Attached files
| file | filename |
|---|---|
| 10-K - 10-K - Gulf Coast Ultra Deep Royalty Trust | gultu202010-k.htm |
| EX-32 - EX-32 - Gulf Coast Ultra Deep Royalty Trust | exhibit322020.htm |
| EX-31 - EX-31 - Gulf Coast Ultra Deep Royalty Trust | exhibit312020.htm |
| EX-23 - EX-23 - Gulf Coast Ultra Deep Royalty Trust | exhibit232020.htm |
January 21, 2021 The Bank of New York Mellon Trust Company, N.A. as Trustee Gulf Coast Ultra Deep Royalty Trust 601 Travis Street, 16th Floor Houston, Texas 77002 Ladies and Gentlemen: In accordance with your request, we have estimated the proved reserves and future revenue, as of December 31, 2020, to the Gulf Coast Ultra Deep Royalty Trust (Gulf Coast) overriding royalty interest in the Jeanerette Minerals 1 well located in Bayou Long Field, St. Martin Parish, Louisiana. We completed our evaluation on or about the date of this letter. It is our understanding that the proved reserves estimated in this report constitute all of the proved reserves owned by Gulf Coast. The estimates in this report have been prepared in accordance with the definitions and regulations of the U.S. Securities and Exchange Commission (SEC) and, with the exception of the exclusion of future income taxes, conform to the FASB Accounting Standards Codificati Oil and Gas. Definitions are presented immediately following this letter. This report has been prepared for Gulf Coast's use in filing with the SEC; in our opinion the assumptions, data, methods, and procedures used in the preparation of this report are appropriate for such purpose. We estimate the gross (100 percent) gas reserves and the net gas reserves and future net revenue to the Gulf Coast overriding royalty interest in the Jeanerette Minerals 1 well, as of December 31, 2020, to be: Gas Reserves (MMCF) Future Net Revenue (M$) Gross Present Worth Category (100%) Net Total at 10% Proved Developed Producing 50,344.2 1,522.9 2,206.1 1,807.3 Proved Developed Non-Producing(1) 0.0 0.0 0.0 0.0 Total Proved Developed 50,344.2 1,522.9 2,206.1 1,807.3 (1) There are no proved developed non-producing reserves at the price and cost parameters used in this report. Gas volumes are expressed in millions of cubic feet (MMCF) at standard temperature and pressure bases. This property has never produced commercial volumes of condensate. Reserves categorization conveys the relative degree of certainty; reserves subcategorization is based on development and production status. Our study indicates that as of December 31, 2020, there are no proved undeveloped reserves for this property. As requested, probable and possible reserves that exist for this property have not been included. The estimates of reserves and future revenue included herein have not been adjusted for risk. This report does not include any value that could be attributed to interests in undeveloped acreage. Gross revenue is Gulf Coast's share of the gross (100 percent) revenue from the property prior to any deductions. Future net revenue is after deductions for Gulf Coast's share of production taxes, ad valorem taxes, and post-production operating expenses but before consideration of any income taxes. The future net revenue has been discounted at an annual rate of 10 percent to determine its present worth, which is shown to indicate the effect of time on the value of money. Future net revenue presented in this report, whether discounted or undiscounted, should not be construed as being the fair market value of the property. Exhibit 99
The gas price used in this report is based on the 12-month unweighted arithmetic average of the first-day-of-the- month Henry Hub spot price for each month in the period January through December 2020. The average price of $1.985 per MMBTU is adjusted for energy content and market differentials. The adjusted gas price of $1.952 per MCF is held constant throughout the life of the property. Because Gulf Coast owns no working interest in this property, no operating costs or capital costs would be incurred, except for Gulf Coast's share of the post-production operating costs of $205,201 per month and $0.03 per MCF of gas. However, operating costs and capital costs have been used to confirm economic producibility and determine economic limits for the property. Operating costs are based on operating expense records of Highlander Oil & Gas Assets LLC (Highlander), the operator of the property, and include only direct lease- and field-level costs and Highlander's estimate of the portion of its headquarters general and administrative overhead expenses necessary to operate the property. Capital costs were provided by Highlander and are based on authorizations for expenditure and internal planning budgets. Operating costs and capital costs are not escalated for inflation. Gulf Coast would not incur any costs due to abandonment, nor would it realize any salvage value for the lease and well equipment. For the purposes of this report, we did not perform any field inspection of the property, nor did we examine the mechanical operation or condition of the well and facilities. Since Gulf Coast owns an overriding royalty interest rather than a working interest in this property, it would not incur any