|  |  | Exhibit 99.1

February 4, 2026
Mr. Bradley G. Gray
Diversified Energy Company
1600 Corporate Drive
Birmingham, Alabama 35242
Dear Mr. Gray:
In accordance with your request, we have estimated the proved reserves and future revenue, as of December 31,
2025, to the Diversified Energy Company (DEC) interest in certain oil and gas properties located in the United
States. 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 DEC. 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 conform to the FASB Accounting Standards Codification Topic 932, Extractive Activities—
Oil and Gas, except that future income taxes are excluded for all properties and, as requested, per-well overhead
expenses are excluded for the operated properties. Definitions are presented immediately following this letter.
This report has been prepared for DEC'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 net reserves and future net revenue to the DEC interest in these properties, as of December 31,
2025, to be:

|  | Net Reserves |  | Future Net Revenue (M$)
|  | Oil |  | NGL |  | Gas |  | Gas Equiv |  |  |  | Present Worth
Category |  | (MBBL) |  | (MBBL) |  | (MMCF) |  | (MMCFE) |  | Total |  | at 10%
Proved Developed Producing |  | 87,020.3 |  | 158,984.5 |  | 4,214,593.5 |  | 5,690,622.6 |  | 6,859,528.4 |  | 4,819,592.2
Proved Developed Non-Producing |  | 21.1 |  | 40.0 |  | 9,518.8 |  | 9,885.3 |  | 26,988.2 |  | 5,985.3
Proved Undeveloped |  | 24,108.6 |  | 5,949.9 |  | 201,620.8 |  | 381,971.4 |  | 955,817.0 |  | 353,873.0
Total Proved |  | 111,150.0 |  | 164,974.4 |  | 4,425,733.1 |  | 6,082,479.4 |  | 7,842,333.6 |  | 5,179,450.5

Totals may not add because of rounding.
The oil volumes shown include crude oil and condensate. Oil and natural gas liquids (NGL) volumes are
expressed in thousands of barrels (MBBL); a barrel is equivalent to 42 United States gallons. Gas volumes are
expressed in millions of cubic feet (MMCF) at standard temperature and pressure bases. Gas equivalent volumes
are expressed in millions of cubic feet equivalent (MMCFE), determined using the ratio of 6 MCF of gas to 1 barrel
of liquids.
Reserves categorization conveys the relative degree of certainty; reserves subcategorization is based on
development and production status. As requested, probable and possible reserves that may exist for these
properties 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 beyond those tracts for which undeveloped reserves have been estimated.
Gross revenue is DEC's share of the gross (100 percent) revenue from the properties prior to any deductions.
Future net revenue is after deductions for DEC's share of production taxes, ad valorem taxes, capital costs,
abandonment costs, and 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 properties.
Prices used in this report are based on the 12-month unweighted arithmetic average of the first-day-of-the-month
price for each month in the period January through December 2025. For oil and NGL volumes, the average West
Texas Intermediate spot price of $66.01 per barrel is adjusted for quality, transportation fees, and market
differentials. For gas volumes, the average Henry Hub spot price of $3.387 per MMBTU is adjusted for energy
content, transportation fees, and market differentials. All prices are held constant throughout the lives of the
properties. The average adjusted product prices weighted by production over the remaining lives of the properties
are $64.26 per barrel of oil, $17.54 per barrel of NGL, and $3.091 per MCF of gas.
Operating costs used in this report are based on operating expense records provided by DEC. For the
nonoperated properties, these costs include the per-well overhead expenses allowed under joint operating
agreements along with estimates of costs to be incurred at and below the district and field levels. As requested,
operating costs for the operated properties include only direct lease- and field-level costs. Operating costs have
been divided into per-well costs and per-unit-of-production costs. For all properties, headquarters general and
administrative overhead expenses of DEC are not included. This report includes additional operating expenses
for the effects of all applicable firm transportation contracts. It is our understanding that DEC is supplying all
committed volumes for these contracts. Operating costs are not escalated for inflation.
Capital costs used in this report were provided by DEC and are based on authorizations for expenditure and
actual costs from recent activity. Capital costs are included as required for artificial lift, workovers, production
equipment, new development wells, and midstream facility maintenance. Based on our understanding of future
development plans, a review of the records provided to us, and our knowledge of similar properties, we regard
these estimated capital costs to be reasonable. Abandonment costs used in this report are DEC's estimates of
the costs to abandon the wells and production facilities, net of any salvage value. Capital costs and abandonment
costs are not escalated for inflation.
For the purposes of this report, we did not perform any field inspection of the properties, nor did we examine the
mechanical operation or condition of the wells and facilities. We have not investigated possible environmental
liability related to the properties; therefore, our estimates do not include any costs due to such possible liability.
We have made no investigation of potential volume and value imbalances resulting from overdelivery or
underdelivery to the DEC 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 DEC receiving its net
revenue interest share of estimated future gross production. In addition, no consideration has been given to any
potential future gas curtailment activities or changes in market conditions.
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 properties will be developed consistent
with current development plans as provided to us by DEC, that the properties 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 and the costs related thereto 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 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, 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, and analogy, 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 DEC, 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 properties 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. Robert C. Barg, a Licensed Professional Engineer in the State of Texas, has been practicing
consulting petroleum engineering at NSAI since 1989 and has over 6 years of prior industry experience. William
J. Knights, a Licensed Professional Geoscientist in the State of Texas, has been practicing consulting petroleum
geoscience at NSAI since 1991 and has over 10 years of prior industry experience. We are independent
petroleum engineers, geologists, geophysicists, and petrophysicists; we do not own an interest in these properties
nor are we employed on a contingent basis.

|  |  | Sincerely, |
|  |  |  | NETHERLAND, SEWELL & ASSOCIATES, INC.
|  |  |  | Texas Registered Engineering Firm F-2699
|  |  |  |  | /s/ Richard B. Talley, Jr.
|  |  |  | By: |  |
|  |  |  |  | Richard B. Talley, Jr., P.E.
|  |  |  |  | Chairman and Chief Executive Officer
| /s/ Robert C. Barg |  |  | /s/ William J. Knights
By: |  |  |  | By: |  |
| Robert C. Barg, P.E. 71658 |  |  | William J. Knights, P.G. 1532
| Senior Vice President |  |  | Vice President
Date Signed: February 4, 2026 |  | Date Signed: February 4, 2026
RCB:BDC |  |  |  |

Definitions - Page 1 of 6

DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
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 - Page 2 of 6

DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
(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
(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.
Definitions - Page 3 of 6

DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
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.
(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.
Definitions - Page 4 of 6

DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
(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
(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.
Definitions - Page 5 of 6

DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
(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. 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.
Definitions - Page 6 of 6

DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
(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.