2121 Old Gatesburg Road, Suite 110 State College, PA 16803 Main Office: (814) 308-9754 www.eclipseresources.com |
November 19, 2018
VIA EDGAR
Division of Corporation Finance
Office of Natural Resources
U.S. Securities and Exchange Commission
Division of Corporation Finance
100 F Street, N.E.
Washington, D.C. 20549-4628
Attn: | John Hodgin, Petroleum Engineer |
Brad Skinner, Senior Assistant Chief Accountant
Re: | Eclipse Resources Corporation |
Form 10-K for the Fiscal Year Ended December 31, 2017
Filed March 2, 2018
File No. 1-36511
Ladies and Gentlemen:
Set forth below is the response of Eclipse Resources Corporation, a Delaware corporation (the “Company,” “we,” “our” or “us”), to the comments of the staff of the Division of Corporation Finance (the “Staff”) of the Securities and Exchange Commission (the “Commission” or the “SEC”) contained in the letter, dated November 8, 2018, concerning the above referenced filing (the “Annual Report on Form 10-K”). For ease of reference, we have included the text of the Staff’s comments in bold type below, followed by the Company’s responses.
Form 10-K for the Fiscal Year Ended December 31, 2017
Business and Properties
Activity, page 1
1. | Revise the disclosure relating to the gross operated and non-operated wells to separately provide the total gross and total net productive oil wells and gas wells as of a reasonably current date or as of the end of the current fiscal year. Refer to disclosure requirements of Item 1208(a) and the definition of a productive well under Item 1208(c)(3) of Regulation S-K. |
The Company acknowledge the Staff’s comment and respectfully note that the Company’s gross and net productive wells are provided in the Annual Report on Form 10-K. The gross well count is displayed on page 1 under the “Activity” section, and the net locations are noted on page 2 under “Net Undeveloped Locations”. Both of these sections highlight the producing wells in separate columns.
Further, all of the Company’s wells drilled over the past three years are classified as gas wells, which is noted on page 13 of the Annual Report on Form 10-K. The Company’s productive wells are predominantly classified as gas wells; however, the Company does have an economic interest in 1 gross (0.1 net) productive, non-operated oil well. The net production associated with this well represented less than 1% of the Company’s total net production for the fiscal year ended December 31, 2017.
November 19, 2018
Page 2
In response to the Staff’s comment, the Company will include the following additional disclosure table in future filings (as applicable and to the extent then required) and will locate it immediately after the table included on page 1 of the Annual Report on Form 10-K:
Operated Net Wells | Non-Operated Net Wells | |||||||||||||||||||||||||||||||
Type Curve Area | Producing to Sales(1) | Awaiting Turn to Sales | Awaiting Completion/ Completing | Drilling | Producing to Sales(2) | Awaiting Turn to Sales | Awaiting Completion/ Completing | Drilling | ||||||||||||||||||||||||
Dry Gas | 34.7 | — | 1.0 | 1.5 | 2.7 | — | — | — | ||||||||||||||||||||||||
Rich Gas | — | — | — | — | 2.8 | — | — | — | ||||||||||||||||||||||||
Condensate(2) | 55.1 | — | 8.2 | 3.2 | 11.6 | — | — | — | ||||||||||||||||||||||||
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Total Utica Core Area | 89.8 | — | 9.2 | 4.7 | 17.1 | — | — | — | ||||||||||||||||||||||||
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Marcellus Condensate(1) | 0.5 | 2.0 | — | — | 0.2 | — | — | — | ||||||||||||||||||||||||
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Marcellus Area | 0.5 | 2.0 | — | — | 0.2 | — | — | — | ||||||||||||||||||||||||
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Total | 90.3 | 2.0 | 9.2 | 4.7 | 17.3 | — | — | — | ||||||||||||||||||||||||
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(1) | Excludes one Marcellus producing well outside our defined type curve area. |
(2) | All producing wells are classified as gas wells, except 1 gross (0.1 net) Non-Operated producing oil well. |
Proved Undeveloped Reserves (PUDS), page 10
2. | Expand the disclosure relating to your proved undeveloped reserves to explain the reasons why material amounts of the proved undeveloped reserves disclosed as of December 31, 2017 will not be converted to developed status within five years of your initial disclosure of such reserves in a filing made with the United States Securities and Exchange Commission. Refer to Item 1203(d) of Regulation S-K. |
In response to the Staff’s comment, for year-end December 31, 2017 the Company had no material undeveloped reserves that would not convert to proved developed within 5 years of initial disclosure. Further, the Company will include the disclosure below in future filings (as applicable and to the extent then required) to expand upon and explain the reason why material amounts of proved undeveloped reserves will not be converted to developed status within five years.
