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

July 13, 2007


April Sifford
Branch Chief
Securities and Exchange Commission
100 F Street NE
Washington DC 20549
USA

www.bp.com

Re: BP p.l.c.
Form 20-F for the Fiscal Year Ended December 31, 2006
Filed March 6, 2007
File No. 001-6262

Dear Ms. Sifford:

Thank you for your letter dated June 18, 2007 setting forth comments of the Staff of the Commission (the “Staff”) relating to the Form 20-F for the Fiscal Period Ended December 31, 2006 of BP p.l.c. (the “20-F”) (File No. 001-6262).

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.

General

1.

We note that the disclosure on page 10 of your 20-F regarding contacts with Iran differs from the disclosure included in the 2005 20-F regarding such contacts, in that it states that “BP conducts or has conducted” certain activities in Iran and in other countries subject to U.S. sanctions. Please advise us whether you conducted activities in Iran during 2006 and whether you currently conduct activities there, and describe any such activities. Please also identify for us the other countries subject to U.S. sanctions to which you refer.

Response:

In response to the Staff’s comment, we confirm that BP conducted limited marketing, licensing and trading activities in Iran during 2006 and currently conducts such limited activities. The words “has conducted” were inserted because BP previously had conducted technical studies in Iran but did not conduct any technical studies there during 2006 and is not currently conducting any technical studies in Iran. We also advise the Staff that BP no longer has a representative office in Iran.

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With respect to other countries subject to US sanctions, BP sells small quantities of lubricants in Cuba and obtains small volumes of crude oil supplies from Syria, mainly for use in its own operations, primarily in France and Germany. These sales and purchases are insignificant, amounting to 0.0045 % of total sales and other operating revenues and 0.22% of purchases in 2006, respectively. BP has no offices in these countries and does not provide any other goods, technologies or services in these countries.

Information on the Company, page 10

Exploration and Production, page 12

Midstream activities, page 21

2.	We understand your Exploration and Production segment includes the activity related to direct and indirect interests in crude oil and natural gas transportation systems. However, you have disclosed that onshore US crude oil and product pipelines and related transportation assets are included under your Refining and Marketing segment. Please tell us why only these onshore US transportation assets have been segregated from the other transportation assets and included in a separate segment. In your response, please refer to the guidance of IAS 14, paragraphs 9 through 15 regarding how you defined your reportable segments as it relates to your transportation assets.
Response:	Under IAS 14 paragraph 9, a business segment is a distinguishable component of an entity that is engaged in providing an individual product or service or a group of related products or services and that is subject to risks and returns that are different from those of other business segments. We note that paragraph 27 of IAS 14 states that an entity’s internal organizational and management structure and its system of internal financial reporting to key management personnel (for example, the board of directors and the chief executive officer) shall normally be the basis for identifying the predominant source and nature of risks and differing rates of return facing the entity.
	The activities of the Exploration and Production (E&P) segment include oil and natural gas exploration, development and production (upstream activities), together with related pipeline, transportation and processing activities (midstream activities). The Refining and Marketing (R&M) segment’s activities include oil supply and trading and the manufacture and marketing of petroleum products as well as refining and marketing and related pipeline and transportation activities. Transportation assets, including pipelines, are included within one of the two business segments described above, depending on the segment to which the risks and returns of transportation assets are most closely related and depending on BP’s organizational structure and internal financial reporting systems.
	The interests in crude oil transportation systems such as the Trans Alaska Pipeline System and the Forties Pipeline System are considered to be closely related to, and subject to the risks and returns of, the E&P activities in Alaska and the North Sea, whilst the US onshore pipelines are used in transporting crude oil and oil products between refineries and markets and are thus considered to be more closely related to, and subject to the risks and returns of, the activities of the R&M segment.

