BP p.l.c. CORRESP Correspondence with SEC

BP HAS CLAIMED CONFIDENTIAL TREATMENT OF

PORTIONS OF THIS LETTER IN ACCORDANCE WITH

17 C.F.R. § 200.83

BP p.l.c.

1 St James’s Square

London SW1Y 4PD

United Kingdom

Switchboard: +44 (0)20 7496 4000

Central Fax: +44 (0)20 7496 4630

Telex: 888811 BPLDN X G

14 December 2010

Mr. H. Roger Schwall,

Assistant Director, Division of Corporation Finance,

Securities and Exchange Commission,

100 F Street, N.E.,

Washington, D.C. 20549-7010

	Re:	BP p.l.c.
		Form 20-F for the Fiscal Year Ended 31 December 2009
		Filed 5 March 2010
		File No. 001-06262

Dear Mr. Schwall:

I refer to your letter to David Jackson, BP company secretary, dated 23 November 2010 setting forth comments of the Staff of the Commission (the “Staff”) relating to the Form 20-F of BP p.l.c. (“BP”) for the fiscal year ended 31 December 2009 (the “Form 20-F”) (File No. 001-06262).

We are currently in the process of preparing our financial statements and related disclosures for the fourth quarter and year ending 31 December 2010. We expect to finalize these results towards the end of January 2011 for release to the market on 1 February 2011.

In accordance with what we understand to be the Staff’s policy with respect to requests for confidential treatment of responses to the Staff’s comment letters, we are submitting two separate letters in response to the Staff’s comments. Concurrent with the submission to you of this letter, confidential treatment of portions of this letter is being requested under the Commission’s rules in accordance with 17 C.F.R. § 200.83. Accordingly, a separate version of this response letter containing confidential information of BP is being filed by hand and not via EDGAR. This letter being submitted via EDGAR does not contain confidential information of BP and therefore is not submitted on a confidential basis.

To facilitate the Staff’s review, we have included in this letter the captions and numbered comments from the Staff’s comment letter in italicized text, and have provided our responses immediately following each comment.

BP HAS CLAIMED CONFIDENTIAL TREATMENT OF PORTIONS OF

THIS LETTER IN ACCORDANCE WITH 17 C.F.R. § 200.83

Form 6-K furnished July 28, 2010

Note 2. Significant event in the period – Gulf of Mexico oil spill, page 26

We note you have accounted for your $20 billion escrow account under IFRIC 5. It appears that this escrow account may be used to settle individual and business claims resolved and settled by the Gulf Coast Claims Facility (GCCF), amounts owed pursuant to final judgments and settlement agreements pertaining to damage claims that are resolved outside of the GCCF process, natural resource damage costs, and state and local government response costs. Tell us in detail how you determined the applicability of IFRIC 5 considering the various types of expenditures that may be made from this escrow account.

Response:

At the request of BP Exploration & Production Inc. (“BPEP”) and the US President, the Gulf Coast Claims Facility (the “GCCF”) was established by Kenneth R. Feinberg to independently administer and settle individual and business claims asserted against BP as a result of the explosion at the Deepwater Horizon rig and consequent spillage of oil into the Gulf of Mexico. The GCCF is currently administered by Mr. Feinberg and certain subcontractors, including, but not limited to, Garden City Group, Inc. and the law firm of Feinberg Rozen, LLP. BPEP has no role in, or authority over, the operations of the GCCF and is independent of, and has no control over, Mr. Feinberg, Garden City Group, Inc., Feinberg Rozen, LLP and all other known contractors involved in the administration of the GCCF.

To support its obligations to pay claims resolved and settled by the GCCF and certain other claims arising from the oil spill, BPEP established the Deepwater Horizon Oil Spill Trust (the “Trust”) pursuant to a Trust Agreement (the “Trust Agreement”) dated as of 6 August 2010 among BPEP, the Corporate Trustee for the Trust (Citigroup Trust-Delaware, N.A.) and the Individual Trustees for the Trust (former US District Judge John S. Martin, Jr. and Kent D. Syverud, Dean of the Washington University Law School). All of the Trustees are independent of BP. BP has no control over any of the Trustees.

The funds contributed by BPEP to the Trust are invested in one or more trust accounts and distributed by the Corporate Trustee upon the submission of appropriate claims documentation in accordance with the terms of the Trust Agreement. Under the Trust Agreement, the Trustees have full authority to administer the Trust in accordance with the terms of the Trust Agreement without the approval or consent of BPEP or any of its affiliates.

The $20-billion Trust fund will be available to satisfy legitimate individual and business claims adjudicated by the GCCF, state and local government claims resolved by BP, final judgments and settlements, state and local response costs, and natural resource damages and related costs. It does not cover fines and penalties, claims centre administration costs or spill response costs.

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BP HAS CLAIMED CONFIDENTIAL TREATMENT OF PORTIONS OF

THIS LETTER IN ACCORDANCE WITH 17 C.F.R. § 200.83

IFRIC 5 ‘Rights to Interests arising from Decommissioning, Restoration and Environmental Rehabilitation Funds’ applies to accounting in the financial statements of a contributor for interests arising from decommissioning, restoration and rehabilitation funds, referred to in IFRIC 5 as “decommissioning funds” or “funds” that have both of the following features:

(a)

the assets are administered separately (either by being held in a separate legal entity or as segregated assets within another entity); and

(b) a contributor’s right to access the assets is restricted.

Although the scope of IFRIC 5, as described above, relates to decommissioning funds, the Basis for Conclusions that accompanies it specifically permits its application to other situations by analogy. Paragraphs BC4-BC5, as reproduced below, are relevant.

BC4

D4 [the earlier exposure draft of the interpretation] did not precisely define the scope because the IFRIC believed that the large variety of schemes in operation would make any definition inappropriate. However, some respondents to D4 disagreed and commented that the absence of any definition made it unclear when the Interpretation should be applied. As a result, the IFRIC has specified the scope by identifying the features that make an arrangement a decommissioning fund. It has also described the different types of fund and the features that may (or may not) be present.

BC5

The IFRIC considered whether it should issue a wider Interpretation that addresses similar forms of reimbursement, or whether it should prohibit the application of the Interpretation to other situations by analogy. The IFRIC rejected any widening of the scope, deciding instead to concentrate on the matter referred to it. The IFRIC also decided that there was no reason to prohibit the application of the Interpretation to other situations by analogy and thus the hierarchy of criteria in paragraphs 7-12 of IAS 8 Accounting Policies, Changes in Accounting Estimates and Errors would apply, resulting in similar accounting for reimbursements under arrangements that are not decommissioning funds, but have similar features.

Paragraphs 7-12 of IAS 8, referenced in BC5 above, deal with the selection and application of accounting policies. In the absence of an IFRS that specifically applies to a transaction, paragraph 10 of IAS 8 requires that management shall use its judgement in developing and applying an accounting policy. Paragraph 11 goes on to provide further guidance, as follows:

In making the judgement described in paragraph 10, management shall refer to, and consider the applicability of, the following sources in descending order:

(a)

the requirements in IFRSs dealing with similar and related issues; and

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BP HAS CLAIMED CONFIDENTIAL TREATMENT OF PORTIONS OF

THIS LETTER IN ACCORDANCE WITH 17 C.F.R. § 200.83

(b)

the definitions, recognition criteria and measurement concepts for assets, liabilities, income and expenses in the Framework.

IFRSs are defined to include interpretations developed by the International Financial Reporting Interpretations Committee (IFRIC). We have followed the requirement of paragraph 11(a), leading us to consider the applicability of IFRIC 5 to the Trust fund. In addition, the costs that will be paid out of the Trust fund are related to environmental remediation, and IFRIC 5 refers to “decommissioning, restoration and environmental rehabilitation funds”.

As noted above, the scope of IFRIC 5 (paragraph 4) states two features that must be present in an arrangement in order for the interpretation to apply, namely that the assets are administered separately and that the contributor’s right to access the assets is restricted. Both these features are present in the case of the Trust fund. The Trust fund is administered separately by being held in the Deepwater Horizon Oil Spill Trust, a trust established by BPEP as grantor, with two independent individual trustees and one independent corporate trustee. Under this arrangement, the Trust is not controlled by BP and BP’s right to access the Trust fund is restricted. The terms of the Trust Agreement and its operation is discussed further in our response to Comment 2.

The additional background included in IFRIC 5 regarding how “decommissioning funds” operate in practice also provides further factors that are similar to the arrangements pertaining to the Trust fund. Specifically:

Contributions to these funds may be voluntary or required by regulation or law. The funds may have one of the following structures:

(a)

funds that are established by a single contributor to fund its own decommissioning obligations, whether for a particular site, or for a number of geographically dispersed sites.

(b)

[text omitted]

(c)

[text omitted]

Such funds generally have the following features:

(a)

the fund is separately administered by independent trustees.

(b)

entities (contributors) make contributions to the fund, which are invested in a range of assets that may include both debt and equity investments, and are available to help pay the contributors’ decommissioning costs. The trustees determine how contributions are invested, within the constraints set by the fund’s governing documents and any applicable legislation or other regulations.

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BP HAS CLAIMED CONFIDENTIAL TREATMENT OF PORTIONS OF

THIS LETTER IN ACCORDANCE WITH 17 C.F.R. § 200.83

(c)

the contributors retain the obligation to pay decommissioning costs. However, contributors are able to obtain reimbursement of decommissioning costs from the fund up to the lower of the decommissioning costs incurred and the contributor’s share of assets of the fund.

(d)

the contributors may have restricted access or no access to any surplus of assets of the fund over those used to meet eligible decommissioning costs.

