October 11, 2016
VIA EDGAR
Brad Skinner
Senior Assistant Chief Accountant
Office of Natural Resources
United States Securities and Exchange Commission
Division of Corporation Finance
100 F Street, N.E.
Washington, D.C. 20549
| Re: | Rice Energy Inc. | |
| Form 10-K for the Year Ended December 31, 2015 | ||
| Filed February 25, 2016 | ||
| Form 8-K | ||
| Furnished August 3, 2016 | ||
| File No. 001-36273 |
Dear Mr. Skinner:
This letter responds to the letter (the “Comment Letter”) dated September 20, 2016 regarding the comments of the staff of the Division of Corporation Finance (the “Staff”) of the Securities and Exchange Commission (the “Commission”) with respect to the above referenced Annual Report on Form 10-K for the year ended December 31, 2015 (the “Form 10-K”) of Rice Energy Inc. (the “Company”, “we” or “our”) and the above referenced Current Report on Form 8-K (the “Form 8-K”) of the Company. For the convenience of the Staff, we have reproduced the Staff’s comments in bold type and have followed each comment with the Company’s response.
Form 10-K for the Fiscal Year Ended December 31, 2015
Risk Factors, page 20
| 1. | You disclose on page 26 that “If commodity prices decrease to a level such that our future undiscounted cash flows from our properties are less than their carrying value for a significant period of time, we will be required to take write-downs of the carrying values of our properties”. Explain to us what you mean by a “significant period of time”. Additionally, explain how the accounting policy implied by this disclosure complies with the requirements of FASB ASC paragraph 360-10-35-17. |
Response: We acknowledge the Staff’s comment and propose to revise the risk factor in future filings as illustrated below. As we discuss in greater detail under Critical
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Accounting Policies and Estimates in Item 7 as well as Note 2 in Item 8 of the Form 10-K, we periodically review the carrying values of our properties when events or circumstances indicate that the remaining carrying amount may not be recoverable. The intent of the risk factor is to disclose that the carrying value of our properties could be at risk of impairment as a result of commodity price decreases, which would reduce the estimated future cash flows of our properties. We respectfully submit that the risk factor with the proposed revisions and our broader description of our accounting policies appearing elsewhere in the Form 10-K comply with the requirements of FASB ASC paragraph 360-10-35-17.
If commodity prices decrease to a level such that our future undiscounted cash flows from our properties are less than their carrying valuefor a significant period of time, wewillmay be required to take write-downs of the carrying values of our properties.
Accounting rules require that we periodically review the carrying value of our properties for possible impairment. Based on prevailing commodity prices and specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development plans, production data, economics and other factors, we may be required to write-down the carrying value of our properties. A write-down constitutes a non-cash charge to earnings. The current downward trend in oil and natural gas prices may result in impairments of our properties, which could have a material adverse effect on our results of operations for the periods in which such charges are taken.
Properties, page 38
Exploration and Production Segment Properties
Reserve Data, page 39
Reserves Presentation, page 39
| 2. | Your disclosure of reserves throughout Form 10-K appears to be in the form of a single aggregated figure provided solely in terms of a gas equivalent volume. To the extent that reserves relating to individual product types other than natural gas are not separately material pursuant to Item 1202(a)(4) of Regulation S-K, please expand the disclosure in Form 10-K to clarify the reason for limiting your reserves disclosure to the gas equivalent volumes. Alternatively, expand your disclosure to provide the net quantities of your condensate and natural gas liquids as part of your presentation or as footnote disclosure. As part of your expanded disclosure, provide in close proximity to your reserves presentation the basis for converting your condensate and natural gas liquids volumes to equivalent gas volumes (e.g. the number of cubic feet of natural gas per barrel equivalent). Refer to Instruction 3 to Item 1202(a)(2) of Regulation S-K. |
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Response: We acknowledge the Staff’s comment and note that we believe our disclosure of estimated proved reserves is in compliance with Item 1202(a) of Regulation S-K. Our estimated proved reserves of oil and natural gas liquids (“NGLs”) do not represent a material proportion of our total estimated proved reserves. As of December 31, 2015, 2014 and 2013, estimated proved reserves of oil and NGLs represented an aggregate 0.3%, 0.0% and 0.0%, respectively, of our total estimated proved reserves. In calculating our estimated reserves on a natural gas equivalent basis, we use a ratio of 6,000 cubic feet of natural gas to one barrel of crude oil and NGLs. We respectfully submit that the definitions of “Mcfe,” “MMcfe” and “Bcfe” appearing in the Glossary of Oil and Natural Gas Terms, which begins on page 152 of the Form 10-K, explain the calculation of our reserves on a natural gas equivalent basis. We will continue to monitor and evaluate the significance of our oil and NGL estimated proved reserves during each reporting period to determine if separate disclosure is material, and if we determine separate disclosure is not material, we will add a footnote in future filings to the table presenting our total estimated proved reserves that explains the basis for converting our oil and NGLs reserves into natural gas equivalent reserves and that our oil and NGLs reserves are immaterial.
