and remove a

facility or an item of plant and to restore the site on which it is located, and when a reliable estimate of that liability can be made. Where an

obligation exists for a new facility or item of plant, such as oil and natural gas production or transportation facilities, this liability will be

recognized on construction or installation. Similarly, where an obligation exists for a well, this liability is recognized when it is drilled. An

obligation for decommissioning may also crystallize during the period of operation of a well, facility or item of plant through a change in

legislation or through a decision to terminate operations; an obligation may also arise in cases where an asset has been sold but the

subsequent owner is no longer able to fulfil its decommissioning obligations, for example due to bankruptcy. The amount recognized is the

present value of the estimated future expenditure determined in accordance with local conditions and requirements. The provision for the

costs of decommissioning wells, production facilities and pipelines at the end of their economic lives is estimated using existing technology, at

future prices, depending on the expected timing of the activity, and discounted using the nominal discount rate.

An amount equivalent to the decommissioning provision is recognized as part of the corresponding intangible asset (in the case of an

exploration or appraisal well) or property, plant and equipment. The decommissioning portion of the property, plant and equipment is

subsequently depreciated at the same rate as the rest of the asset. Other than the unwinding of discount on or utilisation of the provision, any

change in the present value of the estimated expenditure is reflected as an adjustment to the provision and the corresponding asset where

that asset is generating or is expected to generate future economic benefits.

Environmental expenditures and liabilities

Environmental expenditures that are required in order for the group to obtain future economic benefits from its assets are capitalized as part of

those assets. Expenditures that relate to an existing condition caused by past operations that do not contribute to future earnings are

expensed.

Liabilities for environmental costs are recognized when a clean-up is probable and the associated costs can be reliably estimated. Generally,

the timing of recognition of these provisions coincides with the commitment to a formal plan of action or, if earlier, on divestment or on closure

of inactive sites.

The amount recognized is the best estimate of the expenditure required to settle the obligation. Provisions for environmental liabilities have

been estimated using existing technology, at future prices and discounted using a nominal discount rate.

Significant judgements and estimates: provisions

The group holds provisions for the future decommissioning of oil and natural gas production facilities and pipelines at the end of their

economic lives. The largest decommissioning obligations facing BP relate to the plugging and abandonment of wells and the removal and

disposal of oil and natural gas platforms and pipelines around the world. Most of these decommissioning events are many years in the future

and the precise requirements that will have to be met when the removal event occurs are uncertain. Decommissioning technologies and

costs are constantly changing, as are political, environmental, safety and public expectations. The timing and amounts of future cash flows

are subject to significant uncertainty and estimation is required in determining the amounts of provisions to be recognized. Any changes in

the expected future costs are reflected in both the provision and the asset.

If oil and natural gas production facilities and pipelines are sold to third parties, judgement is required to assess whether the new owner will

be unable to meet their decommissioning obligations, whether BP would then be responsible for decommissioning, and if so the extent of

that responsibility. The group has assessed that no material decommissioning provisions should be recognized as at 31 December 2019 (2018

no material provisions) for assets sold to third parties where the sale transferred the decommissioning obligation to the new owner.

Decommissioning provisions associated with downstream refineries and petrochemicals facilities are generally not recognized, as the

potential obligations cannot be measured, given their indeterminate settlement dates. The group performs periodic reviews of its

downstream refineries and petrochemicals long-lived assets for any changes in facts and circumstances that might require the recognition of

a decommissioning provision.

The provision for environmental liabilities is estimated based on current legal and constructive requirements, technology, price levels and

expected plans for remediation. Actual costs and cash outflows can differ from current estimates because of changes in laws and

regulations, public expectations, prices, discovery and analysis of site conditions and changes in clean-up technology.

The timing and amount of future expenditures relating to decommissioning and environmental liabilities are reviewed annually, together with

the interest rate used in discounting the cash flows. The interest rate used to determine the balance sheet obligations at the end of 2019 was

a nominal rate of 2.5% (2018 a nominal rate of 3.0%), which was based on long-dated US government bonds. The weighted average period

over which decommissioning and environmental costs are generally expected to be incurred is estimated to be approximately 18 years (2018

18 years) and 6 years (2018 6 years) respectively.

Further information about the group’s provisions is provided in Note 23. Changes in assumptions in relation to the group's provisions could

result in a material change in their carrying amounts within the next financial year. A 0.5% change in the nominal discount rate could have an

impact of approximately $1.4 billion (2018 $1.3 billion) on the value of the group’s provisions.

A two-year change in the timing of expected future decommissioning expenditures does not have a material impact on the value of the

group’s decommissioning provision. Management do not consider a change of greater than two years to be reasonably possible either in the

next financial year or as a result of changes in the longer-term economic environment.

As described in Note 33, the group is subject to claims and actions for which no provisions have been recognized. The facts and

circumstances relating to particular cases are evaluated regularly in determining whether a provision relating to a specific litigation should be

recognized or revised. Accordingly, significant management judgement relating to provisions and contingent liabilities is required, since the

outcome of litigation is difficult to predict.

BP Annual Report and Form 20-F 2019 167

1. Significant accounting policies, judgements, estimates and assumptions – continued

Employee benefits

Wages, salaries, bonuses, social security contributions, paid annual leave and sick leave are accrued in the period in which the associated

services are rendered by employees of the group. Deferred bonus arrangements that have a vesting date more than 12 months after the

balance sheet date are valued on an actuarial basis using the projected unit credit method and amortized on a straight-line basis over the

service period until the award vests. The accounting policies for share-based payments and for pensions and other post-retirement benefits are

described below.

Share-based payments

Equity-settled transactions

The cost of equity-settled transactions with employees is measured by reference to the fair value of the equity instruments on the date on

which they are granted and is recognized as an expense over the vesting period, which ends on the date on which the employees become fully

entitled to the award. A corresponding credit is recognized within equity. Fair value is determined by using an appropriate, widely used,

valuation model. In valuing equity-settled transactions, no account is taken of any vesting conditions, other than conditions linked to the price of

the shares of the company (market conditions). Non-vesting conditions, such as the condition that employees contribute to a savings-related

plan, are taken into account in the grant-date fair value, and failure to meet a non-vesting condition, where this is within the control of the

employee is treated as a cancellation and any remaining unrecognized cost is expensed.

For other equity-settled share-based payment transactions, the goods or services received and the corresponding increase in equity are

measured at the fair value of the goods or services received unless their fair value cannot be reliably estimated. If the fair value of the goods

and services received cannot be reliably estimated, the transaction is measured by reference to the fair value of the equity instruments

granted.

Cash-settled transactions

The cost of cash-settled transactions is recognized as an expense over the vesting period, measured by reference to the fair value of the

corresponding liability which is recognized on the balance sheet. The liability is remeasured at fair value at each balance sheet date until

settlement, with changes in fair value recognized in the income statement.

Pensions and other post-retirement benefits

The cost of providing benefits under the group’s defined benefit plans is determined separately for each plan using the projected unit credit

method, which attributes entitlement to benefits to the current period to determine current service cost and to the current and prior periods to

determine the present value of the defined benefit obligation. Past service costs, resulting from either a plan amendment or a curtailment (a

reduction in future obligations as a result of a material reduction in the plan membership), are recognized immediately when the company

becomes committed to a change.

Net interest expense relating to pensions and other post-retirement benefits, which is recognized in the income statement, represents the net

change in present value of plan obligations and the value of plan assets resulting from the passage of time, and is determined by applying the

discount rate to the present value of the benefit obligation at the start of the year, and to the fair value of plan assets at the start of the year,

taking into account expected changes in the obligation or plan assets during the year.

Remeasurements of the defined benefit liability and asset, comprising actuarial gains and losses, and the return on plan assets (excluding

amounts included in net interest described above) are recognized within other comprehensive income in the period in which they occur and

are not subsequently reclassified to profit and loss.

The defined benefit pension plan surplus or deficit recognized on the balance sheet for each plan comprises the difference between the

present value of the defined benefit obligation (using a discount rate based on high quality corporate bonds) and the fair value of plan assets

out of which the obligations are to be settled directly. Fair value is based on market price information and, in the case of quoted securities, is

the published bid price. Defined benefit pension plan surpluses are only recognized to the extent they are recoverable, either by way of a

refund from the plan or reductions in future contributions to the plan.

Contributions to defined contribution plans are recognized in the income statement in the period in which they become payable.

Significant estimate: pensions and other post-retirement benefits

Accounting for defined benefit pensions and other post-retirement benefits involves making significant estimates when measuring the

group's pension plan surpluses and deficits. These estimates require assumptions to be made about many uncertainties.

Pensions and other post-retirement benefit assumptions are reviewed by management at the end of each year. These assumptions are used

to determine the projected benefit obligation at the year end and hence the surpluses and deficits recorded on the group's balance sheet,

and pension and other post-retirement benefit expense for the following year.

The assumptions that are the most significant to the amounts reported are the discount rate, inflation rate, salary growth and mortality levels.

Assumptions about these variables are based on the environment in each country. The assumptions used vary from year to year, with

resultant effects on future net income and net assets. Changes to some of these assumptions, in particular the discount rate and inflation

rate, could result in material changes to the carrying amounts of the group's pension and other post-retirement benefit obligations within the

next financial year, in particular for the UK, US and Eurozone plans. Any differences between these assumptions and the actual outcome will

also affect future net income and net assets.

The values ascribed to these assumptions and a sensitivity analysis of the impact of changes in the assumptions on the benefit expense and

obligation used are provided in Note 24.

Income taxes

Income tax expense represents the sum of current tax and deferred tax.

Income tax is recognized in the income statement, except to the extent that it relates to items recognized in other comprehensive income or

directly in equity, in which case the related tax is recognized in other comprehensive income or directly in equity.

Current tax is based on the taxable profit for the period. Taxable profit differs from net profit as reported in the income statement because it is

determined in accordance with the rules established by the applicable taxation authorities. It therefore excludes items of income or expense

that are taxable or deductible in other periods as well as items that are never taxable or deductible. The group’s liability for current tax is

calculated using tax rates and laws that have been enacted or substantively enacted by the balance sheet date.

168 BP Annual Report and Form 20-F 2019

1. Significant accounting policies, judgements, estimates and assumptions – continued

Deferred tax is provided, using the liability method, on temporary differences at the balance sheet date between the tax bases of assets and

liabilities and their carrying amounts for financial reporting purposes. Deferred tax liabilities are recognized for all taxable temporary differences

except:

• Where the deferred tax liability arises on the initial recognition of goodwill.

• Where the deferred tax liability arises on the initial recognition of an asset or liability in a transaction that is not a business combination and,

at the time of the transaction, affects neither accounting profit nor taxable profit or loss.

• In respect of taxable temporary differences associated with investments in subsidiaries and associates and interests in joint arrangements,

where the group is able to control the timing of the reversal of the temporary differences and it is probable that the temporary differences

will not reverse in the foreseeable future.

Deferred tax assets are recognized for deductible temporary differences, carry-forward of unused tax credits and unused tax losses, to the

extent that it is probable that taxable profit will be available against which the deductible temporary differences and the carry-forward of

unused tax credits and unused tax losses can be utilized, except where the deferred tax asset relating to the deductible temporary difference

arises from the initial recognition of an asset or liability in a transaction that is not a business combination and, at the time of the transaction,

affects neither accounting profit nor taxable profit or loss. In respect of deductible temporary differences associated with investments in

subsidiaries and associates and interests in joint arrangements, deferred tax assets are recognized only to the extent that it is probable that the

temporary differences will reverse in the foreseeable future and taxable profit will be available against which the temporary differences can be

utilized.

The carrying amount of deferred tax assets is reviewed at each balance sheet date and reduced to the extent that it is no longer probable or

increased to the extent that it is probable that sufficient taxable profit will be available to allow all or part of the deferred tax asset to be utilized.

Deferred tax assets and liabilities are measured at the tax rates that are expected to apply in the period when the asset is realized or the

liability is settled, based on tax rates (and tax laws) that have been enacted or substantively enacted at the balance sheet date. Deferred tax

assets and liabilities are not discounted.

Deferred tax assets and liabilities are offset only when there is a legally enforceable right to set off current tax assets against current tax

liabilities and when the deferred tax assets and liabilities relate to income taxes levied by the same taxation authority on either the same

taxable entity or different taxable entities where there is an intention to settle the current tax assets and liabilities on a net basis or to realize

the assets and settle the liabilities simultaneously.

Where tax treatments are uncertain, if it is considered probable that a taxation authority will accept the group's proposed tax treatment,

income taxes are recognized consistent with the group's income tax filings. If it is not considered probable, the uncertainty is reflected within

the carrying amount of the applicable tax asset or liability using either the most likely amount or an expected value, depending on which

method better predicts the resolution of the uncertainty.

The computation of the group’s income tax expense and liability involves the interpretation of applicable tax laws and regulations in many

jurisdictions throughout the world. The resolution of tax positions taken by the group, through negotiations with relevant tax authorities or

through litigation, can take several years to complete and in some cases it is difficult to predict the ultimate outcome. Therefore, judgement is

required to determine whether provisions for income taxes are required and, if so, estimation is required of the amounts that could be payable.

In addition, the group has carry-forward tax losses and tax credits in certain taxing jurisdictions that are available to offset against future taxable

profit. However, deferred tax assets are recognized only to the extent that it is probable that taxable profit will be available against which the

unused tax losses or tax credits can be utilized. Management judgement is exercised in assessing whether this is the case and estimates are

required to be made of the amount of future taxable profits that will be available.

Management do not assess there to be a significant risk of a material change to the group’s tax provisioning or recognition of deferred tax

assets within the next financial year, however the tax position remains inherently uncertain and therefore subject to change. To the extent that

actual outcomes differ from management’s estimates, income tax charges or credits, and changes in current and deferred tax assets or

liabilities, may arise in future periods. For more information see Note 9 and Note 33.

Judgement is also required when determining whether a particular tax is an income tax or another type of tax (for example a production tax).

Accounting for deferred tax is applied to income taxes as described above, but is not applied to other types of taxes; rather such taxes are

recognized in the income statement in accordance with the applicable accounting policy such as Provisions and contingencies. No new

significant judgements were made in 2019 in this regard.

Customs duties and sales taxes

Customs duties and sales taxes that are passed on or charged to customers are excluded from revenues and expenses. Assets and liabilities

are recognized net of the amount of customs duties or sales tax except:

• Customs duties or sales taxes incurred on the purchase of goods and services which are not recoverable from the taxation authority are

recognized as part of the cost of acquisition of the asset.

• Receivables and payables are stated with the amount of customs duty or sales tax included.

The net amount of sales tax recoverable from, or payable to, the taxation authority is included within receivables or payables in the balance

sheet.

Own equity instruments – treasury shares

The group’s holdings in its own equity instruments are shown as deductions from shareholders’ equity. Treasury shares represent BP shares

repurchased and available for specific and limited purposes. For accounting purposes, shares held in Employee Share Ownership Plans

(ESOPs) to meet the future requirements of the employee share-based payment plans are treated in the same manner as treasury shares and

are, therefore, included in the consolidated financial statements as treasury shares. The cost of treasury shares subsequently sold or reissued

is calculated on a weighted-average basis. Consideration, if any, received for the sale of such shares is also recognized in equity. No gain or

loss is recognized in the income statement on the purchase, sale, issue or cancellation of equity shares. Shares repurchased under the share

buy-back programme which are immediately cancelled are not shown as treasury shares, but are shown as a deduction from the profit and

loss account reserve in the group statement of changes in equity.

BP Annual Report and Form 20-F 2019 169

1. Significant accounting policies, judgements, estimates and assumptions – continued

Revenue and other income

Revenue from contracts with customers is recognized when or as the group satisfies a performance obligation by transferring control of a

promised good or service to a customer. The transfer of control of oil, natural gas, natural gas liquids, LNG, petroleum and chemical products,

and other items usually coincides with title passing to the customer and the customer taking physical possession. The group principally

satisfies its performance obligations at a point in time; the amounts of revenue recognized relating to performance obligations satisfied over

time are not significant.

When, or as, a performance obligation is satisfied, the group recognizes as revenue the amount of the transaction price that is allocated to that

performance obligation. The transaction price is the amount of consideration to which the group expects to be entitled. The transaction price is

allocated to the performance obligations in the contract based on standalone selling prices of the goods or services promised.

Contracts for the sale of commodities are typically priced by reference to quoted prices. Revenue from term commodity contracts is

recognized based on the contractual pricing provisions for each delivery. Certain of these contracts have pricing terms based on prices at a

point in time after delivery has been made. Revenue from such contracts is initially recognized based on relevant prices at the time of delivery

and subsequently adjusted as appropriate. All revenue from these contracts, both that recognized at the time of delivery and that from post-

delivery price adjustments, is disclosed as revenue from contracts with customers.

Certain contracts entered into by the group that result in physical delivery of products such as crude oil, natural gas and refined products are

required by IFRS 9 to be accounted for as derivative financial instruments. The group's counterparties in these transactions may, however,

meet the IFRS 15 definition of a customer. Revenue recognized relating to such contracts when physical delivery occurs is, therefore,

measured at the contractual transaction price and presented together with revenue from contracts with customers. Changes in the fair value

of derivative assets and liabilities prior to physical delivery are excluded from revenue from contracts with customers and are classified as other

operating revenues. See also Impact of new International Financial Reporting Standards - Not yet adopted - IFRIC agenda decision on IFRS 9

'Financial instruments' below.

Where forward sale and purchase contracts for oil, natural gas or power have been determined to be for short-term trading purposes, the

associated sales and purchases are reported net within sales and other operating revenues whether or not physical delivery has occurred.

Physical exchanges with counterparties in the same line of business in order to facilitate sales to customers are reported net, as are sales and

purchases made with a common counterparty, as part of an arrangement similar to a physical exchange.

Where the group acts as agent on behalf of a third party to procure or market energy commodities, any associated fee income is recognized

but no purchase or sale is recorded.

Interest income is recognized as the interest accrues (using the effective interest rate, that is, the rate that exactly discounts estimated future

cash receipts through the expected life of the financial instrument to the net carrying amount of the financial asset).

Dividend income from investments is recognized when the shareholders’ right to receive the payment is established.

Contract asset and contract liability balances are included within amounts presented for trade receivables and other payables respectively.

Finance costs

Finance costs directly attributable to the acquisition, construction or production of qualifying assets, which are assets that necessarily take a

substantial period of time to get ready for their intended use, are added to the cost of those assets until such time as the assets are

substantially ready for their intended use. All other finance costs are recognized in the income statement in the period in which they are

incurred.

Impact of new International Financial Reporting Standards

BP adopted IFRS 16 ‘Leases’, which replaced IAS 17 ‘Leases’ and IFRIC 4 ‘Determining whether an arrangement contains a lease’, with effect

from 1 January 2019. There are no other new or amended standards or interpretations adopted during the year that have a significant impact on

the consolidated financial statements.

IFRS 16 ‘Leases’

IFRS 16 ‘Leases’ provides a new model for lessee accounting in which the majority of leases will be accounted for by the recognition on the

balance sheet of a right-of-use asset and a lease liability. The subsequent amortization of the right-of-use asset and the interest expense related

to the lease liability is recognized in profit or loss over the lease term.

BP elected to apply the modified retrospective transition approach in which the cumulative effect of initial application is recognized in opening

retained earnings at the date of initial application with no restatement of comparative periods’ financial information. Comparative information in

the group balance sheet and group cash flow statement has, however, been re-presented to align with current year presentation, showing

lease liabilities and lease liability payments as separate line items. These were previously included within finance debt and repayments of long-

term financing line items respectively. Amounts presented in these line items for the comparative periods relate to leases accounted for as

finance leases under IAS 17. We do not consider any of the judgements or estimates made on transition to IFRS 16 to be significant.

IFRS 16 introduces a revised definition of a lease. As permitted by the standard, BP elected not to reassess the existing population of leases

under the new definition and only applies the new definition for the assessment of contracts entered into after the transition date. On

transition the standard permitted, on a lease-by-lease basis, the right-of-use asset to be measured either at an amount equal to the lease

liability (as adjusted for prepaid or accrued lease payments), or on a historical basis as if the standard had always applied. BP elected to use the

historical asset measurement for its more material leases and used the asset equals liability approach for the remainder of the population. In

measuring the right-of-use asset BP applied the transition practical expedient to exclude initial direct costs. BP also elected to adjust the

carrying amounts of the right-of-use assets as at 1 January 2019 for onerous lease provisions that had been recognized on the group balance

sheet as at 31 December 2018, rather than performing impairment tests on transition.

The effect on the group’s balance sheet is set out further below. The presentation and timing of recognition of charges in the income

statement has changed following the adoption of IFRS 16. The operating lease expense previously reported under IAS 17, typically on a straight-

line basis, has been replaced by depreciation of the right-of-use asset and interest on the lease liability. In the cash flow statement payments

are now presented as financing cash flows, representing repayments of principal, and as operating cash flows, representing payments of

interest. Variable lease payments that do not depend on an index or rate are not included in the lease liability and will continue to be presented

as operating cash flows. In prior years, operating lease payments were principally presented within cash flows from operating activities.

170 BP Annual Report and Form 20-F 2019

1. Significant accounting policies, judgements, estimates and assumptions – continued

The following table provides a reconciliation of the operating lease commitments as at 31 December 2018 to the total lease liability recognized

on the group balance sheet in accordance with IFRS 16 as at 1 January 2019, with explanations below.

$ million

Operating lease commitments at 31 December 2018 11,979

Leases not yet commenced (1,372)

Leases below materiality threshold (86)

Short-term leases (91)

Effect of discounting

(1,512)

Impact on leases in joint operations 836

Variable lease payments (58)

Redetermination of lease term (252)

Other (22)

Total additional lease liabilities recognized on adoption of IFRS 16 9,422

Finance lease obligations at 31 December 2018 667

Adjustment for finance leases in joint operations (189)

Total lease liabilities at 1 January 2019 9,900

Leases not yet commenced: The operating lease commitments disclosed as at 31 December 2018 include amounts relating to leases entered

into by the group that had not yet commenced as at 31 December 2018. In accordance with IFRS 16 assets and liabilities will not be

recognized on the group balance sheet in relation to these leases until the dates of commencement of the leases. Commitments for leases

not yet commenced as at 31 December 2019 are disclosed in note 28.

Short-term leases and leases below materiality threshold: As part of the transition to IFRS 16, BP elected not to recognize assets and liabilities

relating to short-term leases i.e. leases with a term of less than 12 months and also applied a materiality threshold for the recognition of assets

and liabilities related to leases. The disclosed operating lease commitments as at 31 December 2018 include amounts related to such leases.

Effect of discounting: The amount of the lease liability recognized in accordance with IFRS 16 is on a discounted basis whereas the operating

lease commitments information as at 31 December 2018 is presented on an undiscounted basis. The discount rates used on transition were

incremental borrowing rates as appropriate for each lease based on factors such as the lessee legal entity, lease term and currency. The

weighted average discount rate used on transition was around 3.5%, with a weighted average remaining lease term of around nine years. For

new leases commencing after 1 January 2019 the discount rate used will be the interest rate implicit in the lease, if this is readily

determinable, or the incremental borrowing rate if the implicit rate cannot be readily determined.

Impact on leases in joint operations: The operating lease commitments for leases within joint operations as at 31 December 2018 were

included on the basis of BP’s net working interest, irrespective of whether BP is the operator and whether the lease has been co-signed by the

joint operators or not. However, for transition to IFRS 16, the facts and circumstances of each lease in a joint operation were assessed to

determine the group’s rights and obligations and to recognize assets and liabilities on the group balance sheet accordingly. This relates mainly

to leases of drilling rigs within joint operations in the Upstream segment. Where all parties to a joint operation jointly have the right to control

the use of the identified asset and all parties have a legal obligation to make lease payments to the lessor, the group’s share of the right-of-use

asset and its share of the lease liability will be recognized on the group balance sheet. This may arise in cases where the lease is signed by all

parties to the joint operation. However, in cases where BP is the only party with the legal obligation to make lease payments to the lessor, the

full lease liability will be recognized on the group balance sheet. This may be the case if for example BP, as operator of the joint operation, is the

sole signatory to the lease. If, however, the underlying asset is jointly controlled by all parties to the joint operation BP will recognize its net

share of the right-of-use asset on the group balance sheet along with a receivable representing the amounts to be recovered from the other

parties. If BP is not legally obliged to make lease payments to the lessor but jointly controls the asset, the net share of the right-of-use asset

will be recognized on the group balance sheet along with a payable representing amounts to be paid to the other parties.

Variable lease payments: Where there are lease payments that vary depending on an index or rate, the measurement of the operating lease

commitments as at 31 December 2018 was based on the variable factor as at inception of the lease and was not updated to reflect

subsequent changes in the variable factor. Such subsequent changes in the lease payments were treated as contingent rentals and charged to

profit or loss as and when paid. Under IFRS 16 the lease liability is adjusted whenever the lease payments are changed in response to changes

in the variable factor, and for transition the liability was measured on the basis of the prevailing variable factor on 1 January 2019.

Redetermination of lease term: Under the transition provisions of IFRS 16, the remaining terms of certain leases were redetermined with the

benefit of hindsight, on the basis that BP was reasonably certain to exercise its option to terminate those leases before the full term.

Under IAS 17 finance leases were recognized on the group balance sheet and continue to be recognized in accordance with IFRS 16. The

amounts recognized on the group balance sheet as at 1 January 2019 in relation to the right-of-use assets and liabilities for previous finance

leases within joint operations are on a net or gross basis as appropriate as described above.

BP Annual Report and Form 20-F 2019 171

1. Significant accounting policies, judgements, estimates and assumptions – continued

In addition to the lease liability, other line items on the group balance sheet adjusted on transition to IFRS 16 include property, plant and

equipment for the right-of-use assets, lease related prepayments, receivables from joint operation partners, accruals, payables to operators of

joint operations, onerous lease provisions and deferred tax balances, as set out below.

$ million

31 December 2018 1 January 2019

Adjustment on

adoption of IFRS 16

Non-current assets

Property, plant and equipment 135,261 143,950 8,689

Trade and other receivables 1,834 2,159 325

Prepayments 1,179 849 (330)

Deferred tax assets 3,706 3,736 30

Current assets

Trade and other receivables

24,478

24,673

195

Prepayments

963

872

(91)

Current liabilities

Trade and other payables 46,265 46,209 (56)

Accruals 4,626 4,578 (48)

Lease liabilities 44 2,196 2,152

Finance debt 9,329 9,329 —

Provisions 2,564 2,547 (17)

Non-current liabilities

Other payables 13,830 14,013 183

Accruals 575 548 (27)

Lease liabilities 623 7,704 7,081

Finance debt 55,803 55,803 —

Deferred tax liabilities 9,812 9,767 (45)

Provisions 17,732 17,657 (75)

Net assets

101,548 101,218 (330)

Equity

BP shareholders' equity 99,444 99,115 (329)

Non-controlling interests 2,104 2,103 (1)

101,548 101,218 (330)

Net assets also includes the line items not affected by the transition to IFRS 16 that are not presented separately in the table

The total adjustments to the group's lease liabilities at 1 January 2019 are reconciled as follows:

$ million

Total additional lease liabilities recognized on adoption of IFRS 16 9,422

Less: adjustment for finance leases in joint operations (189)

Total adjustment to lease liabilities 9,233

Of which – current 2,152

– non-current 7,081

Not yet adopted

The following pronouncements from the IASB have not been adopted by the group in these financial statements as they will only become

effective for future financial reporting periods. In addition, the group is voluntarily changing certain accounting policies from 1 January 2020

following an IFRIC agenda decision on IFRS 9 'Financial instruments'. There are no other standards, amendments or interpretations in issue

but not yet adopted that the directors anticipate will have a material effect on the reported income or net assets of the group.

IFRS 17 ' Insurance Contracts'

IFRS 17 'Insurance Contracts' provides a new general model for accounting for contracts where the issuer accepts significant insurance risk

from another party and agrees to compensate that party if a future uncertain event adversely affects them. IFRS 17 replaces IFRS 4 'Insurance

Contracts' and will be effective for BP for the financial reporting period commencing 1 January 2022 subject to endorsement by the UK and the

EU. BP has commenced an assessment of the impact of IFRS 17 but it is not expected to have a significant effect on future financial reporting.

Interest Rate Benchmark Reform: Amendments to IFRS 9 'Financial instruments'

Amendments to IFRS 9 were issued in September 2019 to provide temporary relief from applying specific hedge accounting requirements to

hedging relationships directly affected by interest rate benchmark reforms. The reliefs have the effect that the uncertainty over the interest rate

benchmark reforms should not generally result in discontinuation of hedge accounting. The amendments have been endorsed by the EU. BP

will adopt the IFRS 9 amendments in the financial reporting period commencing 1 January 2020.

The reliefs provided by the amendments would allow BP to assume that:

• the interest rate benchmark component at initial designation of fair value hedges is separately identifiable; and

• the interest rate benchmark is not altered for the purposes of assessing the economic relationship between the hedged item and the

hedging instrument for fair value hedges.

The amendments are applicable to all of the group's fair value hedges disclosed in note 30.

172 BP Annual Report and Form 20-F 2019

1. Significant accounting policies, judgements, estimates and assumptions – continued

IFRIC agenda decision on IFRS 9

In March 2019, the IFRIC issued an agenda decision on the application of IFRS 9 to the physical settlement of contracts to buy or sell a non-

financial item such as commodities that are not accounted for as 'own-use' contracts. The IFRIC concluded that such contracts are settled by

the delivery or receipt of a non-financial item in exchange for both cash and the settlement of the derivative asset or liability. BP regularly

enters into forward sale and purchase contracts. As described in the group's accounting policy for revenue, revenue recognized at the time

such contracts are physically settled is measured at the contractual transaction price and is presented together with revenue from contracts

with customers in these financial statements. From 1 January 2020, however, the group has changed its accounting policy for these contracts

in accordance with the conclusions included in the agenda decision. Purchases and revenues from such contracts will be measured at the

contractual transaction price plus the carrying amount of the related derivative at the date of settlement. Furthermore, revenues on such sales

contracts will no longer be presented together with the group's revenue from contracts with customers but will be included in other revenues.

This change will have a significant effect on the group's disclosures in relation to revenue from contracts with customers. For 2019, it is

currently estimated that the amount of revenue measured at the contractual transaction price presented together with revenue from contracts

with customers in these financial statements that would be presented as other revenues following application of this change in accounting

policy is approximately $130 billion. Comparative information for revenue from contracts with customers (see Note 6) will be restated in BP's

2020 financial statements.

Gains and losses on these realized physically settled derivative contracts will also be included in other revenues. The group expects there to be

no material effect on reported profit as presented in the group income statement or on net assets as a result of these changes.

BP Annual Report and Form 20-F 2019 173

2. Non-current assets held for sale

The carrying amount of assets classified as held for sale at 31 December 2019 is $7,465 million, with associated liabilities of $1,393 million.

These principally relate to two material disposal transactions which have been classified as held for sale in the group balance sheet.

On 27 August 2019, BP announced that it had agreed to sell all its Alaska operations and interests to Hilcorp Energy for up to $5.6 billion,

subject to customary closing adjustments, of which $1.6 billion is contingent on future cash flows. The sale will include BP’s entire upstream

and midstream business in the state, including BP Exploration (Alaska) Inc., which owns all of BP’s upstream oil and gas interests in Alaska,

and BP Pipelines (Alaska) Inc.’s 49% interest in the Trans Alaska Pipeline System (TAPS). BP will retain decommissioning liability relating to

TAPS, which will be partially offset by a 30% cost reimbursement from Hilcorp. The deal, which is subject to governmental authorizations, is

expected to complete during 2020. Assets of $6,518 million and associated liabilities of $969 million relating to this transaction are classified as

held for sale at 31 December 2019.

In November 2019, BP agreed to sell its interests in the San Juan basin in Colorado and New Mexico to IKAV. The deal is expected to complete

during the first half of 2020. Assets and associated liabilities relating to this transaction are classified as held for sale at 31 December 2019.

The total assets and liabilities held for sale, which are all in the Upstream segment, are set out in the table below.

$ million

2019

Property, plant and equipment 6,359

Intangible assets 610

Investments in associates 43

Inventories 318

Trade and other receivables 135

Assets classified as held for sale

7,465

Trade and other payables (33)

Lease liabilities (280)

Provisions (1,012)

Defined benefit pension plan and other post-retirement benefit plan deficits (68)

Liabilities directly associated with assets classified as held for sale (1,393)

3. Business combinations and other significant transactions

Business combinations

As agreed as part of the original transaction, $3,480 million was paid in 2019 in respect of the 2018 acquisition of Petrohawk Energy

Corporation from BHP Billiton that is described below. Payments on this transaction are now complete. A number of other individually

insignificant business combinations were also undertaken by BP in 2019.

BP undertook a number of business combinations in 2018. For the full year, total consideration paid in cash amounted to $7,100 million, offset

by cash acquired of $114 million.

On 31 October 2018, BP acquired from BHP Billiton Petroleum (North America) Inc. 100% of the issued share capital of Petrohawk Energy

Corporation, a wholly-owned subsidiary of BHP that holds a portfolio of unconventional onshore US oil and gas assets.

The acquisition brings BP extensive oil and gas production and resources in the liquids-rich regions of the Permian and Eagle Ford basins in

Texas and in the Haynesville gas basin in Texas and Louisiana.

The total consideration for the transaction, after customary closing adjustments and the effect of discounting deferred payments, was $10,302

million, which was all paid in cash.

The transaction was accounted for as a business combination using the acquisition method. The fair values of the identifiable assets and

liabilities acquired, as at the date of acquisition, are shown in the table below. No goodwill was recognized on the acquisition and no significant

adjustments were made to the provisional fair values of the identifiable assets and liabilities acquired when those values were finalized.

$ million

2018

Assets

Property, plant and equipment 10,845

Intangible assets 21

Inventories 27

Trade and other receivables 493

Cash 104

Liabilities

Trade and other payables (659)

Provisions (323)

Non-controlling interest (206)

Total consideration 10,302

An analysis of the cash flows relating to the acquisition included within the cash flow statement for 2018 is provided below.

$ million

2018

Transaction costs of the acquisition (included in cash flows from operating activities) 62

Interest on deferred payments (included in cash flows from operating activities) 21

Cash consideration paid, net of cash acquired (included in cash flows from investing activities) 6,684

Total net cash outflow for the acquisition 6,767

From the date of acquisition to 31 December 2018, the acquired activities generated revenues of $472 million and profit before tax of $49

million. If the business combination had taken place on 1 January 2018, it is estimated that the acquired activities would have generated

revenues of $2,798 million and profit before tax of $431 million.

In addition to the BHP transaction described above, BP undertook a number of other individually insignificant business combinations in 2018.

Other significant transactions

On 18 December 2018, BP purchased an additional 16.5% interest in the Clair field in the North Sea, as part of the agreements with

ConocoPhillips in which ConocoPhillips simultaneously purchased BP's entire 39.2% interest in the Greater Kuparuk Area on the North Slope

of Alaska. The purchase gives BP a 45.1% interest in Clair in total. Gross payments made and received of $1,739 million and $1,490 million are

included in Capital expenditure and Proceeds from disposals of businesses, net of cash acquired, respectively, in the group cash flow

statement for 2018. Goodwill of $804 million, resulting from the recognition of a deferred tax liability as part of the transaction accounting, was

recognized on the purchase of the interest in the Clair field.

174 BP Annual Report and Form 20-F 2019

4. Disposals and impairment

The following amounts were recognized in the income statement in respect of disposals and impairments.

$ million

2019 2018 2017

Gains on sale of businesses and fixed assets

Upstream 143 437 526

Downstream 50 15 674

Other businesses and corporate — 4 10

193 456 1,210

$ million

2019 2018 2017

Losses on sale of businesses and fixed assets

Upstream 415 707 127

Downstream 57 59 88

Other businesses and corporate 887 11 —

1,359 777 215

Impairment losses

Upstream 6,752 400 1,138

Downstream 65 12 69

Other businesses and corporate 30 254 32

6,847 666 1,239

Impairment reversals

Upstream (131) (580) (176)

Downstream — (2) (62)

Other businesses and corporate — (1) —

(131) (583) (238)

Impairment and losses on sale of businesses and fixed assets 8,075 860 1,216

Disposals

Disposal proceeds and principal gains and losses on disposals by segment are described below.

$ million

2019 2018 2017

Proceeds from disposals of fixed assets 500 940 2,936

Proceeds from disposals of businesses, net of cash disposed 1,701 1,911 478

2,201 2,851 3,414

By business

Upstream 2,048 2,145 1,183

Downstream 152 120 2,078

Other businesses and corporate 1 586 153

2,201 2,851 3,414

At 31†December†2019, deferred consideration relating to disposals amounted to $159 million receivable within one year (2018 $35 million and

2017 $259 million) and $125 million receivable after one year (2018 $304 million and 2017 $268 million). In addition, contingent consideration

receivable relating to disposals amounted to $598 million at 31†December†2019 (2018 $893 million and 2017 $237 million). These amounts of

contingent consideration are reported within Other investments on the group balance sheet - see Note 18 for further information.

Upstream

In 2019, losses included $191 million fair value movements in relation to contingent consideration arising from the prior period disposal of the

Bruce, Keith and Devenick assets and $171 million in relation to severance costs associated with the divestment of our Alaskan business.

In 2018, gains principally resulted from the disposal of interests in the Bruce, Keith and Rhum fields in the UK North Sea, from the disposal of

certain properties in the US, and from adjustments to disposals in prior periods. Losses included $335 million resulting from the disposal of our

interest in the Magnus field and associated assets in the UK North Sea, $221 million from the disposal of our interest in the Greater Kuparuk

Area in the US (see Note 3 for further information), and adjustments to disposals in prior periods.

In 2017, gains principally resulted from the disposal of a portion of our interest in the Perdido offshore hub in the US, and further gains

associated with disposals in the UK.

Downstream

In 2017, gains principally resulted from the disposal of our interest in the SECCO joint venture and the disposal of certain midstream assets in

Europe.

BP Annual Report and Form 20-F 2019 175

4. Disposals and impairment – continued

Other businesses and corporate

In 2019 losses on disposal of businesses and fixed assets were principally in respect of the reclassification of accumulated foreign exchange

losses from reserves to the income statement upon the contribution of our Brazilian biofuels business to a new 50:50 joint venture BP Bunge

Bioenergia.

In 2018 proceeds from disposals were principally in respect of life insurance policies in the US and wind farms within our US wind business.

Summarized financial information relating to the sale of businesses is shown in the table below.

The principal transaction categorized as a business disposal in 2019 was the sale of our interests in the Gulf of Suez oil concessions in Egypt.

The principal transaction categorized as a business disposal in 2018 was the disposal of our interest in the Greater Kuparuk Area in the US - see

Note 3 for further information.

The principal transaction categorized as a business disposal in 2017 was the disposal of our interest in the Forties Pipeline System in the North

Sea.

$ million

2019 2018 2017

Non-current assets 1,653 3,274 735

Current assets 507 173 57

Non-current liabilities (257) (250) (173)

Current liabilities (108) (97) (86)

Total carrying amount of net assets disposed 1,795 3,100 533

Recycling of foreign exchange on disposal 880 — —

Costs on disposal 190 3 3

2,865 3,103 536

Gains (losses) on sale of businesses (1,190) (221) 44

Total consideration 1,675 2,882 580

Non-cash consideration (938) (282) (216)

Consideration received (receivable)

964 (689) 114

Proceeds from the sale of businesses, net of cash disposed

1,701 1,911 478

$633 million relates to deposits received in advance of the disposal of our Alaska business and certain assets in our BPX business

Proceeds are stated net of cash and cash equivalents disposed of $30 million (2018 $15 million and 2017 $25 million).

Impairments

Impairment losses and impairment reversals in each segment are described below. For information on significant estimates and judgements

made in relation to impairments see Impairment of property, plant and equipment, intangibles and goodwill within Note 1. See also Note 12,

and Note 15 for further information on impairments by asset category.

Upstream

Impairment losses and reversals in all years relate primarily to producing and midstream assets.

The 2019 impairment losses of $6,752 million related to various assets, with the most significant charges arising in the US. Impairment losses

arose primarily as a result of the decision to dispose of certain assets, including $4,703 million in relation to completed and expected disposals

in BPX Energy and $1,264 million relating to the expected disposal of our Alaskan business; of these amounts $355 million primarily relates to

impairment of associated goodwill.

The 2018 impairment losses of $400 million related to a number of different assets, with the most significant charges arising in Australia and

the US. Impairment losses arose primarily as a result of changes to project activity, asset obsolescence and the decision to dispose of certain

assets. The 2018 impairment reversals of $580 million related to a number of different assets, with the most significant reversals arising in the

North Sea and Angola following a change to decommissioning cost estimates.

The 2017 impairment losses of $1,138 million related to a number of different assets, with the most significant charges arising in BPX Energy

(previously known as the US Lower 48 business) and the North Sea. Impairment losses within Upstream arose primarily as a result of changes

in reserves estimates and the decision to dispose of certain assets, including the Forties Pipeline System business.

The 2017 impairment reversals of $176 million related to a number of different assets, with the most significant reversals arising in the North

Sea.

Downstream

Impairment losses totalling $65 million, $12 million, and $69 million were recognized in 2019, 2018 and 2017 respectively.

Other businesses and corporate

Impairment losses totalling $30 million, $254 million, and $32 million were recognized in 2019, 2018 and 2017 respectively. The amount for

2018 is in respect of assets within our US wind business in advance of their disposal in December 2018.

176 BP Annual Report and Form 20-F 2019

5. Segmental analysis

The group’s organizational structure reflects the various activities in which BP is engaged. At 31†December†2019, BP had three reportable

segments: Upstream, Downstream and Rosneft.

Upstream’s activities include oil and natural gas exploration, field development and production; midstream transportation, storage and

processing; and the marketing and trading of natural gas, including liquefied natural gas (LNG), together with power and natural gas liquids

(NGLs).

Downstream’s activities include the refining, manufacturing, marketing, transportation, and supply and trading of crude oil, petroleum,

petrochemicals products and related services to wholesale and retail customers.

BP’s interest in Rosneft is accounted for using the equity method and is reported as a separate operating segment, reflecting the way in which

the investment is managed.

Other businesses and corporate comprises the biofuels and wind businesses, the group’s shipping and treasury functions, and corporate

activities worldwide.

The accounting policies of the operating segments are the same as the group’s accounting policies described in Note 1. However, IFRS

requires that the measure of profit or loss disclosed for each operating segment is the measure that is provided regularly to the chief operating

decision maker for the purposes of performance assessment and resource allocation. For BP, this measure of profit or loss is replacement cost

profit or loss before interest and tax which reflects the replacement cost of supplies by excluding from profit or loss inventory holding gains

and losses

. Replacement cost profit or loss for the group is not a recognized measure under IFRS.

Sales between segments are made at prices that approximate market prices, taking into account the volumes involved. Segment revenues and

segment results include transactions between business segments. These transactions and any unrealized profits and losses are eliminated on

consolidation, unless unrealized losses provide evidence of an impairment of the asset transferred. Sales to external customers by region are

based on the location of the group subsidiary which made the sale. The UK region includes the UK-based international activities of

Downstream.

All surpluses and deficits recognized on the group balance sheet in respect of pension and other post-retirement benefit plans are allocated to

Other businesses and corporate. However, the periodic expense relating to these plans is allocated to the operating segments based upon the

business in which the employees work.

Certain financial information is provided separately for the US as this is an individually material country for BP, and for the UK as this is BP’s

country of domicile.

In February 2020, BP announced plans for a future reorganization of the group’s operating segments.† The group’s current segmental reporting

structure is expected to remain in place throughout 2020 with any changes coming into effect from 1 January 2021.