The features and factors in paragraphs 2(a), 3(a), (b) and (d) accurately describe the arrangements surrounding the Trust fund established under the Trust Agreement. BP also retains the obligation to pay claims which is the feature described in paragraph 3(c). The mechanism for making payments to claimants is that they are made directly from the Trust fund, rather than being paid by BP and reimbursed. It is these considerations that led us to conclude that it is appropriate to apply the IFRIC 5 accounting guidance in this case.

Please provide us with additional detail describing the legal status of the GCCF. Significantly, describe the material terms of the agreement including your legal obligations, involvement in the administration of the fund, and level of control over the fund. In connection with your response, please provide us with your evaluation of paragraphs four and eight of IFRIC 5.

Response:

We have provided an overview of the GCCF and the Trust fund in our response to Comment 1. A discussion of material terms of the Trust Agreement relating to administration of the Trust is set out below.

The Trust is administered by two independent individual trustees and one independent corporate trustee. The selection of the initial Trustees for the Trust was subject to the informal approval of the Department of Justice and the Office of the White House Counsel, each of which, along with the Department of the Treasury, were closely involved in the structuring of the Trust, the drafting and negotiation of the Trust Agreement and the other steps leading to the establishment of the Trust. Before selecting the initial Trustees for the Trust, BPEP provided their names to the Department of Justice and the Office of the White House Counsel and subsequently was informed that neither the Department of Justice nor the Office of the White House Counsel had any objection to the appointment of the initial Trustees. If either of these governmental entities had objected to the appointment of any of the Trustees, such Trustee would not have been appointed. BPEP has no authority to remove or replace any of the Trustees or to appoint any successor Trustees if any of the initial Trustees resigns or otherwise ceases to serve. The Trust is irrevocable. BPEP has no right to amend the Trust Agreement or otherwise terminate the Trust.

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BP HAS CLAIMED CONFIDENTIAL TREATMENT OF PORTIONS OF

THIS LETTER IN ACCORDANCE WITH 17 C.F.R. § 200.83

The GCCF and its subcontractors have the right to submit adjudicated individual and business claims directly to the Trust for payment. BPEP has no role in connection with the payment by the Trust of individual and business claims resolved by the GCCF. BPEP has the authority under the Trust Agreement to present certain other resolved claims, including natural resource damages costs and state and local response costs, to the Trust for payment, provided it provides the Corporate Trustee with all required documents and related materials establishing that such claims are payable by the Trust under the Trust Agreement.

Paragraph 4 of IFRIC 5 says: “This Interpretation applies to accounting in the financial statements of a contributor for interests arising from decommissioning funds that have both of the following features:

(a)

the assets are administered separately (either by being held in a separate legal entity or as segregated assets within another entity); and

(b) a contributor’s right to access the assets is restricted.”

The feature described in paragraph 4(a) is present because the Trust is administered independently of BP by the third-party Trustees.

Under the terms of the Trust Agreement BP has restricted access to the funds once they have been contributed. BP will receive funds from the Trust only upon its expiration, if there are any funds remaining at that point. We therefore consider that the feature described in paragraph 4(b) of IFRIC 5 is also present in this case.

Paragraph 8 of IFRIC 5 requires a contributor to determine whether it has control, joint control or significant influence over the fund by reference to IAS 27, IAS 28, IAS 31 and SIC-12. If it does, the interest in the fund should be accounted for in accordance with those standards and IFRIC 5 would not apply.

The definition of control is provided in IAS 27 paragraph 4 as “the power to govern the financial and operating policies of an entity so as to obtain benefits from its activities”.

The Trustees have full authority to administer the Trust and are independent of BP. BP does not have decision-making powers in relation to the Trust fund or the GCCF, and both are managed independently of BP. The Individual Trustees oversee and monitor the activities of the Corporate Trustee. In addition, the liabilities covered by the Trust fund will be adjudicated principally by third parties. BP does not therefore have the power to govern the financial and operating policies of the Trust.

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BP HAS CLAIMED CONFIDENTIAL TREATMENT OF PORTIONS OF

THIS LETTER IN ACCORDANCE WITH 17 C.F.R. § 200.83

SIC-12 ‘Consolidation – Special Purpose Entities’ requires that an SPE be consolidated when “the substance of the relationship between an entity and the SPE indicates that the SPE is controlled by that entity”. It defines a Special Purpose Entity as an entity “created to accomplish a narrow and well-defined objective”. In this case, the Trust will have the sole purpose of using the funds to settle certain of BP’s liabilities arising from the GOM incident. However, for the reasons stated above, we believe that BP does not in substance have control of the Trust.

Joint control is defined in IAS 31 ‘Interests in Joint Ventures’ as follows: “Joint control is the contractually agreed sharing of control over an economic activity, and exists only when the strategic financial and operating decisions relating to the activity require the unanimous consent of the parties sharing control (the venturers).” As described above the Trustees are independent of BP and have the full authority to administer the Trust, and there is no sharing of decision-making powers. We have therefore concluded that BP does not have joint control of the Trust.

Under IAS 28 ‘Investments in Associates’ significant influence is defined as the power to participate in the financial and operating policy decisions of the investee but is not control or joint control over those policies. As described above the Trustees are independent of BP and have the full authority to administer the Trust, and there is no sharing of decision-making powers. We have therefore concluded that BP does not have significant influence over the Trust.

We note your disclosure stating that any amounts left in the escrow account once all legitimate claims have been resolved and paid will revert to you. Please provide us with a detailed discussion explaining your rights to these residual amounts. Your response should also tell us how you considered paragraph five of IFRIC 5 in regards to any expected residual amounts.

Response:

The Trust Agreement provides for the term of the Trust to continue until 30 April 2016 subject to the right of the Individual Trustees to extend or expedite this expiration date under certain circumstances. The Trust Agreement further provides that upon expiration of the Trust’s term, any assets remaining in the Trust Fund shall be distributed to BPEP, as grantor of the Trust, as long as all amounts owed under any pending claims submitted to the Trust and all approved expenses have been paid. BP is unable to estimate whether any funds will remain in the Trust when it terminates. The amount of remaining funds, if any, will depend on the level of claims asserted both as part of the GCCF process and otherwise in connection with the oil spill, including the costs incurred in natural resource damage assessment and state and local responses, as well as the fees and costs of the Trustees and the paying agents for the Trust in administering the Trust and paying claims made against the Trust.

Paragraph 5 of IFRIC 5 distinguishes between a right to reimbursement from the fund and a residual interest in the fund, and makes it clear that a residual interest falls outside the scope of IFRIC 5 and, instead, may be an equity instrument within the scope of IAS 39.

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BP HAS CLAIMED CONFIDENTIAL TREATMENT OF PORTIONS OF

THIS LETTER IN ACCORDANCE WITH 17 C.F.R. § 200.83

We believe that BP’s residual interest in the Trust Fund meets the definition of an equity instrument as set out in IAS 32, paragraph 11. Therefore, we have referred to IAS 39, paragraph 46 and paragraph 66 in order to determine the measurement of the residual interest, and have concluded that, at this stage, it is not possible to measure reliably the fair value of BP’s residual interest in the fund. The range of reasonable estimates is significant and the probabilities of the various estimates cannot be reasonably assessed. We have therefore ascribed no value to the residual interest. We will continue to assess whether or not the fair value of the residual interest can be reliably measured as we move forward.

We note that a portion of your response related to the classes of provision that are shown on your balance sheet. Notwithstanding your views as to the adequacy of your existing disclosure under IAS 34, please provide us with the information previously requested regarding each class of provision you have identified.

Specifically, for each class of provision that you have identified on pages 27 and 28 (i.e., Offshore and onshore oil spill response, Environmental, Claims under OPA 90 and Fines and Penalties), tell us the amount of the provision that you have made in the period, the amounts used during the period and the carrying amount of the provision at the end of the period. Identify the portion of the provision that relates to costs incurred up to June 30, 2010, obligations for future costs which can be reliably estimated and rights and obligations under the escrow account by class of provision. For each class of provision, clearly explain how the amount of the charge was determined, including the extent to which any amounts have been discounted and the related major assumptions made about future events in determining discounted amounts as contemplated by paragraph 85(b) of IAS 37.

Additionally, provide information that updates your response through September 30, 2010.

Response:

The following table provides an analysis, for each class of provision we have identified, of all of the movements in the provision since inception up to 30 September 2010:

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BP HAS CLAIMED CONFIDENTIAL TREATMENT OF PORTIONS OF

THIS LETTER IN ACCORDANCE WITH 17 C.F.R. § 200.83

$ million	Spill response	Environmental	Litigation & claims	Total

Provided in 2Q	[*]	[*]	[*]	[*]

As at 30 June 2010	[*]	[*]	[*]	[*]

Provided in 3Q	[*]	[*]	[*]	[*]

Unwinding of discount	[*]	[*]	[*]	[*]

Utilization	[*]	[*]	[*]	[*]

As at 30 September 2010	[*]	[*]	[*]	[*]

Amounts expected to be settled from the Trust fund:
- at 30 June 2010	[*]	[*]	[*]	[*]
- at 30 September 2010	[*]	[*]	[*]	[*]

* CONFIDENTIAL INFORMATION HAS BEEN OMITTED AND FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION.

Costs incurred up to 30 June 2010, amounting to $2,892 million, were not included in the provision and are not included in the table presented above. Such costs were either charged to the income statement and cash expended within the second quarter ($2,116 million), or were charged to the income statement and accrued within current trade and other payables on the balance sheet as at 30 June 2010 ($776 million). Costs incurred up to 30 June 2010 are analyzed by category as follows: $2,638 million spill response costs, $70 million environmental costs and $184 million for litigation and claims.

All of the amounts included in the provision balances presented in the table above represent obligations for future costs that can be reliably estimated. They include certain obligations that will be settled from the Trust fund and other obligations that are not covered by the Trust fund and so will be settled by BP. Of the total provision of $17,646 million as at 30 June 2010, the amount expected to be settled from the Trust fund was $7,926 million. At 30 September 2010, the amount expected to be settled from the Trust fund was $7,015 million, out of the total provision of $16,405 million.