Proved Undeveloped Reserves, page 41
| 3. | We note your explanation for the revisions of previous estimates in proved undeveloped reserves for the period ending December 31, 2015. If your revisions are related to more than one unrelated cause, for example, changes in your corporate plans to drill certain wells and changes for well performance, please clarify for us and expand your disclosure to provide the net quantities attributable to each separate cause to comply with the disclosure requirements under Item 1203(b) of Regulation S-K. |
Response: We acknowledge the Staff’s comment and advise the Staff that there were two causes for our revisions to our proved undeveloped reserves in 2015. First, we reclassified approximately 370,410 MMcfe for previously booked locations to the probable category as we did not expect to develop these locations within five years of initial booking. Second, we revised our proved undeveloped reserves to reflect 36,423 MMcfe in positive performance revisions resulting from positive well performance. When taken together, these two causes resulted in the 333,987 MMcfe downward net revision we disclosed on page 41 of the Form 10-K. Please also refer to our response to comment 5 for additional clarification for causes of revisions of previous estimates in proved undeveloped reserves for the period ending December 31, 2015. In our future filings, we will provide more detailed explanations regarding the causes for our revisions of previous estimates of proved undeveloped reserves.
| 4. | Please tell us and expand your disclosure to explain why there appears to be a significant difference between the net quantities added by extensions and discoveries during 2015 relating to proved undeveloped reserves compared to such changes relating to total proved reserves provided elsewhere on page 123. |
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Response: We acknowledge the Staff’s comment and note extensions of 514,932 MMcfe relating to proved undeveloped reserves compared to extensions of 869,038 MMcfe relating to total proved reserves as of December 31, 2015. The primary reason for the significant difference between these net quantities is due to our developing reserves in the Utica Shale in Belmont County, Ohio as well as the Marcellus Shale in Washington County, Pennsylvania in 2015 that were previously considered probable locations. We will continue to enhance disclosures around changes in proved undeveloped reserves and total proved reserves in future filings in a manner consistent with the Staff’s comment.
| 5. | You disclose that the significant negative revisions relating to your proved undeveloped reserves for the fiscal year ending December 31, 2015 were largely the result of reclassifying previously booked locations to the probable category as they are no longer expected to be drilled within five years of initial booking. Elsewhere on page 123, you further explain that such revisions were due to changes in the Company’s operation plans. |
Please explain to us the nature and reason for the changes in your plans regarding your previously disclosed proved undeveloped reserves. Furthermore, in light of the magnitude of the change in previously disclosed proved undeveloped reserves, please tell us how you complied with the requirement of reasonable certainty for proved reserves relating to an adopted development plan and schedule as set forth in the definition of undeveloped reserves under Rule 4-10(a)(31)(ii) of Regulation S-K. Also explain to us why your prior reserves disclosure did not represent a “mere intent to develop” such reserves as noted in the answer to Question 131.04 in the Compliance and Disclosure Interpretations (C&DIs), issued October 26, 2009 and updated May 16, 2013. You may find the C&DIs on our website at the following address:
http://www.sec.gov/divisions/corpfin/guidance/oilandgas-interp.htm.
