EX-99.2 7 exhibit99-2.htm EXHIBIT 99.2

EST. OF FUTURE RESERVES AND REVENUES
U. S. SEC REPORT
WILKINSON COUNTY, MISSISSIPPI
TO LEXARIA CORPORATION
AS OF OCTOBER 31, 2012

January 18, 2013

Table of Contents

Report | 1
SEC Definitions | 7
Report Definitions | 29
Economic Projections | 30
Production Decline Curves | 43
Lexaria Settlement Statement Dated 12/10/2012 | 54
AFE Election for PP F-6 & PP F-7 | 62
ummary of Lease Operating Expenses | 64
Firm Resume | 65

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

January 18, 2013

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, 2012

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 from the F-29. Lexaria owns the same interest in the F-29 as in the other producing wells. 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.

The report filed last year carried two Probable objectives in the PP F-39. However, reserves from this well were dropped because the lease expired and this well was plugged. The following are our conclusions for the estimates of future reserves and revenues for Lexaria Corporation, as of October 31, 2012.

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Lexaria Corporation
Phase I Drilling Program
Wilkinson County, MS
As of October 31, 2012

SEC Pricing
1 st of the Month Average Spot Prices

|  |  |  |  |  |  |  |  |  |  | CASH FLOW, |
|  | NET OIL, |  |  | NET GAS, |  |  | CASH FLOW, |  |  | DISC @ 10% |
Category |  | MBBLS |  |  | MMCF |  |  | UNDISC |  |  |  |
Proved Developed |  | 56.14 |  |  | 0.00 |  | $ | 3,869,983.60 |  | $ | 3,072,722.71 |
Prove Undeveloped |  | 82.90 |  |  | 0.00 |  | $ | 6,661,981.02 |  | $ | 5,022,890.70 |
Total Proved (1P) |  | 139.04 |  |  | 0.00 |  | $ | 10,530,964.62 |  | $ | 8,095,613.41 |

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.

Lexaria Corporation
Working Interest & Net Revenue Interest
As of October 31, 2012

| 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 Nonconsent | 8% | 6.8% | 5.2007038%
F-12-5 | 42% | 35.7% | 27.3036947%
F-12-5 Nonconsent | 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%

_________________________________
1 Statement dated December 10, 2012 attached herein. Interests on statement may not be consistent due to farm-outs.

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CLASSIFICATIONS AND DEFINITIONS

The classifications and definitions for proved reserves are consistent with those of the SEC2.

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 category (Developed and Undeveloped) of reserves, likely differences in uncertainty arise and caution should be used when combining reserves of different categories.

RESERVE ESTIMATES

Total ultimate reserves were estimated by a combination of the volumetric method and an analogy of the Frio oil sand in Stamps field located approximately two miles to the northwest of Belmont Lake field. Remaining Proved Developed Producing Reserves were then estimated by decline curve analysis. The PDP reserves were subtracted from the ultimate total reserves and the balance assigned to remaining Proved Undeveloped Reserves, which were allocated among four locations evenly.

We calculated the recovery factor for the Stamps field to be 995 Bbls/AF by estimating the ultimate recovery and constructing an isopach map of the Frio reservoir in that field (892,680 BO / 897.5 AF). This recovery factor was applied to the calculated volume of Belmont Lake of 682 AF from the isopach map provided by geologist Mr. Ray Lewand. By applying the recovery factor of Stamps field to the estimated volume of Belmont Lake, our estimated ultimate recovery is 678,590 Bbls. As of October 31, 2012 cumulative oil production from the four producing wells in this reservoir is 177,060 Bbls leaving 501,530 Bbls of total Proved remaining recoverable oil in the Belmont Lake Frio reservoir.

The analogy of Stamps is important because of its close proximity to Belmont Lake and the fact that it is also a Frio oil reservoir. Among other reasons we used the analogy of Stamps field are because of the similar values of oil gravity, porosity, permeability and comparable reservoir energy (water drive mechanism). In addition, both reservoirs are formed by a channel sand.

As stated previously, decline curve analysis was used to estimate remaining reserves from the producing wells. Production from all producing wells was terminated by the economic limit. Production is updated through October 31, 2012.

