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 Telex: 888811 BPLDN X G
12 October 2016

By EDGAR

Mr. H. Roger Schwall,Assistant Director,

Office of Natural Resources,Securities and Exchange Commission,100 F Street, N.E.,Washington, D.C. 20549-7010

Dear Mr. Schwall,

Re:	BP p.l.c.
	Form 20-F for the Fiscal Year Ended 31 December 2015
	Filed 4 March 2016
	File No. 001-06262

I refer to your letter dated 7 September 2016 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 2015 (the “2015 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.

- 1 -

BP HAS CLAIMED CONFIDENTIAL TREATMENT OF PORTIONS OF THIS LETTER IN ACCORDANCE WITH 17 C.F.R. § 200.83 - 2 -

Form 20-F for Fiscal Year Ended December 31, 2015

Notes on Financial Statements, page 107

Note 1. Significant accounting policies, judgements, estimates and assumptions, page 107

Significant estimate or judgement: recoverability of asset carrying values, page 111

1. For impairment testing purposes, we note that you determined the recoverable amount of your Upstream assets by estimating both their fair value less costs of disposal and value-in-use. For the assumptions made about future commodity prices, we note the first five years for both measurements were derived from market prices. Please describe for us the factors that justify the long-term price assumptions used for your measurements of both fair value less costs of disposal and value-in-use, including in relation to the market prices through 2020 disclosed in the table on page 111 of your filing.

Response: We noted in our letter to you dated 7 September 2015 that we have an in-house Economics team which advises management regarding the price assumptions that are used for investment appraisal. The long-term price assumptions used in impairment testing on the basis of fair value less costs of disposal are the central case price assumptions used in our internal investment appraisal. The central case represents management’s best estimate of the likely average price over the lifetime of projects which are typically 20 to 30 years. The price assumptions are based on an assessment of the long-run fundamental drivers of the market and reflect factors influencing both demand and supply. Demand factors include growth in the world economy, gains in energy efficiency, shifts in the mix of fuels being consumed and the outlook for carbon emissions. Supply factors include advances in technology, geopolitical developments and the growth of new sources of supply such as shale and renewables.

The Economics team publishes BP Energy Outlook each year, which analyses the key trends affecting energy markets over the next 20 years. From this, they produce forecasts for demand, supply and prices for each of the fuels, including oil and gas. At the time of preparing the 2015 Form 20-F the analysis of the factors impacting upon oil and gas prices was as follows.

The weaker oil price environment was a result of oversupply in the market following increases in US shale and OPEC production volumes, in particular. Nevertheless, our expectation was that the excess of supply over demand would be eliminated, albeit over a period of several years, and oil prices would gradually increase, as the market had already responded with US production starting to fall again and demand was expected to increase in the next year by more than the long-term average. Further out, demand was expected to continue growing driven in particular by China and India, as outlined in BP’s 2015 Energy Outlook – the long-term price assumption was consistent with this sustained increase in global oil demand.

Similarly, the low level of US gas prices reflected strong growth in US shale gas production. In the near term, we expected that gas prices would have to be sufficiently low to allow gas to gain market share from coal in the US power sector. However, with the weakness in both oil and gas prices, we expected that US gas production would be likely to flatten out in 2016 allowing for some firming in prices. Further out, US gas prices are likely to benefit from increased

BP HAS CLAIMED CONFIDENTIAL TREATMENT OF PORTIONS OF THIS LETTER IN ACCORDANCE WITH 17 C.F.R. § 200.83	- 3 -
[*****] 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.

US exports of liquefied natural gas (LNG) over the next five years and strong growth in global demand for gas over the next 20 years. In BP’s 2015 Energy Outlook, natural gas was projected to be the fastest growing fossil fuel, supported by increasing environmental regulation encouraging a switch from coal to gas, especially in the power sector. The long-term price assumption reflected the impact of both of these factors.

For the purposes of impairment testing market prices were used for the first five years. Market prices through 2020 are impacted by near-term factors and reflect the current oversupply in both the oil and gas markets. Although this oversupply is likely to persist for several years, there are signs that energy markets are responding to lower prices and are gradually rebalancing. In the longer term, as energy markets adjust and rebalance, the cyclical factors causing the current near-term weakness are likely to have less impact on prices. There is, therefore, a disconnect between near-term market prices and our expectations for oil and gas prices in the longer term which causes a significant step-up in price assumptions between the two periods.

For impairment tests performed on the basis of value in use, the long-term price assumption is a flat nominal price, whereas impairment tests on the basis of fair value less costs of disposal use a real price, increasing with inflation. This price was determined taking account of the factors set out above as well as the guidance in IFRS as described further in our response to Comment 3 below.

[*****]

2. You state that long-term assumptions used to determine fair value less costs of disposal for your Upstream assets are consistent with the assumptions used by the group for investment appraisal purposes. Please tell us how you determined that internal long-term investment appraisal prices are reflective of the assumptions market participants would use when valuing your Upstream assets. Refer to paragraph 53A of IAS 36.

Response: Forecasts of future oil and gas prices are highly uncertain and different market participants hold differing views on the trajectory for future prices. There is therefore a broad range of forecasts which can be considered to determine the prices that will be used to estimate future cash flows. The internal long-term investment appraisal price assumptions are set by BP management with advice from our Economics team, based upon a view of future market developments, as well as a range of external views. Price forecasts are based on forward-looking supply and demand analysis and predictions of future industry marginal costs. The results of this analysis are sense checked against market views such as those from brokers and energy market consultants. BP’s long-term price assumptions for oil are towards the lower end of a range of external forecasts, including major international organizations (e.g. IEA) and major energy consultancies (e.g. IHS/CERA and Wood MacKenzie), and for gas broadly in the middle of the range. As a buyer and seller of upstream assets management believes that using price assumptions aligned with our own investment appraisal approach is most appropriate when determining what a general market participant would use in valuing Upstream assets.

BP HAS CLAIMED CONFIDENTIAL TREATMENT OF PORTIONS OF THIS LETTER IN ACCORDANCE WITH 17 C.F.R. § 200.83 - 4 -

Paragraph 53A of IAS 36 notes that ‘Fair value reflects the assumptions market participants would use when pricing the asset.’  Market participants are defined in Appendix A of IFRS 13, as buyers and sellers in the principal (or most advantageous) market for the asset or liability that are independent, knowledgeable, able to enter into a transaction and willing to enter into a transaction. Paragraph 53A also notes that in contrast, value in use reflects the effects of factors that may be specific to the entity and not applicable to entities in general. It goes on to note some factors that would not generally be available to market participants.

