Exhibit 99.5

January 21, 2011

NFR Energy LLC
1415 Louisiana Street, Suite 1600
Houston, Texas 77002

Attention: Mr. Todd Levesque

		Re:		Reserves and Future Net Revenues
				As of December 31, 2010

Gentlemen:

     As requested, Miller and Lents, Ltd. (MLL) estimated the reserves and projected the future net revenues attributable to the interests of NFR Energy LLC (NFR) in certain oil and gas properties located primarily in East Texas, Montana, and Utah as of December 31, 2010. The report was prepared for NFR’s use in reserves and financial reporting and planning and was completed on January 19, 2011. The aggregate results of our evaluations, using constant product prices determined under Security and Exchange Commission (SEC) guidelines for year-end 2010 are summarized below. In this table and for some summaries herein, MLL consolidated natural gas liquids (NGLs), oil, and condensate together as hydrocarbon “liquids”.

Reserves and Future Net Revenues as of December 31, 2010

		Net Reserves								Future Net Revenues
														Discounted at
		Liquids,				Gas,				Undiscounted,				10% Per Year,
Reserves Category		MBbls.				MMcf				M$				M$
Proved Developed Producing			4,736.7				215,560.7				792,809.9				381,979.1
Proved Developed Nonproducing			1,416.9				80,078.8				231,768.9				77,871.2
Proved Undeveloped			9,859.3				815,277.6				1,561,277.1				125,823.5
Total Proved			16,012.8				1,110,917.2				2,585,855.8				585,673.6
Probable			4,836.2				802,280.9				923,444.8				-132,694.6
Possible			587.1				53,958.0				126,010.0				19,048.5

Two Houston Center • 9O9 Fannin Street, Suite 1300 • Houston, Texas 77010
Telephone 713-651-9455 • Telefax 713-654-9914 • e-mail: mail@millerandlents.com

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Definitions

     The reserves reported herein conform to the standards of the Petroleum Resources Management System (PRMS), which was prepared by the Oil and Gas Reserves Committee of the Society of Petroleum Engineers (SPE). The document (SPE-PRMS) was reviewed and jointly sponsored by the World Petroleum Council, the American Association of Petroleum Geologists, and the Society of Petroleum Evaluation Engineers. Definitions from the SPE-PRMS are included in Appendix 1. The reserves are also in accordance with the definitions contained in SEC Regulation S-X, Rule 4-10(a) as shown in Appendix 2. Prices used herein represent the twelve month average of the first-day-of-the-month price for each month within the twelve month period prior to December 31, 2010 as required by SEC guidelines.

     Future net revenues, as used herein, are defined as the total gross revenues less royalty, production taxes, operating costs, and capital expenditures. Future net revenues do not include deductions for federal income tax. The future net revenues were discounted at 10 percent per year (referenced later herein as “discounted future net revenues”) in accordance with SEC guidelines and to illustrate the time value of future cash flows. Estimates of future net revenues and discounted future net revenues are not intended and should not be interpreted to represent fair market values for the estimated reserves.

Reserves Considerations

     NFR has advised us that MLL’s estimates herein represent 100 percent of its booked reserves for year-end 2010. All reserves are in the United States and are grouped into two geographic divisions. The properties in NFR’s East Texas Division evaluated herein are located primarily in East Texas, but one lease is in western Louisiana. The properties in NFR’s Rockies Division include several fields in north-central Montana and one field in Utah. Reserves projected for the East Texas area are generally from reservoirs at depths below 7,000 feet that produce gas with modest condensate yields. Reserves projected for the Montana properties are generally from reservoirs shallower than 3,000 feet and produce dry gas. Reserves projected for the Utah properties are from reservoirs at depths below 8,000 feet and typically produce gas with low condensate yields. Discussion of the properties in NFR’s two divisions follows.

East Texas Division

     In the East Texas area, numerous reservoirs are productive. The zones are primarily gas-bearing, have very low average permeabilities, and range in depth from approximately 7,000 feet to more than 14,000 feet. Reservoirs include (from shallowest to deepest) Pettit, Travis Peak, Upper Cotton Valley, Lower Cotton Valley, Bossier, Haynesville, and Cotton Valley Lime. Most of the development to date has been with vertical wells and large hydraulic fracture treatments.