Contributions payable by BP into the Trust fund are not included in the table above; these amounts are recorded within other payables on the balance sheet because the amount and timing of future payments is not uncertain.

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BP HAS CLAIMED CONFIDENTIAL TREATMENT OF PORTIONS OF

THIS LETTER IN ACCORDANCE WITH 17 C.F.R. § 200.83

The determination of the charge and the major assumptions about future events, for each class of provision, are described below.

Spill response

The estimated future costs of the offshore operations are based upon the remaining activities expected to be undertaken, including the US Coast Guard response costs, and decontamination of vessels involved in the spill response. The amount provided has been calculated using daily rates of costs incurred to date, in conjunction with the anticipated activities as noted on pages 4-6 of the 3Q Form 6-K. In addition, the estimated future costs of the shoreline response have been provided for based on the remaining activities expected to be undertaken and the current acreage of shoreline and marshes affected. The majority of these costs are expected to be incurred and paid in the next 12 months.

Environmental

The amounts committed by BP for a 10-year research programme to study the impact of the incident on the marine and shoreline environment of the Gulf of Mexico have been provided for where not expended before 30 September 2010.

As a responsible party under OPA 90, BP is required to pay for natural resource damage resulting from the oil spill. These damages include, amongst other things, the reasonable costs of assessing the injury to natural resources. BP has been incurring natural resource damage assessment costs and a provision has been made for the estimated costs of the assessment phase which are expected to be incurred and paid in the next 12 months. Until the size, location and duration of the impact is assessed, it is not possible to estimate reliably either the amounts or timing of the remaining damage and renewal costs. Therefore no amounts have been provided for these items; however the $20-billion Trust fund established by BP is available to pay for such natural resource damages and BP’s $20-billion obligation to fund the Trust fund has been recognized in full, after taking account of the time value of money. No additional charge will be taken to the income statement for natural resource damage until the $20-billion fund is utilized.

Litigation and claims

The estimated future cost of settling claims received to date under OPA 90 has been provided for, based upon actual payment history to date regarding the average monthly payment per claimant, and an estimate of the period over which payments are expected to continue. Claims centre administration costs have also been provided. The measurement of this provision is subject to a very high degree of uncertainty. The amount provided for claims has been determined in accordance with the requirements of IAS 37 ‘Provisions, Contingent Liabilities and Contingent Assets’ and may be subject to significant revision as the claims process progresses. BP is committed to satisfying all legitimate claims.

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BP HAS CLAIMED CONFIDENTIAL TREATMENT OF PORTIONS OF

THIS LETTER IN ACCORDANCE WITH 17 C.F.R. § 200.83

Further claims will continue to be made. In addition, BP has received more than 400 private civil lawsuits (see Legal proceedings on pages 34-38 of the 3Q Form 6-K for further information). BP’s potential liabilities resulting from pending and future claims, lawsuits and enforcement actions relating to the incident, together with the potential cost of implementing remedies sought in the various proceedings, cannot be estimated reliably at this time. No amounts have been provided for these items, except for the estimated legal costs expected to be incurred in connection with the litigation. However, the $20-billion Trust fund is available to satisfy these claims and the group’s obligation to fund the $20-billion Trust fund has been recognized in full, after taking account of the time value of money. No additional charge to the income statement will be taken for OPA claims and certain litigations covered by the fund until the $20-billion fund is fully exhausted. Claims and litigation settlements are likely to be paid out over many years to come.

Provision has been made for the estimated penalties for strict liability under the Clean Water Act, which are based on a specified maximum penalty per barrel of oil released. While there are uncertainties with respect to both the per-barrel amount of any penalty and volume of oil spilled used in the calculation, assumptions have been made to arrive at a range of potential liabilities upon which this provision is based. This calculation assumes a volume of oil spilled determined using an estimate of the flow rate within the range of figures published, and is based upon BP’s belief that it was not grossly negligent and that it did not engage in willful misconduct.

The amount and timing of these costs depends upon agreement with the appropriate authorities on the amount of penalty to be paid, or if no agreement is reached, on the assessment of a penalty by a court. It is not practicable to estimate the timing of expending these costs. No other amounts have been provided as at 30 September 2010 in relation to other potential fines and penalties because it is not possible to measure the obligation reliably.

Discounting of provisions

The amount provided for BP’s commitment to a 10-year research programme to study the impact of the oil spill incident on the marine and shoreline environment of the Gulf of Mexico has been discounted. All other amounts within provisions have not been discounted because it would not materially impact the amount of the provision as the amounts are expected to be paid out in the relatively near term.

Proposed disclosures for 2010 Annual Report on Form 20-F

The disclosure requirements of IAS 37 are set out in paragraphs 84 to 92 of the standard. Paragraph 84 requires that an entity discloses, for each class of provision, the carrying amount at the beginning and end of the period and movements in the provision during the period, by type.

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BP HAS CLAIMED CONFIDENTIAL TREATMENT OF PORTIONS OF

THIS LETTER IN ACCORDANCE WITH 17 C.F.R. § 200.83

Paragraph 87 of IAS 37 provides some guidance on what constitutes a class of provision. It says:

“In determining which provisions or contingent liabilities may be aggregated to form a class, it is necessary to consider whether the nature of the items is sufficiently similar for a single statement about them to fulfil the requirements of paragraphs 85(a) and (b) and 86(a) and (b).”

Paragraphs 85 and 86 contain the qualitative disclosure requirements for provisions and contingent liabilities, and include a description of the nature of the obligation, the amount and timing of expected outflows of economic benefits, uncertainties and where necessary, major assumptions made and information on possible reimbursements.

Our proposed disclosure for the provisions footnote in the 2010 Annual Report on Form 20-F is shown below. Please note that the amounts presented in the draft tables below are for illustrative purposes only (the amounts relating to the Gulf of Mexico oil spill are 3Q 2010 actual amounts, and the amounts for the group excluding the oil spill are for 2009, therefore the totals are not meaningful other than for illustration).

Note XX Provisions

	Decommissioning	Environmental	Spill response	Litigation and claims	Other	$ million Total
At 1 January	8,418	[*]	[*]	[*]	2,098	[*]
Exchange adjustments	398	[*]	[*]	[*]	29	[*]
New or increased provisions	169	[*]	[*]	[*]	1,256	[*]
Write-back of unused provisions	-	[*]	[*]	[*]	(228)	[*]
Unwinding of discount	184	[*]	[*]	[*]	16	[*]
Change in discount rate	324	[*]	[*]	[*]	8	[*]
Utilization	(383)	[*]	[*]	[*]	(361)	[*]
Deletions	(90)	[*]	[*]	[*]	(3)	[*]
	9,020	[*]	[*]	[*]	2,815	[*]
Of which – within 1 year	287	[*]	[*]	[*]	572	[*]
– after 1 year	8,733	[*]	[*]	[*]	2,243	[*]

* CONFIDENTIAL INFORMATION HAS BEEN OMITTED AND FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION.

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BP HAS CLAIMED CONFIDENTIAL TREATMENT OF PORTIONS OF

THIS LETTER IN ACCORDANCE WITH 17 C.F.R. § 200.83

The table below presents the provisions for the group excluding provisions relating to the Gulf of Mexico oil spill:

	Decommissioning	Environmental	Litigation and claims	Other	$ million Total
At 1 January	8,418	1,691	1,446	2,098	13,653
Exchange adjustments	398	15	22	29	464
New or increased provisions	169	588	302	1,256	2,315
Write-back of unused provisions	-	(259)	(99)	(228)	(586)
Unwinding of discount	184	32	15	16	247
Change in discount rate	324	18	(35)	8	315
Utilization	(383)	(308)	(574)	(361)	(1,626)
Deletions	(90)	(58)	(1)	(3)	(152)
	9,020	1,719	1,076	2,815	14,630
Of which – within 1 year	287	368	433	572	1,660
– after 1 year	8,733	1,351	643	2,243	12,970

The provisions relating to the Gulf of Mexico oil spill are presented as follows:

	Environmental	Spill response	Litigation and claims	$ million Total
At 1 January	-	-	-	-
New or increased provisions	[*]	[*]	[*]	[*]
Unwinding of discount	[*]	[*]	[*]	[*]
Utilization	[*]	[*]	[*]	[*]
	[*]	[*]	[*]	[*]
Of which – within 1 year	[*]	[*]	[*]	[*]
– after 1 year	[*]	[*]	[*]	[*]

* CONFIDENTIAL INFORMATION HAS BEEN OMITTED AND FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION.

Provisions excluding the Gulf of Mexico oil spill

The group makes full provision for the future cost of decommissioning oil and natural gas production facilities and related pipelines on a discounted basis on the installation of those facilities. The provision for the costs of decommissioning these production facilities and pipelines at the end of their economic lives has been estimated using existing technology, at current prices or long-term assumptions, depending on the expected timing of the activity, and discounted using a real discount rate of XXXX% (2009 1.75%). These costs are generally expected to be incurred over the next 30 years. While the provision is based on the best estimate of future costs and the economic lives of the facilities and pipelines, there is uncertainty regarding both the amount and timing of incurring these costs.

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BP HAS CLAIMED CONFIDENTIAL TREATMENT OF PORTIONS OF

THIS LETTER IN ACCORDANCE WITH 17 C.F.R. § 200.83

Provisions for environmental remediation are made when a clean-up is probable and the amount of the obligation can be reliably estimated. Generally, this coincides with commitment to a formal plan of action or, if earlier, on divestment or on closure of inactive sites. The provision for environmental liabilities has been estimated using existing technology, at current prices and discounted using a real discount rate of XXXX% (2009 1.75%). The majority of these costs are expected to be incurred over the next 10 years. The extent and cost of future remediation programmes are inherently difficult to estimate. They depend on the scale of any possible contamination, the timing and extent of corrective actions, and also the group’s share of the liability.