In relation to future price assumptions, the factors that BP uses to make its determination are not specific to BP and are available to any market participant as defined in IFRS 13. In fact, BP regularly makes public its own analysis of energy markets, including the BP Energy Outlook and Statistical Review of World Energy documents which are published annually. The factors noted in IAS 36 paragraph 53A relate to asset-specific items including synergies, legal circumstances and tax characteristics which are not relevant to the determination of future prices.

3. Please tell us how you considered the guidance in paragraph 33(c) of IAS 36 regarding use of an increasing growth rate for estimating cash flows for value-in-use measurement.

Response: Paragraph 33(c) of IAS 36 states:

“In measuring value in use an entity shall:

…(c) estimate cash flow projections beyond the period covered by the most recent budgets/forecasts by extrapolating the projections based on the budgets/forecasts using a steady or declining growth rate for subsequent years, unless an increasing rate can be justified. This growth rate shall not exceed the long-term average growth rate for the products, industries, or country or countries in which the entity operates, or for the market in which the asset is used, unless a higher rate can be justified.

Paragraph 36 goes on to state:

“Cash flow projections until the end of an asset’s useful life are estimated by extrapolating the cash flow projections based on the financial budgets/forecasts using a growth rate for subsequent years. This rate is steady or declining, unless an increase in the rate matches objective information about patterns over a product or industry lifecycle. If appropriate, the growth rate is zero or negative.”

Upstream oil and gas assets have a finite life and the cash flow projections which are prepared for value-in use calculations are projections for the economic life of the asset. Forecasts are based upon annual estimates of production from finite reserves. They are not prepared by extrapolating from recent near-term budgets/forecasts, which is the situation referred to in IAS 36

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as noted above. Therefore the above guidance does not apply directly to this situation.

We have described in response to Comments 1 and 2 above how we determined price assumptions for the near term and long term. We have also noted that the long-term price assumption we use for investment appraisal is a real price, which is increased using an inflation assumption for each forecast year in the future. The use of real oil and gas prices, with an inflation assumption, such that there is no assumed long-run trend in the prices of oil or gas relative to that of other goods and services is a commonly used approach in long-run economic forecasting.

In light of the guidance in paragraph 33(c) for the purpose of value-in-use measurement of Upstream assets we used a flat long-term nominal price assumption, i.e. a zero growth rate.

4. You state that the long-term assumptions were derived from the “$80 per barrel real oil price and $5/mmBtu real Henry Hub assumptions used for investment appraisal.” We note from your letter to us dated September 7, 2015, with regard to your Form 20-F for the fiscal year ended December 31, 2014, that internally determined prices used for investment appraisal were last updated in 2012. Please confirm that price assumptions for 2021 and beyond have been “converted” from your pre-established “real prices” in the manner described in your September 7, 2015 letter or otherwise advise. As part of your response, tell us about the process through which you considered whether a significant shift in long-term market fundamentals occurred in light of the weaker oil price environment described in your filing.

Response: As noted in our letter dated 7 September 2015, the $80 per barrel Brent oil and $5/mmBtu Henry Hub price assumptions represented real prices based in 2012.  Although kept under continuous review, these assumptions had not been changed since 2012 as we had maintained our view of long-term energy prices.

For the purposes of our 2015 year-end reporting, we reduced our long-term investment appraisal prices. The Brent oil price assumption, as used for our 2014 year-end reporting, was $80 per barrel in 2012 prices (which equated to approximately $85 per barrel in 2015 prices). For 2015 year-end reporting the Brent oil assumption was reduced to $80 per barrel in 2015 prices. Similarly, the Henry Hub gas price assumption was reduced from $5/mmBtu in 2012 prices (which equated to approximately $5.3/mmBtu in 2015 prices) to $5/mmBtu in 2015 prices.

Our inflation assumptions were applied from 2016 onwards in arriving at prices used for each year of the cash flow analyses which determine the recoverable amounts on the basis of fair value less costs of disposal.

This re-basing of the long-term price assumptions from real prices in 2012 to real prices in 2015 therefore represented a decrease in the prices used in our impairment testing in 2015, as well as the price assumptions used in investment appraisal. In Note 1 on page 111 of the 2015 Form-20-F we noted that the Brent oil price assumption used for year 6 was $90 per barrel in 2021 compared with a year 6 price of $97 per barrel in 2020 in the 2014 Form 20-F (both subject to

BP HAS CLAIMED CONFIDENTIAL TREATMENT OF PORTIONS OF THIS LETTER IN ACCORDANCE WITH 17 C.F.R. § 200.83	- 6 -
[*****] 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.

inflation thereafter). This decrease in the price assumption for year 6 and beyond is a result of the changes described above. Similarly, the Henry Hub gas price assumption used for 2015 year-end reporting was $5.60/mmBtu in 2021 compared to $6.00/mmBtu in 2020 as of one year earlier (both subject to inflation thereafter).

As described in more detail in our response to Comment 1, our Economics team monitors the near- and long-term price environment, including whether a shift in long-term market fundamentals has occurred. [*****]

5. Please tell us about the extent to which you have sales contracts in place that support the use of the price assumptions for 2021 and beyond. In addition, please tell us how the price assumptions related to the reserves that do not meet the criteria to be considered proved differ from those disclosed in your filing.

Response: The majority of sales contracts that we enter into are floating price contracts i.e. the sales price is linked to, for example, the Brent oil price or the Henry Hub gas price. We do not have any material fixed price contracts extending beyond five years.

Our price assumptions related to reserves that do not meet the criteria to be considered proved do not differ from the price assumptions disclosed in Note 1 of the financial statements on page 111 of our 2015 Form 20-F.

As part of the analysis carried out in performing impairment tests we estimate production profiles on the basis that production will continue until the point at which it becomes uneconomic, based on the relevant price assumptions. This analysis determines the volume of any reserves that may be produced in excess of those that meet the criteria to be considered proved.

The same price assumptions are used to determine the volume of reserves that will be produced and to calculate the estimated cash flows associated with these reserves, and the relevant price assumptions are disclosed in our filing.

6. Please provide us with a table showing scheduled future production by year for the total proved reserves recorded as of December 31, 2015 on a barrel of oil equivalent basis.

Response: The production in the table below, taken from the 2015 Form 20-F Standardized measure of discounted future net cash flows and changes therein relating to proved oil and gas reserves (SMOG) sums to 17,022mmboe which is greater than 99% of our proved reserves of 17,180mmboe as at 31 December 2015. The difference of 158mmboe is due to rounding in the summation of individual field profiles and volumes expected to be produced beyond 2065.