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     Most of NFR’s current production and much of the proved undeveloped reserves are from the Taylor section of the Lower Cotton Valley. Shallower zones are behind pipe opportunities in existing wells and incremental reserves opportunities in proposed vertical locations targeting the Taylor zone. Deeper zones are generally developed with separate wells.

     Vertical wells can be used to produce multiple zones and vertical well development continues to be NFR’s planned scheme for some locations. However, much work has been done over the past two years to evaluate and optimize the use of horizontal wells, particularly in the Taylor interval and in the Haynesville shale. NFR is now planning horizontal wells for essentially all future Haynesville shale development and many undeveloped Cotton Valley areas. Typically, future NFR planned horizontal wells are projected to have lateral lengths of 3,500 feet or more (unless restricted by lease geometry), oriented perpendicular to the main fracture plan in the reservoir. Hydraulic fracture stages spaced about 400 feet apart along the laterals are planned. Currently, spacing between horizontal laterals is ultimately expected to be 600 feet.

     Reserves for existing wells were based on extrapolation of production performance generally using hyperbolic decline curves to a minimum exponential decline rate of four percent per year. Reserves for vertical development locations on each lease were based on analogies using the average ultimate recovery per well determined by extrapolating production for surrounding wells. Production of the undeveloped reserves was forecast based on the development schedule provided by NFR and type curves based on the initial production rate and estimated ultimate recoveries from nearby wells.

     Reserves and production profiles for future Haynesville horizontal wells are based on actual average performance trends from NFR wells, adjusted for expected lateral length, net pay thickness, and well density currently planned for the subject lease. For locations expected to be 4,800 feet or more from another well when drilled, no interference effects are included. As additional wells are drilled at closer intervals, increasing interference effects are assumed and incremental reserves from new wells are reduced. Ultimately, for a lease fully developed with horizontal wells spaced 600 feet apart, MLL assumed the total reserves from all wells on the lease would be only 75 percent of the total derived by multiplying (a) the reserves assigned to the first lease development well by (b) the total number of potential wells on 600-foot spacing.

     MLL should emphasize at this point that we have no reliable data on interference effects in the Haynesville at this time. It is possible that interference effects may be more or less than the 25 percent reduction assumed for full development on 600-foot well spacing. However, the assumed interference seems to us a reasonable approximation based on our long experience with gradual downspacing in low permeability reservoirs.

     Reserves and production profiles for future Cotton Valley horizontal wells were based on models built to compare the actual performance and future extrapolation of horizontal wells (adjusted for the number of frac stages) with actual performance and future extrapolation of adjacent vertical wells. Results from such models were consistent in areas of mature development versus new development and from area to area. The average estimated ultimate recovery (EUR) per frac stage for a horizontal well is approximately 0.60 times the EUR for a vertical well and the initial 30-day average production rate for a horizontal frac stage is approximately 0.66 times that of a vertical well.

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     For this report, vertical well development on 40-acre spacing was assumed based on current regulatory restrictions. Further downspacing may be economically viable in some areas in the future. Wherever vertical well development opportunities are pursued, all viable pay zones are expected to be opened, selectively stimulated, and then commingled for long-term depletion. Although initial pressures are significantly different among the target reservoirs, all are tight gas reservoirs and pressures near well bores can be drawn down to low levels quickly after production begins. Therefore, after relatively short periods of individual zone testing, effective commingling is expected. Although it may be possible to access behind pipe zones in the vertical section of horizontal wells, no behind pipe or incremental undeveloped reserves were projected herein for existing or planned horizontal wells.

     Condensate yields were projected based on actual yields reported for NFR wells. Generally, shallower zones are richer in condensate than deeper zones. For wells connected to gas processing plants and undrilled locations on leases with wells connected to plants, NGLs are projected based on NGL yields obtained from processing plant reports or sales records provided by NFR. Where NGLs are projected, net residue gas sales are reported herein as gas reserves. Where no NGLs are projected, wellhead gas volumes are reported herein as gas reserves. For the table on the first page of this report, MLL consolidated the NGLs with oil and condensate to report hydrocarbon “liquids” reserves.

