VOC Energy Trust - FORM 10-K - EX-99.1 - March 16, 2021

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EX-32.1 - EX32.1 - VOC Energy Trusttm211026d1_ex32-1.htm
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Exhibit 99.1​
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February 18, 2021
​ Bank of New York Mellon Trust Company, N.A. as    Trustee of VOC Energy Trust ​ ​ ​ ​
​ Attn: Elaina C. Rodgers
   601 Travis Street, Floor
   Houston, Texas 77002 		​ ​ ​ ​
​ Re: ​ ​ Evaluation Summary
VOC Energy Trust Net Profits Interests
Total Proved Reserves
Certain Properties in Kansas & Texas
As of December 31, 2020 		​ ​
Pursuant to the Guidelines of the
Securities and Exchange Commission for
Reporting Corporate Reserves and
Future Net Revenue
​
Dear Ms. Rodgers:
As requested, this report was prepared on February 15, 2021 for VOC Energy Trust (“Trust”) for the purpose of submitting our estimates of total proved reserves and forecasts of economics attributable to the Trust term net profits interests. We evaluated 100% of the reserves associated with the Trust, which are made up of various oil and gas properties in Kansas and Texas. This evaluation, effective December 31, 2020, was prepared using constant prices and costs, and conforms to Item 1202(a)(8) of Regulation S-K and other rules of the Securities and Exchange Commission (SEC). A composite summary of the proved reserves is presented below.
​ ​ ​ ​ ​ ​
Proved
Developed
Producing
​ ​
Proved
Developed
Non-Producing
​ ​
Proved
Undeveloped
​ ​
Total
Proved
​
Net Reserves ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Oil
​ ​ −MBBL ​ ​ ​ ​ 2,292.1 ​ ​ ​ ​ ​ 143.7 ​ ​ ​ ​ ​ 587.6 ​ ​ ​ ​ ​ 3.023.2 ​ ​
Gas
​ ​ −MMCF ​ ​ ​ ​ 1,566.8 ​ ​ ​ ​ ​ 67.5 ​ ​ ​ ​ ​ 368.9 ​ ​ ​ ​ ​ 2,003.2 ​ ​
NGL
​ ​ −MBBL ​ ​ ​ ​ 69.9 ​ ​ ​ ​ ​ 10.1 ​ ​ ​ ​ ​ 55.3 ​ ​ ​ ​ ​ 135.4 ​ ​
Revenue ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Oil
​ ​ −M$ ​ ​ ​ ​ 83,143.6 ​ ​ ​ ​ ​ 5,374.9 ​ ​ ​ ​ ​ 21,778.6 ​ ​ ​ ​ ​ 110,297.1 ​ ​
Gas
​ ​ −M$ ​ ​ ​ ​ 1,729.7 ​ ​ ​ ​ ​ 32.7 ​ ​ ​ ​ ​ 178.9 ​ ​ ​ ​ ​ 1,941.3 ​ ​
NGL
​ ​ −M$ ​ ​ ​ ​ 830.3 ​ ​ ​ ​ ​ 120.1 ​ ​ ​ ​ ​ 656.9 ​ ​ ​ ​ ​ 1,607.4 ​ ​
Severance Taxes
​ ​ −M$ ​ ​ ​ ​ 2,743.5 ​ ​ ​ ​ ​ 258.0 ​ ​ ​ ​ ​ 937.2 ​ ​ ​ ​ ​ 3,938.8 ​ ​
Ad Valorem Taxes
​ ​ −M$ ​ ​ ​ ​ 2,461.5 ​ ​ ​ ​ ​ 190.3 ​ ​ ​ ​ ​ 731.9 ​ ​ ​ ​ ​ 3,383.7 ​ ​
Operating Expenses
​ ​ −M$ ​ ​ ​ ​ 42,069.9 ​ ​ ​ ​ ​ 292.9 ​ ​ ​ ​ ​ 1,220.3 ​ ​ ​ ​ ​ 43,583.1 ​ ​
Workover Expenses
​ ​ −M$ ​ ​ ​ ​ 4,846.6 ​ ​ ​ ​ ​ 0.0 ​ ​ ​ ​ ​ 0.0 ​ ​ ​ ​ ​ 4,846.6 ​ ​
COPAS
​ ​ −M$ ​ ​ ​ ​ 6,006.3 ​ ​ ​ ​ ​ 108.8 ​ ​ ​ ​ ​ 344.9 ​ ​ ​ ​ ​ 6,460.0 ​ ​
Other Deductions
​ ​ −M$ ​ ​ ​ ​ 569.6 ​ ​ ​ ​ ​ 291.6 ​ ​ ​ ​ ​ 1,009.1 ​ ​ ​ ​ ​ 1,870.3 ​ ​
Investments
​ ​ −M$ ​ ​ ​ ​ 277.2 ​ ​ ​ ​ ​ 2,132.9 ​ ​ ​ ​ ​ 12,735.0 ​ ​ ​ ​ ​ 15,145.1 ​ ​
80% NPI Net Cash Flow (BFIT)
​ ​
−M$
​ ​ ​
​
21,383.3
 ​ ​ ​ ​
​
1,802.5
 ​ ​ ​ ​
​
4,508.8
 ​ ​ ​ ​ ​ 27,694.6 ​ ​
80% NPI Disc. @ 10% (Present Worth)
​ ​
−M$
​ ​ ​
​
15,363.9
 ​ ​ ​ ​
​
952.9
 ​ ​ ​ ​
​
1,163.3
 ​ ​ ​ ​
​
17,480.0
 ​ ​
 
