January 26, 2023      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,  2022, 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 Codification Topic 932, Extractive Activities— 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, 2022, to be:      Gas Reserves (MMCF)  Future Net Revenue (M$)    Gross      Present Worth  Category  (100%)  Net  Total  at 10%            Proved Developed Producing  30,598.6 935.8  5,508.0 4,738.8 Proved Developed Non-Producing  14,482.7 410.5  2,211.3 1,316.5      Total Proved Developed  45,081.3 1,346.3  7,719.3 6,055.3   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, 2022, 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.    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 2022.  The average price of
 $6.357 per MMBTU is adjusted for energy content and market differentials.  The adjusted gas price of $6.588 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 $206,621 per month and $0.068 per MCF of  gas.  Estimated operating costs and capital costs have been used to confirm economic producibility and determine  economic limits for the property.  Operating cost estimates 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 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  investigation of any firm transportation contracts that may be in place for this property; no adjustments have been  made to our estimates of future revenue to account for such contracts.    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            By:       C.H. (Scott) Rees III, P.E.     Executive Chairman               By:   By:     John R. Cliver, P.E. 107216  Shane M. Howell, P.G. 11276   Vice President  Vice President      Date Signed:  January 26, 2023 Date Signed:  January 26, 2023      JRC:WKE
 DEFINITIONS OF OIL AND GAS RESERVES  Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)     Definitions - Page 1 of 6  The following definitions are set forth in U.S. Securities and Exchange Commission (SEC) Regulation S-X Section 210.4-10(a).   Also included is supplemental information from (1) the 2018 Petroleum Resources Management System approved by the Society  of Petroleum Engineers, (2) the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas, and  (3) the SEC's Compliance and Disclosure Interpretations.    (1) Acquisition of properties.  Costs incurred to purchase, lease or otherwise acquire a property, including costs of lease bonuses  and options to purchase or lease properties, the portion of costs applicable to minerals when land including mineral rights is  purchased in fee, brokers' fees, recording fees, legal costs, and other costs incurred in acquiring properties.    (2) Analogous reservoir.  Analogous reservoirs, as used in resources assessments, have similar rock and fluid properties,  reservoir conditions (depth, temperature, and pressure) and drive mechanisms, but are typically at a more advanced stage of  development than the reservoir of interest and thus may provide concepts to assist in the interpretation of more limited data and  estimation of recovery.  When used to support proved reserves, an "analogous reservoir" refers to a reservoir that shares the  following characteristics with the reservoir of interest:    (i) Same geological formation (but not necessarily in pressure communication with the reservoir of interest);  (ii) Same environment of deposition;  (iii) Similar geological structure; and  (iv) Same drive mechanism.    Instruction to paragraph (a)(2): Reservoir properties must, in the aggregate, be no more favorable in the analog than in the  reservoir of interest.    (3) Bitumen.  Bitumen, sometimes referred to as natural bitumen, is petroleum in a solid or semi-solid state in natural deposits  with a viscosity greater than 10,000 centipoise measured at original temperature in the deposit and atmospheric pressure, on a  gas free basis.  In its natural state it usually contains sulfur, metals, and other non-hydrocarbons.    (4) Condensate.  Condensate is a mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature  and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.    (5) Deterministic estimate.  The method of estimating reserves or resources is called deterministic when a single value for each  parameter (from the geoscience, engineering, or economic data) in the reserves calculation is used in the reserves estimation  procedure.    (6) Developed oil and gas reserves.  Developed oil and gas reserves are reserves of any category that can be expected to be  recovered:    (i) Through existing wells with existing equipment and operating methods or in which the cost of the required  equipment is relatively minor compared to the cost of a new well; and  (ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the  extraction is by means not involving a well.  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.      (7) Development costs.  Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating,  gathering and storing the oil and gas.  More specifically, development costs, including depreciation and applicable operating  costs of support equipment and facilities and other costs of development activities, are costs incurred to:    (i) Gain access to and prepare well locations for drilling, including surveying well locations for the purpose of  determining specific development drilling sites, clearing ground, draining, road building, and relocating public  roads, gas lines, and power lines, to the extent necessary in developing the proved reserves.  (ii) Drill and equip development wells, development-type stratigraphic test wells, and service wells, including the costs  of platforms and of well equipment such as casing, tubing, pumping equipment, and the wellhead assembly.