†

Inventory holding gains and losses represent the difference between the cost of sales calculated using the replacement cost of inventory and the cost of sales calculated on the first-in first-

out (FIFO) method after adjusting for any changes in provisions where the net realizable value of the inventory is lower than its cost. Under the FIFO method, which we use for IFRS

reporting, the cost of inventory charged to the income statement is based on its historical cost of purchase or manufacture, rather than its replacement cost. In volatile energy markets, this

can have a significant distorting effect on reported income. The amounts disclosed represent the difference between the charge to the income statement for inventory on a FIFO basis (after

adjusting for any related movements in net realizable value provisions) and the charge that would have arisen based on the replacement cost of inventory. For this purpose, the replacement

cost of inventory is calculated using data from each operation’s production and manufacturing system, either on a monthly basis, or separately for each transaction where the system allows

this approach. The amounts disclosed are not separately reflected in the financial statements as a gain or loss. No adjustment is made in respect of the cost of inventories held as part of a

trading position and certain other temporary inventory positions.

BP Annual Report and Form 20-F 2019 177

5. Segmental analysis – continued

$ million

2019

By business Upstream Downstream Rosneft

Other

businesses

and

corporate

Consolidation

adjustment

and

eliminations

Total

group

Segment revenues

Sales and other operating revenues 54,501 250,897 — 1,788 (28,789) 278,397

Less: sales and other operating revenues between

segments

(27,034) (973) — (782) 28,789 —

Third party sales and other operating revenues 27,467 249,924 — 1,006 — 278,397

Earnings from joint ventures and associates – after

interest and tax

603 374 2,295 (15) — 3,257

Segment results

Replacement cost profit (loss) before interest and

taxation

4,917 6,502 2,316 (2,771) 75 11,039

Inventory holding gains (losses)

(8) 685 (10) — — 667

Profit (loss) before interest and taxation 4,909 7,187 2,306 (2,771) 75 11,706

Finance costs (3,489)

Net finance expense relating to pensions and other

post-retirement benefits

(63)

Profit before taxation 8,154

Other income statement items

Depreciation, depletion and amortization

US 4,672 1,335 — 55 — 6,062

Non-US 9,560 1,586 — 572 — 11,718

Charges for provisions, net of write-back of unused

provisions, including change in discount rate

118 507 — 560 — 1,185

Segment assets

Investments in joint ventures and associates 12,196 3,609 12,927 1,593 — 30,325

Additions to non-current assets

16,254 4,014 — 2,345 — 22,613

See explanation of inventory holding gains and losses on page 177.

Includes additions to property, plant and equipment; goodwill; intangible assets; investments in joint ventures; and investments in associates.

$ million

2018

By business Upstream Downstream Rosneft

Other

businesses and

corporate

Consolidation

adjustment and

eliminations

Total

group

Segment revenues

Sales and other operating revenues 56,399 270,689 — 1,678 (30,010) 298,756

Less: sales and other operating revenues between

segments

(28,565) (574) — (871) 30,010 —

Third party sales and other operating revenues 27,834 270,115 — 807 — 298,756

Earnings from joint ventures and associates – after

interest and tax

951 589 2,283 (70) — 3,753

Segment results

Replacement cost profit (loss) before interest and

taxation

14,328 6,940 2,221 (3,521) 211 20,179

Inventory holding gains (losses)

(6) (862) 67 — — (801)

Profit (loss) before interest and taxation 14,322 6,078 2,288 (3,521) 211 19,378

Finance costs (2,528)

Net finance expense relating to pensions and other

post-retirement benefits

(127)

Profit before taxation 16,723

Other income statement items

Depreciation, depletion and amortization

US 4,211 900 — 59 — 5,170

Non-US 8,907 1,177 — 203 — 10,287

Charges for provisions, net of write-back of unused

provisions, including change in discount rate

355 834 — 1,557 — 2,746

Segment assets

Investments in joint ventures and associates 12,785 2,772 10,074 689 — 26,320

Additions to non-current assets

b c

24,266 3,609 — 477 — 28,352

See explanation of inventory holding gains and losses on page 177.

Includes additions to property, plant and equipment; goodwill; intangible assets; investments in joint ventures; and investments in associates.

Amounts have been restated to include acquisitions

178 BP Annual Report and Form 20-F 2019

5. Segmental analysis – continued

$ million

2017

By business Upstream Downstream Rosneft

Other

businesses and

corporate

Consolidation

adjustment and

eliminations

Total

group

Segment revenues

Sales and other operating revenues 45,440 219,853 — 1,469 (26,554) 240,208

Less: sales and other operating revenues between

segments

(24,179) (1,800) — (575) 26,554 —

Third party sales and other operating revenues 21,261 218,053 — 894 — 240,208

Earnings from joint ventures and associates – after

interest and tax

930 674 922 (19) — 2,507

Segment results

Replacement cost profit (loss) before interest and

taxation

5,221 7,221 836 (4,445) (212) 8,621

Inventory holding gains (losses)

8 758 87 — — 853

Profit (loss) before interest and taxation 5,229 7,979 923 (4,445) (212) 9,474

Finance costs (2,074)

Net finance expense relating to pensions and other

post-retirement benefits

(220)

Profit before taxation 7,180

Other income statement items

Depreciation, depletion and amortization

US 4,631 875 — 65 — 5,571

Non-US 8,637 1,141 — 235 — 10,013

Charges for provisions, net of write-back of unused

provisions, including change in discount rate

220 304 — 2,902 — 3,426

See explanation of inventory holding gains and losses on page 177.

$ million

2019

By geographical area US Non-US Total

Revenues

Third party sales and other operating revenues

89,334 189,063 278,397

Other income statement items

Production and similar taxes 315 1,232 1,547

Non-current assets

57,757 133,398 191,155

Non-US region includes UK $63,194 million

Non-US region includes UK $22,881 million

Includes property, plant and equipment; goodwill; intangible assets; investments in joint ventures; investments in associates; and non-current prepayments.

$ million

2018

By geographical area US Non-US Total

Revenues

Third party sales and other operating revenues

98,066 200,690 298,756

Other income statement items

Production and similar taxes 369 1,167 1,536

Non-current assets

68,188 124,060 192,248

Non-US region includes UK $65,630 million.

Non-US region includes UK $19,426 million.

Includes property, plant and equipment; goodwill; intangible assets; investments in joint ventures; investments in associates; and non-current prepayments.

BP Annual Report and Form 20-F 2019 179

5. Segmental analysis – continued

$ million

2017

By geographical area US Non-US Total

Revenues

Third party sales and other operating revenues

83,269 156,939 240,208

Other income statement items

Production and similar taxes 52 1,723 1,775

Non-US region includes UK $48,837 million.

180 BP Annual Report and Form 20-F 2019

6. Revenue from contracts with customers

The amounts shown in the table below are included in Sales and other operating revenues in the group income statement. An analysis of total

sales and other operating revenues by segment and region is provided in Note 5.

Revenue from contracts with customers, by product

$†million

2019 2018 2017

Crude oil 62,130 65,276 49,670

Oil products 180,528 195,466 159,821

Natural gas, LNG and NGLs 20,167 21,745 16,196

Non-oil products and other revenues from contracts with customers 13,254 13,768 12,538

Revenues from contracts with customers 276,079 296,255 238,225

The group’s sales to customers of crude oil and oil products were substantially all made by the Downstream segment. The group’s sales to

customers of natural gas, LNG and NGLs were made by the Upstream segment. A significant majority of the group’s sales of non-oil products

and other revenues from contracts with customers were made by the Downstream segment.

See Note 1 - impact of new International Financial Reporting Standards - Not yet adopted - IFRIC agenda decision on IFRS 9 'Financial

instruments' for further information on changes to the presentation of revenue from contracts with customers that will apply from 1 January

2020.

7. Income statement analysis

$ million

2019 2018 2017

Interest and other income

Interest income from

Financial assets measured at amortized cost 371 421 288

Financial assets measured at fair value through profit or loss 49 39 —

Other income 349 313 369

769 773 657

Currency exchange losses charged to the income statement

37 368 83

Expenditure on research and development 364 429 391

Costs relating to the Gulf of Mexico oil spill (pre-interest and tax)

319 714 2,687

Finance costs

Interest payable on lease liabilities

379 51 56

Interest payable on other liabilities measured at amortized cost 2,410 2,147 1,662

Capitalized at 3.50% (2018 3.56% and 2017 2.25%)

(374) (419) (297)

Unwinding of discount on provisions

505 210 150

Unwinding of discount on other payables measured at amortized cost 569 539 503

3,489 2,528 2,074

Excludes exchange gains and losses arising on financial instruments measured at fair value through profit or loss.

Included within production and manufacturing expenses.

Interest payable on lease liabilities in comparative periods relate to leases previously classified as finance leases under IAS 17.

Tax relief on capitalized interest is approximately $51 million (2018 $55 million and 2017 $64 million).

From

1 July 2018, the group changed its method of discounting and unwinding provisions from using real rates to using nominal rates.

8. Exploration for and evaluation of oil and natural gas resources

The following financial information represents the amounts included within the group totals relating to activity associated with the exploration

for and evaluation of oil and natural gas resources. All such activity is recorded within the Upstream segment.

For information on significant judgements made in relation to oil and natural gas accounting see Intangible assets in Note 1.

$ million

2019 2018 2017

Exploration and evaluation costs

Exploration expenditure written off

631 1,085 1,603

Other exploration costs 333 360 477

Exploration expense for the year 964 1,445 2,080

Impairment losses 2 137 —

Intangible assets – exploration and appraisal expenditure

14,091 15,989 17,026

Liabilities 73 60 82

Net assets 14,018 15,929 16,944

Cash used in operating activities 333 360 477

Cash used in investing activities 1,215 1,119 1,901

2018 includes $447 million in the deepwater Gulf of Mexico principally relating to licence expiries. 2017 included write-offs in Angola of $574 million in relation to licence relinquishment and

Egypt of $208 million following a determination that no commercial hydrocarbons had been found. 2017 also included a $145-million write-off in relation to the value ascribed to certain

licences in the deepwater Gulf of Mexico as part of the accounting for the acquisition of upstream assets from Devon Energy in 2011. For further information see Upstream – Exploration on

page 53.

2019 includes approximately $2.5 billion relating to Canadian oil sands. See Note 1 for further information.

The carrying amount, by location, of exploration and appraisal expenditure capitalized as intangible assets at 31†December†2019 is shown in the

table below.

Carrying amount Location

$1 - 2 billion Angola; Egypt; Middle East

$2 - 3 billion US - Gulf of Mexico; Canada; Brazil

BP Annual Report and Form 20-F 2019 181

9. Taxation

Tax on profit

$ million

2019 2018 2017

Current tax

Charge for the year 5,316 6,217 4,208

Adjustment in respect of prior years

(68) (221) 58

5,248 5,996 4,266

Deferred tax

Origination and reversal of temporary differences in the current year (1,190) 907 (503)

Adjustment in respect of prior years (94) 242 (51)

(1,284) 1,149 (554)

Tax charge on profit 3,964 7,145 3,712

The adjustments in respect of prior years reflect the reassessment of the current tax balances for prior years in light of changes in facts and circumstances during the year.

Origination and reversal of temporary differences in the current year include the impact of tax rate changes on deferred tax balances. 2018 includes a credit of $121 million (2017 $859 million

charge) in respect of the reduction in the US federal corporate income tax rate from 35% to 21%, effective from 1 January 2018. The adjustments in respect of prior years reflect the

reassessment of deferred tax balances for prior periods in light of all other changes in facts and circumstances during the year.

In 2019, the total tax charge recognized within other comprehensive income was $227 million (2018 $714 million charge and 2017 $1,499

million charge), primarily comprising the deferred tax impact of the remeasurements of the net pension and other post-retirement benefit

liability or asset. See Note 32 for further information.

The total tax charge recognized directly in equity was $37 million (2018 $17 million charge and 2017 $263 million charge).

Reconciliation of the effective tax rate

The following table provides a reconciliation of the group weighted average statutory corporate income tax rate to the effective tax rate of the

group on profit before taxation.

9. Taxation – continued

$ million

2019 2018 2017

Profit before taxation 8,154 16,723 7,180

Tax charge on profit 3,964 7,145 3,712

Effective tax rate 49% 43% 52%

Tax rate computed at the weighted average statutory rate

52 43 44

Increase (decrease) resulting from

Tax reported in equity-accounted entities (7) (5) (7)

Deferred tax not recognized

(2) 1 6

Tax incentives for investment (3) (2) (6)

Foreign exchange 1 3 (4)

Items not deductible for tax purposes 4 1 5

Impact of US tax reform

— (1) 12

Other

Effective tax rate 49 43 52

Calculated based on the statutory corporate income tax rate applicable in the countries in which the group operates, weighted by the profits and losses before tax in the respective

countries.

A minor amendment has been made to 2017 and 2018 to align with current period presentation.

Relates to the deferred tax impact of the reduction in the US federal corporate income tax rate from 35% to 21%, effective from 1 January 2018.

Deferred tax

$ million

Analysis of movements during the year in the net deferred tax liability 2019 2018

At 31†December 6,106 3,513

Adjustment on adoption of IFRS 9

— (36)

Adjustment on adoption of IFRS 16

(75) —

At 1 January 6,031 3,477

Exchange adjustments 72 (68)

Charge (credit) for the year in the income statement (1,284) 1,149

Charge for the year in other comprehensive income 233 734

Charge for the year in equity 37 17

Acquisitions, disposals and other additions

101 797

At 31 December 5,190 6,106

2018 reflects the deferred tax impact of adjustments recorded by the group on adoption of IFRS 9. See BP Annual Report and Form 20-F 2018 - Financial statements - Note 1 for further

information.

2019 reflects the deferred tax impact of adjustments recorded by the group on adoption of IFRS 16. See Note 1 for further information.

2018 relates primarily to the purchase of an additional 16.5% interest in the Clair field. See Note 3 - Other significant transactions for further information.

182 BP Annual Report and Form 20-F 2019

9. Taxation – continued

The following table provides an analysis of deferred tax in the income statement and the balance sheet by category of temporary difference:

$ million

Income statement

Balance sheet

2019 2018 2017 2019 2018

Deferred tax liability

Depreciation (1,436) (1,297) (3,971) 22,627 22,565

Pension plan surpluses (31) 65 (12) 2,290 1,956

Derivative financial instruments 29 (36) (27) 29 —

Other taxable temporary differences 159 (57) (64) 1,496 1,224

(1,279) (1,325) (4,074) 26,442 25,745

Deferred tax asset

Lease liabilities 264 8 (16) (1,380) (90)

Pension plan and other post-retirement benefit plan deficits 62 (6) 340 (1,367) (1,319)

Decommissioning, environmental and other provisions (472) 1,505 3,503 (7,579) (7,126)

Derivative financial instruments 63 (31) (47) (24) (95)

Tax credits (336) 123 1,476 (3,964) (3,626)

Loss carry forward 12 559 (964) (5,834) (5,900)

Other deductible temporary differences 402 316 (772) (1,104) (1,483)

(5) 2,474 3,520 (21,252) (19,639)

Net deferred tax charge (credit) and net deferred tax liability

(1,284) 1,149 (554) 5,190 6,106

Of which – deferred tax liabilities 9,750 9,812

– deferred tax assets 4,560 3,706

The 2017 and 2018 income statement and 2018 balance sheet are impacted by the reduction in US federal corporate income tax rate from 35% to 21%, effective from 1 January 2018.

The 2019 balance sheet is impacted by the adoption of IFRS 16 and minor amendments have been made to the balance sheet and income statement comparatives to align with current

period presentation.

Included within the net deferred tax liability is a deferred tax asset balance of $5,526 million (2018 $5,562 million) related to the Gulf of Mexico oil spill.

Of the $4,560 million of deferred tax assets recognised on the group balance sheet at 31 December 2019 (2018 $3,706 million), $2,421 million

(2018 $2,758 million) relates to entities that have suffered a loss in either the current or preceding period. This amount is supported by

forecasts that indicate sufficient future taxable profits will be available to utilize such assets. For 2019, $2,421 million relates to the US (2018

$1,563 million relates to the US and $1,108 million relates to India).

A summary of temporary differences, unused tax credits and unused tax losses for which deferred tax has not been recognized is shown in

the table below.

$ billion

At 31†December 2019 2018

Unused US state tax losses

2.3 6.6

Unused tax losses – other jurisdictions

3.5 4.3

Unused tax credits 25.4 22.5

of which – arising in the UK

21.5 18.7

††††††††††††† – arising in the US

3.9 3.8

Deductible temporary differences

40.4 37.3

Taxable temporary differences associated with investments in subsidiaries and equity-accounted entities 1.5 1.5

For 2019 these losses expire in the period 2020-2039 with applicable tax rates ranging from 3% to 12%.

The majority of the unused tax losses have no fixed expiry date.

The UK unused tax credits arise predominantly in overseas branches of UK entities based in jurisdictions with higher statutory corporate income tax rates than the UK. No deferred tax asset

has been recognized on these tax credits as they are unlikely to have value in the future; UK taxes on these overseas branches are largely mitigated by double tax relief in respect of

overseas tax. These tax credits have no fixed expiry date.

For 2019 the US unused tax credits expire in the period 2020-2029.

The majority comprises fixed asset temporary differences in the UK. Substantially all of the temporary differences have no expiry date.

$ million

Impact of previously unrecognized deferred tax or write-down of deferred tax assets on tax charge 2019 2018 2017

Current tax benefit relating to the utilization of previously unrecognized deferred tax assets 272 83 22

Deferred tax benefit arising from the reversal of a previous write-down of deferred tax assets 96 — —

Deferred tax benefit relating to the recognition of previously unrecognized deferred tax assets 364 112 436

Deferred tax expense arising from the write-down of a previously recognized deferred tax asset 73 169 78

BP Annual Report and Form 20-F 2019 183

10. Dividends

The quarterly dividend which is expected to be paid on 27 March†2020 in respect of the fourth quarter 2019 is 10.50 cents per ordinary share

($0.630 per American Depositary Share (ADS)). The corresponding amount in sterling was announced on 16 March 2020.

Pence per share Cents per share $ million

2019 2018 2017 2019 2018 2017 2019 2018 2017

Dividends announced and paid in†cash

Preference shares 1 1 1

Ordinary shares

March 7.7380 7.1691 8.1587 10.25 10.00 10.00 1,435 1,828 1,303

June 8.0660 7.4435 7.7563 10.25 10.00 10.00 1,779 1,727 1,546

September 8.3480 7.9296 7.6213 10.25 10.25 10.00 1,656 1,409 1,676

December 7.8250 8.0251 7.4435 10.25 10.25 10.00 2,075 1,734 1,627

31.9770 30.5673 30.9798 41.00 40.50 40.00 6,946 6,699 6,153

Dividend announced, paid in March

2020

10.50 2,120

The details of the scrip dividends issued are shown in the table below. The board decided not to offer a scrip dividend alternative in respect of

the third quarter 2019 dividend paid in December 2019 and fourth quarter 2019 dividend expected to be paid on 27 March 2020.

2019 2018 2017

Number of shares issued (thousand) 208,927 195,305 289,789

Value of shares issued ($ million) 1,387 1,381 1,714

The financial statements for the year ended 31†December†2019 do not reflect the dividend announced on 4 February 2020 and paid in March

2020; this will be treated as an appropriation of profit in the year ending 31 December 2020.

184 BP Annual Report and Form 20-F 2019

11. Earnings per share

Cents per share

Per ordinary share 2019 2018 2017

Basic earnings per share 19.84 46.98 17.20

Diluted earnings per share 19.73 46.67 17.10

Dollars†per†share

Per American Depositary Share (ADS) 2019 2018 2017

Basic earnings per share 1.19 2.82 1.03

Diluted earnings per share 1.18 2.80 1.03

Basic earnings per ordinary share amounts are calculated by dividing the profit for the year attributable to BP ordinary shareholders by the

weighted average number of ordinary shares outstanding during the year.

The weighted average number of shares outstanding includes certain shares that will be issuable in the future under employee share-based

payment plans and excludes treasury shares, which includes shares held by the Employee Share Ownership Plan trusts (ESOPs).

For the diluted earnings per share calculation, the weighted average number of shares outstanding during the year is adjusted for the average

number of shares that are potentially issuable in connection with employee share-based payment plans. If the inclusion of potentially issuable

shares would decrease loss per share, the potentially issuable shares are excluded from the weighted average number of shares outstanding

used to calculate diluted earnings per share.

$ million

2019 2018 2017

Profit attributable to BP shareholders 4,026 9,383 3,389

Less: dividend requirements on preference shares 1 1 1

Profit for the year attributable to BP ordinary shareholders 4,025 9,382 3,388

Shares thousand

2019 2018 2017

Basic weighted average number of ordinary shares 20,284,859 19,970,215 19,692,613

Potential dilutive effect of ordinary shares issuable under employee share-based payment

plans

114,811 132,278 123,829

Weighted average number of ordinary shares outstanding used to calculate diluted

earnings per share

20,399,670 20,102,493 19,816,442

Shares thousand

2019 2018 2017

Basic weighted average number of ordinary shares – ADS equivalent 3,380,809 3,328,369 3,282,102

Potential dilutive effect of ordinary shares (ADS equivalent) issuable under employee

share-based payment plans

19,136 22,046 20,638

Weighted average number of ordinary shares (ADS equivalent) outstanding used to

calculate diluted earnings per share

3,399,945 3,350,415 3,302,740

11. Earnings per share – continued

The number of ordinary shares outstanding at 31†December†2019, excluding treasury shares, and including certain shares that will be issuable

in the future under employee share-based payment plans was 20,241,170,965. Between 31†December†2019 and 27†February†2020, the latest

practicable date before the completion of these financial statements, there was a net decrease of 46,527,851 in the number of ordinary shares

outstanding primarily as a result of share issues in relation to employee share-based payment plans. A further 120 million of shares have also

been repurchased in January 2020 as part of the share buyback programme at a total cost of $776 million.

Employee share-based payment plans

The group operates share and share option plans for directors and certain employees to obtain ordinary shares and ADSs in the company.

Information on these plans for directors is shown in the Directors remuneration report on pages 100-127.

The following table shows the number of shares potentially issuable under equity-settled employee share option plans, including the number of

options outstanding, the number of options exercisable at the end of each year, and the corresponding weighted average exercise prices. The

dilutive effect of these plans at 31†December is also shown.

Share options 2019 2018

Number of options

thousand

Weighted average

exercise price $

Number of options

thousand

Weighted average

exercise price $

Outstanding 17,112 4.91 19,437 4.28

Exercisable 1,067 3.97 481 4.69

Dilutive effect 3,990 n/a 6,123 n/a

Numbers of options shown are ordinary share equivalents (one ADS is equivalent to six ordinary shares).

At 31†December†2019 the quoted market price of one BP ordinary share was £4.72 (2018 £4.96).

In addition, the group operates a number of equity-settled employee share plans under which share units are granted to the group’s senior

leaders and certain other employees. These plans typically have a three-year performance or restricted period during which the units accrue net

notional dividends which are treated as having been reinvested. Leaving employment will normally preclude the conversion of units into

shares, but special arrangements apply for participants that leave for qualifying reasons. The number of shares that are expected to vest each

year under employee share plans are shown in the table below. The dilutive effect of the employee share plans at 31†December is also shown.

Share plans 2019 2018

Number of shares

Vesting thousand thousand

Within one year 91,105 108,934

1 to 2 years 89,939 106,337

2 to 3 years 80,844 71,407

3 to 4 years 725 588

Over 4 years 576 799

263,189 288,065

Dilutive effect 92,343 127,165

Numbers of shares shown are ordinary share equivalents (one ADS is equivalent to six ordinary shares).

There has been a net decrease of 37,497,364 in the number of potential ordinary shares relating to employee share-based payment plans

between 31†December 2019 and 27†February†2020.

BP Annual Report and Form 20-F 2019 185

12. Property, plant and equipment

$ million

Land and land

improvements Buildings

Oil and gas

properties

Plant,

machinery

and

equipment

Fittings,

fixtures and

office

equipment Transportation

Oil depots,

storage tanks

and service

stations Total

Cost - owned property, plant and

equipment (PP&E)

At 1 January 2019 3,562 1,502 232,684 45,721 2,747 10,183 8,866 305,265

Exchange adjustments (22) 5 — (158) 15 (3) (69) (232)

Additions 88 93 13,237 2,433 172 274 644 16,941

Acquisitions 51 — — — — — 8 59

Transfers from intangible assets — — 1,885 — — — — 1,885

Reclassified as assets held for sale (26) — (22,602) — (76) (6,708) — (29,412)

Deletions (44) (178) (10,852) (1,272) (326) (272) (755) (13,699)

At 31 December 2019 3,609 1,422 214,352 46,724 2,532 3,474 8,694 280,807

Depreciation - owned PP&E

At 1 January 2019 626 697 133,687 20,512 2,041 7,819 5,146 170,528

Exchange adjustments (4) 5 — (63) 12 (3) (45) (98)

Charge for the year 44 59 13,012 1,705 168 173 420 15,581

Impairment losses 1 1 5,871 64 1 404 4 6,346

Impairment reversals — — (129) — — (2) — (131)

Reclassified as assets held for sale — — (17,764) — (69) (5,478) — (23,311)

Deletions (86) (65) (9,911) (691) (147) (169) (660) (11,729)

At 31 December 2019 581 697 124,766 21,527 2,006 2,744 4,865 157,186

Owned PP&E - net book amount at

31 December 2019 3,028 725 89,586 25,197 526 730 3,829 123,621

Right-of-use assets - net book

amount at 31 December 2019

— 1,196 128 1,241 16 3,385 3,055 9,021

Total PP&E - net book amount at 31

December 2019

3,028 1,921 89,714 26,438 542 4,115 6,884 132,642

Cost

At 1 January 2018 3,474 1,573 226,054 46,662 2,853 10,774 8,748 300,138

Exchange adjustments (168) (58) — (892) (73) (43) (501) (1,735)

Additions 233 40 9,712 2,323 204 (112) 736 13,136

Acquisitions 163 4 10,882 9 1 2 36 11,097

Remeasurements

— — 17 — — — — 17

Transfers from intangible assets — — 901 — — — — 901

Deletions (140) (45) (14,699) (1,810) (238) (128) (146) (17,206)

At 31 December 2018 3,562 1,514 232,867 46,292 2,747 10,493 8,873 306,348

Depreciation

At 1 January 2018 683 818 133,326 20,996 2,136 7,523 5,185 170,667

Exchange adjustments (25) (24) — (460) (52) (27) (279) (867)

Charge for the year 92 52 12,342 1,820 189 252 384 15,131

Impairment losses 2 — 86 253 — 178 2 521

Impairment reversals — — (564) (1) — (17) — (582)

Deletions (126) (139) (11,333) (1,733) (232) (75) (145) (13,783)

At 31 December 2018 626 707 133,857 20,875 2,041 7,834 5,147 171,087

Net book amount at 31 December

2018

2,936 807 99,010 25,417 706 2,659 3,726 135,261

Assets held under finance leases at net book

amount included above

At 31 December 2018 — 2 12 207 — 295 6 522

Assets under construction included above

At 31 December 2019 23,897

At 31 December 2018 22,522

Depreciation charge for the year on right-of-use

assets

2019 220 31 671 9 784 526 2,241

For information on significant estimates and judgements made in relation to the estimation of oil and natural reserves see Property, plant and equipment within Note 1.

Includes adjustments to decommissioning provisions; see Note 1 for further information.

$653 million of drilling rig right-of-use assets and $2,929 million of shipping vessel right-of-use assets are included in Plant, machinery and equipment and Transportation respectively.

Leases previously classified as finance leases are included within right-of-use assets following the implementation of IFRS 16 ‘Leases’; see Note 1 for further information. The reconciliation

of owned property, plant and equipment for 2019 does not include right-of-use assets and, therefore, the cost and depreciation at 1 January 2019 is not equal to the cost and depreciation of

total property, plant and equipment at 31 December 2018. The relevant amounts excluded are cost of $1,083 million and depreciation of $559 million relating to leases previously classified as

finance leases.

186 BP Annual Report and Form 20-F 2019

13. Capital commitments

Authorized future capital expenditure for property, plant and equipment (excluding right-of-use assets) by group companies for which contracts

had been signed at 31†December†2019 amounted to $11,382 million (2018 $8,319 million, 2017 $11,340 million). BP has contracted capital

commitments amounting to $787 million (2018 $1,227 million, 2017 $1,451 million) in relation to associates. BP’s share of contracted capital

commitments of joint ventures amounted to $1,024 million (2018 $619†million, 2017 $483 million).

BP Annual Report and Form 20-F 2019 187

14. Goodwill and impairment review of goodwill

$ million

2019 2018

Cost

At 1†January 12,815 12,163

Exchange adjustments 79 (210)

Acquisitions and other additions

26 1,046

Deletions (55) (184)

At 31†December 12,865 12,815

Impairment losses

At 1†January 611 612

Exchange adjustments — —

Impairment losses for the year 386 —

Deletions — (1)

At 31†December 997 611

Net book amount at 31†December 11,868 12,204

Net book amount at 1†January 12,204 11,551

2018 principally relates to the purchase of an additional 16.5% share in the Clair field in the North Sea. See Note 3 - Other significant transactions for further information.

Impairment review of goodwill

Goodwill at 31 December 2019 2018

Upstream 7,958 8,346

Downstream 3,904 3,802

Other businesses and corporate 6 56

11,868 12,204

Goodwill acquired through business combinations has been allocated to groups of cash-generating units that are expected to benefit from the

synergies of the acquisition. For Upstream, goodwill is allocated to all oil and gas assets in aggregate at the segment level. For Downstream,

goodwill has been allocated to Lubricants and Other.

For information on significant estimates and judgements made in relation to impairments see Impairment of property, plant and equipment,

intangible assets and goodwill in Note 1.

Upstream

2019 2018

Goodwill 7,958 8,346

Excess of recoverable amount over carrying amount 93,250 53,391

The table above shows the carrying amount of goodwill for the segment and the excess of the recoverable amount, based on a pre-tax value-

in-use calculation, over the carrying amount (headroom) at the date of the test. The increase in headroom principally arises from acquisitions

(including the acquisition from BHP), new activity and discount rate changes, net of highly probable and completed divestments and price

assumption changes.

Goodwill impairments of $386 million, related to goodwill allocated to expected divestments, were recognized during 2019 (2018 nil).

The value in use is based on the cash flows expected to be generated by the projected oil or natural gas production profiles up to the expected

dates of cessation of production of each producing field, based on current estimates of reserves and resources, appropriately risked.

Midstream and supply and trading activities and equity-accounted entities are generally not included in the impairment review of goodwill,

because they are not part of the grouping of cash-generating units to which the goodwill relates and which is used to monitor the goodwill for

internal management purposes. Where such activities form part of a wider Upstream cash-generating unit, they are reflected in the test. As the

production profile and related cash flows can be estimated from BP’s past experience, management believes that the cash flows generated

over the estimated life of field is the appropriate basis upon which to assess goodwill and individual assets for impairment. The estimated date

of cessation of production depends on the interaction of a number of variables, such as the recoverable quantities of hydrocarbons, the

production profile of the hydrocarbons, the cost of the development of the infrastructure necessary to recover the hydrocarbons, production

costs, the contractual duration of the production concession and the selling price of the hydrocarbons produced. As each producing field has

specific reservoir characteristics and economic circumstances, the cash flows of the fields are computed using appropriate individual economic

models and key assumptions agreed by BP management. Capital expenditure, operating costs and expected hydrocarbon production profiles

are derived from the business segment plan adjusted for assumptions reflecting the price environment at the time that the test was

performed. Estimated production volumes and cash flows up to the date of cessation of production on a field-by-field basis are consistent with

this. The production profiles used are consistent with the reserve and resource volumes approved as part of BP’s centrally controlled process

for the estimation of proved and probable reserves and total resources.

14. Goodwill and impairment review of goodwill – continued

The most recent review for impairment was carried out in the fourth quarter. The key assumptions used in the value-in-use calculation are oil

and natural gas prices, production volumes and the discount rate. Oil and gas price assumptions and discount rate assumptions used were as

disclosed in Note 1. The value-in-use calculation has been prepared solely for the purposes of determining whether the goodwill balance was

impaired. Estimated future cash flows were prepared on the basis of certain assumptions prevailing at the time of the test. The actual

outcomes may differ from the assumptions made. For example, reserves and resources estimates and production forecasts are subject to

revision as further technical information becomes available and economic conditions change. Due to economic developments, regulatory

change and emissions reduction activity arising from climate concern and other factors, future commodity prices and other assumptions may

differ from the forecasts used in the calculations.

Sensitivities to different variables have been estimated using certain simplifying assumptions. For example, lower oil and gas price sensitivities

do not fully reflect the specific impacts for each contractual arrangement and will not capture all favourable impacts that may arise from cost

deflation. A detailed calculation at any given price or production profile may, therefore, produce a different result.

It is estimated that no reasonable sustained fall in the oil or gas price assumption over the next 20 years would individually cause the

recoverable amount to be equal to the carrying amount of goodwill and related net non-current assets of the segment.

Estimated production volumes are based on detailed data for each field and take into account development plans agreed by management as

part of the long-term planning process. The average production for the purposes of goodwill impairment testing over the next 15 years is 829

mmboe†per year (2018 829 mmboe per year). It is estimated that no reasonably possible change in production volumes would cause the

recoverable amount to be equal to the carrying amount of goodwill and related net non-current assets of the segment.

It is estimated that no reasonably possible change in the pre-tax discount rate would cause the recoverable amount to be equal to the carrying

amount of goodwill and related net non-current assets of the segment. The weighted average discount rate used in the test is 12%.

Downstream

$ million

2019 2018

Lubricants Other Total Lubricants Other Total

Goodwill 2,779 1,125 3,904 2,692 1,110 3,802

Cash flows for each cash-generating unit are derived from the business segment plans, which cover a period of up to five years. To determine

the value in use for each of the cash-generating units, cash flows for a period of 10 years are discounted and aggregated with a terminal value.

Lubricants

As permitted by IAS 36, the detailed calculations of Lubricants’ recoverable amount performed in the most recent detailed calculation in 2018

was used as the basis for the tests in 2019 as the criteria of IAS 36 were considered satisfied: the headroom was substantial in 2018; there

have been no significant changes in the assets and liabilities; and the likelihood that the recoverable amount would be less than the carrying

amount is remote.

The key assumptions to which the calculation of value in use for the Lubricants unit is most sensitive are operating unit margins, sales

volumes, and discount rate. Operating margin and sales volumes assumptions used in the detailed impairment review of goodwill calculation

are consistent with the assumptions used in the Lubricants unit’s business plan and values assigned to these key assumptions reflect past

experience. No reasonably possible change in any of these key assumptions would cause the unit’s carrying amount to exceed its recoverable

amount. Cash flows beyond the plan period are extrapolated using a nominal 2.8% growth rate.

188 BP Annual Report and Form 20-F 2019

15. Intangible assets

$ million

2019 2018

Exploration

and appraisal

expenditure

Other

intangibles Total

Exploration and

appraisal

expenditure

Other

intangibles Total

Cost

At 1†January 17,053 4,504 21,557 17,886 4,488 22,374

Exchange adjustments — 2 2 — (128) (128)

Acquisitions — 35 35 — 25 25

Additions 1,268 457 1,725 1,095 318 1,413

Transfers to property, plant and equipment (1,885) — (1,885) (901) — (901)

Reclassified as assets held for sale (671) — (671) — — —

Deletions (459) (98) (557) (1,027) (199) (1,226)

At 31†December 15,306 4,900 20,206 17,053 4,504 21,557

Amortization

At 1†January 1,064 3,209 4,273 860 3,159 4,019

Exchange adjustments — 4 4 — (77) (77)

Charge for the year 631 331 962 1,085 326 1,411

Impairment losses 2 2 4 137 — 137

Reclassified as assets held for sale (61) — (61) — — —

Deletions (421) (94) (515) (1,018) (199) (1,217)

At 31†December 1,215 3,452 4,667 1,064 3,209 4,273

Net book amount at 31†December 14,091 1,448 15,539 15,989 1,295 17,284

Net book amount at 1†January 15,989 1,295 17,284 17,026 1,329 18,355

For further information see Intangible assets within Note 1 and Note 8.

16. Investments in joint ventures

The following table provides aggregated summarized financial information relating to the group’s share of joint ventures. In December 2019, BP

and Bunge both contributed their Brazilian biofuels and biopower businesses into a new joint venture, BP Bunge Bioenergia. BP owns 50% of

the new entity.

$ million

2019 2018 2017

Sales and other operating revenues 14,139 13,258 11,380

Profit before interest and taxation 975 1,396 1,394

Finance costs 111 85 100

Profit before taxation 864 1,311 1,294

Taxation 288 414 117

Profit for the year 576 897 1,177

Other comprehensive income (6) 6 8

Total comprehensive income 570 903 1,185

Non-current assets 13,408 10,399

Current assets 3,738 2,935

Total assets 17,146 13,334

Current liabilities 2,514 1,715

Non-current liabilities 4,676 3,017

Total liabilities 7,190 4,732

Net assets 9,956 8,602

Group investment in joint ventures

Group share of net assets (as above) 9,956 8,602

Loans made by group companies to joint ventures 35 45

9,991 8,647

Transactions between the group and its joint ventures are summarized below.

$ million

Sales to joint ventures 2019 2018 2017

Product Sales

Amount

receivable at

31 December Sales

Amount

receivable at

31 December Sales

Amount

receivable at

31 December

LNG, crude oil and oil products, natural gas 4,884 431 4,603 251 3,578 352

$ million

Purchases from joint ventures 2019 2018 2017

Product Purchases

Amount

payable at

31 December Purchases

Amount

payable at

31 December Purchases

Amount

payable at

31 December

LNG, crude oil and oil products, natural gas, refinery

operating costs, plant processing fees

1,812 225 1,336 300 1,257 176

The terms of the outstanding balances receivable from joint ventures are typically 30 to 45 days. The balances are unsecured and will be

settled in cash. There are no significant provisions for doubtful debts relating to these balances and no significant expense recognized in the

income statement in respect of bad or doubtful debts. Dividends receivable are not included in the table above.

BP Annual Report and Form 20-F 2019 189

17. Investments in associates

The following table provides aggregated summarized financial information for the group’s associates as it relates to the amounts recognized in

the group income statement and on the group balance sheet.

$ million

Income statement Balance sheet

Earnings from associates

- after interest and tax

Investments in

associates

2019 2018 2017 2019 2018

Rosneft 2,295 2,283 922 12,927 10,074

Other associates 386 573 408 7,407 7,599

2,681 2,856 1,330 20,334 17,673

The associate that is material to the group at both 31†December†2019 and 2018 is Rosneft.

BP owns 19.75% of the voting shares of Rosneft which are listed on the MICEX stock exchange in Moscow and its global depository receipts

are listed on the London Stock Exchange. The Russian federal government, through its investment company JSC Rosneftegaz, owned 50.0%

plus one share of the voting shares of Rosneft at 31†December†2019.

BP classifies its investment in Rosneft as an associate because, in management’s judgement, BP has significant influence over Rosneft; see

Interests in other entities within Note 1 for further information. The group’s investment in Rosneft is a foreign operation whose functional

currency is the Russian rouble. The increase in the group's equity-accounted investment balance for Rosneft at 31†December†2019 compared

with 31†December†2018 principally relates to earnings from Rosneft and foreign exchange effects, which have been recognized in other

comprehensive income, offset by dividends.

17. Investments in associates – continued

The value of BP’s 19.75% shareholding in Rosneft based on the quoted market share price of $7.21 per share (2018 $6.18 per share) was

$15,090†million at 31†December†2019 (2018 $12,934 million).

The following table provides summarized financial information relating to Rosneft. This information is presented on a 100% basis and reflects

adjustments made by BP to Rosneft’s own results in applying the equity method of accounting. BP adjusts Rosneft’s results for the accounting

required under IFRS relating to BP’s purchase of its interest in Rosneft and the amortization of the deferred gain relating to the disposal of BP’s

interest in TNK-BP. These adjustments have increased the reported profit for 2019, as shown in the table below, compared with the amounts

reported in Rosneft's IFRS financial statements. In particular, in 2018 these adjustments resulted in BP reporting a lower amount relating to

impairment charges of downstream goodwill than the equivalent amounts reported by Rosneft.

$ million

Gross amount

2019 2018 2017

Sales and other operating revenues 134,046 131,322 103,028

Profit before interest and taxation 17,473 18,886 9,949

Finance costs 1,281 2,785 2,228

Profit before taxation 16,192 16,101 7,721

Taxation 3,058 2,957 1,742

Non-controlling interests 1,514 1,585 1,311

Profit for the year 11,620 11,559 4,668

Other comprehensive income 572 2,086 2,810

Total comprehensive income 12,192 13,645 7,478

Non-current assets 161,327 137,038

Current assets 38,657 43,438

Total assets 199,984 180,476

Current liabilities 44,459 41,311

Non-current liabilities 79,327 78,754

Total liabilities 123,786 120,065

Net assets 76,198 60,411

Less: non-controlling interests 10,744 9,403

65,454 51,008

The group received dividends, net of withholding tax, of $785 million from Rosneft in 2019 (2018 $620 million and 2017 $314 million).

Summarized financial information for the group’s share of associates is shown below.

$ million

BP share

2019 2018 2017

Rosneft

Other Total Rosneft

Other Total

Sales and other operating revenues 26,474 7,934 34,408 25,936 9,134 35,070 20,348 7,600 27,948

Profit before interest and taxation 3,451 788 4,239 3,730 1,150 4,880 1,965 626 2,591

Finance costs 253 87 340 550 78 628 440 54 494

Profit before taxation 3,198 701 3,899 3,180 1,072 4,252 1,525 572 2,097

Taxation 604 315 919 584 499 1,083 344 164 508

Non-controlling interests 299 — 299 313 — 313 259 — 259

Profit for the year 2,295 386 2,681 2,283 573 2,856 922 408 1,330

Other comprehensive income 113 (25) 88 412 (1) 411 555 1 556

Total comprehensive income 2,408 361 2,769 2,695 572 3,267 1,477 409 1,886

Non-current assets 31,862 11,504 43,366 27,065 10,787 37,852

Current assets 7,635 1,924 9,559 8,579 2,398 10,977

Total assets 39,497 13,428 52,925 35,644 13,185 48,829

Current liabilities 8,781 1,908 10,689 8,159 2,232 10,391

Non-current liabilities 15,667 4,577 20,244 15,554 3,817 19,371

Total liabilities 24,448 6,485 30,933 23,713 6,049 29,762

Net assets 15,049 6,943 21,992 11,931 7,136 19,067

Less: non-controlling interests 2,122 — 2,122 1,857 — 1,857

12,927 6,943 19,870 10,074 7,136 17,210

Group investment in associates

Group share of net assets (as†above) 12,927 6,943 19,870 10,074 7,136 17,210

Loans made by group companies to

associates

— 464 464 — 463 463

12,927 7,407 20,334 10,074 7,599 17,673

From 1†October 2014, Rosneft adopted hedge accounting in relation to a portion of highly probable future export revenue denominated in US dollars over a five-year period. Foreign exchange

gains and losses arising on the retranslation of borrowings denominated in currencies other than the Russian rouble and designated as hedging instruments are recognized initially in other

comprehensive income, and are reclassified to the income statement as the hedged revenue is recognized.

190 BP Annual Report and Form 20-F 2019

17. Investments in associates – continued

Transactions between the group and its associates are summarized below.

$ million

Sales to associates 2019 2018 2017

Product Sales

Amount

receivable at

31 December Sales

Amount

receivable at

31 December Sales

Amount

receivable at

31 December

LNG, crude oil and oil products, natural gas 1,544 243 2,064 393 1,612 216

$ million

Purchases from associates 2019 2018 2017

Product Purchases

Amount

payable at

31 December Purchases

Amount

payable at

31 December Purchases

Amount

payable at

31 December

Crude oil and oil products, natural gas, transportation

tariff

9,503 1,641 14,112 2,069 11,613 1,681

In addition to the transactions shown in the table above, in 2018 BP acquired a 49% stake in LLC Kharampurneftegaz, a Rosneft subsidiary,

which develops resources within the Kharampurskoe and Festivalnoye licence areas in Yamalo-Nenets in northern Russia. BP’s interest in LLC

Kharampurneftegaz is accounted for as an associate.