costs due to possible environmental liability. We have made no investigation of potential volume and value imbalances resulting from overdelivery or underdelivery to the Gulf Coast overriding royalty interest. Therefore, our estimates of reserves and future revenue do not include adjustments for the settlement of any such imbalances; our projections are based on Gulf Coast receiving its overriding royalty interest share of estimated future gross production. Additionally, we have made no specific investigation of any firm transportation contracts that may be in place for this property; our estimates of future revenue include the effects of such contracts only to the extent that the associated fees are accounted for in the historical lease-level accounting statement. The reserves shown in this report are estimates only and should not be construed as exact quantities. Proved reserves are those quantities of oil and gas which, by analysis of engineering and geoscience data, can be estimated with reasonable certainty to be economically producible; probable and possible reserves are those additional reserves which are sequentially less certain to be recovered than proved reserves. Estimates of reserves may increase or decrease as a result of market conditions, future operations, changes in regulations, or actual reservoir performance. In addition to the primary economic assumptions discussed herein, our estimates are based on certain assumptions including, but not limited to, that the property will be developed consistent with current development plans as provided to us by Highlander, that the property will be operated in a prudent manner, that no governmental regulations or controls will be put in place that would impact the ability of the interest owner to recover the reserves, and that our projections of future production will prove consistent with actual performance. If the reserves are recovered, the revenues therefrom could be more or less than the estimated amounts. Because of governmental policies and uncertainties of supply and demand, the sales rates, prices received for the reserves, and costs incurred by the working interest owners in recovering such reserves may vary from assumptions made while preparing this report. For the purposes of this report, we used technical and economic data including, but not limited to, well logs, geologic maps, seismic data, well test data, production data, historical price and cost information, and property ownership interests. The reserves in this report have been estimated using deterministic methods; these estimates have been prepared in accordance with the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers (SPE Standards). We used standard engineering and geoscience methods, or a combination of methods, including performance analysis, volumetric analysis, analogy, and reservoir modeling, that we considered to be appropriate and necessary to categorize and estimate reserves in accordance with SEC definitions and regulations. As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering and geoscience data; therefore, our conclusions necessarily represent only informed professional judgment.
The data used in our estimates were obtained from Gulf Coast, Highlander, public data sources, and the nonconfidential files of Netherland, Sewell & Associates, Inc. (NSAI) and were accepted as accurate. Supporting work data are on file in our office. We have not examined the titles to the property or independently confirmed the actual degree or type of interest owned. The technical persons primarily responsible for preparing the estimates presented herein meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the SPE Standards. Mr. John R. Cliver, a Licensed Professional Engineer in the State of Texas, has been practicing consulting petroleum engineering at NSAI since 2009 and has over 5 years of prior industry experience. Mr. Shane M. Howell, a Licensed Professional Geoscientist in the State of Texas, has been practicing consulting petroleum geoscience at NSAI since 2005 and has over 7 years of prior industry experience. We are independent petroleum engineers, geologists, geophysicists, and petrophysicists; we do not own an interest in this property nor are we employed on a contingent basis. Sincerely, NETHERLAND, SEWELL & ASSOCIATES, INC. Texas Registered Engineering Firm F-2699 /s/ C.H. (Scott) Rees III By: C.H. (Scott) Rees III, P.E. Chairman and Chief Executive Officer /s/ John R. Cliver /s/ Shane M. Howell By: By: John R. Cliver, P.E. 107216 Shane M. Howell, P.G. 11276 Vice President Vice President Date Signed: January 21, 2021 Date Signed: January 21, 2021 JRC:WKE Please be advised that the digital document you are viewing is provided by Netherland, Sewell & Associates, Inc. (NSAI) as a convenience to our clients. The digital document is intended to be substantively the same as the original signed document maintained by NSAI. The digital document is subject to the parameters, limitations, and conditions stated in the original document. In the event of any differences between the digital document and the original document, the original document shall control and supersede the digital document.
