June 29, 2018
VIA EDGAR
United States Securities and Exchange Commission
The Division of Corporate Finance
Mail Stop 4628
100 F Street, N.E.
Washington, D.C. 20549-3561
| Attn: | Brad Skinner |
| Joseph Klinko |
| Re: | Viper Energy Partners LP |
| Form 10-K for the Fiscal Year ended December 31, 2017 |
| Filed February 7, 2018 |
| File No. 001-36505 |
Ladies and Gentlemen:
Set forth below is the response of Viper Energy Partners LP, a Delaware limited partnership (the “Partnership”), to the comment letter of the staff (the “Staff”) of the Securities and Exchange Commission (the “Commission”), dated June 4, 2018 with respect to the Form 10-K for the fiscal year ended December 31, 2017 filed by the Partnership with the Commission on February 7, 2018 (the “Form 10-K”).
For your convenience, we have set forth below the Staff’s comment followed by the Partnership’s response.
Annual Report on Form 10-K for the fiscal year ended December 31, 2017
Consolidated Financial Statements, page F-1
Noted to Consolidated Financial Statements, page F-6
Note 12. Supplemental Information on Oil and Natural Gas Operations (Unaudited), page F-16
| 1. | The disclosure regarding changes in your estimated proved reserves indicates, in part, that negative revisions of 3,921 MBOE in 2017 “were primarily due to changes in type curves” and that negative revisions of 1,968 MBOE in 2016 “were primarily due to |
500 West Texas, Suite 1200, Midland, Texas, tel. (432) 221-7430/viperenergy.com
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| technical revisions”. Describe for us, in reasonable detail, the facts and circumstances surrounding these changes and revisions. As part of your response, provide the following: |
| • | Describe the specific properties and development status of the underlying volumes; |
| • | Indicate when the volumes involved were initially recorded, and describe any upward or downward revisions between the time of initial recording and the revisions described in your disclosure; and, |
| • | Explain your basis for concluding that the factors which resulted in the changes and revisions did not impact any other volumes reported as of December 31, 2017 or December 31, 2016 and that these remaining reported volumes met the definition of proved oil and gas reserves properties contained in Rule 4-20(a)(22) of Regulation S-X. |
Response: The property that accounted for over 95% of the revisions is located in the northwest portion of Midland County, Texas in the Permian Basin and is referred to by the exploration and production companies operating in the area (each, an “Operator” and, collectively, the “Operators”) as Spanish Trail. This property is comprised of approximately 16,500 gross acres and is in the Wolfcamp/Spraberry play that is being actively developed throughout the Midland Basin of West Texas. The Partnership holds a 20.4% average royalty interest in this acreage and does not operate this acreage. Development of this property began with vertical wells being drilled in 2008. In 2012, horizontal wells were first tested and, by 2014, development was predominantly through the use of horizontal wells. Spanish Trail is now one of the more heavily developed properties in the Midland Basin with significant development in the Wolfcamp B and Lower Spraberry benches and additional development in the Wolfcamp A and Middle Spraberry intervals. At year end 2017, the Wolfcamp B and Lower Spraberry benches were approximately 75% developed while the Wolfcamp A and Middle Spraberry were less than 25% developed on the property. Additionally, there are other intervals that have been tested in adjacent areas that may ultimately be developed on this property.
The mineral interest in the property was acquired by Diamondback Energy, Inc. in 2013 and transferred to the Partnership in 2014. At year end 2013, (a) there were 193 producing vertical wells and 16 producing horizontal wells, (b) proved undeveloped locations included 106 vertical well locations and 24 horizontal well locations and (c) estimated total proved reserves were 10.3 MMBOE. By year end 2017, (a) there were 237 producing vertical wells and 192 producing horizontal wells, (b) 53 proved undeveloped horizontal well locations and (c) estimated proved reserves totaled 29.3 MMBOE. Prior to 2016, revisions to estimated proved reserves were predominantly associated with removing vertical proved undeveloped well locations. Many of the vertical proved undeveloped locations were booked prior to horizontal development being tested or after successful horizontal testing while it was believed that combined vertical and horizontal development was feasible. The reason for this belief was that the
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June 29, 2018
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vertical productive interval covered over 2,000 feet and the initial horizontal development was only targeting a 200 to 300 foot interval. As more benches or intervals were successfully tested horizontally, it became apparent that multiple bench horizontal development would recover significantly more reserves than vertical development and at a lower development cost per barrel.
Beginning in 2016, some wells began to underperform in comparison to their prior projections. Part of the underperformance was due to development of the Lower Spraberry bench at reduced inter-well spacing. While the initial testing by one of the Operators at the reduced spacing initially appeared successful (with early performance matching that of wider spaced wells), over time it became evident that the reduced inter-well spacing was resulting in reduced per well recoveries. As a result, at year end 2016, the estimates for wells which were performing below the prior forecasts were reduced resulting in the stated revisions. Based on the well performance observations, the Operator made changes to its development strategy to widen the inter-well spacing and change its hydraulic fracture stimulation design. As development continued and expanded to other benches, it became evident that in some instances there was a degree of vertical communication between some of the benches that was greater than anticipated. Additionally, we observed that there was a greater decrease in the performance of an offset well the longer an Operator waited to drill such offset. As a result of this, in 2017 the reserve levels per well for proved undeveloped well locations were reduced and b-factor adjustments were made to some producing wells to account for these effects.
The Spanish Trail property accounted for 77 percent of the Partnership’s total proved reserves and 92 percent of the Partnership’s proved undeveloped at year end 2017. The other properties in the Partnership’s portfolio are generally in earlier stages of development. Combined, these other properties had 364 producing horizontal wells on 231,000 gross acres and only 47 proved undeveloped horizontal locations were included at year end. While each property and its associated wells will have varying performance characteristics, the Partnership believes that it has reasonably accounted for the reserves in these other properties by incorporating the performance results experienced on the Spanish Trail property.
If you have any questions with respect to the foregoing, please do not hesitate to call me at (405) 463-6900 or Seth R. Molay, P.C. of Akin Gump Strauss Hauer & Feld LLP at (214) 969-4780.
Sincerely,
/s/ Teresa L. Dick
Teresa L. Dick
Chief Financial Officer
Executive Vice President and Assistant Secretary
| cc: | Seth R. Molay, P.C. |
| Akin Gump Strauss Hauer & Feld LLP |