     Typically, once processing of gas production from a well begins, processing would be expected to continue in the future. However, the status of gas processing for some NFR wells may change as gathering systems are modified and plant optimization plans are implemented. Such changes may be particularly relevant to Haynesville gas production as processing of that gas is financially less attractive than gas from Cotton Valley and shallower zones due to gas composition differences.

     Some identified development locations are uneconomic based on MLL estimates and SEC-compliant prices and are not included herein. For purposes of this report, projections with positive future net revenues were considered economic even if discounted future net revenues were negative. Many of NFR’s projected Haynesville development wells have positive undiscounted future net revenues but negative discounted future net revenues due to low SEC-compliant gas prices, which are, on average, lower than current market prices.

Rockies Division

     The NFR properties from the Klabzuba acquisition are located in the Bearpaw Arch in north-central Montana. Production is primarily dry gas from shallow clastic reservoir targets including Judith River, Eagle Sandstone, Medicine Hat, Niobrara, and Sawtooth at depths less than 3,000 feet. Current production and future development is based primarily on 160-acre spacing although some reservoirs are being developed on 80-acre spacing.

     The NFR properties from the Gasco acquisition are located in the Riverbend Field of Utah. Production is primarily gas with modest condensate yields. From one to six reservoirs are productive at various locations across the field.

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Attention: Mr. Todd Levesque		Page 5

     Reserves for existing wells were based on extrapolation of production performance, generally using hyperbolic decline curves to a minimum exponential decline rate of six percent per year. Reserves for undeveloped locations are based on analogy, considering the performance of existing wells in the subject area and reservoir.

Economic Considerations

     Future prices and costs were projected based on information provided by NFR. No future escalation of prices or costs were assumed. Operating costs, price differentials from selected benchmarks, and BTU and shrinkage adjustments were included for each well or lease, based on recent actual averages. Operating expenses included both a component cost per well month and a component cost per Mcf produced. Ad valorem and severance taxes were projected based on recent averages, legislated rates, or adjustments used for high cost gas wells in Texas. Capital costs for drilling and completion of future wells and recompletion of existing wells were based on NFR’s recent actual experience and estimates.

     Product prices were projected using selected spot price benchmarks (West Texas Intermediate crude oil sold at Cushing, Oklahoma and gas sold at the Henry Hub) with appropriate differentials applied for each well, lease, or area. The SEC prices applicable for year-end 2010 reserves disclosures are calculated for each product as the average of the prices existent on the first day of each month in 2010. For our cash flow projections, constant prices were used throughout the life of production in accordance with SEC guidelines. The SEC-compliant benchmark prices used herein were $79.43 per barrel for oil and $4.376 per million Btu for gas. The actual average prices used in this report for proved reserves, after appropriate adjustments, were $70.60 per barrel for oil, $39.04 per barrel for NGLs, and $4.53 per Mcf for gas.

Attachments

     Attached Figure 1 is a plot of historical and forecast production for NFR’s properties. Incremental layers of production are shown by reserves category. Figure 2 is a pie chart showing total net reserves and future net revenues by reserves category. Figure 3 is a chart showing net reserves and gross revenues to NFR by product. Figure 4 is a chart showing net proved reserves and associated future net revenues by division. Figure 5 is a chart showing net proved reserves and associated future net revenues by acquisition group. Figures 6 through 15 are charts showing total net reserves and future net revenues by category for each acquisition group. Note that the pie charts do not differentiate between positive and negative discounted net revenues, but the tables below the charts do.