_________________________________
2 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.

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PRODUCT PRICES

The oil prices used in this report are the 12-month average St. James Sweet crude 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. The oil price of $111.61/Bbl is held constant throughout the life of the forecast.

COSTS AND EXPENSES

Costs used to forecast the drilling and completing of the 12-6, 12-7, 12-8 and 12-9 were taken directly from the signed November 12, 2010 AFE Election3 and are in the amount of $568,478. However, this estimate was adjusted by $59,250/well for pipeline installation and the fact that part of the AFE for the 12-7 and 12-6 has been paid. The following table shows the drilling and completion costs used in the forecast.

8/8ths Drilling & Completion Costs
Belmont Lake Field

| AFE | AFE |  | AFE
Well | Budget | Actual | Pipeline | Total
12-6 | 568,478 | (2,793) | 59,250 | 624,935
12-7 | 568,478 | (97,894) | 59,250 | 529,834
12-8 | 568,478 | (0) | 59,250 | 627,728
12-9 | 568,478 | (0) | 59,250 | 627,728

PLUGGING AND ABANDONMENT / RECLAMATION COSTS

Abandonment and reclamation costs were supplied by the operator and are estimated to be $30,500 per well (8/8ths) and were applied at the end of the life for each well separately.

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.

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

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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, operator Griffin & 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 the operator. 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 accounting, rather than engineering interpretation may be controlling. Finally, it must be realized that forecasting, by its nature, is subject to uncertainty, and the conclusions expressed herein are based on interpretation of engineering data and such conclusions necessarily represent only informed professional judgments.

Neither Veazey & Associates, LLC nor any of its employees has any interest in the subject properties and neither the employment to make this study nor the compensation is contingent on our estimates of reserves and future income for the subject properties.

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SEC Proved Oil and Gas Reserve Definitions

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

INTRODUCTION

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

Reg. § 210.4 -10.

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

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

Definitions

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

(1) Oil and gas producing activities.

(i) Such activities include:

(A) The search for crude oil, including condensate and natural gas liquids, or natural gas ("oil and gas") in their natural states and original locations.

(B) The acquisition of property rights or properties for the purpose of further exploration and/or for the purpose of removing the oil or gas from existing reservoirs on those properties.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

RESERVE STATUS CATEGORIES

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

(4) Proved undeveloped reserves. Proved undeveloped oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimates, for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.

(5) Proved properties. Properties with proved reserves.

UNPROVED RESERVES

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

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

(8) Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.

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There may be two or more reservoirs in a field which are separated vertically by intervening impervious strata, or laterally by local geologic barriers, or by both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms "structural feature" and "stratigraphic condition" are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas-of-interest, etc.

(9) Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

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

(11) Development well. A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known-to be productive.

(12) Service well. A well drilled or completed for the purpose of supporting production in an existing field. Specific purposes of service wells include gas injection, water injection, steam injection, air injection, salt-water disposal, water supply for injection, observation, or injection for in-situ combustion.

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

(14) Acquisition of properties. Costs incurred to purchase, lease or otherwise acquire a property, including costs of lease bonuses and options to purchase or lease properties, the portion of costs applicable to minerals when land including mineral rights is purchased in fee, brokers' fees, recording fees, legal costs, and other costs incurred in acquiring properties.

(15) Exploration costs. Costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing oil and gas reserves, including costs of drilling exploratory wells and exploratory-type stratigraphic test wells. Exploration costs may be incurred both before acquiring the related property (sometimes referred to in part as prospecting costs) and after acquiring the property. Principal types of exploration costs, which include depreciation and applicable operating costs of support equipment and facilities and other costs of exploration activities, are:

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(i) Costs of topographical, geographical and geophysical studies, rights of access to properties to conduct those studies, and salaries and other expenses of geologists, geophysical crews, and others conducting those studies. Collectively, these are sometimes referred to as geological and geophysical or "G&G" costs.

(ii) Costs of carrying and retaining undeveloped properties, such as delay rentals, ad valorem taxes on properties, legal costs for title defense, and the maintenance of land and lease records.

(iii) Dry hole contributions and bottom hole contributions.

(iv) Costs of drilling and equipping exploratory wells.

(v) Costs of drilling exploratory-type stratigraphic test wells.

(16) Development costs. Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas. More specifically, development costs, including depreciation and applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to:

(i) Gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines, and power lines, to the extent necessary in developing the proved reserves.

