Harvest Oil & Gas Corp. - FORM 10-K - EX-99.1

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10-K - Harvest Oil & Gas Corp.	v212585_10k.htm
EX-31.2 - Harvest Oil & Gas Corp.	v212585_ex31-2.htm
EX-23.1 - Harvest Oil & Gas Corp.	v212585_ex23-1.htm
EX-32.2 - Harvest Oil & Gas Corp.	v212585_ex32-2.htm
EX-32.1 - Harvest Oil & Gas Corp.	v212585_ex32-1.htm
EX-23.2 - Harvest Oil & Gas Corp.	v212585_ex23-2.htm
EX-31.1 - Harvest Oil & Gas Corp.	v212585_ex31-1.htm
EX-21.1 - Harvest Oil & Gas Corp.	v212585_ex21-1.htm

Cawley, Gillespie & Associates, Inc.

Exhibit 99.1

	petroleum consultants

9601 AMBERGLEN BLVD., SUITE 117	306 WEST SEVENTH STREET, SUITE 302	1000 LOUISIANA STREET, SUITE 625
AUSTIN, TEXAS 78729-1106	FORT WORTH, TEXAS 76102-4987	HOUSTON, TEXAS 77002-5008
512-249-7000	817- 336-2461	713-651-9944
	www.cgaus.com

January 20, 2011

EV Energy Partners, L.P.

1001 Fannin Street, Suite 800

Houston, Texas 77002

Re:	Evaluation Summary
	EV Energy Partners, L.P. Interests
	Total Proved Reserves
	As of December 31, 2010

	Pursuant to the Guidelines of the
	Securities and Exchange Commission for
	Reporting Corporate Reserves and
	Future Net Revenue

Ladies and Gentlemen:

As requested, this report was completed on January 20, 2010 for EV Energy Partners, L.P. (“EVEP”) for the purpose of public disclosure by EVEP in filings made with the SEC in accordance with the disclosure requirements set forth in the SEC regulations. We evaluated 100% of EVEP reserves, which are made up of oil and gas properties in various fields throughout the central, southern and eastern United States. This report, with an effective date of December 31, 2010, was prepared using constant prices and costs and conforms to the guidelines of the Securities and Exchange Commission (SEC). The results of this evaluation are presented in the accompanying tabulations, with a composite summary of the values presented below:

		Proved Producing Developed	Proved Developed Non-Producing	Proved Developed	Proved Undeveloped	Total Proved
Net Reserves
Oil	- Mbbl	10,467.0	455.8	10,922.8	1,965.3	12,888.1
Gas	- MMcf	385,129.6	31,640.7	416,770.3	158,431.8	575,202.0
NGL	- Mbbl	13,812.4	2,141.6	15,954.1	11,514.2	27,468.3
Revenue
Oil	- M$	776,914.9	33,783.8	810,698.7	147,384.6	958,083.1
Gas	- M$	1,596,428.9	120,476.9	1,716,906.0	587,219.6	2,304,126.0
NGL	- M$	594,962.2	88,781.1	683,743.3	477,612.6	1,161,355.9
Net Profits	- M$	383.4	0.0	383.4	1,480.6	1,864.1
Severance Taxes	- M$	166,589.9	13,727.6	180,317.6	56,317.6	236,635.1
Ad Valorem Taxes	- M$	59,110.9	5,826.2	64,937.2	25,377.5	90,314.7
Operating Expenses	- M$	915,409.5	16,747.9	932,157.4	117,451.9	1,049,609.6
Misc. Expenses 2	- M$	4.0	0.0	4.0	0.0	4.0
Other Deductions	- M$	153,913.9	17,151.7	171,065.6	90,019.5	261,084.8
Investments	- M$	0.0	38,694.7	38,694.7	283,093.4	321,788.1
Net Cash Flows	- M$	1,672,894.3	150,893.6	1,823,788.4	638,476.1	2,462,264.5
Discounted @ 10%	- M$	786,461.3	50,453.1	836,914.6	189,578.8	1,026,493.1
(Present Worth)

EV Energy Partners, L.P.

