Exhibit 10.24

 

 

 

 

 

 

 

 

 

 

 

 

ESTIMATED PROVED RESERVES AND FUTURE NET REVENUE AS OF

DECEMBER 31, 2013

 

ATTRIBUTABLE TO INTERESTS OWNED BY

PETRON ENERGY II, INC. IN CERTAIN PROPERTIES LOCATED IN

OKLAHOMA AND TEXAS

 

(SEC CASE)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

FORREST A. GARB & ASSOCIATES, INC.

 

INTERNATIONAL PETROLEUM CONSULTANTS

 

 

FORREST A. GARB & ASSOCIATES, INC. 

 

INTERNATIONAL PETROLEUM CONSULTANTS

5310 HARVEST HILL ROAD, SUITE 275, LB 152

DALLAS, TEXAS 75230 - 5805

(972)788-1110 Telefax (972)991-3160 (E MAIL) forgarb@forgarb.com

 

 

 

 

March 18, 2014

 

 

 

Mr. Floyd Smith

Petron Energy II, Inc.

12850 Preston Road, Suite 960

Dallas, TX 75252

 

 

Dear Mr. Smith:

 

At your request, Forrest A. Garb & Associates, Inc. (FGA) has estimated the
proved reserves and future net revenue, as of December 31, 2013, attributable to
interests owned by Petron Energy II, Inc. (Petron) in certain oil and gas
properties located in Oklahoma and Texas. It is our understanding that the
reserves in this report constitute 100 percent of the reserves owned by Petron.
The purpose of this report is to furnish data to Petron regarding their reserves
for inclusion in their U.S. Securities and Exchange Commission (SEC) filings.

 

This report has been prepared using the definitions and guidelines of the SEC,
and with the exception of the exclusion of future income taxes, conforms to the
FASB Accounting Standards Codification Topic 932, Extractive Industries – Oil
and Gas. These guidelines specify the use of a 12-month first-day-of-the-month
average benchmark price, a ten percent discount factor, and constant oil and gas
prices and costs. The assumptions, data, methods, and procedures used in this
report are appropriate for the purposed of this report as described above.

 

The following table summarizes the estimated total net reserves and future net
revenue, as of December 31, 2013:

 

 

 

  Estimated Net Reserves 1 Estimated Future Net Revenue

 

 

 

Oil

 

 

Gas

 

Undiscounted

 

Discounted

at 10% Per Year3

  Reserve Category          (MBbl)2       (MMcf)2          (M$)2  
             (M$)2 Proved Developed             Producing 25.520   193.611
1,838.544   1,246.813 Non-producing                10.158              0.000
            679.690               546.010 Total Proved4 35.678   193.611
2,518.234   1,792.823

 

1 The definitions for all reserves incorporated in this study have been set
forth in this report.

2 MBbl = thousands of barrels, MMcf = millions of cubic feet, M$ = thousands of
dollars.

3 The discounted future net revenue is not represented to be the fair market
value of these reserves.

4 The reserves and revenues in the summary table were estimated using the Aries
economics program. Due to the rounding procedures used in this program, there
may be slight differences in the calculated and summed values.

 

 

 

ENGINEERING

 

Proved oil and gas 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 from a given date forward. The basis for
estimating the proved producing reserves was the extrapolation of historical
production having an established decline trend. Volumetrics and/or analogy were
used for forecasting properties where insufficient data were present for
production decline extrapolation. Production histories were obtained from
published production data and state reporting records purchased from a third
party provider, HPDI, LLC, and supplemented with data provided by Petron. The
reserves for other reserve categories were estimated by analogy to adjacent
comparable wells. Petron provided the available geologic and engineering data
for FGA's review. FGA has accepted Petron’s intent to recomplete the proved
developed non-producing properties.

 

The analysis and findings presented in this report, represent FGA’s informed
judgments based on accepted standards of professional engineering practice, but
are subject to the generally recognized and unforeseen risks associated with the
interpretation of geological, geophysical, and engineering data. Estimates of
reserves were prepared by the use of appropriate geologic, petroleum
engineering, and evaluation principles and techniques which are in accordance
with practices generally recognized by the petroleum industry. Future changes in
federal, state, or local regulations may adversely impact the ability to recover
the future oil and gas volumes expected. Changes in economic and market
conditions from the assumptions and parameters used in this study may cause the
total quantity of future oil or gas recovered, actual production rates, prices
received, operating expenses and capital costs to vary from the results
presented in this report.