(ii) Drill and equip development wells, development-type stratigraphic test wells, and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment, and the wellhead assembly.

(iii) Acquire, construct, and install production facilities such as lease flow lines, separators, treaters, heaters, manifolds, measuring devices, and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems.

(iv) Provide improved recovery systems.

(17) Production costs.

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

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

(B) Repairs and maintenance.

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

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

(E) Severance taxes.

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

Successful Efforts Method

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

Full Cost Method

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

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

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

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

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

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

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

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

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

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

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

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

(4) Limitation on capitalized costs:

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

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

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

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

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

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

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

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

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

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

(iii) Partnerships, joint ventures and drilling arrangements.

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

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

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

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

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

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

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

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

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

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

Income taxes

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

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SEC Proved Oil and Gas Reserve Definitions

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

INTRODUCTION

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

Reg. § 210.4 -10.

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

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

Definitions

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

(1) Oil and gas producing activities.

(i) Such activities include:

(A) The search for crude oil, including condensate and natural gas liquids, or natural gas ("oil and gas") in their natural states and original locations.

(B) The acquisition of property rights or properties for the purpose of further exploration and/or for the purpose of removing the oil or gas from existing reservoirs on those properties.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

RESERVE STATUS CATEGORIES

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

(4) Proved undeveloped reserves. Proved undeveloped oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimates, for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.

(5) Proved properties. Properties with proved reserves.

UNPROVED RESERVES

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

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

(8) Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.

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There may be two or more reservoirs in a field which are separated vertically by intervening impervious strata, or laterally by local geologic barriers, or by both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms "structural feature" and "stratigraphic condition" are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas-of-interest, etc.

(9) Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

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

(11) Development well. A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known-to be productive.

(12) Service well. A well drilled or completed for the purpose of supporting production in an existing field. Specific purposes of service wells include gas injection, water injection, steam injection, air injection, salt-water disposal, water supply for injection, observation, or injection for in-situ combustion.

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

(14) Acquisition of properties. Costs incurred to purchase, lease or otherwise acquire a property, including costs of lease bonuses and options to purchase or lease properties, the portion of costs applicable to minerals when land including mineral rights is purchased in fee, brokers' fees, recording fees, legal costs, and other costs incurred in acquiring properties.

(15) Exploration costs. Costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing oil and gas reserves, including costs of drilling exploratory wells and exploratory-type stratigraphic test wells. Exploration costs may be incurred both before acquiring the related property (sometimes referred to in part as prospecting costs) and after acquiring the property. Principal types of exploration costs, which include depreciation and applicable operating costs of support equipment and facilities and other costs of exploration activities, are:

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(i) Costs of topographical, geographical and geophysical studies, rights of access to properties to conduct those studies, and salaries and other expenses of geologists, geophysical crews, and others conducting those studies. Collectively, these are sometimes referred to as geological and geophysical or "G&G" costs.

(ii) Costs of carrying and retaining undeveloped properties, such as delay rentals, ad valorem taxes on properties, legal costs for title defense, and the maintenance of land and lease records.

(iii) Dry hole contributions and bottom hole contributions.

(iv) Costs of drilling and equipping exploratory wells.

(v) Costs of drilling exploratory-type stratigraphic test wells.

(16) Development costs. Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas. More specifically, development costs, including depreciation and applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to:

(i) Gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines, and power lines, to the extent necessary in developing the proved reserves.

(ii) Drill and equip development wells, development-type stratigraphic test wells, and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment, and the wellhead assembly.

(iii) Acquire, construct, and install production facilities such as lease flow lines, separators, treaters, heaters, manifolds, measuring devices, and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems.

(iv) Provide improved recovery systems.

(17) Production costs.

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

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

(B) Repairs and maintenance.

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

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

(E) Severance taxes.

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

Successful Efforts Method

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

Full Cost Method

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

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

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

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

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

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

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

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

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

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

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

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

(4) Limitation on capitalized costs:

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

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

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

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

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

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

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

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

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

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

(iii) Partnerships, joint ventures and drilling arrangements.