The terms of the outstanding balances receivable from associates are typically 30 to 45 days. The balances are unsecured and will be settled in

cash. There are no significant provisions for doubtful debts relating to these balances and no significant expense recognized in the income

statement in respect of bad or doubtful debts. Dividends receivable are not included in the table above.

The majority of purchases from associates relate to crude oil and oil products transactions with Rosneft. Sales to associates are related to

various entities.

BP has commitments amounting to $11,198 million (2018 $11,303 million), primarily in relation to contracts with its associates for the purchase

of transportation capacity. For information on capital commitments in relation to associates see Note 13.

BP Annual Report and Form 20-F 2019 191

18. Other investments

$ million

2019 2018

Current Non-current Current Non-current

Equity investments

— 571 1 482

Other 169 705 221 859

169 1,276 222 1,341

The majority of equity investments are unlisted.

Other investments includes $598 million relating to contingent consideration amounts arising on disposals (2018 $893 million) which are

financial assets classified as measured at fair value through profit or loss. The fair value is determined using an estimate of discounted future

cash flows that are expected to be received and is considered a level 3 valuation under the fair value hierarchy. Future cash flows are estimated

based on inputs including oil and natural gas prices, production volumes and operating costs related to the disposed operations. The discount

rate used is based on a risk-free rate adjusted for asset-specific risks.

19. Inventories

$ million

2019 2018

Crude oil 5,610 4,878

Natural gas 222 322

Refined petroleum and petrochemical products 12,907 10,419

18,739 15,619

Trading inventories 182 282

18,921 15,901

Supplies 1,959 2,087

20,880 17,988

Cost of inventories expensed in the income statement 209,672 229,878

The inventory valuation at 31†December†2019 is stated net of a provision of $650 million (2018 $1,009 million) to write down inventories to their

net realizable value, of which $290 million (2018 $604 million) relates to hydrocarbon inventories. The net credit to the income statement in the

year in respect of inventory net realizable value provisions was $348 million (2018 $552 million charge), of which $309 million credit (2018 $553

million charge) related to hydrocarbon inventories.

Trading inventories are valued using quoted benchmark prices adjusted as appropriate for location and quality differentials. They are

predominantly categorized within level 2 of the fair value hierarchy.

20. Trade and other receivables

$ million

2019 2018

Current Non-current Current Non-current

Financial assets

Trade receivables 19,424 22 19,414 7

Amounts receivable from joint ventures and associates 672 2 642 2

Other receivables 3,325 826 3,275 740

23,421 850 23,331 749

Non-financial assets

Gulf of Mexico oil spill trust fund reimbursement asset 201 — 214 —

Sales taxes and production taxes 640 538 790 482

Other receivables 180 759 143 603

1,021 1,297 1,147 1,085

24,442 2,147 24,478 1,834

In both 2019 and 2018 the group entered into non-recourse arrangements to discount certain receivables in support of supply and trading

activities and the management of credit risk.

Trade and other receivables are predominantly non-interest bearing. See Note 29 for further information.

192 BP Annual Report and Form 20-F 2019

21. Valuation and qualifying accounts

$ million

2019 2018 2017

Trade and

other

receivables

Fixed asset

investments

Trade and

other

receivables

Fixed asset

investments

Trade and

other

receivables

Fixed asset

investments

At 1 January – IAS 39 416 235 335 314 392 335

Adjustment on adoption of IFRS 9 — — 115 (85) — —

At 1 January – IFRS 9 416 235 450 229 392 335

Charged to costs and expenses 206 28 30 10 68 47

Charged to other accounts

(2) — (12) (1) 13 3

Deductions (111) (14) (52) (3) (138) (71)

At 31 December 509 249 416 235 335 314

Principally exchange adjustments.

Valuation and qualifying accounts relating to trade and other receivables comprise expected credit loss allowances in 2019 and 2018 and

impairment provisions recognized on an incurred loss basis in 2017. The adjustment on adoption of IFRS 9 relates to the additional loss

allowance required by IFRS 9's expected credit loss model. The expected credit loss allowance comprises $414 million (2018 $327 million)

relating to receivables that were credit-impaired at the end of the year and $95 million (2018 $89 million) relating to receivables that were not

credit-impaired at the end of the year. There were no significant changes to the gross carrying amounts of trade and other receivables during

the year that affected the estimation of the loss allowance at 31†December†2019.

Valuation and qualifying accounts relating to fixed asset investments comprise impairment provisions for investments in equity-accounted

entities in 2019 and 2018. This includes expected credit loss allowances of $2 million (2018 $44 million) relating to loans that form part of the

net investment in equity-accounted entities. The adjustment on adoption of IFRS 9 primarily relates to amounts provided against investments in

equity instruments that were held at cost less impairment losses under IAS 39 but that are classified as measured at fair value through profit

or loss under IFRS 9.

In addition to the amounts presented above, expected loss allowances on cash and cash equivalents classified as measured at amortized cost

totalled $11 million (2018 $11 million). For further information on the group's credit risk management policies and how the group recognizes

and measures expected losses see Note 29.

Valuation and qualifying accounts are deducted in the balance sheet from the assets to which they apply.

22. Trade and other payables

$ million

2019 2018

Current Non-current Current Non-current

Financial liabilities

Trade payables 30,538 — 26,252 —

Amounts payable to joint ventures and associates 1,866 — 2,369 —

Payables for capital expenditure and acquisitions

3,868 1,196 7,325 1,345

Payables related to the Gulf of Mexico oil spill 1,617 10,863 2,279 11,922

Other payables 5,810 133 4,980 318

43,699 12,192 43,205 13,585

Non-financial liabilities

Sales taxes, customs duties, production taxes and social security 2,381 33 2,272 35

Other payables 749 401 788 210

3,130 434 3,060 245

46,829 12,626 46,265 13,830

2018 includes $3,514 million deferred consideration relating to the acquisition of Petrohawk Energy Corporation from BHP Billiton Petroleum (North America) Inc. See Note 3 for further

information.

Materially all of BP's trade payables have payment terms in the range of 30 to 60 days and give rise to operating cash flows.

Trade and other payables, other than those relating to the Gulf of Mexico oil spill, are predominantly interest free. See Note 29 (c) for further

information.

Payables related to the Gulf of Mexico oil spill include amounts payable under the 2016 consent decree and settlement agreement with the

United States and five Gulf coast states, including amounts payable for natural resource damages, state claims and Clean Water Act penalties.

On a discounted basis the amounts included in other payables for these elements of the agreements are $5,166 million payable over 13 years,

$2,742 million payable over 14 years and $3,782 million payable over 13 years respectively at 31†December†2019. Reported within net cash

provided by operating activities in the group cash flow statement is a net cash outflow of $2,694 million (2018 outflow of $3,531 million, 2017

outflow of $5,336 million) related to the Gulf of Mexico oil spill, which includes payments made in relation to these agreements. For 2018 and

2017 payments under the 2012 agreement with the US government to resolve all federal criminal claims arising from the incident are also

included. For full details of these agreements, see BP Annual Report and Form 20-F 2015.

Payables related to the Gulf of Mexico oil spill at 31 December 2019 also include amounts payable for settled economic loss and property

damage claims which are payable over a period of up to eight years.

BP Annual Report and Form 20-F 2019 193

23. Provisions

$ million

Decommissioning Environmental

Litigation and

claims Other Total

At 1 January 2019

13,613 1,567 1,718 3,306 20,204

Exchange adjustments 74 (1) — (19) 54

Acquisitions 13 — 47 22 82

Increase (decrease) in existing provisions 1,045 272 290 960 2,567

Write-back of unused provisions (22) (43) (15) (361) (441)

Unwinding of discount 415 45 28 17 505

Change in discount rate 1,360 40 31 11 1,442

Utilization (9) (252) (674) (665) (1,600)

Reclassified to other payables (187) — (139) (328) (654)

Reclassified as liabilities directly associated with assets held

for sale

(1,004) (8) — — (1,012)

Deletions (188) — (5) (3) (196)

At 31 December 2019 15,110 1,620 1,281 2,940 20,951

Of which – current 317 280 558 1,298 2,453

– non-current 14,793 1,340 723 1,642 18,498

Of which – Gulf of Mexico oil spill — — 189 — 189

Includes adjustment of $92 million for the implementation of IFRS 16. See Note 1 for further information.

The decommissioning provision comprises the future cost of decommissioning oil and natural gas wells, facilities and related pipelines. The

environmental provision includes provisions for costs related to the control, abatement, clean-up or elimination of environmental pollution

relating to soil, groundwater, surface water and sediment contamination. The litigation and claims category includes provisions for matters

related to, for example, commercial disputes, product liability, and allegations of exposures of third parties to toxic substances. Included within

the other category at 31†December†2019 are provisions for deferred employee compensation of $311 million (2018 $338 million).

For information on significant estimates and judgements made in relation to provisions, see Provisions and contingencies within Note 1.

23. Provisions – continued

Gulf of Mexico oil spill

The group has recognized certain assets, payables and provisions and incurs certain residual costs relating to the Gulf of Mexico oil spill that

occurred in 2010. In addition to the Litigation and claims narrative provided in this note, for further information see Notes 7, 9, 20, 22, 29, 33

and Legal proceedings on pages 319-320.

Litigation and claims - PSC settlements

The Economic and Property Damages Settlement Agreement (EPD Settlement Agreement) with the Plaintiff's Steering Committee (PSC)

provides for a court-supervised settlement programme ,the DHCSSP, which commenced operation on 4 June 2012. A separate claims

administrator was appointed to pay medical claims and to implement other aspects of the Medical Benefits Class Action Settlement. For

further information on the PSC settlements, see Legal proceedings on page 319.

The litigation and claims provision reflects the latest estimate for the remaining costs associated with the PSC settlements. These costs relate

predominantly to business economic loss (BEL) claims and associated administration costs. Only a very small number of claims remained to be

determined by the end of 2019 however certain BEL claims determined by the DHCSSP have been and continue to be appealed by BP and/or

the claimants. Claims under appeal will ultimately only be resolved once the full judicial appeals process has been concluded, including appeals

to the Federal District Court and Fifth Circuit, as may be the case, or when settlements are reached with individual claimants. Depending upon

the ultimate resolution of these claims, the amounts payable may differ from those currently provided. Payments to resolve outstanding claims

under the PSC settlements are expected to be made over the next couple of years. The timing of payments, however, is uncertain, and, in

particular, will be impacted by how long it takes to resolve claims that have been appealed and may be appealed in the future.

194 BP Annual Report and Form 20-F 2019

24. Pensions and other post-retirement benefits

Most group companies have pension plans, the forms and benefits of which vary with conditions and practices in the countries concerned.

Pension benefits may be provided through defined contribution plans (money purchase schemes) or defined benefit plans (final salary and

other types of schemes with committed pension benefit payments). For defined contribution plans, retirement benefits are determined by the

value of funds arising from contributions paid in respect of each employee. For defined benefit plans, retirement benefits are based on such

factors as an employee’s pensionable salary and length of service. Defined benefit plans may be funded or unfunded. The assets of funded

plans are generally held in separately administered trusts.

For information on significant estimates and judgements made in relation to accounting for these plans see Pensions and other post-retirement

benefits in Note 1.

The primary pension arrangement in the UK is a funded final salary pension plan under which retired employees draw the majority of their

benefit as an annuity. This pension plan is governed by a corporate trustee whose board is composed of four member-nominated directors, four

company-nominated directors, an independent director and an independent chairman nominated by the company. The trustee board is required

by law to act in the best interests of the plan participants and is responsible for setting certain policies, such as investment policies of the plan.

The UK plan is closed to new joiners but remains open to ongoing accrual for current members. New joiners in the UK are eligible for

membership of a defined contribution plan.

In the US, all pension benefits now accrue under a cash balance formula. Benefits previously accrued under final salary formulas are legally

protected. Retiring US employees typically take their pension benefit in the form of a lump sum payment upon retirement. The plan is funded

and its assets are overseen by a fiduciary Investment Committee. During 2019 the committee was composed of six BP employees appointed

by the president of BP Corporation North America Inc. (the appointing officer). A seventh BP employee was added to the committee on 1

January 2020. The Investment Committee is required by law to act in the best interests of the plan participants and is responsible for setting

certain policies, such as the investment policies of the plan. US employees are also eligible to participate in a defined contribution (401k)†plan in

which employee contributions are matched with company contributions. In the US, group companies also provide post-retirement healthcare

to retired employees and their dependants (and, in certain cases, life insurance coverage); the entitlement to these benefits is usually based on

the employee remaining in service until a specified age and completion of a minimum period of service.

In the Eurozone, there are defined benefit pension plans in Germany, France, the Netherlands and other countries. In Germany and France, the

majority of the pensions are unfunded, in line with market practice. In Germany, the group’s largest Eurozone plan, employees receive a

pension and also have a choice to supplement their core pension through salary sacrifice. For employees who joined since 2002, the core

pension benefit is a career average plan with retirement benefits based on such factors as an employee’s pensionable salary and length of

service. The returns on the notional contributions made by both the company and employees are based on the interest rate which is set out in

German tax law. Retired German employees take their pension benefit typically in the form of an annuity. The German plans are governed by

legal agreements between BP and the works council or between BP and the trade union.

The level of contributions to funded defined benefit plans is the amount needed to provide adequate funds to meet pension obligations as they

fall due. During 2019 the aggregate level of contributions was $349 million (2018 $610 million and 2017 $637 million). The aggregate level of

contributions in 2020 is expected to be approximately $550 million, and includes contributions in all countries that we expect to be required to

make contributions by law or under contractual agreements, as well as an allowance for discretionary funding.

For the primary UK plan there is a funding agreement between the group and the trustee. On an annual basis the latest funding position is

reviewed and a schedule of contributions is agreed covering the next five years. Contractually committed funding amounted to $1,276 million

at 31†December†2019, all of which relates to future service. This amount is included in the group’s committed cash flows relating to pensions

and other post-retirement benefit plans as set out in the table of contractual obligations on page 302.

The surplus relating to the primary UK pension plan is recognized on the balance sheet on the basis that the company is entitled to a refund of

any remaining assets once all members have left the plan.

Pension contributions in the US are determined by legislation and are supplemented by discretionary contributions. No contributions were

made into the primary US pension plan in 2019 and no statutory funding requirement is expected in the next 12 months.

The surplus relating to the primary US fund is recognized on the balance sheet on the basis that economic benefit can be gained from the

surplus through a reduction in future contributions.

There was no minimum funding requirement for the US plan, and no significant minimum funding requirements in other countries at

31†December†2019.

24. Pensions and other post-retirement benefits – continued

The obligation and cost of providing pensions and other post-retirement benefits is assessed annually using the projected unit credit method.

The date of the most recent actuarial review was 31†December†2019. The UK plans are subject to a formal actuarial valuation every three years;

valuations are required more frequently in many other countries. The most recent formal actuarial valuation of the UK pension plans was as at

31 December 2017. A valuation of the US plan and largest Eurozone plans are carried out annually.

The material financial assumptions used to estimate the benefit obligations of the various plans are set out below. The assumptions are

reviewed by management at the end of each year, and are used to evaluate the accrued benefit obligation at 31†December and pension

expense for the following year.

Financial assumptions used to determine benefit

obligation

UK US Eurozone

2019 2018 2017 2019 2018 2017 2019 2018 2017

Discount rate for plan liabilities 2.1 2.9 2.5 3.1 4.1 3.5 1.3 2.0 1.9

Rate of increase in salaries 3.4 3.8 4.1 3.9 3.9 4.1 3.1 3.1 3.0

Rate of increase for pensions in

payment

2.7 3.0 2.9 — — — 1.5 1.5 1.4

Rate of increase in deferred pensions 2.7 3.0 2.9 — — — 0.5 0.5 0.6

Inflation for plan liabilities 2.7 3.1 3.1 1.5 1.5 1.7 1.7 1.7 1.6

Financial assumptions used to determine benefit

expense

UK US Eurozone

2019 2018 2017 2019 2018 2017 2019 2018 2017

Discount rate for plan service cost 3.0 2.6 2.7 4.2 3.6 4.1 2.5 2.4 2.1

Discount rate for plan other finance

expense

2.9 2.5 2.7 4.1 3.5 3.9 2.0 1.9 1.7

Inflation for plan service cost 3.1 3.1 3.2 1.5 1.7 1.8 1.7 1.6 1.6

The discount rate assumptions are based on third-party AA corporate bond indices and for our largest plans in the UK, US and the Eurozone we

use yields that reflect the maturity profile of the expected benefit payments. The inflation rate assumptions for our UK and US plans are based

on the difference between the yields on index-linked and fixed-interest long-term government bonds. In other countries, including the

Eurozone, we use this approach, or advice from the local actuary depending on the information available. The inflation assumptions are used to

determine the rate of increase for pensions in payment and the rate of increase in deferred pensions where there is such an increase.

The assumptions for the rate of increase in salaries are based on the inflation assumption plus an allowance for expected long-term real salary

growth. These include an allowance for promotion-related salary growth, of up to 0.8% depending on country.

In addition to the financial assumptions, we regularly review the demographic and mortality assumptions. The mortality assumptions reflect

best practice in the countries in which we provide pensions, and have been chosen with regard to applicable published tables adjusted where

appropriate to reflect the experience of the group and an extrapolation of past longevity improvements into the future. BP’s most substantial

pension liabilities are in the UK, the US and the Eurozone where our mortality assumptions are as follows:

Years

Mortality assumptions UK US Eurozone

2019 2018 2017 2019 2018 2017 2019 2018 2017

Life expectancy at age 60 for a male

currently aged 60 27.3 27.4 27.4 24.9 25.1 25.1 25.7 25.6 25.1

Life expectancy at age 60 for a male

currently aged 40 28.9 28.9 29.0 26.7 26.9 26.8 28.3 28.1 27.6

Life expectancy at age 60 for a female

currently aged 60 28.7 28.8 28.8 28.0 28.5 28.4 29.1 29.0 29.0

Life expectancy at age 60 for a female

currently aged 40 30.5 30.6 30.5 29.7 30.1 30.0 31.2 31.2 31.4

Pension plan assets are generally held in trusts, the primary objective of which is to accumulate assets sufficient to meet the obligations of the

plans. The assets of the trusts are invested in a manner consistent with fiduciary obligations and principles that reflect current practices in

portfolio management.

A significant proportion of the assets are held in equities, which are expected to generate a higher level of return over the long term, with an

acceptable level of risk. In order to provide reasonable assurance that no single security or type of security has an unwarranted impact on the

total portfolio, the investment portfolios are highly diversified.

The trustee’s long-term investment objective for the primary UK plan as it matures is to invest in assets whose value changes in the same way

as the plan liabilities, in order to reduce the level of funding risk. To move towards this objective, the UK plan uses a liability driven investment

(LDI) approach for part of the portfolio, investing primarily in government bonds to achieve this matching effect for the most significant plan

liability assumptions of interest rate and inflation rate. This is partly funded by short-term sale and repurchase agreements, whereby the plan

borrows money using existing bonds as security and which will be bought back at a specified price at an agreed future date. The funds raised

are used to invest in further bonds to increase the proportion of assets which match the plan liabilities. The borrowings are shown separately in

the analysis of pension plan assets in the table below.

For the primary UK pension plan there is an agreement with the trustee to increase the proportion of assets with liability matching

characteristics over time primarily by reducing the proportion of plan assets held as equities and increasing the proportion held as bonds. There

is a similar agreement in place for the primary US plan. During 2019, the UK and the US plans switched 2% and nil of plan assets respectively

from equities to bonds (2018 12.5% and 10% respectively).

BP Annual Report and Form 20-F 2019 195

24. Pensions and other post-retirement benefits – continued

The current asset allocation policy for the major plans at 31†December†2019 was as follows:

UK US

Asset category % %

Total equity (including private equity) 28 40

Bonds/cash (including LDI) 65 60

Property/real estate 7 —

The amounts invested under the LDI programme by the primary UK pension plan as at 31†December†2019 were $4,804 million (2018 $4,197

million) of government-issued nominal bonds and $19,462 million (2018 $17,491 million) of index-linked bonds.

Some of the group’s pension plans in the Eurozone and other countries use derivative financial instruments as part of their asset mix to

manage the level of risk. The fair value of these instruments are included in other assets in the table below. The UK and US plans do not use

derivative financial instruments.

The group’s main pension plans do not invest directly in either securities or property/real estate of the company or of any subsidiary.

The fair values of the various categories of assets held by the defined benefit plans at 31†December are presented in the table below, including

the effects of derivative financial instruments. Movements in the fair value of plan assets during the year are shown in detail in the table on

page 197.

$ million

Eurozone Other Total

Fair value of pension plan assets

At 31 December 2019

Listed equities – developed markets 6,285 1,290 495 371 8,441

†††– emerging markets 1,096 124 61 64 1,345

Private equity

2,675 1,474 — 3 4,152

Government issued nominal bonds

4,884 2,100 959 572 8,515

Government issued index-linked bonds

19,462 — 100 — 19,562

Corporate bonds

6,132 2,304 569 256 9,261

Property

2,507 — 96 27 2,630

Cash 426 289 33 93 841

Other 98 74 30 26 228

Debt (repurchase agreements) used to fund liability driven investments (7,436) — — — (7,436)

36,129 7,655 2,343 1,412 47,539

At 31 December 2018

Listed equities – developed markets 5,191 1,238 413 306 7,148

†† – emerging markets 950 63 65 56 1,134

Private equity

2,792 1,495 — 4 4,291

Government issued nominal bonds

4,263 2,072 895 533 7,763

Government issued index-linked bonds

17,491 — 102 — 17,593

Corporate bonds

4,606 2,184 506 243 7,539

Property

2,311 6 57 25 2,399

Cash 376 73 42 83 574

Other 116 64 32 40 252

Debt (repurchase agreements) used to fund liability driven investments (6,011) — — — (6,011)

32,085 7,195 2,112 1,290 42,682

At 31 December 2017

Listed equities – developed markets 9,548 2,158 537 376 12,619

†† – emerging markets 2,220 220 83 53 2,576

Private equity

2,679 1,461 — — 4,140

Government issued nominal bonds

2,663 1,777 941 545 5,926

Government issued index-linked bonds

16,177 — 2 — 16,179

Corporate bonds

4,682 2,024 546 272 7,524

Property

2,211 6 71 30 2,318

Cash 390 80 21 98 589

Other 104 53 23 45 225

Debt (repurchase agreements) used to fund liability driven investments (5,583) — — — (5,583)

35,091 7,779 2,224 1,419 46,513

Bonds held by the UK pension plans are denominated in sterling. Property held by the UK pension plans is in the United Kingdom.

Bonds held by the US pension plans are denominated in US dollars.

Private equity is valued at fair value based on the most recent transaction price or third-party net asset, revenue or earnings based valuations that generally result in the use of significant

unobservable inputs.

Bonds held by pension plans are valued using quoted prices in active markets.

Properties are valued based on an analysis of recent market transactions supported by market knowledge derived from third-party professional valuers that generally result in the use of

significant unobservable inputs.

196 BP Annual Report and Form 20-F 2019

24. Pensions and other post-retirement benefits – continued

$ million

2019

UK US Eurozone Other Total

Analysis of the amount charged to profit or loss

Current service cost

227 263 81 38 609

Past service cost

2 — 5 (1) 6

Settlement

— (13) 8 — (5)

Operating charge relating to defined benefit plans 229 250 94 37 610

Payments to defined contribution plans 42 188 7 38 275

Total operating charge 271 438 101 75 885

Interest income on plan assets

(909) (285) (43) (46) (1,283)

Interest on plan liabilities 757 387 133 69 1,346

Other finance (income) expense (152) 102 90 23 63

Analysis of the amount recognized in other comprehensive income

Actual asset return less interest income on plan assets 2,945 1,079 220 97 4,341

Change in financial assumptions underlying the present value of the plan liabilities (2,294) (1,036) (748) (92) (4,170)

Change in demographic assumptions underlying the present value of the plan†liabilities 136 91 3 (4) 226

Experience gains and losses arising on the plan liabilities (57) (22) 6 4 (69)

Remeasurements recognized in other comprehensive income 730 112 (519) 5 328

Movements in benefit obligation during the year

Benefit obligation at 1†January 26,830 9,696 6,906 1,686 45,118

Exchange adjustments 942 — (142) 26 826

Operating charge relating to defined benefit plans 229 250 94 37 610

Interest cost 757 387 133 69 1,346

Contributions by plan participants

20 — 2 6 28

Benefit payments (funded plans)

(1,207) (830) (76) (75) (2,188)

Benefit payments (unfunded plans)

(6) (205) (273) (15) (499)

Reclassified as assets held for sale — (146) — — (146)

Disposals — — (30) — (30)

Remeasurements 2,215 967 739 92 4,013

Benefit obligation at 31 December

29,780 10,119 7,353 1,826 49,078

Movements in fair value of plan assets during the year

Fair value of plan assets at 1†January 32,085 7,195 2,112 1,290 42,682

Exchange adjustments 1,141 — (43) 24 1,122

Interest income on plan assets

909 285 43 46 1,283

Contributions by plan participants

20 — 2 6 28

Contributions by employers (funded plans) 236 4 85 24 349

Benefit payments (funded plans)

(1,207) (830) (76) (75) (2,188)

Reclassified as assets held for sale — (78) — — (78)

Remeasurements

2,945 1,079 220 97 4,341

Fair value of plan assets at 31 December

36,129 7,655 2,343 1,412 47,539

Surplus (deficit) at 31†December 6,349 (2,464) (5,010) (414) (1,539)

Represented by

Asset recognized 6,588 387 27 51 7,053

Liability recognized (239) (2,851) (5,037) (465) (8,592)

6,349 (2,464) (5,010) (414) (1,539)

The surplus (deficit) may be analysed between funded and unfunded plans as†follows

Funded 6,588 387 (136) (87) 6,752

Unfunded (239) (2,851) (4,874) (327) (8,291)

6,349 (2,464) (5,010) (414) (1,539)

The defined benefit obligation may be analysed between funded and unfunded plans as

follows

Funded (29,541) (7,268) (2,479) (1,499) (40,787)

Unfunded (239) (2,851) (4,874) (327) (8,291)

(29,780) (10,119) (7,353) (1,826) (49,078)

The costs of managing plan investments are offset against the investment return, the costs of administering pension plan benefits are generally included in current service cost and the

costs of administering other post-retirement benefit plans are included in the benefit obligation.

Past service costs and settlements in the Eurozone have arisen from restructuring programmes and represent charges for special termination benefits reflecting the increased liability arising

as a result of early retirements. Settlements in the US are the result of a buy-out transaction for the pensions of a group of low value annuitants.

Most of the contributions made by plan participants into UK pension plans were made under salary sacrifice.

The benefit payments amount shown above comprises $2,304 million benefits and $346 million settlements, plus $37 million of plan expenses incurred in the administration of the benefit.

The benefit obligation for the US is made up of $7,789 million for pension liabilities and $2,330 million for other post-retirement benefit liabilities (which are unfunded and are primarily retiree

medical liabilities). The benefit obligation for the Eurozone includes $4,567 million for pension liabilities in Germany which is largely unfunded.

The actual return on plan assets is made up of the sum of the interest income on plan assets and the remeasurement of plan assets as disclosed above.

The fair value of plan assets includes borrowings related to the LDI programme as described on page 196.

BP Annual Report and Form 20-F 2019 197

24. Pensions and other post-retirement benefits – continued

$ million

2018

UK US Eurozone Other Total

Analysis of the amount charged to profit or loss

Current service cost

295 299 84 43 721

Past service cost

15 — 9 4 28

Settlement

— — 17 — 17

Operating charge relating to defined benefit plans 310 299 110 47 766

Payments to defined contribution plans 38 178 5 40 261

Total operating charge 348 477 115 87 1,027

Interest income on plan assets

(868) (262) (44) (45) (1,219)

Interest on plan liabilities 774 369 136 67 1,346

Other finance (income) expense (94) 107 92 22 127

Analysis of the amount recognized in other comprehensive income

Actual asset return less interest income on plan assets (722) (256) (69) (36) (1,083)

Change in financial assumptions underlying the present value of the plan liabilities 1,770 945 14 65 2,794

Change in demographic assumptions underlying the present value of the plan liabilities 123 (9) (42) 7 79

Experience gains and losses arising on the plan liabilities 520 41 (43) 9 527

Remeasurements recognized in other comprehensive income 1,691 721 (140) 45 2,317

Movements in benefit obligation during the year

Benefit obligation at 1†January 31,513 10,820 7,275 1,873 51,481

Exchange adjustments (1,589) — (303) (113) (2,005)

Operating charge relating to defined benefit plans 310 299 110 47 766

Interest cost 774 369 136 67 1,346

Contributions by plan participants

21 — 2 7 30

Benefit payments (funded plans)

(1,780) (597) (84) (83) (2,544)

Benefit payments (unfunded plans)

(6) (218) (301) (17) (542)

Disposals — — — (14) (14)

Remeasurements (2,413) (977) 71 (81) (3,400)

Benefit obligation at 31 December

26,830 9,696 6,906 1,686 45,118

Movements in fair value of plan assets during the year

Fair value of plan assets at 1†January 35,091 7,779 2,224 1,419 46,513

Exchange adjustments (1,883) — (93) (73) (2,049)

Interest income on plan assets

868 262 44 45 1,219

Contributions by plan participants

21 — 2 7 30

Contributions by employers (funded plans) 490 7 88 25 610

Benefit payments (funded plans)

(1,780) (597) (84) (83) (2,544)

Disposals — — — (14) (14)

Remeasurements

(722) (256) (69) (36) (1,083)

Fair value of plan assets at 31†December

32,085 7,195 2,112 1,290 42,682

Surplus (deficit) at 31†December 5,255 (2,501) (4,794) (396) (2,436)

Represented by

Asset recognized 5,473 418 29 35 5,955

Liability recognized (218) (2,919) (4,823) (431) (8,391)

5,255 (2,501) (4,794) (396) (2,436)

The surplus (deficit) may be analysed between funded and unfunded plans as†follows

Funded 5,473 396 (152) (97) 5,620

Unfunded (218) (2,897) (4,642) (299) (8,056)

5,255 (2,501) (4,794) (396) (2,436)

The defined benefit obligation may be analysed between funded and unfunded plans as

follows

Funded (26,612) (6,799) (2,264) (1,387) (37,062)

Unfunded (218) (2,897) (4,642) (299) (8,056)

(26,830) (9,696) (6,906) (1,686) (45,118)

The costs of managing plan investments are offset against the investment return, the costs of administering pension plan benefits are generally included in current service cost and the

costs of administering other post-retirement benefit plans are included in the benefit obligation.

Past service costs and settlements have arisen from restructuring programmes and represent charges for special termination benefits representing the increased liability arising as a result

of early retirements mostly in the UK and Eurozone.

Most of the contributions made by plan participants into UK pension plans were made under salary sacrifice.

The benefit payments amount shown above comprises $3,046 million benefits and $2 million settlements, plus $38 million of plan expenses incurred in the administration of the benefit.

The benefit obligation for the US is made up of $7,290 million for pension liabilities and $2,406 million for other post-retirement benefit liabilities (which are unfunded and are primarily retiree

medical liabilities). The benefit obligation for the Eurozone includes $4,328 million for pension liabilities in Germany which is largely unfunded.

The actual return on plan assets is made up of the sum of the interest income on plan assets and the remeasurement of plan assets as disclosed above.

The fair value of plan assets includes borrowings related to the LDI programme as described on page 196.

198 BP Annual Report and Form 20-F 2019

24. Pensions and other post-retirement benefits – continued

$ million

2017

UK US Eurozone Other Total

Analysis of the amount charged to profit or loss

Current service cost

357 292 85 46 780

Past service cost

12 — 5 (1) 16

Settlement — — 13 — 13

Operating charge relating to defined benefit plans 369 292 103 45 809

Payments to defined contribution plans 31 191 7 38 267

Total operating charge 400 483 110 83 1,076

Interest income on plan assets

(845) (266) (37) (48) (1,196)

Interest on plan liabilities 831 393 121 71 1,416

Other finance (income) expense (14) 127 84 23 220

Analysis of the amount recognized in other comprehensive income

Actual asset return less interest income on plan assets 2,396 826 30 43 3,295

Change in financial assumptions underlying the present value of the plan liabilities (236) (514) 336 (47) (461)

Change in demographic assumptions underlying the present value of the plan liabilities 734 72 — (23) 783

Experience gains and losses arising on the plan liabilities 91 (40) (36) 14 29

Remeasurements recognized in other comprehensive income 2,985 344 330 (13) 3,646

The costs of managing plan investments are offset against the investment return, the costs of administering pension plan benefits are generally included in current service cost and the costs

of administering other post-retirement benefit plans are included in the benefit obligation.

Past service costs have arisen from restructuring programmes and represent a combination of credits as a result of the curtailment in the pension arrangements of a number of employees

mostly in the US and charges for special termination benefits representing the increased liability arising as a result of early retirements mostly in the UK and Eurozone.

Sensitivity analysis

The discount rate, inflation, salary growth and the mortality assumptions all have a significant effect on the amounts reported. A one-

percentage point change, in isolation, in certain assumptions as at 31†December†2019 for the group’s pensions and other post-retirement

benefit expense would have had the effects shown in the tables below. The effects shown for the expense in 2020 comprise the total of

current service cost and net finance income or expense.

$ million

One percentage point

UK US Eurozone

Increase Decrease Increase Decrease Increase Decrease

Discount rate

Effect on expense in 2020 (274) 227 (66) 58 (1) (11)

Effect on obligation at 31 December 2019 (4,729) 6,364 (1,191) 1,478 (1,060) 1,347

Inflation rate

Effect on expense in 2020 171 (134) 11 (9) 35 (27)

Effect on obligation at 31 December 2019 4,711 (3,890) 67 (54) 978 (824)

Salary growth

Effect on expense in 2020 42 (36) 13 (11) 7 (7)

Effect on obligation at 31 December 2019 604 (525) 80 (67) 93 (89)

The amounts presented reflect that the discount rate is used to determine the asset interest income as well as the interest cost on the obligation.

The amounts presented reflect the total impact of an inflation rate change on the assumptions for rate of increase in salaries, pensions in payment and deferred pensions.

$ million

One year increase

UK US Eurozone

Longevity

Effect on expense in 2020 31 6 9

Effect on obligation at 31 December 2019 1,140 147 306

Estimated future benefit payments and the weighted average duration of defined benefit obligations

The expected benefit payments, which reflect expected future service, as appropriate, but exclude plan expenses, up until 2029 and the

weighted average duration of the defined benefit obligations at 31†December†2019 are as follows:

$ million

Estimated future benefit payments UK US Eurozone Other Total

2020 1,065 743 333 104 2,245

2021 1,078 789 323 98 2,288

2022 1,098 711 319 101 2,229

2023 1,138 718 314 98 2,268

2024 1,151 699 300 99 2,249

2025-2029 5,895 3,277 1,438 489 11,099

Years

Weighted average duration 18.3 13.2 16.4 13.0

BP Annual Report and Form 20-F 2019 199

25. Cash and cash equivalents

$ million

2019 2018

Cash 6,462 6,148

Term bank deposits 10,296 13,105

Cash equivalents (excluding term bank deposits) 5,714 3,215

22,472 22,468

Cash and cash equivalents comprise cash in hand; current balances with banks and similar institutions; term deposits of three months or less

with banks and similar institutions; money market funds and commercial paper. The carrying amounts of cash and term bank deposits

approximate their fair values. Substantially all of the other cash equivalents are categorized within level 1 of the fair value hierarchy.

Cash and cash equivalents at 31†December†2019 includes $1,676 million (2018 $1,350 million) that is restricted. The restricted cash balances

include amounts required to cover initial margin on trading exchanges and certain cash balances which are subject to exchange controls.

The group holds $4,678 million (2018 $4,693 million) of cash and cash equivalents outside the UK and it is not expected that any significant tax

will arise on repatriation.

200 BP Annual Report and Form 20-F 2019

26. Finance debt

$ million

2019 2018

Current Non-current Total Current Non-current Total

Borrowings 10,487 57,237 67,724 9,329 55,803 65,132

As a result of the adoption of IFRS 16 ‘Leases’, leases that were previously classified as finance leases under IAS 17 are now presented as

‘Lease liabilities’ on the group balance sheet and therefore do not form part of finance debt. Comparative information for finance debt has been

amended to be on a consistent basis with amounts presented for 2019. See Note 1 and Note 27 for further information.

The main elements of current borrowings are the current portion of long-term borrowings that is due to be repaid in the next 12 months of

$8,166 million (2018 $7,175 million) and issued commercial paper of $2,279 million (2018 $2,040 million). Finance debt does not include accrued

interest, which is reported within other payables.

The following table shows the weighted-average interest rates achieved through a combination of borrowings and derivative financial

instruments entered into to manage interest rate and currency exposures.

Fixed rate debt Floating rate debt Total

Weighted

average

interest

rate

Weighted

average

time for

which rate

is fixed

Years

Amount

$ƒmillion

Weighted

average

interest

rate

Amount

$ƒmillion

Amount

$ƒmillion

2019

US dollar 4 5 25,634 3 41,871 67,505

Other currencies 6 10 183 7 36 219

25,817 41,907 67,724

2018

US dollar 4 4 17,264 4 47,461 64,725

Other currencies 5 5 323 8 84 407

17,587 47,545 65,132

Comparative information in the table above has been amended to exclude previously classified finance lease liabilities of $667 million from US

dollar and other currencies, primarily from fixed-rate debt. The calculation of the comparative weighted-average interest rate and time for which

rate is fixed is unchanged for US dollar fixed-rate debt and was previously 7% and 18 years respectively for other currencies fixed-rate debt.

Fair values

The estimated fair value of finance debt is shown in the table below together with the carrying amount as reflected in the balance sheet.

Long-term borrowings in the table below include the portion of debt that matures in the 12 months from 31†December†2019, whereas in the

group balance sheet the amount is reported within current finance debt.

The carrying amount of the group’s short-term borrowings, comprising mainly of commercial paper, approximates their fair value. The fair

values of the significant majority of the group’s long-term borrowings are determined using quoted prices in active markets, and so fall within

level 1 of the fair value hierarchy. Where quoted prices are not available, quoted prices for similar instruments in active markets are used and

such measurements are therefore categorized in level 2 of the fair value hierarchy.

$ million

2019 2018

Fair value

Carrying

amount Fair value

Carrying

amount

Short-term borrowings 2,321 2,321 2,153 2,153

Long-term borrowings 67,055 65,403 63,213 62,979

Total finance debt 69,376 67,724 65,366 65,132

27. Capital disclosures and net debt

The group defines capital as total equity. We maintain our financial framework to support the pursuit of value growth for shareholders, while

ensuring a secure financial base.

The group monitors capital on basis of gearing (previously termed 'net debt ratio'), that is, the ratio of net debt to net debt plus equity. 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 exchange and interest rate risks relating to finance debt for which hedge accounting is applied, less cash and cash equivalents.

Net debt and gearing are non-GAAP measures. 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 equity from shareholders. The derivatives are reported on the balance sheet within the headings

‘Derivative financial instruments’. All components of equity are included in the denominator of the calculation.

We aim to manage the gearing within a 20-30% band and maintain a significant liquidity buffer. At 31†December†2019, gearing was 31.1%

(2018 30.0%).

As a result of the adoption of IFRS 16 ‘Leases’ from 1 January 2019, leases that were previously classified as finance leases under IAS 17 are

now presented as ‘Lease liabilities’ on the group balance sheet and therefore do not form part of finance debt. Comparative information for

finance debt (previously also termed ‘gross debt’), net debt and gearing have been amended to be on a consistent basis with amounts

presented for 2019. The relevant amount for finance lease liabilities that has been excluded from comparative information for 2018 is $667

million. The previously disclosed amounts for finance debt and net debt for 2018 were $65,799 million and $44,144 million respectively. The

previously disclosed gearing for 2018 was 30.3%.

$ million

At 31 December 2019 2018

Finance debt 67,724 65,132

Less: fair value asset (liability) of hedges related to finance debt

(190) (813)

67,914 65,945

Less: cash and cash equivalents 22,472 22,468

Net debt 45,442 43,477

Equity 100,708 101,548

Gearing 31.1% 30.0%

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 $601

million (2018 liability of $827 million) are not included in the calculation of net debt shown above as hedge accounting was not applied for these instruments. The movement in the year is

attributable to a net cash out flow of $286 million (2018 net cash flow $nil) and fair value loss of $60 million (2018 fair value losses of $193 million).

Net debt including leases is shown in the table below.

$ million

At 31 December 2019 2018

Net debt 45,442 43,477

Lease liabilities 9,722 667

Net partner (receivable) payable for leases entered into on behalf of joint operations (158) —

Net debt including leases 55,006 44,144

An analysis of changes in liabilities arising from financing activities is provided below.

$ million

Finance

debt

Hedge-

accounted

derivatives Lease liabilities

Net partner

payable for

leases entered

into on behalf

of joint

operations

Total liabilities

arising from

financing

activities

At 1 January 2019 65,132 813 667 — 66,612

Adjustment on adoption of IFRS 16

— — 9,233 217 9,450

Exchange adjustments (62) — (4) 8 (58)

Net financing cash flow 1,671 2 (2,372) (14) (713)

Fair value (gains) losses 924 (1,104) — — (180)

New and remeasured leases/joint operation payables — — 2,614 82 2,696

Other movements 59 479 (416) (3) 119

At 31 December 2019 67,724 190 9,722 290 77,926

At 1 January 2018 62,574 175 656 — 63,405

Exchange adjustments (237) — (22) — (259)

Net financing cash flow 3,540 (360) (35) — 3,145

Fair value (gains) losses (856) 998 — — 142

New leases — — 74 — 74

Other movements 111 — (6) — 105

At 31 December 2018 65,132 813 667 — 66,612

See Note 1 for information on adoption of IFRS 16 'Leases'.

BP Annual Report and Form 20-F 2019 201

28. Leases

The group leases a number of assets as part of its activities. This primarily includes drilling rigs in the Upstream segment and retail service

stations, oil depots and storage tanks in the Downstream segment as well as office accommodation and vessel charters across the group. The

weighted-average remaining lease term for the total lease portfolio is around 9 years. Some leases will have payments that vary with market

interest or inflation rates. Certain leases contain residual value guarantees, which may be triggered in certain circumstances such as if market

values have significantly declined at the conclusion of the lease.

The table below shows the timing of the undiscounted cash outflows for the lease liabilities included on the balance sheet.

$ million

2019 2018

Undiscounted lease liability cash flows due:

Within 1 year 2,514 98

1 to 2 years 1,839 97

2 to 3 years 1,364 95

3 to 4 years 1,105 94

4 to 5 years 876 86

5 to 10 years 2,427 309

Over 10 years 1,174 571

11,299 1,350

Impact of discounting (1,577) (683)

Lease liabilities at 31 December 9,722 667

Of which – current 2,067 44

– non-current 7,655 623

Comparative information represents finance leases accounted for under IAS 17

The group may enter into lease arrangements a number of years before taking control of the underlying asset due to construction lead times or

to secure future operational requirements. The total undiscounted amount for future commitments for leases not yet commenced as at 31

December 2019 is $5,688 million. The majority of this future commitment relates to the floating LNG vessel to service the Greater Tortue

Ahmeyim project from 2022.

$ million

2019

Total cash outflow for amounts included in lease liabilities

2,709

Expense for variable payments not included in the lease liability 67

Short-term lease expense 331

Additions to right-of-use assets in the period 2,542

The cash outflows for amounts not included in lease liabilities approximate the income statement expense disclosed above

An analysis of right-of-use assets and depreciation is provided in Note 12. An analysis of lease interest expense is provided in Note 7.

202 BP Annual Report and Form 20-F 2019

29. Financial instruments and financial risk factors

The accounting classification of each category of financial instruments and their carrying amounts are set out below.