January 20, 2011

Page 2

Future revenue is prior to deducting state production taxes and ad valorem taxes. Future net cash flow is after deducting these taxes, future capital costs and operating expenses, but before consideration of federal income taxes. In accordance with SEC guidelines, the future net cash flow has been discounted at an annual rate of ten percent to determine its “present worth”. The present worth is shown to indicate the effect of time on the value of money and should not be construed as being the fair market value of the properties.

The oil reserves include oil and condensate. Oil volumes are expressed in barrels (42 U.S. gallons). Gas volumes are expressed in thousands of standard cubic feet (Mcf) at contract temperature and pressure base.

Our estimates are for proved reserves only and do not include any probable or possible reserves nor have any values been attributed to interest in acreage beyond the location for which undeveloped reserves have been estimated. The Proved Developed category is the summation of the Proved Developed Producing and Proved Developed Non-Producing estimates.

Presentation

This report is divided into five main reserve category sections: Total Proved (“TP”), Proved Developed (“PD”), Proved Developed Producing (“PDP”), Proved Developed Non-Producing (“PDNP”) and Proved Undeveloped (“PUD”). Within each reserve category section are grand total Table I summaries for each of the main property areas and the entire reserve category. Each Table I presents composite reserve estimates and economic forecasts for the particular group of properties. Following each Table I in the TP section are Summary Plots, which are composite rate-time history-forecast curves for the corresponding group of properties. Table II “oneline” summaries are provided within the PDP, PDNP and PUD sections. The oneline summaries present estimates of ultimate recovery, gross and net reserves, ownership, revenue, expenses, investments, net income and discounted cash flow for the individual properties that make up the reserve category. The data presented in each Table I is explained in page 1 of the Appendix.

Hydrocarbon Pricing

The base oil and gas prices calculated for December 31, 2010 were $79.43 per barrel and $4.376 per MMBTU, respectively. As specified by the SEC, a company must use a 12-month average price, calculated as the unweighted 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 base oil price is based upon WTI-Cushing spot prices (EIA) during 2010 and the base gas price is based upon Henry Hub spot prices (Platt’s Gas Daily) during 2010.

The base prices were adjusted for differentials on a per-property basis, which may include local basis differentials, transportation, gas shrinkage, gas heating value (BTU content) and/or crude quality and gravity corrections. After these adjustments, the net realized prices over the life of the proved properties was estimated to be $74.339 per barrel for oil, $4.006 per MCF for gas and $42.28 per barrel for natural gas liquids. All economic factors were held constant in accordance with SEC guidelines.

Economic Parameters

Ownership was accepted as furnished and has not been independently confirmed. Oil and gas price differentials, gas shrinkage, ad valorem taxes, severance taxes, lease operating expenses and investments were calculated and prepared by EVEP and were thoroughly reviewed by us for accuracy, completeness and variance from prior years. Lease operating expenses were calculated based on historical lease operating statements. All economic parameters, including lease operating expenses and investments, were held constant (not escalated) throughout the life of these properties.

EV Energy Partners, L.P.

January 20, 2011

Page 3

SEC Conformance and Regulations

The reserve classifications and the economic considerations used herein conform to the criteria of the SEC as defined in pages 3 and 4 of the Appendix. The reserves and economics are predicated on regulatory agency classifications, rules, policies, laws, taxes and royalties currently in effect except as noted herein. EVEP’s operations may be subject to various levels of governmental controls and regulations. These controls and regulations may include matters relating to land tenure, drilling, production practices, environmental protection, marketing and pricing policies, royalties, various taxes and levies including income tax and are subject to change from time to time. Such changes in governmental regulations and policies may cause volumes of reserves actually recovered and amounts of income actually received to differ significantly from the estimated quantities.