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Future revenue was calculated prior to deducting state production taxes and ad valorem taxes; however, future net cash flow was calculated after deducting these taxes, future capital costs and operating expenses, but before federal income taxes. Future net cash flow has been discounted at an annual rate of ten (10) percent, in accordance with SEC guidelines, to determine net present worth. Present worth indicates the time value of money and should not be construed as being fair market value.
The oil reserves include oil and condensate. Oil and natural gas liquid (“NGL”) volumes are expressed in barrels (42 U.S. gallons). Gas volumes are expressed in thousands of standard cubic feet (“MCF”) at contract temperature and pressure base. Barrels of oil equivalent (“BOE”) is expressed as oil and NGL volumes in barrels plus gas volumes in Mcf divided by six (6) to convert to barrels. Our estimates include proved reserves only. Neither probable or possible reserves, nor interest in acreage beyond the location of proven reserves have been estimated.
Proved Developed reserves are the summation of the Proved Developed Producing and Proved Developed Non-Producing reserve estimates. Proved Developed reserves were estimated at 2,435.8 Mbbl oil, 1,634.3 MMcf gas and 80.0 Mbbl NGLs (or 2,788.2 MBOE). Of the Proved Developed reserves, 2,623.1 MBOE were attributed to producing zones in existing wells and 165.1 MBOE were attributed to zones in existing wells not producing.
Net Profits Calculations
The net profits interests entitle the Trust to receive 80% of the net proceeds from the sale of hydrocarbon production within the Companies’ underlying properties. The net profits interests will terminate on the later to occur (1) December 31, 2030, or (2) the time when 10.6 million barrels of oil equivalent (“MMBOE”) have been produced from the underlying properties and sold, and the trust will soon thereafter wind up its affairs and terminate. For this report, it was estimated that the Trust would terminate September 30, 2031 based on the calculation that 10.6 MMBOE would be produced from the underlying properties and sold (which amount is the equivalent of 8.5 MMBOE in respect of the trust’s right to receive 80% of the net proceeds from the underlying properties pursuant to the net profits interest) by that date. The cash flow tables in this report reflect the termination date of September 30, 2031.
Hydrocarbon Pricing
The base SEC oil and gas prices calculated for December 31, 2020 were $39.57/bbl and $1.985/MMBTU, respectively. As specified by the SEC, a company must use a 12-month average price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period. The base oil price is based upon WTI-Cushing spot prices (EIA) during 2020 and the base gas price is based upon Henry Hub spot prices (Platts Gas Daily) during 2020.
Oil price differentials were forecast at -$4.55 per BBL for all Kansas properties. For Texas properties, oil price differentials were applied at -$2.00 per BBL for the Kurten (Woodbine) Field wells and -$3.75 per BBL for the Sand Flat and Hitts Lake North Fields. Oil price differentials for all other wells in Texas were applied at -$2.00 per BBL. Gas price differentials varied by property as provided. NGL price differentials were applied at 30% of the WTI oil price. These base price differentials may include local basis differentials, transportation, gas shrinkage, gas heating value (BTU content) and/or crude quality and gravity corrections. After these adjustments, the net realized prices over the life of the proved properties was estimated to be $36.48 per BBL for oil, $0.969 per MCF for gas and $11.87 per BBL for NGLs. All economic factors were held constant in accordance with SEC guidelines.
Economic Parameters
Ownership was accepted as furnished and has not been independently confirmed. Oil and gas price differentials, lease operating expenses (LOE), workover expenses and overhead expenses were calculated and prepared by the Companies and reviewed by CG&A for accuracy and completeness. LOE (column 22) and overhead (COPAS, column 26) shown in the tables provided herein were determined at the well level using averages determined from historical lease operating statements. Overhead costs include fixed rate administrative overhead for operated properties. Workover Expenses (column 25) were applied to cover the annual costs for recurring well work and wellbore abandonment. The variable costs consist of fees for water
 
