FOIA CONFIDENTIAL TREATMENT REQUESTED BY

EXXON MOBIL CORPORATION

 

 

October 24, 2016

 

Mr. H. Roger Schwall

Assistant Director

U.S. Securities and Exchange Commission

Division of Corporation Finance

100 F Street, N.E.

Washington, DC  20549

 

Re:      Exxon Mobil Corporation

            Form 10-K for Fiscal Year Ended December 31, 2015

            Filed February 24, 2016

            File No. 1-02256

 

 

Dear Mr. Schwall:

 

On behalf of Exxon Mobil Corporation, please find enclosed our response to your comments regarding the above filing set forth in your letter of September 8, 2016.

 

In accordance with the Commission’s October 5, 2016 announcement that “Tandy” representations are no longer needed in filing reviews, the representations requested in the staff’s September 8, 2016 comment letter have not been included in this response.

 

If you desire clarification of our responses, please direct any questions to Mr. Stephen J. Kestle at 972-444-1290.

 

 

                                                                        Sincerely,

 

                                                                        By:      /s/ David S. Rosenthal

_________________________________________________________________________________________________

                                                                                    Name:     David S. Rosenthal

                                                                                    Title:        Vice President and Controller

 

 

Enclosure

 

c:      Lily Dang

         Brad Skinner

ExxonMobil’s Response to the

Comments Included in the SEC Letter of September 8, 2016

 

Form 10-K for the Fiscal Year Ended December 31, 2015

 

Properties, page 5

 

Proved Undeveloped Reserves, page 7

 

1.    As part of your discussion relating to the changes in proved undeveloped reserves that occurred during 2015, you identify an addition to your reserves of approximately 1.7 GOEB. This figure appears to represent an aggregation of the changes attributable to two separate factors, e.g. extensions and purchases.

 

Your disclosure should reconcile the overall change in the net quantities by separately identifying and quantifying each factor that contributed to a material change so that the change between periods is fully explained. To the extent that two or more factors contribute to a material change, you should indicate the net amount attributable to each factor.

 

Expand your disclosure to quantify the changes in net reserves accompanied by a narrative explanation relating to such individual factors as revisions of previous estimates, improved recovery, extensions and discoveries, acquisitions, divestitures and the net reserves converted during 2015 from proved undeveloped to proved developed. See Item 1203(b) of Regulation S-K.

We believe our current disclosure satisfies the requirements of Item 1203 of Regulation S-K. As required by Item 1203(b), we disclose material changes in proved undeveloped reserves that occurred during the year including proved undeveloped reserves converted into proved developed reserves. Specifically, we disclose an addition of 1.7 GOEB of proved undeveloped reserves which was primarily related to extensions of 1.3 GOEB in Abu Dhabi and the United States unconventional assets, and purchases of 0.2 GOEB in the United States. In future filings, we will expand our proved undeveloped reserves disclosure to separately identify and quantify the material factors that contributed to a change when two or more factors contribute to a material change.

 

Beyond the requirement to disclose material changes, as we believe we have done, Item 1203(b) does not identify reconciliation of period over period changes according to a specified list of factors as is required for changes in proved developed and undeveloped reserves elsewhere in the 10-K.

Management’s Discussion and Analysis

Critical Accounting Estimates, page 56

Impact of Oil and Gas Reserves, Prices and Margins on Testing for Impairment, page 57

 

2.    You disclose that in light of continued weakness in the upstream industry environment in late 2015, you undertook an effort to assess your major long-lived assets most at risk for potential impairment. You further disclose that the results indicate that the future undiscounted cash flows associated with these assets substantially exceed their carrying values, and that the assessment reflects crude and natural gas prices that are generally consistent with the long-term price forecasts published by third-party industry experts.

 

Please tell us in more details the pricing assumptions used in your asset impairment assessment including:

 

·         The specific prices and time periods used, as well as the basis for each;

 

·         How the prices reflect the external evidence represented by current prices at and around December 31, 2015, including how they are “generally consistent” with published long-term prices;

 

·         How the prices were used to develop cash flow projections, both for near-term and longer-term years; and,

 

·         How the prices compared to the prices used in your most recent budgets or forecasts approved by management.

 

As part of your response, explain how your use of these prices takes into consideration the requirements of FASB ASC paragraphs 360-10-35-29 to 35.