$ million

At 31 December 2019 Note

Measured at

amortized

cost

Mandatorily

measured at

fair value

through

profit or loss

Derivative

hedging

instruments

Totalƒcarrying

amount

Financial assets

Other investments 18 — 1,445 — 1,445

Loans 906 63 — 969

Trade and other receivables 20 24,271 — — 24,271

Derivative financial instruments 30 — 9,984 483 10,467

Cash and cash equivalents 25 18,183 4,289 — 22,472

Financial liabilities

Trade and other payables 22 (55,891) — — (55,891)

Derivative financial instruments 30 — (8,122) (676) (8,798)

Accruals (6,062) — — (6,062)

Lease liabilities 28 (9,722) — — (9,722)

Finance debt

26 (67,724) — — (67,724)

(96,039) 7,659 (193) (88,573)

29. Financial instruments and financial risk factors – continued

$ million

At 31 December 2018 Note

Measured at

amortized

cost

Mandatorily

measured at

fair value

through profit

or loss

Derivative

hedging

instruments

Total†carrying

amount

Financial assets

Other investments 18 — 1,563 — 1,563

Loans 839 124 — 963

Trade and other receivables 20 24,080 — — 24,080

Derivative financial instruments 30 — 8,564 427 8,991

Cash and cash equivalents 25 20,366 2,102 — 22,468

Financial liabilities

Trade and other payables 22 (56,790) — — (56,790)

Derivative financial instruments 30 — (7,685) (1,248) (8,933)

Accruals (5,201) — — (5,201)

Lease liabilities 28 (667) — — (667)

Finance debt

26 (65,132) — — (65,132)

(82,505) 4,668 (821) (78,658)

As a result of the adoption of IFRS 16 ‘Leases’, leases that were previously classified as finance leases under IAS 17 are now presented as ‘Lease liabilities’ on the group balance sheet and

therefore do not form part of finance debt. Comparative information for finance debt and lease liabilities have been amended to be on a consistent basis with amounts presented for 2019.

The previously disclosed amounts for finance debt for 2018 was $65,799 million.

The fair value of finance debt is shown in Note 26. For all other financial instruments within the scope of IFRS 9, the carrying amount is either

the fair value, or approximates the fair value.

Information on gains and losses on derivative financial assets and financial liabilities classified as measured at fair value through profit or loss is

provided in the derivative gains and losses section of Note 30. Fair value gains and losses related to other assets and liabilities classified as

measured at fair value through profit or loss totalled a net loss of $129 million. Dividend income of $20 million (2018 $8 million) from

investments in equity instruments classified as measured at fair value through profit or loss is presented within other income - see Note 7.

Interest income and expenses arising on financial instruments are disclosed in Note 7.

Financial risk factors

The group is exposed to a number of different financial risks arising from natural business exposures as well as its use of financial instruments

including market risks relating to commodity prices; foreign currency exchange rates and interest rates; credit risk; and liquidity risk.

The group financial risk committee (GFRC) advises the group chief financial officer (CFO) who oversees the management of these risks. The

GFRC is chaired by the CFO and consists of a group of senior managers including the group treasurer and the heads of the group finance, tax

and the integrated supply and trading functions. The purpose of the committee is to advise on financial risks and the appropriate financial risk

governance framework for the group. The committee provides assurance to the CFO and the group chief executive (GCE), and via the GCE to

the board, that the group’s financial risk-taking activity is governed by appropriate policies and procedures and that financial risks are identified,

measured and managed in accordance with group policies and group risk appetite.

The group’s trading activities in the oil, natural gas, LNG and power markets are managed within the integrated supply and trading

function.†Treasury holds foreign exchange and interest-rate products in the financial markets to hedge group exposures related to debt

issuance; the compliance, control, and risk management processes for these activities are managed within the treasury function.†All other

foreign exchange and interest rate activities within financial markets†are†performed within the integrated supply and trading function†and are

also underpinned by the compliance, control and risk management infrastructure common to the activities of BP’s integrated supply and

trading function.†All derivative activity is carried out by specialist teams that have the appropriate skills, experience and supervision. These

teams are subject to close financial and management control.

The integrated supply and trading function maintains formal governance processes that provide oversight of market risk, credit risk and

operational risk associated with trading activity. A policy and risk committee approves value-at-risk delegations, reviews incidents and validates

risk-related policies, methodologies and procedures. A commitments committee approves the trading of new products, instruments and

strategies and material commitments.

In addition, the integrated supply and trading function undertakes derivative activity for risk management purposes under a control framework

as described more fully below.

(a) Market risk

Market risk is the risk or uncertainty arising from possible market price movements and their impact on the future performance of a business.

The primary commodity price risks that the group is exposed to include oil, natural gas and power prices that could adversely affect the value

of the group’s financial assets, liabilities or expected future cash flows. The group enters into derivatives in a well-established entrepreneurial

trading operation. In addition, the group has developed a control framework aimed at managing the volatility inherent in certain of its natural

business exposures. In accordance with the control framework the group enters into various transactions using derivatives for risk

management purposes.

The major components of market risk are commodity price risk, foreign currency exchange risk and interest rate risk, each of which is

discussed below.

BP Annual Report and Form 20-F 2019 203

29. Financial instruments and financial risk factors – continued

(i) Commodity price risk

The group’s integrated, supply and trading function is responsible for delivering value across the overall crude, oil products, gas and power

supply chains. As such, it routinely enters into spot and term physical commodity contracts in addition to optimising physical storage, pipeline

and transportation capacity. These activities expose the group to commodity price risk which is managed by entering into oil and natural gas

swaps, options and futures.

The group measures market risk exposure arising from its trading positions in liquid periods using value-at-risk techniques based on Variance/

Covariance or Monte Carlo simulation models. These techniques make a statistical assessment of the market risk arising from possible future

changes in market prices over a one-day holding period within a 95% confidence level. The value-at-risk measure is supplemented by stress

testing and scenario analysis through simulating the financial impact of certain physical, economic and geo-political scenarios. Trading activity

occurring in liquid periods is subject to value-at-risk and other limits for each trading activity and the aggregate of all trading activity. The board

has delegated a limit of $100 million (2018 $100 million) value at risk in support of this trading activity. Alternative measures are used to monitor

exposures which are outside liquid periods and for which value-at-risk techniques are not appropriate.

(ii) Foreign currency exchange risk

Since BP has global operations, fluctuations in foreign currency exchange rates can have a significant effect on the group’s reported results and

future expenditure commitments. The effects of most exchange rate fluctuations are absorbed in business operating results through changing

cost competitiveness, lags in market adjustment to movements in rates and translation differences accounted for on specific transactions. For

this reason, the total effect of exchange rate fluctuations is not identifiable separately in the group’s reported results. The main underlying

economic currency of the group’s cash flows is the US dollar. This is because BP’s major product, oil, is priced internationally in US dollars. BP’s

foreign currency exchange management policy is to limit economic and material transactional exposures arising from currency movements

against the US dollar. The group co-ordinates the handling of foreign currency exchange risks centrally, by netting off naturally-occurring

opposite exposures wherever possible and then managing any material residual foreign currency exchange risks.

Most of the group’s borrowings are in US dollars or are hedged with respect to the US dollar. At 31†December†2019, the total foreign currency

borrowings not swapped into US dollars amounted to $219 million (2018 $407 million excludes leases).

The group manages the net residual foreign currency exposures by constantly reviewing the foreign currency economic value at risk and aims

to manage such risk to keep the 12-month foreign currency value at risk below $400 million. At no point over the past three years did the value

at risk exceed the maximum risk limit. A continuous assessment is made in respect to the group’s foreign currency exposures to capture

hedging requirements.

During the year, hedge accounting was applied to foreign currency exposure to highly probable forecast capital expenditure commitments. The

group fixes the US dollar cost of non-US dollar supplies by using currency forwards for the highly probable forecast capital expenditure; the

exposures are in sterling, euro, Australian dollar and Korean won. At 31†December†2019 the most significant open contracts in place were for

$106 million sterling (2018 $434 million sterling).

Where the group enters into foreign currency exchange contracts for entrepreneurial trading purposes the activity is controlled using trading

value-at-risk techniques as explained in (i) commodity price risk above.

(iii) Interest rate risk

BP is also exposed to interest rate risk from the possibility that changes in interest rates will affect future cash flows or the fair values of its

financial instruments, principally finance debt. While the group issues debt in a variety of currencies based on market opportunities, it uses

derivatives to swap the debt to a floating rate exposure, mainly to US dollar floating, but in certain defined circumstances maintains a US dollar

fixed rate exposure for a proportion of debt. The proportion of floating rate debt net of interest rate swaps at 31†December†2019 was 62% of

total finance debt outstanding (2018 73% excludes leases). The weighted average interest rate on finance debt at 31†December†2019 was 3%

(2018 4%) and the weighted average maturity of fixed rate debt was five years (2018 four years excludes leases).

The group’s earnings are sensitive to changes in interest rates on the floating rate element of the group’s finance debt. If the interest rates

applicable to floating rate instruments were to have changed by one percentage point on 1†January 2020, it is estimated that the group’s

finance costs for 2020 would change by approximately $419 million (2018 $475 million).

(b) Credit risk

Credit risk is the risk that a customer or counterparty to a financial instrument will fail to perform or fail to pay amounts due causing financial

loss to the group and arises from cash and cash equivalents, derivative financial instruments and deposits with financial institutions and

principally from credit exposures to customers relating to outstanding receivables. Credit exposure also exists in relation to guarantees issued

by group companies under which the outstanding exposure incremental to that recognized on the balance sheet at 31†December†2019 was

$692 million (2018 $696 million) in respect of liabilities of joint ventures and associates and $523 million (2018 $432 million) in respect of

liabilities of other third parties.

The group has a credit policy, approved by the CFO that is designed to ensure that consistent processes are in place throughout the group to

measure and control credit risk. Credit risk is considered as part of the risk-reward balance of doing business. On entering into any business

contract the extent to which the arrangement exposes the group to credit risk is considered. Key requirements of the policy include

segregation of credit approval authorities from any sales, marketing or trading teams authorized to incur credit risk; the establishment of credit

systems and processes to ensure that all counterparty exposure is rated and that all counterparty exposure and limits can be monitored and

reported; and the timely identification and reporting of any non-approved credit exposures and credit losses. While each segment is

responsible for its own credit risk management and reporting consistent with group policy, the treasury function holds group-wide credit risk

authority and oversight responsibility for exposure to banks and financial institutions.

204 BP Annual Report and Form 20-F 2019

29. Financial instruments and financial risk factors – continued

For the purposes of financial reporting the group calculates expected loss allowances based on the maximum contractual period over which

the group is exposed to credit risk. Lifetime expected credit losses are recognized for trade receivables and the credit risk associated with the

significant majority of financial assets measured at amortized cost is considered to be low. Since the tenor of substantially all of the group's in-

scope financial assets is less than 12 months there is no significant difference between the measurement of 12-month and lifetime expected

credit losses. Expected loss allowances for financial guarantee contracts are typically lower than their fair value less, where appropriate,

amortization. Financial assets are considered to be credit-impaired when there is reasonable and supportable evidence that one or more events

that have a detrimental impact on the estimated future cash flows of the financial asset have occurred. This includes observable data

concerning significant financial difficulty of the counterparty; a breach of contract; concession being granted to the counterparty for economic

or contractual reasons relating to the counterparty’s financial difficulty, that would not otherwise be considered; it becoming probable that the

counterparty will enter bankruptcy or other financial re-organization or an active market for the financial asset disappearing because of financial

difficulties. The group also applies a rebuttable presumption that an asset is credit-impaired when contractual payments are more than 30 days

past due. Where the group has no reasonable expectation of recovering a financial asset in its entirety or a portion thereof, for example where

all legal avenues for collection of amounts due have been exhausted, the financial asset (or relevant portion) is written off.

The measurement of expected credit losses is a function of the probability of default, loss given default (i.e. the magnitude of the loss after

recovery if there is a default) and the exposure at default (i.e. the asset's carrying amount). The group allocates a credit risk rating to exposures

based on data that is determined to be predictive of the risk of loss, including but not limited to external ratings. Probabilities of default derived

from historical, current and future-looking market data are assigned by credit risk rating with a loss given default based on historical experience

and relevant market and academic research applied by exposure type. Experienced credit judgement is applied to ensure probabilities of

default are reflective of the credit risk associated with the group's exposures. Credit enhancements that would reduce the group's credit

losses in the event of default are reflected in the calculation when they are considered integral to the related asset.

The maximum credit exposure associated with financial assets is equal to the carrying amount. The group does not aim to remove credit risk

entirely but expects to experience a certain level of credit losses. As at 31†December†2019, the group had in place credit enhancements

designed to mitigate approximately $7.0 billion (2018 $7.3 billion) of credit risk, of which substantially all relates to assets in the scope of IFRS

9's impairment requirements. Credit enhancements include standby and documentary letters of credit, bank guarantees, insurance and liens

which are typically taken out with financial institutions who have investment grade credit ratings, or are liens over assets held by the

counterparty of the related receivables. Reports are regularly prepared and presented to the GFRC that cover the group’s overall credit

exposure and expected loss trends, exposure by segment, and overall quality of the portfolio.

Management information used to monitor credit risk, which reflects the impact of credit enhancements, indicates that the risk profile of

financial assets which are subject to review for impairment under IFRS 9 is as set out below.

As at 31†December 2019 2018

AAA to AA- 16% 22%

A+ to A- 51% 41%

BBB+ to BBB- 13% 16%

BB+ to BB- 7% 8%

B+ to B- 11% 11%

CCC+ and below 2% 2%

Movements in the impairment provision for trade and other receivables are shown in Note 21.

Financial instruments subject to offsetting, enforceable master netting arrangements and similar agreements

The following table shows the amounts recognized for financial assets and liabilities which are subject to offsetting arrangements on a gross

basis, and the amounts offset in the balance sheet.

Amounts which cannot be offset under IFRS, but which could be settled net under the terms of master netting agreements if certain

conditions arise, and collateral received or pledged, are also presented in the table to show the total net exposure of the group.

$ million

Gross

amounts of

recognized

financial

assets

(liabilities)

Amounts

set off

Netƒamounts

presentedƒon

the balance

sheet

Related amounts not set off

in the balance sheet

NetƒamountAt 31 December 2019

Master

netting

arrangements

Cash

collateral

(received)

pledged

Derivative assets 13,191 (2,724) 10,467 (1,971) (206) 8,290

Derivative liabilities (11,445) 2,724 (8,721) 1,971 — (6,750)

Trade and other receivables 10,661 (5,211) 5,450 (961) (190) 4,299

Trade and other payables (10,266) 5,211 (5,055) 961 — (4,094)

At 31 December 2018

Derivative assets 11,502 (2,511) 8,991 (2,079) (299) 6,613

Derivative liabilities (11,337) 2,511 (8,826) 2,079 — (6,747)

Trade and other receivables 11,296 (5,390) 5,906 (1,020) (169) 4,717

Trade and other payables (10,797) 5,390 (5,407) 1,020 — (4,387)

BP Annual Report and Form 20-F 2019 205

29. Financial instruments and financial risk factors – continued

Liquidity risk is the risk that suitable sources of funding for the group’s business activities may not be available. The group’s liquidity is

managed centrally with operating units forecasting their cash and currency requirements to the central treasury function. Unless restricted by

local regulations, generally subsidiaries pool their cash surpluses to the treasury function, which will then arrange to fund other subsidiaries’

requirements, or invest any net surplus in the market or arrange for necessary external borrowings, while managing the group’s overall net

currency positions.

The group benefits from open credit provided by suppliers who generally sell on five to 60-day payment terms in accordance with industry

norms. BP utilizes various arrangements in order to manage its working capital and reduce volatility in cash flow. This includes discounting of

receivables and, in the supply and trading business, managing inventory, collateral and supplier payment terms within a maximum of 60 days.

It is normal practice in the oil and gas supply and trading business for customers and suppliers to utilise letter of credit (LC) facilities to mitigate

credit and non-performance risk. Consequently, LCs facilitate active trading in a global market where credit and performance risk can be

significant. In common with the industry, BP routinely provides LCs to some of its suppliers.

The group has committed LC facilities totalling $12,175 million (2018 $12,175 million), allowing LCs to be issued for a maximum 24-month

duration. There were also uncommitted secured LC facilities in place at 31†December†2019 for $4,440 million (2018 $4,190 million), which are

secured against inventories or receivables when utilized. The facilities are held with over 20 international banks. The uncommitted secured LC

facilities can only be terminated by either party giving a stipulated termination notice to the other.

In certain circumstances, the supplier has the option to request accelerated payment from the LC provider in order to further reduce their

exposure. BP’s payments are made to the provider of the LC rather than the supplier according to the original contractual payment terms. At

31 December 2019, $4,755 million (2018 $3,705 million) of the group’s trade payables subject to these arrangements were payable to LC

providers, with no material exposure to any individual provider.

Standard†& Poor’s Ratings long-term credit rating for BP is A- (positive outlook) and Moody’s Investors Service rating is A1 (stable outlook).

During 2019, $8 billion (2018 $9 billion) of long-term taxable bonds were issued with terms ranging from one to thirty years. Commercial paper

is issued at competitive rates to meet short-term borrowing requirements as and when needed.

As a further liquidity measure, the group continues to maintain suitable levels of cash and cash equivalents, amounting to $22.5 billion at

31†December†2019 (2018 $22.5 billion), primarily invested with highly rated banks or money market funds and readily accessible at immediate

and short notice. At 31†December†2019, the group had substantial amounts of undrawn borrowing facilities available, consisting of $7,625

million (2018 $7,625 million) of standby facilities, all of which is available to draw and repay up to the first half of 2022. These facilities are with

25 international banks, and borrowings under them would be at pre-agreed rates. On 13

March the group entered into a committed $10,000

million credit facility which is available for two years at pre-agreed margins.

The table below shows the timing of cash outflows relating to finance debt, trade and other payables and accruals.

$†million

2019 2018

Tradeƒand

other

payables

Accruals

Finance

debt

Interest on

finance debt

Trade and

other

payables

Accruals

Finance

debt

Interest on

finance debt

Within one year 43,699 5,066 10,065 2,037 43,230 4,626 9,257 2,350

1 to 2 years 1,937 261 6,726 1,641 2,232 146 6,743 1,904

2 to 3 years 1,465 146 7,949 1,409 1,662 95 6,758 1,653

3 to 4 years 1,409 181 7,022 1,172 1,484 64 8,005 1,379

4 to 5 years 1,332 108 7,554 942 1,406 89 7,009 1,101

5 to 10 years 5,863 231 23,540 1,970 6,058 113 25,187 2,250

Over 10 years 3,957 69 2,497 249 5,001 68 983 9

59,662 6,062 65,353 9,420 61,073 5,201 63,942 10,646

2019 includes $16,129 million (2018 $18,360 million) in relation to the Gulf of Mexico oil spill, of which $14,501 million (2018 $16,058 million) matures in greater than one year.

As a result of the adoption of IFRS 16 ‘Leases’, leases that were previously classified as finance leases under IAS 17 are now presented as ‘Lease liabilities’ on the group balance sheet and

therefore do not form part of finance debt. Comparative information for finance debt and interest on finance debt has been amended to be on a consistent basis with amounts presented for

2019. $667 million and $683 million relating to finance lease liabilities have been excluded from the comparative information for finance debt and interest on finance debt respectively for

2018. The previously disclosed amounts for finance debt and interest on finance debt for 2018 was $64,608 million and $11,329 million respectively. The timing of cash outflows relating to

lease liabilities reported on the balance sheet are now shown in Note 28.

The group manages liquidity risk associated with derivative contracts, other than derivative hedging instruments, based on the expected

maturities of both derivative assets and liabilities as indicated in Note 30. Management does not currently anticipate any cash flows that could

be of a significantly different amount or could occur earlier than the expected maturity analysis provided.

206 BP Annual Report and Form 20-F 2019

29. Financial instruments and financial risk factors – continued

The table below shows the timing of cash outflows for derivative financial instruments entered into for the purpose of managing interest rate

and foreign currency exchange risk associated with finance debt, whether or not hedge accounting is applied, based upon contractual payment

dates. The amounts reflect the gross settlement amount where the pay leg of a derivative will be settled separately from the receive leg, as in

the case of cross-currency swaps hedging non-US dollar finance debt. The swaps are with high investment-grade counterparties and therefore

the settlement-day risk exposure is considered to be negligible. Not shown in the table are the gross settlement amounts (inflows) for the

receive leg of derivatives that are settled separately from the pay leg, which amount to $24,787 million at 31†December†2019 (2018 $22,453

million) to be received on the same day as the related cash outflows. For further information on our derivative financial instruments, see Note

30.

$ million

Cash outflows for derivative financial instruments at 31 December 2019 2018

Within one year 1,678 1,700

1 to 2 years 2,384 1,678

2 to 3 years 2,838 2,384

3 to 4 years 2,906 2,838

4 to 5 years 3,321 2,906

5 to 10 years 10,633 11,475

Over 10 years 2,224 724

25,984 23,705

BP Annual Report and Form 20-F 2019 207

30. Derivative financial instruments

In the normal course of business the group enters into derivative financial instruments (derivatives) to manage its normal business exposures

in relation to commodity prices, foreign currency exchange rates and interest rates, including management of the balance between floating

rate and fixed rate debt, consistent with risk management policies and objectives. An outline of the group’s financial risks and the objectives

and policies pursued in relation to those risks is set out in Note 29. Additionally, the group has a well-established entrepreneurial trading

operation that is undertaken in conjunction with these activities using a similar range of contracts.

For information on significant estimates and judgements made in relation to the valuation of derivatives see Derivative financial instruments

within Note 1.

The fair values of derivative financial instruments at 31†December are set out below.

Exchange traded derivatives are valued using closing prices provided by the exchange as at the balance sheet date. These derivatives are

categorized within level 1 of the fair value hierarchy. Exchange traded derivatives are typically considered settled through the (normally daily)

payment or receipt of variation margin.

Over-the-counter (OTC) financial swaps and physical commodity sale and purchase contracts are generally valued using readily available

information in the public markets and quotations provided by brokers and price index developers. These quotes are corroborated with market

data and are categorized within level 2 of the fair value hierarchy.

In certain less liquid markets, or for longer-term contracts, forward prices are not as readily available. In these circumstances, OTC financial

swaps and physical commodity sale and purchase contracts are valued using internally developed methodologies that consider historical

relationships between various commodities, and that result in management’s best estimate of fair value. These contracts are categorized

within level 3 of the fair value hierarchy.

30. Derivative financial instruments – continued

Financial OTC and physical commodity options are valued using industry standard models that consider various assumptions, including quoted

forward prices for commodities, time value, volatility factors, and contractual prices for the underlying instruments, as well as other relevant

economic factors. The degree to which these inputs are observable in the forward markets determines whether the option is categorized

within level 2 or level 3 of the fair value hierarchy.

$ million

2019 2018

Fair value

asset

Fair value

liability

Fair value

asset

Fair value

liability

Derivatives held for trading

Currency derivatives 81 (744) 69 (898)

Oil price derivatives 1,918 (1,478) 2,361 (1,849)

Natural gas price derivatives 6,569 (4,871) 4,787 (3,888)

Power price derivatives 1,306 (952) 1,240 (943)

Other derivatives 110 — 107 —

9,984 (8,045) 8,564 (7,578)

Embedded derivatives

Other embedded derivatives — (77) — (107)

— (77) — (107)

Cash flow hedges

Currency forwards 1 (4) 5 (14)

Gas price futures — — 2 —

1 (4) 7 (14)

Fair value hedges

Currency swaps 344 (637) 158 (789)

Interest rate swaps 138 (35) 262 (445)

482 (672) 420 (1,234)

10,467 (8,798) 8,991 (8,933)

Of which – current 4,153 (3,261) 3,846 (3,308)

– non-current 6,314 (5,537) 5,145 (5,625)

Derivatives held for trading

The group maintains active trading positions in a variety of derivatives. The contracts may be entered into for risk management purposes, to

satisfy supply requirements or for entrepreneurial trading. Certain contracts are classified as held for trading, regardless of their original

business objective, and are recognized at fair value with changes in fair value recognized in the income statement. Trading activities are

undertaken by using a range of contract types in combination to create incremental gains by arbitraging prices between markets, locations and

time periods. The net of these exposures is monitored using market value-at-risk techniques as described in Note 29.

The following tables show further information on the fair value of derivatives and other financial instruments held for trading purposes.

Derivative assets held for trading have the following fair values and maturities.

$ million

2019

Lessƒthan

1 year

1-2 years 2-3 years 3-4 years 4-5 years

Over

5ƒyears

Total

Currency derivatives 48 23 9 1 — — 81

Oil price derivatives 1,619 114 76 53 45 11 1,918

Natural gas price derivatives 1,889 824 615 489 433 2,319 6,569

Power price derivatives 556 269 146 94 67 174 1,306

Other derivatives 33 — — 77 — — 110

4,145 1,230 846 714 545 2,504 9,984

$†million

2018

Less than

1 year

1-2 years 2-3 years 3-4 years 4-5 years

Over

5†years

Total

Currency derivatives 48 12 9 — — — 69

Oil price derivatives 1,916 363 53 25 4 — 2,361

Natural gas price derivatives 1,333 708 542 452 352 1,400 4,787

Power price derivatives 540 276 158 79 55 132 1,240

Other derivatives — — — — 107 — 107

3,837 1,359 762 556 518 1,532 8,564

208 BP Annual Report and Form 20-F 2019

30. Derivative financial instruments – continued

Derivative liabilities held for trading have the following fair values and maturities.

$ million

2019

Less than

1 year

1-2 years 2-3 years 3-4 years 4-5 years

Over

5ƒyears

Total

Currency derivatives (166) (283) (201) (1) (23) (70) (744)

Oil price derivatives (1,405) (56) (14) (2) (1) — (1,478)

Natural gas price derivatives (1,070) (522) (446) (399) (363) (2,071) (4,871)

Power price derivatives (395) (165) (104) (76) (51) (161) (952)

(3,036) (1,026) (765) (478) (438) (2,302) (8,045)

$ million

2018

Less than

1 year

1-2 years 2-3 years 3-4 years 4-5 years

Over

5†years

Total

Currency derivatives (299) (71) (256) (171) (3) (98) (898)

Oil price derivatives (1,560) (232) (43) (12) (2) — (1,849)

Natural gas price derivatives (1,030) (557) (391) (338) (285) (1,287) (3,888)

Power price derivatives (401) (213) (95) (54) (47) (133) (943)

(3,290) (1,073) (785) (575) (337) (1,518) (7,578)

The following table shows the fair value of derivative assets and derivative liabilities held for trading, analysed by maturity period and by

methodology of fair value estimation. This information is presented on a gross basis, that is, before netting by counterparty.

$ million

2019

Less than

1 year

1-2 years 2-3 years 3-4 years 4-5 years

Over

5ƒyears

Total

Fair value of derivative assets

Level 1 63 6 2 — 2 1 74

Level 2 5,344 1,014 439 210 120 42 7,169

Level 3 779 501 485 540 452 2,708 5,465

6,186 1,521 926 750 574 2,751 12,708

Less: netting by counterparty (2,041) (291) (80) (36) (29) (247) (2,724)

4,145 1,230 846 714 545 2,504 9,984

Fair value of derivative liabilities

Level 1 (49) (8) (4) (1) (2) (1) (65)

Level 2 (4,522) (932) (458) (146) (113) (101) (6,272)

Level 3 (506) (377) (383) (367) (352) (2,447) (4,432)

(5,077) (1,317) (845) (514) (467) (2,549) (10,769)

Less: netting by counterparty 2,041 291 80 36 29 247 2,724

(3,036) (1,026) (765) (478) (438) (2,302) (8,045)

Net fair value 1,109 204 81 236 107 202 1,939

$†million

2018

Less†than

1†year

1-2 years 2-3 years 3-4 years 4-5 years

Over

5†years

Total

Fair value of derivative assets

Level 1 111 14 3 — — — 128

Level 2 5,000 1,362 504 262 120 72 7,320

Level 3 491 385 353 331 427 1,640 3,627

5,602 1,761 860 593 547 1,712 11,075

Less: netting by counterparty (1,765) (402) (98) (37) (29) (180) (2,511)

3,837 1,359 762 556 518 1,532 8,564

Fair value of derivative liabilities

Level 1 (156) (11) (2) (2) — — (171)

Level 2 (4,562) (1,161) (576) (308) (67) (163) (6,837)

Level 3 (337) (303) (305) (302) (299) (1,535) (3,081)

(5,055) (1,475) (883) (612) (366) (1,698) (10,089)

Less: netting by counterparty 1,765 402 98 37 29 180 2,511

(3,290) (1,073) (785) (575) (337) (1,518) (7,578)

Net fair value 547 286 (23) (19) 181 14 986

BP Annual Report and Form 20-F 2019 209

30. Derivative financial instruments – continued

Level 3 derivatives

The following table shows the changes during the year in the net fair value of derivatives held for trading purposes within level 3 of the fair

value hierarchy.

$ million

Oil

price

Naturalƒgas

price

Power

price

Other Total

Fair value contracts at 1 January 2019 23 (13) (148) 107 (31)

Gains (losses) recognized in the income statement 128 82 244 2 456

Gains (losses) recognized in other comprehensive income — — (18) — (18)

Settlements (79) (21) (179) — (279)

Transfers out of level 3 (1) (20) (24) 1 (44)

Net fair value of contracts at 31 December 2019 71 28 (125) 110 84

Deferred day-one gains (losses) 949

Derivative asset (liability) 1,033

$ million

Oil

price

Natural gas

price

Power

price

Other Total

Fair value contracts at 1 January 2018 67 65 (226) 115 21

Gains (losses) recognized in the income statement 58 (26) 209 (8) 233

Settlements (107) (32) (97) — (236)

Transfers out of level 3 5 (20) (34) — (49)

Net fair value of contracts at 31 December 2018 23 (13) (148) 107 (31)

Deferred day-one gains (losses) 577

Derivative asset (liability) 546

The amount recognized in the income statement for the year relating to level 3 held-for-trading derivatives still held at 31†December†2019 was a

$250-million gain (2018 $123-million gain related to derivatives still held at 31†December†2018).

Derivative gains and losses

The group enters into derivative contracts including futures, options, swaps and certain forward sales and forward purchases contracts, relating

to both currency and commodity trading activities. Gains or losses arise on contracts entered into for risk management purposes, optimization

activity and entrepreneurial trading. They also arise on certain contracts that are for normal procurement or sales activity for the group but that

are required to be fair valued under accounting standards. These gains and losses are included within sales and other operating revenues in the

income statement. Also included within this line item are gains and losses on inventory held for trading purposes. The total amount relating to

all these items was a net gain of $2,153 million (2018 $2,504 million net gain and 2017 $1,983 million net gain). This number does not include

gains and losses on realized physical derivative contracts that have been reflected gross in the income statement within sales and purchases

or the change in value of transportation and storage contracts which are not recognized under IFRS, but does include the associated financially

settled contracts. The net amounts for actual gains and losses relating to these derivative contracts and all related items therefore differ

significantly from the amounts disclosed above.

The group also enters into derivative contracts relating to foreign currency risk management activities. Gains and losses on these contracts are

included within production and manufacturing expenses in the income statement. The change in the unrealized value of these contracts was a

net gain of $160 million (2018 $351 million net loss and 2017 $1,420 million net gain), however the gains and losses in each year are largely

offset by opposing net foreign exchange differences on retranslation of the associated non-US dollar debt. The net amounts for actual gains

and losses relating to these derivative contracts and all related items therefore differ significantly from the amounts disclosed above.

Cash flow hedges

(i) Foreign currency risk of highly probable forecast capital expenditure

At 31†December†2019, the group held currency forwards designated as hedging instruments in cash flow hedge relationships of highly

probable forecast non-US dollar capital expenditure. Note 29 outlines the group’s approach to foreign currency exchange risk management.

When the highly probable forecast capital expenditure designated as a hedged item occurs, a non-financial asset is recognized and is

presented within the fixed asset section of the balance sheet.

The group claims hedge accounting only for the spot value of the currency exposure in line with the strategy to fix the volatility in the spot

exchange rate element. The fair value on the instrument attributable to forward points and foreign currency basis spreads is taken immediately

to the income statement.

The group applies hedge accounting where there is an economic relationship between the hedged item and hedging instrument. The existence

of an economic relationship is determined at inception and prospectively by comparing the critical terms of the hedging instrument and those

of the hedged item. The group enters into hedging derivatives that match the currency and notional of the hedged items on a 1:1 hedge ratio

basis. The hedge ratio is determined by comparing the notional amount of the derivative with the notional designated on the forecast

transaction. The group determines the extent to which it hedges highly probable forecast capital expenditures on a project by project basis.

The group has identified the following sources of ineffectiveness, which are not expected to be material:

• counterparty's credit risk, the group mitigates counterparty credit risk by entering into derivative transactions with high credit quality

counterparties; and

• differences in settlement timing between the derivative and hedged items. The latter impacts the discount factor used in the calculation of

the hedge ineffectiveness. The group mitigates differences in timing between the derivatives and hedged items by applying a rolling strategy

and by hedging currency pairs from stable economies (i.e. sterling/US dollar, Euro/US dollar, Korean won/US dollar). The group's cash flow

hedge designations are highly effective as the sources of ineffectiveness identified are expected to result in minimal hedge ineffectiveness.

The group has not designated any net positions as hedged items in cash flow hedges of foreign currency risk.

210 BP Annual Report and Form 20-F 2019

30. Derivative financial instruments – continued

(ii) Commodity price risk of highly probable forecast sales

During the period the group held Henry Hub NYMEX futures designated as hedging instruments in cash flow hedge relationships of certain

highly probable forecast future sales. At 31 December 2019, these hedging instruments and highly probably forecast sales had been realised

and the corresponding amounts recognised in the cash flow hedge reserve were released to the income statement during the period.

The group is exposed to the variability in the gas price, but only applied hedge accounting to the risk of Henry Hub price movements for a

percentage of future gas sales from its BPX Energy business (previously known as US Lower 48 business).

The group applied hedge accounting in relation to these highly probable future sales where there was an economic relationship between the

hedged item and hedging instrument. The existence of an economic relationship was determined at inception and prospectively by comparing

the critical terms of the hedging instrument and those of the hedged item. The group entered into hedging derivatives that matched the

notional amounts of the hedged items on a 1:1 hedge ratio basis. The hedge ratio was determined by comparing the notional amount of the

derivative with the notional amount designated on the forecast transaction.

The hedge was highly effective due to the price index of the hedging instruments matching the price index of the hedged item. The group did

not designate any net positions as hedged items in cash flow hedges of commodity price risk.

The tables below summarize the change in the fair value of hedging instruments and the hedged item used to calculate ineffectiveness in the

period.

$ million

Change in fair

value of

hedging

instrument

used to

calculate

ineffectiveness

Change in fair

value of

hedged item

used to

calculate

ineffectiveness

Hedge

ineffectiveness

recognized in

profit or (loss)

At 31 December 2019

Cash flow hedges

Foreign exchange risk

Highly probable forecast capital expenditure (1) 1 —

Commodity price risk

Highly probable forecast sales (100) 100 —

At 31 December 2018

Cash flow hedges

Foreign exchange risk

Highly probable forecast capital expenditure (5) 5 —

Commodity price risk

Highly probable forecast sales (126) 126 —

The tables below summarize the carrying amount and nominal amount of the derivatives designated as hedging instruments in cash flow

hedge relationships.

Carrying amount of hedging

instrument

Nominal amounts of hedging

instrumentsAssets Liabilities

At 31 December 2019 $ million $ million $ million mmBtu

Cash flow hedges

Foreign exchange risk

Highly probable forecast capital expenditure 1 (4) 150

At 31 December 2018

Cash flow hedges

Foreign exchange risk

Highly probable forecast capital expenditure 5 (14) 386

Commodity price risk

Highly probable forecast sales 2 — 145

All hedging instruments are presented within derivative financial instruments on the group balance sheet.

Of the nominal amount of hedging instruments at 31 December relating to highly probably forecast capital expenditure $150 million (2018 $304

million) matures within 12 months and $nil (2018 $82 million) within one to two years. All of the hedging instruments relating to highly probable

forecast sales at 31 December 2018 matured in 2019.

BP Annual Report and Form 20-F 2019 211

30. Derivative financial instruments – continued

The table below summarizes the weighted average exchange rates and the weighted average sales price in relation to the derivatives

designated as hedging instruments in cash flow hedge relationships at 31 December.

Weighted average price/rate

2019 2018

At 31 December

Forecast

capital

expenditure

Forecast capital

expenditure Forecast sales

Sterling/US dollar 1.35 1.34

Euro/US dollar 1.11 1.14

Australian dollar/US dollar — 0.72

Norwegian krone/US dollar — 8.67

Korean won/US dollar 1,115.66 1,107.90

Henry Hub $/mmBtu 2.86

Fair value hedges

At 31†December†2019, the group held interest rate and cross-currency interest rate swap contracts as fair value hedges of the interest rate risk

and foreign currency risk arising from group fixed rate debt issuances. The interest rate swaps are used to convert US dollar denominated fixed

rate borrowings into floating rate debt. The cross-currency interest rate swaps are used to convert sterling, euro, Swiss franc, Canadian dollar

and Norwegian krone denominated fixed rate borrowings into US dollar floating rate debt. The group manages all risks derived from debt

issuance, such as credit risk, however, the group applies hedge accounting only to certain components of interest rate and foreign currency

risk in order to minimize hedge ineffectiveness. Note 29 outlines the group’s approach to interest rate and foreign currency exchange risk

management.

The interest rate and foreign currency exposures are identified and hedged on an instrument-by-instrument basis. For interest rate exposures,

the group designates as a fair value hedge the benchmark interest rate component only. This is an observable and reliably measurable

component of interest rate risk. For foreign currency exposures, the group excludes from the designation the foreign currency basis spread

component implicit in the cross-currency interest rate swaps. This is separately calculated at hedge designation, is recognized in other

comprehensive income over the life of the hedge and amortized to the income statement on a straight-line basis, in accordance with the

group’s policy on costs of hedging.

The group applies hedge accounting where there is an economic relationship between the hedged item and the hedging instrument. The

existence of an economic relationship is determined initially by comparing the critical terms of the hedging instrument and those of the hedged

item and it is prospectively assessed using linear regression analysis. The group issues fixed rate debt and enters into interest rate and cross-

currency interest rate swaps with critical terms that match those of the debt and on a 1:1 hedge ratio basis. The hedge ratio is determined by

comparing the notional amount of the derivative with the notional amount of the debt. The hedge relationship is designated for the full term

and notional value of the debt. Both the hedging instrument and the hedged item are expected to be held to maturity.

The group has identified the following sources of ineffectiveness, which are not expected to be material:

• derivative counterparty’s credit risk which is not offset by the hedged item. This risk is mitigated by entering into derivative transactions only

with high credit quality counterparties; and

• sensitivity to interest rate between the hedged item and the derivatives. This is driven by differences in payment frequencies between the

instrument and the bond.

The tables below summarize the change in the fair value of hedging instruments and the hedged item used to calculate ineffectiveness in the

period. The signage convention for changes in fair value presented in this table is consistent with that presented in Note 27.

$ million

Change in fair

value of

hedging

instrument

used to

calculate

ineffectiveness

Change in fair

value of

hedged item

used to

calculate

ineffectiveness

Hedge

ineffectiveness

recognized in

profit or (loss)At 31 December 2019

Fair value hedges

Interest rate risk on finance debt (764) 737 27

Interest rate and foreign currency risk on finance debt (336) 286 50

At 31 December 2018

Fair value hedges

Interest rate risk on finance debt (70) 69 (1)

Interest rate and foreign currency risk on finance debt 812 (809) 3

212 BP Annual Report and Form 20-F 2019

30. Derivative financial instruments – continued

The tables below summarize the carrying amount of the derivatives designated as hedging instruments in fair value hedge relationships at 31

December.

$ million

Carrying amount of hedging

instrument

Nominal

amounts of

hedging

instrumentsAt 31 December 2019 Assets Liabilities

Fair value hedges

Interest rate risk on finance debt 138 (35) 13,442

Interest rate and foreign currency risk on finance debt 344 (637) 21,296

At 31 December 2018

Fair value hedges

Interest rate risk on finance debt 262 (445) 24,513

Interest rate and foreign currency risk on finance debt 158 (789) 16,580

All hedging instruments are presented within derivative financial instruments on the group balance sheet. Ineffectiveness arising on fair value

hedges is included within the production and manufacturing expenses section of the income statement.

The tables below summarize the profile by tenor of the nominal amount of the derivatives designated as hedging instruments in fair value

hedge relationships at 31 December. The weighted average floating interest rate of these interest rate swaps and cross-currency interest rate

swaps was 2.36% (2018 3.04%) and 3.27% (2018 4.07%) respectively.

$ million

At 31 December 2019

Less than 1

year

1-2 years 2-3 years 3-4 years 4-5 years 5-10 years Over 10 years Total

Fair value hedges

Interest rate risk on finance debt 3,000 2,576 4,039 1,200 206 2,421 — 13,442

Interest rate and foreign currency

risk on finance debt

882 672 1,400 2,777 3,109 10,216 2,240 21,296

At 31 December 2018

Fair value hedges

Interest rate risk on finance debt 2,694 2,324 2,597 4,923 1,700 10,275 — 24,513

Interest rate and foreign currency

risk on finance debt

— 1,245 1,167 707 2,921 10,254 286 16,580

The tables below summarize the carrying amount, and the accumulated fair value adjustments included within the carrying amount, of the

hedged items designated in fair value hedge relationships at 31 December.

$ million

Carrying amount of hedged item

Accumulated fair value adjustment included in the

carrying amount of hedged items

At 31 December 2019 Assets Liabilities Assets Liabilities

Discontinued

hedges

Fair value hedges

Interest rate risk on finance debt — (13,441) — (100) (714)

Interest rate and foreign currency risk on finance debt — (21,240) — (525) —

At 31 December 2018

Fair value hedges

Interest rate risk on finance debt — (24,747) 175 — (360)

Interest rate and foreign currency risk on finance debt — (16,883) — (62) —

The hedged item for all fair value hedges is presented within finance debt on the group balance sheet.

BP Annual Report and Form 20-F 2019 213

30. Derivative financial instruments – continued

Movement in reserves related to hedge accounting

The table below provides a reconciliation of the cash flow hedge and costs of hedging reserves on a pre-tax basis by risk category. The signage

convention of this table is consistent with that presented in Note 32.

$ million

Cash flow hedge reserve

Costs of

hedging

reserve

Highly

probable

forecast capital

expenditure

Highly

probable

forecast sales

Purchase of

equity

Interest rate

and foreign

currency risk

on finance

debt Total

At 1 January 2019 (21) (6) (651) (223) (901)

Recognized in other comprehensive income

Cash flow hedges marked to market (3) (100) — — (103)

Cash flow hedges reclassified to the income statement - hedged

item affected profit or loss

— 106 — — 106

Costs of hedging marked to market — — — (4) (4)

Costs of hedging reclassified to the income statement — — — 57 57

(3) 6 — 53 56

Cash flow hedges transferred to the balance sheet 23 — — — 23

At 31 December 2019 (1) — (651) (170) (822)

$ million

Cash flow hedge reserve

Costs of

hedging reserve

Highly probable

forecast capital

expenditure

Highly probable

forecast sales

Purchase of

equity

Interest rate

and foreign

currency risk on

finance debt Total

At 31 December 2017 (10) — (651) — (661)

Adjustment on adoption of IFRS 9 — — — (37) (37)

At 1 January 2018 (10) — (651) (37) (698)

Recognized in other comprehensive income

Cash flow hedges marked to market (37) (126) — — (163)

Cash flow hedges reclassified to the income statement - hedged

item affected profit or loss

— 120 — — 120

Costs of hedging marked to market — — — (244) (244)

Costs of hedging reclassified to the income statement — — — 58 58

(37) (6) — (186) (229)

Cash flow hedges transferred to the balance sheet 26 — — — 26

At 31 December 2018 (21) (6) (651) (223) (901)

See Note 32 for further information on the cash flow hedge reserve relating to the purchase of equity

Substantially all of the cash flow hedge reserve balances and all of the amounts reclassified into profit or loss during the year relate to

continuing hedge relationships. Amounts deferred in the cash flow hedge reserve that have been reclassified to profit or loss are presented in

sales and other operating revenues in the income statement.