Acquisition of properties. Analogous reservoir Instruction to paragraph (a)(2) Bitumen Condensate Deterministic estimate Developed oil and gas reserves Supplemental definitions from the 2018 Petroleum Resources Management System: Developed Producing Reserves – Expected quantities to be recovered from completion intervals that are open and producing at the effective date of the estimate. Improved recovery Reserves are considered producing only after the improved recovery project is in operation. Developed Non-Producing Reserves – Shut-in and behind-pipe Reserves. Shut-in Reserves are expected to be recovered from (1) completion intervals that are open at the time of the estimate but which have not yet started producing, (2) wells which were shut-in for market conditions or pipeline connections, or (3) wells not capable of production for mechanical reasons. Behind-pipe Reserves are expected to be recovered from zones in existing wells that will require additional completion work or future re-completion before start of production with minor cost to access these reserves. In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well. Development costs.
Development project Development well Economically producible Estimated ultimate recovery (EUR) Exploration costs Exploratory well Extension well Field Oil and gas producing activities (1) (2)
Instruction 1 to paragraph (a)(16)(i) Instruction 2 to paragraph (a)(16)(i): saleable hydrocarbons Possible reserves. Probable reserves.
Probabilistic estimate. Production costs Proved area. Proved oil and gas reserves.
Proved properties. Reasonable certainty. Reliable technology. Reserves. Note to paragraph (a)(26) Excerpted from the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas: 932-235-50-30 A standardized measure of discounted future net cash flows relating to an entity's interests in both of the following shall be disclosed as of the end of the year: a. Proved oil and gas reserves (see paragraphs 932-235-50-3 through 50-11B) b. Oil and gas subject to purchase under long-term supply, purchase, or similar agreements and contracts in which the entity participates in the operation of the properties on which the oil or gas is located or otherwise serves as the producer of those reserves (see paragraph 932-235-50-7). The standardized measure of discounted future net cash flows relating to those two types of interests in reserves may be combined for reporting purposes. 932-235-50-31 All of the following information shall be disclosed in the aggregate and for each geographic area for which reserve quantities are disclosed in accordance with paragraphs 932-235-50-3 through 50-11B: a. Future cash inflows. These shall be computed by applying prices used in estimating the entity's proved oil and gas reserves to the year-end quantities of those reserves. Future price changes shall be considered only to the extent provided by contractual arrangements in existence at year-end. b. Future development and production costs. These costs shall be computed by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions. If estimated development expenditures are significant, they shall be presented separately from estimated production costs. c. Future income tax expenses. These expenses shall be computed by applying the appropriate year-end statutory tax rates, with consideration of future tax rates already legislated, to the future pretax net cash flows relating to the entity's proved oil and gas reserves, less the tax basis of the properties involved. The future income tax expenses shall give effect to tax deductions and tax credits and allowances relating to the entity's proved oil and gas reserves. d. Future net cash flows. These amounts are the result of subtracting future development and production costs and future income tax expenses from future cash inflows.
e. Discount. This amount shall be derived from using a discount rate of 10 percent a year to reflect the timing of the future net cash flows relating to proved oil and gas reserves. f. Standardized measure of discounted future net cash flows. This amount is the future net cash flows less the computed discount. Reservoir. Resources. Service well. Stratigraphic test well. Undeveloped oil and gas reserves. From the SEC's Compliance and Disclosure Interpretations (October 26, 2009): Although several types of projects — such as constructing offshore platforms and development in urban areas, remote locations or environmentally sensitive locations — by their nature customarily take a longer time to develop and therefore often do justify longer time periods, this determination must always take into consideration all of the facts and circumstances. No particular type of project per se justifies a longer time period, and any extension beyond five years should be the exception, and not the rule. Factors that a company should consider in determining whether or not circumstances justify recognizing reserves even though development may extend past five years include, but are not limited to, the following: The company's level of ongoing significant development activities in the area to be developed (for example, drilling only the minimum number of wells necessary to maintain the lease generally would not constitute significant development activities); The company's historical record at completing development of comparable long-term projects; The amount of time in which the company has maintained the leases, or booked the reserves, without significant development activities; The extent to which the company has followed a previously adopted development plan (for example, if a company has changed its development plan several times without taking significant steps to implement any of those plans, recognizing proved undeveloped reserves typically would not be appropriate); and The extent to which delays in development are caused by external factors related to the physical operating environment (for example, restrictions on development on Federal lands, but not obtaining government permits), rather than by internal factors (for example, shifting resources to develop properties with higher priority). Unproved properties.