CLAYTON WILLIAMS ENERGY, INC.
May 24, 2016
H. Roger Schwall
Assistant Director
United States Securities and Exchange Commission
Division of Corporation Finance
100 F Street, N.E.
Washington, D.C. 20549-3561
Re: | Clayton Williams Energy, Inc. |
| Form 10-K for the Fiscal Year Ended December 31, 2015 |
| Filed March 24, 2016 |
| Response letter dated March 24, 2016 |
| File No. 1-10924 |
Ladies and Gentlemen:
Set forth below are the responses of Clayton Williams Energy, Inc. (the “Company”, “we,” “us” or “our”), to comments received from the staff of the Division of Corporation Finance (the “Staff”) of the Securities and Exchange Commission (the “Commission”) by letter dated May 2, 2016, with respect to Form 10-K for the Fiscal Year Ended December 31, 2015, File No. 1-10924, filed with the Commission on March 24, 2016 (the “Form 10-K”).
For your convenience, each response is prefaced by the exact text of the Staff’s corresponding comment in bold, italicized text. All references to page numbers and captions correspond to the Form 10-K unless otherwise specified.
Form 10-K for the Fiscal Year Ended December 31, 2015
Proved Undeveloped Reserves, page 35
Scheduled PUD locations at year-end 2015, page 35
1. Your response to comment 1(i) of our March 21, 2016 teleconference appears to address incurred costs for reserve additions rather than those for development (conversion to proved developed) of proved undeveloped reserves.
On page 36 of your 2015 10-K, the PUD future conversion schedule is: None in 2016/2017; 2018 - $57.3 million and 4,251 MBOE; 2019 - $71.3 million and 5,430 MBOE; and 2020 ¬$7.1 million and 515 MBOE. This appears to have a unit
conversion cost of $(57.3+71.3+7.1) million/(4.25+5.43+.515) MMBOE = $135.7 million/10.2 MMBOE = $13.3/BOE.
Your reported historical costs for PUD conversion are $19.73/BOE on average for the three years 2013-2015 and are $20.59/BOE for 2015. These projected PUD conversion costs do not appear to be supported by incurred cost history.
Please explain the reasons for this lower projected five year unit cost. Given that proved reserves are required to be economically producible “under existing economic conditions”, we would expect these conversion costs to reflect the levels you have incurred. If applicable, please address your treatment of Drilled UnCompleted (“DUC”) wells, e.g. whether they were included with converted PUDs.
RESPONSE: As shown in the table below, our average future PUD conversion cost at year end 2015 of $13.31/BOE is lower than our average historical PUD conversion costs of $19.78/BOE for the three-year period 2013 through 2015 and $20.59/BOE for the year 2015.
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| Capital Costs |
| MBOE |
| Cost/BOE |
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Future PUD conversions at year-end 2015 |
| $ | 135.7 |
| 10,196 |
| $ | 13.31 |
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Actual PUD conversion for the year ended December 31, |
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2015 |
| $ | 45.0 |
| 2,186 |
| $ | 20.59 |
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2014 |
| $ | 46.9 |
| 2,139 |
| $ | 21.93 |
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2013 |
| $ | 25.1 |
| 1,591 |
| $ | 15.78 |
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3 year average |
| $ | 117.0 |
| 5,916 |
| $ | 19.78 |
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Following is a discussion of the factors that impact the comparability of our future PUD conversion costs to our historical PUD conversion costs, by year.
Future PUD conversion costs at year-end 2015:
All of our future PUD conversions at December 31, 2015 are associated with horizontal well locations in the Delaware Basin. The reserves economics for substantially all of these PUD well locations are based on estimated development costs of $5.9 million and estimated proved reserves of 452 MBOE (net to 100% working interest). This current estimate for development costs is significantly lower than estimated development costs attributable to comparable PUD locations at year-end 2014 due to a substantial reduction in both worldwide and Delaware Basin specific demand for drilling and completion services resulting from the downturn in commodity prices since 2014. This sharp decrease in demand has created a significant decrease in all service
and equipment prices. In addition, year end 2014 PUD locations included PUD locations in the historically more expensive Eagle Ford as described in more detail below.
In determining the current estimate for development costs for our Delaware Basin PUD locations, we obtained bids from service providers and material suppliers for specific line items on the Authority for Expenditure (AFE) representing a substantial portion of the total AFE cost to drill our model horizontal Wolfcamp well in the Delaware Basin. Based on data provided by these bids, as well as data points obtained by observing historical cost trends on less significant AFE line items, we arrived at the current development cost estimate of $5.9 million, representing a 30% reduction from the prior year estimate of $8.5 million, and concluded that such reduction was both reasonable and consistent with general cost trends experienced within the industry. As further substantiation of the reasonableness of our current estimate of development costs, we are in the process of completing our first Delaware Basin well drilled during 2016 based on our PUD model, and, based on field estimates to date; we believe total development costs of that well will be less than $5.9 million. Accordingly, we believe these cost estimates meet the requirements of “existing economic conditions” for our PUD reserves as of December 31, 2015.
Year Ended December 31, 2015:
In 2015, our historical PUD development costs consisted of the cost of drilling and completing six Eagle Ford wells with average development costs of $28.51/BOE and drilling three Delaware Basin horizontal wells with average development costs of $10.90/BOE. In order to compare our historical 2015 conversion costs to our future estimated conversion costs, we must eliminate the effects of the Eagle Ford PUD development since none of our PUD reserves at year-end 2015 are attributable to Eagle Ford locations. The Delaware Basin historical development cost for 2015 of $10.90/BOE is lower than the $13.31/BOE estimated future development cost included in the December 31, 2015 reserve report primarily because all three of the 2015 Delaware Basin PUD wells were drilled in 2014 but completed in 2015, and only completion costs were included as future development costs at December 31, 2014. Had future development costs for these PUD wells included all development costs through completion, based on then-estimated development costs of $8.5 million and proved reserves of 436 MBOE (net to 100% working interest), the cost to develop Delaware basin PUDs completed in 2015 would have been $19.50/BOE. As adjusted, this prior conversion cost is higher than the current estimate of $13.31/BOE due primarily to a 30% reduction in estimated development costs ($8.5 million versus $5.9 million).
Year Ended December 31, 2014:
Our historical PUD conversions during 2014 consisted of five Delaware Basin horizontal wells with average development costs of $20.45/BOE and two Eagle Ford wells with average development costs of $28.29/BOE. Excluding the Eagle Ford locations for the reasons discussed above, the Delaware Basin historical development cost for 2014 of $20.45/BOE is higher than the current estimate of $13.31/BOE due primarily to the cost reductions discussed above.
Year Ended December 31, 2013:
Our historical PUD conversions during 2013 related primarily to vertical wells in the Permian Basin (Delaware Basin and Andrews County, Texas). None of these PUD conversions are relevant to our estimated future conversion costs since all of our PUD reserves at year-end 2015 related to horizontal wells in the Delaware Basin.
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If you have any questions with respect to the foregoing or if you need any additional supplemental information, please contact James M. Prince of Vinson & Elkins L.L.P. at (713) 758-3710.
| Very truly yours, | ||
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| CLAYTON WILLIAMS ENERGY, INC. | ||
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| By: | /s/ Michael L. Pollard | |
| Name: | Michael L. Pollard | |
| Title: | Senior Vice President &Chief Financial Officer | |
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cc: | James M. Prince |
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| Vinson & Elkins L.L.P. |
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