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EST. OF FUTURE RESERVES AND REVENUES
U. S. SEC REPORT
WILKINSON COUNTY, MISSISSIPPI
TO LEXARIA CORPORATION
AS OF OCTOBER 31, 2011

 

December 12, 2011

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Table of Contents

Report 1 Report Definitions 7 SEC Definitions 8 Economic Projections 19
Production Decline Curves 37 Lexaria Settlement Statement dated 10/7/2011 49
Other Cost and Expense Data 58 Firm Resume 62

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6161 Perkins Road, Ste. 2C Phone (225) 765-1914 Baton Rouge, La. 70808 FAX:
(225) 765-1917

December 12, 2011

Lexaria Corporation
Attn: Mr. Chris Bunka, President
700 West Pender, Suite 604
Vancouver, BC V6C 1G8

Re: Estimate of Future Reserves and Revenues   U. S. Securities and Exchange
Commission (SEC) Report   Wilkinson County, Mississippi   As of October 31, 2011

Dear Mr. Bunka,

Following your request, we have estimated the future net reserves and revenues
for Lexaria Corporation (Lexaria) located in Wilkinson County, Mississippi. The
proved developed reserves are located in Belmont Lake field and consist of four
(4) producing wells in an oil zone called the Frio Sand. These wells are gas
lifted by gas supplied by the F-29. Lexaria owns the same interest in the F-29
as in the other producing wells. In addition, lease operating expenses have been
lowered by constructing a saltwater disposal well in Belmont Lake. The proved
un-developed properties consist of four (4) Frio oil locations which off-set the
four existing wells and are located within an area of geological well control.
Since last year’s report, no wells were drilled. However, the F-12-5 was
successfully worked over in the Frio Sand and has been restored to production.

There are also two Probable objectives included in this report. One Probable
objective is a shut-in gas zone in the PP F-39. The other Probable objective is
a behind pipe oil zone in the PP F-39. There are no immediate plans to place the
PP F-39 on-line therefore we estimated first production to be January of 2013.
The following are our conclusions for the estimates of future reserves and
revenues for Lexaria Corporation, as of October 31, 2011.

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Lexaria Corporation Phase I Drilling Program Wilkinson County, MS As of October
31, 2011   SEC Pricing 1st of the Month Average Spot Prices

               CASH   NET OIL, NET GAS, CASH FLOW,      FLOW, Category MBBLS
MMCF      UNDISC DISC @ 10% Proved Developed 68.07 0.00 $4,931,906 $3,531,796
Prove Undeveloped 87.72 0.00 $6,528,571 $4,539,775 Total Proved (1P) 155.79 0.00
$11,460,477 $8,071,571           Probable – Shut-in 0.00 15.04 $26,437 $21,028
Probable – Behind Pipe 2.38 0.00 $179,801 $114,237 Total Probable 2.38 15.04
$206,238 $135,265           Total Proved & Probable (2P) 158.17 15.04
$11,666,715 $8,206,836

The working interests and net revenue interests used to calculate these net
reserves and revenues were supplied by Lexaria Corporation1. The following is a
summary of these interests.

  W.I. Before W.I. After Net Revenue Well Completion Completion Interest F-12-1
42% 35.7% 27.3036947% F-12-3 42% 35.7% 27.3036947% F-12-4 42% 35.7% 27.3036947%
F-12-4 Nonconsent2 8% 6.8% 5.2007038% F-12-5 42% 35.7% 27.3036947% F-12-5
Nonconsent 3 8% 6.8% 5.2007038% F-12-6 42% 35.7% 27.3036947% F-12-7 42% 35.7%
27.3036947% F-12-8 42% 35.7% 27.3036947% F-12-9 42% 35.7% 27.3036947% F-39 42%
35.7% 27.3036947%

_______________________
1 Statement dated October 7, 2011 attached herein. Interests on statement may
not be consistent due to farm-outs.
2 F-12-4 interest reverts to original owner after a 500% penalty ($216,976
effective 10/31/11) is recouped by Lexaria.
3 F-12-5 interest reverts to original owner after a 500% penalty ($188,052
effective 10/31/11) is recouped by Lexaria.

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CLASSIFICATIONS AND DEFINITIONS

The classifications and definitions for proved reserves are consistent with
those of the SEC4.

The reserves presented herein are un-risked and because of this, prudence should
be exercised in interpreting the revenues generated from present and future
potential production. Because of the distinct classification (proved and
probable) and category (producing, shut-in and undeveloped) of reserves, likely
differences in uncertainty arise and caution should be used when combining
reserves of different classes and categories.

RESERVE ESTIMATES

Reserve estimates were made utilizing sufficient historical production data with
cum-cut plots (for the F-12-1 and F-12-3A) and a combination of volumetrics and
analogy of the Frio Sand in its final stages of production in the Stamps field
located approximately 2 miles away. The Stamps field, which is similar in size,
has been estimated to ultimately produce almost 900,000 Bbls of oil.

For the volumetric calculation, 3-D maps, geological maps, logs, core analysis
and test data were supplied by Griffin & Griffin, LLC (Griffin), the operator.
This data was analyzed and utilized in calculating porosity, water saturation,
thickness, temperature and pressure for the Frio Sand.

The Guthrie and Greenberger correlation was utilized to calculate the oil
reserves found in Belmont Lake and the behind pipe in the F-39 well. Guthrie and
Greenberger used multiple analysis methods to find a correlation between oil
sandstone reservoirs under forces of a water drive mechanism and five variables
- permeability, water saturation, viscosity, porosity and thickness. This was a
continuation of a study originally performed by Craze and Buckley in 1945 and
eventually culminated into API Bulletin D14 in 1967 and SPE Paper No. 2068
written by J. J. Arps in 1968.

The Legatski Correlation5 was used in determining gas reserves found in the F-39
well. This correlation predicts the recovery of gas reserves from water-drive
reservoirs. However, the range of sweep efficiency can be altered from a
depletion drive reservoir to a strong water-drive reservoir.

Decline curves were then used in conjunction with these estimates to forecast
the future cash flow from the producing properties. Production was generally
updated through October 2011. Initial rates for the drilling locations were
estimated to be 45 BOPD with declines of 5%/year until the calculated oil
reserves are depleted. The forecast was terminated if a property began to
produce below the economic limit.

_______________________
4 A summary of the SEC oil and gas reserve definitions are attached herein and a
more complete explanation of these guidelines can be found at:
http://www.spee.org/images/PDFs/ReferencesResources/SEC_RevisedRules.pdfare.
5 SPE Paper No. 899, Displacement of Gas from Porous Media by Water, Max W.
Legatski et al

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For those properties which are currently shut-in and/or in need of a work-over,
Griffin has advised that when gas prices rise to support the economy of
operations, the wells will again be turned on and/or worked over. There are no
plans or AFE at this time to work-over or turn these shut-in wells on.

Attached herein are one-line and detailed economic summaries for Lexaria’s
interest in this drilling program. Also attached are the decline curves for the
wells and future wells.

PRODUCT PRICES

The oil and natural gas prices used in this report are the 12-month average St.
James Sweet crude and Henry Hub spots, calculated as the un-weighted arithmetic
average of the first-day-of-the-month price for each month within the 12-month
period prior to the end of the reporting period. These prices of $108.74/Bbl and
$4.20/Mcf were held constant throughout the life of the forecast.

COSTS AND EXPENSES

Costs used to forecast the drilling and completing of the F-12-6, 12-7, 12-8 and
12-9 were taken directly from the signed November 12, 2010 AFE Election6 and are
in the amount of $568,478. However, the estimated cost of the 12-6 and 12-7 used
in the forecast are higher than the amount listed in the AFE Election due to
future pipeline installation. The pipeline to be installed will be utilized for
the 12-8 and 12-9 therefore the cost will not be included in the drilling and
completion for those wells and the costs match the AFE election.

Operating expenses were obtained from the revenue and billing statements which
were supplied by Lexaria. Expenses from the time when the saltwater disposal
well was installed in May of 2011were averaged monthly since this is a better
indicator of what expenses in the future will be. Attached herein is a table
showing the lease operating expenses for the wells in Belmont Lake field. An
estimate for the lease operating expense for the F-39 well in the amount of
$2,880/month was provided by the operator.

PLUGGING AND ABANDONMENT / RECLAMATION COSTS

Abandonment and reclamation costs were estimated to be $2.00 per foot (average
measured depth of 2,800 ft. for Belmont Lake wells) and were applied at the end
of the life for each property separately.

