Lexaria Corp.: Exhibit 10.1 - Filed by newsfilecorp.com






 

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

AS OF OCTOBER 31, 2011 

 

December 12, 2011 




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 







 

	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. 

Page 1 of 77





	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.

Page 14 of 77




(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.

Page 15 of 77




(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).

Page 16 of 77




(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.

Page 17 of 77




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. 



Page 18 of 77




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.

Page 19 of 77




(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:

Page 20 of 77




(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. 

Page 21 of 77




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:

Page 22 of 77




(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.

Page 23 of 77




(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.

Page 24 of 77




(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.

Page 25 of 77




(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.

Page 26 of 77




(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.

Page 27 of 77




(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).

Page 28 of 77




(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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Page 72 of 77




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. 

Page 73 of 77




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). 

Page 74 of 77




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.



Page 75 of 77




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.

Page 76 of 77




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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