BP HAS CLAIMED CONFIDENTIAL TREATMENT OF PORTIONS OF THIS LETTER IN ACCORDANCE WITH 17 C.F.R. § 200.83	- 7 -
[*****] 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.

BP proved reserves – future production

Total hydrocarbons (mmboe/year)

2016	[*****]	2026	[*****]	2036	[*****]	2046	[*****]	2056	[*****]
2017	[*****]	2027	[*****]	2037	[*****]	2047	[*****]	2057	[*****]
2018	[*****]	2028	[*****]	2038	[*****]	2048	[*****]	2058	[*****]
2019	[*****]	2029	[*****]	2039	[*****]	2049	[*****]	2059	[*****]
2020	[*****]	2030	[*****]	2040	[*****]	2050	[*****]	2060	[*****]
2021	[*****]	2031	[*****]	2041	[*****]	2051	[*****]	2061	[*****]
2022	[*****]	2032	[*****]	2042	[*****]	2052	[*****]	2062	[*****]
2023	[*****]	2033	[*****]	2043	[*****]	2053	[*****]	2063	[*****]
2024	[*****]	2034	[*****]	2044	[*****]	2054	[*****]	2064	[*****]
2025	[*****]	2035	[*****]	2045	[*****]	2055	[*****]	2065	[*****]

7. In your letter to us dated September 7, 2015, with regard to your Form 20-F for the fiscal year ended December 31, 2014, you stated that you had not identified any project where material volumes of proved reserves would be removed because the project had halted or slowed. Please provide us with an update on your project sanctioning given changes that have occurred in the commodity price environment since the time of your prior response and describe the development activities and/or projects you planned to undertake that have been revised due to lower prices. Additionally, quantify the portion of your proved undeveloped reserves related to projects where development will not proceed or will be halted if prices do not improve from current levels. As part of your response, describe the planned development activities related to your proved undeveloped reserves for the five year period ending December 31, 2020 and explain how differences between the prices assumed over that period and the prices used for investment appraisal purposes have impacted or may impact those planned development activities.

Response: There has been no significant change to the pace of planned project development since our response dated 7 September 2015. [*****] As noted in our earlier response, we test all projects at a low case price and, at this time, no material projects have been cancelled, although there have been some deferrals of activity and refocus on different activities such as in the US Lower 48 where we have prioritized development of our liquids-rich fields in the short term. Proved reserves as estimated at year end 2015 all met BP’s criteria for project sanctioning and SEC tests for proved reserves. We have not halted or changed our commitment to proceed with any material project to which proved reserves have been attributed.

BP HAS CLAIMED CONFIDENTIAL TREATMENT OF PORTIONS OF THIS LETTER IN ACCORDANCE WITH 17 C.F.R. § 200.83	- 8 -
[*****] 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.

BP has addressed the current downturn in prices by enhancing the efficiency and productivity of our operations. We are significantly reducing our Upstream headcount, moving from a staff and contractor total of over 29,000 in 2013 to an expected number of fewer than [*****] in 2017. We have also reduced our third-party spend which represents a significant portion of our capital spend and around [*****]% of our cost spend, through re-bidding of contracts and working with suppliers to improve our working practices. We have also been focusing on a large number of continuous improvement projects with the objective of eliminating unnecessary waste and simplifying our processes. These efforts have resulted in a reduction in our production costs by [*****]% since 2013. In the North Sea our production costs will reduce from an average of $[*****]/boe in 2013 to an expected average of below $[*****]/boe by 2017. In our US Lower 48 Woodford shale operations, we have seen drill times for new wells reduce from [*****] to [*****] days from 2012 (6 wells drilled) to 2015 (10 wells drilled). As a result, well costs were reduced by [*****]% and per well recovery was also increased [*****]% due to better practices.

Our development activity to progress proved undeveloped (PUD) reserves consists of two main types of activity: (i) development drilling and installation of minor facilities in our existing fields; and (ii) new projects that have had a final investment decision and are progressing towards initial development. The two tables below summarise this activity for our subsidiaries and equity-accounted entities excluding Rosneft. All of the projects listed have had a final investment decision and we do not anticipate any material changes to this progression if prices remain at current levels.

Development activity in existing fields (PUD progressed in mmboe)
	2016	2017	2018	2019	2020	5 Year
Azerbaijan	[*****]	[*****]	[*****]	[*****]	[*****]	[*****]
Alaska	[*****]	[*****]	[*****]	[*****]	[*****]	[*****]
Angola	[*****]	[*****]	[*****]	[*****]	[*****]	[*****]
Asia Pacific	[*****]	[*****]	[*****]	[*****]	[*****]	[*****]
Canada	[*****]	[*****]	[*****]	[*****]	[*****]	[*****]
Gulf of Mexico	[*****]	[*****]	[*****]	[*****]	[*****]	[*****]
India	[*****]	[*****]	[*****]	[*****]	[*****]	[*****]
Latin America	[*****]	[*****]	[*****]	[*****]	[*****]	[*****]
US Lower 48	[*****]	[*****]	[*****]	[*****]	[*****]	[*****]
Middle East	[*****]	[*****]	[*****]	[*****]	[*****]	[*****]
North Africa	[*****]	[*****]	[*****]	[*****]	[*****]	[*****]
North Sea	[*****]	[*****]	[*****]	[*****]	[*****]	[*****]
Russia (excl Rosneft)	[*****]	[*****]	[*****]	[*****]	[*****]	[*****]
Trinidad	[*****]	[*****]	[*****]	[*****]	[*****]	[*****]
Total	[*****]	[*****]	[*****]	[*****]	[*****]	[*****]

BP HAS CLAIMED CONFIDENTIAL TREATMENT OF PORTIONS OF THIS LETTER IN ACCORDANCE WITH 17 C.F.R. § 200.83	- 9 -
[*****] 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.

