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,


 


 


 


Forrest
A. Garb
& Associates,
Inc.


Texas
Registered
Engineering
Firm
F-629


 


 


 


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




    	 



    	 



    

 


 


 


 


ATTACHMENT A-1




    	 



    	 



    

 


  


 


ATTACHMENT A-2







    	 



    	 



    

FORREST
A. GARB & ASSOCIATES, INC.


 


 


 


 


 


 


 


 


 


 


 


 


 


 


 


PROVED DEVELOPED
PRODUCING




    	 



    	 



    

 


 


 







    	 



    	 



    

 


 


 


 





    	 



    	 



    

 


 


 


 




    	 



    	 



    

FORREST
A. GARB & ASSOCIATES, INC.


 


 


 


 


 


 


 


 


 


 


 


 


 


 


 


PROVED
DEVELOPED NON-PRODUCING




    	 



    	 



    

 


 


 




    	 



    	 



    

 


 





 




    	 



    	 



    

 


 


 


 


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.


 


 


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