The Corporation rigorously assesses the fundamentals of worldwide energy markets by region each year, seeking to identify long-term trends important to our business. We annually publish the high‑level results of our energy market analysis, the most recent of which is “The Outlook for Energy – a View to 2040”, available on our website and summarized on pages 41 and 42 of our 2015 Form 10-K. Through its analysis of long-term energy markets, the Corporation develops a range of price assumptions for use in its annual planning and budgeting process. These prices are consistent with those management uses to evaluate investment opportunities, and we test a project’s economic performance over a wide range of prices. We used the midpoint of the range in our assessment of major long-lived assets in late 2015. Given the long-term nature of the energy business our focus is appropriately weighted more toward long-term market fundamentals than short-term volatility considerations.

 

Around the end of 2015 and beginning of 2016, U.S. natural gas prices and worldwide crude prices had fallen to multi-year lows. The Corporation’s management does not believe that lower prices are sustainable if energy is to be delivered with supply security to meet global demand over the long term. Market prices for commodities may occasionally drop below the fully invested cost of production, but with natural decline in current producing assets, prices over the longer term will continue to be driven by the fundamentals requiring a return on investment needed to generate adequate supply to meet demand. Because the lifespans of the vast majority of the Corporation’s major assets are measured in decades, the value of these assets is predominantly based on long-term views of future commodity prices and production costs. While near-term prices are subject to wide fluctuations, longer term price views are more stable and meaningful for purposes of assessing future cash flow projections which serve as a basis of market value.

 

A period of low natural gas and crude prices has only a limited impact on longer term price expectations. Since the lows of early 2016, both U.S. natural gas prices and Brent crude prices have risen 50 to 80 percent.  As indicated in the table below, the midpoint prices the Corporation used for its projection of undiscounted cash flows reflect a gradual rebalancing of supply and demand over the next several years.

 

As noted above, the Corporation reviews crude and gas markets each year and updates its outlook and range of price outlooks as appropriate based on market developments.

 

[Confidential information omitted; XOM-001]

[Confidential information omitted; XOM-002]

[Confidential information omitted; XOM-003]

To develop cash flow projections for the purposes of our 2015 assessment, and in accordance with FASB ASC paragraph 360-10-35-30, the Corporation used its long-term view for development activity for each of the assets, consistent with the midpoint of its long-term price outlook. This long-term view included estimates for drilling costs, well productivity, and production costs. These parameters yield a projection for long-term volumes generated by the development activity. The midpoint of the Corporation’s price outlooks, adjusted as appropriate for quality and location differentials, was then applied to this volume outlook to develop long-term projections of undiscounted cash flows.

 

Consolidated Financial Statements

 

Notes to Consolidated Financial Statements, page 68

 

Note 1 - Summary of Accounting Policies - Property, Plant and Equipment, page 69

 

3.   Regarding the disclosure “In the event that the unit-of-production method does not result in an equitable allocation of cost over the economic life of an upstream asset, an alternative such as the straight-line method is used”, tell us the following:

·         Explain to us how you determine whether an allocation of cost is “equitable”;

 

·         Identify any specific properties to which this policy has been applied, and describe the reasons why the unit-of-production method did not result in an “equitable” allocation of cost; and,

 

·         Describe the specific alternative methods used for the specific properties to which any such methods were applied.

In the Upstream, capitalized exploratory, drilling, and development costs are amortized using unit-of-production (UOP) rates based on the amount of proved developed reserves. An alternative such as the straight-line method is considered in a limited number of situations where the expected future benefits of the asset do not reasonably correlate with the production of related reserves. In these cases, management judgment must be applied to determine whether use of the unit-of-production method would result in equitable allocation of the asset’s costs to the periods in which the benefits are derived.

 

The Corporation can envision certain situations where depreciation by a method other than unit-of-production may be appropriate. When crude oil and natural gas prices are in the range seen in early 2016 for an extended period of time, under the SEC definition of proved reserves, certain quantities of oil and natural gas, such as oil sands operations in Canada and natural gas operations in North America, could temporarily not qualify as proved reserves. Amounts that could be required to be de-booked as proved reserves on an SEC basis are subject to being re-booked as proved reserves at

some point in the future when price levels recover, costs decline further, or operating efficiencies occur. For properties that continue to produce in the interim, U.S. GAAP requires the capitalized development costs of the properties to be amortized as units are produced. To the extent that proved reserves are entirely de-booked, the denominator of the unit-of-production calculation would be zero. In the absence of related reserves with which to calculate a meaningful rate, an alternative depreciation method must be determined which most closely matches the cost of the asset with the units produced.