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Financial and Operating Performance, page 40

3.	We note your disclosure regarding inventory holding gains and losses recognized during the years ended December 31, 2006, 2005 and 2004. You state inventory holding gains and losses represent the difference between cost of sales accounted for using the average cost method versus using the first-in, first-out method. The footnotes to the financial statements state inventories are accounted for under the first-in, first-out method. Tell us if by recognizing these inventory holding gains and losses, you have effectively accounted for inventories using the average cost method in your financial statements. If not, tell us what these amounts represent, why you have separately disclosed them in your discussion of profit attributable to BP shareholders and where they have been accounted for in the statements of income. In your response, please tell us if the “average cost of supplies” method is equivalent to the “weighted average cost formula” referred to in IAS 2, paragraph 25.
Response:	We confirm that we have not accounted for inventories using the average cost method in our financial statements. As stated in our accounting policy note on page 95 of the 20-F, inventories, other than inventory held for trading purposes, are stated at the lower of cost and net realizable value. Cost is determined by the first-in first-out (“FIFO”) method and comprises direct purchase costs, cost of production, transportation and manufacturing expenses.
	This is in contrast to our accounting for other supplies, such as certain catalysts, plant spares and packaging. These supplies are valued at cost of the Group, using the weighted average cost formula as set out in IAS 2, or net realizable value, whichever is lower.
	In our MD&A we say “Inventory holding gains or losses represent the difference between the cost of sales calculated using the average cost of supplies incurred during the year and the cost of sales calculated on the first-in first-out method.” Under the FIFO method, the cost of inventory charged to the income statement can vary significantly from the corresponding sales price because the inventory was purchased at an earlier date when the oil price was different. The amounts disclosed represent the impact of this effect on the reported result. By comparing the charge to the income statement on a FIFO basis with the charge to the income statement using average cost of supplies incurred during the year we have isolated the impact of this effect.
	Management believes this information is useful to illustrate to shareholders the fact that crude oil and product prices can vary significantly from period to period and the impact on our reported result under IFRS can be significant. In order for users of the accounts to understand the underlying performance of the Group, and to make comparisons between reporting periods, BP’s management believes it is helpful to disclose this impact.
	The use of average cost of supplies incurred during the year is not equivalent to the weighted average cost formula referred to in IAS 2.

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Refining and Marketing, page 44

4.	You identify the impact of IFRS fair value accounting as one of the primary additional factors reflected in profit before interest and tax of the Refining and Marketing segment on page 45 and of the Gas, Power and Renewables segment on page 46. Tell us what you mean by “IFRS fair value accounting” and how you have calculated the amounts disclosed and determined whether it results in a positive or negative impact. In your response, please address why you believe this amount is a primary factor of your profit or loss and why it is material information for your investors to understand.
Response:	Summary
	Changes in oil and gas prices can be a significant factor in the change from period to period in the reported results for the Refining and Marketing and Gas, Power and Renewables segments. In part this is because of the way IFRS requires certain inventories, forward physical contracts and capacity contracts (and related derivative instruments which BP uses to manage price exposures) to be accounted for, which differs from the way management measure performance. This is what we mean by fair value accounting effects and is described below more fully under “Explanation”.
	Analysts and investors regularly ask Management to provide more information regarding how this impacts the reported results. We have sought to do this through our discussion in the MD&A. The amounts we disclose are the impact of the differences between management’s measure of performance and the result under IFRS. These amounts are not reported in the IFRS financial statements or the notes thereto because they are not based on IFRS accounting principles and are therefore non-GAAP measures.
	Explanation
	BP uses derivative instruments to manage the economic exposure relating to inventories above normal operating requirements of crude oil, natural gas and petroleum products as well as certain forward contracts to supply physical volumes at future dates. Under IFRS these inventories and forward contracts cannot be recorded at fair value. The related derivative instruments, however, are required to be recorded at fair value with gains and losses recognized in income because hedge accounting is either not permitted or not followed, principally due to the impracticality of effectiveness testing requirements. Therefore, measurement differences in relation to recognition of gains and losses occur. Gains and losses on these inventories and forward contracts are not recognized until the commodity is sold in a subsequent reporting period. Gains and losses on the related derivative commodity contracts are recognized in the income statement from the time the derivative commodity contract is entered into on a fair value basis using forward prices consistent with the contract maturity.
	IFRS also requires that inventory held for trading be recorded at its fair value using period end spot prices whereas any related derivative commodity instruments are required to be recorded at values based on forward prices consistent with the contract maturity. Depending on market conditions, these forward prices can be either higher or lower than spot prices resulting in measurement differences.

