Exhibit 99.2
July 19, 2022
Mr. Matthew W. McFarland
W&T Offshore, Inc.
5718 Westheimer Road, Suite 700
Houston, Texas 77057
Dear Mr. McFarland:
In accordance with your request, we have estimated
the proved, probable, and possible reserves and future revenue, as of June 30, 2022, to the W&T Offshore, Inc. (W&T)
proportional consolidation interest in certain oil and gas properties located in state waters offshore Alabama, Louisiana, and Texas and
in federal waters in the Gulf of Mexico, as listed in the accompanying tabulations. 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
W&T. 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 and, as requested, abandonment costs have not been included in our estimates of future net revenue.
Definitions are presented immediately following this letter.
The net reserves and future net revenue to the
W&T proportional consolidation interest have been estimated incorporating the terms of the Monza Joint Venture (Monza JV) using the
proportional consolidation method. W&T entered into the Monza JV on February 23, 2018. Under the proportional consolidation method,
W&T’s interest share of revenues, expenses, investments, and liabilities includes both W&T’s direct interest in the
properties and W&T’s interest share of the Monza JV.
We estimate the net reserves and future net revenue
to the W&T proportional consolidation interest in these properties, as of June 30, 2022, to be:
| | |
Net Reserves | | |
Future Net Revenue(1) (M$) | |
| Category | |
Oil
(MBBL) | | |
NGL
(MBBL) | | |
Gas
(MMCF) | | |
Total | | |
Present Worth
at 10% | |
| Proved Developed Producing | |
| 25,927.9 | | |
| 16,272.3 | | |
| 520,276.1 | | |
| 3,206,879.2 | | |
| 1,981,672.9 | |
| Proved Developed Non-Producing | |
| 5,264.4 | | |
| 1,346.5 | | |
| 72,721.7 | | |
| 563,413.8 | | |
| 303,728.6 | |
| Proved Undeveloped | |
| 9,462.4 | | |
| 1,219.0 | | |
| 59,762.1 | | |
| 653,262.3 | | |
| 336,932.7 | |
| Total Proved | |
| 40,654.8 | | |
| 18,837.8 | | |
| 652,759.9 | | |
| 4,423,555.4 | | |
| 2,622,334.2 | |
| | |
| | | |
| | | |
| | | |
| | | |
| | |
| Probable Developed | |
| 17,587.1 | | |
| 4,274.0 | | |
| 135,159.6 | | |
| 1,534,922.8 | | |
| 658,429.9 | |
| Probable Undeveloped | |
| 20,987.1 | | |
| 2,422.1 | | |
| 84,189.5 | | |
| 1,793,631.0 | | |
| 909,269.1 | |
| Total Probable | |
| 38,574.3 | | |
| 6,696.1 | | |
| 219,349.1 | | |
| 3,328,553.8 | | |
| 1,567,699.0 | |
| | |
| | | |
| | | |
| | | |
| | | |
| | |
| Possible Developed | |
| 25,208.0 | | |
| 4,440.6 | | |
| 138,804.7 | | |
| 2,085,517.5 | | |
| 593,165.9 | |
| Possible Undeveloped | |
| 36,823.6 | | |
| 4,026.9 | | |
| 137,304.6 | | |
| 3,330,491.9 | | |
| 1,711,559.3 | |
| Total Possible | |
| 62,031.7 | | |
| 8,467.5 | | |
| 276,109.3 | | |
| 5,416,009.4 | | |
| 2,304,725.2 | |
Totals may not add because of rounding.
| (1) | Future net revenue does not include estimated abandonment costs. |
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. Oil equivalent volumes shown in
this report are expressed in thousands of barrels of oil equivalent (MBOE), determined using the ratio of 6 MCF of gas to 1 barrel of
oil.
Reserves categorization conveys the relative degree
of certainty; reserves subcategorization is based on development and production status. Estimates of proved undeveloped reserves have
been included for three proved locations that are scheduled to be drilled more than five years beyond the original booking dates because
of limitations with conductor slot availability. These locations have been included based on the operator’s declared intent to drill
these wells. 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.