This evaluation includes 659 proved undeveloped locations, with the bulk of the projected value from 285 locations in the Talon Barnett region (Texas) and 65 locations in the Jalmat region (New Mexico). Each of these drilling locations proposed as part of EVEP’s development plans conforms to the proved undeveloped standards as set forth by the SEC. In our opinion, EVEP has indicated they have every intent to complete this development plan as scheduled. Furthermore, EVEP has demonstrated that they have the proper company staffing, financial backing and prior development success to ensure the development plan will be fully executed. Reserves in the Austin Chalk region that are not scheduled to be developed within five years are delayed because of existing production through the vertical wellbores. Horizontal development through the utilization of those wellbores is scheduled to occur within the economic productive life of the vertical wells, or within a reasonable timeframe of the projected production economic limit.

Reserve Estimation Methods

The methods employed in estimating reserves are described in page 2 of the Appendix. Reserves for proved developed producing wells were estimated using production performance methods for the vast majority of properties. Certain new producing properties with very little production history were forecast using a combination of production performance and analogy to offset production, both of which are considered to provide a relatively high degree of accuracy.

Non-producing reserve estimates, for both developed and undeveloped properties, were forecast using either volumetric or analogy methods, or a combination of both. These methods provide a relatively high degree of accuracy for predicting proved developed non-producing and proved undeveloped reserves for EVEP properties, due to the mature nature of their properties targeted for development and an abundance of subsurface control data. The assumptions, data, methods and procedures used herein are appropriate for the purpose served by this report.

General Discussion

The estimates and forecasts were based upon interpretations of data furnished by your office and available from our files. To some extent information from public records has been used to check and/or supplement these data. The basic engineering and geological data were subject to third party reservations and qualifications. Nothing has come to our attention, however, that would cause us to believe that we are not justified in relying on such data. All estimates represent our best judgment based on the data available at the time of preparation. Reserves estimates will generally be revised as additional geologic or engineering data become available or as economic conditions change. Moreover, estimates of reserves may increase or decrease as a result of future operations, effects of regulation by governmental agencies or geopolitical or economic risks. As a result, the estimates of oil and gas reserves have an intrinsic uncertainty. The reserves included in this report are therefore estimates only and should not be construed as being exact quantities. They may or may not be actually recovered, and if recovered, the revenues therefrom, and the actual costs related thereto, could be more or less than the estimated amounts.

EV Energy Partners, L.P.

January 20, 2011

Page 4

An on-site field inspection of the properties has not been performed. The mechanical operation or condition of the wells and their related facilities have not been examined nor have the wells been tested by Cawley, Gillespie & Associates, Inc. Possible environmental liability related to the properties has not been investigated nor considered. The cost of plugging and the salvage value of equipment at abandonment have not been included.

Cawley, Gillespie & Associates, Inc. is a Texas Registered Engineering Firm (F-693), made up of independent registered professional engineers and geologists that have provided petroleum consulting services to the oil and gas industry for over 50 years. This evaluation was supervised by W. Todd Brooker, Vice President at Cawley, Gillespie & Associates, Inc. and a State of Texas Licensed Professional Engineer (License #83462). We do not own an interest in the properties or EV Energy Partners, L.P. and are not employed on a contingent basis. We have used all methods and procedures that we consider necessary under the circumstances to prepare this report. Our work-papers and related data utilized in the preparation of these estimates are available in our office.

	Yours very truly,

	CAWLEY, GILLESPIE & ASSOCIATES, INC.
	Texas Registered Engineering Firm F-693

	W. Todd Brooker, P. E.
	Vice President

APPENDIX

Explanatory Comments for Summary Tables

HEADINGS

Table I

Description of Table Information

Identity of Interest Evaluated

Property Description – Location

Reserve Classification and Development Status

Effective Date of Evaluation

FORECAST

(Columns)

