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BP HAS CLAIMED CONFIDENTIAL TREATMENT OF
PORTIONS OF THIS LETTER IN ACCORDANCE WITH
17 C.F.R. § 200.83
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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
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| Re: |
BP p.l.c.
Form 20-F for the Fiscal Year Ended 31 December 2015 Filed 4 March 2016 File No. 001-06262 |
| Response: |
In view of the lower oil and gas price environment we included a new two-page section in our 2015 Form 20-F, beginning on page 18, to provide information on the implications for BP and the actions being taken in response. As noted in your comment, we explained the impact of lower prices on our financial results in this section. We also provided additional disclosures in various other sections of the document to inform investors about the impacts lower prices were having and could have in the future.
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In particular, we set out on page 19 the expected prospective impacts of actions that we have taken to address the low oil price, i.e. reduced capital expenditure and reduced production costs, the reduction in the number of employees and additional proceeds being generated from divestments. We also noted on page 19 that we expected gearing to be at an increased level while low oil prices persist and disclosed the oil price at which we expected to be able to balance cash inflows and outflows in the future. Further information was provided in the “Liquidity and capital resources” section on page 219 where we discussed our cash position and sources of funding in further detail.
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We also noted oil and gas prices as one of our strategic and commercial risks, in the “Risk factors” section on page 53. Specifically, decreases in prices could have an adverse effect on revenue, margins, profitability and cash flows. We stated that if price decreases were significant or for a prolonged period, we may have to write down assets and re-assess the viability of certain projects, which may impact future cash flows, profit, capital expenditure and our ability to maintain our long-term investment programme.
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In the Market Outlook section on page 10 and the Our Markets in 2015 section on page 24 we commented on the current price environment and the factors impacting upon prices during the year, our expectation that prices will remain low for the near term and noted some of the factors that will impact upon energy demand for the future. We also explained some of the actions which we are taking to embed cost efficiency and simplification in the current environment. We noted on page 24 the increase in global oil consumption in response to the decline in world oil prices.
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In our Upstream Outlook for 2016 section on page 28 we provided disclosure regarding our expectation for 2016 production, capital investment and operating costs and stated specifically that oil prices will continue to be challenging in the near term.
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We do not believe that it is possible to provide a meaningful quantification of the possible impacts of the lower oil price environment on the group’s results of operations, liquidity and capital resources. The interrelationships between different variables are complex, non-linear and specific to various different businesses and contractual arrangements within the group. Changes in prices have differing effects on revenue, depending upon the contractual arrangements in place, and costs are difficult to forecast because in a lower price environment efficiency improvements are realised along with a general deflation in contracting and other costs.
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Where possible we have provided quantification. As noted above we disclosed the oil price at which we expected to be able to balance cash inflows and outflows. Furthermore, as part of our disclosure relating to the annual impairment testing of goodwill (Note 13 on the financial statements, page 135), we provided an estimate of the change in oil and natural gas price assumptions that would reduce the recoverable amount of goodwill to its carrying amount. However, we note that such sensitivities are necessarily estimated using simplifying assumptions, by flexing only one variable at a time. We stated as part of this disclosure, for example, that “lower oil and gas prices sensitivities do not reflect the specific impacts for each contractual arrangement and will not capture fully any favourable impacts that may arise from cost deflation. Therefore a detailed calculation at any given price or production profile may produce a different result.”
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We therefore do not believe it is reasonably practicable to provide any additional meaningful sensitivities in relation to the impact of continued lower oil prices on future results of operations, liquidity and capital resources.
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As indicated in our response to prior comment 1, our long-term price assumptions are reviewed annually and following the 2016 review the long-term real price assumptions were reduced. We will include additional disclosure in our Form 20-F for the fiscal year ended 31 December 2016 (“2016 Form 20-F”) to explain how recent prices compare to our long-run price assumptions and the reasons why we expect market dynamics to lead to these long-run prices in the long term. This text will be based upon the explanations we provided in response to prior comment 1, in particular the third and fourth paragraphs of that response.