The litigation 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 2010 are provisions for deferred employee compensation of $XXXX million (2009 $789 million) and for expected rental shortfalls on surplus properties of $XXXX million (2009 $246 million). These provisions are discounted using either a nominal discount rate of XXXX% (2009 4.0%) or a real discount rate of XXXX% (2009 1.75%), as appropriate.

Provisions relating to the Gulf of Mexico oil spill

Spill response

The estimated future costs of the offshore operations are based upon the remaining activities expected to be undertaken, including the US Coast Guard response costs, and decontamination of vessels involved in the spill response. The amount provided has been calculated using daily rates of costs incurred to date, in conjunction with the anticipated activities as noted on pages XX-XX. In addition, the estimated future costs of the shoreline response have been provided for based on the remaining activities expected to be undertaken and the current acreage of shoreline and marshes affected. The majority of these costs are expected to be incurred and paid in the next 12 months.

Environmental

As a responsible party under the OPA 90, BP is required to pay for natural resource damage resulting from the oil spill. These damages include, amongst other things, the reasonable costs of assessing the injury to natural resources. BP has been incurring natural resource damage assessment costs and a provision has been made for the estimated costs of the assessment phase. Until the size, location and duration of the impact is assessed, it is not possible to estimate reliably either the amounts or timing of the remaining damage and renewal costs. Therefore no amounts have been provided for these items; however the $20-billion Trust fund established by BP is available to pay for such natural resource damages and BP’s $20-billion obligation to fund the Trust fund has been recognized in full, after taking account of the time value of money.

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Litigation and claims

The estimated future cost of settling claims received to date under OPA 90 has been provided for, based upon actual payment history to date regarding the average monthly payment per claimant, and an estimate of the period over which payments are expected to continue. Claims centre administration costs have also been provided for. The measurement of this provision is subject to a very high degree of uncertainty. The amount provided for claims has been determined in accordance with IFRS and may be subject to significant revision as the claims process progresses. BP is committed to satisfying all legitimate claims.

Further claims will continue to be made. In addition, BP has received more than XXX private civil lawsuits (see Legal proceedings on pages XX-XX for further information). BP’s potential liabilities resulting from pending and future claims, lawsuits and enforcement actions relating to the incident, together with the potential cost of implementing remedies sought in the various proceedings, cannot be estimated reliably at this time. No amounts have been provided for these items, except for the estimated legal costs expected to be incurred in connection with the litigation. However, the $20-billion Trust fund is available to satisfy these claims and the group’s obligation to fund the $20-billion Trust fund has been recognized in full, after taking account of the time value of money. Claims and litigation settlements are likely to be paid out over many years to come.

We have been carefully considering whether it is appropriate to disclose fines and penalties within the litigation and claims category.

Treating Clean Water Act Section 311 civil penalties as litigation-related provisions is, we believe, consistent with the statutory framework and litigation process specified by the express language of Section 311 of the Act. The Department of Justice has stated its intention to file within the next couple of weeks a complaint submitting its claim for Clean Water Act Section 311 penalties against BP and others for contested litigation in the Multi District Litigation. Thus, like other issues of common law or statutory liability and damages, BP’s liability for, and the amount of any and all Clean Water Act Section 311 civil penalties, will be lodged squarely with the court for ongoing litigation and decision.

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Please tell us how you determined your $7.9 billion share of the assets held in the escrow fund (i.e., the reimbursement asset) at June 30, 2010. Your response should explain how this amount was calculated and the status of the approval process surrounding the reimbursement of this amount from the escrow account. Tell us the total amount of asset held in the escrow fund at June 30, 2010. Refer to paragraph nine of IFRIC 5.

Additionally, provide information that updates your response through September 30, 2010 and the $7.0 billion reimbursement asset recognized.

Response:

On 16 June 2010 BP agreed with the US Government that it would establish an escrow account of $20 billion to satisfy certain claims and costs related to the Gulf of Mexico oil spill. As described in our response to Comment 1, the Trust fund was formally established in August and BP agreed to contribute $3 billion to the fund in 3Q 2010 and a further $2 billion in 4Q 2010, followed by 12 quarterly payments of $1.25 billion from 1Q 2011 through 4Q 2013. No payments had been made by BP into the Trust fund by 30 June 2010. The Trust was established during August and the first payment of $3 billion had been paid before 30 September 2010.

The $20-billion obligation to fund the Trust fund meets the definition of a liability and has therefore been recognized in full and recorded on the group balance sheet as at 30 June 2010 within other payables. Additionally, IFRIC 5, paragraph 10 clarifies that a contributor to a fund shall recognize a liability only if it is probable that additional contributions will be made. In this case it is probable that the contributions will be made, as they have been agreed with the US Government. The amount initially recognized as at 30 June 2010 amounted to $19,580 million on a discounted basis.

We have also recognized in full, as provisions under IAS 37, those future costs associated with the Gulf of Mexico oil spill that are reliably measurable. We also noted that certain of these future costs will be settled from the Trust fund.

We are therefore required, under paragraph 9 of IFRIC 5, to recognize a reimbursement asset as the lower of:

(a)

the amount of the obligation recognized – in this case the relevant amount is the portion of the oil spill provision expected to be paid from the Trust fund; and

(b)

BP’s share of the fair value of net assets of the fund – in this case the relevant amount is the receivable in the fund ($19,580 million at 30 June 2010 and approximately $19 billion at 30 September 2010).

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As at 30 June 2010, the total amount of estimated future costs recognized for the oil spill provision was $17,646 million, of which $7,926 million was expected to be settled from the Trust fund. This portion of the provision relates to the types of costs that have been agreed to be covered by the fund i.e. individual and business claims adjudicated by the GCCF, state and local government claims resolved by BP, final judgments and settlements, state and local response costs, and natural resource damages and related costs.

The reimbursement asset is therefore the lower of $19,580 million and $7,926 million. A reimbursement asset of $7,296 million was therefore recognized on the group balance sheet at 30 June 2010.

At 30 September 2010, the total amount of estimated future costs recognized for the oil spill provision was $16,405 million, of which $7,015 million was expected to the settled from the Trust fund. A reimbursement asset of $7,015 million was therefore recognized on the group balance sheet at 30 September 2010.

There is no approval process surrounding the reimbursement asset, other than provisions included in the Trust Agreement stating that any remaining amounts will be returned to BP upon expiration of the Trust. As described above, the recognition of the reimbursement asset is required by IFRIC 5. In the absence of the reimbursement asset, those future costs that will be settled from the Trust would be double-counted as the liability has been recognized within the oil spill provision and also the $20-billion obligation to fund the Trust fund has been recognized in full.

Form 6-K furnished November 2, 2010

Gulf of Mexico Oil Spill, page 4

Financial Impact of the Response, page 6

We note your statement that the contractual arrangements put in place at the height of the response to the Gulf of Mexico oil spill were complex, involving many parties including contractors, sub-contractors and the UAC, and that arrangements were put in place rapidly to ensure that the response was timely. We also note your disclosure that you have provided for the cost of all estimable known obligations but it is possible that further costs might arise from the intense activity that took place at that time. Please expand your disclosure to briefly describe the nature of the contractual arrangements, and provide material examples of the nature of the related uncertainties that may result in additional future costs as a result of their complex nature and the speed in which they were put in place.

Response:

The statements regarding the contractual arrangements and the speed with which they were put in place were made in order to highlight uncertainties surrounding the estimation of the liabilities associated with them.

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Unified Area Command (UAC) is an overarching response organization structure designed to manage and administer a large scale emergency response effort. The UAC brings together the federal and state agencies with oversight authority along with the responsible party(ies) (RP) to create a management team for response actions. For the MC252 Deepwater Horizon spill response, the United States Coast Guard functioned as the Federal On-Scene Coordinator (FOSC) with ultimate legal authority to direct response activities. The Coast Guard provided the National Incident Commander (NIC) (a role held by Adm. Thad Allen for the majority of the response). The NIC / FOSC, along with BP and a number of state and federal agencies formed the nucleus of the UAC. Formal member roles in the UAC were held by:

U.S. Coast Guard

Bureau of Offshore Energy Management Regulation and Enforcement (BOEMRE) (formerly known as Minerals Management Service (MMS))

State On-Scene Coordinators from Louisiana, Mississippi, Alabama and Florida

Additionally, other State and Federal Agencies participated, to varying degrees and in varying roles depending on defined purview. A partial list includes:

National Oceanographic and Atmospheric Administration (NOAA)

U.S. Environmental Protection Agency

U.S. Department of Homeland Security

U.S. Department of Interior

U.S. Department of Defense

U.S. Fish and Wildlife Service

U.S. National Park Service

U.S. Department of State

U.S. Geologic Survey (USGS)

Centers for Disease Control and Prevention

OSHA

As a group, the UAC works via consensus to manage and direct the spill response. Incident Commanders (ICs) with different areas of geographic oversight reported up through the UAC to the NIC. In the MC252 response, ICs managed Incident Command Posts (ICPs) in Houston, TX; Houma, LA; Mobile, AL; and Miami, FL. The UAC was first located in Robert, LA and later moved to New Orleans, LA.

Operational Control: The Incident Command System (ICS)

Oil spill response efforts under the jurisdiction of the federal government must be managed in accordance with the National Contingency Plan (NCP). To more reliably and effectively manage responses in a manner consistent with the NCP, the federal government has adopted the ICS. The ICS consists of a standard management hierarchy and procedures for managing temporary incident(s) of any size. ICS procedures are largely pre-established and sanctioned by participating authorities. ICS includes procedures to select and form temporary management hierarchies to control funds, personnel, facilities, equipment, and communications. ICS is designed around the following objectives:

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Allow personnel from a wide variety of agencies to meld rapidly into a common management structure.