     Attached Exhibits 1 through 6 are summary totals by reserves category showing annual projections of reserves and cash flows. Exhibit 7 is a one-line summary showing reserves and future cash flows for each of our evaluation cases, grouped by reserves category and sorted alphabetically by entity name within each category. Exhibit 8 is a one-line summary grouped by Acquisition (designated by NFR) then sorted by reserves category and entity name. Exhibit 9 is a one-line summary sorted alphabetically by entity name, without reserves category or acquisition groupings. Exhibit 10 is a one-

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line summary ranking of entities (from highest to lowest discounted future net revenues) within each reserves category. On all the one-line summaries, the East Texas Division properties and the Rockies Division properties are grouped separately.

     Indexes are provided at the beginning of the attached Figures and Exhibits sections, respectively.

Other Considerations

     The timing of production start from development drilling and from recompletions was based on estimates or schedules provided by NFR. Capital costs for development well drilling were generally incorporated into our cash flows from one to five months before production start, based on recent experience with new wells in various areas and reservoirs. Costs for recompletion workovers were generally incorporated one month before production start, and completion costs for all wells were generally incorporated just before production start.

     The probable and possible reserves volumes and the estimated future net revenues therefrom have not been adjusted for uncertainty. Caution should be exercised when aggregated reserves or revenues from different classifications are used without appropriate risk adjustment.

     Future costs of abandoning facilities and wells and any future costs of restoration of producing fields to satisfy environmental standards were not deducted from total revenues as such estimates are considered separately from our reserves report in NFR’s financial accounting.

     Gas volumes are reported at the standard pressure base used for each state. Therefore, some aggregates shown herein are at a mixed pressure base.

     Well counts, as reported in the various economic output tables, actually represent completions and recompletions. Thus, a single well bore may be counted more than once in the total well count.

     In conducting this evaluation, MLL relied upon production histories; accounting and cost data; ownership; geological, geophysical, and engineering data; development plans supplied by NFR; and upon non-confidential data from public records or commercial data services. These data were accepted as represented and are considered appropriate for the purpose served by the report. MLL used all methods, procedures, and assumptions as it considered necessary and appropriate under the circumstances in using the data provided to prepare the report.

     The evaluations presented in this report, with the exceptions of those parameters specified by others, reflect MLL’s informed judgments and are subject to inherent uncertainties associated with the interpretation of geological, geophysical, and engineering information. These uncertainties include but are not limited to the utilization of indirect or imprecise data and the application of professional judgment in performing these evaluations. Government policies and market conditions different from those employed in this study may cause the total quantity of oil or gas to be recovered, actual production rates, prices received, or operating and capital costs to vary from those presented in this

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report. At this time, MLL is not aware of any regulations that would affect NFR’s ability to recover the estimated reserves. Minor precision inconsistencies in subtotals may exist in the report due to truncation or rounding of aggregated values.

     Miller and Lents, Ltd. is an independent oil and gas consulting firm. No director, officer, or key employee of Miller and Lents, Ltd. has any financial ownership in NFR Energy LLC, or any affiliate. Our compensation for the required investigations and preparation of this report is not contingent on the results obtained and reported, and we have not performed other work that would affect our objectivity. Production of this report was supervised by Carl D. Richard, an officer of the firm who is a professionally qualified and licensed Professional Engineer in the State of Texas with more than 25 years of relevant experience in the estimation, assessment, and evaluation of oil and gas reserves.

		Very truly yours,
		MILLER AND LENTS, LTD. Texas Registered Engineering Firm, No, F-1442
		By		R. W. Frazier, P.E. Senior Consultant
		By		Leslie A. Fallon, P.E. Vice President
		By		Carl D. Richard, P.E Senior Vice President

RWF/psh

Appendix 1
Page 1 of 3

Definitions and Guidelines for Petroleum Resources

Recoverable Resources
Classes and Sub-Classes

Reserves

     Reserves are those quantities of petroleum anticipated to be commercially recoverable by application of development projects to known accumulations from a given date forward under defined conditions.

     Reserves must satisfy four criteria: they must be discovered, recoverable, commercial, and remaining based on the development project(s) applied. Reserves are further subdivided in accordance with the level of certainty associated with the estimates and may be sub-classified based on project maturity and/or characterized by their development and production status.