_______________________
6 Attached is the AFE Election for drilling the F-12-6 & F-12-7.

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PROJECTIONS

The attached reserve and revenue projections are on a calendar year basis.

REPORT QUALIFICATIONS

The estimated revenues, both discounted and undiscounted, are not represented as
constituting the fair market value of the properties. Rather, these projections
are intended to provide investors with an indication of the relative quantity of
reserves that is likely to be extracted in the future based on the assigned
classification and categorization.

Veazey & Associates, LLC has made no independent examination of titles to the
appraised properties, nor has the actual degree or type of interest owned been
independently confirmed. The data used in our evaluation were supplied by
Lexaria, Griffin or obtained from public records of the Mississippi State Oil
and Gas Board and/or published industry sources and were considered accurate. A
field inspection of the properties was not made nor considered necessary for the
purpose of this report.

We did not inspect the properties nor conduct independent well tests.
Environmental studies were not conducted and are beyond the scope of this
investigation. This study is based on the assumption that these properties are
not negatively affected by the existence of hazardous substances, non-hazardous
substances, naturally occurring radioactive material (“NORM”) or other
detrimental environmental conditions or the possibility of restoration
obligations or responsibilities that may be imposed by relevant federal, state
or local regulatory agencies. The appraiser is not an expert in the
identification of hazardous substances, non-hazardous substances, or detrimental
environmental conditions. It is possible that tests and inspections made by a
qualified environmental expert could reveal the existence of hazardous or
non-hazardous material and environmental conditions in, on, under or around
these properties or other properties or facilities held in connection therewith
that could negatively affect their value.

Ownership, product prices and other factual data have been accepted as
represented by Lexaria and Griffin. We have generally tested the validity of
these data and believe the information is correct.

The quality of available information and the application of engineering
interpretation and judgment affect the reliability of any reserve estimate. In
our opinion, the reserve estimates presented herein are reasonable. These
reserves should be accepted with the understanding that drilling activity or
additional information subsequent to the date of this report might require their
revision.

In performing this study, we have not considered matters in which legal or

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SEC Proved Oil and Gas Reserve Definitions

 * Proved Reserves
 * Proved Developed Reserves
 * Proved Undeveloped Reserves
 * Reserve Status Categories - (producing, non-producing, etc)

INTRODUCTION

Financial Accounting and Reporting for Oil and Gas Producing Activities Pursuant
to the Federal Securities Laws and the Energy Policy and Conservation Act of
1975

Reg. § 210.4 -10.

This section prescribes financial accounting and reporting standards for
registrants with the Commission engaged in oil and gas producing activities in
filings under the federal securities laws and for the preparation of accounts by
persons engaged, in whole or in part, in the production of crude oil or natural
gas in the United States, pursuant to Section 503 of the Energy Policy and
Conservation Act of 1975 [42 U.S.C. 6383] ("EPCA") and section 11(c) of the
Energy Supply and Environmental Coordination Act of 1974 [IS U.S.C. 796]
("ESECA"), as amended by section 505 of EPCA. The application of this section to
those oil and gas producing operations of companies regulated for rate-making
purposes on an individual-company-cost-of-service basis may, however, give
appropriate recognition to differences arising because of the effect of the
rate-making process.

Exemption. Any person exempted by the Department of Energy from any
record-keeping or reporting requirements pursuant to Section 11(c) of ESECA, as
amended, is similarly exempted from the related provisions of this section in
the preparation of accounts pursuant to EPCA. This exemption does not affect the
applicability of this section to filings pursuant to the federal securities
laws.

Definitions

(a) Definitions. The following definitions apply to the terms listed below as
they are used in this section:

(1) Oil and gas producing activities.

(i) Such 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 and/or for the purpose of removing the oil or gas from existing
reservoirs on those properties.

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(C) The construction, drilling and production activities necessary to retrieve
oil and gas from its natural reservoirs, and the acquisition, construction,
installation, and maintenance of field gathering and storage systems -including
lifting the oil and gas to the surface and gathering, treating, field processing
(as in the case of processing gas to extract liquid hydrocarbons) and field
storage. For purposes of this section, the oil and gas production function shall
normally be regarded as terminating at the outlet valve on the lease or field
storage tank; if unusual physical or operational circumstances exist, it may be
appropriate to regard the production functions as terminating at the first point
at which oil, gas, or gas liquids are delivered to a main pipeline, a common
carrier, a refinery, or a marine terminal.

(ii) Oil and gas producing activities do not include:

(A) The transporting, refining and marketing of oil and gas.

(B) Activities relating to the production of natural resources other than oil
and gas.

(C) The production of geothermal steam or the extraction of hydrocarbons as a
byproduct of the production of geothermal steam or associated geothermal
resources as defined in the Geothermal Steam Act of 1970.

(D) The extraction of hydrocarbons from shale, tar sands, or coal.

(2) Proved oil and gas reserves. Proved oil and gas reserves are the estimated
quantities of crude oil, natural gas, and natural gas liquids which geological
and engineering data demonstrate with reasonable certainty to be recoverable in
future years from known reservoirs under existing economic and operating
conditions, i.e., prices and costs as of the date the estimate is made. Prices
include consideration of changes in existing prices provided only by contractual
arrangements, but not on escalations based upon future conditions.

(i) Reservoirs are considered proved if economic producibility is supported by
either actual production or conclusive formation test. The area of a reservoir
considered proved includes (A) that portion delineated by drilling and defined
by gas-oil and/or oil-water contacts, if any; and (B) the immediately adjoining
portions not yet drilled, but which can be reasonably judged as economically
productive on the basis of available geological and engineering data. In the
absence of information on fluid contacts, the lowest known structural occurrence
of hydrocarbons controls the lower proved limit of the reservoir.

(ii) Reserves which can be produced economically through application of improved
recovery techniques (such as fluid injection) are included in the "proved"
classification when successful testing by a pilot project, or the operation of
an installed program in the reservoir, provides support for the engineering
analysis on which the project or program was based.

(iii) Estimates of proved reserves do not include the following:

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(A) oil that may become available from known reservoirs but is classified
separately as "indicated additional reserves";

(B) crude oil, natural gas, and natural gas liquids, the recovery of which is
subject to reasonable doubt because of uncertainty as to geology, reservoir
characteristics, or economic factors;

(C) crude oil, natural gas, and natural gas liquids, that may occur in undrilled
prospects; and

(D) crude oil, natural gas, and natural gas liquids, that may be recovered from
oil shales, coal, gilsonite and other such sources.

RESERVE STATUS CATEGORIES

(3) Proved developed oil and gas reserves. Proved developed oil and gas reserves
are reserves that can be expected to be recovered through existing wells with
existing equipment and operating methods. Additional oil and gas expected to be
obtained through the application of fluid injection or other improved recovery
techniques for supplementing the natural forces and mechanisms of primary
recovery should be included as "proved developed reserves" only after testing by
a pilot project or after the operation of an installed program has confirmed
through production response that increased recovery will be achieved.

(4) Proved undeveloped reserves. Proved undeveloped oil and gas reserves are
reserves 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. Reserves on undrilled acreage shall be limited to those drilling
units offsetting productive units that are reasonably certain of production when
drilled. Proved reserves for other undrilled units can be claimed only where it
can be demonstrated with certainty that there is continuity of production from
the existing productive formation. Under no circumstances should estimates, for
proved 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 tests
in the area and in the same reservoir.

(5) Proved properties. Properties with proved reserves.

UNPROVED RESERVES

(6) Unproved properties. Properties with no proved reserves.

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

(8) 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.

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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.

(9) 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.

(10) Exploratory well. A well drilled to find and produce oil or gas in an
unproved area, to find a new reservoir in a field previously found to be
productive of oil or gas in another reservoir, or to extend a known reservoir.
Generally, an exploratory well is any well that is not a development well, a
service well, or a stratigraphic test well as those items are defined below.

(11) 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.

(12) 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.

(13) Stratigraphic test well. A drilling effort, geologically directed, to
obtain information pertaining to a specific geologic condition. Such wells
customarily arc drilled without the intention of being completed for hydrocarbon
production. This classification also includes tests identified as core tests and
all types of expendable holes related to hydrocarbon exploration. Stratigraphic
test wells are classified as (i) "exploratory type," if not drilled in a proved
area, or (ii) "development type," if drilled in a proved area.

(14) 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.

