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 |
October 8, 2010
By Hand
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 December 31, 2009
Filed March 5, 2010
File No. 001-06262
Dear Mr. Schwall:
I refer to your letter to David Jackson, BP company secretary, dated September 24, 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 December 31, 2009 (the “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. This letter contains confidential information of BP and is submitted to the Staff on a confidential basis. Concurrent with the submission to you of this letter, confidential treatment is being requested under the Commission’s rules. Accordingly, this response letter is being filed by hand and not via EDGAR. The other letter being submitted 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 20-F for Fiscal Year Ended December 31, 2009
Our Performance, page 11
Safety, page 11
| 1. | We note your response to comments 2 and 9 in our letter dated July 19, 2010, and your statement that you “would expect” to include a discussion in your 2010 Form 20-F of any significant changes to OMS in connection with the recommendations and lessons learned from the various investigations into the accident. Please confirm that you will disclose any material changes in your annual report on Form 20-F for the fiscal year ended December 31, 2010, if not sooner. |
| Response: | We confirm that we will include a discussion of any material changes in our 2010 Form 20-F. |
Risk Factors, page 14
| 2. | We note your response to comment 4 in our letter dated July 19, 2010. We also note your disclosure at page 43 of your report on Form 6-K dated July 28, 2010 that in many of your major projects and operations, risk allocation and management is shared with third parties, such as contractors, sub-contractors, joint venture partners and associated companies. In addition, we note your disclosure at page 45 of such 6-K regarding joint ventures and other contractual arrangements. Please expand your disclosure at page 43 to provide a cross-reference to the risk factor disclosure regarding joint ventures that you have provided at page 45. In addition, please disclose the portion of your operations that are subject to joint venture arrangements, and the portion of such arrangements for which you are not the operator. |
| Response: | In our 2010 Form 20-F and future filings, we will include a cross-reference to the risk factor disclosure regarding joint ventures in our discussion of joint venture arrangements. |
| | 76% of our total proved reserves of subsidiaries as at December 31, 2009 were subject to unincorporated joint venture arrangements, and we were not the operator for 27% of the proved reserves subject to such arrangements. We will disclose the figures for 2010 in our 2010 Form 20-F. |
| 3. | We note your response to comment 11 in our letter dated July 19, 2010. Please expand your disclosure to provide the information that you included in your response. Please also address in your revised disclosure your ability to respond to multiple spills. In addition, please quantify the physical and financial resources that you have allocated to your spill response plans. |
| Response: | We will expand our disclosure in our 2010 Form 20-F to include the information provided in response to the Staff’s prior comment 11 and the additional information below. |
BP HAS CLAIMED CONFIDENTIAL TREATMENT OF PORTIONS OF
THIS LETTER IN ACCORDANCE WITH 17 C.F.R. § 200.83
| | In the unlikely event of multiple concurrent spills, each affected facility would activate its independent Oil Spill Response Plan (see answer to comment 5 below) and respond accordingly. Although responding to multiple spills of the same magnitude and complexity as occurred in the Gulf of Mexico would be a challenge for the company, our response plans are not interdependent. Further, the plans do not contain physical or financial constraints – BP is committed to devoting such resources as are necessary to mitigate the consequences of any spill to people and the environment. This is demonstrated by the Deepwater Horizon incident. The cost of the response to October 7 is approximately $12 billion and at the peak of the response approximately 46,000 people (on July 11) and 6,890 vessels (on July 6) were deployed. Further, on June 16, BP announced an agreed package of measures, including the creation of a $20 billion escrow account to satisfy certain obligations arising from the spill. Following the Deepwater Horizon incident, we have also announced our intent to join the proposed Marine Well Containment Company (MWCC) and to make our underwater well containment equipment available to all oil and gas companies operating in the Gulf of Mexico. This and other equipment will preserve the current capability for use by the oil and gas industry in the U.S. Gulf of Mexico while Chevron, ConocoPhillips, ExxonMobil and Shell build a system that exceeds current response capabilities. Under the terms of an agreement with the MWCC operator ExxonMobil, the sponsor companies’ project team will utilize full time BP technical personnel with experience from the Deepwater Horizon response. BP considers that the deepwater intervention experience and specialized equipment will be important to the industry as a whole as well as the MWCC. In addition to the MWCC, we work with all of the other seven major international spill response organizations in the world. |
| 4. | Please expand your headings in your Risk Factors section to briefly describe the risk presented under each heading. |
| Response: | We will expand the headings in the Risk Factors section of our 2010 Form 20-F to briefly describe the risks presented under each heading. |
Corporate Responsibility, page 42
| 5. | The last bullet point of our prior comment 9 asked for details regarding current specific safeguards incorporated by your OMS to prevent oil spills and well blow outs with separate attention to offshore occurrences. Please describe for us the safeguards in place for containment of an offshore spill. |
| Response: | Central to our ability to manage the risk of loss of containment of hydrocarbon offshore are effective oil spill response plans (OSRPs). OSRPs will contain descriptions of facilities and procedures for containment at the source and for the protection of sensitive locations. Examples of containment include the resources described in our response to comment 3 above, in addition to the tactical and strategic resources in various locations around the world. |
BP’s Operating Management System (OMS) framework is a structured set of processes designed to keep the company’s operations safe, responsible and reliable.
