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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

22 June 2015

By EDGAR

Mr. Ethan Horowitz,

Branch Chief,

Division of Corporation Finance,

Securities and Exchange Commission,

100 F Street, N.E.,

Washington, D.C. 20549-7010.

Dear Mr. Horowitz,

Re:

BP p.l.c.

Form 20-F for the Fiscal Year Ended 31 December 2014

Filed 3 March 2015

File No. 001-06262

I refer to your letter dated 22 May 2015 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 2014 (the “2014 Form 20-F”) (File No. 001-06262).

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 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.

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BP HAS CLAIMED CONFIDENTIAL TREATMENT OF PORTIONS OF

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

Form 20-F for Fiscal Year Ended December 31, 2014

Strategic Report, page 1

Our Market Outlook, page 10

We note that you sanction upstream projects at $80 per barrel, while testing projects for resilience at $60 per barrel. Please describe the process through which upstream projects are tested for resilience and explain how the results impacted your estimates of proved reserves. As part of your response, please tell us how recent declines in commodity prices were a factor in this testing process. In addition, tell us whether the pattern of volatility in commodity prices discussed in your filing represents a trend or uncertainty which management considers reasonably likely to have a material effect on the recoverability of your proved reserves. Refer to Item 5.D. of Form 20-F.

Response:

On page 10 of our 2014 Form 20-F we explained that we sanction upstream projects at $80 per barrel, while testing projects for resilience at $60 per barrel (in real terms based to 2012). All significant projects in BP follow a prescribed process, the “Capital Value Process” (CVP). At the point of sanctioning, upstream projects are evaluated at a central price case of $80 per barrel, and sensitivities at a high price case and a low price case are also considered. The low price case is $60 per barrel. Project economics are evaluated using a standard economic evaluation methodology and price assumptions are applied to the full duration of the project which typically exceeds 10 years, depending on the profile of recoverable resources. The oil price sensitivities are part of a range of standard sensitivities embedded in BP’s capital investment assurance and approval process that are required for evaluating any upstream project as it moves through the CVP. This approach is used by BP management to assess the quality and robustness of the project to prescribed theoretical market conditions. BP’s approach to evaluating investments has not changed in the current lower oil price environment. The disclosure in our filing was included to explain how we evaluate projects, with the prices used reflecting possible price scenarios for the longer term, not the current price environment at a particular point in time. The evaluation and sanctioning of projects through the CVP helps us to optimize the allocation of capital to potential investments.

The project investment assurance and approval process is separate from BP’s annual process for estimating and assuring proved reserves. It does, however, represent the first step for determining proved reserves, because no proved reserves are assigned to a project until a final investment decision has been taken. Moreover, our investment evaluation is based on the entire volume of hydrocarbons that we expect to recover, and not only the proved reserves that meet the economic and technical criteria under SEC regulations at the time. The reserves assurance process is designed to ensure that the Group’s estimate of proved reserves disclosed in its Form 20-F meets SEC requirements for proved reserves using the economic and technical criteria set out in Rule 4-10 of Regulation S-X, which includes an oil price assumption which equates to the average over the preceding 12 months.

As indicated in our 2014 Form 20-F, the relationship between commodity prices and reserves is complex. Under tax and royalty regime concessions, proved reserves typically decrease when oil prices are lower. Our entitlement to the proved reserves associated with production-sharing agreements often increases when oil prices are lower because we are entitled to recover volumes

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BP HAS CLAIMED CONFIDENTIAL TREATMENT OF PORTIONS OF

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

[*****] Indicates that certain information contained herein has been omitted and filed separately with the Securities and Exchange Commission. Confidential treatment has been requested with respect to the omitted portions.

equating to the costs incurred to develop and produce the proved reserves. Furthermore, whilst lower oil prices in the reporting period may impact the reporting of reserves at the year end, longer term oil and gas prices are a more significant factor in determining the ultimate economic recoverability of oil and gas reserves. Given the above complexities, and the uncertainty in relation to future commodity prices, it is not possible to assert whether there is a trend or uncertainty which is reasonably likely to have a material effect on the recoverability of proved reserves. For this reason, we have clearly identified the inherent uncertainty in oil and gas prices as one of BP’s material risk factors for investors to consider.

Notes on Financial Statements

Note 1 - Significant Accounting Policies, Judgements, Estimates and Assumptions, page 100

Development Expenditure, page 102

Disclosure in your filing refers to expired leases in the Gulf of Mexico for which you are negotiating extensions with the U.S. Bureau of Safety and Environmental Enforcement. Please describe your basis for stating that these leases are expected to be renewed and quantify the amount of capitalized exploration and appraisal costs related to this prospect. As part of your response, please tell us when you began negotiating lease extensions and describe the current state of those negotiations. In addition, please tell us whether you expect the renegotiated lease terms to provide you sufficient time to develop the subsea technology necessary to ensure that the hydrocarbons can be extracted safely.

Response:

The leases we referred to in our filing relate to the [*****] prospect in the Gulf of Mexico (“the Prospect”). In our disclosure we explained that a significant proportion of our capitalized exploration and appraisal costs in the Gulf of Mexico relate to this prospect. On page 124 of the 2014 Form 20-F we disclose an analysis of the amount of capitalized exploration and appraisal expenditure by geographical area. This analysis shows that the total carrying amount of capitalized exploration and appraisal expenditure for all prospects in the Gulf of Mexico was $4-5 billion at 31 December 2014. Of this amount, $[*****] billion is capitalized exploration and appraisal costs related to the Prospect.