(15) 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:

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(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.

(16) 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.

(17) 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.

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(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.

Successful Efforts Method

(b) A reporting entity that follows the successful efforts method shall comply
with the accounting and financial reporting disclosure requirements of Statement
of Financial Accounting Standards No. 19, as amended.

Full Cost Method

(c) Application of the full cost method of accounting. A reporting entity that
follows the full cost method shall apply that method to all of its operations
and to the operations of its subsidiaries, as follows:

(1) Determination of cost centers. Cost centers shall be established-on a
country-by-country basis.

(2) Costs to be capitalized. All costs associated with property acquisition,
exploration, and development activities (as defined in paragraph (a) of this
section) shall be capitalized within the appropriate cost center. Any internal
costs that are capitalized shall be limited to those costs that can be directly
identified with acquisition, exploration, and development activities undertaken
by the reporting entity for its own account, and shall not include any costs
related to production, general corporate overhead, or similar activities.

(3) Amortization of capitalized costs. Capitalized costs within a cost center
shall be amortized on the unit-of-production basis using proved oil and gas
reserves, as follows:

(i) Costs to be amortized shall include (A) all capitalized costs, less
accumulated amortization, other than the cost of properties described in
paragraph (ii) below; (B) the estimated future expenditures (based on current
costs) to be incurred in developing proved reserves; and (C) estimated
dismantlement and abandonment costs, net of estimated salvage values.

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(ii) The cost of investments in unproved properties and major development
projects may be excluded from capitalized costs to be amortized, subject to the
following:

(A) All costs directly associated with the acquisition and evaluation of
unproved properties may be excluded from the amortization computation until it
is determined whether or not proved reserves can be assigned to the properties,
subject to the following conditions: (1) Until such a determination is made, the
properties shall be assessed at least annually to ascertain whether impairment
has occurred. Unevaluated properties whose costs are individually significant
shall be assessed individually. Where it is not practicable to individually
assess the amount of impairment of properties for which costs are not
individually significant, such properties may be grouped for purposes of
assessing impairment. Impairment may be estimated by applying factors based on
historical experience and other data such as primary Lease terms of the
properties, average holding periods of unproved properties, and geographic and
geologic data to groupings of individually insignificant properties and
projects. The amount of impairment assessed under either of these methods shall
be added to the costs to be amortized. (2) The costs of drilling exploratory dry
holes shall be included in the amortization base immediately upon determination
that the well is dry. (3) If geological and geophysical costs cannot be directly
associated with specific unevaluated properties, they shall be included in the
amortization base as incurred. Upon complete evaluation of a property, the total
remaining excluded cost (net of any impairment) shall be included in the full
cost amortization base.

(B) Certain costs may be excluded from amortization when incurred in connection
with major development projects expected to entail significant costs to
ascertain the quantities of proved reserves attributable to the properties under
development (e.g., the installation of an offshore drilling platform from which
development wells are to be drilled, the installation of improved recovery
programs, and similar major projects undertaken in the expectation of
Significant additions to proved reserves). The amounts which may be excluded are
applicable portions of (1) the costs that relate to the major development
project and have not previously been included in the amortization base, and (2)
the estimated future expenditures associated with the development project. The
excluded portion of any common costs associated with the development project
should be based, as is most appropriate in the circumstances, on a comparison of
either (i) existing proved reserves to total proved reserves expected to be
established upon completion of the project, or (ii) the number of wells to which
proved reserves have been assigned and total number of wells expected to be
drilled. Such costs may be excluded from costs to be amortized until the earlier
determination of whether additional reserves are proved or impairment occurs.

(C) Excluded costs and the proved reserves related to such costs shall be
transferred into the amortization base on an ongoing (well-by-well or
property-by-property) basis as the project is evaluated and proved reserves
established or impairment determined. Once proved reserves are established,
there is no further justification for continued exclusion from the full cost
amortization base even if other factors prevent immediate production or
marketing.

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(iii) Amortization shall be computed on the basis of physical units, with oil
and gas converted to a common unit of measure on the basis of their approximate
relative energy content, unless economic circumstances (related to the effects
of regulated prices) indicate that use of units of revenue is a more appropriate
basis of computing amortization. In the latter case, amortization shall be
computed on the basis of current gross revenues (excluding royalty payments and
net profits disbursements) from production in relation to future cross revenues,
based on current prices (including consideration of changes in existing prices
provided only by contractual arrangements), from estimated production of proved
oil and gas reserves. The effect of a significant price increase during the year
on estimated future gross revenues shall be reflected in the amortization
provision only for the period after the price increase occurs.

(iv) In some cases it may be more appropriate to depreciate natural gas cycling
and processing plants by a method other than the unit-of-production method.

(v) Amortization computations shall be made on a consolidated basis, including
investees accounted for on a proportionate consolidation basis. Investees
accounted for on the equity method shall be treated separately.

(4) Limitation on capitalized costs:

(i) For each cost center, capitalized costs, less accumulated amortization and
related deferred income taxes, shall not exceed an amount (the cost center
ceiling) equal to the sum of:

(A) the present value of estimated future net revenues computed by applying
current prices of oil and gas reserves (with consideration of price changes only
to the extent provided by contractual arrangements) to estimated future
production of proved oil and gas reserves as of the date of the latest balance
sheet presented, less estimated future expenditures (based on current costs) to
be incurred in developing and producing the proved reserves computed using a
discount factor of ten percent and assuming continuation of existing economic
conditions; plus

(B) the cost of properties not being amortized pursuant to paragraph (i)(3)(ii)
of this section; plus

(C) the lower of cost or estimated fair value of unproven properties included in
the costs being amortized; less

(D) income tax effects related to differences between the book and tax basis of
the properties referred to in paragraphs (i)(4)(i)(B) and (C) of this section.

(ii) If unamortized costs capitalized within a cost center, less related
deferred income taxes, exceed the cost center ceiling, the excess shall be
charged to expense and separately disclosed during the period in which the
excess occurs. Amounts thus required to be written off shall not be reinstated
for any subsequent increase in the cost center ceiling.

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(5) Production costs. All costs relating to production activities, including
workover costs incurred solely to maintain or increase levels of production from
an existing completion interval, shall be charged to expense as incurred.

(6) Other transactions. The provisions of paragraph (h) of this section,
"Mineral property conveyances and related transactions if the successful efforts
method of accounting is followed," shall apply also to those reporting entities
following the full cost method except as follows:

(i) Sales and abandonments of oil and gas properties. Sales of oil and gas
properties, whether or not being amortized currently, shall be accounted for as
adjustments of capitalized costs, with no gain or loss recognized, unless such
adjustments would significantly alter the relationship between capitalized costs
and proved reserves of oil and gas attributable to a cost center. For instance,
a significant alteration would not ordinarily be expected to occur for sales
involving less than 25 percent of the reserve quantities of a given cost center.
If gain or loss is recognized on such a sale, total capitalization costs within
the cost center shall be allocated between the reserves sold and reserves
retained on the same basis used to compute amortization, unless there are
substantial economic differences between the properties sold and those retained,
in which case capitalized costs shall be allocated on the basis of the relative
fair values of the properties. Abandonments of oil and gas properties shall be
accounted for as adjustments of capitalized costs; that is, the cost of
abandoned properties shall be charged to the full cost center and amortized
(subject to the limitation on capitalized costs in paragraph (b) of this
section).

(ii) Purchases of reserves. Purchases of oil and gas reserves in place
ordinarily shall be accounted for as additional capitalized costs within the
applicable cost center; however, significant purchases of production payments or
properties with lives substantially shorter than the composite productive life
of the cost center shall be accounted for separately.

(iii) Partnerships, joint ventures and drilling arrangements.

(A) Except as provided in subparagraph (i)(6)(i) of this section, all
consideration received from sales or transfers of properties in connection with
partnerships, joint venture operations, or various other forms of drilling
arrangements involving oil and gas exploration and development activities (e.g.,
carried interest, turnkey wells, management fees, etc.) shall be credited to the
full cost account, except to the extent of amounts that represent reimbursement
of organization, offering, general and administrative expenses, etc., that are
identifiable with the transaction, if such amounts are currently incurred and
charged to expense.

(B) Where a registrant organizes and manages a limited partnership involved only
in the purchase of proved developed properties and subsequent distribution of
income from such properties, management fee income may be recognized provided
the properties involved do not require aggregate development expenditures in
connection with production of existing proved reserves in excess of 10% of the
partnership's recorded cost of such properties. Any income not recognized as a
result of this limitation would be credited to the full cost account and
recognized through a lower amortization provision as reserves are produced.