BP HAS CLAIMED CONFIDENTIAL TREATMENT OF PORTIONS OF
THIS LETTER IN ACCORDANCE WITH 17 C.F.R. § 200.83
It includes a set of “Group Essential” statements and requires BP operating entities to apply a performance improvement cycle to attain and maintain conformance with them. So that BP operating entities are prepared for and able to respond to crisis and emergency events that may threaten the safe responsible and reliable operation of their assets, OMS includes the following Group Essentials:
| | · | Identify crisis and continuity management scenarios utilising the entity’s risk register, the output of the entity’s Major Accident Risk assessment and other information. |
| | · | Implement and maintain crisis and continuity management plans to manage the scenarios identified. These will include procedures from initiation to response and recovery. At site level, these plans shall include arrangements for evacuation and, where needed, for initial shelter-in-place. |
| | · | Validate the plans through exercising them at defined intervals. Review the plans at least annually to reflect changes in hazards, risks, organisation or contact details, and implement identified improvements. |
| | · | Provide access to the trained personnel, resources, medical emergency and other facilities needed to implement and execute the crisis and continuity management plans. |
| | · | Implement, maintain and exercise a documented process for accounting for personnel during and after an emergency evacuation. |
In addition to these Group Essentials it is the responsibility of each operating entity to meet any regulatory requirements relating to crisis and continuity management that apply in its location. When implementing the OMS, each of BP’s operating entities creates its own local OMS, tailored to its operations, which includes crisis and continuity plans for the scenarios identified in the entity’s risk register and Major Accident Risk assessment. For an entity that operates offshore assets this includes a plan for containment of an offshore spill (an OSRP). With regard to the safeguards in place for containing an offshore spill, including in the event of a well blow out, these were described in our response to your prior comment 11. See also our response to comment 3 above.
| 6. | We note your response to comment 12 in our letter dated July 19, 2010. As noted in our comment, your disclosure on page 74 states that “Areas where [the Independent Expert] believed more attention was warranted included….” Your disclosure in your annual report should include all material information related to the Independent Expert's annual report. If material, please expand your disclosure to identify in your annual report all of the areas that the Independent Expert believed warranted more focused attention. If you determine that certain such areas are not material and therefore determine not to disclose them, please ensure that your disclosure clearly indicates that you have not included in your filing a complete list of all the areas that the Independent Expert believed warranted more focused attention. |
BP HAS CLAIMED CONFIDENTIAL TREATMENT OF PORTIONS OF
THIS LETTER IN ACCORDANCE WITH 17 C.F.R. § 200.83
| Response: | We will include expanded disclosure of the Independent Expert’s report in our 2010 Form 20-F in response to the Staff’s comment. |
Form 6-K furnished July 28, 2010
Note 2. Significant event in the period – Gulf of Mexico oil spill, page 26
| 7. | We note that you recorded a pre-tax charge of $32.2 billion in the second quarter of 2010 in relation to the Gulf of Mexico oil spill. We further note your disclosure which states that this amount comprises costs incurred up to June 30, 2010, obligations for future costs which can be reliably estimated, and rights and obligations under the escrow account. |
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), please 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.
As part of your response, please tell us your consideration of providing disclosure of this nature in future filings based on the disclosure requirements of paragraphs 84 and 85 of IAS 37. In addition, please tell us how your accounting for the recognition and measurement of these provisions complies with paragraphs 14 through 52 of IAS 37. In connection with this, please explain in greater detail why a provision was not recorded for certain items because of the inability to estimate the amount and how your accounting complies with paragraphs 25 and 26 of IAS 37.