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disposal, gas compression, processing and transportation, and other variable expenses and can be found as Other Deductions (column 27). All economic parameters were held constant (not escalated) throughout the life of these properties.
Capital costs for PDNP and PUD properties include recompletion, drilling and completion costs for both vertical and horizontal wells as provided by the Companies. For certain producing and undeveloped horizontal wells, a capital cost for conversion to rod pump is included. All capital costs were held constant (not escalated) throughout the life of these properties.
For Kansas properties, severance taxes were applied at 4.33 percent of revenue until exemption levels were forecasted to be reached. The severance tax rate was dropped to zero (0) when a rate of six (6) BBL/​day per well was reached, or when gross gas production value reached $87/day per gas well. Severance taxes were forecasted at 4.6 percent of oil revenue and 7.5 percent of gas revenue for properties in Texas. Ad valorem taxes for Kansas properties were applied at 6.0 percent of revenue, but dropped to 2.0 percent as properties qualified for the tax exemption. Kansas oil and gas conservation taxes were included within the severance tax estimates shown herein. Ad valorem taxes were applied at 3.29 percent of revenue (after severance taxes) for Texas properties.
SEC Conformance and Regulations
The reserve classifications and the economic considerations used herein for the SEC pricing scenario conform to the criteria of the SEC as defined in pages three (3) and four (4) of the Appendix. The reserves and economics are predicated on regulatory agency classifications, rules, policies, laws, taxes and royalties currently in effect except as noted herein. The possible effects of changes in legislation or other Federal or State restrictive actions which could affect the reserves and economics have not been considered. However, we do not anticipate nor are we aware of any legislative changes or restrictive regulatory actions that may impact the recovery of reserves.
This evaluation includes 15 PUD locations in various fields throughout Kansas and Texas, nine of which are commercial based on SEC pricing. Each of these drilling locations proposed as part of the Companies’ development plans conforms to the proved undeveloped standards as set forth by the SEC. In our opinion, the Companies have indicated they have intent to complete this development plan within the next five (5) years. Furthermore, the Companies have demonstrated that they have the proper company staffing, financial backing and prior development success to ensure this five (5) year development plan will be fully executed.
Reserve Estimation Methods
The data presented in each Table I is explained in page one (1) of the Appendix. The methods employed in estimating reserves are described in page two (2) of the Appendix. Reserves for proved developed producing wells were estimated using production performance methods for the vast majority of properties. Certain new producing properties with very little production history were forecast using a combination of production performance and analogy to similar production, both of which are considered to provide a relatively high degree of accuracy.
Non-producing reserve estimates, for both developed and undeveloped properties, were forecast using either volumetric or analogy methods, or a combination of both. These methods provide a relatively high degree of accuracy for predicting proved developed non-producing and proved undeveloped reserves for the Companies’ properties, due to the mature nature of their properties targeted for development and an abundance of subsurface control data. The assumptions, data, methods and procedures used herein are appropriate for the purpose served by this report.
General Discussion
The estimates and forecasts were based upon interpretations of data furnished by your office and available from our files. To some extent information from public records has been used to check and/or supplement these data. The basic engineering and geological data were subject to third party reservations and qualifications. Nothing has come to our attention, however, that would cause us to believe that we are not
 
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justified in relying on such data. All estimates represent our best judgment based on the data available at the time of preparation. Due to inherent uncertainties in future production rates, commodity prices and geologic conditions, it should be realized that the reserve estimates, the reserves actually recovered, the revenue derived therefrom and the actual cost incurred could be more or less than the estimated amounts.
An on-site field inspection of the properties has not been performed. The mechanical operation or condition of the wells and their related facilities have not been examined nor have the wells been tested by Cawley, Gillespie & Associates, Inc. Possible environmental liability related to the properties has not been investigated nor considered. The cost of plugging and the salvage value of equipment at abandonment have been included as part of the workover expenses described previously.
Cawley, Gillespie & Associates, Inc. is a Texas Registered Engineering Firm (F-693), made up of independent registered professional engineers and geologists that have provided petroleum consulting services to the oil and gas industry for over 50 years. This evaluation was supervised by W. Todd Brooker, President at Cawley, Gillespie & Associates, Inc. and a State of Texas Licensed Professional Engineer (License #83462). We do not own an interest in the properties or VOC Energy Trust and are not employed on a contingent basis. We have used all methods and procedures that we consider necessary under the circumstances to prepare this report. Our work-papers and related data utilized in the preparation of these estimates are available in our office..
​ ​ ​ ​ Yours very truly, ​
​ ​ ​ ​
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​ ​
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​ ​ ​ ​ W. Todd Brooker, P.E.
Senior Vice President
CAWLEY, GILLESPIE & ASSOCIATES, INC.
Texas Registered Engineering Firm (F-693) 		​
 

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