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(iv) Other services. No income shall be recognized in connection with
contractual services performed (e.g. drilling, well service, or equipment supply
services, etc.) in connection with properties in which the registrant or an
affiliate (as defined in § 210.1 -02(b)) holds an ownership or other economic
interest, except as follows:

(A) Where the registrant acquires an interest in the properties in connection
with the service contract, income may be recognized to the extent the cash
consideration received exceeds the related contract costs plus the registrant's
share of costs incurred and estimated to be incurred in connection with the
properties. Ownership interests acquired within one year of the date of such a
contract are considered to be acquired in connection with the service for
purposes of applying this rule. The amount of any guarantees or similar
arrangements undertaken as part of this contract should be considered as part of
the costs related to the properties for purposes of applying this rule.

(B) Where the registrant acquired an interest in the properties at least one
year before the date of the service contract through transactions unrelated to
the service contract, and that interest is unaffected by the service contract,
income from such contract may be recognized subject to the general provisions
for elimination of intercompany profit under generally accepted accounting
principles.

(C) Notwithstanding the provisions of (A) and (B) above, no income may be
recognized for contractual services performed on behalf of investors in oil and
gas producing activities managed by the registrant or an affiliate. Furthermore,
no income may be recognized for contractual services to the extent that the
consideration received for such services represents an interest in the
underlying property.

(D) Any income not recognized as a result of these rules would be credited to
the full cost account and recognized through a lower amortization provision as
reserves are produced.

(7) Disclosures. Reporting entities that follow the full cost method of
accounting shall disclose all of the information required by paragraph (k) of
this section, with each cost center considered as a separate geographic area,
except that reasonable groupings may be made of cost centers that are not
significant in the aggregate. In addition:

(i) For each cost center for each year that an income statement is required,
disclose the total amount of amortization expense (per equivalent physical unit
of production if amortization is computed on the basis of physical units or per
dollar of gross revenue from production if amortization is computed on the basis
of gross revenue).

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(ii) State separately on the face of the balance sheet the aggregate of the
capitalized costs of unproved properties and major development projects that are
excluded, in accordance with paragraph (i)(3) of this section, from the
capitalized costs being amortized. Provide a description in the notes to the
financial statements of the current status of the significant properties or
projects involved, including the anticipated timing of the inclusion of the
costs in the amortization computation. Present a table that shows, by category
of cost, (A) the total costs excluded as of the most recent fiscal year; and (B)
the amounts of such excluded costs, incurred (1) in each of the three most
recent fiscal years and (2) in the aggregate for any earlier fiscal years in
which the costs were incurred. Categories of cost to be disclosed include
acquisition costs, exploration costs, development costs in the case of
significant development projects and capitalized interest.

Income taxes

(d) Income taxes. Comprehensive inter-period income tax allocation by a method
which complies with generally accepted accounting principles shall be followed
for intangible drilling and development costs and other costs incurred that
enter into the determination of taxable income and pretax accounting income in
different periods.

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Report Definitions

Authority for Expenditure

(AFE) A document prepared by the operator that lists the estimated costs of
drilling, completing, working over or plugging a well or some other major cost
associated with the well or lease. The document is provided to partners for
approval. Failure to approve an AFE may result in a penalty or loss of interest
depending on contractual

Barrels of Oil Equivalent

(BOE) Barrels of Oil Equivalent is a unit of energy based on the approximate
energy released from burning one barrel of oil roughly equal to 6,000 cubic feet
of natural gas.

Behind Pipe  

A term referring to up-hole potential in another sand encountered in the same
well.

BOPD  

Acronym for "Barrels of Oil per Day" and refers to the volume of oil in barrels
that are produced in a 24 hour day.

BWPD

Acronym for "Barrels of Water per Day" and refers to the volume of water in
barrels that are produced in a 24 hour day.

Cash Flow  

Cash flow is the profit the interest owner receives from its share of revenue
after taxes, expenses and costs are

Completion

A generic term used to describe the down hole assembly and equipment required to
enable production of oil and/or gas from a well.

Cum Cut Plot

A graph of water cut or oil cut on the ordinate (y-axis) and cumulative oil
production on the abscissa (x-axis) used to predict ultimate cumulative oil
production at some limit of water or oil cut.

Decline Curve

A method of estimating petroleum reserves by determining the natural production
decline of a well and extrapolating to predict future production.

Depletion Drive  

The reservoir drive mechanism in which oil is produced by the expansion of the
volume of the gas in solution.

Fair Market Value

(FMV) The Fair Market Value is defined as the amount at which property would
transfer between a willing buyer and a willing seller, neither being under any
compulsion to buy or sell and both having reasonable knowledge of the relevant
facts.

Farmout

A contractual agreement with an owner who holds a working interest in an oil and
gas lease to assign all or part of that interest to another party in exchange
for fulfilling contractually specified conditions such as drilling a well or
installing equipment.

Gas Lift

A method of raising oil in the wellbore from a lower depth to the surface by
injecting gas in the well from the casing through the tubing via gas lift valves
installed in the tubing.

Gross Reserves (Oil or Gas)  

The volume of reserves attributed to the whole (100%).

Internal Rate of Return

(IROR) The interest rate which makes the present value of the revenues equal to
the present value of the expenditures. In other words, the discounting rate
which makes the net present value equal to zero.

Lease Operating Expense

(LOE) The Lease Operating Expenses include such things as direct operating
costs, overhead, production (severance) taxes and ad valorem (property) taxes
attributed to the lease (or well) and paid in the year which they are incurred .
In the detailed economic projection(s), Net Lease Cost or Net Well Cost may be
synonymous with the LOEs paid by the working interest ownership being evaluated.

MCFD

Acronym for "Mcf of Gas per Day" and refers to the volume of gas in thousand
cubic feet that are produced in a 24 hour day.

Naturally Occurring  

(NORM) Naturally Occurring Radioactive Material is radio active deposits such as
scale found in tubulars.

Radioactive Material (NORM)  

Net Ad Valorem Tax  

The property tax paid by the interest owner on drilling rigs, production
equipment, etc.

Net Investment

As related to the economic forecast(s) attached herein, it is either the
drilling, completion or plugging costs to the working interest being evaluated.

Net Lease Cost  

See Lease Operating Expense.

Net Production Tax

The state severance tax that the interest owner pays on oil and/or gas levied
when removed from the ground. The tax can be levied as a percent of the mineral
value or in cents per barrel of oil/mcf of gas.

Net Reserves (Oil or Gas)  

The volume of reserves attributed to a certain interest.

Net Revenue

Net revenue is the inflow of money as a result of oil and gas sales that the
interest owner receives from its share of production. This income is before
paying taxes, expenses and costs.

Net Revenue Interest

(NRI) The fractional share (usually between 3/4 and 7/8) of all oil and gas
production revenue from the leased premises that goes to the working interest.

Net Well Cost  

See Lease Operating Expense.

On-line  

Refers to the status of a well that is producing.

Overriding Royalty Interest  

Ownership in a percentage of production revenues, free of the cost of
production.

Payout

(PO) Payout is the length of time after initial investment until accumulated net
revenues from production equal all costs of leasing, exploring, drilling and
operating.

Permeability

A measure of the ability of a rock to conduct a fluid through its interconnected
pore space when that fluid is at 100% saturation.

Plug and Abandonment

(P&A) A term referring to when a well is shut-in permenantly and closed off from
the surface by placing cement plugs (among other techniques) in the wellbore to
isolate the higher pressured formation sands from the surface. Many times the
well casing is cut below the plow depth and a steel plate welded on top, but in
some states the casing is extended above ground and flagged.

Porosity  

The ratio of volume of the pore spaces in rock grains compared to the total rock
volume.

Reserves

The unproduced but recoverable oil and/or gas in place in a formation
(reservoir). There are four basic criteria which must be satisfied for petroleum
deposits to be considered reserves: they must be discovered, recoverable,
commercial and remaining as of the effective date of the evaluation. Please
refer to the Petroleum Resources Management System definitions for
classification and categorization of reserves.

Reservoir  

A subsurface porous, permeable rock body in which oil or gas or both can be
stored.

Return on Investment  

(ROI) The ratio of profit to investment (also called "profit to investment
ratio").