 

Gas volumes are expressed in millions of cubic feet (MMcf) at standard
temperature and pressure. Gas sales imbalances have not been taken into account
in the reserve estimates. The oil reserves shown in this study include crude oil
and/or condensate. Oil volumes are expressed in thousands of barrels (MBbl),
with one barrel equivalent to 42 United States gallons.

 

ECONOMIC CONSIDERATIONS

 

The benchmark oil and gas prices used in this study are the average of the
first- day-of-the-month spot prices posted for the West Texas Intermediate (WTI)
oil and Henry Hub natural gas, per SEC guidelines. Oil prices are based on a
benchmark price of

$96.90 per barrel and have been adjusted by lease for gravity, transportation
fees, and regional price differentials. Gas prices per thousand cubic feet (MCF)
are based on a

benchmark price of $3.67 per million British thermal units (MMBtu) and have been
adjusted by lease for Btu content, transportation fees, and regional price
differentials. The average realized prices were $96.90 per barrel for oil and
$3.67 per MMBtu for gas. The oil and gas prices are held constant for the
economic life of the properties as specified by the SEC.

 

Lease operating costs and capital expenditures, as required for workovers,
future development of new wells, and for production equipment, were provided by
Petron for FGA’s review. All costs have been held constant in this evaluation.
Existing or potential liabilities stemming from environmental conditions caused
by current or past operating practices have not been considered in this report.
No costs were included for abandonment, as these not considered material. No
costs are included in the projections

 

 

 

of future net revenue or in our economic analyses to restore, repair, or improve
the environmental conditions of the properties studied to meet existing or
future local, state, or federal regulations.

 

Petron provided ownership interests in the properties, and FGA accepted the
extent and character of ownership (working interest and net revenue interest) as
represented. Our staff conducted no independent well tests, property
inspections, or audits of completion and operating expenses as part of this
study.

 

The estimated future net revenues shown are those which should be realized from
the sale of estimated oil and gas reserves after the deduction of severance
taxes, ad valorem taxes, direct operating costs, and future capital
expenditures. No deductions have been made for overhead, federal income taxes,
or other indirect costs, such as interest expense and loan repayments. Surface
and well equipment salvage values have not been considered in the revenue
projections. The estimated reserves included in the cash flow projections have
not been adjusted for risk. The reserves included in this study are estimates
only and should not be construed as exact quantities. Future conditions may
affect recovery of estimated reserves and revenue, and all categories of
reserves may be subject to revision as more performance data become available.

 

Grand total summary economic projections by reserve category and category
summaries (including one-line summaries for the individual properties) are
presented in Attachment A.

 

Attachment B presents the definitions of proved oil and gas reserves in
accordance with the SEC. General comments regarding this report and the
estimation of future reserves and revenue are presented in Attachment C.
Attachment D contains the consulting firm profile.

 

FGA is an independent firm of geologists and petroleum engineers. Neither the
firm nor its employees own any interest in the properties studied, nor have we
been employed on a contingency basis. FGA has used all necessary methods and
procedures in the preparation of this report for the evaluation of these
properties.

 

We appreciate the opportunity to submit this evaluation. Should you have any
questions, please do not hesitate to call.

 

This report was prepared under the supervision of W.D. Harris III, Registered

Professional Engineer No. 75222, State of Texas and completed on March 18, 2014.

 

Yours truly,

 

 [garbsig.jpg]

 

Forrest A. Garb & Associates, Inc.

Texas Registered Engineering Firm F-629

 

 [wdharris.jpg]

 

W. D. Harris III

Chief Executive Officer

Forrest A. Garb & Associates, Inc.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

ATTACHMENTS

 

 

A. CATEGORY AND ONE-LINE SUMMARIES

 

B. DEFINITIONS FOR OIL AND GAS RESERVES C. GENERAL COMMENTS

D. CONSULTING FIRM PROFILE

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

ATTACHMENT A

 

 

CATEGORY AND ONE-LINE SUMMARIES

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

PROVED

 

 

 

 [table1.jpg]

 

 

ATTACHMENT A-1

 

 

 

[table2.jpg]  

 

ATTACHMENT A-2

 

 

FORREST A. GARB & ASSOCIATES, INC.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

PROVED DEVELOPED PRODUCING

 

 

 

[table3.jpg] 

 

 

 

 

[table4.jpg] 

 

 

 

 

 

 

[table5.jpg] 

 

 

 

FORREST A. GARB & ASSOCIATES, INC.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

PROVED DEVELOPED NON-PRODUCING

 

 

 

[table6.jpg] 

 

 

 

 

 

[table7.jpg]

 

 

 

 

 

 

 

ATTACHMENT B

 

 

DEFINITIONS FOR OIL AND GAS RESERVES

 

 

 

 

DEFINITIONS FOR OIL AND GAS RESERVES*

 

 

 

(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.