Costs of hedging relates to the foreign currency basis spreads of hedging instruments used to hedge the group's interest rate and foreign

currency risk on debt which is a time-period related item.

214 BP Annual Report and Form 20-F 2019

31. Called-up share capital

The allotted, called up and fully paid share capital at 31†December was as follows:

2019 2018 2017

Issued

thousand

$ million

thousand

$ million

thousand

$ million

8% cumulative first preference shares of £1 each

7,233 12 7,233 12 7,233 12

9% cumulative second preference shares of £1 each

5,473 9 5,473 9 5,473 9

21 21 21

Ordinary shares of 25 cents each

At 1†January 21,525,464 5,381 21,288,193 5,322 21,049,696 5,263

Issue of new shares for the scrip dividend programme 208,927 52 195,305 49 289,789 72

Issue of new shares for employee share-based

payment†plans 37,400 9 92,168 23 — —

Issue of new shares – other — — — — — —

Repurchase of ordinary share capital (235,951) (59) (50,202) (13) (51,292) (13)

At 31†December 21,535,840 5,383 21,525,464 5,381 21,288,193 5,322

5,404 5,402 5,343

The nominal amount of 8% cumulative first preference shares and 9% cumulative second preference shares that can be in issue at any time shall not exceed £10,000,000 for each class of

preference shares.

Voting on substantive resolutions tabled at a general meeting is on a poll. On a poll, shareholders present in person or by proxy have two votes

for every £5 in nominal amount of the first and second preference shares held and one vote for every ordinary share held. On a show-of-hands

vote on other resolutions (procedural matters) at a general meeting, shareholders present in person or by proxy have one vote each.

In the event of the winding up of the company, preference shareholders would be entitled to a sum equal to the capital paid up on the

preference shares, plus an amount in respect of accrued and unpaid dividends and a premium equal to the higher of (i)†10% of the capital paid

up on the preference shares and (ii)†the excess of the average market price of such shares on the London Stock Exchange during the previous

six months over par value.

During 2019 the company repurchased 236 million ordinary shares for a total consideration of $1,511 million, including transaction costs of $8

million, as part of the share repurchase programme announced on 31 October 2017. All shares purchased were for cancellation. The

repurchased shares represented 1.1% of ordinary share capital. A further 120 million of shares have been repurchased in January 2020 at a

total cost of $776 million. The number of shares in issue is reduced when shares are repurchased.

Treasury shares

2019 2018 2017

thousand

Nominalƒvalue

$ million

thousand

Nominal†value

$ million

thousand

Nominal†value

$†million

At 1†January 1,426,265 356 1,482,072 370 1,614,657 403

Purchases for settlement of employee share plans 1,118 — 757 — 4,423 1

Issue of new shares for employee share-based

payment†plans

37,400 9 92,168 23 — —

Shares re-issued for employee share-based payment

plans

(167,927) (42) (148,732) (37) (137,008) (34)

At 31†December 1,296,856 323 1,426,265 356 1,482,072 370

Of which – shares held in treasury by BP 1,163,077 290 1,264,732 316 1,472,343 368

– shares held in ESOP trusts 133,707 33 161,518 40 9,705 2

– shares held by BP’s US share plan

administrator

72 — 15 — 24 —

See Note 32 for definition of treasury shares.

Held in the form of ADSs to meet the requirements of employee share-based payment plans in the US.

For each year presented, the balance at 1†January represents the maximum number of shares held in treasury by BP during the year,

representing 5.9% (2018 6.9% and 2017 7.5%) of the called-up ordinary share capital of the company.

During 2019, the movement in shares held in treasury by BP represented less than 0.5% (2018 less than 1.0% and 2017 less than 0.5%) of the

ordinary share capital of the company.

BP Annual Report and Form 20-F 2019 215

32. Capital and reserves

capital

premium

account

Capital

redemption

reserve

Merger

reserve

Total

shareƒcapital

andƒcapital

reserves

At 31 December 2018 5,402 12,305 1,439 27,206 46,352

Adjustment on adoption of IFRS 16, net of tax — — — — —

At 1 January 2019 5,402 12,305 1,439 27,206 46,352

Profit (loss) for the year — — — — —

Items that may be reclassified subsequently to profit or loss

Currency translation differences (including reclassifications) — — — — —

Cash flow hedges and costs of hedging (including reclassifications) — — — — —

Share of items relating to equity-accounted entities, net of tax

— — — — —

Other — — — — —

Items that will not be reclassified to profit or loss

Remeasurements of the net pension and other post-retirement benefit liability or asset — — — — —

Cash flow hedges that will subsequently be transferred to the balance sheet — — — — —

Total comprehensive income — — — — —

Dividends 52 (52) — — —

Cash flow hedges transferred to the balance sheet, net of tax — — — — —

Repurchases of ordinary share capital (59) — 59 — —

Share-based payments, net of tax

9 164 — — 173

Share of equity-accounted entities’ changes in equity, net of tax — — — — —

Transactions involving non-controlling interests, net of tax

— — — — —

At 31 December 2019 5,404 12,417 1,498 27,206 46,525

At 31 December 2017 5,343 12,147 1,426 27,206 46,122

Adjustment on adoption of IFRS 9, net of tax — — — — —

At 1 January 2018 5,343 12,147 1,426 27,206 46,122

Profit (loss) for the year — — — — —

Items that may be reclassified subsequently to profit or loss

Currency translation differences (including reclassifications) — — — — —

Cash flow hedges and costs of hedging (including reclassifications) — — — — —

Share of items relating to equity-accounted entities, net of tax

— — — — —

Other — — — — —

Items that will not be reclassified to profit or loss

Remeasurements of the net pension and other post-retirement benefit liability or asset — — — — —

Cash flow hedges that will subsequently be transferred to the balance sheet — — — — —

Total comprehensive income — — — — —

Dividends 49 (49) — — —

Cash flow hedges transferred to the balance sheet, net of tax — — — — —

Repurchases of ordinary share capital (13) — 13 — —

Share-based payments, net of tax

23 207 — — 230

Share of equity-accounted entities’ changes in equity, net of tax — — — — —

Transactions involving non-controlling interests, net of tax — — — — —

At 31 December 2018 5,402 12,305 1,439 27,206 46,352

At 1 January 2017 5,284 12,219 1,413 27,206 46,122

Profit (loss) for the year — — — — —

Items that may be reclassified subsequently to profit or loss

Currency translation differences (including reclassifications) — — — — —

Available-for-sale investments (including reclassifications) — — — — —

Cash flow hedges (including reclassifications) — — — — —

Share of items relating to equity-accounted entities, net of tax

— — — — —

Other — — — — —

Items that will not be reclassified to profit or loss

Remeasurements of the net pension and other post-retirement benefit liability or asset — — — — —

Total comprehensive income — — — — —

Dividends 72 (72) — — —

Repurchases of ordinary share capital (13) — 13 — —

Share-based payments, net of tax

— — — — —

Share of equity-accounted entities’ changes in equity, net of tax — — — — —

Transactions involving non-controlling interests, net of tax

— — — — —

At 31 December 2017 5,343 12,147 1,426 27,206 46,122

Principally foreign exchange effects relating to the Russian rouble.

Movements in treasury shares relate to employee share-based payment plans.

216 BP Annual Report and Form 20-F 2019

32. Capital and reserves – continued

$ million

Treasury

Foreign

currency

translation

reserve

Available-

for-sale

investments

Cash flow

hedges

Costs of

hedging

Total

fair value

reserves

Profit and

loss

account

shareholders’

equity

Non-

controlling

interests Total equity

(15,767) (8,902) — (777) (210) (987) 78,748 99,444 2,104 101,548

— — — — — — (329) (329) (1) (330)

(15,767) (8,902) — (777) (210) (987) 78,419 99,115 2,103 101,218

— — — — — — 4,026 4,026 164 4,190

— 2,407 — — — — — 2,407 9 2,416

— — — 5 50 55 — 55 — 55

— — — — — — 82 82 — 82

— — — — — — (64) (64) — (64)

— — — — — — 171 171 — 171

— — — (3) — (3) — (3) — (3)

— 2,407 — 2 50 52 4,215 6,674 173 6,847

— — — — — — (6,929) (6,929) (213) (7,142)

— — — 23 — 23 — 23 — 23

— — — — — — (1,511) (1,511) — (1,511)

1,355 — — — — — (809) 719 — 719

— — — — — — 5 5 — 5

— — — — — — 316 316 233 549

(14,412) (6,495) — (752) (160) (912) 73,706 98,412 2,296 100,708

(16,958) (5,156) 17 (760) — (743) 75,226 98,491 1,913 100,404

— — (17) — (37) (54) (126) (180) — (180)

(16,958) (5,156) — (760) (37) (797) 75,100 98,311 1,913 100,224

— — — — — — 9,383 9,383 195 9,578

— (3,746) — — — — — (3,746) (41) (3,787)

— — — (6) (173) (179) — (179) — (179)

— — — — — — 417 417 — 417

— — — — — — 7 7 — 7

— — — — — — 1,599 1,599 — 1,599

— — — (37) — (37) — (37) — (37)

— (3,746) — (43) (173) (216) 11,406 7,444 154 7,598

— — — — — — (6,699) (6,699) (170) (6,869)

— — — 26 — 26 — 26 — 26

— — — — — — (355) (355) — (355)

1,191 — — — — — (718) 703 — 703

— — — — — — 14 14 — 14

— — — — — — — — 207 207

(15,767) (8,902) — (777) (210) (987) 78,748 99,444 2,104 101,548

(18,443) (6,878) 3 (1,156) — (1,153) 75,638 95,286 1,557 96,843

— — — — — — 3,389 3,389 79 3,468

— 1,722 — — — — (3) 1,719 52 1,771

— — 14 — — 14 — 14 — 14

— — — 396 — 396 — 396 — 396

— — — — — — 564 564 — 564

— — — — — — (72) (72) — (72)

— — — — — — 2,343 2,343 — 2,343

— 1,722 14 396 — 410 6,221 8,353 131 8,484

— — — — — — (6,153) (6,153) (141) (6,294)

— — — — — — (343) (343) — (343)

1,485 — — — — — (798) 687 — 687

— — — — — — 215 215 — 215

— — — — — — 446 446 366 812

(16,958) (5,156) 17 (760) — (743) 75,226 98,491 1,913 100,404

Principally relates to the sale of a 49% interest in BP's retail property portfolio in Australia.

Principally relates to the initial public offering of common units in BP Midstream Partners LP for which net proceeds of $811 million were received.

BP Annual Report and Form 20-F 2019 217

32. Capital and reserves – continued

Share capital

The balance on the share capital account represents the aggregate nominal value of all ordinary and preference shares in issue, including

treasury shares.

Share premium account

The balance on the share premium account represents the amounts received in excess of the nominal value of the ordinary and preference

shares.

Capital redemption reserve

The balance on the capital redemption reserve represents the aggregate nominal value of all the ordinary shares repurchased and cancelled.

Merger reserve

The balance on the merger reserve represents the fair value of the consideration given in excess of the nominal value of the ordinary shares

issued in an acquisition made by the issue of shares.

Treasury shares

Treasury shares represent BP shares repurchased and available for specific and limited purposes. For accounting purposes shares held in

Employee Share Ownership Plans (ESOPs) and BP’s US share plan administrator to meet the future requirements of the employee share-

based payment plans are treated in the same manner as treasury shares and are, therefore, included in the financial statements as treasury

shares. The ESOPs are funded by the group and have waived their rights to dividends in respect of such shares held for future awards. Until

such time as the shares held by the ESOPs vest unconditionally to employees, the amount paid for those shares is shown as a reduction in

shareholders’ equity. Assets and liabilities of the ESOPs are recognized as assets and liabilities of the group.

Foreign currency translation reserve

The foreign currency translation reserve records exchange differences arising from the translation of the financial statements of foreign

operations. Upon disposal of foreign operations, the related accumulated exchange differences are reclassified to the income statement.

Available-for-sale investments

This reserve recorded the changes in fair value of investments classified as available-for-sale under IAS 39 except for impairment losses,

foreign exchange gains or losses, or changes arising from revised estimates of future cash flows. On adoption of IFRS 9 the balance in this

reserve was transferred to the profit and loss account reserve. Under the new standard the group recognizes fair value gains and losses on

these investments in profit or loss.

Cash flow hedges

This reserve records the portion of the gain or loss on a hedging instrument in a cash flow hedge that is determined to be an effective hedge.

It includes $651 million relating to the acquisition of an 18.5% interest in Rosneft in 2013 which will only be reclassified to the income

statement if the investment in Rosneft is either sold or impaired. For further information on the accounting for cash flow hedges see Note 1 -

Derivative financial instruments and hedging activities.

Costs of hedging

This reserve records the change in fair value of the foreign currency basis spread of financial instruments to which cost of hedge accounting

has been applied. The accumulated amount relates to time-period related hedged items and is amortized to profit or loss over the term of the

hedging relationship.

Prior to the group’s adoption of IFRS 9 changes in the fair value of such foreign currency basis spreads were recognized in profit or loss. On

adoption of the new standard a transfer from the profit and loss account reserve to the costs of hedging reserve was made in order to reflect

the opening reserves position for relevant hedging instruments existing on transition. For further information on the accounting for costs of

hedging see Note 1 - Derivative financial instruments and hedging activities.

Profit and loss account

The balance held on this reserve is the accumulated retained profits of the group.

218 BP Annual Report and Form 20-F 2019

32. Capital and reserves – continued

The pre-tax amounts of each component of other comprehensive income, and the related amounts of tax, are shown in the table below.

$ million

2019

Pre-tax Tax Netƒofƒtax

Items that may be reclassified subsequently to profit or loss

Currency translation differences (including reclassifications) 2,418 (2) 2,416

Cash flow hedges (including reclassifications) 6 (1) 5

Costs of hedging (including reclassifications) 53 (3) 50

Share of items relating to equity-accounted entities, net of tax 82 — 82

Other — (64) (64)

Items that will not be reclassified to profit or loss

Remeasurements of the net pension and other post-retirement benefit liability or asset 328 (157) 171

Cash flow hedges that will subsequently be transferred to the balance sheet (3) — (3)

Other comprehensive income 2,884 (227) 2,657

$ million

2018

Pre-tax Tax Net of tax

Items that may be reclassified subsequently to profit or loss

Currency translation differences (including reclassifications) (3,771) (16) (3,787)

Cash flow hedges (including reclassifications) (6) — (6)

Costs of hedging (including reclassifications) (186) 13 (173)

Share of items relating to equity-accounted entities, net of tax 417 — 417

Other — 7 7

Items that will not be reclassified to profit or loss

Remeasurements of the net pension and other post-retirement benefit liability or asset 2,317 (718) 1,599

Cash flow hedges that will subsequently be transferred to the balance sheet (37) — (37)

Other comprehensive income (1,266) (714) (1,980)

$ million

2017

Pre-tax Tax Net of tax

Items that may be reclassified subsequently to profit or loss

Currency translation differences (including reclassifications) 1,866 (95) 1,771

Available-for-sale investments (including reclassifications) 14 — 14

Cash flow hedges (including reclassifications) 425 (29) 396

Share of items relating to equity-accounted entities, net of tax 564 — 564

Other — (72) (72)

Items that will not be reclassified to profit or loss

Remeasurements of the net pension and other post-retirement benefit liability or asset 3,646 (1,303) 2,343

Other comprehensive income 6,515 (1,499) 5,016

BP Annual Report and Form 20-F 2019 219

33. Contingent liabilities

There were contingent liabilities at 31†December†2019 in respect of guarantees and indemnities entered into as part of the ordinary course of

the group’s business. No material losses are likely to arise from such contingent liabilities. Further information on financial guarantees is

included in Note 29.

In the normal course of the group’s business, BP group entities are subject to legal and regulatory proceedings arising out of current and past

operations, including matters related to commercial disputes, product liability, antitrust, commodities trading, premises-liability claims,

consumer protection, general health, safety, climate change and environmental claims and allegations of exposures of third parties to toxic

substances, such as lead pigment in paint, asbestos and other chemicals. The amounts claimed could be significant and could be material to

the group’s results of operations, financial position or liquidity. While it is difficult to predict the ultimate outcome in some cases, BP expects

that the impact of current legal and regulatory proceedings on the group‘s results of operations, liquidity or financial position will not be

material.

The group files tax returns in many jurisdictions throughout the world. Various tax authorities are currently examining the group’s tax returns.

Tax returns contain matters that could be subject to differing interpretations of applicable tax laws and regulations including the tax

deductibility of certain intercompany charges. The resolution of tax positions through negotiations with relevant tax authorities, or through

litigation, can take several years to complete and the amounts could be significant and could, in aggregate, be material to the group’s results of

operations, financial position or liquidity. While it is difficult to predict the ultimate outcome in some cases, BP does not expect there to be any

material impact upon the group‘s results of operations, financial position or liquidity.

33. Contingent liabilities – continued

The group is subject to numerous national and local health, safety and environmental laws and regulations concerning its products, operations

and other activities. These laws and regulations may require the group to take future action to remediate the effects on the environment of

prior disposal or release of chemicals or petroleum substances by the group or other parties. Such contingencies may exist for various sites

including refineries, chemical plants, oil fields, commodities extraction sites, service stations, terminals and waste disposal sites. In addition,

the group may have obligations relating to prior asset sales or closed facilities. The ultimate requirement for remediation and its costs are

inherently difficult to estimate. However, the estimated cost of environmental obligations has been provided in these accounts in accordance

with the group‘s accounting policies. While the amounts of future possible costs that are not provided for could be significant and material to

the group‘s results of operations in the period in which they are recognized, it is not possible to estimate the amounts involved. BP does not

expect these costs to have a material impact on the group’s results of operations, financial position or liquidity.

If oil and natural gas production facilities and pipelines are sold to third parties and the subsequent owner is unable to meet their

decommissioning obligations it is possible that, in certain circumstances, BP could be partially or wholly responsible for decommissioning.

While the amounts associated with decommissioning provisions reverting to the group could be significant and could be material, BP is not

currently aware of any such cases that have a greater than remote chance of reverting to the group. Furthermore, as described in Provisions

and contingencies within Note 1, decommissioning provisions associated with downstream and petrochemical facilities are not generally

recognized as the potential obligations cannot be measured given their indeterminate settlement dates.

See also Legal proceedings on pages 319-320.

Contingent liabilities related to the Gulf of Mexico oil spill

For information on legal proceedings relating to the Deepwater Horizon oil spill, see Legal proceedings on pages 319-320. Any further

outstanding Deepwater Horizon related claims are not expected to have a material impact on the group's financial performance.

220 BP Annual Report and Form 20-F 2019

34. Remuneration of senior management and non-executive directors

Remuneration of directors

$†million

2019 2018 2017

Total for all directors

Emoluments 9 8 9

Amounts received under incentive schemes

20 16 9

Total 29 24 18

Excludes amounts relating to past directors.

Emoluments

These amounts comprise fees paid to the non-executive chairman and the non-executive directors and, for executive directors, salary and

benefits earned during the relevant financial year, plus cash bonuses awarded for the year.

Pension contributions

During 2019 one executive director participated in a UK final salary pension plan in respect of service prior to 1 April 2011. During 2019, one

executive director participated in retirement savings plans established for US employees and in a US defined benefit pension plan in respect of

service prior to 1 September 2016.

Further information

Full details of individual directors’ remuneration are given in the Directors’ remuneration report on page 100. See also Related-party

transactions on page 321.

Remuneration of directors and senior management

$†million

2019 2018 2017

Total for all senior management and non-executive directors

Short-term employee benefits 30 25 29

Pensions and other post-retirement benefits 2 2 2

Share-based payments 32 32 29

Total 64 59 60

Senior management comprises members of the executive team, see pages 78-79 for further information.

Short-term employee benefits

These amounts comprise fees and benefits paid to the non-executive chairman and non-executive directors, as well as salary, benefits and

cash bonuses for senior management. Deferred annual bonus awards, to be settled in shares, are included in share-based payments. Short

term employee benefits includes compensation for loss of office of $nil in 2019 (2018 $nil and 2017 $nil).

Pensions and other post-retirement benefits

The amounts represent the estimated cost to the group of providing pensions and other post-retirement benefits to senior management in

respect of the current year of service measured in accordance with IAS 19 ‘Employee Benefits’.

Share-based payments

This is the cost to the group of senior management’s participation in share-based payment plans, as measured by the fair value of options and

shares granted, accounted for in accordance with IFRS 2 ‘Share-based Payments’.

35. Employee costs and numbers

$ million

Employee costs 2019 2018 2017

Wages and salaries

7,497 7,931 7,572

Social security costs 733 743 711

Share-based payments

694 669 624

Pension and other post-retirement benefit costs 948 1,154 1,296

9,872 10,497 10,203

2019 2018 2017

Average number of employees

US Non-US Total US Non-US Total US Non-US Total

Upstream 5,800 11,000 16,800 5,900 11,500 17,400 6,200 12,200 18,400

Downstream

5,700 37,300 43,000 6,000 36,300 42,300 6,100 35,900 42,000

Other businesses and corporate

e†

2,100 10,600 12,700 1,900 12,100 14,000 1,900 12,400 14,300

13,600 58,900 72,500 13,800 59,900 73,700 14,200 60,500 74,700

Includes termination costs of $182 million (2018 $493 million and 2017 $189 million).

The group provides certain employees with shares and share options as part of their remuneration packages. The majority of these share-based payment arrangements are equity-settled.

Reported to the nearest 100.

Includes 18,100 (2018 17,100 and 2017 16,500) service station staff.

Includes 2,500 (2018 4,000 and 2017 4,700) agricultural, operational and seasonal workers in Brazil.

BP Annual Report and Form 20-F 2019 221

36. Auditor’s remuneration

$ million

Fees 2019 2018 2017

The audit of the company annual accounts

32 25 26

The audit of accounts of subsidiaries of the company 11 10 11

Total audit 43 35 37

Audit-related assurance services

4 4 7

Total audit and audit-related assurance services 47 39 44

Non-audit and other assurance services 1 2 3

Total non-audit or non-audit-related assurance services 1 2 3

Services relating to BP pension plans 1 1 —

49 42 47

Fees in respect of the audit of the accounts of BP p.l.c. including the group’s consolidated financial statements.

Includes interim reviews and audit of internal control over financial reporting and non-statutory audit services.

With effect from 2018, following a competitive tender process, Deloitte LLP (Deloitte) was appointed as auditor of the Company, replacing

Ernst & Young LLP (EY). In the table above, auditor’s remuneration for services provided during the years ended 31 December 2019 and 31

December 2018 thus relates to Deloitte and for the year ended 31 December 2017 EY.

2019 includes $3.6 million of additional fees for 2018. In addition to the amounts shown in the table above, in 2018 $0.75 million of additional

fees were paid to EY in respect of their audit for 2017. Auditor's remuneration is included in the income statement within distribution and

administration expenses.

Tax services (in relation to income tax, indirect tax compliance, employee tax services and tax advisory services) were $nil in all periods

presented.

The audit committee has established pre-approval policies and procedures for the engagement of Deloitte to render audit and certain

assurance and other services. The audit fees payable to Deloitte were considered as part of the audit tender process in 2016 and challenged by

the audit committee through comparison with the audit pricing proposals of the other bidding firms, before being approved. Deloitte performed

further assurance services that were not prohibited by regulatory or other professional requirements and were pre-approved by the

Committee. Deloitte is engaged for these services when its expertise and experience of BP are important. Most of this work is of an audit-

related or assurance nature.

Under SEC regulations, the remuneration of the auditor of $49 million (2018 $42 million and 2017 $47 million) is required to be presented as

follows: audit $43 million (2018 $35 million and 2017 $37 million); other audit-related $4 million (2018 $4 million and 2017 $7 million); tax $nil

(2018 $nil and 2017 $nil); and all other fees $3 million (2018 $3 million and 2017 $3 million).

37. Subsidiaries, joint arrangements and associates

The more important subsidiaries and associates of the group at 31†December†2019 and the group percentage of ordinary share capital (to

nearest whole number) are set out below. There are no individually significant incorporated joint arrangements. The group's share of the assets

and liabilities of the more important unincorporated joint arrangements are held by subsidiaries listed in the table below. Those subsidiaries

held directly by the parent company are marked with an asterisk (*), the percentage owned being that of the group unless otherwise indicated.

A complete list of undertakings of the group is included in Note 14 in the parent company financial statements of BP p.l.c. which are filed with

the Registrar of Companies in the UK, along with the group’s annual report.

Subsidiaries %

Country of

incorporation Principal activities

International

BP Corporate Holdings 100 England & Wales Investment holding

BP Exploration Operating Company 100 England & Wales Exploration and production

*BP Global Investments 100 England & Wales Investment holding

*BP International 100 England & Wales Integrated oil operations

BP Oil International 100 England & Wales Integrated oil operations

*Burmah Castrol 100 Scotland Lubricants

Angola

BP Exploration (Angola) 100 England & Wales Exploration and production

Azerbaijan

BP Exploration (Caspian Sea) 100 England & Wales Exploration and production

BP Exploration (Azerbaijan) 100 England & Wales Exploration and production

Canada

*BP Holdings Canada 100 England & Wales Investment holding

Egypt

BP Exploration (Delta) 100 England & Wales Exploration and production

Germany

BP Europa SE 100 Germany Refining and marketing

India

BP Exploration (Alpha) 100 England & Wales Exploration and production

Trinidad†& Tobago

BP Trinidad and Tobago 70 US Exploration and production

BP Capital Markets 100 England & Wales Finance

*BP Holdings North America 100 England & Wales Investment holding

Atlantic Richfield Company 100 US

Exploration and production, refining and

marketing

BP America 100 US

BP America Production Company 100 US

BP Company North America 100 US

BP Corporation North America 100 US

BP Exploration (Alaska) 100 US

BP Products North America 100 US

Standard Oil Company 100 US

BP Capital Markets America 100 US Finance

Associates %

Country of

incorporation Principal activities

Russia

Rosneft Oil Company 19.75 Russia Integrated oil operations

222 BP Annual Report and Form 20-F 2019

38. Condensed consolidating information on certain US subsidiaries

BP p.l.c. fully and unconditionally guarantees the payment obligations of its 100%-owned subsidiary BP Exploration (Alaska) Inc. under the BP

Prudhoe Bay Royalty Trust. As described in Note 2, in 2020 BP expects, subject to governmental authorizations, to complete the sale of all of

its Alaska operations, including its interest in BP Exploration (Alaska) Inc., to Hilcorp Energy. Following completion of the sale, BP will continue

to fully and unconditionally guarantee the payment obligations of BP Exploration (Alaska) Inc. to the BP Prudhoe Bay Royalty Trust. The

following financial information for BP p.l.c., BP Exploration (Alaska) Inc. and all other subsidiaries on a condensed consolidating basis is

intended to provide investors with meaningful and comparable financial information about BP p.l.c. and its subsidiary issuers of registered

securities and is provided pursuant to Rule 3-10 of Regulation S-X in lieu of the separate financial statements of each subsidiary issuer of public

debt securities. Non-current assets for BP p.l.c. includes investments in subsidiaries recorded under the equity method for the purposes of the

condensed consolidating financial information. Equity-accounted income of subsidiaries is the group’s share of profit related to such

investments. The eliminations and reclassifications column includes the necessary amounts to eliminate the intercompany balances and

transactions between BP p.l.c., BP Exploration (Alaska) Inc. and other subsidiaries. The financial information presented in the following tables

for BP Exploration (Alaska) Inc. incorporates subsidiaries of BP Exploration (Alaska) Inc. using the equity method of accounting and excludes

the BP group’s midstream operations in Alaska that are reported through different legal entities and that are included within the ‘other

subsidiaries’ column in these tables. BP p.l.c. also fully and unconditionally guarantees securities issued by BP Capital Markets p.l.c. and BP

Capital Markets America Inc. These companies are 100%-owned finance subsidiaries of BP p.l.c.

Income statement

$ million

2019

Issuer Guarantor

BP Exploration

(Alaska) Inc. BP p.l.c.

Other

subsidiaries

Eliminations

and

reclassifications BP group

Sales and other operating revenues 4,413 — 278,111 (4,127) 278,397

Earnings from joint ventures - after interest and tax — — 576 — 576

Earnings from associates - after interest and tax — — 2,681 — 2,681

Equity-accounted income of subsidiaries - after interest and tax — 5,916 — (5,916) —

Interest and other income 42 385 2,284 (1,942) 769

Gains on sale of businesses and fixed assets 4 — 189 — 193

Total revenues and other income 4,459 6,301 283,841 (11,985) 282,616

Purchases 2,361 — 211,438 (4,127) 209,672

Production and manufacturing expenses 907 — 20,908 — 21,815

Production and similar taxes 163 — 1,384 — 1,547

Depreciation, depletion and amortization 169 — 17,611 — 17,780

Impairment and losses on sale of businesses and fixed assets 747 — 7,328 — 8,075

Exploration expense — — 964 — 964

Distribution and administration expenses 75 803 10,333 (154) 11,057

Profit (loss) before interest and taxation 37 5,498 13,875 (7,704) 11,706

Finance costs 17 1,569 3,691 (1,788) 3,489

Net finance (income) expense relating to pensions and other post-

retirement benefits

— (153) 216 — 63

Profit (loss) before taxation 20 4,082 9,968 (5,916) 8,154

Taxation (40) 56 3,948 — 3,964

Profit (loss) for the year 60 4,026 6,020 (5,916) 4,190

Attributable to

BP shareholders 60 4,026 5,856 (5,916) 4,026

Non-controlling interests — — 164 — 164

60 4,026 6,020 (5,916) 4,190

BP Annual Report and Form 20-F 2019 223

38. Condensed consolidating information on certain US subsidiaries – continued

Income statement continued

$ million

2018

Issuer Guarantor

BP Exploration

(Alaska) Inc. BP p.l.c.

Other

subsidiaries

Eliminations and

reclassifications BP group

Sales and other operating revenues 4,315 — 298,620 (4,179) 298,756

Earnings from joint ventures - after interest and tax — — 897 — 897

Earnings from associates - after interest and tax — — 2,856 — 2,856

Equity-accounted income of subsidiaries - after interest and tax — 10,942 — (10,942) —

Interest and other income 42 373 2,081 (1,723) 773

Gains on sale of businesses and fixed assets — — 456 — 456

Total revenues and other income 4,357 11,315 304,910 (16,844) 303,738

Purchases 1,507 — 232,550 (4,179) 229,878

Production and manufacturing expenses 1,015 — 21,990 — 23,005

Production and similar taxes 282 — 1,254 — 1,536

Depreciation, depletion and amortization 377 — 15,080 — 15,457

Impairment and losses on sale of businesses and fixed assets 66 — 794 — 860

Exploration expense — — 1,445 — 1,445

Distribution and administration expenses 22 642 11,673 (158) 12,179

Profit (loss) before interest and taxation 1,088 10,673 20,124 (12,507) 19,378

Finance costs 8 1,326 2,759 (1,565) 2,528

Net finance (income) expense relating to pensions and other post-

retirement benefits

— (95) 222 — 127

Profit (loss) before taxation 1,080 9,442 17,143 (10,942) 16,723

Taxation 164 59 6,922 — 7,145

Profit (loss) for the year 916 9,383 10,221 (10,942) 9,578

Attributable to

BP shareholders 916 9,383 10,026 (10,942) 9,383

Non-controlling interests — — 195 — 195

916 9,383 10,221 (10,942) 9,578

Income statement continued

$ million

2017

Issuer Guarantor

BP Exploration

(Alaska) Inc.

BP p.l.c.

Other

subsidiaries

Eliminations and

reclassifications

BP group

Sales and other operating revenues 3,264 — 240,177 (3,233) 240,208

Earnings from joint ventures - after interest and tax — — 1,177 — 1,177

Earnings from associates - after interest and tax — — 1,330 — 1,330

Equity-accounted income of subsidiaries - after interest and tax — 4,436 — (4,436) —

Interest and other income 11 369 1,470 (1,193) 657

Gains on sale of businesses and fixed assets 71 9 1,139 (9) 1,210

Total revenues and other income 3,346 4,814 245,293 (8,871) 244,582

Purchases 1,010 — 181,939 (3,233) 179,716

Production and manufacturing expenses 1,156 — 23,073 — 24,229

Production and similar taxes

(18) — 1,793 — 1,775

Depreciation, depletion and amortization 735 — 14,849 — 15,584

Impairment and losses on sale of businesses and fixed assets — — 1,216 — 1,216

Exploration expense — — 2,080 — 2,080

Distribution and administration expenses 19 616 10,022 (149) 10,508

Profit (loss) before interest and taxation 444 4,198 10,321 (5,489) 9,474

Finance costs 6 826 2,286 (1,044) 2,074

Net finance (income) expense relating to pensions and other post-

retirement benefits

— (15) 235 — 220

Profit (loss) before taxation 438 3,387 7,800 (4,445) 7,180

Taxation (392) (11) 4,115 — 3,712

Profit (loss) for the year 830 3,398 3,685 (4,445) 3,468

Attributable to

BP shareholders 830 3,398 3,606 (4,445) 3,389

Non-controlling interests — — 79 — 79

830 3,398 3,685 (4,445) 3,468

Includes revised non-cash provision adjustments; actual cash payments for Production and similar taxes remain in line with prior year.

224 BP Annual Report and Form 20-F 2019

38. Condensed consolidating information on certain US subsidiaries – continued

Statement of comprehensive income

$ million

2019

Issuer Guarantor

BP Exploration

(Alaska) Inc. BP p.l.c.

Other

subsidiaries

Eliminations

and

reclassifications BP group

Profit (loss) for the year 60 4,026 6,020 (5,916) 4,190

Other comprehensive income

Items that may be reclassified subsequently to profit or loss

Currency translation differences — 200 1,338 — 1,538

Exchange (gains) or losses on translation of foreign operations

transferred to gain or loss on sale of businesses and fixed assets

— — 880 — 880

Cash flow hedges marked to market — — (100) — (100)

Cash flow hedges - recycled to the income statement — — 106 — 106

Costs of hedging market to market — — (4) — (4)

Costs of hedging reclassified to the income statement — — 57 — 57

Share of items relating to equity-accounted entities, net of tax — — 82 — 82

Income tax relating to items that may be reclassified — — (70) — (70)

— 200 2,289 — 2,489

Items that will not be reclassified to profit or loss

Remeasurements of the net pension and other post-retirement

benefit liability or asset

— 732 (404) — 328

Cash flow hedges that will subsequently be transferred to the

balance sheet

— — (3) — (3)

Income tax relating to items that will not be reclassified — (331) 174 — (157)

— 401 (233) — 168

Other comprehensive income — 601 2,056 — 2,657

Equity-accounted other comprehensive income of subsidiaries — 2,047 — (2,047) —

Total comprehensive income 60 6,674 8,076 (7,963) 6,847

Attributable to

BP shareholders 60 6,674 7,903 (7,963) 6,674

Non-controlling interests — — 173 — 173

60 6,674 8,076 (7,963) 6,847

Statement of comprehensive income continued

$ million

2018

Issuer Guarantor

BP Exploration

(Alaska) Inc. BP p.l.c.

Other

subsidiaries

Eliminations and

reclassifications BP group

Profit (loss) for the year 916 9,383 10,221 (10,942) 9,578

Other comprehensive income

Items that may be reclassified subsequently to profit or loss

Currency translation differences — (296) (3,475) — (3,771)

Cash flow hedges (including reclassifications) — — (6) — (6)

Costs of hedging (including reclassifications) — — (186) — (186)

Share of items relating to equity-accounted entities, net of tax — — 417 — 417

Income tax relating to items that may be reclassified — — 4 — 4

— (296) (3,246) — (3,542)

Items that will not be reclassified to profit or loss

Remeasurements of the net pension and other post-retirement

benefit liability or asset

— 1,689 628 — 2,317

Cash flow hedges that will subsequently be transferred to the

balance sheet

— — (37) — (37)

Income tax relating to items that will not be reclassified — (511) (207) — (718)

— 1,178 384 — 1,562

Other comprehensive income — 882 (2,862) — (1,980)

Equity-accounted other comprehensive income of subsidiaries — (2,821) — 2,821 —

Total comprehensive income 916 7,444 7,359 (8,121) 7,598

Attributable to

BP shareholders 916 7,444 7,205 (8,121) 7,444

Non-controlling interests — — 154 — 154

916 7,444 7,359 (8,121) 7,598

BP Annual Report and Form 20-F 2019 225

38. Condensed consolidating information on certain US subsidiaries – continued

Statement of comprehensive income continued

$ million

2017

Issuer Guarantor

BP Exploration

(Alaska) Inc. BP p.l.c.

Other

subsidiaries

Eliminations and

reclassifications BP group

Profit (loss) for the year 830 3,398 3,685 (4,445) 3,468

Other comprehensive income

Items that may be reclassified subsequently to profit or loss

Currency translation differences — 166 1,820 — 1,986

Exchange (gains) losses on translation of foreign operations

transferred to gain or loss on sale of businesses and fixed assets

— — (120) — (120)

Available-for-sale investments marked to market — — 14 — 14

Cash flow hedges marked to market — — 197 — 197

Cash flow hedges reclassified to the income statement — — 116 — 116

Cash flow hedges reclassified to the balance sheet — — 112 — 112

Share of items relating to equity-accounted entities, net of tax — — 564 — 564

Income tax relating to items that may be reclassified — — (196) — (196)

— 166 2,507 — 2,673

Items that will not be reclassified to profit or loss

Remeasurements of the net pension and other post-retirement

benefit liability or asset

— 2,984 662 — 3,646

Income tax relating to items that will not be reclassified — (1,169) (134) — (1,303)

— 1,815 528 — 2,343

Other comprehensive income — 1,981 3,035 — 5,016

Equity-accounted other comprehensive income of subsidiaries — 2,983 — (2,983) —

Total comprehensive income 830 8,362 6,720 (7,428) 8,484

Attributable to

BP shareholders 830 8,362 6,589 (7,428) 8,353

Non-controlling interests — — 131 — 131

830 8,362 6,720 (7,428) 8,484

226 BP Annual Report and Form 20-F 2019

38. Condensed consolidating information on certain US subsidiaries – continued

Balance sheet

$ million

2019

Issuer Guarantor

BP Exploration

(Alaska) Inc.

BP p.l.c.

Other

subsidiaries

Eliminations and

reclassifications

BP group

Non-current assets

Property, plant and equipment — — 132,642 — 132,642

Goodwill — — 11,868 — 11,868

Intangible assets — — 15,539 — 15,539

Investments in joint ventures — — 9,991 — 9,991

Investments in associates — 2 20,332 — 20,334

Other investments — — 1,276 — 1,276

Subsidiaries - equity-accounted basis — 167,895 — (167,895) —

Fixed assets — 167,897 191,648 (167,895) 191,650

Loans — — 32,524 (31,894) 630

Trade and other receivables — 2,771 2,147 (2,771) 2,147

Derivative financial instruments — — 6,314 — 6,314

Prepayments — — 781 — 781

Deferred tax assets — — 4,560 — 4,560

Defined benefit pension plan surpluses — 6,588 465 — 7,053

— 177,256 238,439 (202,560) 213,135

Current assets

Loans — — 339 — 339

Inventories 44 — 20,836 — 20,880

Trade and other receivables 690 135 42,157 (18,540) 24,442

Derivative financial instruments — — 4,153 — 4,153

Prepayments — — 857 — 857

Current tax receivable 45 — 1,237 — 1,282

Other investments — — 169 — 169

Cash and cash equivalents — — 22,472 — 22,472

779 135 92,220 (18,540) 74,594

Assets classified as held for sale 5,023 — 2,442 — 7,465

5,802 135 94,662 (18,540) 82,059

Total assets 5,802 177,391 333,101 (221,100) 295,194

Current liabilities

Trade and other payables 436 17,986 46,947 (18,540) 46,829

Derivative financial instruments — — 3,261 — 3,261

Accruals 347 21 4,698 — 5,066

Lease liabilities — — 2,067 — 2,067

Finance debt — — 10,487 — 10,487

Current tax payable — — 2,039 — 2,039

Provisions — — 2,453 — 2,453

783 18,007 71,952 (18,540) 72,202

Liabilities directly associated with assets classified as held for sale 706 — 687 — 1,393

1,489 18,007 72,639 (18,540) 73,595

Non-current liabilities

Other payables — 31,927 15,364 (34,665) 12,626

Derivative financial instruments — — 5,537 — 5,537

Accruals — — 996 — 996

Lease liabilities — — 7,655 — 7,655

Finance debt — — 57,237 — 57,237

Deferred tax liabilities 456 2,293 7,001 — 9,750

Provisions 114 — 18,384 — 18,498

Defined benefit pension plan and other post-retirement benefit

plan deficits

— 202 8,390 — 8,592

570 34,422 120,564 (34,665) 120,891

Total liabilities 2,059 52,429 193,203 (53,205) 194,486

Net assets 3,743 124,962 139,898 (167,895) 100,708

Equity

BP shareholders’ equity 3,743 124,962 137,602 (167,895) 98,412

Non-controlling interests — — 2,296 — 2,296

3,743 124,962 139,898 (167,895) 100,708

BP Annual Report and Form 20-F 2019 227

38. Condensed consolidating information on certain US subsidiaries – continued

Balance sheet continued

$ million

2018

Issuer Guarantor

BP Exploration

(Alaska) Inc. BP p.l.c.

Other

subsidiaries

Eliminations and

reclassifications BP group

Non-current assets

Property, plant and equipment 4,445 — 130,816 — 135,261

Goodwill — — 12,204 — 12,204

Intangible assets 598 — 16,686 — 17,284

Investments in joint ventures — — 8,647 — 8,647

Investments in associates — 2 17,671 — 17,673

Other investments — — 1,341 — 1,341

Subsidiaries - equity-accounted basis — 166,311 — (166,311) —

Fixed assets 5,043 166,313 187,365 (166,311) 192,410

Loans — — 32,402 (31,765) 637

Trade and other receivables — 2,600 1,834 (2,600) 1,834

Derivative financial instruments — — 5,145 — 5,145

Prepayments — — 1,179 — 1,179

Deferred tax assets — — 3,706 — 3,706

Defined benefit pension plan surpluses — 5,473 482 — 5,955

5,043 174,386 232,113 (200,676) 210,866

Current assets

Loans — — 326 — 326

Inventories 302 — 17,686 — 17,988

Trade and other receivables 2,536 151 38,931 (17,140) 24,478

Derivative financial instruments — — 3,846 — 3,846

Prepayments 7 — 956 — 963

Current tax receivable — — 1,019 — 1,019

Other investments — — 222 — 222

Cash and cash equivalents — 13 22,455 — 22,468

2,845 164 85,441 (17,140) 71,310

Total assets 7,888 174,550 317,554 (217,816) 282,176

Current liabilities

Trade and other payables 413 14,634 48,358 (17,140) 46,265

Derivative financial instruments — — 3,308 — 3,308

Accruals 89 31 4,506 — 4,626

Lease liabilities — — 44 — 44

Finance debt — — 9,329 — 9,329

Current tax payable 310 — 1,791 — 2,101

Provisions 1 — 2,563 — 2,564

813 14,665 69,899 (17,140) 68,237

Non-current liabilities

Other payables — 31,800 16,395 (34,365) 13,830

Derivative financial instruments — — 5,625 — 5,625

Accruals — — 575 — 575

Lease liabilities — — 623 — 623

Finance debt — — 55,803 — 55,803

Deferred tax liabilities 586 1,907 7,319 — 9,812

Provisions 670 — 17,062 — 17,732

Defined benefit pension plan and other post-retirement benefit

plan deficits

— 184 8,207 — 8,391

1,256 33,891 111,609 (34,365) 112,391

Total liabilities 2,069 48,556 181,508 (51,505) 180,628

Net assets 5,819 125,994 136,046 (166,311) 101,548

Equity

BP shareholders’ equity 5,819 125,994 133,942 (166,311) 99,444

Non-controlling interests — — 2,104 — 2,104

5,819 125,994 136,046 (166,311) 101,548

228 BP Annual Report and Form 20-F 2019

38. Condensed consolidating information on certain US subsidiaries – continued

Cash flow statement

$ million

2019

Issuer Guarantor

BP Exploration

(Alaska) Inc. BP p.l.c.