 DEFINITIONS OF OIL AND GAS RESERVES  Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)     Definitions - Page 2 of 6  (iii) Acquire, construct, and install production facilities such as lease flow lines, separators, treaters, heaters, manifolds,  measuring devices, and production storage tanks, natural gas cycling and processing plants, and central utility and  waste disposal systems.  (iv) Provide improved recovery systems.    (8) Development project.  A development project is the means by which petroleum resources are brought to the status of  economically producible.  As examples, the development of a single reservoir or field, an incremental development in a producing  field, or the integrated development of a group of several fields and associated facilities with a common ownership may constitute  a development project.    (9) Development well.  A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known  to be productive.    (10) Economically producible.  The term economically producible, as it relates to a resource, means a resource which generates  revenue that exceeds, or is reasonably expected to exceed, the costs of the operation.  The value of the products that generate  revenue shall be determined at the terminal point of oil and gas producing activities as defined in paragraph (a)(16) of this  section.    (11) Estimated ultimate recovery (EUR).  Estimated ultimate recovery is the sum of reserves remaining as of a given date and  cumulative production as of that date.    (12) Exploration costs.  Costs incurred in identifying areas that may warrant examination and in examining specific areas that  are considered to have prospects of containing oil and gas reserves, including costs of drilling exploratory wells and exploratory- type stratigraphic test wells.  Exploration costs may be incurred both before acquiring the related property (sometimes referred  to in part as prospecting costs) and after acquiring the property.  Principal types of exploration costs, which include depreciation  and applicable operating costs of support equipment and facilities and other costs of exploration activities, are:    (i) Costs of topographical, geographical and geophysical studies, rights of access to properties to conduct those  studies, and salaries and other expenses of geologists, geophysical crews, and others conducting those studies.   Collectively, these are sometimes referred to as geological and geophysical or "G&G" costs.  (ii) Costs of carrying and retaining undeveloped properties, such as delay rentals, ad valorem taxes on properties,  legal costs for title defense, and the maintenance of land and lease records.  (iii) Dry hole contributions and bottom hole contributions.  (iv) Costs of drilling and equipping exploratory wells.  (v) Costs of drilling exploratory-type stratigraphic test wells.    (13) Exploratory well.  An exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously found  to be productive of oil or gas in another reservoir.  Generally, an exploratory well is any well that is not a development well, an  extension well, a service well, or a stratigraphic test well as those items are defined in this section.    (14) Extension well.  An extension well is a well drilled to extend the limits of a known reservoir.    (15) Field.  An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual  geological structural feature and/or stratigraphic condition.  There may be two or more reservoirs in a field which are separated  vertically by intervening impervious strata, or laterally by local geologic barriers, or by both.  Reservoirs that are associated by  being in overlapping or adjacent fields may be treated as a single or common operational field.  The geological terms "structural  feature" and "stratigraphic condition" are intended to identify localized geological features as opposed to the broader terms of  basins, trends, provinces, plays, areas-of-interest, etc.    (16) Oil and gas producing activities.    (i) Oil and gas producing activities include:    (A) The search for crude oil, including condensate and natural gas liquids, or natural gas ("oil and gas") in  their natural states and original locations;  (B) The acquisition of property rights or properties for the purpose of further exploration or for the purpose of  removing the oil or gas from such properties;  (C) The construction, drilling, and production activities necessary to retrieve oil and gas from their natural  reservoirs, including the acquisition, construction, installation, and maintenance of field gathering and  storage systems, such as:  (1) Lifting the oil and gas to the surface; and  (2) Gathering, treating, and field processing (as in the case of processing gas to extract liquid  hydrocarbons); and
 DEFINITIONS OF OIL AND GAS RESERVES  Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)     Definitions - Page 3 of 6  (D) Extraction of saleable hydrocarbons, in the solid, liquid, or gaseous state, from oil sands, shale, coalbeds,  or other nonrenewable natural resources which are intended to be upgraded into synthetic oil or gas, and  activities undertaken with a view to such extraction.    Instruction 1 to paragraph (a)(16)(i): The oil and gas production function shall be regarded as ending at a "terminal point",  which is the outlet valve on the lease or field storage tank.  If unusual physical or operational circumstances exist, it may be  appropriate to regard the terminal point for the production function as:    a. The first point at which oil, gas, or gas liquids, natural or synthetic, are delivered to a main pipeline, a common  carrier, a refinery, or a marine terminal; and  b. In the case of natural resources that are intended to be upgraded into synthetic oil or gas, if those natural resources  are delivered to a purchaser prior to upgrading, the first point at which the natural resources are delivered to a  main pipeline, a common carrier, a refinery, a marine terminal, or a facility which upgrades such natural resources  into synthetic oil or gas.    