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In addition to the above, the Gas, Power and Renewables business enters into contracts for pipelines and storage capacity which, under IFRS cannot be fair valued. These contracts are risk managed using a variety of derivative instruments which are fair valued under IFRS. Again, this results in measurement differences in relation to recognition of gains and losses.

Calculation of the amounts disclosed

The way that BP manages the economic exposures described above through the use of derivatives and measures performance internally, differs from the way these activities are measured under IFRS. We calculate this difference by comparing the IFRS result with management’s internal measure of performance, under which the inventory, forward contracts and capacity contracts in question are valued based on a fair value using relevant forward prices prevailing at the end of the period. We believe that disclosing management’s estimate of this difference provides useful information for investors because it enables investors to see the economic effect of these activities as a whole.

The impact is positive or negative depending on whether management’s internal performance measure is higher or lower than the reported result under IFRS in the respective periods.

In future filings, we will clarify that these amounts are non-GAAP measures and explain how they are calculated.

Impairment and losses on sale of businesses and fixed assets, page 114

Loss on sale of fixed assets, page 115

5.	We note the principal transaction leading to a loss on the sale of fixed assets in the Refining and Marketing segment during 2006 was retail churn. Please tell us what you mean by “retail churn” and why it led to a loss in 2006 but not in the previous years.
Response:	‘Retail churn’ is the overall process of acquiring and disposing of retail sites by which BP aims to improve the quality and mix of its portfolio of service stations. This is an ongoing activity of the Group and results in either a gain or a loss on disposal, depending on the carrying value of the retail site and the proceeds received. The overall loss therefore reflects the specific amounts for the retail sites disposed of and the extent of disposal activity in any year.
	On page 115 of our 20-F, we noted that retail churn was also a principal factor in contributing to the loss on sale of fixed assets in 2004.

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36 Derivatives, page 132

6.	On page 133, you discuss your accounting for “day one profit” relating to derivatives held for trading purposes. To assist us in our understanding, it would be helpful for you to provide us with an example of the typical derivative purchased for trading purposes whose fair value on day one is not supported by an observable market. In your example, please identify the typical length of time from day one to the date observable market data is available, at which point you recognize the deferred amounts of “day one profit”. Additionally, tell us the amount of deferred day one profit recognized on the balance sheet as of December 31, 2006 and 2005. Please support your accounting by specifically referring to the appropriate IFRS literature.
Response:	An example of a typical derivative entered into for trading purposes whose fair value at inception is not supported by an observable market would be a derivative swap agreement with an industrial counterparty to exchange one set of cash flows based on a specific floating gas price index in the UK for a fixed set of cash flows over a ten-year term. Settlement will be made financially on a net basis through monthly payments based on the difference between the floating price and the fixed price multiplied by a notional amount.
	The tenure of the contract extends beyond the active trading market for natural gas, which we have determined to be five years. In this example, any calculated inception gain (i.e. day one profit) based on a combination of observable prices for the first five years and extrapolated prices for the last five years will be deferred and will not be recognized in the income statement until the referenced natural gas price index is observable for the remaining term of the transaction (i.e. when only five years of the contract remains).
	As disclosed in the table on page 133 of the 20-F, the amount of deferred “day one profit” recognized on the balance sheet as of December 31, 2006 and 2005, was $36 million and $49 million, respectively.
	The deferral of these amounts results from applying the fair value guidance as discussed in IAS 39, paragraph 48. This guidance states that “In determining the fair value of a financial asset or a financial liability for the purpose of applying this Standard, IAS 32 or IFRS 7, an entity shall apply paragraphs AG69-AG82 of Appendix A.”
	Paragraph AG76 of Appendix A, in part, states:
	“The best evidence of the fair value of a financial instrument at initial recognition is the transaction price (i.e. the fair value of the consideration given or received) unless the fair value of that instrument is evidenced by comparison with other observable current market transactions in the same instrument (i.e. without modification or repackaging) or based on a valuation technique whose variables include only data from observable markets.”
	We believe that this supports our accounting for the deferral of day one profits. In our example above, as there is not an observable market beyond five years in order to determine the fair value, the inception gain (i.e. day one profit) is deferred and is not recognized in the income statement until the referenced natural gas price index is observable for the remaining term of the transaction.