Other

subsidiaries

Eliminations

and

reclassifications BP group

Operating activities

Profit (loss) before taxation 20 4,082 9,968 (5,916) 8,154

Adjustments to reconcile profit (loss) before taxation to net cash

provided by operating activities

Exploration expenditure written off — — 631 — 631

Depreciation, depletion and amortization 169 — 17,611 — 17,780

Impairment and (gain) loss on sale of businesses and fixed assets 743 — 7,139 — 7,882

Earnings from joint ventures and associates — — (3,257) — (3,257)

Dividends received from joint ventures and associates — — 1,962 — 1,962

Equity accounted income of subsidiaries - after interest and tax — (5,916) — 5,916 —

Dividends received from subsidiaries — 6,360 — (6,360) —

Interest receivable (1) — (2,228) 1,788 (441)

Interest received 1 12 2,191 (1,788) 416

Finance costs 17 — 5,260 (1,788) 3,489

Interest paid (6) — (4,652) 1,788 (2,870)

Net finance expense relating to pensions and other post-

retirement benefits

— (153) 216 — 63

Share-based payments — 739 (9) — 730

Net operating charge for pensions and other post-retirement

benefits, less contributions and benefit payments for unfunded

plans

— (10) (228) — (238)

Net charge for provisions, less payments 21 — (197) — (176)

(Increase) decrease in inventories (31) — (3,375) — (3,406)

(Increase) decrease in other current and non-current assets (132) (155) (2,048) — (2,335)

Increase (decrease) in other current and non-current liabilities 1,954 3,469 (2,600) — 2,823

Income taxes paid (444) (1) (4,992) — (5,437)

Net cash provided by (used in) operating activities 2,311 8,427 21,392 (6,360) 25,770

Investing activities

Expenditure on property, plant and equipment, intangible and other

assets

(173) — (15,245) — (15,418)

Acquisitions, net of cash acquired — — (3,562) — (3,562)

Investment in joint ventures — — (137) — (137)

Investment in associates — — (304) — (304)

Total cash capital expenditure (173) — (19,248) — (19,421)

Proceeds from disposals of fixed assets 19 — 481 — 500

Proceeds from disposals of businesses, net of cash disposed — — 1,701 — 1,701

Proceeds from loan repayments 21 — 225 — 246

Net cash provided by (used in) investing activities (133) — (16,841) — (16,974)

Financing activities

Repurchase of shares — (1,511) — — (1,511)

Lease liability payments (46) — (2,326) — (2,372)

Proceeds from long-term financing — — 8,597 — 8,597

Repayments of long-term financing — — (7,118) — (7,118)

Net increase (decrease) in short-term debt — — 180 — 180

Net increase (decrease) in non-controlling interests — — 566 — 566

Dividends paid

BP shareholders (2,132) (6,929) (4,245) 6,360 (6,946)

Non-controlling interests — — (213) — (213)

Net cash provided by (used in) financing activities (2,178) (8,440) (4,559) 6,360 (8,817)

Currency translation differences relating to cash and cash equivalents — — 25 — 25

Increase (decrease) in cash and cash equivalents — (13) 17 — 4

Cash and cash equivalents at beginning of year — 13 22,455 — 22,468

Cash and cash equivalents at end of year — — 22,472 — 22,472

BP Annual Report and Form 20-F 2019 229

38. Condensed consolidating information on certain US subsidiaries – continued

Cash flow statement continued

$ million

2018

Issuer Guarantor

BP Exploration

(Alaska) Inc. BP p.l.c.

Other

subsidiaries

Eliminations and

reclassifications BP group

Operating activities

Profit (loss) before taxation 1,080 9,442 17,143 (10,942) 16,723

Adjustments to reconcile profit (loss) before taxation to net cash

provided by operating activities

Exploration expenditure written off — — 1,085 — 1,085

Depreciation, depletion and amortization 377 — 15,080 — 15,457

Impairment and (gain) loss on sale of businesses and fixed assets 66 — 338 — 404

Earnings from joint ventures and associates — — (3,753) — (3,753)

Dividends received from joint ventures and associates — — 1,535 — 1,535

Equity accounted income of subsidiaries - after interest and tax — (10,942) — 10,942 —

Dividends received from subsidiaries — 3,490 — (3,490) —

Interest receivable (42) (215) (1,776) 1,565 (468)

Interest received 42 215 1,656 (1,565) 348

Finance costs 8 1,326 2,759 (1,565) 2,528

Interest paid (8) (1,326) (2,159) 1,565 (1,928)

Net finance expense relating to pensions and other post-

retirement benefits

— (95) 222 — 127

Share-based payments — 671 19 — 690

Net operating charge for pensions and other post-retirement

benefits, less contributions and benefit payments for unfunded

plans

— (183) (203) — (386)

Net charge for provisions, less payments 33 — 953 — 986

(Increase) decrease in inventories (62) — 734 — 672

(Increase) decrease in other current and non-current assets (72) 165 (951) (2,000) (2,858)

Increase (decrease) in other current and non-current liabilities (491) 4,509 (6,595) — (2,577)

Income taxes paid (133) — (5,579) — (5,712)

Net cash provided by operating activities 798 7,057 20,508 (5,490) 22,873

Investing activities

Expenditure on property, plant and equipment, intangible and other

assets

(273) — (16,434) — (16,707)

Acquisitions, net of cash acquired — — (6,986) — (6,986)

Investment in joint ventures — — (382) — (382)

Investment in associates — — (1,013) — (1,013)

Total cash capital expenditure (273) — (24,815) — (25,088)

Proceeds from disposals of fixed assets — — 940 — 940

Proceeds from disposals of businesses, net of cash disposed 1,475 — 436 — 1,911

Proceeds from loan repayments — — 666 — 666

Net cash provided by (used in) investing activities 1,202 — (22,773) — (21,571)

Financing activities

Repurchase of shares — (355) — — (355)

Lease liability payments — — (35) — (35)

Proceeds from long-term financing — — 9,038 — 9,038

Repayments of long-term financing — — (7,175) — (7,175)

Net increase (decrease) in short-term debt — — 1,317 — 1,317

Dividends paid

BP shareholders (2,000) (6,699) (3,490) 5,490 (6,699)

Non-controlling interests — — (170) — (170)

Net cash provided by (used in) financing activities (2,000) (7,054) (515) 5,490 (4,079)

Currency translation differences relating to cash and cash equivalents — — (330) — (330)

Increase (decrease) in cash and cash equivalents — 3 (3,110) — (3,107)

Cash and cash equivalents at beginning of year — 10 25,565 — 25,575

Cash and cash equivalents at end of year — 13 22,455 — 22,468

230 BP Annual Report and Form 20-F 2019

38. Condensed consolidating information on certain US subsidiaries – continued

Cash flow statement continued

$ million

2017

Issuer Guarantor

BP Exploration

(Alaska) Inc. BP p.l.c.

Other

subsidiaries

Eliminations and

reclassifications BP group

Operating activities

Profit (loss) before taxation 438 3,387 7,800 (4,445) 7,180

Adjustments to reconcile profit (loss) before taxation to net cash

provided by operating activities

Exploration expenditure written off — — 1,603 — 1,603

Depreciation, depletion and amortization 735 — 14,849 — 15,584

Impairment and (gain) loss on sale of businesses and fixed assets (71) (9) 77 9 6

Earnings from joint ventures and associates — — (2,507) — (2,507)

Dividends received from joint ventures and associates — — 1,253 — 1,253

Equity accounted income of subsidiaries - after interest and tax — (4,436) — 4,436 —

Dividends received from (paid to) subsidiaries — 3,183 — (3,183) —

Interest receivable (11) (220) (1,117) 1,044 (304)

Interest received 11 220 1,188 (1,044) 375

Finance costs 6 826 2,286 (1,044) 2,074

Interest paid (6) (826) (1,784) 1,044 (1,572)

Net finance expense relating to pensions and other post-

retirement benefits

— (15) 235 — 220

Share-based payments — 595 66 — 661

Net operating charge for pensions and other post-retirement

benefits, less contributions and benefit payments for unfunded

plans

— (145) (249) — (394)

Net charge for provisions, less payments (128) — 2,234 — 2,106

(Increase) decrease in inventories (25) — (823) — (848)

(Increase) decrease in other current and non-current assets 108 522 (5,478) — (4,848)

Increase (decrease) in other current and non-current liabilities (830) 3,374 (200) — 2,344

Income taxes paid — — (4,002) — (4,002)

Net cash provided by operating activities 227 6,456 15,431 (3,183) 18,931

Investing activities

Expenditure on property, plant and equipment, intangible and other

assets

(321) — (16,241) — (16,562)

Acquisitions, net of cash acquired — — (327) — (327)

Investment in joint ventures — — (50) — (50)

Investment in associates — — (901) — (901)

Total cash capital expenditure (321) — (17,519) — (17,840)

Proceeds from disposals of fixed assets 94 — 2,842 — 2,936

Proceeds from disposals of businesses, net of cash disposed — — 478 — 478

Proceeds from loan repayments — — 349 — 349

Net cash provided by (used in) investing activities (227) — (13,850) — (14,077)

Financing activities

Net issue (repurchase) of shares — (343) — — (343)

Lease liability payments — — (45) — (45)

Proceeds from long-term financing — — 8,712 — 8,712

Repayments of long-term financing — — (6,231) — (6,231)

Net increase (decrease) in short-term debt — — (158) — (158)

Net increase (decrease) in non-controlling interests — — 1,063 — 1,063

Dividends paid

BP shareholders — (6,153) (3,183) 3,183 (6,153)

Non-controlling interests — — (141) — (141)

Net cash provided by (used in) financing activities — (6,496) 17 3,183 (3,296)

Currency translation differences relating to cash and cash equivalents — — 544 — 544

Increase (decrease) in cash and cash equivalents — (40) 2,142 — 2,102

Cash and cash equivalents at beginning of year — 50 23,434 — 23,484

Cash and cash equivalents at end of year — 10 25,576 — 25,586

BP Annual Report and Form 20-F 2019 231

Supplementary information on oil and natural gas (unaudited)

The regional analysis presented below is on a continent basis, with separate disclosure for countries that contain 15% or more of the total

proved reserves (for subsidiaries plus equity-accounted entities), in accordance with SEC and FASB requirements.

Oil and gas reserves – certain definitions

Unless the context indicates otherwise, the following terms have the meanings shown below:

Proved oil and gas reserves

Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with

reasonable certainty to be economically producible – from a given date forward, from known reservoirs, and under existing economic

conditions, operating methods, and government regulations – prior to the time at which contracts providing the right to operate expire, unless

evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation.

The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project

within a reasonable time.

(i) The area of the reservoir considered as proved includes:

(A) The area identified by drilling and limited by fluid contacts, if any; and

(B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain

economically producible oil or gas on the basis of available geoscience and engineering data.

(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in

a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with

reasonable certainty.

(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an

associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience,

engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid

injection) are included in the proved classification when:

(A) Successful testing by a pilot project in an area of the reservoir with properties no more favourable than in the reservoir as a

whole, the operation of an installed programme in the reservoir or an analogous reservoir, or other evidence using reliable

technology establishes the reasonable certainty of the engineering analysis on which the project or programme was based; and

(B) The project has been approved for development by all necessary parties and entities, including governmental entities.

(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price

shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an

unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by

contractual arrangements, excluding escalations based upon future conditions.

Undeveloped oil and gas reserves

Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from

existing wells where a relatively major expenditure is required for recompletion.

(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of

production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility

at greater distances.

(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they

are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.

(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid

injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects

in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.

Developed oil and gas reserves

Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively

minor compared to the cost of a new well; and

(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means

not involving a well.

For details on BP’s proved reserves and production compliance and governance processes, see pages 308-313.

232 BP Annual Report and Form 20-F 2019

Oil and natural gas exploration and production activities

$ million

2019

Europe

North

America

South

America

Africa Asia Australasia Total

Rest of

Europe US

Rest of

North

America

Russia

Rest of

Asia

Subsidiaries

Capitalized costs at 31 December

a b

Gross capitalized costs

Proved properties 31,655 — 67,319 3,421 15,194 48,150 — 42,629 6,300 214,668

Unproved properties 425 — 3,106 2,547 3,262 3,495 — 1,865 606 15,306

32,080 — 70,425 5,968 18,456 51,645 — 44,494 6,906 229,974

Accumulated depreciation 18,481 — 35,379 409 9,922 35,572 — 22,481 3,924 126,168

Net capitalized costs 13,599 — 35,046 5,559 8,534 16,073 — 22,013 2,982 103,806

Costs incurred for the year ended 31 December

a b

Acquisition of properties

Proved 2 — 5 — — — — 188 — 195

Unproved 13 — 50 1 220 18 — — — 302

15 — 55 1 220 18 — 188 — 497

Exploration and appraisal costs

128 — 271 15 220 417 2 171 61 1,285

Development 717 — 4,047 33 737 2,530 — 2,614 137 10,815

Total costs 860 — 4,373 49 1,177 2,965 2 2,973 198 12,597

Results of operations for the year ended 31 December

Sales and other operating revenues

Third parties 229 — 1,780 274 1,620 2,736 2 1,588 1,142 9,371

Sales between businesses 2,345 — 10,785 1 142 2,815 — 7,596 554 24,238

2,574 — 12,565 275 1,762 5,551 2 9,184 1,696 33,609

Exploration expenditure 157 — 233 13 124 222 2 187 26 964

Production costs 607 — 2,742 118 437 1,045 — 961 131 6,041

Production taxes (75) — 315 — 293 — — 951 63 1,547

Other costs (income)

(308) — 2,527 67 92 33 42 (124) 153 2,482

Depreciation, depletion and amortization 1,383 — 4,456 118 1,056 3,806 2 2,384 297 13,502

Net impairments and (gains) losses on

sale of businesses and fixed assets

483 (10) 5,726 (1) 160 151 — 1 — 6,510

2,247 (10) 15,999 315 2,162 5,257 46 4,360 670 31,046

Profit (loss) before taxation

327 10 (3,434) (40) (400) 294 (44) 4,824 1,026 2,563

Allocable taxes (141) — (776) (76) (234) 593 (8) 3,078 392 2,828

Results of operations 468 10 (2,658) 36 (166) (299) (36) 1,746 634 (265)

Upstream and Rosneft segments replacement cost profit (loss) before interest and tax

Exploration and production activities –

subsidiaries (as above)

327 10 (3,434) (40) (400) 294 (44) 4,824 1,026 2,563

Midstream and other activities –

subsidiaries

749 (26) (363) 442 194 (19) 11 766 9 1,763

Equity-accounted entities

(6) 70 23 — 65 82 2,460 213 — 2,907

Total replacement cost profit (loss)

before interest and tax

1,070 54 (3,774) 402 (141) 357 2,427 5,803 1,035 7,233

These tables contain information relating to oil and natural gas exploration and production activities of subsidiaries, which includes our share of oil and natural gas exploration and production

activities of joint operations. They do not include any costs relating to the Gulf of Mexico oil spill. Amounts relating to the management and ownership of crude oil and natural gas pipelines,

LNG liquefaction and transportation operations are excluded. In addition, our midstream activities of marketing and trading of natural gas, power and NGLs in the US, Canada, UK, Asia and

Europe are excluded. The most significant midstream pipeline interests include the Trans-Alaska Pipeline System, the South Caucasus Pipeline and the Baku-Tbilisi-Ceyhan pipeline. Major

LNG activities are located in Trinidad, Indonesia, Australia and Angola.

Costs of decommissioning are included in capitalized costs at 31†December but are excluded from costs incurred for the year.

Includes exploration and appraisal drilling expenditures, which are capitalized within intangible assets, and geological and geophysical exploration costs, which are charged to income as

incurred.

Presented net of transportation costs, purchases and sales taxes.

Includes property taxes and other government take. The UK region includes a $361-million gain which is offset by corresponding charges primarily in the US region, relating to the group self-

insurance programme.

Excludes the unwinding of the discount on provisions and payables amounting to $439 million which is included in finance costs in the group income statement.

Midstream and other activities excludes inventory holding gains and losses.

The profits of equity-accounted entities are included after interest and tax.

BP Annual Report and Form 20-F 2019 233

Oil and natural gas exploration and production activities – continued

$ million

2019

Europe

North

America

South

America

Africa Asia Australasia Total

Rest of

Europe US

Rest of

North

America

Russia

Rest of

Asia

Equity-accounted entities (BPƒshare)

Capitalized costs at 31 December

b c

Gross capitalized costs

Proved properties — 4,078 — — 10,376 — 29,883 — — 44,337

Unproved properties — 768 — — 93 — 1,120 — — 1,981

— 4,846 — — 10,469 — 31,003 — — 46,318

Accumulated depreciation — 1,046 — — 5,078 — 9,248 — — 15,372

Net capitalized costs — 3,800 — — 5,391 — 21,755 — — 30,946

Costs incurred for the year ended 31 December

b d e

Acquisition of properties

Proved — — — — — — — — — —

Unproved — — — — — — 58 — — 58

— — — — — — 58 — — 58

Exploration and appraisal costs

— 120 — — 19 — 198 — — 337

Development — 640 — — 675 — 3,076 — — 4,391

Total costs — 760 — — 694 — 3,332 — — 4,786

Results of operations for the year ended 31 December

Sales and other operating revenues

Third parties — 1,002 — — 1,621 — — — — 2,623

Sales between businesses — — — — — — 15,979 — — 15,979

— 1,002 — — 1,621 — 15,979 — — 18,602

Exploration expenditure — 92 — — 43 — 73 — — 208

Production costs — 216 — — 465 — 1,535 — — 2,216

Production taxes — — — — 343 — 7,861 — — 8,204

Other costs (income) — 59 — — 16 — 358 — — 433

Depreciation, depletion and amortization — 323 — — 414 — 1,773 — — 2,510

Net impairments and losses on sale of

businesses and fixed assets

— — — — (42) — 49 — — 7

— 690 — — 1,239 — 11,649 — — 13,578

Profit (loss) before taxation — 312 — — 382 — 4,330 — — 5,024

Allocable taxes — 229 — — 245 — 848 — — 1,322

Results of operations — 83 — — 137 — 3,482 — — 3,702

Upstream and Rosneft segments replacement cost profit (loss) before interest and tax from equity-accounted entities

Exploration and production activities –

equity-accounted entities after tax (as

above)

— 83 — — 137 — 3,482 — — 3,702

Midstream and other activities after†tax

(6) (13) 23 — (72) 82 (1,022) 213 — (795)

Total replacement cost profit (loss) after

interest and tax

(6) 70 23 — 65 82 2,460 213 — 2,907

Amounts reported for Russia in this table include BP’s share of Rosneft’s worldwide activities, including insignificant amounts outside Russia. The amounts reported include the

corresponding amounts for their equity-accounted entities.

These tables contain information relating to oil and natural gas exploration and production activities of equity-accounted entities. Amounts relating to the management and ownership of

crude oil and natural gas pipelines, LNG liquefaction and transportation operations as well as downstream activities of Rosneft and Pan American Energy Group are excluded.

Costs of decommissioning are included in capitalized costs at 31†December but are excluded from costs incurred for the year.

Includes exploration and appraisal drilling expenditures, which are capitalized within intangible assets, and geological and geophysical exploration costs, which are charged to income as

incurred.

The amounts shown reflect BP’s share of equity-accounted entities’ costs incurred, and not the costs incurred by BP in acquiring an interest in equity-accounted entities.

Presented net of sales tax.

Includes interest and adjustment for non-controlling interests. Excludes inventory holding gains and losses.

234 BP Annual Report and Form 20-F 2019

Oil and natural gas exploration and production activities – continued

$ million

2018

Europe

North

America

South

America

Africa Asia Australasia Total

Rest of

Europe US

Rest of

North

America

Russia

Rest of

Asia

Subsidiaries

Capitalized costs at 31 December

a b

Gross capitalized costs

Proved properties 29,730 — 89,069 3,385 14,269 51,980 — 38,315 6,119 232,867

Unproved properties 451 — 3,602 2,667 2,742 3,870 — 3,153 568 17,053

30,181 — 92,671 6,052 17,011 55,850 — 41,468 6,687 249,920

Accumulated depreciation 16,809 — 47,051 420 8,517 38,324 — 20,173 3,626 134,920

Net capitalized costs 13,372 — 45,620 5,632 8,494 17,526 — 21,295 3,061 115,000

Costs incurred for the year ended 31 December

a b

Acquisition of properties

Proved 1,933 — 10,650 — — (1) — 36 — 12,618

Unproved — — 35 — 100 50 — (5) — 180

1,933 — 10,685 — 100 49 — 31 — 12,798

Exploration and appraisal costs

238 — 216 139 245 283 5 148 24 1,298

Development 817 — 3,429 46 591 2,340 — 2,458 236 9,917

Total costs 2,988 — 14,330 185 936 2,672 5 2,637 260 24,013

Results of operations for the year ended 31 December

Sales and other operating revenues

Third parties 619 — 1,306 105 2,074 3,228 — 1,430 1,410 10,172

Sales between businesses 2,255 — 11,656 1 195 3,928 — 7,793 665 26,493

2,874 — 12,962 106 2,269 7,156 — 9,223 2,075 36,665

Exploration expenditure 105 — 509 146 252 405 5 20 3 1,445

Production costs 646 — 2,729 120 430 1,066 — 951 138 6,080

Production taxes (269) — 369 — 357 — — 1,010 69 1,536

Other costs (income)

(331) (2) 2,379 43 165 133 42 94 223 2,746

Depreciation, depletion and amortization 1,199 — 3,921 101 1,023 3,635 — 2,165 298 12,342

Net impairments and (gains) losses on

sale of businesses and fixed†assets

(226) — 203 10 — (141) — 21 136 3

1,124 (2) 10,110 420 2,227 5,098 47 4,261 867 24,152

Profit (loss) before taxation

1,750 2 2,852 (314) 42 2,058 (47) 4,962 1,208 12,513

Allocable taxes

446 — 454 (95) 314 1,184 13 3,509 508 6,333

Results of operations 1,304 2 2,398 (219) (272) 874 (60) 1,453 700 6,180

Upstream and Rosneft segments replacement cost profit (loss) before interest and tax

Exploration and production activities –

subsidiaries (as above)

1,750 2 2,852 (314) 42 2,058 (47) 4,962 1,208 12,513

Midstream and other activities –

subsidiaries

(20) 265 188 (111) 135 (58) 5 463 6 873

Equity-accounted entities

i j

(2) 130 28 — 209 207 2,346 245 — 3,163

Total replacement cost profit (loss)

before interest and tax

1,728 397 3,068 (425) 386 2,207 2,304 5,670 1,214 16,549

These tables contain information relating to oil and natural gas exploration and production activities of subsidiaries, which includes our share of oil and natural gas exploration and production

activities of joint operations. They do not include any costs relating to the Gulf of Mexico oil spill. Amounts relating to the management and ownership of crude oil and natural gas pipelines,

LNG liquefaction and transportation operations are excluded. In addition, our midstream activities of marketing and trading of natural gas, power and NGLs in the US, Canada, UK, Asia and

Europe are excluded. The most significant midstream pipeline interests include the Trans-Alaska Pipeline System, the South Caucasus Pipeline and the Baku-Tbilisi-Ceyhan pipeline. Major

LNG activities are located in Trinidad, Indonesia, Australia and Angola.

Costs of decommissioning are included in capitalized costs at 31†December but are excluded from costs incurred for the year.

Includes exploration and appraisal drilling expenditures, which are capitalized within intangible assets, and geological and geophysical exploration costs, which are charged to income as

incurred.

Presented net of transportation costs, purchases and sales taxes.

Includes property taxes, other government take and the fair value gain on embedded derivatives of $17 million. The UK region includes a $384-million gain which is offset by corresponding

charges primarily in the US region, relating to the group self-insurance programme.

Excludes the unwinding of the discount on provisions and payables amounting to $208 million which is included in finance costs in the group income statement.

US region includes the deferred tax impact of the reduction in the US Federal corporate income tax rate from 35% to 21% enacted in December 2017.

Midstream and other activities excludes inventory holding gains and losses.

The profits of equity-accounted entities are included after interest and taxes.

From 16 December 2017, BP entered into a new 50:50 joint venture Pan American Energy Group (PAEG). Prior to this, Pan American Energy (PAE) was owned 60% by BP and 40% by Bridas

Corporation.

BP Annual Report and Form 20-F 2019 235

Oil and natural gas exploration and production activities – continued

$ million

2018

Europe

North

America

South

America

Africa Asia Australasia Total

Rest of

Europe US

Rest of

North

America

Russia

Rest of

Asia

Equity-accounted entities (BP share)

Capitalized costs at 31 December

b c

Gross capitalized costs

Proved properties — 3,439 — — 9,643 — 24,052 3,646 — 40,780

Unproved properties — 657 — — 86 — 828 26 — 1,597

— 4,096 — — 9,729 — 24,880 3,672 — 42,377

Accumulated depreciation — 670 — — 4,665 — 6,749 3,672 — 15,756

Net capitalized costs — 3,426 — — 5,064 — 18,131 — — 26,621

Costs incurred for the year ended 31 December

b d e

Acquisition of properties

Proved — — — — — — 425 — — 425

Unproved — 137 — — — — 148 — — 285

— 137 — — — — 573 — — 710

Exploration and appraisal costs

— 67 — — 25 — 207 — — 299

Development — 251 — — 575 — 3,255 212 — 4,293

Total costs — 455 — — 600 — 4,035 212 — 5,302

Results of operations for the year ended 31 December

Sales and other operating revenues

Third parties — 1,114 — — 1,792 — — 353 — 3,259

Sales between businesses — — — — — — 15,901 — — 15,901

— 1,114 — — 1,792 — 15,901 353 — 19,160

Exploration expenditure — 89 — — 7 — 112 — — 208

Production costs — 207 — — 438 — 1,487 39 — 2,171

Production taxes — — — — 361 — 7,634 94 — 8,089

Other costs (income) — 21 — — 55 — 638 — — 714

Depreciation, depletion and amortization — 290 — — 416 — 1,627 212 — 2,545

Net impairments and losses on sale of

businesses and fixed assets

— 6 — — — — 47 1 — 54

— 613 — — 1,277 — 11,545 346 — 13,781

Profit (loss) before taxation — 501 — — 515 — 4,356 7 — 5,379

Allocable taxes — 350 — — 321 — 849 — — 1,520

Results of operations

— 151 — — 194 — 3,507 7 — 3,859

Upstream and Rosneft segments replacement cost profit (loss) before interest and tax from equity-accounted entities

Exploration and production activities –

equity-accounted entities after tax (as

above)

— 151 — — 194 — 3,507 7 — 3,859

Midstream and other activities after tax

(2) (21) 28 — 15 207 (1,161) 238 — (696)

Total replacement cost profit (loss) after

interest and tax

(2) 130 28 — 209 207 2,346 245 — 3,163

Amounts reported for Russia in this table include BP’s share of Rosneft’s worldwide activities, including insignificant amounts outside Russia. The amounts reported include the

corresponding amounts for their equity-accounted entities.

These tables contain information relating to oil and natural gas exploration and production activities of equity-accounted entities. Amounts relating to the management and ownership of

crude oil and natural gas pipelines, LNG liquefaction and transportation operations as well as downstream activities of Rosneft and Pan American Energy Group are excluded.

Costs of decommissioning are included in capitalized costs at 31†December but are excluded from costs incurred for the year.

Includes exploration and appraisal drilling expenditures, which are capitalized within intangible assets, and geological and geophysical exploration costs, which are charged to income as

incurred.

The amounts shown reflect BP’s share of equity-accounted entities’ costs incurred, and not the costs incurred by BP in acquiring an interest in equity-accounted entities.

Presented net of sales taxes.

From 16 December 2017, BP entered into a new 50:50 joint venture Pan American Energy Group (PAEG). Prior to this, Pan American Energy (PAE) was owned 60% by BP and 40% by Bridas

Corporation.

Includes interest and adjustment for non-controlling interests. Excludes inventory holding gains and losses.

236 BP Annual Report and Form 20-F 2019

Oil and natural gas exploration and production activities – continued

$ million

2017

Europe

North

America

South

America

Africa Asia Australasia Total

Rest of

Europe US

Rest of

North

America

Russia

Rest of

Asia

Subsidiaries

Capitalized costs at 31 December

a b

Gross capitalized costs

Proved properties 34,208 — 83,449 3,518 13,581 49,795 — 35,519 5,984 226,054

Unproved properties 481 — 3,957 2,561 2,905 4,013 — 3,407 562 17,886

34,689 — 87,406 6,079 16,486 53,808 — 38,926 6,546 243,940

Accumulated depreciation 21,793 — 48,462 367 7,495 34,870 — 18,007 3,192 134,186

Net capitalized costs 12,896 — 38,944 5,712 8,991 18,938 — 20,919 3,354 109,754

Costs incurred for the year ended 31 December

a b

Acquisition of properties

Proved — — 22 — — 564 — 1,187 — 1,773

Unproved 13 — 13 — 330 374 — 228 — 958

13 — 35 — 330 938 — 1,415 — 2,731

Exploration and appraisal costs

336 — 102 52 264 682 11 190 18 1,655

Development 995 — 2,776 58 911 2,972 — 2,760 223 10,695

Total costs 1,344 — 2,913 110 1,505 4,592 11 4,365 241 15,081

Results of operations for the year ended 31 December

Sales and other operating revenues

Third parties 204 — 724 171 1,134 2,211 — 1,276 967 6,687

Sales between businesses 1,745 — 9,117 2 327 4,022 — 6,394 487 22,094

1,949 — 9,841 173 1,461 6,233 — 7,670 1,454 28,781

Exploration expenditure 331 — 282 39 83 1,346 11 (29) 17 2,080

Production costs 629 — 2,256 116 573 979 — 904 157 5,614

Production taxes (37) — 52 — 86 — — 1,618 56 1,775

Other costs (income)

(272) 2 1,655 34 71 280 39 311 349 2,469

Depreciation, depletion and amortization 1,190 — 4,258 96 742 3,586 — 2,147 366 12,385

Net impairments and (gains) losses on

sale of businesses and fixed assets

133 (12) 87 (1) (31) — — (10) 13 179

1,974 (10) 8,590 284 1,524 6,191 50 4,941 958 24,502

Profit (loss) before taxation

(25) 10 1,251 (111) (63) 42 (50) 2,729 496 4,279

Allocable taxes

(104) — (1,811) (28) 155 788 (19) 1,505 146 632

Results of operations 79 10 3,062 (83) (218) (746) (31) 1,224 350 3,647

Upstream and Rosneft segments replacement cost profit (loss) before interest and tax

Exploration and production activities –

subsidiaries (as above)

(25) 10 1,251 (111) (63) 42 (50) 2,729 496 4,279

Midstream and other activities –

subsidiaries

(185) 97 (176) (111) 140 (80) 3 315 11 14

Equity-accounted entities

— 71 25 — 381 205 837 245 — 1,764

Total replacement cost profit (loss)

before interest and tax

(210) 178 1,100 (222) 458 167 790 3,289 507 6,057

These tables contain information relating to oil and natural gas exploration and production activities of subsidiaries, which includes our share of oil and natural gas exploration and production

activities of joint operations. They do not include any costs relating to the Gulf of Mexico oil spill. Amounts relating to the management and ownership of crude oil and natural gas pipelines,

LNG liquefaction and transportation operations are excluded. In addition, our midstream activities of marketing and trading of natural gas, power and NGLs in the US, Canada, UK, Asia and

Europe are excluded. The most significant midstream pipeline interests include the Trans-Alaska Pipeline System, the South Caucasus Pipeline, the Forties Pipeline System and the Baku-

Tbilisi-Ceyhan pipeline. The Forties Pipeline System was divested on 31 October 2017. Major LNG activities are located in Trinidad, Indonesia, Australia and Angola.

Costs of decommissioning are included in capitalized costs at 31†December but are excluded from costs incurred for the year.

Includes exploration and appraisal drilling expenditures, which are capitalized within intangible assets, and geological and geophysical exploration costs, which are charged to income as

incurred.

Presented net of transportation costs, purchases and sales taxes.

Includes property taxes, other government take and the fair value gain on embedded derivatives of $32 million. The UK region includes a $343-million gain which is offset by corresponding

charges primarily in the US region, relating to the group self-insurance programme.

Excludes the unwinding of the discount on provisions and payables amounting to $120 million which is included in finance costs in the group income statement.

US region includes the deferred tax impact of the reduction in the US Federal corporate income tax rate from 35% to 21% enacted in December 2017.

Midstream and other activities excludes inventory holding gains and losses.

The profits of equity-accounted entities are included after interest and tax.

From 16 December 2017, BP entered into a new 50:50 joint venture Pan American Energy Group (PAEG). Prior to this, Pan American Energy (PAE) was owned 60% by BP and 40% by Bridas

Corporation. Of BP's initial 60% interest in PAE, 10% was classified as held for sale on 9 September 2017.†For September, only 9 days of income was reported for the full 60%.†After this

equity accounting continued for the 50% not classified as held for sale.†BP accounted for 50% of the enlarged entity from 16 December 2017.

BP Annual Report and Form 20-F 2019 237

Oil and natural gas exploration and production activities – continued

$ million

2017

Europe

North

America

South

America

Africa Asia Australasia Total

Rest of

Europe US

Rest of

North

America

Russia

Rest†of

Asia

Equity-accounted entities (BP share)

Capitalized costs at 31 December

b c

Gross capitalized costs

Proved properties — 3,187 — — 9,096 — 24,686 3,434 — 40,403

Unproved properties — 481 — — 68 — 907 26 — 1,482

— 3,668 — — 9,164 — 25,593 3,460 — 41,885

Accumulated depreciation — 400 — — 4,249 — 6,207 3,460 — 14,316

Net capitalized costs — 3,268 — — 4,915 — 19,386 — — 27,569

Costs incurred for the year ended 31 December

b d e

Acquisition of properties

Proved — 323 — — — — 653 — — 976

Unproved — 152 — — 20 — 416 — — 588

— 475 — — 20 — 1,069 — — 1,564

Exploration and appraisal costs

— 49 — — 43 — 194 — — 286

Development — 199 — — 576 — 3,361 446 — 4,582

Total costs — 723 — — 639 — 4,624 446 — 6,432

Results of operations for the year ended 31 December

Sales and other operating revenues

Third parties — 773 — — 1,750 — — 988 — 3,511

Sales between businesses — — — — — — 11,537 — — 11,537

— 773 — — 1,750 — 11,537 988 — 15,048

Exploration expenditure — 68 — — — — 59 — — 127

Production costs — 157 — — 592 — 1,424 117 — 2,290

Production taxes — — — — 336 — 5,712 426 — 6,474

Other costs (income) — 67 — — 11 — 409 (5) — 482

Depreciation, depletion and amortization — 328 — — 458 — 1,539 446 — 2,771

Net impairments and losses on sale of

businesses and fixed assets

— 6 — — 27 — 54 — — 87

— 626 — — 1,424 — 9,197 984 — 12,231

Profit (loss) before taxation — 147 — — 326 — 2,340 4 — 2,817

Allocable taxes — 54 — — (18) — 457 — — 493

Results of operations

— 93 — — 344 — 1,883 4 — 2,324

Upstream and Rosneft segments replacement cost profit (loss) before interest and tax from equity-accounted entities

Exploration and production activities –

equity-accounted entities after tax (as

above)

— 93 — — 344 — 1,883 4 — 2,324

Midstream and other activities after tax

— (22) 25 — 37 205 (1,046) 241 — (560)

Total replacement cost profit (loss) after

interest and tax

— 71 25 — 381 205 837 245 — 1,764

Amounts reported for Russia in this table include BP’s share of Rosneft’s worldwide activities, including insignificant amounts outside Russia. The amounts reported include the

corresponding amounts for their equity-accounted entities.

These tables contain information relating to oil and natural gas exploration and production activities of equity-accounted entities. Amounts relating to the management and ownership of

crude oil and natural gas pipelines, LNG liquefaction and transportation operations as well as downstream activities of Rosneft and Pan American Energy Group are excluded.

Costs of decommissioning are included in capitalized costs at 31†December but are excluded from costs incurred for the year.

Includes exploration and appraisal drilling expenditures, which are capitalized within intangible assets, and geological and geophysical exploration costs, which are charged to income as

incurred.

The amounts shown reflect BP’s share of equity-accounted entities’ costs incurred, and not the costs incurred by BP in acquiring an interest in equity-accounted entities.

Presented net of sales taxes.

From 16 December 2017, BP entered into a new 50:50 joint venture Pan American Energy Group (PAEG). Prior to this, Pan American Energy (PAE) was owned 60% by BP and 40% by Bridas

Corporation. Of BP's initial 60% interest in PAE, 10% was classified as held for sale on 9 September 2017. For September, only 9 days of income was reported for the full 60%. After this

equity accounting continued for the 50% not classified as held for sale. BP accounted for 50% of the enlarged entity from 16 December 2017.

Includes interest and adjustment for non-controlling interests. Excludes inventory holding gains and losses.

238 BP Annual Report and Form 20-F 2019

Movements in estimated net proved reserves

million†barrels

Crude oil

a b

2019

Europe

North

America

South

America

Africa Asia Australasia Total

Rest of

Europe US

c d

Rest of

North

America Russia

Rest of

Asia

Subsidiaries

At 1†January

Developed 223 — 962 43 8 223 — 1,126 30 2,615

Undeveloped 243 — 802 190 5 36 — 482 5 1,763

466 — 1,764 234 14 259 — 1,608 34 4,378

Changes attributable to

Revisions of previous estimates (23) — 72 (8) 1 39 — 104 2 187

Improved recovery — — 189 1 — — — — — 191

Purchases of reserves-in-place — — — — — — — 1 — 1

Discoveries and extensions — — 34 — — — — 11 — 45

Production (36) — (143) (9) (3) (57) — (125) (6) (378)

Sales of reserves-in-place — — (12) — — (45) — — — (57)

(59) — 141 (16) (2) (63) — (9) (4) (12)

At 31 December

Developed 206 — 1,063 40 7 156 — 1,074 26 2,572

Undeveloped 200 — 842 179 5 40 — 525 4 1,794

406 — 1,905 218 12 196 — 1,599 30 4,367

Equity-accounted entities (BP share)

At 1†January

Developed — 57 — — 293 1 3,190 — — 3,541

Undeveloped — 100 — 19 259 — 2,414 — — 2,792

— 157 — 19 552 1 5,604 — — 6,333

Changes attributable to

Revisions of previous estimates — 2 — 1 (13) 1 158 — — 147

Improved recovery — 4 — — — — — — — 4

Purchases of reserves-in-place — — — — — — 7 — — 7

Discoveries and extensions — — — — 33 — 277 — — 310

Production — (13) — — (24) — (345) — — (382)

Sales of reserves-in-place — — — — — — (6) — — (6)

— (7) — 1 (4) 1 91 — — 81

At 31 December

Developed — 115 — — 291 2 3,159 — — 3,567

Undeveloped — 35 — 20 257 — 2,535 — — 2,847

— 150 — 20 548 2 5,695 — — 6,415

Total subsidiaries and equity-accounted entities (BP share)

At 1†January

Developed 223 57 962 43 302 224 3,190 1,126 30 6,156

Undeveloped 243 100 802 209 264 36 2,414 482 5 4,555

466 157 1,764 253 566 260 5,604 1,608 34 10,711

At 31†December

Developed 206 115 1,063 40 298 158 3,159 1,074 26 6,140

Undeveloped 200 35 842 198 262 40 2,535 525 4 4,642

406 150 1,905 238 560 198 5,695 1,599 30 10,781

Crude oil includes condensate and bitumen. Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the

underlying production and the option and ability to make lifting and sales arrangements independently.

Because of rounding, some totals may not exactly agree with the sum of their component parts.

Proved reserves in the Prudhoe Bay field in Alaska include an estimated 4.5†million barrels upon which a net profits royalty will be payable over the life of the field under the terms of the BP

Prudhoe Bay Royalty Trust.

Includes 362†million barrels of crude oil associated with Assets Held for Sale in the USA.

Includes 4†million barrels of crude oil in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC.

Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities.

Includes 346†million barrels of crude oil in respect of the 6.17% non-controlling interest in Rosneft, including 26 mmbbl held through BP's interests in Russia other than Rosneft.

Total proved crude oil reserves held as part of our equity interest in Rosneft is 5,604 million barrels, comprising less than 1†million barrels in Egypt, Vietnam, Iraq and Canada, 35 million

barrels in Venezuela and 5,568 million barrels in Russia.

BP Annual Report and Form 20-F 2019 239

Movements in estimated net proved reserves - continued

million†barrels

Natural gas liquids

a b

2019

Europe

North

America

South

America

Africa Asia Australasia Total

Rest of

Europe US

Rest of

North

America Russia

Rest of

Asia

Subsidiaries

At 1†January

Developed 8 — 266 — 2 14 — — 5 295

Undeveloped 6 — 246 — 25 4 — — — 280

14 — 511 — 27 18 — — 5 576

Changes attributable to

Revisions of previous estimates — — (46) — (1) — — — — (47)

Improved recovery 1 — 62 — — — — — — 63

Purchases of reserves-in-place — — — — — — — — — —

Discoveries and extensions — — 1 — — — — — — 1

Production

(1) — (33) — (3) (3) — — (1) (41)

Sales of reserves-in-place — — (17) — — — — — — (17)

(1) — (32) — (4) (3) — — (1) (41)

At 31†December

Developed 8 — 229 — 2 12 — — 4 255

Undeveloped 5 — 250 — 21 4 — — — 280

13 — 479 — 23 16 — — 4 535

Equity-accounted entities (BP share)

At 1†January

Developed — 4 — — — 7 103 — — 114

Undeveloped — 3 — — — — 51 — — 54

— 7 — — — 7 154 — — 169

Changes attributable to

Revisions of previous estimates — — — — 3 5 (11) — — (3)

Improved recovery — 1 — — — — — — — 1

Purchases of reserves-in-place — — — — — — — — — —

Discoveries and extensions — — — — — — — — — —

Production — (1) — — — (2) (2) — — (4)

Sales of reserves-in-place — — — — — — — — — —

— — — — 2 4 (13) — — (7)

At 31 December

g h

Developed — 5 — — 2 11 89 — — 107

Undeveloped — 3 — — — — 52 — — 55

— 7 — — 2 11 141 — — 162

Total subsidiaries and equity-accounted entities (BP share)

At 1†January

Developed 8 4 266 — 2 22 103 — 5 409

Undeveloped 6 3 246 — 25 4 51 — — 335

14 7 511 — 27 26 154 — 5 744

At 31†December

Developed 8 5 229 — 4 23 89 — 4 363

Undeveloped 5 3 250 — 21 4 52 — — 334

13 7 479 — 25 27 141 — 4 697

Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to

make lifting and sales arrangements independently.

Because of rounding, some totals may not exactly agree with the sum of their component parts.

Includes 94†million barrels of NGL associated with Assets Held for Sale in the USA.

Excludes NGLs from processing plants in which an interest is held of less than 1†thousand barrels per day for subsidiaries and 3†thousand barrels per day for equity-accounted entities.

Includes 7†million barrels of NGL in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC.

Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities.

Includes 11†million barrels of NGLs in respect of the 7.90% non-controlling interest in Rosneft.

Total proved NGL reserves held as part of our equity interest in Rosneft is 141 million barrels, comprising less than 1†million barrels in Egypt, Venezuela, Vietnam and Canada, and 141 million

barrels in Russia.

