sc0046.htm

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

I refer to your letter dated 8 May 2014 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 2013 (the “2013 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.

Disclosure in your filing states that part of the gain arising from the sale of your interest in TNK-BP to Rosneft was deferred because Rosneft is now accounted for as an associate and that the deferred gain will be released to your income statement over time as the TNK-BP assets are depreciated or amortized. Please tell us about your conclusion that a portion of the gain associated with the disposal of your interest in TNK-BP should be deferred and recognized through your income statement in future periods in the context of the relevant authoritative guidance.

28.

Gains and losses resulting from ‘upstream’ and ‘downstream’ transactions between an entity (including its consolidated subsidiaries) and its associate or joint venture are recognised in the entity’s financial statements only to the extent of unrelated investors’ interests in the associate or joint venture. ‘Upstream’ transactions are, for example, sales of assets from an associate or a joint venture to the investor. ‘Downstream’ transactions are, for example, sales or contributions of assets from the investor to its associate or its joint venture. The investor’s share in the associate’s or joint venture’s gains or losses resulting from these transactions is eliminated.

30.

The contribution of a non-monetary asset to an associate or a joint venture in exchange for an equity interest in the associate or joint venture shall be accounted for in accordance with paragraph 28, except when the contribution lacks commercial substance, as that term is described in IAS 16 Property, Plant and Equipment. If such a contribution lacks commercial substance, the gain or loss is regarded as unrealised and is not recognised unless paragraph 31 also applies. Such unrealised gains and losses shall be eliminated against the investment accounted for using the equity method and shall not be presented as deferred gains or losses in the entity’s consolidated statement of financial position or in the entity’s statement of financial position in which investments are accounted for using the equity method.

We also referred to paragraph BC33 of the Basis for Conclusions which accompanies IAS 28, which explains that as part of the revisions to the standard in 2011 the consensus in the interpretation SIC-13 ‘Jointly Controlled Entities – Non-Monetary Contributions by Venturers’ was incorporated into IAS 28 and extended to also apply to associates. Paragraph 2 of SIC-13 included a sentence “Contributions may be made simultaneously by the venturers either upon establishing the JCE or subsequently”. This additional guidance makes it clear that the IASB intended that paragraphs 28 and 30 of IAS 28 would apply when the investee became an associate only as a result of the contributions of the venturers, as was the case for the TNK-BP/Rosneft transaction.

Paragraph 31 of IAS 28, which is referred to in paragraph 30 of IAS 28 above, provides further guidance on gain recognition in the case of a transaction that lacks commercial substance, which is not relevant in our case.

The sale of BP’s interest in TNK-BP to Rosneft represents a “downstream” transaction as described in IAS 28, specifically it is a contribution of a non-monetary asset to an associate in exchange for an equity interest in that associate. As such, following the requirements of paragraph 28, only that portion of the gain on disposal that represents the unrelated investors’ interests in Rosneft, i.e. 80.25%, was recognised in the BP group income statement at the time of the transaction in 2013. The remaining 19.75% of the gain on disposal, representing BP’s interest in Rosneft, is eliminated against the investment in Rosneft presented on the BP group balance sheet.

The rationale for this accounting treatment, as noted in paragraph 30 of the standard, is that the portion of the gain relating to BP’s interest in Rosneft is unrealised at the time of the transaction. This is because BP has effectively retained an interest in TNK-BP’s assets that were contributed to Rosneft, through its equity investment in Rosneft.

The deferred portion of the gain on disposal of TNK-BP to Rosneft is realised subsequently. We are releasing the deferred gain to the income statement over the life of the assets based upon the depreciation or amortisation charge that arises in each period. The depreciation or amortisation charge in any period represents the consumption of economic benefits embodied in those assets and is therefore an appropriate mechanism to determine when the gain is realised.

You state the net result of the overall transaction to dispose of TNK-BP “was that BP would receive $12.3 billion in cash.” Please tell us why the table on page 148 of your annual report showing the gain on disposal of your investment in TNK-BP does not appear to reflect the portion of the transaction wherein “BP would use $4.8 billion of the cash consideration to acquire a further 5.66% stake in Rosneft.”