Major projects in new and existing fields (PUD progressed in mmboe)
	Activity	2016	2017	2018	2019	2020	5 Year
Azerbaijan	Shah Deniz Phase 2	[*****]	[*****]	[*****]	[*****]	[*****]	[*****]
Alaska	Point Thomson	[*****]	[*****]	[*****]	[*****]	[*****]	[*****]
Asia Pac	Tannguh Expansion, NWS Developments	[*****]	[*****]	[*****]	[*****]	[*****]	[*****]
Gulf of Mexico	Thunder Horse South Expansion	[*****]	[*****]	[*****]	[*****]	[*****]	[*****]
Middle East	Khazzan (Oman) Phase 1	[*****]	[*****]	[*****]	[*****]	[*****]	[*****]
North Africa	West Nile Delta (Egypt), In Salah & In Amenas expansion (Algeria)	[*****]	[*****]	[*****]	[*****]	[*****]	[*****]
North Sea	Clair Ridge, Q204, Culzean	[*****]	[*****]	[*****]	[*****]	[*****]	[*****]
Trinidad	Juniper, Onshore Compression	[*****]	[*****]	[*****]	[*****]	[*****]	[*****]
Total		[*****]	[*****]	[*****]	[*****]	[*****]	[*****]

This plan totals [*****] bnboe of PUD to proved developed (PD) progression over the five years, [*****]% of the total PUD of 4.6 bnboe for our assets excluding Rosneft that were disclosed in our 2015 Form 20-F. The remaining volumes are associated with projects where there are significant external controls on the pace of delivery, such as LNG capacity limits, environmental concerns or the scale of infrastructure required. In addition to these volumes, we have plans to progress by 2020 an additional [*****]mmboe of resources that do not yet meet SEC proved reserves definitions.

For Rosneft, the PUD reserves at the end of 2015 were 3.1bnboe. All of the Rosneft volumes have been reviewed and included in our proved reserves only after review and agreement by DeGolyer & MacNaughton as documented in their third-party report published with our 2015 Form 20-F.

Rosneft is committed to starting commercial production in new large fields in East and West Siberia between 2016 and 2020, including Suzunskoye, Tagulskoye, Lodochnoye, Urubcheno-Tokhomskoye, Russkoye, Kharampur (gas deposits) and Kynsko-Chaselskoye license area.

Detail on specific projects, progress to date and forward plans can be found in the Rosneft 2015 Annual Report, section 2.6.

Note 4. Disposals and impairments, page 122

8. We note that you recognized both impairment losses and impairment reversals during the fiscal year ended December 31, 2015 related to cash generating units in the North Sea. Please provide us with a detailed discussion of the factors underlying the impairment charge recognized during 2015 and explain how those factors were considered as part of the process through which you determined the previously recognized impairment loss should be reversed. With your response, address your basis

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for changes in the assumptions underlying the estimates used to determine the recoverable amount of the previously impaired cash generating units (e.g., the discount rate applied). Refer to paragraph 114 of IAS 36.

Response: Paragraph 114 of IAS 36 requires that an impairment loss recognized in a prior period shall be reversed only if there has been a change in the estimates used to determine the asset’s recoverable amount since the impairment loss was recognized.

In 2015 we recognized impairment charges and impairment reversals relating to cash-generating units in the North Sea. There were various indicators of impairment or impairment reversal that gave rise to the requirement to perform impairment tests for these cash-generating units. In some cases there were several indicators for an individual cash-generating unit (CGU).

Certain of the indicators identified in 2015 were adverse in nature such as lower price assumptions, whilst other indicators were favourable, such as reduced estimates of future costs.

The valuations of recoverable amount are sensitive to the assumptions used in the calculations and different CGUs are more or less sensitive to the various different assumptions. In addition to the factors that affect valuation of recoverable amounts for all CGUs to a greater or lesser extent, some CGUs were also affected by CGU-specific factors such as changes in reserves estimates.

The principal changes in assumptions underlying the estimates used to determine recoverable amounts were:

(i) lower short-term price assumptions: as described above in our response to Comment 1, our price assumptions for the first five years in any impairment test are market forward prices, which at the end of 2015 were more than $20 per barrel lower for Brent oil than at the end of 2014, as disclosed on page 111 of the 2015 Form 20-F. Any assets with lives of less than five years will only be impacted by changes in the near-term price assumptions, and those with longer expected lives will be impacted to varying degrees by changes in the long-term prices;

(ii) reduced estimates of future costs: due to the low oil price environment and the resulting sector-specific deflation, estimates of future costs, including both operating costs and decommissioning costs, have generally reduced. Examples of such cost reductions are noted above in our response to Comment 7. The extent to which such cost reductions have been, or are expected to be, achieved varies amongst the different CGUs. By the end of 2015, with more experience of the lower oil price environment, we were able to modify estimates of cost reductions which we had not been able to take account of when the original impairment charges were taken;

(iii) reduction in discount rate: the discount rates used in impairment tests are based upon the cost of funding the group derived from an established model. The inputs to this model are subject to periodic review and in 2015, as a result of this review which included consideration of market conditions, the discount rates used in impairment tests were reduced by 1% for recoverable amounts based on both value in use and fair value less costs of disposal (where such tests were based on discounted cash flow

BP HAS CLAIMED CONFIDENTIAL TREATMENT OF PORTIONS OF THIS LETTER IN ACCORDANCE WITH 17 C.F.R. § 200.83 - 11 -

analyses). In particular, risk-free returns and the required equity risk premium were both considered to have reduced. The positive impact to an asset’s recoverable amount of a reduction in the discount rate is relatively more significant on assets with longer lives.

 The impairment charges recognized in relation to North Sea assets in 2015 were primarily driven by the reduction in short-term price assumptions during the period, reflecting market conditions. Certain CGU valuations were also affected by reserves reductions and, in limited circumstances, decommissioning cost increases. For those CGUs for which impairment charges were recognized these adverse impacts were only partly offset by any favourable impact of reductions in estimates of future costs and the reduction in the discount rate assumption.

The CGUs for which we recognized impairment reversals in 2015 also suffered adverse impacts from lower short-term price assumptions as noted above. However, for these CGUs, this was more than offset by the favourable impact of reductions in estimates of future costs and the reduction in the discount rate assumption.

Note10. Earnings per ordinary share, page 131

9. We note the average number of shares outstanding for purposes of calculating basic earnings per share includes “certain shares that will be issuable in the future under employee share-based payment plans.” Please tell us why these future issuances were included in the weighted average number of ordinary shares outstanding. As necessary, describe the terms and conditions associated with the issuance of these shares. Refer to paragraphs 19 and 21 of IAS 33.

Response: Paragraph 19 of IAS 33 states that the number of ordinary shares to be used for the purpose of calculating basic earnings per share (EPS) shall be the weighted average number of ordinary shares outstanding during the period. In the case of ordinary shares issued for the rendering of services to the entity, paragraph 21(g) provides further guidance that shares are included in the weighted average number of shares as the services are rendered.

Paragraph 24 of IAS 33 states that contingently issuable shares are treated as outstanding and are included in the calculation of basic EPS only from the date when all necessary conditions are satisfied i.e. the events have occurred. Shares that are issued solely after the passage of time are not contingently issuable shares, because the passage of time is a certainty.