Accounting treatment for oil spill-related items
The charge of $32,192 million recognised in the second quarter comprises three elements, as follows:
(i) Costs incurred and accrued up to June 30, 2010 of $2,982 million.
Of this amount, cash payments made to June 30, 2010 amounted to $2,116 million, whilst the remaining $776 million represents accrued costs recorded within current trade and other payables on the balance sheet.
BP HAS CLAIMED CONFIDENTIAL TREATMENT OF PORTIONS OF
THIS LETTER IN ACCORDANCE WITH 17 C.F.R. § 200.83
| | (ii) | Amounts provided for future expenditure of $17,646 million, recognised and measured in accordance with IAS 37 ‘Provisions, Contingent Liabilities and Contingent Assets’. This represents obligations for future costs that can be reliably estimated and is recorded on the balance sheet within current provisions ($11,809 million) and non-current provisions ($5,837 million). |
| | (iii) | A net charge of $11,654 million arising from the rights and obligations under the $20-billion escrow account which is accounted for in compliance with IFRIC 5 ‘Rights to Interests arising from Decommissioning, Restoration and Environmental Rehabilitation Funds’. This accounting treatment is described in our Form 6-K dated July 28, 2010 containing our results for the interim period ended June 30, 2010 (the “ 2Q 6-K”), Note 1 – Basis of preparation, as follows: |
“Where the group makes contributions into a separately administered fund for restoration, environmental rehabilitation and other obligations, which it does not control, and the group's right to the assets in the fund is restricted, the obligation to contribute to the fund is recognized as a liability where it is probable that such additional contributions will be made. The group recognizes a reimbursement asset separately, being the lower of the amount of the associated claims obligation recognized and the group's share of the fair value of the net assets of the fund available to contributors. Changes in the carrying amount of the reimbursement asset, other than contributions to and payments from the fund, are recognized in profit or loss.”
Thus, BP’s obligation to contribute $20 billion to the escrow account has been provided for in full, with the liability recorded on the balance sheet within other payables, amounting to $19,580 million on a discounted basis ($7,500 million current and $12,080 million non-current).
In addition, and in accordance with IFRIC 5, a reimbursement asset of $7,926 million has been recognised ($6,233 million current and $1,693 million non-current), representing those elements of the estimated future expenditure provided for as described in (ii) above that will be paid out of the escrow account.
Approach to disclosures relating to the oil spill provision
As described in (ii) above, the provision of $17,646 million for estimated future expenditure has been accounted for in accordance with the recognition and measurement requirements of IAS 37. However, our interim financial statements, as represented by our quarterly Form 6-K submissions, are prepared in accordance with IAS 34 ‘Interim Financial Reporting’. This standard provides the relevant guidance regarding disclosures required in interim financial statements.
Specifically, paragraph 18 of IAS 34 provides the following guidance with respect to interim disclosures:
BP HAS CLAIMED CONFIDENTIAL TREATMENT OF PORTIONS OF
THIS LETTER IN ACCORDANCE WITH 17 C.F.R. § 200.83
“Other IFRSs specify disclosures that should be made in financial statements. In that context, financial statements means complete sets of financial statements of the type normally included in an annual financial report and sometimes included in other reports. Except as required by paragraph 16(i), the disclosures required by those other IFRSs are not required if an entity’s interim financial report includes only condensed financial statements and selected explanatory notes rather than a complete set of financial statements.”
We have provided explanatory notes that we consider to be relevant to an understanding of the interim financial statements but, as permitted by IAS 34, we have not included in our 2Q 6-K all of the disclosures required to be in annual financial reports for each class of provision pursuant to paragraphs 84 to 92 of IAS 37. Specifically, we provided details of the nature of the expenses that we had charged to the income statement, not the classes of provision that were shown in the balance sheet.
The detailed requirements for disclosures by class of provision, as set out in paragraphs 84 and 85 of IAS 37, will be given further consideration as we prepare our 2010 Form 20-F. However, it should be noted that we have not yet completed our evaluation of these requirements as they apply to the oil spill provision. We have deferred our determination of the classes of provision until the end of the year because we wish to understand the magnitude of the remaining provision by category at that time and assess whether there are any legal implications from providing the disclosure at that time. We note that a “class” of provision may encompass one or more of the items for which we have provided narrative disclosure.