(1) (11) (21)		Calendar or Fiscal years/months commencing on effective date.
(2) (3) (4)		Gross Production (8/8th) for the years/months which are economical. These are expressed as thousands of barrels (Mbbl) and millions of cubic feet (MMcf) of gas at standard conditions. Total future production, cumulative production to effective date, and ultimate recovery at the effective date are shown following the annual/monthly forecasts.
(5) (6) (7)		Net Production accruable to evaluated interest is calculated by multiplying the revenue interest times the gross production. These values take into account changes in interest and gas shrinkage.
(8)		Average (volume weighted) gross liquid price per barrel before deducting production-severance taxes.
(9)		Average (volume weighted) gross gas price per Mcf before deducting production-severance taxes.
(10)		Average (volume weighted) gross NGL price per barrel before deducting production-severance taxes.
(12)		Revenue derived from oil sales — column (5) times column (8).
(13)		Revenue derived from gas sales — column (6) times column (9).
(14)		Revenue derived from NGL sales — column (7) times column (10).
(15)		Revenue derived from hedge positions.
(16)		Total Revenue – sum of column (12) through column (15).
(17)		Net Profits Paid – Net profits interest burden times cash flow, where cash flow is column (16) minus column (18), column (19), column (22), column (25), column (26), column (27) and column (29).
(18)		Production-Severance taxes deducted from gross oil, gas and NGL revenue.
(19)		Ad Valorem taxes.
(20)		Net MMCFE6 represents the equivalent net gas volume and is equal to column (6) plus the sum of column (5) and column (7) multiplied by 6.0.
(22)		Operating Expenses are direct operating expenses to the evaluated working interest.
(23)		Average gross wells.
(24)		Average net wells are gross wells times working interest.
(25)		Misc Expense1 are non-direct operating expenses and may include maintenance, well service, compressor, tubing, and pump repair.
(26)		Misc Expense2 are expenses not included in column (22) or column (25).
(27)		Other Deductions may include compression-gathering expenses, transportation costs and water disposal costs.
(28)		Investments, if any, include re-completions, future drilling costs, pumping units, etc. and may include either tangible or intangible or both, and the costs for plugging and the salvage value of equipment at abandonment may be shown as negative investments at end of life.
(29) (30)		Future Net Cash Flow is column (18) less the total of column (19), column (22), column (25), column (26), column (27) and column (28). The data in column (29) are accumulated in column (30). Federal income taxes have not been considered.
(31)		Cumulative Discounted Cash Flow is calculated by discounting monthly cash flows at the specified annual rates.

MISCELLANEOUS

DCF Profile	•	The cumulative cash flow discounted at six different interest rates are shown at the bottom of columns (30-31). Interest has been compounded monthly.
Life	•	The economic life of the appraised property is noted in the lower right-hand corner of the table.
Footnotes	•	Comments regarding the evaluation may be shown in the lower left-hand footnotes.
Price Deck	•	A table of oil and gas prices, price caps and escalation rates may be shown in the lower middle footnotes.
Differentials	•	Total annual price adjustments may be shown in gray font to the left of column (8), column (9) and column (10).

APPENDIX

Methods Employed in the Estimation of Reserves

The four methods customarily employed in the estimation of reserves are (1) Production Performance, (2) Material Balance, (3) Volumetric and (4) Analogy. Most estimates, although based primarily on one method, utilize other methods depending on the nature and extent of the data available and the characteristics of the reservoirs.

Basic information includes production, pressure, geological and laboratory data. However, a large variation exists in the quality, quantity and types of information available on individual properties. Operators are generally required by regulatory authorities to file monthly production reports and may be required to measure and report periodically such data as well pressures, gas-oil ratios, well tests, etc. As a general rule, an operator has complete discretion in obtaining and/or making available geological and engineering data. The resulting lack of uniformity in data renders impossible the application of identical methods to all properties, and may result in significant differences in the accuracy and reliability of estimates.

A brief discussion of each method, its basis, data requirements, applicability and generalization as to its relative degree of accuracy follows:

Production Performance. This method employs graphical analyses of production data on the premise that all factors which have controlled the performance to date will continue to control and that historical trends can be extrapolated to predict future performance. The only information required is production history. Capacity production can usually be analyzed from graphs of rates versus time or cumulative production. This procedure is referred to as "decline curve" analysis. Both capacity and restricted production can, in some cases, be analyzed from graphs of producing rate relationships of the various production components. Reserve estimates obtained by this method are generally considered to have a relatively high degree of accuracy with the degree of accuracy increasing as production history accumulates.