Royalty Interest

(RI) The fractional share (usually between 1/8 and 1/4) of the total oil and gas
production revenue from the leased premises free of all costs and expenses
(except taxes).

Sand (Formation)  

A general term applied in the oil and gas industry to refer to the strata of
interest.

Shut-in  

Refers to the status of a well that is not producing.

SWD  

Acronym for Saltwater Disposal Well

Sweep Efficiency  

A measure of the effectiveness in the water displacing the oil as the water
sweeps through the reservoir.

Thickness  

Usually refers to bed or sand thickness.

Viscosity  

One of the physical properties of a liquid which is a direct measurement of its
ability to flow.

Volumetric Calculation

A method of estimating petroleum reserves by determining the net thickness,
porosity, water saturation and other properties of the oil and/or gas and
reservoir.

Water Drive

The reservoir drive mechanism in which oil is produced by the expansion of the
volume of the underlying water, which forces the oil into the wellbore.

Water Saturation  

The percentage of the pore volume of a rock occupied by water.

Working Interest

(WI) The operating interest under an oil and gas lease which bears the full cost
and expense of the lease including drilling, development and operating expenses.

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SEC Proved Oil and Gas Reserve Definitions

 * Proved Reserves
 * Proved Developed Reserves
 * Proved Undeveloped Reserves
 * Reserve Status Categories - (producing, non-producing, etc)

INTRODUCTION

Financial Accounting and Reporting for Oil and Gas Producing Activities Pursuant
to the Federal Securities Laws and the Energy Policy and Conservation Act of
1975

Reg. § 210.4 -10.

This section prescribes financial accounting and reporting standards for
registrants with the Commission engaged in oil and gas producing activities in
filings under the federal securities laws and for the preparation of accounts by
persons engaged, in whole or in part, in the production of crude oil or natural
gas in the United States, pursuant to Section 503 of the Energy Policy and
Conservation Act of 1975 [42 U.S.C. 6383] ("EPCA") and section 11(c) of the
Energy Supply and Environmental Coordination Act of 1974 [IS U.S.C. 796]
("ESECA"), as amended by section 505 of EPCA. The application of this section to
those oil and gas producing operations of companies regulated for rate-making
purposes on an individual-company-cost-of-service basis may, however, give
appropriate recognition to differences arising because of the effect of the
rate-making process.

Exemption. Any person exempted by the Department of Energy from any
record-keeping or reporting requirements pursuant to Section 11(c) of ESECA, as
amended, is similarly exempted from the related provisions of this section in
the preparation of accounts pursuant to EPCA. This exemption does not affect the
applicability of this section to filings pursuant to the federal securities
laws.

Definitions

(a) Definitions. The following definitions apply to the terms listed below as
they are used in this section:

(1) Oil and gas producing activities.

(i) Such 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 and/or for the purpose of removing the oil or gas from existing
reservoirs on those properties.

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(C) The construction, drilling and production activities necessary to retrieve
oil and gas from its natural reservoirs, and the acquisition, construction,
installation, and maintenance of field gathering and storage systems -including
lifting the oil and gas to the surface and gathering, treating, field processing
(as in the case of processing gas to extract liquid hydrocarbons) and field
storage. For purposes of this section, the oil and gas production function shall
normally be regarded as terminating at the outlet valve on the lease or field
storage tank; if unusual physical or operational circumstances exist, it may be
appropriate to regard the production functions as terminating at the first point
at which oil, gas, or gas liquids are delivered to a main pipeline, a common
carrier, a refinery, or a marine terminal.

(ii) Oil and gas producing activities do not include:

(A) The transporting, refining and marketing of oil and gas.

(B) Activities relating to the production of natural resources other than oil
and gas.

(C) The production of geothermal steam or the extraction of hydrocarbons as a
byproduct of the production of geothermal steam or associated geothermal
resources as defined in the Geothermal Steam Act of 1970.

(D) The extraction of hydrocarbons from shale, tar sands, or coal.

(2) Proved oil and gas reserves. Proved oil and gas reserves are the estimated
quantities of crude oil, natural gas, and natural gas liquids which geological
and engineering data demonstrate with reasonable certainty to be recoverable in
future years from known reservoirs under existing economic and operating
conditions, i.e., prices and costs as of the date the estimate is made. Prices
include consideration of changes in existing prices provided only by contractual
arrangements, but not on escalations based upon future conditions.

(i) Reservoirs are considered proved if economic producibility is supported by
either actual production or conclusive formation test. The area of a reservoir
considered proved includes (A) that portion delineated by drilling and defined
by gas-oil and/or oil-water contacts, if any; and (B) the immediately adjoining
portions not yet drilled, but which can be reasonably judged as economically
productive on the basis of available geological and engineering data. In the
absence of information on fluid contacts, the lowest known structural occurrence
of hydrocarbons controls the lower proved limit of the reservoir.

(ii) Reserves which can be produced economically through application of improved
recovery techniques (such as fluid injection) are included in the "proved"
classification when successful testing by a pilot project, or the operation of
an installed program in the reservoir, provides support for the engineering
analysis on which the project or program was based.

(iii) Estimates of proved reserves do not include the following:

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(A) oil that may become available from known reservoirs but is classified
separately as "indicated additional reserves";

(B) crude oil, natural gas, and natural gas liquids, the recovery of which is
subject to reasonable doubt because of uncertainty as to geology, reservoir
characteristics, or economic factors;

(C) crude oil, natural gas, and natural gas liquids, that may occur in undrilled
prospects; and

(D) crude oil, natural gas, and natural gas liquids, that may be recovered from
oil shales, coal, gilsonite and other such sources.

RESERVE STATUS CATEGORIES

(3) Proved developed oil and gas reserves. Proved developed oil and gas reserves
are reserves that can be expected to be recovered through existing wells with
existing equipment and operating methods. Additional oil and gas expected to be
obtained through the application of fluid injection or other improved recovery
techniques for supplementing the natural forces and mechanisms of primary
recovery should be included as "proved developed reserves" only after testing by
a pilot project or after the operation of an installed program has confirmed
through production response that increased recovery will be achieved.

(4) Proved undeveloped reserves. Proved undeveloped oil and gas reserves are
reserves 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. Reserves on undrilled acreage shall be limited to those drilling
units offsetting productive units that are reasonably certain of production when
drilled. Proved reserves for other undrilled units can be claimed only where it
can be demonstrated with certainty that there is continuity of production from
the existing productive formation. Under no circumstances should estimates, for
proved 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 tests
in the area and in the same reservoir.

(5) Proved properties. Properties with proved reserves.

UNPROVED RESERVES

(6) Unproved properties. Properties with no proved reserves.

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

(8) 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.

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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.

(9) 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.

(10) Exploratory well. A well drilled to find and produce oil or gas in an
unproved area, to find a new reservoir in a field previously found to be
productive of oil or gas in another reservoir, or to extend a known reservoir.
Generally, an exploratory well is any well that is not a development well, a
service well, or a stratigraphic test well as those items are defined below.

(11) 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.

(12) 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.

(13) Stratigraphic test well. A drilling effort, geologically directed, to
obtain information pertaining to a specific geologic condition. Such wells
customarily arc drilled without the intention of being completed for hydrocarbon
production. This classification also includes tests identified as core tests and
all types of expendable holes related to hydrocarbon exploration. Stratigraphic
test wells are classified as (i) "exploratory type," if not drilled in a proved
area, or (ii) "development type," if drilled in a proved area.

(14) 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.

(15) 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:

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(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.

(16) 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.

(17) 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.

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(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.

Successful Efforts Method

(b) A reporting entity that follows the successful efforts method shall comply
with the accounting and financial reporting disclosure requirements of Statement
of Financial Accounting Standards No. 19, as amended.

Full Cost Method

(c) Application of the full cost method of accounting. A reporting entity that
follows the full cost method shall apply that method to all of its operations
and to the operations of its subsidiaries, as follows:

(1) Determination of cost centers. Cost centers shall be established-on a
country-by-country basis.

(2) Costs to be capitalized. All costs associated with property acquisition,
exploration, and development activities (as defined in paragraph (a) of this
section) shall be capitalized within the appropriate cost center. Any internal
costs that are capitalized shall be limited to those costs that can be directly
identified with acquisition, exploration, and development activities undertaken
by the reporting entity for its own account, and shall not include any costs
related to production, general corporate overhead, or similar activities.