We note that paragraph 92 of IAS 37 states the following with regard to disclosure of information about provisions:
“In extremely rare cases, disclosure of some or all of the information required by paragraphs 84-89 can be expected to prejudice seriously the position of the entity in a dispute with other parties on the subject matter of the provision, contingent liability or contingent asset. In such cases, an entity need not disclose the information, but shall disclose the general nature of the dispute, together with the fact that, and reason why, the information has not been disclosed.”
We have yet to conclude whether or not it will be appropriate to invoke this exemption.
For our third-quarter interim financial statements filed on Form 6-K and our 2010 Form 20-F we intend to provide similar, but updated, disclosures. This will include a description, or a table, to explain the utilization of amounts that were provided in relation to the Gulf of Mexico oil spill at June 30, 2010, adjustments or further amounts provided in subsequent periods, and the carrying amount of the provision at the end of the relevant period.
BP HAS CLAIMED CONFIDENTIAL TREATMENT OF PORTIONS OF
THIS LETTER IN ACCORDANCE WITH 17 C.F.R. § 200.83
Determination of amounts provided, discounting and major assumptions
Notwithstanding that we have not concluded whether the individual items comprising the oil spill provision represent separate classes of provision, we provided detailed narrative disclosure in our 2Q 6-K regarding determination of the amounts provided and major assumptions made about future events as shown below:
“Offshore and onshore oil spill response
The estimated future costs of the offshore oil spill response, containment and relief well drilling are based upon the activities expected to be undertaken and reflect the number of vessels involved in surface operations, including the U.S. Coast Guard response costs. The amount provided has been calculated using daily rates of costs incurred to date, for the period up until August when it is expected that the flow of hydrocarbons from the well will have been halted permanently. Thereafter a reduced daily rate has been used to estimate the ongoing spill remediation costs that are expected to continue until the end of the year. The substantial majority of these costs are expected to be incurred and paid in the period up to the end of 2010. In addition, the estimated future costs of the onshore response have been provided for based on the current acreage of shoreline affected, daily rates of costs incurred to date and information from previous spills not involving BP. Daily rates of costs reflect the large number of people engaged in the onshore response. These costs are expected to be incurred and paid over the next three years.
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, and for funding of the cost of the Louisiana barrier islands project, have been provided for where not expended before 30 June 2010.
As a responsible party under the Oil Pollution Act of 1990 (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.
BP HAS CLAIMED CONFIDENTIAL TREATMENT OF PORTIONS OF
THIS LETTER IN ACCORDANCE WITH 17 C.F.R. § 200.83
Claims under OPA 90
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. 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.
Fines and penalties
Provision has been made for the estimated penalties for strict liability under the Clean Water Act, which are based on a specified range 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 that the flow of hydrocarbons will have been permanently halted during August and 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.
The amount and timing of these costs depends upon the success of efforts to permanently halt the flow of hydrocarbons from the well in the expected timeframe and agreement with the appropriate authorities on the volume of oil spilled. It is not practicable to estimate the timing of expending these costs.”
In respect of fines and penalties, we also stated in the 2Q 6-K, under the heading “Principal risks and uncertainties – The Gulf of Mexico oil spill – Claims, litigation and enforcement risk”, that the “penalties for strict liability under the Clean Water Act can reach up to $1,100 per barrel of oil spilled, increasing up to $4,300 per barrel if gross negligence is found”.
Discounting of liabilities
In respect of discounting, we note that 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.
Within other payables, the $20-billion commitment to fund the escrow account has been discounted based upon the agreed schedule of payments.
BP HAS CLAIMED CONFIDENTIAL TREATMENT OF PORTIONS OF
THIS LETTER IN ACCORDANCE WITH 17 C.F.R. § 200.83
Recognition and measurement of the provision – compliance with IAS 37
The principal requirements of paragraphs 14 to 52 of IAS 37 can be summarised as follows, along with a summary explanation of our application of these requirements.