Instruction 2 to paragraph (a)(16)(i): For purposes of this paragraph (a)(16), the term saleable hydrocarbons means  hydrocarbons that are saleable in the state in which the hydrocarbons are delivered.    (ii) Oil and gas producing activities do not include:    (A) Transporting, refining, or marketing oil and gas;  (B) Processing of produced oil, gas, or natural resources that can be upgraded into synthetic oil or gas by a  registrant that does not have the legal right to produce or a revenue interest in such production;  (C) Activities relating to the production of natural resources other than oil, gas, or natural resources from  which synthetic oil and gas can be extracted; or  (D) Production of geothermal steam.    (17) Possible reserves.  Possible reserves are those additional reserves that are less certain to be recovered than probable  reserves.    (i) When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability  of exceeding proved plus probable plus possible reserves.  When probabilistic methods are used, there should be  at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable  plus possible reserves estimates.  (ii) Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and  interpretations of available data are progressively less certain.  Frequently, this will be in areas where geoscience  and engineering data are unable to define clearly the area and vertical limits of commercial production from the  reservoir by a defined project.  (iii) Possible reserves also include incremental quantities associated with a greater percentage recovery of the  hydrocarbons in place than the recovery quantities assumed for probable reserves.  (iv) The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable  alternative technical and commercial interpretations within the reservoir or subject project that are clearly  documented, including comparisons to results in successful similar projects.  (v) Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of  a reservoir within the same accumulation that may be separated from proved areas by faults with displacement  less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore,  and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir.   Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these  areas are in communication with the proved reservoir.  (vi) Pursuant to paragraph (a)(22)(iii) of this section, where direct observation has defined a highest known oil (HKO)  elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the  structurally higher portions of the reservoir above the HKO only if the higher contact can be established with  reasonable certainty through reliable technology.  Portions of the reservoir that do not meet this reasonable  certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and  pressure gradient interpretations.    (18) Probable reserves.  Probable reserves are those additional reserves that are less certain to be recovered than proved  reserves but which, together with proved reserves, are as likely as not to be recovered.    (i) When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed  the sum of estimated proved plus probable reserves.  When probabilistic methods are used, there should be at  least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves  estimates.
 DEFINITIONS OF OIL AND GAS RESERVES  Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)     Definitions - Page 4 of 6  (ii) Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or  interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or  productivity does not meet the reasonable certainty criterion.  Probable reserves may be assigned to areas that  are structurally higher than the proved area if these areas are in communication with the proved reservoir.  (iii) Probable reserves estimates also include potential incremental quantities associated with a greater percentage  recovery of the hydrocarbons in place than assumed for proved reserves.  (iv) See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this section.    (19) Probabilistic estimate.  The method of estimation of reserves or resources is called probabilistic when the full range of  values that could reasonably occur for each unknown parameter (from the geoscience and engineering data) is used to generate  a full range of possible outcomes and their associated probabilities of occurrence.    (20) Production costs.    (i) Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and  applicable operating costs of support equipment and facilities and other costs of operating and maintaining those  wells and related equipment and facilities.  They become part of the cost of oil and gas produced.  Examples of  production costs (sometimes called lifting costs) are:    (A) Costs of labor to operate the wells and related equipment and facilities.  (B) Repairs and maintenance.  (C) Materials, supplies, and fuel consumed and supplies utilized in operating the wells and related equipment  and facilities.  (D) Property taxes and insurance applicable to proved properties and wells and related equipment and  facilities.  (E) Severance taxes.    (ii) Some support equipment or facilities may serve two or more oil and gas producing activities and may also serve  transportation, refining, and marketing activities.  To the extent that the support equipment and facilities are used  in oil and gas producing activities, their depreciation and applicable operating costs become exploration,  development or production costs, as appropriate.  Depreciation, depletion, and amortization of capitalized  acquisition, exploration, and development costs are not production costs but also become part of the cost of oil  and gas produced along with production (lifting) costs identified above.    (21) Proved area.  The part of a property to which proved reserves have been specifically attributed.    (22) Proved oil and gas reserves.  Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of  geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date  forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior  to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain,  regardless of whether deterministic or probabilistic methods are used for the estimation.  