 

As another example, we depreciate certain gas plants and processing facilities using the straight-line method. Over their economic lives, these plants and facilities may process third party gas from surrounding fields in which ExxonMobil does not have an interest, and facility capacity is maintained via other contractual arrangements. In these arrangements, economic benefit is partly related to other compensation such as processing fees. Therefore, the utilization of these plants and facilities does not necessarily fluctuate with the Corporation’s production. In these cases, the straight-line method provides a more equitable allocation of costs over the economic life of the asset. ASC 932-360-35-7 acknowledges that depreciation of gas cycling and processing plants by a method other than the unit-of-production method is appropriate. The largest (by net book value) gas plants and processing facilities reported in ExxonMobil’s Property, Plant, and Equipment which are depreciated using the straight-line method include:

 

[Confidential information omitted; XOM-004]

 

 

 

 

 

  

 

ExxonMobil also uses the straight-line method for certain support equipment and processing assets associated with our bitumen mining operations in Canada. Unlike typical oil and gas wells, the productive life of heavy mining equipment and hydro-transport lines is more closely related to usage and physical wear and tear over time than to reserves. As such, the expected useful life of these assets can be shorter than the expected life of the mine. Use of the straight-line method results in a depreciation charge that is generally higher than what would be calculated under a UOP methodology and more representative of the useful life consumed in the period. The largest (by net book value) support and processing assets reported in ExxonMobil’s

Property, Plant, and Equipment which are depreciated using the straight-line method include:

 

[Confidential information omitted; XOM-005]

 

 

 

 

  

 

4.    Your disclosure indicates that you do not view “temporarily” low prices or margins as a trigger event for conducting impairment tests. Expand this disclosure to clarify how you determine whether low prices or margins are temporary and to explain how you consider items such as the decrease in your standardized measure between December 31, 2014 and December 31, 2015 or the recurring quarterly losses reported in your US upstream operations during 2015 and the first half of 2016 in assessing whether a triggering event has occurred.

The Corporation believes that its 2015 Form 10-K disclosure appropriately explains what factors it considers when determining potential events for impairment evaluations, and believes significant management judgment must be applied when determining whether or not events and circumstances indicate that long-lived assets should be tested for recoverability. Among such events and circumstances could be a prolonged and deep reduction in commodity prices. As noted earlier in our response to Question 2, the Corporation develops price assumptions for use in its annual planning and budgeting process. In this context, the term “temporary” means any changes in current or near-term prices that do not result in a significant change to the range of long-term price assumptions which the Corporation uses for its capital investment decisions. Over the last 25 years, due to political, economic, and technological reasons, both crude and natural gas prices have exhibited significant volatility, with prices reaching, at their highest, levels that were 10 times or more their lowest over the period. In our business where asset values must be measured over decades, our focus is appropriately weighted more toward long-term market fundamentals than short-term volatility considerations.

 

The decrease in the standardized measure between December 31, 2014 and December 31, 2015 did not enter into the Corporation’s consideration regarding whether or not an impairment assessment was warranted. The standardized measure includes only proved reserves and reflects prescriptive assumptions such as use of current year average prices. As such, the Corporation does not believe the standardized measure

provides a reliable estimate of expected future cash flows or market value for its major assets, and therefore is not useful for assessing the recoverability of long-lived assets.

 

The quarterly losses reported by the Corporation’s U.S. Upstream operations in 2015 and 2016 reflect a general weakness in the industry environment at that time. In light of this, and as noted in our 2015 Form 10-K filing, the Corporation undertook an effort to assess its major long-lived assets. That assessment did not indicate a projection or forecast of continuing losses, and in fact indicated that future undiscounted cash flows associated with those assets substantially exceeded their carrying value.

 

Note 10 - Accounting for Suspended Exploratory Well Costs, page 77

 

5.    Disclosure under this note suggests that suspended well costs include amounts attributable to the Rosneft joint venture. However, disclosure under Note 7 - Equity Company Information suggests that the Rosneft joint venture is reported as an equity company and is reported under the balance sheet caption Investments, Advances and Long-Term Receivables. If suspended well costs attributable to the Rosneft joint venture are included in the amounts reported under Note 10, explain your basis for this and, given the existing sanctions applicable to the joint venture, explain why continued capitalization of these costs is appropriate. See FASB ASC paragraph 932-360-35-13.