| | (a) | Recognition – criteria are set out in paragraph 14 as follows: |
| | · | Present obligation as a result of a past event (paragraphs 15-22) – we consider that BP has an obligation, legal for certain elements and constructive for certain elements, as a result of the explosion that occurred on 20 April 2010. |
| | · | Probability that an outflow of economic resources will be required to settle the obligation (paragraphs 23-24) – BP has committed to fund the $20-billion escrow account to be used to settle certain of the obligations arising, whilst other obligations will be settled by BP directly. Since there is no uncertainty in relation to BP’s commitment to fund the $20-billion escrow account, this liability is included within other payables rather than within provisions. |
| | · | Reliable estimate (paragraphs 25-26) – for certain obligations we did not consider that, as at 30 June 2010, we were able to provide a reliable estimate. Whilst acknowledging that the standard indicates that such cases should be extremely rare, given the unique nature and magnitude of this incident, we do consider that some of the obligations arising fall into this category. No amounts were recognized for such items in the interim financial statements contained in our 2Q 6-K, as noted below: |
| | o | Natural resource damages under OPA 90, other than the costs of the assessment phase – at the time of preparation of the interim financial statements there was still a high degree of uncertainty regarding the permanent halting of the flow of oil and gas from the well, and the assessment of the size and location of natural resource damage had not been assessed. It was therefore not possible to reliably estimate the associated costs. |
| | o | Claims not yet received – the provision recognized in the interim financial statements included amounts relating to claims received, albeit with a very high degree of uncertainty with regards to the timing and amount. However, no amounts were recognized for claims not yet received as it was not possible to estimate the expected level and magnitude of claims. This was primarily due to the fact that we had very little claims history on which to base a future claims estimate. As a claims history develops going forward we will monitor this and at some point we would expect to provide an additional amount for claims not yet received. |
BP HAS CLAIMED CONFIDENTIAL TREATMENT OF PORTIONS OF
THIS LETTER IN ACCORDANCE WITH 17 C.F.R. § 200.83
| | o | Litigation – more than 300 lawsuits had been received when the interim financial statements were prepared but, as we had not completed our legal analysis of these claims, it was not possible to make a reliable estimate of the potential settlements that may arise or the cost of implementing remedies sought. We have, however, recognized an amount for estimated legal costs that we are likely to incur in the process as this is more readily estimable. |
| | o | Fines and penalties – a provision was recognized in the interim financial statements for estimated penalties for strict liability under the Clean Water Act, determined as described above. However, no amounts were recognized for any other fines and penalties that may arise because it was not possible to measure the obligation reliably. It is not possible to estimate fines until they are levied, but we will continue to monitor the situation. |
At this stage, it is not possible to say when a reliable estimate can be made for natural resource damages and litigation. We will monitor developments and recognize provisions accordingly when reliable estimates can be made. However, in accordance with the accounting treatment described above under IFRIC 5, income statement charges arising as a result of the recognition of such provisions will be matched by income statement credits as a reimbursement asset is also recognized. This applies as long as the provisions recognized in respect of items that will be settled from the escrow account do not exceed the liability recognized in respect of BP’s commitment to make contributions to the $20-billion escrow account. Items that will be settled from the escrow account are: individual and business claims resolved and settled by the Gulf Coast Claims Facility (GCCF); amounts owed by BP pursuant to final judgments and settlement agreements pertaining to damage claims that are resolved outside of the GCCF process; natural resource damage costs (including assessment costs); and state and local government response costs.