(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.

 

 

 

 

*These Reserves Definitions are those included in the Securities and Exchange
Commission Regulation S-X as of January 1, 2010.

 

ATTACHMENT B-1

 

 

 

 

(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.

 

ATTACHMENT B-2

 

 

 

 

(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 mutiple 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
that 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.

 

ATTACHMENT B-3 

 

 

 

 

(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.

 

ATTACHMENT B-4 

 

 

 

 

(ii) Probable reserves may be assigned to areas of a reservoir adjacent to
proved reserves where data control or interpretations of available data are less
certain, even if the interpreted reservoir continuity of structure or
productivity does not meet the reasonable certainty criterion. Probable reserves
may be assigned to areas that are structurally higher than the proved area if
these areas are in communication with the proved reservoir.

 

(iii) Probable reserves estimates also include potential incremental quantities
associated with a greater percentage recovery of the hydrocarbons in place than
assumed for proved reserves.

 

(iv) See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this
section.

(19) Probabilistic estimate. The method of estimation of reserves or resources
is called probabilistic when the full range of values that could reasonably
occur for each unknown parameter (from the geoscience and engineering data) is
used to generate a full range of possible outcomes and their associated
probabilities of occurrence.

 

(20) Production costs. (i) Costs incurred to operate and maintain wells and
related equipment and facilities, including depreciation and applicable
operating costs of support equipment and facilities and other costs of operating
and maintaining those wells and related equipment and facilities. They become
part of the cost of oil and gas produced. Examples of production costs
(sometimes called lifting costs) are:

 

(A) Costs of labor to operate the wells and related equipment and facilities.

(B) Repairs and maintenance.

(C) Materials, supplies, and fuel consumed and supplies utilized in operating
the wells and related equipment and facilities.

 

(D) Property taxes and insurance applicable to proved properties and wells and
related equipment and facilities.

 

(E) Severance taxes.

 

(ii) Some support equipment or facilities may serve two or more oil and gas
producing activities and may also serve transportation, refining, and marketing
activities. To the extent that the support equipment and facilities are used in
oil and gas producing activities, their depreciation and applicable operating
costs become exploration, development or production costs, as appropriate.
Depreciation, depletion, and amortization of capitalized acquisition,
exploration, and development costs are not production costs but also become part
of the cost of oil and gas produced along with production (lifting) costs
identified above.

 

(21) Proved area. The part of a property to which proved reserves have been
specifically attributed.

 

ATTACHMENT B-5 

 

 

 

 

(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.

 

ATTACHMENT B-6 

 

 

 

 

(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).

 

(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.

 

ATTACHMENT B-7 

 

 

 

 

(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.

 

(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.

 

ATTACHMENT B-8 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

ATTACHMENT C

GENERAL COMMENTS

 

 

 

 

GENERAL COMMENTS

 

 

(1) The reserve estimates presented in this report have been calculated using
deterministic procedures. The reserves shown in this report are those estimated
to be recoverable under the new guidelines of the Securities and Exchange
Commission (SEC). The definitions for oil and gas reserves in accordance with
SEC Regulation S-X are set forth in this report.

 

(2) The estimated future net revenue shown in the cash flow projections is that
revenue which should be realized from the sale of the estimated net reserves.
Surface and well equipment salvage values have not been considered in the
revenue projections. Future net revenue as stated in this report is before the
deduction of federal income tax.

 

(3) The discounted future net revenue is not represented to be the fair market
value of these reserves. The estimated reserves included in the cash flow
projections have not been adjusted for risk.

 

(4) The reserves included in this study are estimates only and should not be
construed as exact quantities. Future conditions may affect recovery of
estimated reserves and revenue, and all categories of reserves may be subject to
revision as more performance data become available.

 

(5) Extent and character of ownership, oil and gas prices, production data,
direct operating costs, required capital expenditures, and other data furnished
have been accepted as represented. No independent well tests, property
inspections, or audits of operating expenses were conducted by our staff in
conjunction with this study.

 

(6) If investments or business decisions are to be made in reliance on these
estimates by anyone other than our client, such a person, with the approval of
our client, is invited to visit our offices at his own expense so that he can
evaluate the assumptions made and the completeness and extent of the data
available on which our estimates are based.

 

(7) Gas contract differences, including take or pay claims, are not considered
in this report. (8) Gas sales imbalances have not been taken into account in the
reserve estimates.