During the year end December 31, 2017, we converted approximately 90.0 Bcfe, or 52% of our proved undeveloped reserves as of December 31, 2016 to proved developed reserves at a capital cost of approximately $34 million. Estimated future development costs relating to the development of our proved undeveloped reserves as of December 31, 2017 are approximately $835 million over the next five years. All PUD drilling locations are scheduled to be converted to proved developed within five years of initial disclosure, with more than 69% of the future development costs expected to be spent in the next three years.
November 19, 2018
Page 3
The development plan is formulated by our operations department and reviewed by the reserves committee and senior management. This plan is frequently reviewed to ensure all capital is allocated to the wells that have the highest rate of return and optimal development profile within the undrilled well inventory. This process may cause wells that were previously planned to be developed within five years to be rescheduled beyond five years and therefore no longer included as proved undeveloped wells in future filings.
Production and Price History, page 11
3. | Tell us how you considered the requirements with regard to disclosure of production, by final product sold, for individual fields and/or geological formations that contain 15% or more of your total proved reserves. Refer to Item 1204(a) of Regulation S-K and Rule 4-10(a)(15) of Regulation S-X. |
The Company acknowledges the Staff’s comment and respectfully notes that the Company operates exclusively in the Appalachian basin as noted on page 1 of the Annual Report on Form 10-K. The Company’s current properties are located in the Utica Shale and Marcellus Shale fairways in Ohio and Pennsylvania with approximately 99% of the Company’s production coming from the Utica Shale.
In response to the Staff’s comment, the Company will continue to monitor this disclosure and update appropriately if the Company operates in another region or geological area that meets the 15% or more of total proved reserves threshold.
Supplemental Oil and Natural Gas Information (Unaudited)
Reserve Quantity Information, page F-33
4. | Expand the disclosure of proved reserves to additionally provide the net quantities, by individual product type, of proved developed and proved undeveloped reserves at the beginning of the year ended December 31, 2015. Refer to FASB ASC paragraph 932-235-50-4. |
In response to the Staff’s comment, the Company will expand our disclosure to include proved reserves for the beginning of the year ended December 31, 2015 below in future filings (as applicable and to the extent then required). Such proposed disclosure is provided below for reference:
Natural Gas (Bcf) | Natural Gas Liquids (MBbl) | Oil (MBbl) | Total (Bcfe) | |||||||||||||
Proved developed reserves: | ||||||||||||||||
December 31, 2014 | 133.0 | 6,758.6 | 3,880.9 | 196.8 | ||||||||||||
December 31, 2015 | 209.5 | 7,245.7 | 4,239.2 | 278.4 | ||||||||||||
December 31, 2016 | 226.1 | 7,520.0 | 4,439.5 | 297.8 | ||||||||||||
December 31, 2017 | 334.6 | 13,782.9 | 6,449.6 | 456.0 | ||||||||||||
Proved undeveloped reserves: | ||||||||||||||||
December 31, 2014 | 123.4 | 4,120.4 | 1,816.4 | 159.0 | ||||||||||||
December 31, 2015 | 64.5 | 513.0 | 453.9 | 70.3 | ||||||||||||
December 31, 2016 | 160.4 | 1,155.5 | 718.1 | 171.6 | ||||||||||||
December 31, 2017 | 755.5 | 28,147.7 | 13,031.2 | 1,002.6 |
November 19, 2018
Page 4
5. | Expand your disclosure of the changes in total proved reserves to provide an appropriate narrative explanation of the significant changes related to each line item other than production for each period presented. To the extent that two or more unrelated factors are combined to arrive at the line item figure, your disclosure should separately identify and quantify each individual factor that contributed to a significant change so that the change in net reserves between periods is fully explained. Expand the disclosure relating to revisions in the previous estimates of your reserves to identify such factors as changes caused by commodity prices and/or well performance. Refer to FASB ASC 932-235-50-5. |
In response to the Staff’s comment, the Company will include the below disclosure to expand upon changes in total proved reserves year over year in future filings (as applicable and to the extent then required):