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

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

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

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

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

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

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

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

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

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

Income taxes

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

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Report Definitions

Authority for Expenditure | (AFE) A document prepared by the operator that lists the estimated costs of drilling, completing, working over or plugging a well or some other major cost associated with the well or lease. The document is provided to partners for approval. Failure to approve an AFE may result in a penalty or loss of interest depending on contractual agreements.
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 paid.
Completion | A generic term used to describe the down hole assembly and equipment required to enable production of oil and/or gas from a well.
Cum Cut Plot | A graph of water cut or oil cut on the ordinate (y-axis) and cumulative oil production on the abscissa (x-axis) used to predict ultimate cumulative oil production at some limit of water or oil cut.
Decline Curve | A method of estimating petroleum reserves by determining the natural production decline of a well and extrapolating to predict future production.
Depletion Drive | The reservoir drive mechanism in which oil is produced by the expansion of the volume of the gas in solution.
Fair Market Value | (FMV) The Fair Market Value is defined as the amount at which property would transfer between a willing buyer and a willing seller, neither being under any compulsion to buy or sell and both having reasonable knowledge of the relevant facts.
Farmout | A contractual agreement with an owner who holds a working interest in an oil and gas lease to assign all or part of that interest to another party in exchange for fulfilling contractually specified conditions such as drilling a well or installing equipment.
Gas Lift | A method of raising oil in the wellbore from a lower depth to the surface by injecting gas in the well from the casing through the tubing via gas lift valves installed in the tubing.
Gross Reserves (Oil or Gas) | The volume of reserves attributed to the whole (100%).
Internal Rate of Return | (IROR) The interest rate which makes the present value of the revenues equal to the present value of the expenditures. In other words, the discounting rate which makes the net present value equal to zero.
Lease Operating Expense | (LOE) The Lease Operating Expenses include such things as direct operating costs, overhead, production (severance) taxes and ad valorem (property) taxes attributed to the lease (or well) and paid in the year which they are incurred . In the detailed economic projection(s), Net Lease Cost or Net Well Cost may be synonymous with the LOEs paid by the working interest ownership being evaluated.
MCFD | Acronym for "Mcf of Gas per Day" and refers to the volume of gas in thousand cubic feet that are produced in a 24 hour day.
Naturally Occurring | (NORM) Naturally Occurring Radioactive Material is radio active deposits such as scale found in tubulars.
Radioactive Material (NORM) |
Net Ad Valorem Tax | The property tax paid by the interest owner on drilling rigs, production equipment, etc.
Net Investment | As related to the economic forecast(s) attached herein, it is either the drilling, completion or plugging costs to the working interest being evaluated.
Net Lease Cost | See Lease Operating Expense.
Net Production Tax | The state severance tax that the interest owner pays on oil and/or gas levied when removed from the ground. The tax can be levied as a percent of the mineral value or in cents per barrel of oil/mcf of gas.
Net Reserves (Oil or Gas) | The volume of reserves attributed to a certain interest.
Net Revenue | Net revenue is the inflow of money as a result of oil and gas sales that the interest owner receives from its share of production. This income is before paying taxes, expenses and costs.
Net Revenue Interest | (NRI) The fractional share (usually between 3/4 and 7/8) of all oil and gas production revenue from the leased premises that goes to the working interest.
Net Well Cost | See Lease Operating Expense.
On-line | Refers to the status of a well that is producing.
Overriding Royalty Interest | Ownership in a percentage of production revenues, free of the cost of production.
Payout | (PO) Payout is the length of time after initial investment until accumulated net revenues from production equal all costs of leasing, exploring, drilling and operating.
Permeability | A measure of the ability of a rock to conduct a fluid through its interconnected pore space when that fluid is at 100% saturation.
Plug and Abandonment | (P&A) A term referring to when a well is shut-in permenantly and closed off from the surface by placing cement plugs (among other techniques) in the wellbore to isolate the higher pressured formation sands from the surface. Many times the well casing is cut below the plow depth and a steel plate welded on top, but in some states the casing is extended above ground and flagged.
Porosity | The ratio of volume of the pore spaces in rock grains compared to the total rock volume.
Reserves | The unproduced but recoverable oil and/or gas in place in a formation (reservoir). There are four basic criteria which must be satisfied for petroleum deposits to be considered reserves: they must be discovered, recoverable, commercial and remaining as of the effective date of the evaluation. Please refer to the Petroleum Resources Management System definitions for classification and categorization of reserves.
Reservoir | A subsurface porous, permeable rock body in which oil or gas or both can be stored.
Return on Investment | (ROI) The ratio of profit to investment (also called "profit to investment ratio").
Royalty Interest | (RI) The fractional share (usually between 1/8 and 1/4) of the total oil and gas production revenue from the leased premises free of all costs and expenses (except taxes).
Sand (Formation) | A general term applied in the oil and gas industry to refer to the strata of interest.
Shut-in | Refers to the status of a well that is not producing.
SWD | Acronym for Saltwater Disposal Well
Sweep Efficiency | A measure of the effectiveness in the water displacing the oil as the water sweeps through the reservoir.
Thickness | Usually refers to bed or sand thickness.
Viscosity | One of the physical properties of a liquid which is a direct measurement of its ability to flow.
Volumetric Calculation | A method of estimating petroleum reserves by determining the net thickness, porosity, water saturation and other properties of the oil and/or gas and reservoir.
Water Drive | The reservoir drive mechanism in which oil is produced by the expansion of the volume of the underlying water, which forces the oil into the wellbore.
Water Saturation | The percentage of the pore volume of a rock occupied by water.
Working Interest | (WI) The operating interest under an oil and gas lease which bears the full cost and expense of the lease including drilling, development and operating expenses.