The project to extract the hydrocarbons  must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.    (i) The area of the reservoir considered as proved includes:       (A) The area identified by drilling and limited by fluid contacts, if any, and   (B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous  with it and to contain economically producible oil or gas on the basis of available geoscience and  engineering data.     (ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known  hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and  reliable technology establishes a lower contact with reasonable certainty.  (iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential  exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the  reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact  with reasonable certainty.  (iv) Reserves which can be produced economically through application of improved recovery techniques (including,  but not limited to, fluid injection) are included in the proved classification when:    (A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in  the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir,  or other evidence using reliable technology establishes the reasonable certainty of the engineering  analysis on which the project or program was based; and
 DEFINITIONS OF OIL AND GAS RESERVES  Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)     Definitions - Page 5 of 6  (B) The project has been approved for development by all necessary parties and entities, including  governmental entities.    (v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be  determined.  The price shall be the average price during the 12-month period prior to the ending date of the period  covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each  month within such period, unless prices are defined by contractual arrangements, excluding escalations based  upon future conditions.    (23) Proved properties.  Properties with proved reserves.    (24) Reasonable certainty.  If deterministic methods are used, reasonable certainty means a high degree of confidence that the  quantities will be recovered.  If probabilistic methods are used, there should be at least a 90% probability that the quantities  actually recovered will equal or exceed the estimate.  A high degree of confidence exists if the quantity is much more likely to  be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical),  engineering, and economic data are made to estimated ultimate recovery (EUR) with time, reasonably certain EUR is much  more likely to increase or remain constant than to decrease.    (25) Reliable technology.  Reliable technology is a grouping of one or more technologies (including computational methods) that  has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the  formation being evaluated or in an analogous formation.    (26) Reserves.  Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be  economically producible, as of a given date, by application of development projects to known accumulations.  In addition, there  must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the  production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to  implement the project.    Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults  until those reservoirs are penetrated and evaluated as economically producible.  Reserves should not be assigned to areas that  are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low  reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from  undiscovered accumulations).    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.
 DEFINITIONS OF OIL AND GAS RESERVES  Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)     Definitions - Page 6 of 6   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.      (27) Reservoir.  A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas  that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.    (28) Resources.  Resources are quantities of oil and gas estimated to exist in naturally occurring accumulations.  A portion of  the resources may be estimated to be recoverable, and another portion may be considered to be unrecoverable.  Resources  include both discovered and undiscovered accumulations.    (29) Service well.  A well drilled or completed for the purpose of supporting production in an existing field.  Specific purposes of  service wells include gas injection, water injection, steam injection, air injection, salt-water disposal, water supply for injection,  observation, or injection for in-situ combustion.    (30) Stratigraphic test well.  A stratigraphic test well is a drilling effort, geologically directed, to obtain information pertaining to a  specific geologic condition.  Such wells customarily are drilled without the intent of being completed for hydrocarbon production.   The classification also includes tests identified as core tests and all types of expendable holes related to hydrocarbon exploration.   Stratigraphic tests are classified as "exploratory type" if not drilled in a known area or "development type" if drilled in a known  area.    (31) Undeveloped oil and gas reserves.  Undeveloped oil and gas reserves are reserves of any category that are expected to  be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for  recompletion.    (i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are  reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes  reasonable certainty of economic producibility at greater distances.  (ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted  indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer  time.  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).    (iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an  application of fluid injection or other improved recovery technique is contemplated, unless such techniques have  been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph  (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.    (32) Unproved properties.  Properties with no proved reserves.