240 BP Annual Report and Form 20-F 2019

Movements in estimated net proved reserves - continued

million†barrels

Total liquids

a b

2019

Europe

North

America

South

America Africa Asia Australasia Total

Rest of

Europe US

c d

Rest of

North

America Russia

Rest of

Asia

Subsidiaries

At 1†January

Developed 231 — 1,228 43 10 237 — 1,126 35 2,910

Undeveloped 249 — 1,048 190 30 40 — 482 5 2,044

480 — 2,276 234 41 277 — 1,608 39 4,954

Changes attributable to

Revisions of previous estimates (24) — 26 (8) — 40 — 104 2 140

Improved recovery 1 — 252 1 — — — — — 254

Purchases of reserves-in-place — — — — — — — 1 — 1

Discoveries and extensions — — 35 — — — — 11 — 46

Production

(38) — (176) (9) (6) (60) — (125) (7) (420)

Sales of reserves-in-place — — (28) — — (45) — — — (74)

(60) — 109 (16) (6) (65) — (9) (5) (52)

At 31 December

Developed 214 — 1,292 40 9 168 — 1,074 30 2,828

Undeveloped 205 — 1,092 179 26 43 — 525 4 2,074

420 — 2,384 218 35 212 — 1,599 34 4,902

Equity-accounted entities (BP share)

At 1†January

Developed — 60 — — 293 8 3,293 — — 3,655

Undeveloped — 104 — 19 259 — 2,465 — — 2,846

— 164 — 19 552 8 5,758 — — 6,502

Changes attributable to

Revisions of previous estimates — 2 — 1 (11) 7 146 — — 145

Improved recovery — 5 — — — — — — — 5

Purchases of reserves-in-place — — — — — — 7 — — 7

Discoveries and extensions — — — — 33 — 277 — — 310

Production — (14) — — (24) (2) (346) — — (386)

Sales of reserves-in-place — — — — — — (6) — — (6)

— (7) — 1 (1) 5 78 — — 75

At 31 December

h i

Developed — 120 — — 293 13 3,248 — — 3,675

Undeveloped — 37 — 20 257 — 2,588 — — 2,902

— 157 — 20 550 13 5,836 — — 6,576

Total subsidiaries and equity-accounted entities (BP share)

At 1†January

Developed 231 60 1,228 44 303 245 3,293 1,126 35 6,565

Undeveloped 249 104 1,048 209 289 40 2,465 482 5 4,890

480 164 2,276 253 593 285 5,758 1,608 39 11,456

At 31†December

Developed 214 120 1,292 40 302 181 3,248 1,074 30 6,502

Undeveloped 205 37 1,092 198 283 43 2,588 525 4 4,976

420 157 2,384 238 585 224 5,836 1,599 34 11,478

Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to

make lifting and sales arrangements independently.

Because of rounding, some totals may not exactly agree with the sum of their component parts.

Proved reserves in the Prudhoe Bay field in Alaska include an estimated 4.5†million barrels of oil equivalent upon which a net profits royalty will be payable, over the life of the field under the

terms of the BP Prudhoe Bay Royalty Trust.

Includes 456†million barrels associated with Assets Held for Sale in the USA.

Excludes NGLs from processing plants in which an interest is held of less than 1†thousand barrels per day for subsidiaries and 3†thousand barrels per day for equity-accounted entities.

Also includes 11†million barrels in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC.

Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities.

Includes 357†million barrels in respect of the non-controlling interest in Rosneft, including 26 mmboe held through BP’s interests in Russia other than Rosneft.

Total proved liquid reserves held as part of our equity interest in Rosneft is 5,745 million barrels, comprising 35 million barrels in Venezuela, less than 1†million barrels in Iraq, Canada, Egypt

and Vietnam and 5,709 million barrels in Russia.

BP Annual Report and Form 20-F 2019 241

Movements in estimated net proved reserves – continued

billion†cubic†feet

Natural gas

a b

2019

Europe

North

America

South

America

Africa Asia Australasia Total

Restƒof

Europe US

Restƒof

North

America Russia

Restƒof

Asia

Subsidiaries

At 1†January

Developed 439 — 6,270 — 2,168 1,313 — 3,599 2,630 16,420

Undeveloped 343 — 5,056 — 3,073 1,067 — 3,218 1,179 13,936

782 — 11,326 — 5,241 2,380 — 6,817 3,809 30,355

Changes attributable to

Revisions of previous estimates (34) — (1,877) 1 (263) (4) — 285 (129) (2,022)

Improved recovery 9 — 307 — — — — — — 315

Purchases of reserves-in-place — — — — — — — 50 — 50

Discoveries and extensions — — 11 — 178 — — 299 — 488

Production

(57) — (923) (1) (729) (450) — (383) (291) (2,834)

Sales of reserves-in-place — — (386) — — (21) — — — (406)

(82) — (2,869) — (814) (475) — 251 (420) (4,410)

At 31 December

Developed 493 — 6,330 — 2,192 1,163 — 3,667 2,256 16,101

Undeveloped 207 — 2,127 — 2,235 742 — 3,401 1,132 9,844

700 — 8,458 — 4,427 1,905 — 7,068 3,389 25,946

Equity-accounted entities (BP share)

At 1†January

Developed — 107 — — 1,207 391 7,798 12 — 9,515

Undeveloped — 55 — 4 446 143 8,719 4 — 9,369

— 161 — 4 1,653 534 16,517 15 — 18,884

Changes attributable to

Revisions of previous estimates — 9 — 3 (120) 38 789 — — 718

Improved recovery — 15 — — — — — — — 15

Purchases of reserves-in-place — — — — — — — — — —

Discoveries and extensions — — — — 180 — 534 — — 714

Production

— (22) — — (135) (65) (448) (5) — (676)

Sales of reserves-in-place — — — — — — — — — —

— 2 — 3 (75) (27) 874 (5) — 772

At 31 December

g h

Developed — 108 — — 1,130 507 9,324 10 — 11,079

Undeveloped — 56 — 6 447 — 8,067 — — 8,576

— 164 — 6 1,577 507 17,391 10 — 19,656

Total subsidiaries and equity-accounted entities (BP share)

At 1†January

Developed 439 107 6,270 — 3,375 1,704 7,798 3,610 2,630 25,934

Undeveloped 343 55 5,056 4 3,519 1,210 8,719 3,221 1,179 23,305

782 161 11,326 4 6,894 2,914 16,517 6,832 3,809 49,239

At 31†December

Developed 493 108 6,330 — 3,323 1,670 9,324 3,677 2,256 27,181

Undeveloped 207 56 2,127 6 2,682 742 8,067 3,401 1,132 18,421

700 164 8,458 6 6,004 2,412 17,391 7,078 3,389 45,601

Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to

make lifting and sales arrangements independently.

Because of rounding, some totals may not exactly agree with the sum of their component parts.

Includes 3,054†billion cubic feet of natural gas associated with Assets Held for Sale in the USA.

Includes 188 billion cubic feet of natural gas consumed in operations, 146 billion cubic feet in subsidiaries, 42 billion cubic feet in equity-accounted entities.

Includes 1,330 billion cubic feet of natural gas in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC.

Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities.

Includes 1,433 billion cubic feet of natural gas in respect of the 9.72% non-controlling interest in Rosneft including 569 billion cubic feet held through BP’s interests in Russia other than

Rosneft.

Total proved gas reserves held as part of our equity interest in Rosneft is 14,705 billion cubic feet, comprising 28 billion cubic feet in Venezuela, 10 billion cubic feet in Vietnam, 171 billion

cubic feet in Egypt and 14,495 billion cubic feet in Russia.

242 BP Annual Report and Form 20-F 2019

Movements in estimated net proved reserves – continued

million barrels of oil equivalent

Total hydrocarbons

a b

2019

Europe

North

America

South

America

Africa Asia Australasia Total

Rest of

Europe US

d e

Rest of

North

America Russia

Rest of

Asia

Subsidiaries

At 1†January

Developed 307 — 2,309 43 384 464 — 1,746 488 5,741

Undeveloped 308 — 1,919 190 560 224 — 1,037 208 4,447

615 — 4,228 234 944 687 — 2,783 696 10,188

Changes attributable to

Revisions of previous estimates (29) — (297) (8) (45) 39 — 153 (21) (208)

Improved recovery 3 — 305 1 — — — — — 309

Purchases of reserves-in-place — — — — — — — 10 — 10

Discoveries and extensions — — 36 — 31 — — 63 — 130

Production

f g

(48) — (335) (9) (131) (137) — (191) (57) (908)

Sales of reserves-in-place — — (95) — — (49) — — — (144)

(74) — (386) (16) (146) (147) — 35 (78) (813)

At 31 December

Developed 300 — 2,384 40 387 369 — 1,707 419 5,604

Undeveloped 241 — 1,459 179 411 171 — 1,111 199 3,771

540 — 3,842 218 798 540 — 2,818 618 9,375

Equity-accounted entities (BP share)

At 1†January

Developed — 79 — — 501 76 4,638 2 — 5,296

Undeveloped — 113 — 20 336 25 3,968 1 — 4,462

— 192 — 20 837 101 8,605 3 — 9,757

Changes attributable to

Revisions of previous estimates — 4 — 1 (31) 13 282 — — 269

Improved recovery — 7 — — — — — — — 7

Purchases of reserves-in-place — — — — — — 7 — — 7

Discoveries and extensions — — — — 64 — 369 — — 434

Production

— (17) — — (47) (13) (424) (1) — (503)

Sales of reserves-in-place — — — — — — (6) — — (6)

— (6) — 1 (14) — 229 (1) — 208

At 31 December

j k

Developed — 139 — — 488 100 4,856 2 — 5,585

Undeveloped — 47 — 21 334 — 3,978 — — 4,381

— 186 — 21 822 100 8,834 2 — 9,965

Total subsidiaries and equity-accounted entities (BP share)

At 1†January

Developed 307 79 2,309 44 885 539 4,638 1,749 488 11,037

Undeveloped 308 113 1,919 210 896 249 3,968 1,037 208 8,908

615 192 4,228 253 1,781 788 8,605 2,786 696 19,945

At 31†December

Developed 300 139 2,384 40 875 469 4,856 1,708 419 11,189

Undeveloped 241 47 1,459 199 746 171 3,978 1,112 199 8,152

540 186 3,842 239 1,621 640 8,834 2,820 618 19,341

Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to

make lifting and sales arrangements independently.

Because of rounding, some totals may not exactly agree with the sum of their component parts.

5.8 billion cubic feet of natural gas = 1†million barrels of oil equivalent.

Proved reserves in the Prudhoe Bay field in Alaska include an estimated 4.5†million barrels of oil equivalent upon which a net profits royalty will be payable, over the life of the field under the

terms of the BP Prudhoe Bay Royalty Trust.

Includes 982 million barrels of oil equivalent associated with Assets Held for Sale in the USA.

Excludes NGLs from processing plants in which an interest is held of less than 1†thousand barrels per day for subsidiaries and 3†thousand barrels per day for equity-accounted entities.

Includes 32†million barrels of oil equivalent of natural gas consumed in operations, 25†million barrels of oil equivalent in subsidiaries, 7†million barrels of oil equivalent in equity-accounted

entities.

Includes 240†million barrels of oil equivalent in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC.

Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities.

Includes 603†million barrels of oil equivalent in respect of the non-controlling interest in Rosneft, including 124 mmboe held through BP’s interests in Russia other than Rosneft.

Total proved reserves held as part of our equity interest in Rosneft is 8,281 million barrels of oil equivalent, comprising less than 1†million barrels of oil equivalent in Iraq and Canada, 40 million

barrels of oil equivalent in Venezuela, 2 million barrels of oil equivalent in Vietnam, 30 million barrels of oil equivalent in Egypt and 8,208 million barrels of oil equivalent in Russia.

BP Annual Report and Form 20-F 2019 243

Movements in estimated net proved reserves – continued

million†barrels

Crude oil

a b

2018

Europe

North

America

South

America

Africa Asia Australasia Total

Rest of

Europe US

Rest of

North

America Russia

Rest of

Asia

Subsidiaries

At 1†January

Developed 245 — 932 54 10 281 — 1,040 31 2,592

Undeveloped 164 — 492 195 6 28 — 642 11 1,537

409 — 1,423 248 16 309 — 1,682 42 4,129

Changes attributable to

Revisions of previous estimates 22 — 116 (6) 1 11 — 40 (2) 183

Improved recovery — — 51 — — 1 — — — 52

Purchases of reserves-in-place 93 — 412 — — — — — — 504

Discoveries and extensions 15 — 17 — — 13 — — — 46

Production (37) — (137) (9) (3) (75) — (114) (6) (381)

Sales of reserves-in-place (37) — (118) — — — — — — (155)

57 — 341 (15) (2) (50) — (74) (8) 249

At 31 December

Developed 223 — 962 43 8 223 — 1,126 30 2,615

Undeveloped 243 — 802 190 5 36 — 482 5 1,763

466 — 1,764 234 14 259 — 1,608 34 4,378

Equity-accounted entities (BP share)

At 1†January

Developed — 56 — — 285 1 3,124 6 — 3,473

Undeveloped — 89 — — 263 — 2,251 — — 2,603

— 145 — — 548 1 5,374 6 — 6,076

Changes attributable to

Revisions of previous estimates — 11 — — 7 — 150 — — 168

Improved recovery — 13 — — — — — — — 13

Purchases of reserves-in-place — — — — — — 89 — — 89

Discoveries and extensions — — — 19 21 — 326 — — 366

Production — (13) — — (25) — (335) (6) — (379)

Sales of reserves-in-place — — — — — — — — — —

— 12 — 19 4 (1) 229 (6) — 257

At 31 December

Developed — 57 — — 293 1 3,190 — — 3,541

Undeveloped — 100 — 19 259 — 2,414 — — 2,792

— 157 — 19 552 1 5,604 — — 6,333

Total subsidiaries and equity-accounted entities (BP share)

At 1†January

Developed 245 56 932 54 295 282 3,124 1,047 31 6,064

Undeveloped 164 89 492 195 269 28 2,251 642 11 4,140

409 145 1,423 249 564 310 5,374 1,688 42 10,205

At 31†December

Developed 223 57 962 43 302 224 3,190 1,126 30 6,156

Undeveloped 243 100 802 209 264 36 2,414 482 5 4,555

466 157 1,764 253 566 260 5,604 1,608 34 10,711

Crude oil includes condensate and bitumen. Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the

underlying production and the option and ability to make lifting and sales arrangements independently.

Because of rounding, some totals may not exactly agree with the sum of their component parts.

Proved reserves in the Prudhoe Bay field in Alaska include an estimated 16†million barrels upon which a net profits royalty will be payable over the life of the field under the terms of the BP

Prudhoe Bay Royalty Trust.

Includes 4†million barrels of crude oil in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC.

Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities.

Includes 344†million barrels of crude oil in respect of the 6.28% non-controlling interest in Rosneft, including 24 mmbbl held through BP’s interests in Russia other than Rosneft.

Total proved crude oil reserves held as part of our equity interest in Rosneft is 5,539 million barrels, comprising less than 1†million barrels in Vietnam and Canada, 58 million barrels in

Venezuela and 5,481 million barrels in Russia.

244 BP Annual Report and Form 20-F 2019

Movements in estimated net proved reserves – continued

million†barrels

Natural gas liquids

a b

2018

Europe

North

America

South

America

Africa Asia Australasia Total

Rest†of

Europe US

Rest of

North

America Russia

Rest†of

Asia

Subsidiaries

At 1†January

Developed 11 — 177 — 2 21 — — 5 216

Undeveloped 3 — 69 — 28 — — — 1 102

14 — 246 — 30 21 — — 6 318

Changes attributable to

Revisions of previous estimates 1 — 20 — — (3) — — — 17

Improved recovery — — 16 — — 2 — — — 18

Purchases of reserves-in-place — — 253 — — — — — — 253

Discoveries and extensions 3 — 1 — — 3 — — — 7

Production

(2) — (25) — (3) (3) — — (1) (34)

Sales of reserves-in-place (3) — — — — — — — — (3)

— — 265 — (3) (2) — — (1) 258

At 31 December

Developed 8 — 266 — 2 14 — — 5 295

Undeveloped 6 — 246 — 25 4 — — — 280

14 — 511 — 27 18 — — 5 576

Equity-accounted entities (BP share)

At 1†January

Developed — 4 — — — 10 82 — — 97

Undeveloped — 4 — — — — 49 — — 53

— 8 — — — 10 131 — — 149

Changes attributable to

Revisions of previous estimates — — — — — (1) 25 — — 23

Improved recovery — — — — — — — — — —

Purchases of reserves-in-place — — — — — — — — — —

Discoveries and extensions — — — — — — — — — —

Production — (1) — — — (1) (2) — — (4)

Sales of reserves-in-place — — — — — — — — — —

— (1) — — — (3) 23 — — 19

At 31 December

Developed — 4 — — — 7 103 — — 114

Undeveloped — 3 — — — — 51 — — 54

— 7 — — — 7 154 — — 169

Total subsidiaries and equity-accounted entities (BP share)

At 1†January

Developed 11 4 177 — 2 31 82 — 5 313

Undeveloped 3 4 69 — 28 — 49 — 1 154

14 8 246 — 30 31 131 — 6 467

At 31†December

Developed 8 4 266 — 2 22 103 — 5 409

Undeveloped 6 3 246 — 25 4 51 — — 335

14 7 511 — 27 26 154 — 5 744

Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to

make lifting and sales arrangements independently.

Because of rounding, some totals may not exactly agree with the sum of their component parts.

Excludes NGLs from processing plants in which an interest is held of less than 1†thousand barrels per day for subsidiaries and 3†thousand barrels per day for equity-accounted entities.

Includes 8†million barrels of NGL in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC.

Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities.

Includes 12†million barrels of NGLs in respect of the 7.82% non-controlling interest in Rosneft.

Total proved NGL reserves held as part of our equity interest in Rosneft is 154 million barrels, comprising less than 1†million barrels in Venezuela, Vietnam and Canada, and 154 million barrels

in Russia.

BP Annual Report and Form 20-F 2019 245

Movements in estimated net proved reserves – continued

million†barrels

Total liquids

a b

2018

Europe

North

America

South

America Africa Asia Australasia Total

Rest†of

Europe US

Rest of

North

America Russia

Rest†of

Asia

Subsidiaries

At 1†January

Developed 256 — 1,108 54 12 301 — 1,040 36 2,808

Undeveloped 167 — 561 195 34 28 — 642 12 1,639

424 — 1,669 248 46 329 — 1,682 48 4,447

Changes attributable to

Revisions of previous estimates 23 — 136 (6) 1 8 — 40 (2) 200

Improved recovery — — 67 — — 3 — — — 70

Purchases of reserves-in-place 93 — 665 — — — — — — 758

Discoveries and extensions 18 — 18 — — 16 — — — 52

Production

(39) — (162) (9) (6) (79) — (114) (7) (415)

Sales of reserves-in-place (40) — (118) — — — — — — (158)

56 — 606 (15) (5) (52) — (74) (9) 507

At 31 December

Developed 231 — 1,228 43 10 237 — 1,126 35 2,910

Undeveloped 249 — 1,048 190 30 40 — 482 5 2,044

480 — 2,276 234 41 277 — 1,608 39 4,954

Equity-accounted entities (BP share)

At 1†January

Developed — 60 — — 285 11 3,206 6 — 3,569

Undeveloped — 93 — — 263 — 2,300 — — 2,656

— 153 — — 548 12 5,505 6 — 6,225

Changes attributable to

Revisions of previous estimates — 11 — — 7 (2) 175 — — 191

Improved recovery — 13 — — — — — — — 13

Purchases of reserves-in-place — — — — — — 89 — — 89

Discoveries and extensions — — — 19 21 — 326 — — 366

Production — (13) — — (25) (2) (337) (6) — (383)

Sales of reserves-in-place — — — — — — — — — —

— 11 — 19 4 (3) 253 (6) — 277

At 31 December

g h

Developed — 60 — — 293 8 3,293 — — 3,655

Undeveloped — 104 — 19 259 — 2,465 — — 2,846

— 164 — 19 552 8 5,758 — — 6,502

Total subsidiaries and equity-accounted entities (BP share)

At 1†January

Developed 256 60 1,108 54 297 313 3,206 1,047 36 6,377

Undeveloped 167 93 561 195 297 28 2,300 642 12 4,295

424 153 1,669 249 594 341 5,505 1,688 48 10,672

At 31†December

Developed 231 60 1,228 44 303 245 3,293 1,126 35 6,565

Undeveloped 249 104 1,048 209 289 40 2,465 482 5 4,890

480 164 2,276 253 593 285 5,758 1,608 39 11,456

Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to

make lifting and sales arrangements independently.

Because of rounding, some totals may not exactly agree with the sum of their component parts.

Proved reserves in the Prudhoe Bay field in Alaska include an estimated 16†million barrels of oil equivalent upon which a net profits royalty will be payable, over the life of the field under the

terms of the BP Prudhoe Bay Royalty Trust.

Excludes NGLs from processing plants in which an interest is held of less than 1†thousand barrels per day for subsidiaries and 3†thousand barrels per day for equity-accounted entities.

Also includes 12†million barrels in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC.

Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities.

Includes 356†million barrels in respect of the non-controlling interest in Rosneft, including 24 mmboe held through BP’s interests in Russia other than Rosneft.

Total proved liquid reserves held as part of our equity interest in Rosneft is 5,693 million barrels, comprising less than 1†million barrels in Canada, 58 million barrels in Venezuela, less than

1†million barrels in Vietnam and 5,635 million barrels in Russia.

246 BP Annual Report and Form 20-F 2019

Movements in estimated net proved reserves – continued

billion†cubic†feet

Natural gas

a b

2018

Europe

North

America

South

America

Africa Asia Australasia Total

Rest of

Europe US

Rest of

North

America Russia

Rest of

Asia

Subsidiaries

At 1†January

Developed 523 — 5,238 (1) 2,862 1,159 — 2,755 2,730 15,266

Undeveloped 320 — 3,086 — 3,330 1,510 — 4,245 1,505 13,997

843 — 8,323 (1) 6,193 2,670 — 7,000 4,235 29,263

Changes attributable to

Revisions of previous estimates 84 — 10 3 (195) (444) — 140 (123) (524)

Improved recovery — — 1,315 — — — — — — 1,315

Purchases of reserves-in-place 40 — 2,655 — — — — — — 2,695

Discoveries and extensions 60 — 11 — 31 578 — — — 680

Production

(66) — (751) (3) (788) (423) — (324) (303) (2,658)

Sales of reserves-in-place (178) — (237) — — — — — — (416)

(61) — 3,003 1 (951) (290) — (184) (426) 1,092

At 31 December

Developed 439 — 6,270 — 2,168 1,313 — 3,599 2,630 16,420

Undeveloped 343 — 5,056 — 3,073 1,067 — 3,218 1,179 13,936

782 — 11,326 — 5,241 2,380 — 6,817 3,809 30,355

Equity-accounted entities (BP share)

At 1†January

Developed — 112 — — 1,274 476 6,077 17 — 7,955

Undeveloped — 69 — — 450 146 7,173 3 — 7,841

— 180 — — 1,724 622 13,250 20 — 15,796

Changes attributable to

Revisions of previous estimates — 2 — — (50) (39) 805 2 — 719

Improved recovery — — — — 1 — — — — 1

Purchases of reserves-in-place — — — — — — 2,413 — — 2,413

Discoveries and extensions — — — 4 122 — 512 — — 638

Production

— (22) — — (145) (48) (464) (6) — (685)

Sales of reserves-in-place — — — — — — — — — —

— (19) — 3 (71) (87) 3,267 (5) — 3,087

At 31 December

f g

Developed — 107 — — 1,207 391 7,798 12 — 9,515

Undeveloped — 55 — 4 446 143 8,719 4 — 9,369

— 161 — 4 1,653 534 16,517 15 — 18,884

Total subsidiaries and equity-accounted entities (BP share)

At 1†January

Developed 523 112 5,238 — 4,136 1,635 6,077 2,771 2,730 23,221

Undeveloped 320 69 3,086 — 3,781 1,656 7,173 4,249 1,505 21,838

843 180 8,323 — 7,917 3,291 13,250 7,020 4,235 45,060

At 31†December

Developed 439 107 6,270 — 3,375 1,704 7,798 3,610 2,630 25,934

Undeveloped 343 55 5,056 4 3,519 1,210 8,719 3,221 1,179 23,305

782 161 11,326 4 6,894 2,914 16,517 6,832 3,809 49,239

Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to

make lifting and sales arrangements independently.

Because of rounding, some totals may not exactly agree with the sum of their component parts.

Includes 181 billion cubic feet of natural gas consumed in operations, 139 billion cubic feet in subsidiaries, 42 billion cubic feet in equity-accounted entities.

Includes 1,573 billion cubic feet of natural gas in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC.

Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities.

Includes 1,211 billion cubic feet of natural gas in respect of the 8.60% non-controlling interest in Rosneft including 480 billion cubic feet held through BP’s interests in Russia other than

Rosneft.

Total proved gas reserves held as part of our equity interest in Rosneft is 14,325 billion cubic feet, comprising 0 billion cubic feet in Canada, 26 billion cubic feet in Venezuela, 15 billion cubic

feet in Vietnam, 200 billion cubic feet in Egypt and 14,084 billion cubic feet in Russia.

BP Annual Report and Form 20-F 2019 247

Movements in estimated net proved reserves – continued

million†barrels†of†oil†equivalent

Total hydrocarbons

a b

2018

Europe

North

America

South

America

Africa Asia Australasia Total

Rest of

Europe US

Rest of

North

America Russia

Rest of

Asia

Subsidiaries

At 1†January

Developed 347 — 2,011 54 505 501 — 1,515 507 5,440

Undeveloped 222 — 1,093 195 608 288 — 1,374 272 4,052

569 — 3,104 248 1,114 790 — 2,889 779 9,492

Changes attributable to

Revisions of previous estimates 38 — 138 (5) (33) (69) — 64 (23) 110

Improved recovery — — 294 — — 3 — — — 297

Purchases of reserves-in-place 100 — 1,123 — — — — — — 1,222

Discoveries and extensions 29 — 20 — 5 116 — — — 169

Production

e f

(50) — (292) (9) (142) (152) — (170) (59) (874)

Sales of reserves-in-place (70) — (159) — — — — — — (229)

46 — 1,124 (15) (169) (102) — (106) (82) 696

At 31 December

Developed 307 — 2,309 43 384 464 — 1,746 488 5,741

Undeveloped 308 — 1,919 190 560 224 — 1,037 208 4,447

615 — 4,228 234 944 687 — 2,783 696 10,188

Equity-accounted entities (BP share)

At 1†January

Developed — 80 — — 505 93 4,254 9 — 4,941

Undeveloped — 105 — — 341 25 3,536 1 — 4,008

— 184 — — 846 119 7,790 10 — 8,949

Changes attributable to

Revisions of previous estimates — 11 — — (1) (8) 313 — — 315

Improved recovery — 13 — — — — — — — 14

Purchases of reserves-in-place — — — — — — 505 — — 505

Discoveries and extensions — — — 20 42 — 414 — — 476

Production

— (17) — — (50) (10) (417) (7) — (501)

Sales of reserves-in-place — — — — — — — — — —

— 8 — 19 (9) (18) 816 (7) — 809

At 31 December

i j

Developed — 79 — — 501 76 4,638 2 — 5,296

Undeveloped — 113 — 20 336 25 3,968 1 — 4,462

— 192 — 20 837 101 8,605 3 — 9,757

Total subsidiaries and equity-accounted entities (BP share)

At 1†January

Developed 347 80 2,011 54 1,010 595 4,254 1,524 507 10,381

Undeveloped 222 105 1,093 195 949 314 3,536 1,374 272 8,060

569 184 3,104 249 1,959 908 7,790 2,899 779 18,441

At 31†December

Developed 307 79 2,309 44 885 539 4,638 1,749 488 11,037

Undeveloped 308 113 1,919 210 896 249 3,968 1,037 208 8,908

615 192 4,228 253 1,781 788 8,605 2,786 696 19,945

Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to

make lifting and sales arrangements independently.

Because of rounding, some totals may not exactly agree with the sum of their component parts.

5.8 billion cubic feet of natural gas = 1†million barrels of oil equivalent.

Proved reserves in the Prudhoe Bay field in Alaska include an estimated 16†million barrels of oil equivalent upon which a net profits royalty will be payable, over the life of the field under the

terms of the BP Prudhoe Bay Royalty Trust.

Excludes NGLs from processing plants in which an interest is held of less than 1†thousand barrels per day for subsidiaries and 3†thousand barrels per day for equity-accounted entities.

Includes 31†million barrels of oil equivalent of natural gas consumed in operations, 24†million barrels of oil equivalent in subsidiaries, 7†million barrels of oil equivalent in equity-accounted

entities.

Includes 283†million barrels of oil equivalent in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC.

Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities.

Includes 565†million barrels of oil equivalent in respect of the non-controlling interest in Rosneft, including 107 mmboe held through BP’s interests in Russia other than Rosneft.

Total proved reserves held as part of our equity interest in Rosneft is 8,163 million barrels of oil equivalent, comprising less than 1†million barrels of oil equivalent in Canada, 62 million barrels

of oil equivalent in Venezuela, 3 million barrels of oil equivalent in Vietnam, 35 million barrels of oil equivalent in Egypt and 8,063 million barrels of oil equivalent in Russia.

248 BP Annual Report and Form 20-F 2019

Movements in estimated net proved reserves – continued

million†barrels

Crude oil

a b

2017

Europe

North

America

South

America

Africa Asia Australasia Total

Rest of

Europe US

Rest of

North

America

Russia

Rest of

Asia

Subsidiaries

At 1†January

Developed 155 — 826 42 9 317 — 1,107 32 2,487

Undeveloped 274 — 497 209 11 42 — 245 14 1,291

429 — 1,322 251 20 358 — 1,352 46 3,778

Changes attributable to

Revisions of previous estimates 15 — 208 5 1 35 — 407 2 673

Improved recovery — — 12 — — 2 — — — 14

Purchases of reserves-in-place 3 — 1 — — 1 — — — 5

Discoveries and extensions — — 12 — — — — 42 — 53

Production (29) — (131) (7) (5) (88) — (119) (6) (384)

Sales of reserves-in-place (9) — — — — — — — — (9)

(20) — 101 (2) (4) (50) — 330 (4) 351

At 31 December

Developed 245 — 932 54 10 281 — 1,040 31 2,592

Undeveloped 164 — 492 195 6 28 — 642 11 1,537

409 — 1,423 248 16 309 — 1,682 42 4,129

Equity-accounted entities (BP share)

At 1†January

Developed — 45 — — 321 1 3,162 43 — 3,573

Undeveloped — 69 — — 325 — 2,134 1 — 2,529

— 114 — — 646 1 5,296 44 — 6,101

Changes attributable to

Revisions of previous estimates — 2 — — 1 — 102 (1) — 104

Improved recovery — 11 — — 4 — — — — 16

Purchases of reserves-in-place — 34 — — — — 37 — — 71

Discoveries and extensions — 1 — — 22 — 264 — — 288

Production — (11) — — (28) — (325) (36) — (401)

Sales of reserves-in-place — (5) — — (98) — — — — (103)

— 31 — — (98) — 78 (37) — (25)

At 31 December

Developed — 56 — — 285 1 3,124 6 — 3,473

Undeveloped — 89 — — 263 — 2,251 — — 2,603

— 145 — — 548 1 5,374 6 — 6,076

Total subsidiaries and equity-accounted entities (BP share)

At 1†January

Developed 155 45 826 42 330 318 3,162 1,150 32 6,060

Undeveloped 274 69 497 209 336 42 2,134 246 14 3,819

429 114 1,322 251 666 360 5,296 1,395 46 9,879

At 31†December

Developed 245 56 932 54 295 282 3,124 1,047 31 6,064

Undeveloped 164 89 492 195 269 28 2,251 642 11 4,140

409 145 1,423 249 564 310 5,374 1,688 42 10,205

Crude oil includes condensate and bitumen. Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the

underlying production and the option and ability to make lifting and sales arrangements independently.

Because of rounding, some totals may not exactly agree with the sum of their component parts.

Proved reserves in the Prudhoe Bay field in Alaska include an estimated 9†million barrels upon which a net profits royalty will be payable over the life of the field under the terms of the BP

Prudhoe Bay Royalty Trust.

Includes 5†million barrels of crude oil in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC.

Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities.

Includes 337†million barrels of crude oil in respect of the 6.31% non-controlling interest in Rosneft, including 6 mmbbl held through BP’s equity accounted interest in Taas-Yuryakh

Neftegazodobycha.

Total proved crude oil reserves held as part of our equity interest in Rosneft is 5,402 million barrels, comprising less than 1†million barrels in Vietnam and Canada, 59 million barrels in

Venezuela and 5,342 million barrels in Russia.

BP Annual Report and Form 20-F 2019 249

Movements in estimated net proved reserves – continued

million†barrels

Natural gas liquids

a b

2017

Europe

North

America

South

America

Africa Asia Australasia Total

Rest of

Europe US

Rest of

North

America Russia

Rest of

Asia

Subsidiaries

At 1†January

Developed 13 — 226 — 5 13 — — 9 266

Undeveloped 3 — 73 — 28 1 — — 2 107

16 — 299 — 33 14 — — 11 373

Changes attributable to

Revisions of previous estimates 2 — (44) — — 11 — — (4) (36)

Improved recovery — — 15 — — — — — — 15

Purchases of reserves-in-place — — — — — — — — — —

Discoveries and extensions — — 1 — — — — — — 1

Production

(3) — (24) — (3) (4) — — (1) (35)

Sales of reserves-in-place (1) — — — — — — — — (1)

(2) — (52) — (3) 7 — — (5) (55)

At 31 December

Developed 11 — 177 — 2 21 — — 5 216

Undeveloped 3 — 69 — 28 — — — 1 102

14 — 246 — 30 21 — — 6 318

Equity-accounted entities (BP share)

At 1†January

Developed — 3 — — — 11 50 — — 65

Undeveloped — 2 — — — — 15 — — 17

— 5 — — — 11 65 — — 81

Changes attributable to

Revisions of previous estimates — — — — — 1 68 — — 69

Improved recovery — 1 — — — — — — — 1

Purchases of reserves-in-place — 2 — — — — — — — 2

Discoveries and extensions — — — — — — — — — —

Production — (1) — — — (1) (2) — — (4)

Sales of reserves-in-place — — — — — — — — — —

— 3 — — — (1) 66 — — 68

At 31 December

Developed — 4 — — — 10 82 — — 97

Undeveloped — 4 — — — — 49 — — 53

— 8 — — — 10 131 — — 149

Total subsidiaries and equity-accounted entities (BP share)

At 1†January

Developed 13 3 226 — 5 24 50 — 9 331

Undeveloped 3 2 73 — 28 1 15 — 2 123

16 5 299 — 33 25 65 — 11 454

At 31†December

Developed 11 4 177 — 2 31 82 — 5 313

Undeveloped 3 4 69 — 28 — 49 — 1 154

14 8 246 — 30 31 131 — 6 467

Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to

make lifting and sales arrangements independently.

Because of rounding, some totals may not exactly agree with the sum of their component parts.

Excludes NGLs from processing plants in which an interest is held of less than 1†thousand barrels per day for subsidiaries and 2†thousand barrels per day for equity-accounted entities.

Includes 9†million barrels of NGL in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC.

Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities.

Total proved NGL reserves held as part of our equity interest in Rosneft is 131†million barrels, comprising less than 1†million barrels in Venezuela, Vietnam and Canada, and 131†million barrels

in Russia.

250 BP Annual Report and Form 20-F 2019

Movements in estimated net proved reserves – continued

million†barrels

Total liquids

a b

2017

Europe

North

America

South

America

Africa Asia Australasia Total

Rest of

Europe US

Rest of

North

America Russia

Rest of

Asia

Subsidiaries

At 1†January

Developed 168 — 1,051 42 14 330 — 1,107 42 2,753

Undeveloped 277 — 569 209 39 43 — 245 16 1,398

445 — 1,621 251 53 372 — 1,352 57 4,151

Changes attributable to

Revisions of previous estimates 17 — 164 5 1 45 — 407 (2) 637

Improved recovery — — 27 — — 2 — — — 29

Purchases of reserves-in-place 3 — 1 — — 1 — — — 5

Discoveries and extensions — — 12 — — — — 42 — 54

Production

(32) — (155) (7) (8) (92) — (119) (7) (419)

Sales of reserves-in-place (10) — — — — — — — — (10)

(22) — 49 (2) (7) (43) — 330 (9) 296

At 31 December

Developed 256 — 1,108 54 12 301 — 1,040 36 2,808

Undeveloped 167 — 561 195 34 28 — 642 12 1,639

424 — 1,669 248 46 329 — 1,682 48 4,447

Equity-accounted entities (BP share)

At 1†January

Developed — 48 — — 321 12 3,213 43 — 3,637

Undeveloped — 71 — — 325 — 2,148 1 — 2,545

— 119 — — 646 12 5,361 44 — 6,183

Changes attributable to

Revisions of previous estimates — 2 — — 1 1 170 (1) — 174

Improved recovery — 13 — — 4 — — — — 17

Purchases of reserves-in-place — 36 — — — — 37 — — 72

Discoveries and extensions — 1 — — 22 — 264 — — 288

Production — (12) — — (28) (2) (327) (36) — (405)

Sales of reserves-in-place — (6) — — (98) — — — — (104)

— 34 — — (98) (1) 144 (37) — 43

At 31 December

g h

Developed — 60 — — 285 11 3,206 6 — 3,569

Undeveloped — 93 — — 263 — 2,300 — — 2,656

— 153 — — 548 12 5,505 6 — 6,225

Total subsidiaries and equity-accounted entities (BP share)

At 1†January

Developed 168 48 1,051 42 335 342 3,213 1,150 42 6,390

Undeveloped 277 71 569 209 364 43 2,148 246 16 3,943

445 119 1,621 251 699 385 5,361 1,395 57 10,333

At 31†December

Developed 256 60 1,108 54 297 313 3,206 1,047 36 6,377

Undeveloped 167 93 561 195 297 28 2,300 642 12 4,295

424 153 1,669 249 594 341 5,505 1,688 48 10,672

Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to

make lifting and sales arrangements independently.

Because of rounding, some totals may not exactly agree with the sum of their component parts.

Proved reserves in the Prudhoe Bay field in Alaska include an estimated 9†million barrels of oil equivalent upon which a net profits royalty will be payable, over the life of the field under the

terms of the BP Prudhoe Bay Royalty Trust.

Excludes NGLs from processing plants in which an interest is held of less than 1†thousand barrels per day for subsidiaries and 2†thousand barrels per day for equity-accounted entities.

Also includes 14†million barrels in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC.

Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities.

Includes 338†million barrels in respect of the non-controlling interest in Rosneft, including 6 mmboe held through BP’s equity accounted interest in Taas-Yuryakh Neftegazodobycha.

Total proved liquid reserves held as part of our equity interest in Rosneft is 5,533 million barrels, comprising less than 1†million barrels in Canada, 59 million barrels in Venezuela, less than

1†million barrels in Vietnam and 5,473 million barrels in Russia.

BP Annual Report and Form 20-F 2019 251

Movements in estimated net proved reserves – continued

billion†cubic†feet

Natural gas

a b

2017

Europe

North

America

South

America

Africa Asia Australasia Total

Rest of

Europe US

Rest of

North

America Russia

Rest of

Asia

Subsidiaries

At 1†January

Developed 499 — 5,447 — 1,784 767 — 1,890 3,012 13,398

Undeveloped 350 — 2,567 — 4,970 2,191 — 3,769 1,643 15,490

848 — 8,014 — 6,755 2,958 — 5,659 4,654 28,888

Changes attributable to

Revisions of previous estimates 50 — (38) 3 (677) (450) — 258 (129) (983)

Improved recovery — — 1,002 — — 1 — 6 — 1,009

Purchases of reserves-in-place 25 — — — — 527 — — — 552

Discoveries and extensions — — 10 — 829 14 — 1,229 — 2,082

Production

(77) — (664) (3) (714) (380) — (152) (291) (2,281)

Sales of reserves-in-place (4) — — — — — — — — (4)

(5) — 309 — (562) (288) — 1,342 (420) 376

At 31 December

Developed 523 — 5,238 (1) 2,862 1,159 — 2,755 2,730 15,266

Undeveloped 320 — 3,086 — 3,330 1,510 — 4,245 1,505 13,997

843 — 8,323 (1) 6,193 2,670 — 7,000 4,235 29,263

Equity-accounted entities (BP share)

At 1†January

Developed — 89 — — 1,546 412 5,544 26 — 7,617

Undeveloped — 21 — — 534 — 6,304 4 — 6,863

— 110 — 1 2,080 412 11,847 30 — 14,480

Changes attributable to

Revisions of previous estimates — 19 — — 47 5 1,556 (2) — 1,625

Improved recovery — 37 — — 55 — — — — 92

Purchases of reserves-in-place — 39 — — — 237 10 — — 286

Discoveries and extensions — 1 — — 67 — 324 — — 392

Production

— (19) — — (178) (32) (488) (8) — (726)

Sales of reserves-in-place — (6) — — (347) — — — — (353)

— 70 — — (356) 210 1,403 (10) — 1,316

At 31 December

Developed — 112 — — 1,274 476 6,077 17 — 7,955

Undeveloped — 69 — — 450 146 7,173 3 — 7,841

— 180 — — 1,724 622 13,250 20 — 15,796

Total subsidiaries and equity-accounted entities (BP share)

At 1†January

Developed 499 89 5,447 — 3,330 1,179 5,544 1,916 3,012 21,015

Undeveloped 350 21 2,567 — 5,505 2,191 6,304 3,772 1,643 22,353

848 110 8,014 — 8,835 3,370 11,847 5,688 4,654 43,368

At 31†December

Developed 523 112 5,238 — 4,136 1,635 6,077 2,771 2,730 23,221

Undeveloped 320 69 3,086 — 3,781 1,656 7,173 4,249 1,505 21,838

843 180 8,323 — 7,917 3,291 13,250 7,020 4,235 45,060

Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to

make lifting and sales arrangements independently.

Because of rounding, some totals may not exactly agree with the sum of their component parts.

Includes 180 billion cubic feet of natural gas consumed in operations, 131 billion cubic feet in subsidiaries, 49 billion cubic feet in equity-accounted entities.

Includes 1,860 billion cubic feet of natural gas in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC.

Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities.

Includes 306 billion cubic feet of natural gas in respect of the 2.30% non-controlling interest in Rosneft including 2 billion cubic feet held through BP’s equity accounted interest in Taas-

Yuryakh Neftegazodobycha.

Total proved gas reserves held as part of our equity interest in Rosneft is 13,522 billion cubic feet, comprising 0 billion cubic feet in Canada, 28 billion cubic feet in Venezuela, 19 billion cubic

feet in Vietnam, 237 billion cubic feet in Egypt and 13,237 billion cubic feet in Russia.