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Belmont Lake Field
Summary of 8/8ths Lease Operating Expenses
FY 2011/2012

PRODUCTION |  |  |  |  | UNDRILLED
DATE | PP F-12 | PP F-3 | PP F-4 | PP F-5 | LOCATIONS
11/1/2011 | $8,346 | $9,496 | $11,271 | $11,275 |
12/1/2011 | $10,307 | $10,304 | $26,191 | $26,051 |
1/1/2012 | $12,770 | $12,770 | $16,233 | $16,233 |
2/1/2012 | $13,185 | $13,185 | $13,525 | $13,525 |
3/1/2012 | $20,202 | $10,094 | $20,355 | $16,507 |
4/1/2012 | $12,698 | $8,933 | $18,817 | $14,201 |
5/1/2012 | $3,500 | $7,238 | $5,282 | $7,278 |
6/1/2012 | $9,063 | $9,429 | $10,298 | $10,317 |
7/1/2012 | $1,043 | $1,043 | $1,383 | $1,383 |
8/1/2012 | $13,617 | $13,820 | $10,809 | $10,809 |
9/1/2012 | $13,782 | $12,229 | $14,993 | $14,755 |
10/1/2012 | $14,633 | $21,249 | $14,921 | $14,921 |
Average 8/8ths LOE | $11,096 | $10,816 | $13,673 | $13,105 | $12,172 *

*Undrilled Locations are average of four wells. $12,172 per undrilled well.

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RESUME

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

PERSONAL DATA

Born June, 1944: Married, two children

EDUCATION

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

PROFESSIONAL SOCIETIES AND ACTIVITIES

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

EXPERIENCE

1983-PRESENT

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

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

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

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

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

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

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2003-2007

LOUISIANA STATE UNIVERSITY - Adjunct Professor of Petroleum Engineering at LSU

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

1978-1983

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

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

1974-1978

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

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

1972-1974

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

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

1968-1972

CHEVRON -

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

Summers

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

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SELECTED PUBLICATIONS

| 1. | Veazey, M.J. and Carlton, A.: RECORD OKLAHOMA WELL DRILLED THROUGH TROUBLESOME ATOKA SHALE, Oil and Gas Journal, August 23, 1976.
| 2. | Veazey, M.J. and Carlton, A.: NEW LOGGING APPROACH TO OLD WELLS, Petroleum Engineer, July, 1976.
| 3. | Veazey, M.J. and Smith, P.: SIMPLE EQUATION, CALCULATOR SPEED LEASE EVALUATION, Oil and Gas Journal, May 22, 1978.
| 4. | Veazey, M.J. and Bassiouni, Z.: THE EVALUATION OF WATER CYCLING AS A TECHNIQUE FOR RECOVERING THE DISSOLVED GAS IN A GEOPRESSURED AQUIFER, LSU Dept. of Petroleum Engineering Report to DOE, August, 1978.
| 5. | Veazey, M.J., Hawkins, M.F., et. al.: METHODS FOR DETERMINING VENTED VOLUMES DURING GAS WELL BLOWOUTS, DOE Publication, October, 1980.
| 6. | Veazey, M.J., Hawkins, M.F., et. al.: METHODS FOR DETERMINING VENTED VOLUMES DURING GAS-CONDENSATE BLOWOUTS, DOE Publication , November, 1981.
| 7. | Veazey, M.J., Alexander, W.H., and Corty, F.L.: OIL AND GAS LEASING: A MYSTERY IN LOUISIANA, Louisiana Rural Economist, Vol. 44 No. 4, November, 1982.