(9) Unless otherwise stated in the text, existing or potential liabilities
stemming from environmental conditions caused by current or past operating
practices have not been considered in this report. No costs are included in the
projections of future net revenue or in our economic analyses to restore,
repair, or improve the environmental conditions of the properties studied to
meet existing or future local, state, or federal regulations.

 

(10) Any distribution of this report or any part thereof must include these
general comments and the cover letter in their entirety.

 

(11) This report was prepared under the supervision of W.D. Harris III,
Registered Professional

Engineer No. 75222, State of Texas.

 

ATTACHMENT C-1 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

ATTACHMENT D

CONSULTING FIRM PROFILE

 

 

FORREST A. GARB & ASSOCIATES, INC.

 

INTERNATIONAL PETROLEUM CONSULTANTS

5310 HARVEST HILL ROAD, SUITE 275, LB 152

DALLAS, TEXAS 75230 – 5805 (972) 788-1110 Fax (972) 991-3160

E-Mail: forgarb@forgarb.com

Web Site: www.forgarb.com

 

 

 

We are pleased to present this profile of Forrest A. Garb & Associates, Inc.
(FGA). FGA is an international petroleum engineering and geologic consulting
firm staffed by experienced engineers and geologists. Collectively our staff has
more than a century of world-wide experience. FGA has no outside ownership. And
the firm has no direct or contingent participation in oil or gas ventures. There
are no conflicts of interest or concerns about maintaining the confidentiality
of our client’s data. The company is dedicated to providing the highest level of
integrity, technology, and service.

 

FGA expertise includes:

 

• Exploration and Prospect Evaluations

• Reserve Estimation and Evaluation Studies

• Fair Market Value Analyses

• Economic and Market Analyses

• Forensic Engineering and Expert Witness Testimony

• Reservoir Engineering

• Regional and Detailed Geological Studies

• Numeric Simulation Studies

• Special Computer Applications

• Pressure Transient Test Design, Supervision, and Evaluation

• Reservoir Characterization

• Geostatistical Studies

• Oil & Gas Production Environmental Studies

• Minerals Evaluations

• Petrophysical Analyses

 

 

 

OUR SENIOR STAFF

 

 

 

Mr. Forrest A. Garb, Founder, Chairman of the Board and Chief Engineer Emeritus,
with more than 50 years of practical petroleum industry experience, was a staff
member and then a principal of a major consulting firm for over 30 years,
serving as president and chief operating officer of this firm for the last 14 of
those years. During his tenure, he supervised or prepared over 12,500
assignments varying from simple evaluations to complex reservoir simulations.
Using this experience as a base, he assembled the best work system offered to
the oil and gas industry. The use of state of the art computers and office
equipment, together with an experienced staff, ensures economic service to the
client.

 

ATTACHMENT D-1 

 

 

 

 

 

Mr. William D. Harris III, P.E., joined FGA in August 1998, and is now the Chief
Executive Officer. Previously, he was a Vice President with DeGolyer and
MacNaughton where he prepared and supervised engineering studies and reserve and
appraisal reports for fields in many countries. Mr. Harris holds a B.S. in
Petroleum Engineering from Texas A&M University and a M.B.A. from Southern
Methodist University. He is a member of the Society of Petroleum Engineers and
is a registered professional engineer in the state of Texas.

 

Mr. John Cooper, Senior Geologist, joined Forrest A. Garb & Associates, Inc. in
2007. Mr. Cooper received his Bachelor's degree in Geology from the University
of Louisiana - Lafayette (formerly the University of Southwestern Louisiana) and
holds an MBA from Tulane University. He was employed at Great Southern Oil and
Gas, Innex Energy, and Hunt Petroleum in various geological and technical
positions, and is experienced in log analysis, geological interpretations, and
reserves evaluations using the latest technologies. Mr. Cooper is a member of
the American Association of Petroleum Geologists, the Society of Economic
Geophysicists, and the Dallas Geological & Geophysical Society.

 

Mr. Gerald K. Ebanks, Senior Geologist, received his M.A. degree in geology from
the University of Texas at Austin and has more than 35 years of experience in
petroleum geology. He was employed with Mobil Oil Corporation, and subsequently
with Ray Holifield and Associates, and PXI, Incorporated, in various geological
positions. Mr. Ebanks is a member of the American Association of Petroleum
Geologists, Dallas Geological Society, Houston Geological Society, and is a
certified petroleum geologist.