Provide organized logistical and administrative support to operational staff.

Provide a unified, centrally authorized emergency organization.

The ICS provides some defined processes for the procurement of material and personnel determined to be necessary for any response. The system is designed to be flexible enough to be applied to responses of any size. However, it is not necessarily designed for large-scale, rapidly expanding organizations. For MC252, with the Coast Guard as the FOSC agency, a form known as the “213 RR CG” (Resource Request Message or simply the “213”) was the primary tool for authorizing the procurement of resources of any kind. Although the 213 form was the primary tracking tool, it was not the only tracking tool and as the operation expanded, there was not a centralized approval process. With a large number of state and federal agencies, multiple named Responsible Parties and the large scale of the response, the ultimate funding flow is complex and results in difficulty in maintaining real time monitoring of expenses.1

The Various MC252 Procurement Processes

To facilitate rapid and effective response, On-Scene Coordinators (OSCs), the responsible parties and some local governments with emergency response authority are all empowered to procure necessary resources for a response action. So long as those expenses can be found to be consistent with the National Contingency Plan, the responsible party(ies) will be expected to pay those costs regardless of whether or not the responsible parties were involved in or approved the decision to procure the resource.

The scale of the MC252 response and the need to scale up operations rapidly necessitated having procurement authority vested with each Incident Commander in each Incident Command Post. Additionally, various state and local governments assumed active roles in the marshalling and staging of response resources. In some instances, those state and local government authorities utilized the 213 process and in some cases, particularly very early in the response, goods and services were procured directly without utilizing any centralized process. As a result, BP has seen and continues to review substantial numbers of invoices generated from work procured outside the 213 process to determine legitimacy and consistency with the NCP.

1 The U.S. Government Accountability Office has recently completed a report describing some of the complexity of funding flow as it relates to federal agency expenses for response. See, GAO-11-90R, Deepwater Horizon Oil Spill: Preliminary Assessment of Federal Financial Risks and Cost Reimbursement and Notification Policies and Procedures.

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Some examples of resourcing that took place during the response efforts outside of the UAC centralized 213 process include, but are not limited to the following:

On 1 July 2010, just 15 days before the well was capped, a BP contractor hired a vessel and equipment at a rate of $35,000/day. The vessel was hired outside of the 213 process and remained on hire until 6 October 2010 with no authorization from BP;

After the well was capped, and without BP’s knowledge or authorization, a contractor hired an oil skimming vessel for a minimum 90-day term. The contractor sought payment from BP in excess of $1 million;

A parish hired a private helicopter and trailer for an extended period of time with no authorization from BP, and sought reimbursement from BP in the amount of $717,000.

And finally, the federal agencies themselves had authority to procure response-related services directly and did so in connection with the response. Additionally, utilizing Pollution Removal Funding Authorization (PRFA) processes, commitments were made to allocate monies between various agencies for response costs. Initially, costs authorized by PRFA are paid from the Oil Spill Liability Trust Fund (OSLTF). In typical situations, the RP is expected to reimburse the OSLTF. But because of the anticipated scale of the MC252 response, BP was requested to deposit / pre-fund for the benefit of the OLSTF before expenses were incurred rather than reimbursing after expenses were incurred.2

Contingent Liabilities, page 6

We note your disclosure that at the present time, you do not believe it is possible to measure reliably any obligation in relation to future claims, including natural resource damage under OPA 90, or litigation actions that have been received to date or may be received in the future. Please describe the nature of the specific types of costs that are not deemed to be estimable and tell us in more detail why you are not able to determine the amount of these expenses and the expected timing of payment. Your response should also provide your expectations as to when, and under what circumstances, you will be in a position to measure these obligations in a reliable manner.

Response:

Background

BP p.l.c.’s Form 6-K for the period ended 30 September 2010, filed 2 November 2010 with the SEC, included the following statements:

“The total amounts that will ultimately be paid by BP in relation to all obligations relating to the incident are subject to significant uncertainty. The ultimate exposure and cost to BP will be dependent on many factors including the rate at which the number of people involved in the response is gradually reduced, the time taken to reduce the number of vessels involved in the response and to complete associated decontamination activities, and the timing of transition of control of the operation

2 Additional information on the funding process can be obtained at www.uscg.mil/npfc/PDFs/OLSTF_Funding_for_Oil_Spills.pdf

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from the UAC to the BP Gulf Coast Restoration Organization. Furthermore, the amount of claims that become payable by BP, the amount of fines ultimately levied on BP (including any determination of negligence by BP), the outcome of federal and derivative lawsuits, and any costs arising from any longer-term environmental consequences of the oil spill, will also impact upon the ultimate cost for BP.

Contingent liabilities

BP has provided for its best estimate of items that will be paid through the $20-billion Trust fund. At the present time, BP considers it is not possible to measure reliably any obligation in relation to future claims, including natural resource damage under OPA 90, or litigation actions that have been received to date or may be received in the future. Although it is not possible at the current time to estimate a liability in excess of the amount currently provided, BP’s full obligation under the $20-billion Trust fund has been expensed in the income statement, taking account of the time value of money. For those items not covered by the Trust fund it is not possible to measure reliably any obligation in relation to other litigation or potential fines and penalties except, subject to certain assumptions noted above, for those relating to Section 311 of the Clean Water Act. The magnitude and timing of possible obligations in relation to the Gulf of Mexico oil spill are subject to a very high degree of uncertainty as described further in our 2Q and 3Q Forms 6-K under Principal risks and uncertainties. Any such possible obligations are therefore contingent liabilities and, at present, it is not practicable to estimate their magnitude or possible timing of payment. Therefore no amounts have been provided as of 30 September 2010 in relation to these. Furthermore, other material unanticipated obligations may arise in future in relation to the incident.”

The following section describes a number of specific areas of contingent liabilities as to which, at present, it is not practicable to estimate their magnitude or possible timing of payment. These areas are (i) pending litigation, (ii) certain OPA claims (including those of government agencies and those that have been incurred but not reported), (iii) liability for natural resource damages, and (iv) liability for fines and penalties under provisions other than Section 311 of the Clean Water Act.

Contingent Liabilities: Litigation:

General Description of the Deepwater Horizon Litigation

Actions Pending. There are approximately 420 active lawsuits against BP related to the Deepwater Horizon incident and oil spill, asserting primarily the following claims:

Economic Losses: Approximately 300 cases assert claims under OPA 90 and common law torts and allege lost income for individuals and businesses whose livelihoods relate to the Gulf Coast, as well as claims by owners and operators of property along the Gulf Coast.

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ii.

Personal Injury: Forty-four personal injury cases allege injuries resulting from the 20 April 2010 incident or from exposure to dispersants and hydrocarbons following the spill.

iii.

Environmental Claims: Fourteen environmental claims are pending against BP, including citizen suits under the Clean Water Act and other environmental statutes, seeking cleanup, injunctions, and civil penalties.

iv.

Shareholder Value Claims: Twenty-six securities, shareholder derivative and ERISA cases have been filed against BP in relation to the Deepwater Horizon incident.

Insurance Claims: Two identical lawsuits have been filed by Transocean’s insurers seeking a declaration that they have no obligation to BP as an “additional insured.”

vi.

RICO Actions: There are five pending RICO claims relating to drilling operations and to representations made to the Minerals Management Service.

vii.

Spill Response Disputes: Twenty lawsuits arise from BP’s spill response efforts, including contract disputes with containment boom suppliers and the owners/operators of vessels in the Vessels of Opportunity program.

viii.

Transocean Limitation Action: On 13 May 2010, Transocean filed a Limitation of Liability Action under admiralty law in federal court.

Status: Most of the litigation has been consolidated into one of two MDLs, with a smaller number of lawsuits pending in state courts or other federal courts.

MDL 2179: Several hundred cases have been transferred to Judge Carl Barbier in the Eastern District of Louisiana, who now oversees over 350 cases. Under a recent JPML order, MDL 2179 will include the RICO cases. In October, Judge Barbier issued a case management order which continues a stay of responsive pleadings and allows for limited discovery and motion practice.

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Judge Barbier intends to schedule one or more OPA cases for trial in June 2011 to serve as test cases on issues of liability and damages. The Court plans to sever contribution and third-party claims and allow the strict liability cases to go forward against BP alone, as a responsible party under OPA. Liaison counsel are to confer by late January 2011 to identify potential OPA test cases.

MDL 2179 now includes the Limitation Action filed by Transocean. Parties subject to the Limitation Action must file their claims against the Transocean entities in that court by 20 April 2011, with an 18 March 2011 deadline for cross-claims against other parties, including Halliburton. A February 2012 trial in the Limitation proceeding is set to determine not only Transocean’s ability to limit its liability but also (via expected cross-claims and third-party claims) the relative responsibility of various parties including BP for the 20 April 2010 casualty.

ii.

MDL 2185: Twenty-one securities, shareholder derivative and ERISA cases have been consolidated before Judge Keith Ellison in the Southern District of Texas. No responsive pleadings are currently due, pending the filing of consolidated amended complaints.

iii.

Insurance cases: There are two actions in federal court in Texas brought by Transocean’s excess insurance carriers versus BP.

iv.

State Court Litigation: Over 30 cases are currently pending in state court, including eight shareholder derivative lawsuits. In two cases, both personal injury suits filed by oil spill response workers, Texas courts have set trial for 17 October 2011 and 6 February 2012.

A Reliable Measure of BP’s Litigation Exposure is Not Possible at this Time because of the Uncertainty of Events and Future Results in the Litigation.

In general, the litigation pending against the BP group is at very early stages of proceedings.