The number of such issuable shares included in the basic weighted average number of shares is less than 0.4% of the total and there are no employee share plans currently in operation that award new shares in this way. The impact of the inclusion of these issuable shares on the EPS for full-year 2015 was 0.11 cents per share on the published EPS of (35.39) cents per share. It does not, therefore, have a material effect on the EPS calculation.

The Long Term Performance Plan (LTPP) was an employee share plan for senior employees which was used prior to 2005. No new grants have been made under this share plan since that time. At the time of grant there were

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performance conditions that must be satisfied by the employee in order for the shares to be awarded. However, in respect of the shares included in the basic EPS calculation, the performance conditions have been satisfied and the relevant services rendered by the employees. The only remaining condition that must be satisfied is the passage of time. As noted above, the standard is clear that where this is the case the shares are not treated as contingently issuable because the passage of time is a certainty and they are therefore included in the calculation of basic EPS.

Supplementary information on oil and natural gas (unaudited), page 169

Standardized measure of discounted future net cash flows…, page 191

10. You indicate in footnote “b” that the future decommissioning costs are included in the “Future development cost” line item of the standardized measure calculation. Please tell us the figures for such decommissioning costs that are included in the “Total” columns for subsidiaries and for equity entities in the years 2013, 2014 and 2015.

Response: The future decommissioning costs included in the standardized measure calculation for subsidiaries and equity-accounted entities, as referred to in footnote “b”, are set out in the table below.

$ million	2013	2014	2015
Subsidiaries	22,232	24,014	23,642
Equity-accounted entities	2,065	1,578	1,139

Productive oil and gas wells and acreage, page 194

11. We note that you have 126 million net undeveloped acres as of year-end 2015 which includes leases and concessions. Please tell us the proved undeveloped reserves, if any, which you have attributed to acreage whose expiration date precedes the scheduled date for initial PUD reserves development. If applicable, address the approach you will employ to forestall the expiry of such acreage.

Response: None of our PUD reserves are attributed to acreage whose expiration date precedes the scheduled date for initial PUD development.

Selected financial information, page 216

12. Your presentation of “income statement data” shows certain non-GAAP measures before the most directly comparable IFRS measure which is inconsistent with the updated Compliance and Disclosure Interpretations issued on May 17, 2016. Please review your presentation here and

BP HAS CLAIMED CONFIDENTIAL TREATMENT OF PORTIONS OF THIS LETTER IN ACCORDANCE WITH 17 C.F.R. § 200.83 - 13 -

throughout your filing and to ensure that non-GAAP measures do not precede the comparable IFRS measure.

Response: We note that elsewhere within our Form 20-F filing we present the most directly comparable IFRS profit measures before the related non-GAAP profit measures, for example on pages 2 and 26.

Nevertheless, we undertake to ensure in future filings that the non-GAAP measure does not precede the comparable IFRS measure in the ‘income statement data’ table.

13. The non-GAAP measure Underlying Replacement Cost includes an adjustment for “fair value accounting effects.” Tell us more about the items underlying this adjustment and explain how your presentation of “unrecognized gains (losses) brought forward from previous period” and “unrecognized (gains) losses carried forward” is derived from and reflective of the description of “fair value accounting effects” provided on pages 256 and 257 of your filing.

Response: The way that BP manages the economic exposure and measures performance relating to certain activities differs from the way these activities are measured under IFRS. We calculate the difference by comparing the IFRS result with management’s internal measure of performance and the difference is disclosed as a fair value accounting effect. Fair value accounting effects generally arise because IFRS generates an accounting asymmetry which does not exist under BP’s internal performance measure.

We note the previous correspondence in 2007 between BP and the SEC Staff on the topic of fair value accounting effects, resulting in the narrative and tabular disclosures that we have since included in our filings.  Since that time only minor amendments have been made to these disclosures.

The items underlying the adjustment for fair value accounting effects are as follows:

(1) Under IFRS, non-trading inventories held are recognized on the balance sheet at historical cost less any provision to reduce the carrying amount to net realizable value. However, where such inventories held in our integrated supply and trading function are over and above normal operating requirements, and the related price exposure is risk-managed using derivative instruments, they are valued at market price for internal purposes, taking into account storage costs if appropriate. Thus a measurement difference arises which is disclosed as a fair value accounting effect.

(2) The group enters into certain forward commodity contracts for own use purposes, such as the purchase of crude oil for a refinery or the sale of BP’s gas production, but which are treated as derivatives and fair valued under IFRS because they are managed as part of a larger portfolio of similar transactions. The change in fair value of such contracts represents a fair value accounting effect where such contracts are accounted for on an accruals basis for internal purposes.

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(3) IFRS requires that the fair value of our held-for-trading inventory is determined using period-end spot prices. In contrast, BP’s internal measurement is based on market forward prices, resulting in a different valuation from IFRS. Similarly, BP enters into contracts which are recorded at fair value in accordance with IFRS based on the principal market for the asset, which is usually the market in which it is located. However, for internal purposes the contract may be valued based on a different location or delivery period giving rise to a different valuation. In both the cases described the valuation differences represent fair value accounting effects.

(4) BP enters into contracts for pipeline transportation and storage capacity which are accounted for on an accruals basis under IFRS. The economic exposure arising from these contracts is typically risk-managed using derivative financial instruments which are recognized at fair value under IFRS. Internally these contracts are measured at fair value based on the expected economic value to be derived from them. For a pipeline contract this reflects the price differential between two locations, and for a storage contract it represents the price differential between the beginning and end of the storage period.

(5) The group enters into certain contracts, such as processing or other contracts, which are accounted for on an accruals basis under IFRS. Such contracts may be risk-managed by hedging using derivative instruments that are recognized at fair value under IFRS. Where hedge accounting is not applied under IFRS measurement differences arise which are disclosed as fair value accounting effects.

(6) Where forward contracts are entered into for own use purposes and are not part of a larger portfolio of similar transactions, they are accounted for on an accruals basis for IFRS. For internal purposes, where these contracts are risk-managed using derivative financial instruments that are fair valued under IFRS, such contracts are fair valued based on the location and delivery period appropriate to normal trading conditions and this represents a fair value accounting effect.

As an example, where we enter into a contract for pipeline transportation which is accounted for under IFRS on an accruals basis as described in (4) above, it is an executory contract and there is no asset or liability reflected on the balance sheet. However, for internal management reporting its fair value is determined as described above, reflecting the price differential between two locations. This fair value is a notional balance sheet item that will change over time and the change in fair value is reflected as a “fair value accounting effect” and reflected in our underlying replacement cost profit measure. The fair value at a point in time reflects the accumulated changes in fair value since the contract was entered into.