Response: We acknowledge the Staff’s comment and respectfully submit that we record proved undeveloped reserves when all the requirements of Rule 4-10 of Regulation S-X have been met. Annually, in the fourth quarter, we prepare our capital expenditure budget for the subsequent year. As part of the annual budget process, we analyze various factors, including the nature of the wells and well economics, anticipated drilling schedule, current and projected commodity prices, acreage position, proximity to infrastructure, lease terms, midstream requirements for anticipated throughput, and the process involved in proving up reserves in undeveloped or new acreage. Based on this analysis and our financial capacity, we determine the number of wells that we plan to drill on operated assets for the subsequent year based on the then available data points. Further, we evaluate a multi-year outlook for developing our operated assets. We then incorporate the selected undeveloped locations (both proved and probable) into our budget and business plan. For assets operated by others, we work with the operator to determine a drilling schedule for the following year and the five-year plan with respect to the undeveloped locations determined by the operator. Based on these short-term and long-term
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considerations, we record proved undeveloped reserves only after a plan has been approved to complete the associated development drilling within five years of initial booking. This process is intended to ensure that proved undeveloped reserves are only claimed for locations where a final investment decision has been made either by the Company (in the case of operated acreage) or by the operator (in the case of non-operated acreage).
With respect to the guidance provided by the Commission in response to question 131.04 of the Commission’s Compliance and Disclosure Interpretations (“C&DIs”), we respectfully submit that the proved undeveloped reserves previously claimed were not claimed based on a “mere intent to develop” with respect to such reserves, but were a part of an approved development plan to develop those reserves. However, after a development plan has been adopted, we periodically make adjustments to the approved development plan due to events or circumstances that have occurred subsequent to the time the plan was approved. In this case, in light of the recent downturn in commodity prices among other reasons, we adjusted the development plan to focus more on developing contiguous acreage within our core areas of development. Adding contiguous acreage in 2015 has allowed us to optimize our returns on investment through planned development of a greater number of highest returning, longer laterals from fewer pad drilling sites compared to other locations previously booked as proved undeveloped reserves. While we adopted a development plan that satisfied the requirements of a “final investment decision” as noted in Question 131.04 in the above referenced C&DIs, we reevaluated the development plan in the fourth quarter of 2015 for the reasons described above.
In future filings, we will disclose in greater detail the reasons for reclassifying previously booked proved undeveloped locations to the probable category.
| 6. | Tell us when the 334 MMcfe of proved undeveloped reserves that were reclassified to the probable category during 2015 were initially booked as proved reserves. Additionally, tell us the economic, operational or other factors that resulted in the deferral and reclassification of these quantities and explain how these factors compare with those related to new proved undeveloped locations booked during 2015. To the extent that locations were deferred for different reasons, provide separate discussion for each location or group of similar locations. |
Response: We acknowledge the Staff’s comment. Of the total 370,410 MMcfe of proved undeveloped reserves that we reclassified to the probable category in 2015, 220,045 MMcfe were initially booked as proved reserves in 2013, with the remaining 150,365 MMcfe initially booked as proved reserves in 2014. We reclassified these locations to the probable category in connection with adjusting our approved development plan as discussed in greater detail in response to comment 5 above. Additionally, we revised our proved undeveloped reserves to reflect 36,423 MMcfe in positive performance revisions resulting from positive well performance. When taken together, these two causes resulted in the 333,987 MMcfe downward net revision we disclosed in the table on page 41 of the
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Form 10-K. We also note that the last paragraph on page 41 of the Form 10-K contains a typographical error in that the reference to “334 MMcfe” should have been “334 Bcfe” or “333,987 MMcfe.”