MDL 2179: For example in MDL 2179 (ED LA), where the vast majority of the cases are pending, plaintiffs will not be filing consolidated and master complaints until 15 December 2010 and the defendants including BP are not required to answer or otherwise respond to those complaints until 18 January 2011. The defendants expect to file motions seeking legal rulings on 18 January 2011 that, if successful, could significantly narrow the scope of claims and legal theories that can be asserted; but the motions will not be fully briefed until at least March 2011 and the MDL 2179 court is not expected to rule on such motions until 2Q 2011. In cases with RICO claims against BP, the schedule will be even slower – the master RICO complaint is not expected until 18 January 2011 with legal motions directed at that complaint following in February 2011.

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No motions for class certification have been filed in MDL 2179 and according to lead plaintiffs’ counsel in those cases, they do not expect to seek class certification for some time pending other developments such as the Limitation action trial in February 2012, discussed above.

In addition, extensive fact and expert discovery in MDL 2179 is at an early stage. Document and other written discovery of defendants has commenced, but depositions will not commence until January 2011. Plaintiffs have recently served about 25,000 individual, one page Plaintiff Profile Forms pursuant to court order, but these forms provide very basic information and do not include an estimate of claimed damages. And relatedly, the Gulf Coast Claims Facility (“GCCF”) has only recently announced its final protocol for the submission and resolution of OPA claims.

Expert discovery in the Limitation action will not commence until the third quarter of 2011 under the current schedule, and that discovery is expected to focus on liability issues, not damages. It will be well after that before any discovery on the amount of economic damages claimed in the cases as a whole in MDL 2179 proceeds, with the exception of a few test cases that the Judge may conduct on the claims of OPA claimants as soon as June 2011.

The February 2012 Limitation proceeding trial in MDL 2179 is expected to last several months; and its first phase will decide Transocean’s right to limit its liability and, assuming cross claims among BP and other defendants are filed by the 18 March 2011 deadline, assessments of the relative fault of BP and various other parties (but not quantum of damages). And the results of the first phase are subject to appeals as of right under federal admiralty law.

As a result of these and other similar factors, it is too early in the proceedings to estimate the exposure of BP in these proceedings, either as to personal injury, economic losses, RICO allegations, or other damage claims.

State court cases: Twenty-six cases are currently pending in state court, including eight personal injury lawsuits and over ten contract disputes with individuals and firms involved in spill response efforts (and excluding eight state-court shareholder derivative lawsuits, which are discussed below). While service has been effected in all but three of these cases, written discovery has commenced in only three of these cases, with the remainder of the cases at the pleadings stage. In two personal injury cases involving response workers, Texas courts have set preliminary schedules which include trial dates of 17 October 2011 and 6 February 2012. In addition, it is possible that a number of these cases may be removed to federal court and consolidated with MDL 2179.

Because of the lack of fact discovery in these cases, the absence of any rulings on key legal issues that may limit BP’s potential liability, as well as other factors, it is too early in the proceedings to estimate the exposure of BP in these state court proceedings.

MDL 2185 and other derivative cases: Similarly, BP expects to file motions to dismiss in the securities and ERISA cases pending in federal court in MDL 2185 and has filed (or expects to file) motions to dismiss in the derivative cases pending in federal court in MDL 2185 and in certain state courts. In the now-consolidated ERISA case pending in MDL 2185, the parties have agreed to defer the time to respond until 60 days after filing of a consolidated amended complaint. Only limited discovery has commenced in any of these cases and no plaintiff has made a quantified claim of damages in discovery so far.

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Insurance cases: In the two insurance coverage actions, certain of Transocean’s insurers seek a declaration that they have no obligation to defend or indemnify BP against DWH liabilities as an “additional insured”. BP has counterclaimed for a declaration of coverage. BP has filed a motion to consolidate the two cases in the Southern District of Texas while the insurers have argued that the cases should be transferred to MDL 2179. The Judicial Panel on Multidistrict Litigation has conditionally transferred the cases to MDL 2179, and briefing on BP’s motion to vacate the conditional transfer order is underway.

No discovery has taken place in either action, nor has a discovery or case management schedule been set. There has been no briefing on the legal issue of BP’s right to claim under the policies as an “additional insured,” or on other substantive coverage defenses that the insurers may assert. In addition, Transocean’s insurance program provides an aggregate of $1 billion in coverage, which may be exhausted by payments to Transocean for its own liabilities. As a result of these and other factors, it is too early in the proceedings to quantify any potential recovery by BP in these proceedings.

Future Events that May Lead to an Increased Ability to Measure Litigation Exposure

As suggested above, upcoming events in the litigation may (in the future) increase BP’s ability to reasonably measure its litigation exposure in these matters. Such events include (but are not limited to) the following:

Legal rulings on expected motion practice in MDL 2179, MDL 2185 and other cases.

Disclosures in discovery, including amount of damages claimed by various plaintiff groups through fact discovery or in expert reports.

The results of the GCCF claims process, especially final claims that are expected to include the execution of releases by claimants who elect to accept final payments.

Findings and conclusions of the MDL 2179 court in the Limitation action trial in 2012, as well as the result of any appeal of such findings and conclusions.

Possible settlements (if any) negotiated with various plaintiffs and plaintiffs’ groups, and possibly among BP and other defendant parties such as its business partners.

Contingent Liabilities: Other OPA Claims

Governmental Claims

At this time, BP is unable to estimate the extent of potential liability with regard to state and local claims under OPA. This uncertainty derives in large part from the nature of the potential liability to government entities under OPA. A responsible party is liable to states and their political subdivisions for the net loss of certain revenue and net increased costs of certain public services directly caused by the oil spill. The calculation of net loss turns on a number of variables, several of which will not be known or estimable for some time to come. First, with regard to allegations of lost income tax revenue, BP and the GCCF have compensated and will continue to compensate individuals and businesses for their legitimate claims. Such claims payments are subject to income tax and thus will offset alleged loss of income tax revenue in many circumstances. Likewise, claims payments to individuals and business will generate sales and other tax revenue, which must be taken into account in calculating net loss. Second, the unprecedented response effort has and continues to generate significant tax revenue, which must be offset against alleged losses. For example, response teams numbering in the tens of thousands stayed at hotels, shopped at stores, ate at restaurants, purchased fuel and earned income, all of which are subject to taxation, in multiple jurisdictions throughout the Gulf. In addition, goods purchased for the response effort were and are subject to taxation. Because it is necessary to take into account the many streams of taxable revenue discussed above, among others, it will not be possible to reliably estimate potential liability for state and local government claims until the claims payment process, litigation seeking recovery for alleged economic loss, and the response effort are much closer to completion.

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Incurred But Not Reported Claims

It is also not possible to estimate the Company’s potential liability with respect to claims under OPA that have been incurred but not yet reported at this time. BP’s, and subsequently the GCCF’s, claims process have been widely advertised throughout the Gulf states and beyond for the past seven months. During this time period, more than 500,000 individual and business claims have been filed with BP and the GCCF. Given the passage of time, the fact that the release of oil from the Macondo well was stopped in July, and the sheer volume of claims filed, it would be reasonable to assume that the large majority of potential claimants have filed claims. However, there is significant uncertainty as to how many claimants have yet to come forward and the extent of their claims and no reasonable basis to estimate what the potential liability on those claims might be.

Contingent Liabilities: Natural Resource Damages Claims

The NRD assessment is a highly-prescribed, technical and regulatory-driven process that is led by the governmental agencies responsible for natural resources and often takes several years. In this matter, there are over 15 different federal or state agencies responsible for the NRD assessment. To date, there has been no Government demand of BP with respect to NRD. To our knowledge, the Government has not produced or communicated any valuation of NRD resulting from the Deepwater Horizon incident.

It is not possible to provide a reasonable estimate for natural resource damages at this time. Many aspects of the natural resource damages assessment will require extensive spatial and temporal data collection. The spatial assessment is large because the area of potential impact includes several states and large parts of the Gulf of Mexico. The temporal assessment is extensive because data collection needs to be conducted over time in order to determine both the severity and duration of the injury. In many cases, data will need to be collected over one or more reproductive seasons in order to assess if there have been population impacts above baseline.

Further, due to the large scale of the NRDA in this case, the process of collecting, analyzing and interpreting data is very time consuming. There are approximately 90 cooperative studies on-going or completed. For few, if any, of these studies is there a complete dataset. Thousands of samples are still at labs waiting to be analyzed. Massive amounts of non-analytical data (field notes, photographs, instrumentation readings, GPS coordinates, chains of custody sheets, etc.) have not been exchanged, reviewed or analyzed. Until data is actually collected, verified, and interpreted, it is not possible to reliably estimate damages. If this matter proceeds as an ordinary NRDA process, the collection and evaluation of data to address this damages category would take at least two to four years.

There may be circumstances and discrete areas where an assessment of natural resource damages can occur more quickly. For example, in cases where there is limited injury or short-term injury only, the range of damages can be calculated. The ability to provide this analysis will depend upon, among other things, BP receiving all environmental data from various governmental agencies, much of which has not yet been shared with BP. Over the coming months, BP will be working with the various governmental agencies to obtain and evaluate this data.

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Contingent Liabilities: Civil Fines and Penalties Other Provisions Other Than Section 311 of the Clean Water Act

There are a number of provisions of federal and state environmental and other laws that the federal or state government could seek to invoke to seek civil fines or penalties arising from this incident. While a number of states have taken administrative actions as a predicate to seeking such penalties, no actions seeking such fines or penalties have yet been commenced in court. Even if such actions were to be commenced, it is not possible to determine at this time whether and to what extent the actions would be successful or what fines or penalties might be assessed. Even if such fines or penalties were sought, the maximum amounts the Government could seek would generally be determined on a per violation or per day basis, and the total amounts that could be sought would be vastly lower than the amounts that can be sought under Section 311 of the Clean Water Act. Thus, it is not expected that additional claims for civil fines or penalties would materially change the total liability, including under Section 311, that BP may have for civil fines or penalties.