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| 2. |
We note your disclosure stating that if prices remain lower for longer than anticipated, you expect to continue to recalibrate for the weaker environment. Separately, as part of your response to prior comment 7, you state that material changes to the progression of your proved undeveloped reserves are not anticipated if prices remain at current levels. Please add disclosure addressing your commitment to your development plan at current oil and gas prices here and in the section of your filing on page 227 regarding proved undeveloped reserves. Refer to Rule 4-10(a)(31)(ii) of Regulation S-X and question 131.04 of the Compliance and Disclosure Interpretations regarding Oil & Gas Rules.
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| Response: |
We intend to include additional disclosure in our 2016 Form 20-F in the section regarding proved undeveloped reserves, as follows:
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“Proved reserves as estimated at year end 2016 meet 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 undeveloped reserves have been attributed in light of lower oil and gas prices. BP has responded to the downturn in prices by enhancing the efficiency and productivity of our operations.”
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| 3. |
It appears from your response to prior comment 1 that your short-term price assumptions for the first five years will no longer be based on market prices. We further note the disclosure on page 17 of your Form 6-K for the period ended September 30, 2016 which states: “For both value-in-use and fair value less costs of disposal impairment tests performed during the third quarter, the price assumptions used have been set such that there is a gradual transition over a five-year period from current market prices to the long-term price assumptions for 2022.” Explain to us in more detail why you believe the change to the short-term price assumptions is appropriate. As part of your response, tell us more about how you will determine the corresponding prices used for this five-year period and what those prices were for testing performed as of September 30, 2016.
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| Response: |
IFRS (IAS 36.33) requires that value-in-use cash flow projections should be based upon reasonable and supportable assumptions that represent management’s best estimate of the range of economic conditions that will exist over the life of the asset, with greater weight being given to external evidence. Cash flow projections for the earlier years should be based on the most recent financial budgets/forecasts approved by management.
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Prior to the third quarter 2016 our short-term price assumptions used for both value-in-use and fair value less costs of disposal impairment tests for the first five years were market prices derived from the forward curves for the commodities concerned. However, as noted on page 111 of our 2015 Form 20-F, these prices have been particularly volatile in the current price environment, and as part of our annual review of prices for 2016 we noted a lack of liquidity in markets beyond the very near term. Liquidity data for forward market prices shows that the volume of trades which underpin the published prices falls significantly after the first year to a relatively low level by the third year. Furthermore, forward market prices now differ from prices used for planning purposes. Therefore, although forward market prices represent external evidence, we concluded that these prices no longer represent the most appropriate assumptions for impairment testing.
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As set out in our response to prior comment 1, our long-term price assumptions are based on an assessment of the long-run fundamental drivers of the market and reflect factors influencing both demand and supply, as advised by our
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Economics team. For the first five years the prices we used for our third-quarter reporting, and intend to use going forwards, are our latest internal planning assumptions. These assumptions are set annually based on a review of market fundamentals and taking into account the prevailing market environment. The review is conducted jointly by our Long Term Planning, Economics, Trading Analytics and Segment teams. As a result of this review, our short-term planning assumptions are based on a gradual transition from the current price environment to our long-term planning assumptions. In reality oil and gas prices exhibit volatility due to short-term drivers which are inherently difficult to predict. However, this profile represents management’s best estimate of the transition from the current environment of significant excess oil inventories to a more balanced market. There are no specific factors at this time that management believes it can predict that would suggest anything other than a gradual transition over the first five years.
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Confidentially for the information of the Staff, the short-term prices used for impairment testing in the third quarter are shown in the table below and we expect to use these same price assumptions for our 2016 year-end reporting.
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2017
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2018
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2019
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2020
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2021
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Brent oil price ($/bbl)
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[***]
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[***]
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[***]
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[***]
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[***]
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Henry Hub natural gas price ($/mmBtu)
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[***]
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[***]
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[***]
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[***]
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[***]
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| 4. |
The projected unit development cost from the 2015 subsidiaries standardized measure is $15.13/BOE (=$63,700 million/4211 MMBOE). Your 2015 incurred unit development cost appears to be $21.50/BOE (=$13,458 million/626 MMBOE from page 227). We see similar differences for 2014 and 2013. Please explain the reason(s) for these variances between your projected and incurred unit development costs.
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| Response: |
Development costs expended during the year result from two broadly different types of activities: (i) base development activity in existing fields that result in a progression of PUD to PD reserves in the year of the expenditure; and (ii) major projects in new and existing fields that will incur development costs in the years preceding the progression of PUD to PD reserves. The two tables included in our response to prior comment 7 detail the progression and planned progression of PUD to PD reserves for our regions and major projects over the five years from 2016 to 2020.