Determination of Drilling Locations, page 43
| 7. | Expand your disclosure or provide a cross-reference to disclosure such as presented on page 6 in footnote (1) to clarify “The drilling locations on which we actually drill will depend on the availability of capital, regulatory approval, commodity prices, costs, actual drilling results and other factors. Please see Item 1A. Risk Factors—Risks Related to Our Business—Our drilling locations are scheduled out over many years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling. In addition, we may not be able to raise the substantial amount of capital that would be necessary to drill our drilling locations.” |
Response: We acknowledges the Staff’s comment and will revise this section in future filings to include the cross reference to address the Staff’s comment.
Production, Revenues and Price History, page 43
| 8. | Please expand your presentation to disclose the production, by final product sold, for each field that contains 15% or more of the Company’s total proved reserves. Refer to the disclosure requirements under Item 1204(a) of Regulation S-K. |
Response: We acknowledge the Staff’s comment and respectfully submit that the production, revenues and price history information appearing on page 44 of the Form 10-K is presented for our operations in the Appalachian Basin, which is the only geographic area that contains 15% or more of our total proved reserves. We interpret Item 1204(a) of Regulation S-K and the adopting release (SEC Release No. 33-8995) to require disclosure of this information for any basin that exceeds the 15% threshold, and based upon our review of other disclosures by similarly situated companies, it appears that a number of other reporting companies may have made this same interpretation. In our future filings, however, we will revise the paragraph appearing before the table with this information to clarify that such information is presented for our operations in the Appalachian Basin.
| 9. | Please revise your presentation to disclose the figures for production and the average sales price by final product sold of condensate and natural gas liquids to comply with Items 1204(a) and 1204(b)(1) of Regulation S-K |
Response: We acknowledge the Staff’s comment and note that we believe our disclosure of production and average sales price is in compliance with Items 1204(a) and 1204(b)(1). We respectfully submit that aggregated figures for production and average sales price for oil and NGL sales for the years ended December 31, 2015, 2014 and 2013 are included on the table on page 44 of the Form 10-K. Our NGL production does not represent a material proportion of our revenues. For the years ended December 31, 2015,
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2014 and 2013, production of NGLs represented less than 0.5% of our total revenues. We will continue to monitor and evaluate the significance of our NGL production each reporting period to determine if separate disclosure is required under Item 1204(a) and 1204(b)(1) of Regulation S-K, and if we determine separate disclosure is not required, we will add a footnote in future filings to the production table stating that our NGL revenues are immaterial. To the extent that oil and NGLs represent more than an immaterial amount of our hydrocarbon production in a future reporting period, we will disaggregate this information in the future filing for such period between the product types and will separately present the production and average sales price figures for oil and NGL sales.
Management’s Discussion and Analysis of Financial Condition and Results of Operations, page 52
Critical Accounting Policies and Estimates, page 70
Natural Gas Properties, page 71
| 10. | You indicate that the carrying values of your proved properties are evaluated for impairment at the formation level. Explain to us, in reasonable detail, how this policy is applied, including how you determine the formation level. Additionally, explain to us how this policy is consistent with the requirement to group assets at the lowest level for which identifiable cash flows are largely independent of the cash flows of other assets and liabilities. See FASB ASC paragraph 360-10-35-23. |
Response: We acknowledge the Staff’s comment regarding our statement in the Form 10-K that we evaluate proved properties for recoverability at the formation level. The formation level is determined to be the targeted strata, or formation, for which a leasehold is intended to be developed. Given our condensed operational footprint, the identification of the formation from which we produce hydrocarbons results in discrete geographical groupings. Our Marcellus and Upper Devonian operations are limited to two adjoining counties in Pennsylvania, and our Utica operations are limited to a single county in Ohio. As a result of this operational footprint, identifiable cash flows (both inflows and outflows) are largely discrete for each formation. Therefore, our asset groupings for purposes of ASC 360-10-35-23 are the Marcellus, Utica and Upper Devonian formations and we performed separate recoverability analyses for each of these formations during fiscal 2015.