The Corporation discloses suspended exploratory well costs for both consolidated subsidiaries and equity companies when the well has found a sufficient quantity of reserves to justify its completion as a producing well and the Corporation is making sufficient progress assessing the reserves and the economic and operating viability of the project. The amount attributable to equity companies included in the ending balance is separately identified. Consistent with the oil and gas disclosures in the Form 10-K regarding proved reserves, exploratory wells drilled, acreage, production, results of operations, capitalized costs, and costs incurred, we believe it is appropriate to provide equity company information regarding suspended exploratory well costs in order to provide additional information to investors. The nature of the oil and gas business often involves investments in equity companies that explore and develop world class size resources.

 

Suspended exploratory well costs attributable to the Rosneft joint venture are included for the University-1 well in the Kara Sea that spudded in August 2014. Pursuant to the European Union and United States imposed sanctions relating to the Russian energy sector, the exploration activities in the Kara Sea were suspended in 2014. Both ExxonMobil and the Kara Sea joint venture company continue to comply with all applicable laws, rules and regulations, including the conduct of certain activities authorized under licenses. When the government sanctions are lifted, exploratory activities, such as additional analysis of the well results and technical evaluations, are expected to resume in the Kara Sea. These activities are necessary in order to complete the assessment of a Kara Sea development. Since the imposition of the

sanctions, we have not obtained information that raises substantial doubt about the economic or operational viability of a development, and we will continue to monitor the economic, legal, political, and environmental aspects of the potential development. Once sanctions are lifted and the exploratory activities are completed, we will be able to make a final determination on the viability of a Kara Sea development.

 

6.    Regarding the suspended well costs attributable to your Horn River project, address the following:

 

·         Explain to us the current status of the project;

 

·         Describe any changes in the status or the nature and timing of all planned future activities between 2014 and 2015;

 

·         Explain whether and how the lower project activity in Canada described elsewhere in your filing will impact the project; and,

 

·         Explain how you have evaluated the criteria in FASB ASC paragraphs 932-360-35-13 and 932-360-35-18 through 20 in determining that continued capitalization of these costs is appropriate.

In regards to Horn River, as disclosed in Note 10 - Accounting for Suspended Exploratory Well Costs, we are evaluating development alternatives to tie into planned infrastructure. At year-end 2015, the suspended exploratory well costs were $241 million for 21 exploratory wells drilled in the years from 2009 to 2012. Also, at year-end 2015, there was no further exploratory activity planned at Horn River. As noted in our second quarter 2016 Form 10-Q, $111 million of suspended exploratory well costs was expensed in the first six months of 2016, of which $37 million was for three exploratory wells associated with acreage in the southern portion of Horn River which was voluntarily relinquished during second quarter 2016. Currently, the development of the Horn River resource is being assessed as a resource for a potential LNG project in Prince Rupert, British Columbia, known as the West Coast Canada (WCC) LNG project. Under this scenario the Horn River resource would be exported through an export license received by ExxonMobil in 2013 from the National Energy Board to export up to 30 million tonnes of LNG per year for 25 years. The export license was extended in July 2016 to 40 years. A suitable site has been identified with scale to facilitate cost effective development. ExxonMobil is making progress on an environmental assessment process and has engaged the British Columbia Environmental Assessment Office and First Nations. Discussions are being held with federal and provincial governments on fiscal and regulatory framework. Ongoing project design and cost reduction efforts have identified opportunities to improve global competitiveness. Also, Horn River production has the potential to be marketed in North America.

 

Between 2014 and 2015, evaluation of our Horn River acreage position progressed with the completion of a production pilot. The Horn River development studies continued to

be updated with key technical data collected from the pilot. Engineering and environmental studies continued in 2015, supporting concept selection and regulatory activity for the WCC LNG project.

 

The discussion of “lower project activity in Canada” as included in our 2015 Form 10-K, Management’s Discussion and Analysis, Environmental Matters section and elsewhere in our filing is in reference to a decreased amount of future environmental expenditures as a result of the expected completion of our Kearl Fine Tailings Treatment project in 2016. Therefore, this statement does not apply to the future development of the Horn River resource.

 

The continued capitalization of exploratory well costs associated with the development of the Horn River resource is in accordance with FASB ASC paragraphs 932-360-35-13 and 932-360-35-18 through 20 as evidenced by the previously referenced activities and progress under way to assess the reserves and the economic and operating viability of the project. As also noted above, those costs no longer deemed an integral part of the project have been expensed.