(3) Amortization of capitalized costs. Capitalized costs within a cost center
shall be amortized on the unit-of-production basis using proved oil and gas
reserves, as follows:

(i) Costs to be amortized shall include (A) all capitalized costs, less
accumulated amortization, other than the cost of properties described in
paragraph (ii) below; (B) the estimated future expenditures (based on current
costs) to be incurred in developing proved reserves; and (C) estimated
dismantlement and abandonment costs, net of estimated salvage values.

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(ii) The cost of investments in unproved properties and major development
projects may be excluded from capitalized costs to be amortized, subject to the
following:

(A) All costs directly associated with the acquisition and evaluation of
unproved properties may be excluded from the amortization computation until it
is determined whether or not proved reserves can be assigned to the properties,
subject to the following conditions: (1) Until such a determination is made, the
properties shall be assessed at least annually to ascertain whether impairment
has occurred. Unevaluated properties whose costs are individually significant
shall be assessed individually. Where it is not practicable to individually
assess the amount of impairment of properties for which costs are not
individually significant, such properties may be grouped for purposes of
assessing impairment. Impairment may be estimated by applying factors based on
historical experience and other data such as primary Lease terms of the
properties, average holding periods of unproved properties, and geographic and
geologic data to groupings of individually insignificant properties and
projects. The amount of impairment assessed under either of these methods shall
be added to the costs to be amortized. (2) The costs of drilling exploratory dry
holes shall be included in the amortization base immediately upon determination
that the well is dry. (3) If geological and geophysical costs cannot be directly
associated with specific unevaluated properties, they shall be included in the
amortization base as incurred. Upon complete evaluation of a property, the total
remaining excluded cost (net of any impairment) shall be included in the full
cost amortization base.

(B) Certain costs may be excluded from amortization when incurred in connection
with major development projects expected to entail significant costs to
ascertain the quantities of proved reserves attributable to the properties under
development (e.g., the installation of an offshore drilling platform from which
development wells are to be drilled, the installation of improved recovery
programs, and similar major projects undertaken in the expectation of
Significant additions to proved reserves). The amounts which may be excluded are
applicable portions of (1) the costs that relate to the major development
project and have not previously been included in the amortization base, and (2)
the estimated future expenditures associated with the development project. The
excluded portion of any common costs associated with the development project
should be based, as is most appropriate in the circumstances, on a comparison of
either (i) existing proved reserves to total proved reserves expected to be
established upon completion of the project, or (ii) the number of wells to which
proved reserves have been assigned and total number of wells expected to be
drilled. Such costs may be excluded from costs to be amortized until the earlier
determination of whether additional reserves are proved or impairment occurs.

(C) Excluded costs and the proved reserves related to such costs shall be
transferred into the amortization base on an ongoing (well-by-well or
property-by-property) basis as the project is evaluated and proved reserves
established or impairment determined. Once proved reserves are established,
there is no further justification for continued exclusion from the full cost
amortization base even if other factors prevent immediate production or
marketing.

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(iii) Amortization shall be computed on the basis of physical units, with oil
and gas converted to a common unit of measure on the basis of their approximate
relative energy content, unless economic circumstances (related to the effects
of regulated prices) indicate that use of units of revenue is a more appropriate
basis of computing amortization. In the latter case, amortization shall be
computed on the basis of current gross revenues (excluding royalty payments and
net profits disbursements) from production in relation to future cross revenues,
based on current prices (including consideration of changes in existing prices
provided only by contractual arrangements), from estimated production of proved
oil and gas reserves. The effect of a significant price increase during the year
on estimated future gross revenues shall be reflected in the amortization
provision only for the period after the price increase occurs.

(iv) In some cases it may be more appropriate to depreciate natural gas cycling
and processing plants by a method other than the unit-of-production method.

(v) Amortization computations shall be made on a consolidated basis, including
investees accounted for on a proportionate consolidation basis. Investees
accounted for on the equity method shall be treated separately.

(4) Limitation on capitalized costs:

(i) For each cost center, capitalized costs, less accumulated amortization and
related deferred income taxes, shall not exceed an amount (the cost center
ceiling) equal to the sum of:

(A) the present value of estimated future net revenues computed by applying
current prices of oil and gas reserves (with consideration of price changes only
to the extent provided by contractual arrangements) to estimated future
production of proved oil and gas reserves as of the date of the latest balance
sheet presented, less estimated future expenditures (based on current costs) to
be incurred in developing and producing the proved reserves computed using a
discount factor of ten percent and assuming continuation of existing economic
conditions; plus

(B) the cost of properties not being amortized pursuant to paragraph (i)(3)(ii)
of this section; plus

(C) the lower of cost or estimated fair value of unproven properties included in
the costs being amortized; less

(D) income tax effects related to differences between the book and tax basis of
the properties referred to in paragraphs (i)(4)(i)(B) and (C) of this section.

(ii) If unamortized costs capitalized within a cost center, less related
deferred income taxes, exceed the cost center ceiling, the excess shall be
charged to expense and separately disclosed during the period in which the
excess occurs. Amounts thus required to be written off shall not be reinstated
for any subsequent increase in the cost center ceiling.

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(5) Production costs. All costs relating to production activities, including
workover costs incurred solely to maintain or increase levels of production from
an existing completion interval, shall be charged to expense as incurred.

(6) Other transactions. The provisions of paragraph (h) of this section,
"Mineral property conveyances and related transactions if the successful efforts
method of accounting is followed," shall apply also to those reporting entities
following the full cost method except as follows:

(i) Sales and abandonments of oil and gas properties. Sales of oil and gas
properties, whether or not being amortized currently, shall be accounted for as
adjustments of capitalized costs, with no gain or loss recognized, unless such
adjustments would significantly alter the relationship between capitalized costs
and proved reserves of oil and gas attributable to a cost center. For instance,
a significant alteration would not ordinarily be expected to occur for sales
involving less than 25 percent of the reserve quantities of a given cost center.
If gain or loss is recognized on such a sale, total capitalization costs within
the cost center shall be allocated between the reserves sold and reserves
retained on the same basis used to compute amortization, unless there are
substantial economic differences between the properties sold and those retained,
in which case capitalized costs shall be allocated on the basis of the relative
fair values of the properties. Abandonments of oil and gas properties shall be
accounted for as adjustments of capitalized costs; that is, the cost of
abandoned properties shall be charged to the full cost center and amortized
(subject to the limitation on capitalized costs in paragraph (b) of this
section).

(ii) Purchases of reserves. Purchases of oil and gas reserves in place
ordinarily shall be accounted for as additional capitalized costs within the
applicable cost center; however, significant purchases of production payments or
properties with lives substantially shorter than the composite productive life
of the cost center shall be accounted for separately.

(iii) Partnerships, joint ventures and drilling arrangements.

(A) Except as provided in subparagraph (i)(6)(i) of this section, all
consideration received from sales or transfers of properties in connection with
partnerships, joint venture operations, or various other forms of drilling
arrangements involving oil and gas exploration and development activities (e.g.,
carried interest, turnkey wells, management fees, etc.) shall be credited to the
full cost account, except to the extent of amounts that represent reimbursement
of organization, offering, general and administrative expenses, etc., that are
identifiable with the transaction, if such amounts are currently incurred and
charged to expense.

(B) Where a registrant organizes and manages a limited partnership involved only
in the purchase of proved developed properties and subsequent distribution of
income from such properties, management fee income may be recognized provided
the properties involved do not require aggregate development expenditures in
connection with production of existing proved reserves in excess of 10% of the
partnership's recorded cost of such properties. Any income not recognized as a
result of this limitation would be credited to the full cost account and
recognized through a lower amortization provision as reserves are produced.

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(iv) Other services. No income shall be recognized in connection with
contractual services performed (e.g. drilling, well service, or equipment supply
services, etc.) in connection with properties in which the registrant or an
affiliate (as defined in § 210.1 -02(b)) holds an ownership or other economic
interest, except as follows:

(A) Where the registrant acquires an interest in the properties in connection
with the service contract, income may be recognized to the extent the cash
consideration received exceeds the related contract costs plus the registrant's
share of costs incurred and estimated to be incurred in connection with the
properties. Ownership interests acquired within one year of the date of such a
contract are considered to be acquired in connection with the service for
purposes of applying this rule. The amount of any guarantees or similar
arrangements undertaken as part of this contract should be considered as part of
the costs related to the properties for purposes of applying this rule.