Our reserves within each formation consist of highly contiguous, centralized acreage with independently consistent production profiles and estimated ultimate recoveries of hydrocarbons analogous by respective formation. The most significant costs associated with the development and production of our assets include development costs, gas gathering and compression costs, and lease operating costs. Such types of costs are primarily managed and negotiated at the formation level. The costs to develop and operate each respective formation are inter-dependent of one another. Our development costs are the most significant individual cost to develop our asset base; the Company’s
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2015 development program consisted of operating one horizontal rig and one well stimulation team in each respective formation. Furthermore, gathering and compression is primarily provided by one provider at a fixed rate by volumes produced in each respective formation. Lease operating costs and other operational costs are shared at the formation level to produce hydrocarbons from each formation, and are largely inclusive of services provided based on terms negotiated at the formation level with certain service providers. There are differing state governmental agencies overseeing our operations, including taxing authorities and environmental regulatory authorities, and we are subject to differing severance taxes and environmental compliance standards dependent on the geographical location of the producing formation. Based on these facts and circumstances, we treat each formation as the lowest level for which identifiable cash flows are largely independent of the cash flows of other assets and liabilities.
| 11. | Provide us a reasonably detailed summary of the cash flow analysis that supports your assessment that the undiscounted future cash flows of your Marcellus and Utica proved properties exceeded their carrying values in excess of 50%. As part of your response, clarify the level at which cash flows were determined and compared to carrying values. Additionally, describe all material assumptions as to prices, costs and quantities and explain your basis for all assumptions made. To the extent that quantities other than proved reserves were considered, explain whether and how such quantities were risk adjusted. |
Response: We acknowledge the Staff’s comment. For purposes of the December 31, 2015 proved properties impairment test, we provided our independent reserves consultant, Netherland, Sewell & Associates, Inc. (“NSAI”), with strip pricing assumptions based on publicly available strip pricing curves, adjusted for basis, as of the date of the test and held flat after the third year. NSAI applied these strip pricing assumptions to our existing SEC reserves report to formulate updated undiscounted cash flows at strip pricing while leveraging other determined assumptions used in the SEC reserves report, such as reservoir decline curves, gathering and compression costs, transportation expenses, and estimated capital expenditures based on our cost experience which is consistent with our historical results. Consideration was also given to ensure that material cost elements appropriately reflected our best estimate of future costs and align with the pricing assumptions used in the undiscounted cash flow analysis. The updated undiscounted cash flows were summarized by formation as clarified in our response to comment 10 above, and compared to the respective carrying values as of December 31, 2015. The Company did not use any quantities or undiscounted cash flows other than proved reserves in its analysis. Please refer to the following table for a summary of the undiscounted cash flows summarized by formation using strip pricing assumptions compared to respective carrying values as of December 31, 2015, for our Marcellus and Utica proved properties as requested by the Staff.
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| (all $ amounts in 000’s) | ||||||||||||||||
| Undiscounted | ||||||||||||||||
Strata | Cash Flows | Carrying Value | Headroom | Headroom % | ||||||||||||
Marcellus | $ | 1,850,543 | $ | 1,024,750 | $ | 825,793 | 81 | % | ||||||||
Utica | $ | 574,992 | $ | 246,738 | $ | 328,254 | 133 | % | ||||||||
Financial Statements and Supplementary Data, page 78
Notes to Consolidated Financial Statements, page 86
Note 3. Goodwill, page 91
| 12. | You disclose that you recorded an impairment charge of $249.9 million to eliminate the carrying value of the goodwill of the exploration and production reporting unit at December 31, 2015. Describe for us, in reasonable detail, all material assumptions underlying the analysis that resulted in the impairment charge and explain to us how these assumptions compare to the assumptions used in connection with both the purchase price and goodwill allocation at the time of the 2014 Marcellus JV Buy-In and the 2015 asset impairment test. |
Response: We acknowledge the Staff’s comment and note that pricing assumptions, discount rate and terminal growth rate represent the most significant assumptions in estimating the fair value of our Exploration and Production reporting unit. When comparing the assumptions used in connection with the most recent annual goodwill impairment test (“Annual Test”) and the assumptions used in the purchase price and goodwill allocation at the time of the 2014 Marcellus JV Buy-In (“Initial Valuation”), the assumptions that differed materially were the pricing assumptions and discount rate. The terminal growth rate used in the Annual Test and the Initial Valuation were materially consistent. The pricing assumptions used in the Annual Test were as much as forty percent less than those used in the Initial Valuation based on the significant difference in publicly available forward strip pricing curves in December 2015 versus publicly available forward strip pricing curves in January 2014. Additionally, in connection with the general weakness in the capital markets, and in the energy industry, including the relative performance of our peer group as of December 31, 2015, our discount rate used in the Annual Test was approximately three hundred basis points greater than that used in the Initial Valuation. Furthermore, as a component of the Annual Test also considered the guideline public company method under the market approach, the weakness in the energy industry, our peer group, and our own performance resulted in low multiples being utilized in this part of the Annual Test, which were significantly lower than such multiples in 2014. These factors had a significant negative impact on the discounted cash flows of the Exploration and Production reporting unit as part of the Annual Test, which resulted in the goodwill impairment loss recorded at December 31, 2015.