| | (b) | Contingent liabilities (paragraphs 27-30) – contingent liabilities have not been recognized in the interim financial statements but they have been disclosed. This treatment is also applied for items that meet the criteria for recognition other than the “reliable estimate” criterion, as required by paragraph 26 and described above. |
| | (c) | Contingent assets (paragraphs 31-35) – no contingent assets have been recognized, as required by IAS 37. |
| | · | Best estimate (paragraphs 36-41) – management’s best estimate has been used for each element of the oil spill provision that has been recognized. |
| | · | Risks and uncertainties (paragraphs 42-44) – many of the elements of the oil spill provision are subject to a very high degree of uncertainty, both in timing and amount. In each case this has been described in the interim financial statements. |
BP HAS CLAIMED CONFIDENTIAL TREATMENT OF PORTIONS OF
THIS LETTER IN ACCORDANCE WITH 17 C.F.R. § 200.83
| | · | Present value (paragraphs 45-47) – where appropriate, the estimated cash flows have been discounted to their present value, as described above. The discount rate used represents a current market assessment of the time value of money for an appropriate term. |
| | · | Future events (paragraphs 48-50) – in estimating the costs of the spill response and clean-up, we have not anticipated the development of any new technologies. |
| | · | Expected disposal of assets (paragraphs 51-52) – no gains relating to the potential disposal of assets have been taken in to account in the measurement of the provision. Where equipment has been purchased as part of the spill response, the cost has been expensed. No decisions have yet been made as to how such assets will be disposed of in future, but no proceeds or gains have been anticipated. |
Engineering Comments
Exploration and Production, page 18
Key Statistics, page 19
| 8. | We do not concur with your response 18 which states that the requirements of Item 1204 of Regulation S-K apply only to reporting entities and not to equity accounted entities. It is the staff’s position that the Item 1200 disclosure requirements do not distinguish between direct or indirect ownership. It is also the staff’s position that the presentation of production required by Item 1204 should be consistent with the presentation of reserves under Item 1202. We reissue our prior comment 18. |
| Response: | We will revise our presentation to provide the information about the average sales prices and the average unit production costs of equity-accounted entities in our 2010 Form 20-F. |
| 9. | We note that your prior response 21 presents proved undeveloped reserves attributed to long lived U.S. drilling programs and to international projects with gas contracted well into the future [Appendix 1]. |
| | · | It appears that the drilling programs are composed of individual wells, each comprising a separate project that should be initiated within 5 years of booking to claim PUD reserves. Please explain to us the reasons such reserves should be recognized as PUD. Address section 108.01 of our Compliance and Disclosure Interpretations with attention to the statement, “The scope and scale of a project are such that, if a project were terminated before completion, for whatever reason, a significant portion of the previously invested capital would be lost.” |
BP HAS CLAIMED CONFIDENTIAL TREATMENT OF PORTIONS OF
THIS LETTER IN ACCORDANCE WITH 17 C.F.R. § 200.83
| | · | Projects with contracted sales from wells to be drilled well into the future may have appreciable uncertainty. Please explain to us if you have executed a final investment decision for all the PUD reserves claimed for these projects. Tell us the “break even” point in time and in capital recovery for each of these international activities. |
US and Canada Drilling Projects
Each of the US and Canada projects (Anadarko, Woodford Shale, Wamsutter, San Juan North, Jonah and Noel) listed in Appendix 1 of our previous correspondence is being developed as a major infrastructure-led project within BP. All of these projects were subject to an individual final investment decision which included a definite cost estimate and time schedule. Each project has been approved, and has the full commitment of BP management. These US and Canada projects require investment in facilities and infrastructure and in some cases drilling to maintain lease rights. In addition, in many of our remote and environmentally sensitive programs we have commitments with the communities and local and federal governments which determine the pace and scale of our developments.
We believe that each of these projects fully meets the requirements of the Staff’s Compliance and Disclosure Interpretations 108.01 as described below.
San Juan North
In 2007 BP took a final investment decision to develop and fund a major development program including infill drilling and infrastructure enhancements. The San Juan North development is in an environmentally sensitive area. We have lease agreements with individual mineral leaseholders, the US federal government and the sovereign nation of the Southern Ute Indian Tribe. Lead time to fully meet the needs of all stakeholders and environmental requirements in San Juan North is significant. The pace of development is governed by the needs of the environment and local communities, and not by availability of BP capital.
The San Juan North development is commercial because of its scale and the efficiencies that this scale brings. Wells are drilled using a “factory” approach with the same equipment, crews and procedures. This ensures crew and contractor understanding of development requirements. Also, it brings significant benefits to safety and integrity of operations as crews, contractors and suppliers maintain skills and knowledge to best drill and complete the wells.
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.
BP HAS CLAIMED CONFIDENTIAL TREATMENT OF PORTIONS OF
THIS LETTER IN ACCORDANCE WITH 17 C.F.R. § 200.83
To date, BP has spent [CONFIDENTIAL INFORMATION HAS BEEN OMITTED AND FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION] on the San Juan North drilling expansion program. If the remaining project was prematurely terminated after five years, the loss to BP would be approximately [CONFIDENTIAL INFORMATION HAS BEEN OMITTED AND FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION]. This is a loss in capital due to premature termination and not simply a reduction in the return on capital employed. This, coupled with the significant loss in reputation that would result from breaking our commitment to the local community, we believe fully supports BP’s full commitment to completing the entire project as planned. Since the final investment decision, development has been consistent with the development plan and results have been in line or better than expected.
