November 21, 2019
VIA EDGAR
Mr. Ethan Horowitz
Branch Chief, Office of Energy and Transportation
Division of Corporate Finance
Securities and Exchange Commission
100 F Street, N.E.
Washington, D.C. 20549-4628
| Re: | Energy 11, L.P. |
Form 10-K for the Fiscal Year Ended December 31, 2018 Filed March 12, 2019 File No. 000-55615 |
Dear Mr. Horowitz:
This letter is being submitted on behalf of Energy 11, L.P. (the “Partnership”) in response to your letter dated November 7, 2019. We have recited the comments in this letter in bold type and have followed each comment with the Partnership’s response.
Form 10-K for the Fiscal Year Ended December 31, 2018
Notes to Consolidated Financial Statements
Supplementary Information on Oil, Natural Gas and Natural Gas Liquid Reserves (Unaudited)
Estimated Quantities of Proved Oil, NGL and Natural Gas Reserves, page 68
1. | The disclosure provided on page 6 related to the Partnership’s drilling activity indicates six new wells were drilled in October and November 2017 with costs incurred of approximately $1.3 million in the year ended December 31, 2017. The disclosure also indicates two of these wells were completed in March 2018 and the remaining four wells were completed in April, June and July of 2018 with costs incurred of approximately $6.5 million in the year ended December 31, 2018. As 83% of the total cost of drilling and completing these wells was not incurred until 2018, tell us why you considered the proved undeveloped reserves attributable to these six wells to be converted to proved developed status during 2017. Refer to Rule 4-10(a)(6) of Regulation S-X. |
Response: As a non-operator of the wells, the Partnership does not have the visibility into the status of completion and the timing of when expenses are billed for a well. Of the six wells in progress at December 31, 2017, the known costs billed to the Partnership by the operators ranged from 7% to 37% of the anticipated total costs to complete the wells. The two wells in which the Partnership had the largest ownership and represented approximately 64% of the estimated total costs began producing in late February and early March 2018. The Partnership believed these two wells had minor amounts of work to be completed at December 31, 2017 based on first production dates, and therefore met the criteria to be defined as proved developed reserves. The reserves for these two wells totaled approximately 330,000 BOE and the reserves for all six wells totaled 519,000 BOE, or 2.4% and 3.8%, respectively, of the Partnership’s total proved developed reserves. The remaining four wells were not significant to the total reserves. The Partnership will provide, as necessary, additional detail regarding its classification of in-process wells between developed and undeveloped proved reserves in future filings.
Exhibits and Financial Statement Schedules
Exhibit 99.1, page 81
2. | Disclosure in the reserve report indicates the Partnership supplied an expense model to be used in the preparation of the reserves and related cash flows in which the operating costs are forecast to scale down from $25,000 per well per month in year one to $7,500 per well per month in year eight and then are held constant at $6,800 per well per month in year fourteen and through the end of the well life. |
Based on the definition of proved reserves in Rule 4-10(a)(22) of Regulation S-X, explain to us why you consider a change in the existing economic conditions and operating methods resulting in a projected reduction in future operating costs to be reasonably certain. As part of your response, provide us with supporting documentation of actual historical cost reductions or contractual arrangements in place as of fiscal year end that achieve the cost reductions shown in your reserve report.
Response: The Partnership developed its operating cost forecast, as summarized in its reserve report, based on historical actual operating costs of its wells. The projected reduction in operating costs are applied based on the age of each individual well. Consistent with the industry, operating costs are a blend of fixed and variable (based on production) expenses, so as wells age and production declines, the variable operating costs decrease over time. Please refer to Exhibit A for a summary of actual operating costs incurred compared to projected operating costs. The Partnership will clarify in future filings that the operating expenses are based on actual costs and the age of each individual well.
Should you have additional questions or comments concerning the responses provided within, please contact me directly at (804) 727-6318.
Sincerely,
/s/ David S. McKenney
David S. McKenney
Chief Financial Officer
Energy 11 GP, LLC
| CC: | Mr. John Hodgin |
| Mr. John Menke, Shearman and Sterling LLP |
Exhibit A
The gross operating expense estimates used in the reserve reports are based upon the age of each well. Please refer to the following table that summarizes the expense model used in the reserve reports of Energy 11, L.P. (the “Partnership”) dated January 1, 2019 and 2018, respectively.
Age of well, based on initial production date | Reserve report gross operating expenses per month |
Well producing 1.5 years or less | $25,000/month for 1.5 years then … |
Well producing between 1.5 and 3.0 years | $20,000/month for 1.5 years then … |
Well producing between 3.0 and 4.0 years | $15,000/month for 1 year then … |
Well producing between 4.0 and 5.0 years | $12,000/month for 1 year then … |
Well producing between 5.0 and 8.0 years | $10,000/month for 3 years then … |
Well producing between 8.0 and 13.0 years | $7,500/month for 5 years then … |
Well producing at least 13.0 years to end of life | $6,800/month until ECL |
The Partnership believes the model described above materially estimates the operating expenses for its wells, as evidenced by the data summarized in the table below. The following information represents a comparison of the actual operating expenses of the Partnership to the estimated operating expenses in the Partnership’s reserve reports for the periods defined below. The Partnership’s actual operating expenses were compiled using monthly joint interest billings (“JIB”) received by the Partnership from its operators. In total, over the course of the three-year period, the variance between the Partnership’s actual operating costs to estimated operating costs in the Partnership’s reserve reports was approximately 6.3%.
Period | Actual net operating expenses | Operating expenses per reserve report | |||||||
| Q1 2016 | $ | 921,066 | $ | 1,048,199 | |||||
Q2 2016 | 1,041,602 | 1,048,199 | |||||||
Q3 2016 | 1,010,491 | 1,012,665 | |||||||
Q4 2016 | 892,370 | 1,000,188 | |||||||
Q1 2017 | 1,724,049 | 1,316,552 | |||||||
Q2 2017 | 1,910,404 | 2,278,158 | |||||||
Q3 2017 | 2,061,323 | 2,123,925 | |||||||
Q4 2017 | 1,851,855 | 2,120,303 | |||||||
Q1 2018 | 1,711,712 | 1,873,815 | |||||||
Q2 2018 | 1,745,333 | 1,863,701 | |||||||
Q3 2018 | 1,655,467 | 1,789,915 | |||||||
Q4 2018 | 1,522,434 | 1,789,915 | |||||||
Total | $ | 18,048,106 | $ | 19,265,535 | |||||
In addition to the Partnership’s analysis of its JIB expenses, Pinnacle Energy Services (“Pinnacle”), the Partnership’s independent petroleum engineer, indicates the Partnership’s expense model is consistent with the historical operational data Pinnacle has compiled in its extensive North Dakota well database. Pinnacle confirmed that its clients with well interests in the Bakken basin of North Dakota have modeled reserve report operating expenses, by individual well, to include fixed and variable components, with variable expenses declining as a well ages and production volumes decrease.