Legal Proceedings, page 35

8.	We note your disclosure regarding purported class action lawsuits that have been filed in U.S. federal courts against BP entities and various current and former officers and directors alleging securities fraud claims. Please provide to us the complaints related to such lawsuits.

Response:

We are providing copies of the complaints relating to the securities fraud claims under separate cover.

Engineering Comments

Form 20-F for Fiscal Year Ended December 31, 2009

General

9.	For those prior comments to which you have agreed to prospective compliance, please furnish to us the disclosure you intend to provide.

Response:

In response to the Staff’s prior Comment 8, per the letter dated 24 September 2010, we will include the following tables:

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BP HAS CLAIMED CONFIDENTIAL TREATMENT OF PORTIONS OF

THIS LETTER IN ACCORDANCE WITH 17 C.F.R. § 200.83

Average sales price and production cost per unit of production for equity accounted entities

The table below presents our average sales price per unit of production.

									$ per unit of productiona
	Europe		North America		South America	Africa	Asia		Australia	Total group average
	UK	Rest of Europe	US	Rest of North America			Russia	Rest of Asia
Average sales priceb
Subsidiaries
2010
Liquidsc	XXX	XXX	XXX	XXX	XXX	XXX	–	XXX	XXX	XXX
Gas	XXX	XXX	XXX	XXX	XXX	XXX	XXX	XXX	XXX
2009
Liquidsc	62.19	60.73	53.68	30.77	52.48	57.40	–	61.27	57.22	56.26
Gas	4.68	7.62	3.07	3.53	2.50	3.61	–	3.30	5.25	3.25
2008
Liquidsc	89.82	93.77	89.22	64.42	91.61	89.44	–	97.20	86.33	90.20
Gas	8.41	6.96	6.77	7.87	4.90	4.46	–	3.63	9.22	6.00
Equity-accounted entities
2010
Liquidsc	XXX	XXX	XXX	XXX	XXX	XXX	XXX	XXX	XXX	XXX
Gas	XXX	XXX	XXX	XXX	XXX	XXX	XXX	XXX	XXX	XXX
2009
Liquidsc	XXX	XXX	XXX	XXX	XXX	XXX	XXX	XXX	XXX	XXX
Gas	XXX	XXX	XXX	XXX	XXX	XXX	XXX	XXX	XXX	XXX
2008
Liquidsc	XXX	XXX	XXX	XXX	XXX	XXX	XXX	XXX	XXX	XXX
Gas	XXX	XXX	XXX	XXX	XXX	XXX	XXX	XXX	XXX	XXX

a Units of production are barrels for liquids and thousands of cubic feet for gas.

b Realizations include transfers between businesses.

c Crude oil and natural gas liquids.

The table below presents our average production cost per unit of production.

									$ per unit of production
	Europe		North America		South America	Africa	Asia		Australia	Total group average
	UK	Rest of Europe	US	Rest of North America			Russia	Rest of Asia
The average production cost per unit of productiona
Subsidiaries
2010	XXX	XXX	XXX	XXX	XXX	XXX	XXX	XXX	XXX	XXX
2009	12.38	10.72	7.26	14.45	2.20	6.05	–	4.35	1.60	6.39
2008	12.19	8.74	9.02	15.35	2.34	6.72	–	5.24	1.74	7.24
Equity-accounted entities
2010	XXX	XXX	XXX	XXX	XXX	XXX	XXX	XXX	XXX	XXX
2009	XXX	XXX	XXX	XXX	XXX	XXX	XXX	XXX	XXX	XXX
2008	XXX	XXX	XXX	XXX	XXX	XXX	XXX	XXX	XXX	XXX

a Units of production are barrels for liquids and thousands of cubic feet for gas. Amounts do not include ad valorem and severance taxes.

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BP HAS CLAIMED CONFIDENTIAL TREATMENT OF PORTIONS OF

THIS LETTER IN ACCORDANCE WITH 17 C.F.R. § 200.83

In response to the Staff’s prior Comment 10, per the letter dated 24 September 2010, we will expand the 2010 disclosure to include the following information on our proved undeveloped reserves:

In 2010, we converted x,xxx mmboe of proved undeveloped reserves to proved developed reserves through ongoing investment in our upstream development activities. The table below describes the changes to our proved undeveloped reserves position through the year.

volumes in mmboe

	PUD volume at 1 January 2010	x,xxx
	Revisions of Previous Estimates	x,xxx
	Improved Recovery	x,xxx
	Discoveries & Extensions	x,xxx
	Purchases	x,xxx
	Sales	x,xxx
	Total in year PUD changes	x,xxx
	Progressed to PD	x,xxx
	PUD volume at 31 December 2010	x,xxx

In response to the Staff’s prior Comment 11, per the letter dated 24 September 2010, we will revise the line item in the SMOG reconciliation as shown below:

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	xx	xx	xx
Previously estimated Development costs incurred during the yearfor the current year as estimated in previous year	xx	xx	xx
Extensions, discoveries and improved recovery, less related costs	xx	xx	xx
Net changes in prices and production cost	xx	xx	xx
Revisions of previous reserves estimates	xx	xx	xx
Net change in taxation	xx	xx	xx
Future development costs	xx	xx	xx
Net change in purchase and sales of reserves-in-place	xx	xx	xx
Addition of 10% annual discount	xx	xx	xx
Total change in the standardized measure during the year	xx	xx	xx

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BP HAS CLAIMED CONFIDENTIAL TREATMENT OF PORTIONS OF

THIS LETTER IN ACCORDANCE WITH 17 C.F.R. § 200.83

In response to the Staff’s prior Comment 12, per the letter dated 24 September 2010, we will include the following sentence regarding lease expirations in the 2010 Form 20-F:

The group holds no licences due to expire within next three years which would have significant impact on BP’s reserves or production.

Exploration and Production, page 18

Key Statistics, page 19

10.	We note your response nine to our September 24, 2010 letter. Please tell us:

Whether you have made a final investment decision to develop all of each project’s proved undeveloped reserves;

For each project, the capital investments you made for drilling and those you made for infrastructure and the total capital investments that you have made and that are scheduled to be made.

The time from booking that you estimate each project will pay out its capital costs.

Response:

All of BP’s proved reserves reported in our SEC Form 20-F have had a final investment decision. Specifically, each of the projects mentioned in our response to the Staff’s comment letter dated 24 September 2010 have had a final investment decision to develop the project’s currently booked proved undeveloped reserves. We are fully committed to the development of these projects as shown by our financial commitments, as well as by our commitments to the local communities in which we operate.

USA and Canada Projects

San Juan North

In 2007 BP took a final investment decision to develop and fund a multi-billion dollar development program including infill drilling and infrastructure enhancements in the environmentally sensitive San Juan North field area. The San Juan Basin is one of the largest gas deposits in the USA and BP operates over 1,100 wells in the northern and 2,300 in the southern areas. We have lease agreements with individual mineral leaseholders, the US federal government and the sovereign nation of the Southern Ute Indian Tribe. The pace of development is governed by the needs of the environment and local communities, and not by BP’s timing considerations, nor the availability of BP capital. BP, the local communities and federal government recognize that this is a long-term project with commitments to development over many decades.

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BP HAS CLAIMED CONFIDENTIAL TREATMENT OF PORTIONS OF

THIS LETTER IN ACCORDANCE WITH 17 C.F.R. § 200.83

The actual and forecast capital investments for the San Juan North project, including the number of wells completed, are shown below.

		Actual 2007-2010 Incl	Forecast 2011-2017 Incl	Total
Well Count		[*]	[*]	[*]

Capital	Wells	[*]	[*]	[*]
Invested	Infrastructure	[*]	[*]	[*]
	Total	[*]	[*]	[*]

[US$ millions, Undiscounted, Working Interest Basis]

* CONFIDENTIAL INFORMATION HAS BEEN OMITTED AND FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION.

As mentioned in our response to the Staff’s comment letter dated 24 September 2010, BP has entered into a number of long-term agreements for gas delivery and electrical supply for facilities that would incur a penalty of approximately $50 million if the project was prematurely terminated.

The estimated time of payout, where we will recover our total capital investment on an undiscounted constant margin basis (i.e., existing economic conditions including prices and costs at which economic producibility from the reservoir was determined) using 2009 average prices (as described in Rule S-X 210.4-10 para 22(v)), is [CONFIDENTIAL INFORMATION HAS BEEN OMITTED AND FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION]. Since the final investment decision in 2007, development has been consistent with the development plan and results have been in line or better than expected.

As a result of ongoing activity and further optimization of our rig scheduling and phasing in 2010, we have reduced the volume of proved undeveloped reserves beyond five years reported in our earlier reply from [CONFIDENTIAL INFORMATION HAS BEEN OMITTED AND FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION] to [CONFIDENTIAL INFORMATION HAS BEEN OMITTED AND FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION].

Wamsutter

In 2005 BP made a final investment decision on a $2.2 billion Wamsutter project for the drilling of 2,000 wells and a $120 million technology program for further development. In 2008, after a spend of $700 million on the project, BP made a final investment decision to expand the project to a $7.4 billion development program which required a major mobilization of staff and industry capability within the region. We have made significant commitments to the local community on staffing and to midstream and purchasers for obtaining concessions for compression and transport.

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BP HAS CLAIMED CONFIDENTIAL TREATMENT OF PORTIONS OF

THIS LETTER IN ACCORDANCE WITH 17 C.F.R. § 200.83

The actual and forecast capital investments for the Wamsutter project through the end of development drilling, including the number of wells completed, are shown below. We will invest an additional [CONFIDENTIAL INFORMATION HAS BEEN OMITTED AND FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION] of capital in Wamsutter beyond the end of development drilling to ensure that facilities are in compliance with regulatory changes. Our current total anticipated capital spend in Wamsutter is [CONFIDENTIAL INFORMATION HAS BEEN OMITTED AND FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION] following optimization of the drilling program (32% savings), other efficiency gains and reductions in BP’s working interest in the total project.