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

Experience

D-O-R Engineering, Inc. 5/09 to Present
Part Owner/Secretary/Engineering Manager
D-O-R 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 mineral owners along the Gulf Coast. The firm also provides general consulting services in the areas of petroleum engineering and property management and has particular expertise in the areas of 1) expert witness testimony as related to reservoir engineering or general practices in the oil and gas industry and 2) reserve determination for the purposes of oil and gas property sales and/or acquisitions, investment in oil and gas properties, appraisals for year-end-reports, S. E. C. filings, Canadian filings, F. D. I. C. reports, bank loans and estate successions.

Veazey & Associates, LLC 8/01 to Present
Part Owner/Senior Petroleum Engineer
Veazey & Associates provides services related to reservoir engineering including fair market value appraisals and various aspects of mineral management. All engineers on staff are knowledgeable in the 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. Our firm manages the 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. We conduct site visits to monitor oil and gas surface activities which may have a direct impact on our client’s land. We conduct regulatory filings at the Office of Conservation and are capable of extensive due diligence research as related to that Office, as well as interfacing with Conservation staff regarding regulatory compliance issues and other special situations involving this state agency.

Office of Conservation/Inspection & Enforcement Section 4/98 to 8/01
Advanced Petroleum Engineer
Jim’s main function in this position was to manage complaints from land owners or concerned citizens regarding oil and gas operations in Louisiana. Further, if any violations were discovered, to initiate corrective action and keep complainant informed of all actions taken by Conservation. He reviewed passive closure data for oil field pits to ensure conformance with the applicable rules and regulations. Jim was responsible for monitoring inactive oil and gas wells in the state to ensure that the sites, which are deemed as having no future utility, were plugged and abandoned in accordance with the requirements of Statewide Order No. 29-B. This involved requesting and evaluating engineering and geological data from operators of inactive wells to justify the classification of the well(s) as having future utility. On many occasions, Jim accompanied enforcement agents on field inspections to insure compliance with rules and regulations of the Office of Conservation. He coordinated and supervised the compilation of statistics relating to oil and gas activities such as unitization hearings or meetings with industry representatives.

Office of Conservation/Orphan Well Section 9/96 to 4/98
Petroleum Engineer
Jim reviewed and audited well records in order to prepare bid packages for orphan well projects. This included down-hole plugging procedures, pit closure and facility removal. He oversaw obtaining soil analyses on all oil field pits or tank bottoms associated with the orphaned site. Jim directed site visits for plugging and restoration contractors so bids could be prepared for future restoration operations. He prepared 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. Also, Jim assisted in the establishment of Site Specific Trust Accounts.

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Veazey & Associates, Inc. 9/95 to 9/96
Petroleum Engineer
Jim performed reserve forecasts for annual reports and estate appraisals and assisted in the preparation of unitization hearings for industry and land owner clients. He managed the minerals for two state agencies (over 50,000 acres under management).

Union Oil Company of California 5/94 to 8/94
Summer Intern
Jim helped to design well workovers and wrote associated AFEs and was involved in decision making of workover and recompletion procedures in the office and in the field. He assisted the Senior Production Engineer with daily field activity.

Veazey & Associates, Inc. 5/91 to 5/94
Technical Assistant
Jim performed extensive research collection at the Office of Conservation and Mineral Resources. Jim also plotted decline curves, planimetered isopach maps for volumetric reserve calculations, maintained company well history and engineering files and assisted in the management and company finances.

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

Registered Professional Engineer in Louisiana and Texas
Applied Subsurface Geological Mapping, 2008
Mineral Law Institute – Multiple Years
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

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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