(B) Where the registrant acquired an interest in the properties at least one
year before the date of the service contract through transactions unrelated to
the service contract, and that interest is unaffected by the service contract,
income from such contract may be recognized subject to the general provisions
for elimination of intercompany profit under generally accepted accounting
principles.

(C) Notwithstanding the provisions of (A) and (B) above, no income may be
recognized for contractual services performed on behalf of investors in oil and
gas producing activities managed by the registrant or an affiliate. Furthermore,
no income may be recognized for contractual services to the extent that the
consideration received for such services represents an interest in the
underlying property.

(D) Any income not recognized as a result of these rules would be credited to
the full cost account and recognized through a lower amortization provision as
reserves are produced.

(7) Disclosures. Reporting entities that follow the full cost method of
accounting shall disclose all of the information required by paragraph (k) of
this section, with each cost center considered as a separate geographic area,
except that reasonable groupings may be made of cost centers that are not
significant in the aggregate. In addition:

(i) For each cost center for each year that an income statement is required,
disclose the total amount of amortization expense (per equivalent physical unit
of production if amortization is computed on the basis of physical units or per
dollar of gross revenue from production if amortization is computed on the basis
of gross revenue).

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(ii) State separately on the face of the balance sheet the aggregate of the
capitalized costs of unproved properties and major development projects that are
excluded, in accordance with paragraph (i)(3) of this section, from the
capitalized costs being amortized. Provide a description in the notes to the
financial statements of the current status of the significant properties or
projects involved, including the anticipated timing of the inclusion of the
costs in the amortization computation. Present a table that shows, by category
of cost, (A) the total costs excluded as of the most recent fiscal year; and (B)
the amounts of such excluded costs, incurred (1) in each of the three most
recent fiscal years and (2) in the aggregate for any earlier fiscal years in
which the costs were incurred. Categories of cost to be disclosed include
acquisition costs, exploration costs, development costs in the case of
significant development projects and capitalized interest.

Income taxes

(d) Income taxes. Comprehensive inter-period income tax allocation by a method
which complies with generally accepted accounting principles shall be followed
for intangible drilling and development costs and other costs incurred that
enter into the determination of taxable income and pretax accounting income in
different periods.

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Note: SWD well went on-line in May of 2011 therefore a more indicative LOE for
the F-12 wells will be an average beginning in May, 2011

    Gross Lease Operating Expense             Production           Month Billing
Date PP F12 PP F12-3 PP F12-4 PP F12-5 Nov-10 11/30/2010 $20,882.76 $20,882.71
$33,215.25   Dec-10 12/31/2010 $19,546.20 $19,546.21 $30,322.13   Jan-11
1/31/2011 $22,174.30 $23,134.13 $35,722.29   Feb-11 2/28/2011 $19,369.45
$13,421.88 $37,423.29   Mar-11 3/31/2011 $28,150.10 $25,530.17 $28,256.27  
Apr-11 4/30/2011 $15,062.82 $15,062.82 $22,596.04 $19,770.99 May-11 5/31/2011
$9,187.40 $9,187.40 $9,471.66 $9,471.65 Jun-11 6/30/2011 $12,858.68 $13,652.38
$12,376.22 $13,376.23 Jul-11 7/31/2011 $13,054.48 $11,343.44 $12,157.34
$12,157.36 Aug-11 8/31/2011 $9,079.62 $29,582.31 $9,286.16 $8,863.94            
Average   $11,045.05 $15,941.38 $10,822.85 $10,967.30

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RESUME

MICHAEL J. VEAZEY
5539 Coldwater Creek
Baton Rouge, La. 70808

PERSONAL DATA

Born June, 1944: Married, two children

EDUCATION

B.S. in Petroleum Engineering, LSU, 1966
Elected to Tau Beta Pi (Honorary Engineering Society)
Elected to Pi Epsilon Tau (Honorary Petroleum Engineering Society)
M.S. in Petroleum Engineering, LSU, 1968
Elected to Phi Kappa Phi (National Honorary Society)

PROFESSIONAL SOCIETIES AND ACTIVITIES

Registered Professional Engineer in Louisiana (Petroleum) since 1972 Registered
Professional Engineer in Louisiana (Environmental) since 1994 Member of Society
of Petroleum Engineers of AIME since 1964 Member of Society of Society of
Petroleum Evaluation Engineers American Association of Drilling Engineers
(Steering Com.) Faculty Advisor to Student Section of SPE (1978 - 1983) Mineral
Consultant to LSU Board of Supervisors (1980 - 1983) Phi Kappa Phi honor society
Tau Beta Pi honor society Pi Epsilon Tau honor society

EXPERIENCE

1983-PRESENT

D-O-R Engineering, Inc. In May 2009, Mr. Veazey acquired an equity position in
the established consulting firm, D-O-R Engineering. Mr. Veazey is the President
and Chief Executive Officer of the Company. D-O-R is a full service petroleum
consulting engineering firm that will complement the firm of Veazey and
Associates, LLC.

VEAZEY AND ASSOCIATES, LLC - an oil and gas consulting firm located in Baton
Rouge, Louisiana

Mr. Veazey has been the President of Veazey and Associates, LLC (Formerly Veazey
& Associates, Inc and MJV, Inc.) since 1978. He has served as an Instructor in
the LSU/IADC Well Control School, and he has recently assisted the LSU
Department of Petroleum Engineering as an Adjunct Professor of the faculty of
the LSU Petroleum Engineering Department.

Mr. Veazey serves as the primary engineering analyst responsible for the
estimation of oil and gas reserve volumes for a number of oil and gas companies.
In addition to his role as an estimator of oil and gas reserves, he has provided
the primary engineering work upon which many oil and gas reserve acquisitions
have been based. He has also performed many Estate Appraisals.

Since 1980, Mr. Veazey has assisted the Vermilion Parish School Board with the
management of minerals associated with the 22,000 + acres of State Land held in
trust for that School Board, and Mr. Veazey has assisted The Terrebonne Parish
School Board since 1986 with similar services for the 22,000+ acres of State
Land held in trust for that School Board. In 2004, Veazey & Associates, Inc. was
selected by the Lafourche Parish School Board to assist in the management of the
9,000+ acres of School Board Section 16 minerals.

Mr. Veazey has provided Expert Testimony and given sworn depositions in both
Federal and State Court. He has qualified as an expert in the field of Petroleum
Engineering, Petroleum Reservoir Engineering and Oil Field Operations. He has
also testified before the Louisiana Office of Conservation in numerous
Unitization hearings.

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2003-2007

LOUISIANA STATE UNIVERSITY - Adjunct Professor of Petroleum Engineering at LSU

Mr. Veazey taught undergraduate courses in phase behavior and production
equipment design.

1978-1983

LOUISIANA STATE UNIVERSITY - Assistant Professor of Petroleum Engineering at
LSU.

Mr. Veazey taught undergraduate courses in petroleum economics, drilling,
petrophysics, unitization, and phase behavior. During his tenure, he was the
Director of LSU/IADC Well Control School from 1980 through 1983. He was also the
Mineral Consultant to the LSU Board of Supervisors from 1980 through 1983.

1974-1978

SAMSON RESOURCE COMPANY - A publicly traded, independent oil and gas company
specializing in production acquisitions and development drilling, located in
Tulsa, Oklahoma.

Mr. Veazey was the Senior Petroleum Engineer responsible for all drilling,
production and acquisitions. During the period in which he served as the
companies' chief engineering evaluator, Samson was recognized as one of the
nation’s most successful and fastest growing independent oil and gas companies.
During employment with Samson, Mr. Veazey co-author three technical papers, one
of which related to the development of a Monte Carlo Simulation model for a
programmable calculator, allowing the general engineering population to access
and utilize this powerful statistical tool for oil and gas acquisition and
development activities in a manner which had previously been reserved for only
those with access to powerful main frame computers.

1972-1974

PLACID OIL COMPANY - An international oil and gas company headquartered in
Dallas, Texas.

Mr. Veazey served as a Staff Petroleum Engineer responsible for oil and gas
reserve calculations and development drilling programs which concentrated on
large offshore Louisiana oil and gas fields. He was also responsible for
representing Placid at numerous technical committee meetings with joint venture
partners. Mr. Veazey also performed reservoir engineering and statistical
evaluations of major undeveloped tracts of land for the purpose of participation
in competitive lease sales. As a result of these efforts, the company invested
$180MM and was rewarded with the discovery of the South Marsh Island 268 Field.
He also worked with other engineers to continually evaluate the companies'
producing oil and gas fields. These activities were concentrated in the gulf
coast area of Louisiana, but also extended to other geographic areas such as
Alabama, Mississippi, the Florida Gulf Coast and the North Sea.