As described in the text in Note 6 of our annual report, BP entered into three contracts to carry out both the sale of BP’s interest in TNK-BP to Rosneft and for BP to acquire a further interest in Rosneft.

BP sold its 50% shareholding in TNK-BP to Rosneft for cash consideration of $25.4 billion (which included a dividend of $0.7 billion received from TNK-BP in December 2012) and Rosneft shares representing a 3.04% stake in Rosneft; and

In the event, the cash elements of these two contracts were in fact settled on a net basis, i.e., BP actually received the net of the $25.4 billion consideration for the sale and the $8.3 billion for the acquisition of Rosneft shares (as adjusted for the TNK-BP dividend noted above, and interest).

The first table in Note 6 therefore sets out the impacts of these two contracts only and shows the calculation of the gain on disposal of TNK-BP, as well as providing information on the cash disposal proceeds included in the BP group cash flow statement.

This was a separate transaction, not directly involved in the disposal of BP’s interest in TNK-BP, and therefore it does not appear in the first table in Note 6. Cash was received from the disposal which was then used to purchase a further interest in Rosneft.

We believe that it is useful for investors to provide a description in our annual report of the overall impact of all three of the contracts, whereby we disposed of our interest in TNK-BP and acquired an interest of 18.5% in Rosneft. To that end, the overall net cash impact of the three contracts was that BP received $12.3 billion, being the net of $25.4 billion consideration receivable under the first contract, less $8.3 billion payable to Rosneft under the second contract, less the $4.8 billion that was paid separately by BP to Rosneftegaz under the third contract described above.

We note that you had material volumes of proved undeveloped reserves (“PUDs”) held for more than five years in Trinidad and the Gulf of Mexico as of December 31, 2013. Please tell us about the quantity of PUDs held in the Gulf of Mexico that have been on your books for more than five years and address any other PUDs held in the Gulf of Mexico that are not scheduled to be converted to proved developed status within five years of initial booking. As part of your response, please describe the drilling program associated with these PUDs. In addition, please quantify the total estimated cost associated with the conversion of these reserves and the amount incurred through December 31, 2013. Refer to Item 1203(d) of Regulation S-K.

Response:

BP has a total of 1,196 mmboe of proved reserves in our Gulf of Mexico portfolio as of December 31, 2013 (YE2013). Of these, 764 mmboe (64%) are currently undeveloped; this volume makes up less than 5% of BP’s total proved reserves portfolio. We have a total of 259 mmboe of proved undeveloped (PUD) reserves which have been on our books for longer than five years; this volume makes up less than 2% of BP’s total proved reserves portfolio. This volume has reduced from 333 mmboe at December 31, 2012. These PUD reserves are all associated with long term infrastructure projects, which BP has a successful track record of completing within the Gulf of Mexico and internationally.

Development of PUD reserves in the Gulf of Mexico nearly always takes longer than five years from the date of their initial booking. Gulf of Mexico PUD reserves are associated with large scale projects where external factors including harsh deepwater offshore operating environments, result in development plans requiring more than five years to complete. Development durations are a consequence of:

BP has a track record of annually converting roughly 20% of our total PUD reserves on a rolling average basis. In the Gulf of Mexico, this rate of conversion has been approximately 15% of our PUD reserves which equates to an average conversion of approximately 6.7 years. Our 2013 conversion volume was 114 mmboe, or 14% of the opening PUD balance.

[****] 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.

in the case of volumes expected to take longer than five years to develop, our development timing and phasing is a consequence of external factors such as facility constraints (number of rigs on a platform or manifold installation), or adverse weather.

Table 1 below provides a breakdown by field for the four fields that have PUD reserves booked for more than five years at YE2013, time to convert to developed status, well scope and costs. Conversion of PUD reserves on the books for more than 5 years at YE2013 is estimated to take a further 2-9 years. Conversion timing is longest for Mad Dog due to loss of the drill rig in Hurricane Ike in 2008. Drilling resumed in 2013 after an approximately 5 year gap to allow for damage assessment, repairs, and rig replacement. As of YE2013, BP has invested a total of approximately [****] capex in these four fields, including approximately [****] costs incurred for facilities which support conversion of PUD reserves on the books for more than 5 years at YE2013. Approximately [****] future costs are estimated for conversion of PUDs on the books for more than five years at YE2013, primarily for drilling of 21 producers and 6 injectors.