Seven leases make up the Prospect. Four were due to expire on 20 December 2013 and three leases were due to expire on 9 August 2014. The Bureau of Safety and Environmental Enforcement (BSEE) has regulatory authority to suspend the termination of a lease for a set period of time pursuant to regulations that provide for either a Suspension of Operations (SOO) or a Suspension of Production (SOP). On 13 January 2013, BP submitted to BSEE a request for an SOO for the Prospect on the basis that BP needed time to develop 20K technology to safely develop the Prospect. On 13 March 2013, BSEE denied BP’s SOO request. BP has appealed the SOO denial with the Interior Board of Land Appeals (IBLA) of the Department of the Interior.

On 11 December 2013, BP filed a request for an SOP also on the grounds that it needed time to develop the 20K technology, as well as to drill production wells and arrange for a Floating Production Storage and Offloading vessel. On 18

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BP HAS CLAIMED CONFIDENTIAL TREATMENT OF PORTIONS OF

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

December 2013, BP filed an amended SOO application (the Amended SOO) that replaced the activity schedule with one based on the one BP submitted with its SOP request. On 11 July 2014, BP received BSEE’s denial of the SOP on the grounds that BP had not: (a) demonstrated a commitment to production; (b) submitted a reasonable schedule of work leading to the commencement of production; or (c) showed its request met the requirements of the regulations.

On 28 August 2014, BP appealed the denial of the SOP and the IBLA consolidated it with the pending appeal of the first SOO. The Amended SOO is still pending before BSEE. While the appeals are pending, the IBLA has issued an order, dated 16 September 2014, to which BSEE consented, staying the effect of the decisions under appeal thereby suspending termination of the leases.

Since September 2014, BP and BSEE have been actively negotiating a settlement to extend the terms of the leases. Historically, BSEE (previously the MMS) has granted suspensions of the lease terminations in numerous cases following similar negotiations with lease owners. The parties filed joint status reports as required by IBLA indicating the status of settlement proceedings on 16 December 2014, 13 March 2015 and 12 June 2015. In the joint status reports the parties represent that they are actively engaged in settlement negotiations that may resolve the issues underlying BP’s consolidated appeal.

The negotiations between BSEE and BP are confidential. [*****] Based on the status of negotiations with BSEE and BP’s understanding of BSEE’s historical practice for granting lease extensions in the Gulf, BP expects that the Prospect leases will be extended.

If the parties were not able to reach a settlement, then the parties would proceed to a formal appeal process through the IBLA. The leases would remain in effect until the final resolution of the appeal.

BP continues development of the 20K technology and is working collaboratively with other operators of discoveries in the same region. BP expects the negotiated grant of an SOP to provide sufficient time to complete development of the subsea 20K technology necessary to ensure the hydrocarbons can be extracted safely and BP will not agree to an activity schedule that does not provide sufficient time to do this.

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BP HAS CLAIMED CONFIDENTIAL TREATMENT OF PORTIONS OF

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

Additional Disclosures, page 207

Upstream Analysis by Region page 213

Australasia, page 216

We note that you signed a long-term LNG sales agreement with PT PLN (Persero), Indonesia’s state-owned electricity company. We also note the disclosure in your filing which states: “The agreement commits 40% of annual production from train 3 to the domestic market.” Please explain to us whether you have booked proved undeveloped reserves attributed to Tangguh train 3 and, if so, tell us the portion of train 3’s future production for which you have executed gas sales contracts. In addition, please tell us the portion of your required project capital you have financed and whether your partners have consented to fund their share of the project obligations. Also, please tell us whether you must enter into additional contracts for the remaining production from train 3 to proceed with the Tangguh expansion project.

Response:

The Tangguh partnership has signed two long-term LNG sales agreements which are intended to be supplied by Tangguh train 3. In addition to the PT PLN contract to supply domestic gas to Indonesia, we have an agreement with the Kansai Electric Power Company, which combined will commit approximately 65% of the 3.8 mtpa capacity of train 3. The partnership goal is to have 100% of the train 3 production under long-term LNG sales agreements at the start of construction, and negotiation on the sales of the remaining 1.3 mtpa of production is currently ongoing. However, in circumstances where less than 100% of the train 3 production is under long-term LNG sales agreements, the partnership can still determine to proceed with the expansion project.

We have reported net entitlement production associated with the PT PLN and Kansai contracts as proved undeveloped reserves in our 2014 Form 20-F. No uncontracted volumes have been included in our proved reserves for Tangguh train 3.

The Tangguh partnership has entered into a PSA with the Government of Indonesia. The Government of Indonesia and all partners have approved the Plan of Development and committed to the LNG sales agreements. The train 3 capital cost is projected to total $[*****] including both upstream and midstream. The upstream investment will be equity financed by the partners while the midstream facilities will be financed through third-party project financing of approximately $[*****]. Timing for the close of third-party financing is targeted for mid-2016 at the start of project execution.

Partners have consented to fund their share of the project obligations through mid-2016 (approximately $[*****] comprised of ca. $[*****] of capital expenditure and $[*****] of operating costs). The partner approved budget for 2015 is $[*****] consisting of work on onshore Front-End Engineering Design (FEED) and commitment to long lead items. Part of this investment will only be recovered, under the PSA terms, from train 3 production.

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BP HAS CLAIMED CONFIDENTIAL TREATMENT OF PORTIONS OF

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

*****

We acknowledge that BP is responsible for the adequacy and accuracy of the disclosure in its 2014 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 2014 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.

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. Gilvary
	Dr B. GILVARY

cc:	K.A. Campbell (Sullivan & Cromwell LLP)