As shown in the Table of Contents, this report
includes summary projections of reserves and revenue by reserves category. Also included are reserves and economics data for each reserves
category; these data include a summary projection of reserves and revenue along with one-line summaries of basic data, reserves, and economics
by lease.
Gross revenue shown in this report is W&T’s
share of the gross (100 percent) revenue from the properties prior to any deductions. Future net revenue is after deductions for W&T’s
share of state production taxes, ad valorem taxes, capital 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 July 2021 through June 2022.
For oil and NGL volumes, the average West Texas Intermediate spot price of $85.82 per barrel is adjusted by field for quality, transportation
fees, and market differentials. For gas volumes, the average Henry Hub spot price of $5.133 per MMBTU is adjusted by field for energy
content, transportation fees, and market differentials. All prices are held constant throughout the lives of the properties. Average adjusted
product prices weighted by production over the remaining lives of the properties are shown for each category in the following table:
| | |
Average Adjusted Prices | |
| Category | |
Oil
($/Barrel) | | |
NGL
($/Barrel) | | |
Gas
($/MCF) | |
| Proved | |
| 83.47 | | |
| 39.66 | | |
| 5.065 | |
| Probable | |
| 83.72 | | |
| 41.63 | | |
| 4.991 | |
| Possible | |
| 83.87 | | |
| 42.44 | | |
| 4.959 | |
Operating costs used in this report are based
on operating expense records of W&T. 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 are limited to direct lease- and field-level costs and W&T’s estimate of the portion of its
headquarters general and administrative overhead expenses necessary to operate the properties. Economic projections are included to account
for the fees associated with W&T’s oil transportation contracts for Green Canyon 859 Field; the minimum transportation obligation
extends beyond the economic life of the field. For all other areas, we have made no specific investigation of any firm transportation
contracts that may be in place and 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 field- and lease-level accounting statements. Operating costs have been divided into field-level
costs, per-well costs, and per-unit-of-production costs and are not escalated for inflation. As requested, the field-level costs are allocated
by month among the proved reserves categories.
Capital costs used in this report were provided
by W&T and are based on authorizations for expenditure (AFEs) prepared for internal approval and, if applicable, external interest
owner approval. If an AFE was not available, W&T provided cost estimates based on recent activity similar in scope to the proposed
project. Capital costs are included as required for workovers, new development wells, and production equipment. Based on our understanding
of W&T’s 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. Capital costs are not escalated for inflation. As requested, our estimates do not include
any salvage value for the lease and well equipment or the cost of abandoning the properties.
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 W&T 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 W&T receiving its net revenue
interest share of estimated future gross production after field usage and shrinkage.
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 W&T, 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, petrophysical data, seismic data, well test data, production
data, bottomhole pressure 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
W&T, public data sources, and the nonconfidential files of Netherland, Sewell & Associates, Inc. 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. 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 |
| |
|
|
| |
By: |
 |
| |
|
C.H. (Scott) Rees III, P.E. |
| |
|
Executive Chairman |
GSC:ARS
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. |
Definitions - Page 1 of 10
DEFINITIONS
OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
|
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. |
| (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.
Definitions - Page 2 of 10
DEFINITIONS
OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
(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 |
Definitions - Page 3 of 10
DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
| (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. |
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. |
Definitions - Page 4 of 10
DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
| (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. |
(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.
Definitions - Page 5 of 10
DEFINITIONS
OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
(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. |
| (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. |
Definitions - Page 6 of 10
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 10
| (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.
(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).
Definitions - Page 7 of 10
DEFINITIONS
OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
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.
Definitions - Page 8 of 10
DEFINITIONS
OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
(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 |
Definitions - Page 9 of 10
DEFINITIONS
OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
| · | 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.
Definitions - Page 10 of 10
