Exhibit 99.3
May 10, 2017
Mr. Hugh Menown
Energy XXI Gulf Coast, Inc.
1021 Main Street, Suite 2626
Houston, Texas 77002
Dear Mr. Menown:
In accordance with your request, we have
prepared a price sensitivity to our report dated May 9, 2017, which sets forth our estimates of reserves and future revenue, as
of March 31, 2017, to the Energy XXI Gulf Coast, Inc. (Energy XXI) interest in certain oil and gas properties located in Louisiana,
Texas, and federal waters in the Gulf of Mexico. The estimates in the May 9 report were 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, corporate-level overhead expenses are
excluded for the operated properties. The differences between the estimates of reserves and revenue in the May 9 and
this report are due to changes in price parameters only. With the exception of these changes, we completed our evaluation on or
about May 9, 2017. This report has been prepared using price and cost parameters specified by Energy XXI, referred to as the Strip
Price Sensitivity Case, as discussed in the subsequent paragraphs of this letter. This report has been prepared for Energy XXI's
use in filing with the SEC as a sensitivity; in our opinion the assumptions, data, methods, and procedures used in the preparation
of this report are appropriate for such purpose. For your reference, the SEC definitions are presented immediately following this
letter.
We estimate the net reserves and future
net revenue to the Energy XXI interest in these properties, as of March 31, 2017, to be:
| | |
Net Reserves | | |
Future Net Revenue(1) (M$) | |
| | |
Oil | | |
NGL | | |
Gas | | |
| | |
Present Worth | |
| Category | |
(MBBL) | | |
(MBBL) | | |
(MMCF) | | |
Total | | |
at 10% | |
| | |
| | |
| | |
| | |
| | |
| |
| Proved Developed Producing | |
| 53,815.9 | | |
| 890.4 | | |
| 56,115.2 | | |
| -645,004.2 | | |
| -13,216.2 | |
| Proved Developed Non-Producing | |
| 9,730.3 | | |
| 914.9 | | |
| 34,791.5 | | |
| 260,606.0 | | |
| 133,907.8 | |
| Proved Undeveloped | |
| 27,501.8 | | |
| 468.5 | | |
| 31,086.7 | | |
| 772,632.6 | | |
| 278,364.9 | |
| Total Proved | |
| 91,048.0 | | |
| 2,273.8 | | |
| 121,993.4 | | |
| 388,234.3 | | |
| 399,056.6 | |
| | |
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| | | |
| | | |
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| Probable Developed | |
| 12,479.3 | | |
| 1,101.7 | | |
| 51,404.8 | | |
| 272,436.6 | | |
| 240,218.0 | |
| Probable Undeveloped | |
| 35,238.6 | | |
| 375.7 | | |
| 73,367.0 | | |
| 1,360,058.5 | | |
| 509,548.8 | |
| Total Probable | |
| 47,717.9 | | |
| 1,477.4 | | |
| 124,771.8 | | |
| 1,632,494.6 | | |
| 749,767.0 | |
Totals may not add because of rounding.
| (1) | Future net revenue is after deducting 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.
The estimates shown in this report are
for proved and probable reserves. As requested, 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. 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.
Gross revenue is Energy XXI's share of
the gross (100 percent) revenue from the properties prior to any deductions. Future net revenue is after deductions for Energy
XXI's share of production 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.
As requested, this report has been prepared
using oil, NGL, and gas price parameters specified by Energy XXI. Oil and NGL prices are based on NYMEX West Texas Intermediate
prices and are adjusted by field for quality, transportation fees, and market differentials. Gas prices are based on NYMEX Henry
Hub prices and are adjusted by field for energy content, transportation fees, and market differentials. For the proved reserves,
the average initial prices, after adjustments, are $49.95 per barrel of oil, $24.14 per barrel of NGL, and $3.122 per MCF of gas.
For the proved reserves, the average adjusted product prices weighted by production over the remaining lives of the properties
are $51.04 per barrel of oil, $25.92 per barrel of NGL, and $2.756 per MCF of gas. All prices, before adjustments, are shown in
the following table:
| Period | |
Oil/NGL Price | |
Gas Price |
| Ending | |
($/Barrel) | |
($/MMBTU) |
| | |
| |
|
| 12-31-2017 | |
51.58 | |
3.325 |
| 12-31-2018 | |
51.90 | |
3.034 |
| 12-31-2019 | |
51.37 | |
2.833 |
| 12-31-2020 | |
51.39 | |
2.821 |
| 12-31-2021 | |
51.98 | |
2.832 |
| Thereafter | |
52.98 | |
2.842 |
Operating costs used in this report are
based on operating expense records of Energy XXI. 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 field-level costs, per-well costs, and per-unit-of-production costs. For all properties, headquarters general
and administrative overhead expenses of Energy XXI are not included. Operating costs are not escalated for inflation.
Capital costs used in this report were
provided by Energy XXI 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 Energy XXI's estimates of the costs to abandon the 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 Energy XXI 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
Energy XXI 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 Energy XXI,
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, 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 Energy XXI, 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. Connor B. Riseden, a Licensed Professional Engineer in the State of Texas, has been practicing consulting petroleum
engineering at NSAI since 2006 and has over 4 years of prior industry experience. Shane M. Howell, a Licensed Professional Geoscientist
in the State of Texas, has been practicing consulting petroleum geoscience at NSAI since 2005 and has over 7 years of prior industry
experience. We are independent petroleum engineers, geologists, geophysicists, and petrophysicists; we do not own an interest in
these properties nor are we employed on a contingent basis.
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Sincerely, |
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NETHERLAND, SEWELL & ASSOCIATES, INC. |
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Texas Registered Engineering Firm F-2699 |
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By: |
/s/ C.H. (Scott) Rees III |
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C.H. (Scott) Rees III, P.E. |
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Chairman and Chief Executive Officer |
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| By: |
/s/ Connor B. Riseden |
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By: |
/s/ Shane M. Howell |
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Connor B. Riseden, P.E. 100566 |
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Shane M. Howell, P.G. 11276 |
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Vice President |
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Vice President |
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| Date Signed: May 10, 2017 |
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Date Signed: May 10, 2017 |
CBR:SAO
| Please be advised that the digital document you are viewing is provided by Netherland, Sewell & Associates, Inc. (NSAI) as a convenience to our clients. The digital document is intended to be substantively the same as the original signed document maintained by NSAI. The digital document is subject to the parameters, limitations, and conditions stated in the original document. In the event of any differences between the digital document and the original document, the original document shall control and supersede the digital document. |
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. |
(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.
(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. |
| (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. |
| (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. |
| (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).
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.
(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:
| Ÿ | 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); |
| Ÿ | The company's historical record at completing development
of comparable long-term projects; |
| Ÿ | The amount of time in which the company has maintained
the leases, or booked the reserves, without significant development activities; |
| Ÿ | 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 |
| Ÿ | 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.