Wamsutter
In 2005 BP approved the final investment decision for a [CONFIDENTIAL INFORMATION HAS BEEN OMITTED AND FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION] project to drill 2,000 wells and a [CONFIDENTIAL INFORMATION HAS BEEN OMITTED AND FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION] technology program for further development. In 2008, after a spend of [CONFIDENTIAL INFORMATION HAS BEEN OMITTED AND FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION] on the project, a final investment decision was taken to fund a further [CONFIDENTIAL INFORMATION HAS BEEN OMITTED AND FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION] development program which required a significant mobilization of staff and industry capability within the region. This included the construction of camps and infrastructure for the production, gathering, processing and marketing of the gas and liquids. We have made significant commitments to the local community on staffing and to gatherers and purchasers for obtaining concessions for compression and transport. In 2009 we began the construction of a [CONFIDENTIAL INFORMATION HAS BEEN OMITTED AND FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION] condensate gathering system that is sized and dependent on the full development for efficient recovery of its capital.
The Wamsutter development is commercial because of its scale and the efficiencies that this scale brings. Wells are drilled using a “factory” approach which ensures crew and contractor understanding of development requirements. From 2007 to today, the drilling efficiency improvements resulting from this “factory” approach have resulted in an approximately 50% reduction in our rig days.
Since 2007, BP has invested [CONFIDENTIAL INFORMATION HAS BEEN OMITTED AND FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION] in the Wamsutter drilling project. If the remaining project was prematurely terminated after five years, the loss to BP would be [CONFIDENTIAL INFORMATION HAS BEEN OMITTED AND FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION]. This is a loss in capital due to premature termination and not simply a reduction in the return on capital employed. This, coupled with the significant loss in reputation
BP HAS CLAIMED CONFIDENTIAL TREATMENT OF PORTIONS OF
THIS LETTER IN ACCORDANCE WITH 17 C.F.R. § 200.83
that would result from breaking our commitment to the local community, we believe fully supports BP’s full commitment to completing the entire project as planned. Since the final investment decision, development has been consistent with the development plan and results have been in line or better than expected.
Woodford Shale
BP entered into the Woodford Shale play with the purchase from Chesapeake in 2008 of 90,000 net acres for a price of [CONFIDENTIAL INFORMATION HAS BEEN OMITTED AND FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION]. In 2009 BP took a final investment decision to develop seven years of Woodford shale development consisting of two years of acreage capture followed by five years of development drilling. Given the purchase price for the leases BP needs to continue to develop the Woodford Shale for many years in order to see a return on the full investment made, although each individual well is clearly commercial from a point forward basis. There would be a significant loss of capital resulting from premature termination of the project.
Noel
Final investment decision for Noel development project in Canada 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 [CONFIDENTIAL INFORMATION HAS BEEN OMITTED AND FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION]. This included low-risk drilling, completion and tie in activities from 2009 until 2017.
A [CONFIDENTIAL INFORMATION HAS BEEN OMITTED AND FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION], twenty year, take-or-pay commitment was made with Spectra, a midstream gas processing company. This specified that BP produce 560 bcf of gas volumes over this time period. This directly corresponds to the expected production from all 136 project wells and proved reserves over this time frame. The expected production from proved undeveloped reserves booked from five to seven years is required to fully achieve these contract rates. This commitment resulted in Spectra constructing a 56 mile, 20-inch gas pipeline from their McMahon plant, to connect with the Noel project. This pipeline was required to provide transport of all project gas volumes, and also allowed access to preferred gas markets. Failure to comply with this contract would result in an operating expense to BP of [CONFIDENTIAL INFORMATION HAS BEEN OMITTED AND FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION] in processing fees.
Anadarko and Jonah
The Anadarko and Jonah projects are multi-year infill drilling projects that have been running for many years. BP has a multi-year track record of drilling similar sized programs in each of the fields and we remain fully committed to the final investment decision that was made for these projects. Jonah’s planned seven year
BP HAS CLAIMED CONFIDENTIAL TREATMENT OF PORTIONS OF
THIS LETTER IN ACCORDANCE WITH 17 C.F.R. § 200.83
drilling program extends to 2016 and Anadarko’s planned nine year program extends to 2018. In each case, the majority of the wells to be drilled will be completed within five years. Premature termination of each does not result in a loss of capital, although it does result in a significant reduction in the rate of return for the projects. Each project has a distinct beginning and end, a definitive cost estimate, time schedule and final investment decision. Each has been approved for funding by management and will be fully operational upon completion. BP has a commitment and track record of significant ongoing development activities in the area and an historical track record of completing comparable long-term projects. Jonah is a good example of this track record. From 2006 through 2010, BP and outside operating partners have drilled a total of 366 wells. BP plans to drill 87 more wells through 2015. BP is following a previously adopted development plan and the pace is driven by sound engineering practices and not on internal factors.