The tables on page 218 of our 2015 Form 20-F show, by segment, the aggregate amount of such accumulated changes in fair value, at the beginning of the period (1 January 2015 in the case of the 2015 Form 20-F), which is described in our disclosures as “unrecognized gains (losses) brought forward from previous period”, and similarly at the end of the period (31 December 2015 in the case of the 2015 Form 20-F), which is described as “unrecognized (gains) losses carried forward”.

BP HAS CLAIMED CONFIDENTIAL TREATMENT OF PORTIONS OF THIS LETTER IN ACCORDANCE WITH 17 C.F.R. § 200.83 - 15 -

The difference between these amounts is the change in fair value during the year, which is described as “impact of fair value accounting effects”. The aggregate change in the year, on a post-tax basis, is reflected, along with non-operating items, as a reconciling item in the reconciliation of underlying RC profit before interest and tax on page 216.

14. We note that you disclose Replacement Cost and Underlying Replacement Cost on a per share basis. Tell us whether this information is presented in accordance with paragraph 73 of IAS 33 and how you considered the related disclosure requirements. Alternatively, if this is a non-GAAP measure, provide a reconciliation to the most directly comparable measure calculated in accordance with IFRS to comply with Item 10(e)(i)(B) of Regulation S-K and question 102.05 of the Compliance and Disclosure Interpretations regarding Non-GAAP Financial Measures.

Response: Paragraph 73 of IAS 33 deals with “amounts per share using a reported component of the statement of comprehensive income other than the one required by this Standard”. In addition, paragraph 73 also applies to “amounts per share using a reported item of profit or loss, other than the one required by this Standard”, as set out in paragraph 73A.

Replacement cost profit (loss) and Underlying replacement cost profit are not reported components of the statement of comprehensive income and are not reported items of profit or loss and therefore paragraph 73 does not apply to the associated per share amounts. These per share amounts are nevertheless calculated in accordance with the requirements of paragraph 73, i.e. the weighted average number of ordinary shares used in the calculations is determined in accordance with the Standard and is the same number as that used to calculate basic and diluted earnings per share on the basis of Profit (loss) for the year.

Replacement cost profit for the group and Underlying replacement cost profit are non-GAAP profit measures, and therefore the associated per share amounts are also non-GAAP measures. The most directly comparable IFRS financial measure is the basic amount per share on the basis of Profit (loss) for the year. As noted above, the denominator used to calculate the non-GAAP per share amounts is the same as that used in the IFRS measure. The measures used as the numerators of the non-GAAP per share amounts are reconciled to the most directly comparable IFRS measure in the table of selected financial information, in the rows immediately preceding the per share amounts and we considered that this satisfied the Item 10(e)(1)(i)(B) disclosure requirement.

However, we undertake to provide in our future filings a reconciliation of the per share amounts in the following format:

Per ordinary share (basic) - cents	2015
Profit (loss) for the year attributable to BP shareholders	(35.39)
Inventory holding gains (losses), net of taxation	7.20
RC profit (loss) for the year attributable to BP shareholders	(28.18)
Non-operating items and fair value accounting effects, net of taxation	60.40
Underlying RC profit for the year attributable to BP shareholders	32.22

BP HAS CLAIMED CONFIDENTIAL TREATMENT OF PORTIONS OF THIS LETTER IN ACCORDANCE WITH 17 C.F.R. § 200.83 - 16 -

15. It appears that the information you present here regarding capital expenditures (e.g., organic capital expenditure, on an accruals basis) is a non-GAAP measure. Tell us how you have considered the disclosure requirements of Item 10(e) of Regulation S-K.

Response: ‘Capital expenditure and acquisitions, on an accruals basis’, is determined as the aggregation of the additions recorded in the IFRS accounts for certain specified non-current assets as disclosed in our 2015 Form 20-F. As such, we consider ‘Capital expenditure and acquisitions, on an accruals basis’ as presented in our 2015 Form 20-F to be a GAAP measure. In the financial statements on page 125 of our 2015 Form 20-F we explain what is included in this measure.

Organic capital expenditure excludes expenditure on acquisitions and similar items. We included a definition for this item in the glossary on page 257 of the 2015 Form 20-F and in ‘Selected Financial Information’ on page 216 we provided a reconciliation between our reported GAAP measure ‘Capital expenditure and acquisitions, on an accruals basis’ and ‘Organic capital expenditure, on an accruals basis’.

During the second quarter of 2016 we amended the title of the measure to ‘Capital expenditure on an accruals basis’ and revised its definition as we believe this measure would otherwise result in certain transactions being reported in this category which would not be helpful to users of the accounts because there is no associated cash flow. For example, in 2016 BP expects to complete the dissolution of a joint arrangement following which the joint arrangement partners will each have sole ownership of certain of the assets currently owned by the joint arrangement. There will be no cash flows associated with the dissolution but under our former definition we would have reported a material amount of capital expenditure for this transaction. As a result of revising the definition we now treat ‘Capital expenditure on an accruals basis’ as a non-GAAP measure.

You will note that in BP’s Form 6-K for the period ended 30 June 2016 we disclosed that ‘Capital expenditure on an accruals basis’, ‘Organic capital expenditure’ and ‘Inorganic capital expenditure’ are non-GAAP measures. We provided definitions of these measures. We also included in the ‘Additional information’ section of our filing a reconciliation from ‘Capital expenditure on an accruals basis’ to the nearest equivalent GAAP measure, which is ‘Additions to non-current assets’. IFRS 8 paragraph 24(b) requires disclosure, on an annual basis, of ‘additions to non-current assets’ by segment, and IFRS 8 paragraph 28 requires a reconciliation between the sum of the amounts disclosed for each segment to the equivalent amounts for the group as a whole. We have also provided a table in the filing which reconciles ‘Capital expenditure on an accruals basis’ to ‘Organic capital expenditure’ with ‘Inorganic capital expenditure’ being the reconciling item.

It is our view that ‘Capital expenditure on an accruals basis’, ‘Inorganic capital expenditure’ and ‘Organic capital expenditure’ are measures that are important in our industry and useful to investors. Furthermore, whilst we believe that these terms are generally understood by users, we recognize that our second-quarter filing did not address the disclosure requirement in Item 10(e) of regulation S-K to explain why BP’s management believes that presentation of these non-GAAP financial measures provides useful information to investors regarding BP’s

BP HAS CLAIMED CONFIDENTIAL TREATMENT OF PORTIONS OF THIS LETTER IN ACCORDANCE WITH 17 C.F.R. § 200.83	- 17 -
[*****] 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.

financial condition and results of operations. We will address this in future filings.