2015 Changes in Reserves
• | Extensions, discoveries and other additions of 221.7 Bcfe, which exceeded 2015 production of 75.8 Bcfe. |
• | Negative revisions of 152.9 Bcfe related to a negative revision of 215.2 Bcfe due to reductions in SEC pricing, a positive revision of 22.3 Bcfe due to changes in differentials and positive technical revisions of 40.0 Bcfe. |
2016 Changes in Reserves
• | Extension, discoveries and other additions of 196.1 Bcfe, which exceeded 2016 production of 83.7 Bcfe. |
• | Positive revisions of 14.8 Bcfe related to a negative revision of 50.8 Bcfe due to reductions in SEC pricing, a negative revision of 17.9 Bcfe due to changes in differentials, and a positive technical revision of 83.5 Bcfe. |
• | 4.1 Bcfe related to acquiring proved developed and proved undeveloped leasehold acreage in the Utica Shale. |
• | 10.7 Bcfe related to divesting proved developed and proved undeveloped leasehold acreage in the Utica Shale. |
November 19, 2018
Page 5
2017 Changes in Reserves
• | Extension, discoveries and other additions of 405.1 Bcfe, which exceeded 2017 production of 113.4 Bcfe. |
• | Positive revisions of 695.6 Bcfe related to a positive revision of 607.2 Bcfe due to improvements in SEC pricing, a positive revision of 61.4 Bcfe due to changes in differentials, and a positive technical revision of 69.6 Bcfe offset by a negative revision of 42.6 Bcfe due to changes in the Company’s development plan. |
Exhibits
6. | With respect to Exhibit 99.1, provide us with a reconciliation of the expenses for firm transportation disclosed on page 62 and such costs included in the determination of economic producibility of the proved reserves disclosed in Exhibit 99.1 as of December 31, 2017. To the extent that there are material differences in such costs, provide us with a reasonably detailed explanation for the difference(s). Refer to Rule 4-10(a)(10) of Regulation S-X and FASB ASC 932-235-10. |
In response to the Staff’s comment, the cost assumptions used in the Company’s proved reserve report, included as Exhibit 99.1 to the Annual Report on Form 10-K, are based on the 12-month historical average results adjusted for any significant future contractual arrangements. The 12-month historical average firm transportation costs are derived from the Company’s internal accounting records, consistent with the costs outlined on page 62 of the Annual Report on Form 10-K.
The Company’s proved reserve report projects firm transportation costs by type curve groupings. These type curve groupings share common cost structures, gathering systems, contractual rates and market outlets. Further, the Company computes the firm transportation costs for its non-operated properties by operator and type curve grouping. The firm transportation costs outlined on page 62 of the Annual Report on Form 10-K are based on the Company’s consolidated operations. Below is a reconciliation of the Company’s firm transportation expenses of the significant type groupings from the Company’s financial statements to the assumptions in the 2017 proved reserves report illustrated in Exhibit 99.1 to the Annual Report on Form 10-K.
Firm Transportation ($/Mcfe) Analysis | ||||
Type Curve Grouping | Reserve Report Forecast ($/Mcfe) | % of 2017 Actual Production | ||
Eclipse Dry Gas | $0.49 | 49% | ||
Eclipse Wet Gas | $0.19 | 41% |
Reserve Forecast Weighted Avg Firm Transportation (% of Production in $/Mcfe) | $ | 0.32 | ||||||
Firm Transportation ($/Mcfe) per 10K (Page 62) | $ | 0.34 | ||||||
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Difference | ($ | 0.02 | ) |
November 19, 2018
Page 6
The $0.02 difference between the weighted average firm transportation expense from reserve report and the firm transportation located on page 62 of the Annual Report on Form 10-K relates to non-operated production which make up approximately 10% of our 2017 production. Our non-operated properties have various cost structures and firm transportation expenses.
November 19, 2018
Page 7
*****
Please do not hesitate to contact me by telephone at (814) 308-9754 with any questions or comments regarding this correspondence.
Regards, |
/s/ Benjamin W. Hulburt |
Benjamin W. Hulburt |
Chairman, President and Chief Executive Officer |
Eclipse Resources Corporation |