Trinidad Gas
The Trinidad gas projects (Angelin, Manakin, SEQB and Serrette) listed in Appendix 1 of our previous correspondence have all had a final investment decision. Each is a critical component of the fulfillment of our gas commitments in Trinidad. 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. As all of the projects share infrastructure and hub facilities, it is difficult to estimate a breakeven point for an individual satellite. There are, however, significant penalties for not meeting the supply contracts which is sufficient to justify BP’s ongoing commitment.
BP incurs liabilities to the LNG processing entities if it fails to make the annual contract quantity of gas available. 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].
The following figure shows the track record and development plan for bringing fields on line to meet the gas sales contract shown in red. We have no proved reserves beyond those required to fulfill our contractual commitments. Our ongoing exploration and appraisal programs will continue to progress our contingent resources to proved reserves to meet the demands of the contract in later life. Note that actual construction of facilities and pre-drilling of wells begins approximately 18 to 24 months prior to the individual field start-up.
[CONFIDENTIAL INFORMATION HAS BEEN OMITTED AND FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION]
BP HAS CLAIMED CONFIDENTIAL TREATMENT OF PORTIONS OF
THIS LETTER IN ACCORDANCE WITH 17 C.F.R. § 200.83
| 10. | Your prior response 22 presents the line item changes to your PUD reserves over 2009. Item 1203 (b) of Regulation S-K requires disclosure of material changes to PUD reserves over the year, including those converted to proved developed reserves. This requires the disclosure of the other prescribed (by FASB ASC 932) line items for reserve changes as you have furnished. Please amend your document to disclose the information in the first and last columns of the top table of confidential item marked “BP-94”. |
| Response: | We will provide the line item changes for PUD reserves as shown in the first and last columns of the table included in our prior response in our 2010 Form 20-F. |
Supplementary information on oil and natural gas (unaudited), page 183
Standardized measure of discounted future net cash flows and changes therein relating to proved oil and gas reserves, page 194
| 11. | Our prior comment 26 pointed out that the figures for “Previously estimated development costs incurred during the year” line item - $13,800 million - exceeded the actual development capital expended - $12,392 million. This appears to be inconsistent as both disclosures refer to development costs incurred in 2009. Please explain this difference to us and amend your document if it is appropriate. |
| Response: | The “Previously estimated development costs incurred during the year” line item is presented in order to reconcile Standardized measure of discounted future cash flows at the end of 2008 to end 2009 position. The amount we currently disclose represents development expenditure we estimated at the end of 2008 to be spent in 2009. The difference between the development costs that we estimated and the development costs that we actually incurred is shown in the line item “Net changes in prices and production costs”. In our future filings we will rename the line item in the reconciliation to ‘Development costs for the current year as estimated in previous year’ to ensure that there is no ambiguity. |
Productive oil and gas wells and acreage, page 196
| 12. | Your prior response 27 states that, generally, a significant number of lease and concession arrangements are not near expiry and that you have disclosed such significant events in the past. The example you cite, Santiago de las Atalayas in Colombia, appears to have been disclosed three months prior to expiry via your Form 20-F filing. Please explain to us the reasons you believe notice within three months of such material expiry is sufficient for the investing public. |
| Response: | The expiry of the Santiago de las Atalayas licence was disclosed as part of the description of 2009 events in Colombia. Whilst it is significant in the context of our operations in Colombia, it is not material in the context of BP group results. Production from this licence in the last full year prior to expiry amounted to 10 mboed which is only 0.3% of the total group production. |
BP HAS CLAIMED CONFIDENTIAL TREATMENT OF PORTIONS OF
THIS LETTER IN ACCORDANCE WITH 17 C.F.R. § 200.83
In the event that we view the expiry of any existing lease or concession as material to our security holders, we will disclose such expiry on a timely basis, as evident in our 2009 20-F, for example as follows: “The BP group holds interests, through associates, in onshore and offshore concessions in Abu Dhabi, expiring in 2014 and 2018 respectively.”
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) |