 

Ms. Stacy M. Light, P.E., Senior Vice President Petroleum Engineering, joined
Forrest A. Garb & Associates, Inc. in May 2010 as a reservoir engineer. Ms.
Light previously worked for ARCO Oil and Gas as a reservoir/operations engineer
and crude oil risk management director. She performed detailed production,
reservoir and economic analyses for both onshore and offshore properties, and
supervised engineers in the same capacity. She also performed risk management
duties, trading crude oil futures and options on the New York Mercantile
Exchange. Areas worked include onshore and offshore Gulf Coast and the
mid-continent area. Ms. Light received a B.S. in Petroleum Engineering from
Texas A&M University and is a registered professional engineer in the state of
Texas and a member of the Society of Petroleum Engineers (SPE).

 

Mr. Claude M. (Mike) Rightmire, Senior Vice President Petroleum Engineering,
joined Forrest A. Garb & Associates, Inc. in December 2007, as a reservoir
engineer. Mr. Rightmire previously worked for ARCO Alaska and ARCO Exploration &
Production Technologies as a reservoir and operations engineer and most recently
for Pinnacle Technologies as a senior engineer and project manager. His work
experience includes over 25 years of operations and reservoir engineering
assignments, reservoir engineering research and applications development work,
and fracture stimulation engineering. Mr. Rightmire holds a B.S. in Petroleum
Engineering from Texas A&M University, a B.S. in Biological Science from the
University of Alaska Anchorage, and is a member of the Society of Petroleum
Engineers (SPE).

 

Ms. Sandra W. Wall, Senior Vice President Petroleum Engineering, joined Forrest
A. Garb & Associates, Inc. in August 2006. Ms. Wall previously worked for Texas
Eastern Corp., Exploration and Production Division, and Transwestern Pipeline
Company as a reservoir engineer and project manager. She performed detailed
reservoir and economic analyses for both onshore and offshore properties, ran 3D
computer simulation studies for massive hydraulic

 

ATTACHMENT D-2 

 

 

 

 

 

fracturing, water floods, and CO2 floods, and coordinated the development of
exploration projects. Areas worked include onshore and offshore Gulf Coast,
Alaska North Slope, Rocky Mountains, offshore California, offshore Australia,
Indonesia, and North Sea. Ms. Wall holds a B.S. in Petroleum Engineering from
Texas A&M University, a M.B.A. from Houston Baptist University, and is a member
of the Society of Petroleum Engineers (SPE).

 

 

THE COMPANY

 

Forrest A. Garb & Associates, Inc. (FGA) is a consulting firm comprised of
professional petroleum engineers, geologists, and technical support personnel
with diversified backgrounds in all phases of the petroleum and energy
industries. The group prides itself in offering the highest level of ethics,
state of the art technology, and prompt dedicated service to our clients.

 

FGA professionals have extensive experience in the world's important hydrocarbon
producing areas, including North and South America, the Middle East, Australia,
New Zealand, Indonesia, Turkey, North Africa, Russia, China, Thailand, Myanmar,
West Africa, India, the North Sea, Alaska, and Mexico.

 [globe.jpg]

 

The firm offers a complete range of geological and engineering services - from
screening exploration prospects and designing development drilling projects to
estimating reserves, forecasting future production, and presenting economic
analyses. Major financial institutions accept the validity of our studies,
particularly in the areas of reserve estimation and appraisal. The fair market
value analysis technique developed by FGA is being applied by some of industry’s
largest players.

 

Major integrated and independent oil and gas companies have used our estimates
of future production rates and available hydrocarbon resources to design
facilities, and to establish contract terms.

 

FGA is a leader in the development and application of computers to the daily
requirements of petroleum engineering. Mainframe programs, hand-held computer
programs, and personal computer systems designed by Mr. Garb have been installed
in many major integrated oil company offices around the world.

 

 

 

Associations with facilities design, seismic interpretation, petrology, and
environmental firms, renowned in their own right, enable the FGA organization to
offer a complete service to its clients under one master contract.

 

Because the company has no hydrocarbon production and because it has no outside
ownership to dictate opinions, the determinations of the firm are independent.
Its studies are without bias and are based on the best interpretation of all
available data after processing with "state of the art" methods and equipment.

 

ATTACHMENT D-3 

 

 

 

 

 

 

FGA restricts its activities exclusively to consultation; it does not accept
contingent fees nor does it own operating interests in any oil, gas, or mineral
properties. The firm subscribes to a code of professional conduct, and its
employees actively support their related technical and professional societies.

 

The entire FGA staff is dedicated to providing each client with a personalized
and cost- efficient approach to serve their individual needs.

 

ATTACHMENT D-4