1968-1972

CHEVRON -

Mr. Veazey worked as a Reservoir Engineer and Drilling Engineer in the New
Orleans office. He worked on secondary recovery projects and prepared reserve
calculations for large oil and gas fields in south Louisiana and offshore
Louisiana. He also worked as a field drilling engineer on offshore and inland
water rigs for two years.

Summers

1967 Drilling Engineer, Chevron Oil Co.
1966 Reservoir Engineer, Chevron Oil Co.
1965 Lease Pumper, Gulf Oil Co.
1964 Roustabout, Pan American Petroleum Corp. (Amoco).

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SELECTED PUBLICATIONS

  1.

Veazey, M.J. and Carlton, A.: RECORD OKLAHOMA WELL DRILLED THROUGH TROUBLESOME
ATOKA SHALE, Oil and Gas Journal, August 23, 1976.

        2.

Veazey, M.J. and Carlton, A.: NEW LOGGING APPROACH TO OLD WELLS, Petroleum
Engineer, July, 1976.

        3.

Veazey, M.J. and Smith, P.: SIMPLE EQUATION, CALCULATOR SPEED LEASE EVALUATION,
Oil and Gas Journal, May 22, 1978.

        4.

Veazey, M.J. and Bassiouni, Z.: THE EVALUATION OF WATER CYCLING AS A TECHNIQUE
FOR RECOVERING THE DISSOLVED GAS IN A GEOPRESSURED AQUIFER, LSU Dept. of
Petroleum Engineering Report to DOE, August, 1978.

        5.

Veazey, M.J., Hawkins, M.F., et. al.: METHODS FOR DETERMINING VENTED VOLUMES
DURING GAS WELL BLOWOUTS, DOE Publication, October, 1980.

        6.

Veazey, M.J., Hawkins, M.F., et. al.: METHODS FOR DETERMINING VENTED VOLUMES
DURING GAS-CONDENSATE BLOWOUTS, DOE Publication , November, 1981.

        7.

Veazey, M.J., Alexander, W.H., and Corty, F.L.: OIL AND GAS LEASING: A MYSTERY
IN LOUISIANA, Louisiana Rural Economist, Vol. 44 No. 4, November, 1982.

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Jim Veazey, P. E.
6161 Perkins Rd., Ste. 2C
Baton Rouge, LA 70808
(225) 765-1914

Experience

D-O-R Engineering, Inc. 5/09 to Present
Part Owner/Secretary/Engineering Manager
Offers a diverse range of consulting petroleum engineering and management
services to major and independent oil companies, financial institutions, legal
firms investment companies, private estates and land and mineral owners along
the Gulf Coast. While the firm offers general consulting services in the areas
of petroleum engineering and property management, it has particular expertise in
the areas of: 1) expert witness; and 2) reserve determination for the purpose of
oil and gas property sale and/or acquisition, investment in oil and gas
properties; and appraisals for year-end-reports, S. E. C. filings, Canadian
filings, FDIC reports, bank loans and estate successions. D-O-R Engineering,
Inc. was established in 1971.

Veazey & Associates, LLC 8/01 to Present
Part Owner/Senior Petroleum Engineer
Provide services related to reservoir engineering including fair market value
appraisals and various aspects of mineral management. Knowledgeable in
calculation of reserves by a multitude of methods and implementing economic
software (PHD Win) to relate a present value forecast for said reserves so the
client can make informed budget decisions regarding financing, investments,
private acquisitions or acquisition by state imminent domain. Manage minerals of
over 50,000 acres for public lands. This includes all aspects of permitting,
leasing, scouting oil and gas activity, as well as providing a complete
inventory of past and present surface and mineral activity. Accounting of
surface activity includes multiple site visits to properties. Conducted
regulatory filings and plugging operations for operator terminating business in
state. Also located and negotiated a suitable new company to take over
operations and relieve client from all plugging and environmental
responsibility. Capable of extensive due diligence research at the Office of
Conservation and permitting as related to that Office, as well as interfacing
with Office of Conservation staff regarding regulatory compliance issues and
other special situations involving this state agency. Knowledge of and
experience with ArcView GIS software.

Department of Natural Resources/Inspection & Enforcement Section 4/98 to 8/01
Advanced Petroleum Engineer
Manage complaints from land owners or concerned citizens regarding oil and gas
operations in the vicinity of their property. Further, if any violations are
discovered, initiate corrective action and keep complainant informed of all
actions taken by this Office. Review passive closure data for oil field pits to
ensure conformance with the applicable State rules and regulations. Responsible
for monitoring inactive oil and gas wells in the state to ensure that the sites,
which are deemed as having no future utility, are plugged and abandoned in
accordance with the requirements of Statewide Order No. 29-B. This involves
requesting and evaluating engineering and geological data provided by operators
of inactive wells to justify the classification of the well(s) as having future
utility. Review Lease Facility Inspection, Production Pit Inspection, Reserve
Pit Inspection and Narrative Reports submitted by field agents for the Office of
Conservation and take necessary action. Accompany agents on field inspections to
insure compliance with rules and regulations of the Office of Conservation.
Coordinate and supervise the compilation of statistics relating to oil and gas
conservation activities; such as unitization hearings or meetings with industry
representatives. Produce quad and satellite maps from Arc View, a GIS software,
to aid with site visits in the field or identification of environmentally
sensitive areas.

Department of Natural Resources/Orphan Well Section 9/96 to 4/98
Petroleum Engineer
Review and audit records in order to prepare bid packages for orphan well
projects. Prepare restoration procedures for orphaned sites including down-hole
plugging procedures, pit closure and facility removal. Obtain soil analyses on
all oil field pits or tank bottoms associated with the orphaned site. Oversee
site visits for plugging and restoration contractors so bids can be prepared.
Prepare data relative to Act 404 (Oilfield Site Restoration Law) for
dissemination to the respective legislative oversight committees, the Oilfield
Site Restoration Commission, the Secretary of the Department of Natural
Resources, and the Assistant Secretary. Assist in establishment of Site Specific
Trust Accounts. Develop and implement appropriate procedures to determine that
oil field sites which are not closed or maintained in accordance with provisions
of Statewide Order No. 29-B are orphaned. Manage applications for approved
contractors applying for work under Oilfield Site Restoration. Organize with
Louisiana Oil Spill Coordinator’s Office in order to expend funds from the Oil
Spill Contingency Fund in the event of an emergency.

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Veazey & Associates, Inc. 9/95 to 9/96
Petroleum Engineer
Perform reserve forecasts for annual reports and estate appraisals. Mineral
management of two state agencies (total of 40,000 + acres under management).
Assist in preparation of unitization hearings for industry and land owner
clients.

Union Oil Company of California 5/94 to 8/94
Summer Intern
Design well workovers and write AFEs, involved in decision making of workover
and recompletion procedures in the office and in the field. Assist Senior
Production Engineer with daily field activity.

Veazey & Associates, Inc. 5/91 to 5/94
Technical Assistant
Extensive research collection at Department of Natural Resources. Plotting of
decline curves, planimetering isopach maps for volumetric reserve calculations.
Maintenance of company well history and engineering files. Office management and
company finance management.

L. S. U. Petroleum Engineering Department 9/89 to 5/95
Student Worker
Responsible for maintenance of laboratories, maintenance of supplies and general
office work.

Conoco, Inc. 6/88 to 8/88
Summer Intern
Observed secondary and tertiary recovery methods and performed lease maintenance
work in the field.

Professional Organizations

Society of Petroleum Evaluation Engineers
Society of Petroleum Engineers

Certifications and Short Courses

Mineral Law Institute, 2001 thru 2007
Registered Professional Engineer License, 2001
NORM Surveying and Control Certification, 1998
Soil Remediation for Petroleum Extraction Industry, 1997 and 1998
Mineral Management Service Well Control and Under Balanced Drilling, 1997 and
1998
Introduction to Arc View GIS, 1998
Engineer-In-Training (EIT) Certification, 1995

Education

Louisiana State University - 1995 Graduate in Petroleum Engineering
Louisiana State University - 1991 Graduate in General Studies with a business
emphasis
Catholic High School, Baton Rouge - 1986 Graduate

Personal

Married with two children

References

Available Upon Request

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