Attached files
Exhibit 99.1
February 8,
2018
Mr. Sam
L. Banks
Yuma
Energy, Inc.
1177
West Loop South, Suite 1825
Houston,
Texas 77027
Dear
Mr. Banks:
In
accordance with your request, we have estimated the proved reserves
and future revenue, as of December 31, 2017, to the Yuma Energy,
Inc. (Yuma) interest in certain oil and gas properties located in
California, Louisiana, North Dakota, Oklahoma, and Texas. 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 Yuma. 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 Yuma'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 Yuma
interest in these properties, as of December 31, 2017, to
be:
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Net
Reserves
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Future
Net Revenue (M$)
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Oil
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NGL
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Gas
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Present
Worth
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Category
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(MBBL)
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(MBBL)
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(MMCF)
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Total
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at
10%
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Proved
Developed Producing
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1,101.3
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559.6
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11,817.1
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50,940.9
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42,143.1
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Proved
Developed Non-Producing
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661.9
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449.6
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9,313.8
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46,821.1
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21,884.6
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Proved
Undeveloped
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598.9
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284.9
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2,464.6
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16,732.3
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8,875.0
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Total
Proved
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2,362.1
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1,294.2
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23,595.5
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114,494.3
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72,902.7
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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.
Reserves
categorization conveys the relative degree of certainty; reserves
subcategorization is based on development and production status.
The estimates of reserves and future revenue included herein have
not been adjusted for risk. As requested, probable and possible
reserves that exist for these properties have not been included.
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 Yuma's share of the gross (100 percent) revenue from the
properties prior to any deductions. Future net revenue is after
deductions for Yuma'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 2017. For oil and NGL volumes, the
average West Texas Intermediate spot price of $51.34 per barrel is
adjusted by lease for quality, transportation fees, and market
differentials. For gas volumes, the average Henry Hub spot price of
$2.976 per MMBTU is adjusted by lease 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 $50.77 per barrel of oil, $24.87 per
barrel of NGL, and $2.973 per MCF of gas.
Operating
costs used in this report are based on operating expense records of
Yuma. 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. Operating
costs have been divided into per-well costs and
per-unit-of-production costs. Headquarters general and
administrative overhead expenses of Yuma are included to the extent
that they are covered under joint operating agreements for the
operated properties. Operating costs are not escalated for
inflation.
Capital
costs used in this report were provided by Yuma and are based on
authorizations for expenditure and actual costs from recent
activity. Capital costs are included as required for workovers, new
development wells, and production equipment. 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 Yuma's estimates of the costs to abandon
the existing wells, platforms, 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 Yuma 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 Yuma receiving its net revenue interest
share of estimated future gross production. Additionally, we have
made no investigation of any firm transportation contracts that may
be in place for these properties; 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 properties will be developed consistent with current
development plans as provided to us by Yuma, 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, 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, and analogy, that we considered to be appropriate and
necessary to categorize and estimate reserves in accordance with
SEC definitions and regulations. A substantial portion of these
reserves are for behind-pipe zones, undeveloped locations, and
producing wells that lack sufficient production history upon which
performance-related estimates of reserves can be based; such
reserves are based on estimates of reservoir volumes and recovery
efficiencies along with analogy to properties with similar geologic
and reservoir characteristics. 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 Yuma, various
operators of the properties, 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. G. Lance Binder, a
Licensed Professional Engineer in the State of Texas, has been
practicing consulting petroleum engineering at NSAI since 1983 and
has over 5 years of prior industry experience. Philip R. Hodgson, a
Licensed Professional Geoscientist in the State of Texas, has been
practicing consulting petroleum geoscience at NSAI since 1998 and
has over 14 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.
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Sincerely,
NETHERLAND,
SEWELL & ASSOCIATES, INC.
Texas
Registered Engineering Firm F-2699
/s/
C.H. (Scott) Rees III
By:
C.H.
(Scott) Rees III, P.E.
Chairman and Chief
Executive Officer
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/s/ G. Lance Binder
By:
G. Lance Binder, P.E. 61794
Executive Vice
President
Date Signed:
February 8, 2018
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/s/ Philip R. Hodgson
By:
Philip R. Hodgson, P.G. 1314
Vice President
Date Signed:
February 8, 2018
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GLB:SDB
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event of any differences between the digital document and the
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supersede the digital document.
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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 2007 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 2007 Petroleum Resources
Management System:
Developed Producing Reserves – Developed Producing Reserves
are expected to be recovered from completion intervals that are
open and producing at the time of the estimate. Improved recovery
reserves are considered producing only after the improved recovery
project is in operation.
Developed Non-Producing Reserves – Developed Non-Producing
Reserves include shut-in and behind-pipe Reserves. Shut-in Reserves
are expected to be recovered from (1) completion intervals which
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 which will require
additional completion work or future recompletion prior to start of
production. In all cases, production can be initiated or restored
with relatively low expenditure compared to the cost of drilling a
new well.
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Definitions - Page
1 of
7
DEFINITIONS OF OIL AND GAS RESERVES
Adapted
from U.S. Securities and Exchange Commission Regulation S-X Section
210.4-10(a)
(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.
(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.
Definitions - Page
2 of
7
DEFINITIONS OF OIL AND GAS RESERVES
Adapted
from U.S. Securities and Exchange Commission Regulation S-X Section
210.4-10(a)
(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.
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.
Definitions - Page
3 of
7
DEFINITIONS OF OIL AND GAS RESERVES
Adapted
from U.S. Securities and Exchange Commission Regulation S-X Section
210.4-10(a)
(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.
(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.
Definitions - Page
4 of
7
DEFINITIONS OF OIL AND GAS RESERVES
Adapted
from U.S. Securities and Exchange Commission Regulation S-X Section
210.4-10(a)
(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.
(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
Definitions - Page
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DEFINITIONS OF OIL AND GAS RESERVES
Adapted
from U.S. Securities and Exchange Commission Regulation S-X Section
210.4-10(a)
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.
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(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
6 of
7
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
•
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).
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(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
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