		Actual 2005-2010 Incl	Forecast 2011-2023 Incl	Total
Well Count		[*]	[*]	[*]

Capital	Wells	[*]	[*]	[*]
Invested	Infrastructure	[*]	[*]	[*]
	Total	[*]	[*]	[*]

[US$ millions, Undiscounted, Working Interest Basis]

* CONFIDENTIAL INFORMATION HAS BEEN OMITTED AND FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION.

The estimated time of payout, where we will recover our total capital investment on an undiscounted constant margin basis using 2009 average prices, is [CONFIDENTIAL INFORMATION HAS BEEN OMITTED AND FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION]. Since the final investment decision in 2005 and 2008, development has been consistent with the development plan and results have been in line or better than expected.

Noel

The final investment decision for the Canada Noel project, including all wells, was taken by BP in 2008. The final investment decision included drilling, completion, and tie-in of 136 wells and construction of 6 gathering and compression nodes, key trunk lines, and power lines, at a total cost of US$1.5 billion.

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BP HAS CLAIMED CONFIDENTIAL TREATMENT OF PORTIONS OF

THIS LETTER IN ACCORDANCE WITH 17 C.F.R. § 200.83

The actual and forecast capital investments for the Noel project, including the number of wells completed, are shown below.

		Actual 2008-2010 Incl	Forecast 2011-2018 Incl	Total
Well Count		[*]	[*]	[*]

Capital	Wells	[*]	[*]	[*]
Invested	Infrastructure	[*]	[*]	[*]
	Total	[*]	[*]	[*]

[US$ millions, Undiscounted, Working Interest Basis]

* CONFIDENTIAL INFORMATION HAS BEEN OMITTED AND FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION.

As mentioned in our response to the Staff’s comment letter dated 24 September 2010, a twenty year, take-or-pay commitment was made with Spectra, a midstream gas processing company, to supply [CONFIDENTIAL INFORMATION HAS BEEN OMITTED AND FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION] of gas. The full count of [CONFIDENTIAL INFORMATION HAS BEEN OMITTED AND FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION] wells to be drilled through 2018 is required to fulfill these contract rates.

The estimated time of payout, where we will recover our total capital investment on an undiscounted constant margin basis using 2008 average prices, is [CONFIDENTIAL INFORMATION HAS BEEN OMITTED AND FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION]. The estimated time of payout using 2009 average prices and estimated future capital investments is [CONFIDENTIAL INFORMATION HAS BEEN OMITTED AND FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION]. There has been no substantive change in project activity or pace of investment since project final investment decision in 2008.

BP sold the Noel asset in 2010 as a part of a larger divestment of gas assets in Canada.

Anadarko, Woodford Shale and Jonah

As a result of ongoing activity and further optimization of our rig scheduling and phasing in 2010, the volumes of proved undeveloped reserves that will not be converted to proved developed reserves within five years has dropped significantly in the Anadarko, Woodford Shale and Jonah. These reductions show the orderly progression of proved undeveloped to proved developed reserves that we expect as our large field developments mature.

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BP HAS CLAIMED CONFIDENTIAL TREATMENT OF PORTIONS OF

THIS LETTER IN ACCORDANCE WITH 17 C.F.R. § 200.83

We now believe that none of the 2010 proved undeveloped reserves in the Anadarko asset will remain undeveloped beyond five years.

All our 2010 proved undeveloped reserves booked in the Woodford Shale will be progressed to proved developed reserves within six years. The proved undeveloped reserves that will be converted to proved developed reserves beyond five years is 8 mmboe.

All our 2010 proved undeveloped reserves booked in the Jonah asset will be progressed to proved developed reserves within six years. The proved undeveloped reserves that will be converted to proved developed reserves beyond five years is 2 mmboe.

Trinidad Gas Projects

Each of the projects referenced below is a critical component of the fulfillment of our gas commitments in Trinidad. BP produces 450 thousand barrels of oil equivalent a day from 12 offshore platforms in Trinidad. Our production represents approximately 55 percent of Trinidad and Tobago’s production and ten percent of BP’s global production. BP has a long track record of hub field tie-backs to the existing infrastructure. Each of these developments requires the construction of offshore facilities and is being developed in an infrastructure-led manner where field developments are phased to meet but not excessively exceed facility capacity limits over many years. All of the projects share infrastructure and hub facilities. As mentioned in our response to the Staff’s comment letter dated 24 September 2010, there are significant penalties for not fulfilling our contractual obligations for gas supply. As an example calculation, if there was a 200 mmscfd shortfall of gas, this would result in an annual penalty of over [CONFIDENTIAL INFORMATION HAS BEEN OMITTED AND FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION].

Serrette

Final investment decision was taken in 2001 for the Serrette field development as part of our fulfillment of gas sales contracts within Trinidad. Development spending began in 2009. First production is expected in early 2011.

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BP HAS CLAIMED CONFIDENTIAL TREATMENT OF PORTIONS OF

THIS LETTER IN ACCORDANCE WITH 17 C.F.R. § 200.83

The actual and forecast capital investments for the Serrette project, including well counts, are shown below.

		Actual 2001-2010 Incl	Forecast 2011-2017 Incl	Total
Well Count		[*]	[*]	[*]

Capital	Wells	[*]	[*]	[*]
Invested	Infrastructure	[*]	[*]	[*]
	Total	[*]	[*]	[*]

[US$ millions, Undiscounted, Working Interest Basis]

* CONFIDENTIAL INFORMATION HAS BEEN OMITTED AND FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION.

The estimated time of payout for Serrette, where we will recover our total capital investment on an undiscounted constant margin basis using 2009 average prices, is [CONFIDENTIAL INFORMATION HAS BEEN OMITTED AND FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION]. There has been no substantive change in project activity or pace of investment since project final investment decision in 2001.

Angelin

Final investment decision was taken in 2000 for the Angelin field development as part of our fulfillment of gas sales contracts within Trinidad. Development spending is scheduled to begin in 2013.

The actual and forecast capital investments for the Angelin project, including the number of wells completed, are shown below.

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BP HAS CLAIMED CONFIDENTIAL TREATMENT OF PORTIONS OF

THIS LETTER IN ACCORDANCE WITH 17 C.F.R. § 200.83

		Forecast 2011-2018 Incl
Well Count		[*]

Capital	Wells	[*]
Invested	Infrastructure	[*]
	Total	[*]

[US$ millions, Undiscounted, Working Interest Basis]

* CONFIDENTIAL INFORMATION HAS BEEN OMITTED AND FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION.

The estimated time of payout for Angelin, where we will recover our total capital investment on an undiscounted constant margin basis using 2009 average prices, is [CONFIDENTIAL INFORMATION HAS BEEN OMITTED AND FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION]. There has been no substantive change in planned project activity or pace of investment since project final investment decision in 2000.

SEQB

Final investment decision was taken in 2003 for the SEQB field development as part of our fulfillment of gas sales contracts within Trinidad. Development spending is scheduled to begin in 2014.

The actual and forecast capital investments for the SEQB project, including the number of wells completed, are shown below.

		Forecast 2011-2018 Incl
Well Count		[*]

Capital	Wells	[*]
Invested	Infrastructure	[*]
	Total	[*]

[US$ millions, Undiscounted, Working Interest Basis]

* CONFIDENTIAL INFORMATION HAS BEEN OMITTED AND FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION.

The estimated time of payout for SEQB, where we will recover our total capital investment on an undiscounted constant margin basis using 2009 average prices, is [CONFIDENTIAL INFORMATION HAS BEEN OMITTED AND FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION]. There has been no substantive change in planned project activity or pace of investment since project final investment decision in 2003.

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BP HAS CLAIMED CONFIDENTIAL TREATMENT OF PORTIONS OF

THIS LETTER IN ACCORDANCE WITH 17 C.F.R. § 200.83

Manakin

Final investment decision was taken in 2003 for the Manakin field development as part of our fulfillment of gas sales contracts within Trinidad. Development spending is scheduled to begin in 2014.

The actual and forecast capital investments for the Manakin project, including the number of wells completed, are shown below.

		Forecast 2011-2019 Incl
Well Count		[*]

Capital	Wells	[*]
Invested	Infrastructure	[*]
	Total	[*]

[US$ millions, Undiscounted, Working Interest Basis]

* CONFIDENTIAL INFORMATION HAS BEEN OMITTED AND FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION.

The estimated time of payout for Manakin, where we will recover our total capital investment on an undiscounted constant margin basis using 2009 average prices, is [CONFIDENTIAL INFORMATION HAS BEEN OMITTED AND FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION]. There has been no substantive change in planned project activity or pace of investment since project final investment decision in 2003.

*****

In some of our responses, we have agreed to change or supplement the disclosure in our future filings. We are doing that in response to the Staff’s comment and not because we believe our prior filing is materially deficient or inaccurate. Accordingly, any changes implemented in future filings should not be taken as an admission that prior disclosures were in any way deficient.

We acknowledge that BP is responsible for the adequacy and accuracy of the disclosure in its Form 20-F, that Staff comments or changes to disclosure in response to Staff comments do not foreclose the Commission from taking any action with respect to BP’s Form 20-F, and that BP may not assert Staff comments as a defense in any proceeding initiated by the Commission or any person under the federal securities laws of the United States.

As discussed with the Staff, we are available to discuss the foregoing with you and the Staff at your convenience either by telephone or in person.

Very truly yours,

/s/ B.E. GROTE

B.E. GROTE

cc:	K. Campbell (Sullivan & Cromwell LLP)

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BP p.l.c. (BP) CORRESPCorrespondence with SEC