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As shown in the tables, base development activity, principally consisting of extensional and infill drilling, is roughly constant with annual additions of [***] to [***] mmboe. Major project PD additions, however, occur only after significant investment in facilities and wells. For particularly complex projects with external constraints on the pace of development, there may be a lag of up
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to or greater than five years from the development expenditure and the PD addition. Thus the total PD volume added in any given year is not associated with the total development expenditure in that year.
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As shown in the second table in our response to prior comment 7, 2017 and 2019 will be exceptionally significant years for PD additions as our Clair Ridge, Quad 204 (North Sea), Khazzan (Oman), Juniper (Trinidad) and West Nile Delta (Egypt) projects begin production. These years will show substantially lower unit development costs than 2013 through 2015, as a significant percentage of the development costs have already been incurred.
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| 5. |
Response 16 presents a five year (plus summary) table for the changes to your proved undeveloped reserves. We note that those changes include volumes that were not categorized as PUD at beginning of each year, but appear to be revisions, and are not the results of development activity. Please revise your discussion here to present also those portions of PUD reserves available at the beginning of each of the five years that you converted to proved developed status with development activities.
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| Response: |
The only changes presented in our response to prior comment 16 that were not included in the original PUD balance were the impact of price on the life of the field. Note that our response to prior comment 16 stated that “our calculation does not account for growth in our PD reserves through revisions of previous estimates”. Removing the impact of price from the calculation of our weighted average progression results in a five-year weighted average of [***], as shown in the following table, rather than the 18% which we reported in our 2015 Form 20-F.
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(Volume in mmboe)
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2011
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2012
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2013
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2014
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2015
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5 Year
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Opening PUD Balance
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7,898
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7,919
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7,526
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8,080
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7,788
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39,210
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Disposals
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-302
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-116
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-2,472
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-15
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-17
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-2,923
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Corrected Opening PUD Balance
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7,597
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7,802
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5,054
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8,064
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7,771
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36,288
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Net PUD-PD Progression
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716
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1,305
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1,094
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1,031
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959
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5,106
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Removal of PD-PUD volumes
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[***]
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[***]
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[***]
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[***]
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[***]
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[***]
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Total Volume Added to PD from PUD
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[***]
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[***]
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[***]
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[***]
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[***]
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[***]
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Percent PUD Progressed
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[***]
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[***]
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[***]
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[***]
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[***]
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[***]
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However, we do not believe this approach to the calculation provides a meaningful representation of our weighted progression of PUDs to PDs as it does not account for changes to the starting balance as a result of changes in price, and may distort the perceived progression either positively or negatively. While we are not aware of any specific guidance on the method of calculating changes to proved reserves, we note that for the changes to standardized discounted cash flows, ASC 932-235-50-35 states that:
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“In computing the amounts under each of the above categories, the effects of changes in prices and costs shall be computed before the effects of changes in quantities.”
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For example, consider a single-well project with PUD reserves of 10 mmboe. If a price change in the year of drilling extended the cessation of production date, increasing PUD reserves to 12 mmboe, this change would be made to the PUD volume prior to the progression to PD. The project would thus have a 120% progression of volume compared to the PUD volumes available at the beginning of the period. This would be adjusted to 100% only by including the impact of price changes to the opening balance.
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While we acknowledge that there are alternative ways to calculate the progression of PUD to PD reserves, we believe that our approach as described in our response to prior comment 16 provides the most meaningful representation of our weighted average progression of PUD to PD for the investor.
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| 6. |
We note your response to prior comment 17. Revise your disclosure to include quantification for each material item underlying the revisions to your previous estimates for proved undeveloped reserves to comply with Item 1203(b) of Regulation S-K.
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| Response: |
We will include disclosure and quantification of all material items underlying our 2016 revisions in our 2016 Form 20-F. We do not believe that any of the individual revisions reflected in our 2015 Form 20-F merited specific discussion as no individual revision was material.
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Yours sincerely,
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/s/ B. Gilvary
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Dr. B. GILVARY
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| cc: |
K.A. Campbell (Sullivan & Cromwell LLP)
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