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7.

On a similar matter, please tell us how you have accounted for “day one profit” under US GAAP. Please refer to the appropriate guidance used to support your accounting and where you accounted for any differences between IFRS and US GAAP in the reconciliation in note 53.

Response:

The guidance supporting our accounting for “day one profits” under US GAAP is footnote 3 of EITF 02-3, “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities” (Issue 02-3). Issue 02-3 prohibits inception gains for certain derivatives in the absence of: i) quoted market prices in an active market; ii) observable prices of other current transactions; or iii) other observable data supporting the valuation technique. We are aware that in September 2006, the FASB issued Statement No. 157, Fair Value Measurements (FAS 157), which nullifies the guidance in footnote 3. FAS 157 is effective for fiscal periods beginning after November 15, 2007 and we have not adopted it early. We believe the guidance in footnote 3 of EITF 02-3 is consistent with the IFRS guidance in paragraphs AG76 of Appendix A to IAS 39 (see response to Comment 6). As such, we have not disclosed any differences between IFRS and US GAAP in the US GAAP reconciliation in Note 53.

41 Pensions and other post-retirement benefits, page 143

8.	You have disclosed that assumptions used to determine projected benefit plan obligations, pension and other post-retirement benefit expenses, and the calculation of contributions to defined benefit plans are based on advice from independent actuaries. Please revise your disclosure to name the actuaries used and provide a consent as an expert. Refer to Section 7(a) of the Securities Act of 1933.
Response:	The assumptions used to determine projected benefit plan obligations, pension and other post-retirement benefit expenses, and the calculation of contributions to defined benefit plans are management’s assumptions. We will delete the reference to third party actuaries in our future filings.

44 Share-based payments, page 153

9.	Please identify the third party estimate used in determining expected volatility. To the extent you are relying upon estimates provided by a third party, revise your disclosure to name the third party you are relying on and provide a consent as an expert. Refer to Section 7(a) of the Securities Act of 1933.
Response:	The fair value of share-based payments is determined by management using an appropriate valuation model. Management is responsible for all inputs and assumptions in relation to that model, including the determination of expected volatility. In our future filings, we will not refer to the use of a third party estimate.

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53 US GAAP reconciliation, page 169

(b) Provisions, page 171

10.	We note you have recorded a provision for asset retirement obligations related to the costs of decommissioning oil and natural gas production facilities and pipelines under IFRS using an estimate of economic lives of 30 years or less. Tell us what information you used to support the expected settlement dates used in your accounting under IAS 37. In addition, please support the reliability and accuracy of these estimates under the guidance of SFAS 143 and FIN 47 in accounting for your asset retirement obligations under US GAAP.
Response:	The oil and natural gas production facilities and pipelines referred to above and in Note 40 to the financial statements are those that are integrated within oil and/or natural gas fields. Decommissioning provisions are recognised at the time the liability is incurred.
	Uncertainty relating to the timing of the decommissioning is reflected in the estimate of the expected settlement dates. In arriving at the expected settlement dates used in accounting for the associated decommissioning provisions under IAS 37, we use management’s best estimate of the timing of when the decommissioning will occur. This is driven by the assessment of the expected date of cessation of production at the respective fields. A number of estimates are used to determine the expected date of cessation of production that are also key to management’s future planning and decision making regarding the respective assets, including estimates of hydrocarbon reserves, costs of production and commodities prices. These estimates are based on our long run and asset specific planning assumptions. In arriving at the expected settlement date, the date of cessation of production is adjusted to reflect track record/experience of existing decommissioning projects or specific knowledge of the timing of decommissioning as the project itself approaches decommissioning. The expected timing of decommissioning expenditure is reviewed annually by the Audit Committee.
	The decommissioning cost estimates are based on our best estimate of the future expenditure. Cost estimates for assets where the cessation of production date is within five years are based on current market prices. For assets where the cessation of production date is beyond five years, cost estimates are based on our best judgement of future costs based on knowledge of local markets and on our long run planning assumptions.
	Decommissioning cost estimates are updated quarterly for changes in assumptions and circumstances, such as facility installation. Annually, there is a comprehensive update of all assumptions, circumstances and estimates.
	We believe that the above estimates form the basis of our reasonable estimate of the fair value of the decommissioning provisions as discussed in paragraph 3 of FAS 143 and FIN 47.