Material Balance. This method employs the analysis of the relationship of production and pressure performance on the premise that the reservoir volume and its initial hydrocarbon content are fixed and that this initial hydrocarbon volume and recoveries therefrom can be estimated by analyzing changes in pressure with respect to production relationships. This method requires reliable pressure and temperature data, production data, fluid analyses and knowledge of the nature of the reservoir. The material balance method is applicable to all reservoirs, but the time and expense required for its use is dependent on the nature of the reservoir and its fluids. Reserves for depletion type reservoirs can be estimated from graphs of pressures corrected for compressibility versus cumulative production, requiring only data that are usually available. Estimates for other reservoir types require extensive data and involve complex calculations most suited to computer models which make this method generally applicable only to reservoirs where there is economic justification for its use. Reserve estimates obtained by this method are generally considered to have a degree of accuracy that is directly related to the complexity of the reservoir and the quality and quantity of data available.

Volumetric. This method employs analyses of physical measurements of rock and fluid properties to calculate the volume of hydrocarbons in-place. The data required are well information sufficient to determine reservoir subsurface datum, thickness, storage volume, fluid content and location. The volumetric method is most applicable to reservoirs which are not susceptible to analysis by production performance or material balance methods. These are most commonly newly developed and/or no-pressure depleting reservoirs. The amount of hydrocarbons in-place that can be recovered is not an integral part of the volumetric calculations but is an estimate inferred by other methods and a knowledge of the nature of the reservoir. Reserve estimates obtained by this method are generally considered to have a low degree of accuracy; but the degree of accuracy can be relatively high where rock quality and subsurface control is good and the nature of the reservoir is uncomplicated.

Analogy. This method which employs experience and judgment to estimate reserves is based on observations of similar situations and includes consideration of theoretical performance. The analogy method is applicable where the data are insufficient or so inconclusive that reliable reserve estimates cannot be made by other methods. Reserve estimates obtained by this method are generally considered to have a relatively low degree of accuracy.

Much of the information used in the estimation of reserves is itself arrived at by the use of estimates. These estimates are subject to continuing change as additional information becomes available. Reserve estimates which presently appear to be correct may be found to contain substantial errors as time passes and new information is obtained about well and reservoir performance.

APPENDIX

Reserve Definitions and Classifications

The Securities and Exchange Commission, in SX Reg. 210.4-10 dated November 18, 1981, as amended on September 19, 1989 and January 1, 2010, requires adherence to the following definitions of oil and gas reserves:

"(22) Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations— prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

"(i) The area of a reservoir considered as proved includes: (A) The area identified by drilling and limited by fluid contacts, if any, and (B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

"(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

"(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

"(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (B) The project has been approved for development by all necessary parties and entities, including governmental entities.

"(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

"(6) Developed oil and gas reserves. Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

“(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

“(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

"(31) Undeveloped oil and gas reserves. Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

“(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

“(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.

“(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.

"(18) Probable reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.

“(i) When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.

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

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

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

"(17) Possible reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.

“(i) When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.

“(ii) Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.

“(iii) Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.

“(iv) The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.

“(v) Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.

“(vi) Pursuant to paragraph (22)(iii) of this section (above), where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.”

Instruction 4 of Item 2(b) of Securities and Exchange Commission Regulation S-K was revised January 1, 2010 to state that "a registrant engaged in oil and gas producing activities shall provide the information required by Subpart 1200 of Regulation S–K." This is relevant in that Instruction 2 to paragraph (a)(2) states: “The registrant is permitted, but not required, to disclose probable or possible reserves pursuant to paragraphs (a)(2)(iv) through (a)(2)(vii) of this Item.”

"(26) Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

“Note to paragraph (26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).”

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