	Total PUD @ YE2013	PUDs booked for > 5 years @ YE2013	Time to convert PUD booked > 5 years @ YE2013	PUD > 5 years @ YE2013 are all converted by:	Injectors	Producers	Total Capex to YE2013 (c)	Facilities Capex to YE2013 (c)	Estimated Capex to complete conversion of PUDS > 5 years@ YE2013 (c,d)
	(mmboe)	(mmboe)	(years)	(Year)	(count)	(count)	(US$bn)	(US$bn)	(US$bn)
Atlantis	[****]	[****]	2	2015	0	3	[****]	[****]	[****]
Great White	[****]	[****]	5	2018	3	4	[****]	[****]	[****]
Mad Dog (a,b)	[****]	[****]	9	2022	0	7	[****]	[****]	[****]
Thunder Horse	[****]	[****]	5	2018	3	7	[****]	[****]	[****]

Total: above 4 fields	[****]	[****]	-	-	6	21	[****]	[****]	[****]

Note (b): Mad Dog total costs at YE2013 are approx. [****]. Mad Dog facilities capex to YE2013 is approx. [****], of which [****] is for the existing Mad Dog A spar facility where PUD reserves have been booked for more than 5 years at YE2013, and [****] for the next phase of development.

Table 2 below provides a breakdown by field of total PUD reserves for the 5 fields with the greatest PUD volumes (as approximately 90% of PUD reserves in these fields at YE2013 are expected to take longer than 5 years from their initial booking to convert), and shows time to convert to developed status, well scope and costs. As of YE2013 BP has invested a total of approximately [****] capex in development of the 5 fields shown. Estimated future costs for PUD to proved developed (PD) reserves conversion are approximately [****] capex (BP share). The activities involved include an additional production facility on Mad Dog with subsea infrastructure, and continuous rig programmes on the 5 fields to drill 86 producers and 19 injectors. Conversion times are longest for those fields where facilities construction is planned (Mad Dog), facilities have recently started production (Mars Olympus) and where pace is limited by the number of platform drilling rigs (Thunder Horse).

	Total PUD @ YE2013	Future injectors	Future producers	Estimated years to convert 95% of all PUDS	2013 conversion rate	Years to convert at 2013 rate	Total Capex to YE2013 (d)	Estimated Future Facilities Capex (d)	Estimated Future Wells Capex (d)
	(mmboe)	(count)	(count)	(years)	(mmboe/yr)	(Years)	(US$bn)	(US$bn)	(US$bn)
Atlantis	[****]	1	9	5	[****]	[****]	[****]	[****]	[****]
Great White (c)	[****]	4	8	6	[****]	[****]	[****]	[****]	[****]
Mad Dog (a,b)	[****]	8	14	10	[****]	[****]	[****]	[****]	[****]
Mars	[****]	3	33	12	[****]	[****]	[****]	[****]	[****]
Thunder Horse	[****]	3	22	18	[****]	[****]	[****]	[****]	[****]

Total: above 5 fields	[****]	19	86	-	[****]	[****]	[****]	[****]	[****]

Based on our forward facilities and continuous rig programmes, BP expects to convert 60% of the 764 mmboe PUD reserves in GOM over the next 5 years, 87% over 10 years and 95% over 15 years. This pace of conversion does not recognise the potential for successful outcomes from drilling of non-proved locations (that are not on our books), which would support faster progression of volumes to developed status.

The Atlantis field had an initial booking of [****] mmboe PUD reserves at the point of its final investment decision in 2002 with a planned full conversion to developed status within 11 years. Field start-up in 2007 was delayed from the original planned date of 2005 due to fabrication and installation issues, and a hydrate problem with the export system. Subsequent development of the field after startup was planned with a continuous drilling program with two rigs. Drilling activities were suspended in 2010 for 15 months. Two rig drilling resumed in 2012. By YE2013, BP had progressed [****] mmboe to PD, more than the original booking.