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11.	Please revise your reconciliation of changes in asset retirement obligations under US GAAP presented on page 172 to separately state new provisions incurred and adjustments to previously recorded provisions. See paragraph 22(c) of SFAS 143 for further guidance.
Response:	Under IFRS we disclose new provisions or increases in provisions within the same line item, as permitted by IAS 37, paragraph 84. Please see below the revised reconciliation of changes in asset retirement obligations. We will present the reconciliation in this revised format in our future filings with the SEC.

	2006			2005
	$ million			$ million
At 1 January		4,429			3,898
Exchange adjustments		9			4
New provisions		177			217
Adjustments to provisions		1,502			337
Unwinding of discount		280			237
Utilized/deleted		(360	)		(264	)
At 31 December		6,037			4,429

(c) Oil and natural gas reserves differences, page 172

12.

We understand the calculation of reserves under UK SORP versus under US SEC rules results in a difference, which effects depreciation, depletion and amortization expense. We note you adopted the SEC rules as a basis for determining your reserves for the last three months of fiscal year 2006. The reconciliation to US GAAP includes adjustments to increase depreciation, depletion and amortization in 2006 and to decrease the expense in 2005 and 2004. Similarly, we note the adjustments to property, plant and equipment decrease the amount as of December 31, 2006 and increase the amount as of December 31, 2005. Please explain why the adjustments in 2006, which include only the change in estimate for three months, are not consistent with adjustments to prior periods.

Response:

The difference between depreciation, depletion and amortization (“DD&A”) under IFRS and DD&A under US GAAP is dependent upon many different factors across our whole portfolio of assets that impact DD&A in different ways. Some factors increase DD&A under US GAAP whilst others decrease DD&A under US GAAP. As noted, the change to reserves methodology which occurred in the last three months of the year impacted the difference in 2006. In 2006, changes in the size of the difference were, in particular, also impacted by:

• Changes in the level of production for assets with significant differences in net book values; increases or decreases in production compared to prior periods result in changes to the difference between the DD&A under IFRS and US GAAP.

• Disproportionate changes in SORP and SEC reserves; where changes in assumptions result in a change to SORP reserves which is different from the corresponding change to SEC reserves, this will result in a change to the difference between DD&A under IFRS and US GAAP.

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The adjustment to Property, Plant and Equipment is driven by the same factors noted above and reflects the brought forward adjustment plus the current year DD&A difference. The adjustment also reflects the impact of disposals where there was a difference between their net book values under IFRS and US GAAP.

In addition to the factors above, we note that in 2004 and 2005 we included certain impairment related adjustments within the Oil and Natural Gas reserves differences category of our reconciliation. In 2004 an adjustment of $110 million to reduce DD&A was included and in 2005 an adjustment of $94 million to reduce DD&A was included. The inclusion of these amounts did not materially impact the Groups DD&A charge under US GAAP since they represent less than 1% of US GAAP DD&A of $11.5 billion in 2004 and $9.5 billion in 2005. In 2006 all impairment related reconciliation items have been reported within the Impairments category of the US GAAP reconciliation.

***

BP acknowledges that it is responsible for the accuracy of the disclosure in its Form 20-F, that Staff comments or changes in response to Staff comments do not foreclose the Commission from taking any action with respect to BP’s 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.

Very truly yours,

/s/ B.E. GROTE

B.E. GROTE

cc: S. Buskirk (Securities and Exchange Commission)
K. Campbell (Sullivan & Cromwell LLP)
R. Wilson (Ernst & Young LLP)

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