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Notes to Consolidated Financial Statements
Supplemental Information on Gas-Producing Activities (Unaudited), page 122
| 13. | We note your disclosure of reserves and the changes therein is presented as a single aggregated figure provided solely in terms of a gas equivalent volume. Please revise your presentation to separately disclose reserves by individual product type pursuant to the requirements under FASB ASC 932-235-50-4. |
Response: We acknowledge the Staff’s comment and note that our total estimated proved reserves of oil and NGLs do not represent a material proportion of our total estimated proved reserves, as referenced in our response to comment 2 above. As of December 31, 2015, 2014 and 2013, estimated proved reserves of oil and NGLs represented an aggregate 0.3%, 0.0% and 0.0%, respectively, of our total estimated proved reserves. We concluded that separate disclosure of oil and NGL estimated proved reserves was immaterial and would not provide meaningful information to our investors given their relative insignificance. We will continue to monitor and evaluate the significance of our oil and NGL estimated proved reserves during each reporting period to determine if separate disclosure is material, and if we determine separate disclosure is not material, we will add a footnote in future filings to the table in this section of our financial statements stating that our oil and NGL estimated proved reserves are immaterial and clarifying the basis for converting our oil and NGLs reserves into natural gas equivalent reserves.
| 14. | Expand your disclosure of the changes in net quantities of proved reserves for the period ending December 31, 2014 to include an appropriate narrative explanation of the significant changes relating to revisions of previous estimates. Refer to the disclosure requirements under FASB ASC 932-235-50-5. |
Response: We acknowledge the Staff’s comment and will modify the disclosure of the changes in net quantities of proved reserves for the period ending December 31, 2014 in the next Form 10-K filing in a manner consistent with the Staff’s comment.
Form 8-K furnished August 3, 2016
Exhibit 99.1 – Press Release
| 15. | The reconciliation of adjusted net income (loss) provided on page 15 presents various reconciling items net of tax. This is inconsistent with the updated Compliance and Disclosure Interpretations (C&DI) issued on May 17, 2016, in particular C&DI 102.11. Please review this guidance for your future earnings release. |
Response: The Company acknowledges the Staff’s comment and has reviewed the C&DI issued on May 17, 2016, including C&DI 102.11 and will revise its future filings in a manner consistent with the Staff’s comment.
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Once you have had time to review our responses to the Staff’s comments, we would appreciate the opportunity to discuss any additional questions or concerns that you may have. Please feel free to call me at (832) 708-3432. Written correspondence to the Company may be directed to my attention at 333 Clay Street, Suite 4150, Houston, Texas 77002, email Will.Jordan@RiceEnergy.com.
Sincerely, | ||
Rice Energy Inc. | ||
/s/ William E. Jordan | ||
Name: | William E. Jordan | |
Title: | Senior Vice President, General Counsel and Corporate Secretary | |
| cc: | Joseph Klinko, the Commission | |
| John Hodgin, the Commission | ||
| Sean T. Wheeler, Latham & Watkins LLP | ||
William N. Finnegan, IV, Latham & Watkins LLP |
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