Oil and gas disclosures for the group, page 227

16. You state that “[i]n 2015 we progressed 959mmboe of proved undeveloped reserves (626mmboe for our subsidiaries alone) to proved developed reserves through ongoing investment in our subsidiaries’ and equity-accounted entities’ upstream development activities.” As shown on your table below, the 2015 PUD conversion to proved developed reserves of 959 MMBOE is about 12% (=959/7788) of the PUD reserves available for development at the beginning of 2015. With similar procedures, we calculate the cumulative PUD reserves conversion over the period 2011-2015 is about 68%. This does not appear to be in agreement with your statement here, “Over the past five years, BP has annually progressed a weighted average 18% of our group proved undeveloped reserves (including the impact of disposals and price acceleration effects in PSAs) to proved developed reserves. This equates to a turnover time of about five and a half years.” Please explain these differences in conversions to us. Address the “impact of disposals and price acceleration effects in PSAs.”

Proved Undeveloped Reserves	MMBOE
PUD Reserves at 1 January 2015	7788
Revisions of Previous Estimates	300
Improved Recovery	111
Discoveries and Extensions	339
Purchases	126
Sales	(17)
Total in Year PUD Reserves Changes	8646
Progressed to Proved Developed Reserves	(959)
PUD Reserves at 31 December 2015	7687

Response: There are a number of factors to be accounted for in the estimation of the rate of progression of proved undeveloped reserves to proved developed reserves. The 959mmboe of PUD progressed to PD referred to in our filing is a net transfer volume, and includes [*****]mmboe that were demoted from PD to PUD following analysis of field performance and operational information. This volume has been excluded from the calculation of the weighted average rate of volume progressed, as it is not included in the PUD volume at the beginning of the year.  Disposals are accounted for in the rate of progression calculation by reducing the PUD volume available to progress. Disposals are effectively an alternative mechanism to monetise the PUDs and could be considered as part of the progression volume, but in the calculation presented, it has been excluded from the initial PUD volume. In production-sharing agreements, increasing capital costs or falling prices increase and accelerate the amount and rate of capital recovery through the cost-sharing mechanism. This has the result of accelerating the production and progression of PUD reserves to developed status. There is a similar impact where there are extensions to the field life due to price impacts – a portion of the PUD volume will be produced by existing PD wells, reducing the volume to be progressed. These impacts are included as a progression in our rate of PUD-PD calculations, but are not in the volume

BP HAS CLAIMED CONFIDENTIAL TREATMENT OF PORTIONS OF THIS LETTER IN ACCORDANCE WITH 17 C.F.R. § 200.83	- 18 -
[*****] 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.

progressed, as they are not included in the PUD volume at the beginning of the year.

Our calculation does not account for growth in our PD reserves through revisions of previous estimates, which in some cases may similarly reduce the PUD volume available for progression, for example when field performance indicates that a well’s drainage area is larger than prognosed, draining oil that was previously considered to require an additional well penetration to recover.  These corrections are reflected as a negative revision in our PUD volumes which will reduce the volume available for progression in the following year.

The following table shows the calculation on a yearly and five-year volume weighted average for the rate of progression.

Volume (mmboe)	2011	2012	2013	2014	2015	5 Year
Opening PUD balance	7,898	7,919	7,526	8,080	7,788	39,210
Disposals	-302	-116	-2,472	-15	-17	-2,923
Adjusted opening PUD balance	7,597	7,802	5,054	8,064	7,771	36,288
Net PUD-PD progression	716	1,305	1,094	1,031	959	5,106
Removal of PD-PUD volumes	[*****]	[*****]	[*****]	[*****]	[*****]	[*****]
Price impact	[*****]	[*****]	[*****]	[*****]	[*****]	[*****]
Total volume added to PD from PUD	1,091	1,504	1,198	1,140	1,419	6,353
Percent PUD progressed	14%	19%	24%	14%	18%	18%

The shaded areas show data not included in our 2015 Form 20-F, but which is necessary to make the weighted average calculation.

17. You state that revisions of previous estimates for proved undeveloped reserves (“PUDs”) are due to changes relating to field performance, well results or changes in commercial conditions including price impacts. Please revise to quantify the impact of each factor that resulted in a material change to your PUDs during 2015. Refer to Item 1203(b) of Regulation S-K.

Response: We reported a total of 300mmboe of revisions of previous estimates for BP comprised of 61mmboe in our subsidiaries and a net 239mmboe in our equity-accounted entities, primarily in Rosneft.

Changes in prices were the most significant factor for our subsidiaries, with a net impact of [*****]mmboe in total, being[*****]mmboe in our production-sharing agreements and [*****]mmboe in our tax and royalty concessions. BP’s portfolio is heavily biased to developments where our cessation of production date is limited by licence date and facility life, rather than economic production. This makes our portfolio more resilient to price impacts. No individual field or region had a material revision.

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[*****] 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.

The primary revisions within the Rosneft fields were in the gas assets, Rospan International (including Rospan, Tyumenneftegas, Tagul, Suzun and Rossko-Rechenskoye fields) had additions reflecting the approval of new gas contracts confirming the ability and intent to deliver gas through the Vankor area pipeline.

International trade sanctions, page 242

18. In your letter to us dated September 19, 2013, you discussed contacts with Syria and Sudan. As you are aware, Syria and Sudan are designated by the U.S. Department of State as state sponsors of terrorism and are subject to U.S. economic sanctions and export controls. Please describe to us the nature and extent of your past, current, and anticipated contacts with Syria and Sudan since your 2013 letter, whether through subsidiaries, affiliates, distributors, resellers or other direct or indirect arrangements. You should describe any products, services or technology you have provided to Syria and Sudan, directly or indirectly, and any agreements, commercial arrangements, or other contacts with the governments of those countries or entities they control.

Response: Since our letter dated 19 September 2013, we have continued to disclose information regarding activities in sanctioned countries in our annual reports filed on Form 20-F. We refer the Staff to the most recent disclosure under the heading “International trade sanctions” in the 2015 Form 20-F.

As described in our response to Comment 19 below, we do not consider that the limited business activities BP has conducted in, or with companies from, Syria and Sudan are material to the BP group.