Atlantis has a total of [****] mmboe of PUD reserves booked at YE2013. [****] mmboe have been on our books for longer than five years, and these are expected to be developed by the end of 2015. All remaining PUD reserves are expected to be converted by 2018.

The forward development plan consists of a continuous drilling programme to drill and complete 10 wells using the DD2/West Auriga and DD3 rigs. There are sufficient manifold and well slots available for all remaining sanctioned development wells.

As of YE2013, BP had spent approximately [****] CAPEX on development of Atlantis. There is approximately [****] costs (BP share) to complete development. Of this, approximately [****] is associated with the development of the PUD volumes that have been on our books for longer than five years.

Great White was initially booked at [****] mmboe PUD reserves with a final investment decision in 2006, with a subsequent increase to [****] mmboe PUD reserves in 2007, and an expectation of conversion within 11 years. Drilling activities were suspended for approximately 6 months in 2010. Production started in 2010, and by YE2013 eight producers and three injectors were on-line and [****] mmboe PUD reserves had been converted.

At YE2013 Great White had [****] mmboe of PUD reserves, [****] mmboe of which had been on our books for longer than five years. Conversion is being progressed through the forward drilling programme, with all PUD reserves expected to be developed by 2019. PUD reserves on the books for more than 5 years at YE2013 are expected to be developed by 2018. The Great White drilling schedule consists of a continuous two rig program through 2015 and one rig from 2016 to develop 8 producers and 4 injectors.

As of YE2013, BP had spent approximately [****] CAPEX on development of Great White. There is approximately [****] CAPEX (BP share) of remaining costs to complete development. Of this, [****] is associated with the development of PUD volumes that have been on our books for longer than five years.

The Mad Dog field consists of the A Spar development and a New Phase of development. The A Spar had a final investment decision in 2002 with a PUD reserves booking of [****] mmboe and a development time of 16 years. The A Spar drilling rig was lost during Hurricane Ike in 2008, causing a suspension of all drilling activities and a delay to the original planned development. Drilling resumed in 2013 after an approximately 5 year gap to allow for damage assessment, and completion of a large offshore repair workscope including removal of the damaged rig, structural repairs and the construction and offshore installation of a replacement rig. By YE2013, [****] mmboe of the original booking had been converted to PD.

The A Spar has [****] mmboe of PUD reserves all of which have been on our books for longer than five years. The A Spar drilling rig has a continuous program of development for the next 7 years during which [****] mmboe of this PUD volume is expected to be converted to PD. The remaining [****] mmboe will be developed as side-tracks or recompletions to existing producers when the existing completions reach an appropriate level of maturity.

BP made a final investment decision on a New Phase of development in 2011, increasing Mad Dog PUD reserves by [****] mmboe that year. The project schedule at the time of booking was based on 2018 first oil, with a continuous drilling schedule following start-up of the facility, with more than 99% of the PUD reserves converted by 2023. Development drilling activities are expected to begin this year with the GC825 SP14 well. This project includes construction and installation of a new large deepwater production facility and extensive subsea infrastructure. BP is currently optimising the design of the New Phase of development, with optimisation focused on choice of hull type for the facility, and optimisation of subsea layout and drillcentres. This is expected to result in a delayed start-up date and revised reserve conversion timing.

In addition to the proved locations, the continuous drilling programmes for the A Spar and the New Phase of development include drilling and completing a number of locations that do not currently meet the technical requirements for proved reserves (and are not included in our bookings).

As of YE2013, BP had spent approximately [****] CAPEX on development of Mad Dog. There is approximately [****] CAPEX (BP share) of remaining costs to complete development. Of this, [****] is associated with development of PUD volumes on our books for longer than 5 years.

The Mars field consists of two major projects, Mars A and Olympus (or Mars B). At YE2013, there are no PUD reserves that have been on the books for more than five years. Drilling activities were suspended in 2010 for a period of approximately one year. Existing PUDs are expected to take more than five years from initial booking to convert to developed status.