252 BP Annual Report and Form 20-F 2019

Movements in estimated net proved reserves – continued

million†barrels†of†oil†equivalent

Total hydrocarbons

a b

2017

Europe

North

America

South

America

Africa Asia Australasia Total

Rest of

Europe US

Rest of

North

America Russia

Rest of

Asia

Subsidiaries

At 1†January

Developed 254 — 1,990 42 321 462 — 1,433 561 5,063

Undeveloped 338 — 1,012 209 896 420 — 895 299 4,068

592 — 3,002 251 1,217 882 — 2,327 860 9,131

Changes attributable to

Revisions of previous estimates 25 — 157 5 (116) (32) — 451 (24) 467

Improved recovery — — 200 — — 2 — 1 — 203

Purchases of reserves-in-place 8 — 1 — — 92 — — — 100

Discoveries and extensions — — 14 — 143 3 — 254 — 413

Production

e f

(45) — (270) (8) (131) (157) — (145) (57) (812)

Sales of reserves-in-place (11) — — — — — — — — (11)

(23) — 102 (2) (104) (93) — 562 (81) 361

At 31 December

Developed 347 — 2,011 54 505 501 — 1,515 507 5,440

Undeveloped 222 — 1,093 195 608 288 — 1,374 272 4,052

569 — 3,104 248 1,114 790 — 2,889 779 9,492

Equity-accounted entities (BP share)

At 1†January

Developed — 63 — — 588 83 4,168 47 — 4,951

Undeveloped — 75 — — 417 — 3,235 1 — 3,729

— 138 — — 1,005 83 7,404 49 — 8,679

Changes attributable to

Revisions of previous estimates — 5 — — 9 2 439 (1) — 454

Improved recovery — 19 — — 14 — — — — 33

Purchases of reserves-in-place — 42 — — — 41 38 — — 122

Discoveries and extensions — 1 — — 34 — 320 — — 355

Production

— (15) — — (58) (7) (411) (38) — (530)

Sales of reserves-in-place — (7) — — (158) — — — — (165)

— 46 — — (159) 35 386 (39) — 269

At 31 December

i j

Developed — 80 — — 505 93 4,254 9 — 4,941

Undeveloped — 105 — — 341 25 3,536 1 — 4,008

— 184 — — 846 119 7,790 10 — 8,949

Total subsidiaries and equity-accounted entities (BP share)

At 1†January

Developed 254 63 1,990 42 909 545 4,168 1,480 561 10,014

Undeveloped 338 75 1,012 209 1,313 420 3,235 896 299 7,797

592 138 3,002 251 2,222 966 7,404 2,376 860 17,810

At 31†December

Developed 347 80 2,011 54 1,010 595 4,254 1,524 507 10,381

Undeveloped 222 105 1,093 195 949 314 3,536 1,374 272 8,060

569 184 3,104 249 1,959 908 7,790 2,899 779 18,441

Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to

make lifting and sales arrangements independently.

Because of rounding, some totals may not exactly agree with the sum of their component parts.

5.8 billion cubic feet of natural gas = 1†million barrels of oil equivalent.

Proved reserves in the Prudhoe Bay field in Alaska include an estimated 9†million barrels of oil equivalent upon which a net profits royalty will be payable, over the life of the field under the

terms of the BP Prudhoe Bay Royalty Trust.

Excludes NGLs from processing plants in which an interest is held of less than 1†thousand barrels per day for subsidiaries and 2†thousand barrels per day for equity-accounted entities.

Includes 31†million barrels of oil equivalent of natural gas consumed in operations, 23†million barrels of oil equivalent in subsidiaries, 8†million barrels of oil equivalent in equity-accounted

entities.

Includes 335†million barrels of oil equivalent in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC.

Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities.

Includes 391†million barrels of oil equivalent in respect of the non-controlling interest in Rosneft, including 7 mmboe held through BP’s equity accounted interest in Taas-Yuryakh

Neftegazodobycha.

Total proved reserves held as part of our equity interest in Rosneft is 7,864 million barrels of oil equivalent, comprising less than 1 million barrels of oil equivalent in Canada, 64 million barrels

of oil equivalent in Venezuela, 3 million barrels of oil equivalent in Vietnam, 41 million barrels of oil equivalent in Egypt and 7,755 million barrels of oil equivalent in Russia.

BP Annual Report and Form 20-F 2019 253

Standardized measure of discounted future net cash flows and changes therein relating to proved oil and

gas reserves

The following tables set out the standardized measure of discounted future net cash flows, and changes therein, relating to crude oil and

natural gas production from the group’s estimated proved reserves. This information is prepared in compliance with FASB Oil and Gas

Disclosures requirements.

Future net cash flows have been prepared on the basis of certain assumptions which may or may not be realized. These include the timing of

future production, the estimation of crude oil and natural gas reserves and the application of average crude oil and natural gas prices and

exchange rates from the previous 12 months. Furthermore, both proved reserves estimates and production forecasts are subject to revision as

further technical information becomes available and economic conditions change. BP cautions against relying on the information presented

because of the highly arbitrary nature of the assumptions on which it is based and its lack of comparability with the historical cost information

presented in the financial statements.

$ million

2019

Europe North

America

South

America

Africa Asia Australasia Total

Rest of

Europe US

Rest of

North

America

Russia

Rest of

Asia

At 31†December

Subsidiaries

Future cash inflows

28,600 — 135,900 7,400 11,500 21,200 — 135,800 24,000 364,400

Future production cost

13,700 — 59,200 3,400 5,700 6,700 — 53,200 6,100 148,000

Future development cost

1,700 — 16,400 1,200 2,000 1,300 — 16,700 2,700 42,000

Future taxation

5,200 — 8,700 200 1,300 3,300 — 46,000 5,300 70,000

Future net cash flows 8,000 — 51,600 2,600 2,500 9,900 — 19,900 9,900 104,400

10% annual discount

2,700 — 23,100 1,400 600 2,300 — 7,200 4,400 41,700

Standardized measure of discounted

future net cash flows

e f

5,300 — 28,500 1,200 1,900 7,600 — 12,700 5,500 62,700

Equity-accounted entities (BP share)

Future cash inflows

— 10,300 — — 36,800 — 322,000 — — 369,100

Future production cost

— 3,500 — — 14,900 — 222,600 — — 241,000

Future development cost

— 700 — — 3,900 — 21,800 — — 26,400

Future taxation

— 4,700 — — 4,100 — 13,300 — — 22,100

Future net cash flows — 1,400 — — 13,900 — 64,300 — — 79,600

10% annual discount

— 400 — — 8,200 — 37,100 — — 45,700

Standardized measure of discounted

future net cash flows

h i

— 1,000 — — 5,700 — 27,200 — — 33,900

Total subsidiaries and equity-accounted entities

Standardized measure of discounted

future net cash flows

5,300 1,000 28,500 1,200 7,600 7,600 27,200 12,700 5,500 96,600

The following are the principal sources of change in the standardized measure of discounted future net cash flows:

$ million

Subsidiaries

Equity-accounted

entitiesƒ(BPƒshare)

Totalƒsubsidiariesƒand

equity-accounted

entities

Sales and transfers of oil and gas produced, net of production costs (27,400) (8,400) (35,800)

Development costs for the current year as estimated in previous year 9,200 4,100 13,300

Extensions, discoveries and improved recovery, less related costs 3,800 2,600 6,400

Net changes in prices and production cost (28,100) (8,200) (36,300)

Revisions of previous reserves estimates 300 1,100 1,400

Net change in taxation 16,600 2,400 19,000

Future development costs (1,500) (4,300) (5,800)

Net change in purchase and sales of reserves-in-place (1,400) — (1,400)

Addition of 10% annual discount 8,300 4,100 12,400

Total change in the standardized measure during the year

(20,200) (6,600) (26,800)

The marker prices used were Brent $62.74/bbl, Henry Hub $2.58/mmBtu.

Production costs, which include production taxes, and development costs relating to future production of proved reserves are based on the continuation of existing economic conditions.

Future decommissioning costs are included.

Taxation is computed with reference to appropriate year-end statutory corporate income tax rates.

Future net cash flows from oil and natural gas production are discounted at 10% regardless of the group assessment of the risk associated with its producing activities.

In certain situations, revenues and costs are included in the standardized measure of discounted future net cash flows valuation and excluded from the determination of proved reserves and

vice versa. This can result in the standardized measure of discounted future net cash flows being negative.

Non-controlling interests in BP Trinidad and Tobago LLC amounted to $600 million.

The standardized measure of discounted future net cash flows of equity-accounted entities includes standardized measure of discounted future net cash flows of equity-accounted

investments of those entities.

Non-controlling interests in Rosneft amounted to $2,100 million in Russia.

No equity-accounted future cash flows in Africa because proved reserves are received as a result of contractual arrangements, with no associated costs.

Includes future net cash flows for assets held for sale at 31 December 2019.

Total change in the standardized measure during the year includes the effect of exchange rate movements. Exchange rate effects arising from the translation of our share of Rosneft changes

to US dollars are included within ‘Net changes in prices and production cost’.

254 BP Annual Report and Form 20-F 2019

Standardized measure of discounted future net cash flows and changes therein relating to proved oil and

gas reserves‚–‚continued‚

$ million

2018

Europe North

America

South

America

Africa Asia Australasia Total

Rest of

Europe US

Rest of

North

America

Russia

Rest of

Asia

At 31†December

Subsidiaries

Future cash inflows

39,700 — 160,000 4,100 17,500 30,400 — 147,500 30,000 429,200

Future production cost

15,000 — 57,600 3,400 7,200 8,500 — 55,800 7,600 155,100

Future development cost

2,100 — 17,800 1,100 2,800 2,600 — 16,400 2,500 45,300

Future taxation

8,900 — 16,600 — 3,200 5,300 — 51,100 6,900 92,000

Future net cash flows 13,700 — 68,000 (400) 4,300 14,000 — 24,200 13,000 136,800

10% annual discount

5,000 — 29,900 (200) 700 3,300 — 9,400 5,800 53,900

Standardized measure of discounted

future net cash flows

e f

8,700 — 38,100 (200) 3,600 10,700 — 14,800 7,200 82,900

Equity-accounted entities (BP share)

Future cash inflows

— 12,800 — — 38,500 — 356,800 — — 408,100

Future production cost

— 4,200 — — 16,100 — 238,400 — — 258,700

Future development cost

— 800 — — 3,600 — 19,300 — — 23,700

Future taxation

— 5,900 — — 4,400 — 17,700 — — 28,000

Future net cash flows — 1,900 — — 14,400 — 81,400 — — 97,700

10% annual discount

— 600 — — 8,500 — 48,100 — — 57,200

Standardized measure of discounted

future net cash flows

h i

— 1,300 — — 5,900 — 33,300 — — 40,500

Total subsidiaries and equity-accounted entities

Standardized measure of discounted

future net cash flows

8,700 1,300 38,100 (200) 9,500 10,700 33,300 14,800 7,200 123,400

The following are the principal sources of change in the standardized measure of discounted future net cash flows:

$ million

Subsidiaries

Equity-accounted

entities†(BP†share)

Total†subsidiaries†and

equity-accounted

entities

Sales and transfers of oil and gas produced, net of production costs (18,800) (8,000) (26,800)

Development costs for the current year as estimated in previous year 8,500 4,300 12,800

Extensions, discoveries and improved recovery, less related costs 5,800 3,300 9,100

Net changes in prices and production cost 41,000 13,100 54,100

Revisions of previous reserves estimates (2,100) 2,000 (100)

Net change in taxation (17,000) (4,600) (21,600)

Future development costs 1,000 (3,500) (2,500)

Net change in purchase and sales of reserves-in-place 7,600 400 8,000

Addition of 10% annual discount 5,200 3,100 8,300

Total change in the standardized measure during the year

31,200 10,100 41,300

The marker prices used were Brent $71.43/bbl, Henry Hub $3.10/mmBtu.

Production costs, which include production taxes, and development costs relating to future production of proved reserves are based on the continuation of existing economic conditions.

Future decommissioning costs are included. 2018 comparative for Russia equity-accounted entity future production cost has been restated from $232,100 million to maintain consistency

with 2019 presentation.

Taxation is computed with reference to appropriate year-end statutory corporate income tax rates. 2018 comparative for Russia equity-accounted entity future taxation has been restated

from $24,000 million to maintain consistency with 2019 presentation.

Future net cash flows from oil and natural gas production are discounted at 10% regardless of the group assessment of the risk associated with its producing activities.

In certain situations, revenues and costs are included in the standardized measure of discounted future net cash flows valuation and excluded from the determination of proved reserves and

vice versa. This can result in the standardized measure of discounted future net cash flows being negative.

Non-controlling interests in BP Trinidad and Tobago LLC amounted to $1,100 million.

The standardized measure of discounted future net cash flows of equity-accounted entities includes standardized measure of discounted future net cash flows of equity-accounted

investments of those entities.

Non-controlling interests in Rosneft amounted to $2,500 million in Russia.

No equity-accounted future cash flows in Africa because proved reserves are received as a result of contractual arrangements, with no associated costs.

Total change in the standardized measure during the year includes the effect of exchange rate movements. Exchange rate effects arising from the translation of our share of Rosneft changes

to US dollars are included within ‘Net changes in prices and production cost’.

BP Annual Report and Form 20-F 2019 255

Standardized measure of discounted future net cash flows and changes therein relating to proved oil and

gas reserves‚–‚continued

$ million

2017

Europe North

America

South

America

Africa Asia Australasia Total

Rest of

Europe US

Rest of

North

America

Russia

Rest of

Asia

At 31†December

Subsidiaries

Future cash inflows

26,300 — 99,200 7,100 15,200 27,000 — 118,800 26,200 319,800

Future production cost

13,800 — 46,700 4,100 7,100 8,600 — 52,600 8,400 141,300

Future development cost

1,700 — 12,100 1,100 2,400 3,400 — 18,200 3,200 42,100

Future taxation

4,200 — 6,500 — 1,700 3,800 — 33,200 4,800 54,200

Future net cash flows 6,600 — 33,900 1,900 4,000 11,200 — 14,800 9,800 82,200

10% annual discount

2,100 — 13,100 1,100 500 3,400 — 5,500 4,800 30,500

Standardized measure of discounted

future net cash flows

4,500 — 20,800 800 3,500 7,800 — 9,300 5,000 51,700

Equity-accounted entities (BP share)

Future cash inflows

— 9,000 — — 32,900 — 205,100 400 — 247,400

Future production cost

— 4,100 — — 15,500 — 114,900 300 — 134,800

Future development cost

— 800 — — 3,400 — 17,600 100 — 21,900

Future taxation

— 3,100 — — 3,100 — 12,400 — — 18,600

Future net cash flows — 1,000 — — 10,900 — 60,200 — — 72,100

10% annual discount

— 400 — — 6,400 — 34,900 — — 41,700

Standardized measure of discounted

future net cash flows

g h

— 600 — — 4,500 — 25,300 — — 30,400

Total subsidiaries and equity-accounted entities

Standardized measure of discounted

future net cash flows

4,500 600 20,800 800 8,000 7,800 25,300 9,300 5,000 82,100

The following are the principal sources of change in the standardized measure of discounted future net cash flows:

$ million

Subsidiaries

Equity-accounted

entities†(BP†share)

Total†subsidiaries†and

equity-accounted

entities

Sales and transfers of oil and gas produced, net of production costs (12,800) (5,500) (18,300)

Development costs for the current year as estimated in previous year 9,800 4,200 14,000

Extensions, discoveries and improved recovery, less related costs 2,300 1,300 3,600

Net changes in prices and production cost 33,100 7,300 40,400

Revisions of previous reserves estimates 2,800 1,000 3,800

Net change in taxation (12,500) (1,500) (14,000)

Future development costs 3,000 (4,600) (1,600)

Net change in purchase and sales of reserves-in-place 800 (600) 200

Addition of 10% annual discount 2,300 2,600 4,900

Total change in the standardized measure during the year

28,800 4,200 33,000

The marker prices used were Brent $54.36/bbl, Henry Hub $2.96/mmBtu.

Production costs, which include production taxes, and development costs relating to future production of proved reserves are based on the continuation of existing economic conditions.

Future decommissioning costs are included.

Taxation is computed with reference to appropriate year-end statutory corporate income tax rates.

Future net cash flows from oil and natural gas production are discounted at 10% regardless of the group assessment of the risk associated with its producing activities.

Non-controlling interests in BP Trinidad and Tobago LLC amounted to $1,100 million.

The standardized measure of discounted future net cash flows of equity-accounted entities includes standardized measure of discounted future net cash flows of equity-accounted

investments of those entities.

Non-controlling interests in Rosneft amounted to $1,963 million in Russia.

No equity-accounted future cash flows in Africa because proved reserves are received as a result of contractual arrangements, with no associated costs.

Total change in the standardized measure during the year includes the effect of exchange rate movements. Exchange rate effects arising from the translation of our share of Rosneft to US

dollars are included within ‘Net changes in prices and production cost’.

256 BP Annual Report and Form 20-F 2019

Operational and statistical information

The following tables present operational and statistical information related to production, drilling, productive wells and acreage. Figures include

amounts attributable to assets held for sale.

Crude oil and natural gas production

The following table shows crude oil, natural gas liquids and natural gas production for the years ended 31†December†2019, 2018 and 2017.

Production for the year

a b

Europe North

America

South

America

Africa Asia Australasia Total

Rest of

Europe US

Rest of

North

America

Russia

Rest of

Asia

Subsidiaries

Crude oil

thousand barrels per day

2019 100 — 400 24 7 156 — 343 17 1,046

2018 101 — 385 24 7 204 — 313 17 1,051

2017 80 — 370 20 12 241 — 325 17 1,064

Natural gas liquids

thousand barrels per day

2019 3 — 81 — 9 8 — — 2 104

2018 5 — 60 — 9 11 — — 2 88

2017 6 — 56 — 10 10 — — 2 85

Natural gas

million cubic feet per day

2019 129 — 2,358 2 1,977 1,138 — 976 786 7,366

2018 152 — 1,900 7 2,136 1,061 — 826 819 6,900

2017 182 — 1,659 9 1,936 949 — 371 783 5,889

Equity-accounted entities (BP share)

Crude oil

thousand barrels per day

2019 — 35 — — 56 1 955 — — 1,047

2018 — 34 — — 55 1 933 16 — 1,040

2017 — 31 — — 63 1 905 99 — 1,099

Natural gas liquids

thousand barrels per day

2019 — 2 — — 1 8 3 — — 14

2018 — 2 — — — 6 4 — — 12

2017 — 2 — — — 6 4 — — 12

Natural gas

million cubic feet per day

2019 — 56 — — 314 87 1,279 — — 1,736

2018 — 59 — — 335 80 1,286 — — 1,760

2017 — 53 — — 418 77 1,308 — — 1,855

Production excludes royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make

lifting and sales arrangements independently.

Because of rounding, some totals may not exactly agree with the sum of their component parts.

Amounts reported for Russia include BP’s share of Rosneft worldwide activities, including insignificant amounts outside Russia.

All of the oil and liquid production from Canada is bitumen.

Crude oil includes condensate.

Natural gas production excludes gas consumed in operations.

BP Annual Report and Form 20-F 2019 257

Operational and statistical information – continued

Productive oil and gas wells and acreage

The following tables show the number of gross and net productive oil and natural gas wells and total gross and net developed and

undeveloped oil and natural gas acreage in which the group and its equity-accounted entities had interests as at 31†December†2019. A ‘gross’

well or acre is one in which a whole or fractional working interest is owned, while the number of ‘net’ wells or acres is the sum of the whole or

fractional working interests in gross wells or acres. Productive wells are producing wells and wells capable of production. Developed acreage is

the acreage within the boundary of a field, on which development wells have been drilled, which could produce the reserves; while

undeveloped acres are those on which wells have not been drilled or completed to a point that would permit the production of commercial

quantities, whether or not such acres contain proved reserves.

Europe North

America

South

America

Africa Asia Australasia Total

Rest of

Europe US

Rest of

North

America

Russia

Rest of

Asia

Number of productive wells at 31 December 2019

Oil wells

–†gross 117 80 2,775 177 5,526 290 66,696 2,067 12 77,740

– net 70 24 1,152 48 2,528 65 13,278 477 2 17,644

Gas wells

–†gross 36 1 18,552 238 1,119 220 447 129 78 20,820

– net 7 — 8,811 118 401 91 92 60 16 9,596

Oil and natural gas acreage at 31 December 2019

thousands of acres

Developed –†gross 75 81 6,232 143 1,354 823 7,709 1,322 173 17,912

– net 44 24 3,658 62 361 287 1,377 292 41 6,146

Undeveloped

–†gross 2,851 150 5,311 14,953 23,892 51,105 439,848 9,793 4,022 551,925

– net 1,594 45 3,749 7,890 8,456 33,683 84,689 2,430 1,889 144,425

Based on information received from Rosneft as at 31†December†2019.

Because of rounding, some totals may not exactly agree with the sum of their component parts.

Includes approximately 6,916 gross (1,314 net) multiple completion wells (more than one formation producing into the same well bore).

Includes approximately 2,618 gross (1,265 net) multiple completion wells. If one of the multiple completions in a well is an oil completion, the well is classified as an oil well.

Undeveloped acreage includes leases and concessions.

Net oil and gas wells completed or abandoned

The following table shows the number of net productive and dry exploratory and development oil and natural gas wells completed or

abandoned in the years indicated by the group and its equity-accounted entities. Productive wells include wells in which hydrocarbons were

encountered and the drilling or completion of which, in the case of exploratory wells, has been suspended pending further drilling or evaluation.

A dry well is one found to be incapable of producing hydrocarbons in sufficient quantities to justify completion.

Europe North

America

South

America

Africa Asia Australasia Total

Rest of

Europe US

Rest of

North

America

Russia

Rest of

Asia

2019

Exploratory

Productive — 0.2 0.8 0.8 3.5 2.3 11.6 5.2 — 24.4

Dry 1.0 0.3 1.6 0.5 1.1 0.3 0.5 0.4 0.2 5.9

Development

Productive 1.7 2.4 193.0 0.2 110.7 6.0 230.8 49.6 0.4 594.8

Dry — 0.3 10.0 — 0.6 — — 1.0 — 11.9

2018

Exploratory

Productive 0.3 — 1.7 — 2.0 — 15.0 5.0 — 24.0

Dry — — — 0.5 2.0 2.4 — — — 4.9

Development

Productive 1.4 0.6 142.7 5.0 103.9 14.4 137.3 53.5 1.3 460.1

Dry — — 6.8 — 3.6 — — 2.6 — 13.0

2017

Exploratory

Productive 2.8 0.1 1.5 1.2 3.2 2.6 9.4 1.4 — 22.2

Dry 2.4 — — — — 2.9 — 1.0 — 6.3

Development

Productive 2.5 0.5 124.0 8.0 103.7 16.5 282.7 43.6 1.1 582.6

Dry — — 0.5 — 1.6 2.1 — 0.8 — 5.0

Because of rounding, some totals may not exactly agree with the sum of their component parts.

258 BP Annual Report and Form 20-F 2019

Operational and statistical information – continued

Drilling and production activities in progress

The following table shows the number of exploratory and development oil and natural gas wells in the process of being drilled by the group and

its equity-accounted entities as of 31†December†2019. Suspended development wells and long-term suspended exploratory wells are also

included in the table.

Europe North

America

South

America

Africa Asia Australasia Total

Rest of

Europe US

Rest of

North

America

Russia

Rest of

Asia

At 31 December 2019

Exploratory

Gross — — 8.0 — 2.0 4.0 — 5.0 — 19.0

Net — — 4.9 — 0.5 1.6 — 0.5 — 7.5

Development

Gross 6.0 3.6 213.0 6.0 13.0 26.0 — 216.0 2.0 485.6

Net 2.0 1.1 140.0 3.0 4.1 14.5 — 29.1 0.8 194.6

Because of rounding, some totals may not exactly agree with the sum of their component parts.

BP Annual Report and Form 20-F 2019 259

Parent company financial statements of BP p.l.c.

The parent company financial statements of BP p.l.c. on pages 260-296 do not form part of BP’s Annual Report on Form 20-F as filed with

the†SEC.

260 BP Annual Report and Form 20-F 2019

Company balance sheet

At 31†December $ million

Note 2019 2018

Non-current assets

Investments 2 166,256 166,271

Receivables 3 2,771 2,600

Defined benefit pension plan surpluses 4 6,588 5,473

175,615 174,344

Current assets

Receivables 3 135 151

Cash and cash equivalents — 13

135 164

Total assets 175,750 174,508

Current liabilities

Payables 5 18,007 14,665

Non-current liabilities

Payables 5 31,927 31,800

Deferred tax liabilities 6 2,293 1,907

Defined benefit pension plan deficits 4 202 184

34,422 33,891

Total liabilities 52,429 48,556

Net assets 123,321 125,952

Capital and reserves

Profit and loss account

Brought forward 96,430 101,078

Profit for the year 4,470 1,931

Other movements (8,829) (6,579)

92,071 96,430

Called-up share capital 7 5,404 5,402

Share premium account 12,417 12,305

Other capital and reserves 13,429 11,815

123,321 125,952

See Statement of changes in equity on page 261 for further information.

The financial statements on pages 260-296 were approved and signed by the group chief executive on 18†March†2020 having been duly

authorized to do so by the board of directors:

B Looney Chief executive officer

Company statement of changes in equity

$ million

Share capital

premium

account

Capital

redemption

reserve

Merger

reserve

Treasury

Foreign

currency

translation

reserve

Profit and

loss account Total equity

At 1 January 2019 5,402 12,305 1,439 26,509 (15,767) (366) 96,430 125,952

Profit for the year — — — — — — 4,470 4,470

Other comprehensive income — — — — — 200 401 601

Total comprehensive income — — — — — 200 4,871 5,071

Dividends 52 (52) — — — — (6,929) (6,929)

Repurchases of ordinary share capital (59) — 59 — — — (1,511) (1,511)

Share-based payments, net of tax 9 164 — — 1,355 — (790) 738

At 31 December 2019 5,404 12,417 1,498 26,509 (14,412) (166) 92,071 123,321

At 1 January 2018 5,343 12,147 1,426 26,509 (16,958) (70) 101,078 129,475

Profit for the year — — — — — — 1,931 1,931

Other comprehensive income — — — — — (296) 1,178 882

Total comprehensive income — — — — — (296) 3,109 2,813

Dividends 49 (49) — — — — (6,699) (6,699)

Repurchases of ordinary share capital (13) — 13 — — — (355) (355)

Share-based payments, net of tax 23 207 — — 1,191 — (703) 718

At 31 December 2018 5,402 12,305 1,439 26,509 (15,767) (366) 96,430 125,952

See Note 8 for further information.

The parent company financial statements of BP p.l.c. on pages 260-296 do not form part of BP’s Annual Report on Form 20-F as filed with

the†SEC.

BP Annual Report and Form 20-F 2019 261

Notes on financial statements

The parent company financial statements of BP p.l.c. on pages 260-296 do not form part of BP’s Annual Report on Form 20-F as filed with

the†SEC.

262 BP Annual Report and Form 20-F 2019

1. Significant accounting policies, judgements, estimates and assumptions

Authorization of financial statements and statement of compliance with Financial Reporting Standard 101 ‘Reduced Disclosure

Framework’ (FRS 101)

The financial statements of BP p.l.c. for the year ended 31†December†2019 were approved and signed by the chief executive officer on

18†March†2020 having been duly authorized to do so by the board of directors. The company meets the definition of a qualifying entity under

Financial Reporting Standard 100 ‘Application of Financial Reporting Requirements’ (FRS 100) issued by the Financial Reporting Council.

Accordingly, these financial statements have been prepared in accordance with FRS 101 and in accordance with the provisions of the UK

Companies Act 2006.

Basis of preparation

The financial statements have been prepared on a going concern basis and in accordance with the Companies Act 2006 and applicable UK

accounting standards.

The financial statements have been prepared under the historical cost convention. Historical cost is generally based on the fair value of the

consideration given in exchange for the assets.

As permitted by FRS 101, the company has taken advantage of the disclosure exemptions available in relation to:

(a) the requirements of IFRS 7 ‘Financial Instruments: Disclosures’;

(b) the requirements of paragraphs 10(d), 10(f), 16, 38A, 38B, 38C, 38D, 40A, 40B, 40C, 40D, 111 and 134 to 136 of IAS 1 ‘Presentation of

Financial Statements’;

(c) the requirements in paragraph 38 of IAS 1 'Presentation of Financial Statements' to present comparative information in respect of

paragraph 79(a)(iv) of IAS 1.

(d) the requirements of IAS 7 ‘Statement of Cash Flows’;

(e) the requirements of paragraphs 30 and 31 of IAS 8 ‘Accounting Policies, Changes in Accounting Estimates and Errors’ in relation to

standards not yet effective;

(f) the requirements of paragraphs 17 and 18A of IAS 24 ‘Related Party Disclosures’;

(g) the requirements of IAS 24 ‘Related Party Disclosures’ to disclose related party transactions entered into between two or more members

of a group, provided that any subsidiary which is a party to the transaction is wholly owned by such a member; and

(h) the requirement of the second sentence of paragraph 110 and paragraphs 113(a), 114,115, 118, 119(a) to (c), 120 to 127 and 129 of IFRS 15

'Revenue from Contracts with Customers'.

Where required, equivalent disclosures are given in the consolidated financial statements of BP p.l.c.

As permitted by Section†408 of the Companies Act 2006, the income statement of the company is not presented as part of these financial

statements.

The financial statements are presented in US dollars and all values are rounded to the nearest million dollars ($ million), except where

otherwise indicated.

Significant accounting policies: use of judgements, estimates and assumptions

Inherent in the application of many of the accounting policies used in preparing the financial statements is the need for management to make

judgements, estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and

liabilities, and the reported amounts of revenues and expenses. Actual outcomes could differ from the estimates and assumptions used. The

accounting judgements and estimates that have a significant impact on the results of the company are set out in boxed text below, and should

be read in conjunction with the information provided in the Notes on financial statements.

Investments

Investments in subsidiaries are recorded at cost. The company assesses investments for impairment whenever events or changes in

circumstances indicate that the carrying amount may not be recoverable. If any such indication of impairment exists, the company makes an

estimate of its recoverable amount. Where the carrying amount of an investment exceeds its recoverable amount, the investment is

considered impaired and is written down to its recoverable amount. Where these circumstances have reversed, the impairment previously

made is reversed to the extent of the original cost of the investment.

Foreign currency translation

The functional and presentation currency of the financial statements is US dollars. Transactions in foreign currencies are initially recorded in the

functional currency by applying the spot exchange rate on the date of the transaction. Monetary assets and liabilities denominated in foreign

currencies are retranslated into the functional currency at the spot exchange rate on the balance sheet date. Any resulting exchange

differences are included in the income statement. Non-monetary assets and liabilities, other than those measured at fair value, are not

retranslated subsequent to initial recognition.

Exchange adjustments arising when the opening net assets and the profits for the year retained by a non-US dollar functional currency branch

are translated into US dollars are recognized in a separate component of equity and reported in other comprehensive income. Income

statement transactions are translated into US dollars using the average exchange rate for the reporting period.

Financial guarantees

The company enters into financial guarantee contracts with its subsidiaries. At the inception of a financial guarantee contract, a liability is

recognized initially at fair value and then subsequently at the higher of the estimated loss and amortized cost. Where a guarantee is issued for

a premium, a receivable of an amount equal to the liability is initially recognized. Subsequently, the liability and receivable reduce by the amount

of consideration received, which is recognized in the income statement. Where a guarantee is issued without a premium, the fair value is

recognized as additional investment in the entity to which the guarantee relates.

1. Significant accounting policies, judgements, estimates and assumptions – continued

Share-based payments

Equity-settled transactions

The cost of equity-settled transactions with employees of the company and other members of the group is measured by reference to the fair

value of the equity instruments on the date on which they are granted and is recognized as an expense over the vesting period, which ends on

the date on which the employees become fully entitled to the award. A corresponding credit is recognized within equity. Fair value is

determined by using an appropriate, widely used, valuation model. In valuing equity-settled transactions, no account is taken of any vesting

conditions, other than conditions linked to the price of the shares of the company (market conditions). Non-vesting conditions, such as the

condition that employees contribute to a savings-related plan, are taken into account in the grant-date fair value, and failure to meet a non-

vesting condition, where this is within the control of the employee, is treated as a cancellation and any remaining unrecognized cost is

expensed.

For other equity-settled share-based payment transactions, the goods or services received and the corresponding increase in equity are

measured at the fair value of the goods or services received, unless their fair value cannot be reliably estimated. If the fair value of the goods

and services received cannot be reliably estimated, the transaction is measured by reference to the fair value of the equity instruments

granted.

Cash-settled transactions

The cost of cash-settled transactions is recognized as an expense over the vesting period, measured by reference to the fair value of the

corresponding liability which is recognized on the balance sheet. The liability is remeasured at fair value at each balance sheet date until

settlement, with changes in fair value recognized in the income statement.

Pensions

The defined benefit pension plans are plans that share risks between entities under common control. †In each instance BP p.l.c. is the principal

employer and carries the whole plan surplus or deficit on its balance sheet. The cost of providing benefits under the company’s defined benefit

plans is determined separately for each plan using the projected unit credit method, which attributes entitlement to benefits to the current

period to determine current service cost and to the current and prior periods to determine the present value of the defined benefit obligation.

Past service costs, resulting from either a plan amendment or a curtailment (a reduction in future obligations as a result of a material reduction

in the plan membership), are recognized immediately when the company becomes committed to a change.

Net interest expense relating to pensions, which is recognized in the income statement, represents the net change in present value of plan

obligations and the value of plan assets resulting from the passage of time, and is determined by applying the discount rate to the present

value of the benefit obligation at the start of the year, and to the fair value of plan assets at the start of the year, taking into account expected

changes in the obligation or plan assets during the year.

Remeasurements of the defined benefit liability and asset, comprising actuarial gains and losses, and the return on plan assets (excluding

amounts included in net interest described above) are recognized within other comprehensive income in the period in which they occur and

are not subsequently reclassified to profit and loss.

The defined benefit pension plan surplus or deficit recognized on the balance sheet for each plan comprises the difference between the

present value of the defined benefit obligation (using a discount rate based on high quality corporate bonds) and the fair value of plan assets

out of which the obligations are to be settled directly. Fair value is based on market price information and, in the case of quoted securities, is

the published bid price. Defined benefit pension plan surpluses are only recognized to the extent they are recoverable, typically by way of

refund.

Contributions to defined contribution plans are recognized in the income statement in the period in which they become payable.

Significant estimate: pensions

Accounting for defined benefit pensions involves making significant estimates when measuring the company's pension plan surpluses and

deficits. These estimates require assumptions to be made about many uncertainties.

Pension assumptions are reviewed by management at the end of each year. These assumptions are used to determine the projected benefit

obligation at the year end and hence the surpluses and deficits recorded on the company’s balance sheet, and pension expense for the

following year. The assumptions used are provided in Note 4.

The assumptions that are the most significant to the amounts reported are the discount rate, inflation rate, salary growth and mortality levels.

Assumptions about these variables are based on the environment in each country. The assumptions used vary from year to year, with

resultant effects on future net income and net assets. Changes to some of these assumptions, in particular the discount rate and inflation

rate, could result in material changes to the carrying amounts of the company’s pension obligations within the next financial year for the UK

plan. Any differences between these assumptions and the actual outcome will also affect future net income and net assets.

The values ascribed to these assumptions and a sensitivity analysis of the impact of changes in the assumptions on the benefit expense and

obligation used are provided in Note 4.

Income taxes

Income tax expense represents the sum of current tax and deferred tax.

Income tax is recognized in the income statement, except to the extent that it relates to items recognized in other comprehensive income or

directly in equity, in which case the related tax is recognized in other comprehensive income or directly in equity.

Current tax is based on the taxable profit for the period. Taxable profit differs from net profit as reported in the income statement because it is

determined in accordance with the rules established by the applicable taxation authorities. It therefore excludes items of income or expense

that are taxable or deductible in other periods as well as items that are never taxable or deductible. The company’s liability for current tax is

calculated using tax rates and laws that have been enacted or substantively enacted by the balance sheet date.

Deferred tax is provided, using the liability method, on temporary differences at the balance sheet date between the tax bases of assets and

liabilities and their carrying amounts for financial reporting purposes. Deferred tax liabilities are recognized for taxable temporary differences.

Deferred tax assets are only recognized to the extent that it is probable that they will be realized in the future.

The parent company financial statements of BP p.l.c. on pages 260-296 do not form part of BP’s Annual Report on Form 20-F as filed with

the†SEC.

BP Annual Report and Form 20-F 2019 263

1. Significant accounting policies, judgements, estimates and assumptions – continued

Deferred tax assets and liabilities are measured at the tax rates that are expected to apply in the period when the asset is realized or the

liability is settled, based on tax rates (and tax laws) that have been enacted or substantively enacted at the balance sheet date. Deferred tax

assets and liabilities are not discounted. See note 6 for further details.

Financial assets

The company determines the classification of its financial assets at initial recognition. Financial assets are recognized initially at fair value,

normally being the transaction price plus directly attributable transaction costs. The subsequent measurement of financial assets depends on

their classification, as set out below. The company derecognizes financial assets when the contractual rights to the cash flows expire or the

rights to receive cash flows have been transferred to a third party along with substantially all of the risks and rewards or control of the asset.

Financial assets measured at amortized cost

Financial assets are classified as measured at amortized cost when they are held in a business model the objective of which is to collect contractual

cash flows and the contractual cash flows represent solely payments of principal and interest. Such assets are carried at amortized cost using

the effective interest method if the time value of money is significant. Gains and losses are recognized in profit or loss when the assets are

derecognized or impaired and when interest is recognized using the effective interest method. This category of financial assets includes trade

and other receivables.

Cash equivalents

Cash equivalents are short-term highly liquid investments that are readily convertible to known amounts of cash, are subject to insignificant risk

of changes in value and generally have a maturity of three months or less from the date of acquisition. Cash equivalents are classified as

financial assets measured at amortized cost.

Financial liabilities

All financial liabilities held by the company are classified as financial liabilities measured at amortized cost. Financial liabilities include other

payables, accruals, and finance debt. The company determines the classification of its financial liabilities at initial recognition.

Financial liabilities measured at amortized cost

All financial liabilities are initially recognized at fair value, net of directly attributable transaction costs. For interest-bearing loans and borrowings

this is typically equivalent to the fair value of the proceeds received, net of issue costs associated with the borrowing.

After initial recognition, financial liabilities are subsequently measured at amortized cost using the effective interest method. Amortized cost is

calculated by taking into account any issue costs and any discount or premium on settlement. Gains and losses arising on the repurchase,

settlement or cancellation of liabilities are recognized in interest and other income and finance costs respectively.

Impact of new International Financial Reporting Standards

The company adopted IFRS 16 ‘Leases’, which replaced IAS 17 ‘Leases’ and IFRIC 4 ‘Determining whether an arrangement contains a lease’,

with effect from 1 January 2019. The adoption of IFRS 16 has had no material impact on the company's financial statements. There are no other

new or amended standards or interpretations adopted during the year that have a significant impact on the financial statements.

The parent company financial statements of BP p.l.c. on pages 260-296 do not form part of BP’s Annual Report on Form 20-F as filed with

the†SEC.

264 BP Annual Report and Form 20-F 2019

2. Investments

$ million

Subsidiaries Associates

Shares Shares Total

Cost

At 1 January 2019 166,302 2 166,304

Additions — — —

Disposals (15) — (15)

At 31 December 2019 166,287 2 166,289

Amounts provided

At 1 January 2019 33 — 33

At 31 December 2019 33 — 33

Cost

At 1 January 2018 166,307 2 166,309

Additions 270 — 270

Disposals (275) — (275)

At 31 December 2018 166,302 2 166,304

Amounts provided

At 1 January 2018 33 — 33

At 31 December 2018 33 — 33

At 31 December 2019 166,254 2 166,256

At 31 December 2018 166,269 2 166,271

The more important subsidiaries of the company at 31†December†2019 and the percentage holding of ordinary share capital (to the nearest

whole number) are set out below. For a full list of related undertakings see Note 14.

Subsidiaries % Country†of†incorporation Principal†activities

International

BP Global Investments 100 England & Wales Investment holding

BP International 100 England & Wales Integrated oil operations

Burmah Castrol 100 Scotland Lubricants

Canada

BP Holdings Canada 100 England & Wales Investment holding

BP Holdings North America 100 England & Wales Investment holding

The carrying value of the investment in BP International Limited at 31†December†2019 was $76,152 million (2018 $76,152 million).

The parent company financial statements of BP p.l.c. on pages 260-296 do not form part of BP’s Annual Report on Form 20-F as filed with

the†SEC.

BP Annual Report and Form 20-F 2019 265

3. Receivables€

$ million

2019 2018

Current Non-current Current Non-current

Amounts receivable from subsidiaries

134 2,771 148 2,600

Amounts receivable from associates 1 — 4 —

Other receivables — — (1) —

135 2,771 151 2,600

Non-current receivables includes a promissory note issued by BP (Abu Dhabi) Limited in 2016 in consideration for the issue of BP p.l.c. ordinary shares to the government of Abu Dhabi.

4. Pensions

The primary pension arrangement is a funded final salary pension plan in the UK under which retired employees draw the majority of their

benefit as an annuity. This pension plan is governed by a corporate trustee whose board is composed of four member-nominated directors, four

company-nominated directors, an independent director, and an independent chairman nominated by the company. The trustee board is required

by law to act in the best interests of the plan participants and is responsible for setting certain policies, such as investment policies of the plan.

The plan is closed to new joiners but remains open to ongoing accrual for current members. New joiners are eligible for membership of a

defined contribution plan.

The level of contributions to funded defined benefit plans is the amount needed to provide adequate funds to meet pension obligations as they

fall due. During 2019 the aggregate level of contributions was $236 million (2018 $490 million). The aggregate level of contributions in 2020 is

expected to be approximately $255 million, and includes contributions we expect to be required to make by law or under contractual

agreements, as well as an allowance for discretionary funding.

4. Pensions – continued

For the primary UK plan there is a funding agreement between the company and the trustee. On an annual basis the latest funding position is

reviewed and a schedule of contributions is agreed covering the next five years. Contractually committed funding amounted to $1,276 million

at 31†December†2019, all of which relates to future service. The surplus relating to the primary UK pension plan is recognized on the balance

sheet on the basis that the company is entitled to a refund of any remaining assets once all members have left the plan.

The obligation and cost of providing the pension benefits is assessed annually using the projected unit credit method. The date of the most

recent actuarial review was 31 December 2019. The principal plans are subject to a formal actuarial valuation every three years in the UK. The

most recent formal actuarial valuation of the main pension plan was as at 31 December 2017.

The material financial assumptions used for estimating the benefit obligations of the plans are set out below. The assumptions are reviewed by

management at the end of each year and are used to evaluate accrued pension benefits at 31 December and pension expense for the following

year.

Financial assumptions used to determine benefit obligation %

2019 2018

Discount rate for pension plan liabilities 2.1 2.9

Rate of increase in salaries 3.4 3.8

Rate of increase for pensions in payment 2.7 3.0

Rate of increase in deferred pensions 2.7 3.0

Inflation for pension plan liabilities 2.7 3.1

Financial assumptions used to determine benefit expense %

2019 2018

Discount rate for pension plan service costs 3.0 2.6

Discount rate for pension plan other finance expense 2.9 2.5

Inflation for pension plan service costs 3.1 3.1

The discount rate assumption is based on third-party AA corporate bond indices and we use yields that reflect the maturity profile of the

expected benefit payments. The inflation rate assumption is based on the difference between the yields on index-linked and fixed-interest long-

term government bonds. The inflation assumption is used to determine the rate of increase for pensions in payment and the rate of increase in

deferred pensions.

The assumption for the rate of increase in salaries is based on our inflation assumption plus an allowance for expected long-term real salary

growth. This comprises of an allowance for promotion-related salary growth of 0.7%.

In addition to the financial assumptions, we regularly review the demographic and mortality assumptions. The mortality assumptions reflect

best practice in the UK and have been chosen with regard to the latest available published tables adjusted to reflect the experience of the

plans and an extrapolation of past longevity improvements into the future. For the main pension plan the mortality assumptions are as follows:

Mortality assumptions Years

2019 2018

Life expectancy at age 60 for a male currently aged 60 27.3 27.4

Life expectancy at age 60 for a male currently aged 40 28.9 28.9

Life expectancy at age 60 for a female currently aged 60 28.7 28.8

Life expectancy at age 60 for a female currently aged 40 30.5 30.6

The assets of the primary plan are held in a trust, the primary objective of which is to accumulate pools of assets sufficient to meet the

obligations of the plan. The assets of the trusts are invested in a manner consistent with fiduciary obligations and principles that reflect current

practices in portfolio management.

A significant proportion of the assets are held in equities, owing to a higher expected level of return over the long term of such assets with an