Sudan

BP has equity interests in non-operated joint arrangements with aviation fuel sellers, resellers, and fuel delivery services around the world. From time to time, the joint arrangement operator or other partners may sell or deliver fuel to airlines from Sudan or flights to Sudan without BP’s prior knowledge or consent.

Sales to resellers that we understand were subsequently used to fuel Sudan-registered aircraft or aircraft owned or operated by Sudanese entities amounted to $[*****] in 2013. BP is not aware of any such resales in 2014, 2015 or the first half of 2016.

In addition, in March 2015, BP provided aircraft refuelling services at O.R. Tambo International Airport in South Africa to an aircraft of [*****], which is registered in North Sudan. A sale of fuel was made by a third party to the operator of the aircraft. BP provided the into-plane service only, and, for competition purposes, is not permitted to obtain the price or volume details of the sale. BP does not knowingly accept fuel requests for Sudan-registered aircraft or aircraft belonging to Sudanese airlines.

BP has also registered certain of its patents and trademarks in Sudan and paid approximately $[*****] in 2013, $[*****] in 2014 and $[*****] in 2015 for intellectual property (IP) registration services and maintenance and enforcement

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[*****] 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.

of registered trade mark rights. No such payments were made in the six-month period ended 30 June 2016.

No other technologies, equipment, services or products have been provided to Sudan. No other payments have been made to the government of Sudan. BP has no facilities in Sudan.

Syria

As BP has previously disclosed, following the imposition in 2011 of further US and EU sanctions against Syria, BP terminated all sales of crude oil and petroleum products into Syria.

BP has equity interests in non-operated joint arrangements with aviation fuel sellers, resellers, and fuel delivery services around the world. From time to time, however, the joint arrangement operator or other partners may sell or deliver fuel to airlines from Syria or flights to Syria without BP’s prior knowledge or consent.

BP has made sales of aviation fuel at various locations outside of Syria to four UAE-incorporated resellers that were owned wholly or partly by Syrian nationals: [*****]. BP has been advised that sales to these resellers do not violate US or EU sanctions. Sales to these resellers totalled $[*****] in 2013, $[*****] in 2014, $[*****] in 2015 and $[*****] in the six months ended 30 June 2016. Sales to [*****] have now been terminated. BP does not knowingly accept fuel requests for Syrian-registered aircraft or aircraft belonging to Syrian airlines.

BP has registered certain of its patents and trademarks in Syria and paid approximately $[*****] in 2013, $[*****] in 2014, $[*****] in 2015 and $[*****] in the six months ended 30 June 2016 for IP registration services and maintenance and enforcement of registered trade mark rights.

No other payments have been made to the government of Syria, and no other technologies, equipment, services or products have been provided to Syria.

19. Please discuss the materiality of any contacts with Syria and Sudan you describe in response to the comment above, and whether those contacts constitute a material investment risk for your security holders. You should address materiality in quantitative terms, including the approximate dollar amounts of any associated revenues, assets, and liabilities for the last three fiscal years and the subsequent interim period. Also, address materiality in terms of qualitative factors that a reasonable investor would deem important in making an investment decision, including the potential impact of corporate activities upon a company’s reputation and share value. As you know, various state and municipal governments, universities, and other investors have proposed or adopted divestment or similar initiatives regarding investment in companies that do business with U.S.-designated state sponsors of terrorism. You should address the potential impact of the investor sentiment evidenced by such actions directed toward companies that have operations associated with Syria and Sudan.

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[*****] 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.

Response: Sudan

Sales of aviation fuel to resellers that we understand were subsequently used to fuel Sudan-registered aircraft or aircraft owned or operated by Sudanese entities described in response to Comment 18 represented less than [*****]% of BP group’s total sales and other operating revenues for the fiscal year ended 31 December 2013.

For each of the fiscal years ended 31 December 2013, 2014 and 2015 and the six-month period ended 30 June 2016, BP made no purchases and had no sales, other operating revenues or assets within Sudan or otherwise attributable to Sudan contacts, other than the limited sales of aviation fuel described in response to Comment 18.

Syria

Sales of aviation fuel attributable to UAE-incorporated resellers that are owned wholly or partly by Syrian nationals represented less than [*****]% of BP group’s total sales and other operating revenues for each of the fiscal years ended 31 December 2013, 2014 and 2015 and the six-month period ended 30 June 2016.

For each of the fiscal years ended 31 December 2013, 2014 and 2015 and the six-month period ended 30 June 2016, BP made no purchases and had no sales, other operating revenues or assets within Syria or otherwise attributable to Syrian contacts, other than the limited sales of aviation fuel described in response to Comment 18.

As noted in response to Comment 18 and in the 2015 Form 20-F, BP has equity interests in, and other contractual and non-contractual relationships with, aviation fuel sellers, resellers, and fuel delivery services around the world. From time to time, such seller, reseller or fuel delivery services company may sell or deliver fuel to airlines from sanctioned countries or flights to sanctioned countries without BP’s prior knowledge or consent.

From a quantitative point of view, and taking into account the size and diversity of the overall operations of BP, we do not believe that BP’s operations in sanctioned countries are material to BP or pose any material risk for its security holders.

We have also considered qualitative factors that a reasonable investor would deem important in making an investment decision, including the potential impact of corporate activities upon a company’s reputation and share value that could result from the fact that BP has business interests with countries that the US Government has designated a sponsor of terrorism and that currently are subject to US and/or EU economic sanctions. We have also noted the adoption and potential adoption of legislation by certain US states and the internal policies of certain US institutions, which would prohibit investment in, and/or require divestment from, companies that conduct certain business with certain sanctioned countries.

In light of the immateriality of our limited contacts with Syria and Sudan, which were entered into in the ordinary course of business, and the reduction or cessation of certain activities as noted above, we believe that our existing security holders and potential new investors would not consider that these

BP HAS CLAIMED CONFIDENTIAL TREATMENT OF PORTIONS OF THIS LETTER IN ACCORDANCE WITH 17 C.F.R. § 200.83 - 22 -

activities adversely affect, or could adversely affect, our reputation or share value.

We monitor our activities with sanctioned countries to ensure compliance with applicable laws and regulations of the US, the EU and other countries or regions where BP operates. We are continuing to monitor our activities with sanctioned countries in order to, as appropriate, convey any potential material risk to our security holders.

We acknowledge that BP is responsible for the adequacy and accuracy of the disclosure in its 2015 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 2015 Form 20-F, and that BP may not assert Staff comments as a defense in any proceeding initiated by the Commission or any person under the federal securities laws of the United States.

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

Yours sincerely,

 /s/ B. Gilvary          

Dr B. GILVARY

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