Mars A was originally booked in 1991 with PUD reserves of [****] mmboe, with start-up in 1996. A total of [****] mmboe of PUD has been converted to PD through year end 2013. Olympus was first booked in 2010 as part of an integrated Mars development plan, including construction of the Olympus TLP. In 2010, PUD reserves increased to [****] mmboe, [****] mmboe associated with Olympus and [****] mmboe associated with Mars A. At this time, the estimated development duration for Olympus was 13 years.

At YE2013 there were [****] mmboe of PUD reserves on Mars A associated with 6 future wells, which are expected to be developed by 2023. The Mars A TLP has 24 producer slots – all currently in use. Mars A has a continuous platform rig programme, including injectors to enable PUD to PD conversions at supported producers, wellwork, and future producers. The timing of conversion is governed by when well slots become available for side-track or recompletion.

At YE2013 there were [****] mmboe of PUD reserves on Olympus associated with 30 future wells, expected to be developed by 2026. Olympus has 24 TLP platform slots all with dedicated targets, and a six-well subsea tieback development. Oil production from the new Olympus TLP commenced in early 2014, from the first subsea well, and Olympus will begin platform drilling upon completion of its drilling rig in 2016. Drilling is planned to be continuous through 2026 with the pace of PUD to PD conversion a function of drilling duration and slot utilisation.

The Thunder Horse development covers 2 separate accumulations, Thunder Horse North (THN) and Thunder Horse South (THS). Each accumulation is developed through independent subsea infrastructure and fed to a taut wire moored semi-submersible system equipped with production facilities, a drilling rig, and quarters (PDQ) via multiple flowlines and risers.

Thunder Horse final investment decision and initial booking occurred in 2001. At end 2003, PUD reserves were [****] mmboe and the estimated development duration was 16 years from initial booking. The drilling schedule at this time did not include allowances for well interventions, slow-downs or shut downs associated with maintenance or project activity. The field started production in 2008 and by year end 2013 [****] mmboe had been converted from PUD to developed.

Field start-up in 2008 was delayed from the original planned date of 2005 due to fabrication and installation issues and a platform listing incident in 2005 following Hurricane Dennis requiring substantial topsides remediation. Subsequent development of the field was planned with a continuous drilling program using two rigs: the PDQ platform rig accessing 16 production slots and 4 injection slots to develop THS; and a MODU rig to access 7 remote drilling centres with a total of 11 production and 8 injection slots, predominantly developing THN. Water injection manifolds are scheduled to be commissioned in 2015.

Drilling activities were suspended in 2010 for a period of 25 to 30 months. In addition, well interventions and issues with execution of drilling and completion operations delayed the progression of PUD volumes. In response, a third rig was approved for Thunder Horse in 2012, and 5 rigs are expected to be in operation at Thunder Horse throughout 2014 to address well intervention inventory and to progress drilling. In 2017, Thunder Horse is expected to return to a continuous two rig development program.

At YE2013, Thunder Horse has [****] mmboe of PUD reserves, [****] mmboe of which have been on our books for longer than five years. The PUDs on our books for more than five years are expected to be developed by the end of 2018. The related programme consists of 7 producers and 3 injectors across THS and THN accumulations, using a combination of the West Capricorn, West Vela, West Auriga, Enterprise, and PDQ rigs.

The remaining [****] mmboe PUD volumes are expected to be developed between 2019-2033 and are a combination of new wells, side-tracks, and recompletions at THS which is serviced by the PDQ rig. Fourteen of the 15 activities are a part of the continuous PDQ rig programme on THS, which also includes time for well intervention work and drilling of reserves and resources other than proved (which are not included in our bookings).

As of YE2013, BP had spent approximately [****] CAPEX on development of Thunder Horse. There is approximately [****] CAPEX (BP share) of remaining costs to complete development. Of this, approximately [****] is associated with the development of PUD volumes that have been on our books for longer than five years.

We acknowledge that BP is responsible for the adequacy and accuracy of the disclosure in its 2013 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 2013 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.

	Very truly yours,


	/s/ B. Gilvary
	Dr B. GILVARY