     To be included in the Reserves class, a project must be sufficiently defined to establish its commercial viability. There must be a reasonable expectation that all required internal and external approvals will be forthcoming, and there is evidence of firm intention to proceed with development within a reasonable time frame.

     A reasonable time frame for the initiation of development depends on the specific circumstances and varies according to the scope of the project. While 5 years is recommended as a benchmark, a longer time frame could be applied where, for example, development of economic projects are deferred at the option of the producer for, among other things, market-related reasons, or to meet contractual or strategic objectives. In all cases, the justification for classification as Reserves should be clearly documented.

     To be included in the Reserves class, there must be a high confidence in the commercial producibility of the reservoir as supported by actual production or formation tests. In certain cases, Reserves may be assigned on the basis of well logs and/or core analysis that indicate that the subject reservoir is hydrocarbon-bearing and is analogous to reservoirs in the same area that are producing or have demonstrated the ability to produce on formation tests.

     On Production. The development project is currently producing and selling petroleum to market. The key criterion is that the project is receiving income from sales, rather than the approved development project necessarily being complete. This is the point at which the project “chance of commerciality” can be said to be 100%. The project “decision gate” is the decision to initiate commercial production from the project.

     Approved for Development. All necessary approvals have been obtained, capital funds have been committed, and implementation of the development project is under way. At this point, it must be certain that the development project is going ahead. The project must not be subject to any contingencies such as outstanding regulatory approvals or sales contracts. Forecast capital expenditures should be included in the reporting entity’s current or following year’s approved budget. The project “decision gate” is the decision to start investing capital in the construction of production facilities and/or drilling development wells.

     Justified for Development. Implementation of the development project is justified on the basis of reasonable forecast commercial conditions at the time of reporting, and there are reasonable expectations that all necessary approvals/contracts will be obtained.

     In order to move to this level of project maturity, and hence have reserves associated with it, the development project must be commercially viable at the time of reporting, based on the reporting entity’s assumptions of future prices, costs, etc. (“forecast case”) and the specific circumstances of the project. Evidence of a firm intention to proceed with development within a reasonable time frame will be sufficient to demonstrate commerciality. There should be a development plan in sufficient detail to support the assessment of commerciality and a reasonable expectation that any regulatory approvals or sales contracts required prior to project implementation will be forthcoming. Other than such approvals/contracts, there should be no known contingencies that could preclude the development from proceeding within a reasonable timeframe (see Reserves class).

     The project “decision gate” is the decision by the reporting entity and its partners, if any, that the project has reached a level of technical and commercial maturity sufficient to justify proceeding with development at that point in time.

Contingent Resources

     Those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations by application of development projects, but which are not currently considered to be commercially recoverable due to one or more contingencies.

     Contingent Resources may include, for example, projects for which there are currently no viable markets, or where commercial recovery is dependent on technology under development, or where evaluation of the accumulation is insufficient to clearly assess commerciality. Contingent Resources are further categorized in accordance with the level of certainty associated with the estimates and may be sub-classified based on project maturity and/or characterized by their economic status.

     Development Pending. A discovered accumulation where project activities are ongoing to justify commercial development in the foreseeable future.

     The project is seen to have reasonable potential for eventual commercial development, to the extent that further data acquisition (e.g. drilling, seismic data) and/or evaluations are currently ongoing with a view to confirming that the project is commercially viable and providing the basis for selection of an appropriate development plan. The critical contingencies have been identified and are reasonably expected to be resolved within a reasonable time frame. Note that disappointing appraisal/evaluation results could lead to a re-classification of the project to “On Hold” or “Not Viable” status.

     The project “decision gate” is the decision to undertake further data acquisition and/or studies designed to move the project to a level of technical and commercial maturity at which a decision can be made to proceed with development and production.

Appendix 1
Page 2 of 3

     Development Unclarified or on Hold. A discovered accumulation where project activities are on hold and/or where justification as a commercial development may be subject to significant delay.

     The project is seen to have potential for eventual commercial development, but further appraisal/evaluation activities are on hold pending the removal of significant contingencies external to the project, or substantial further appraisal/evaluation activities are required to clarify the potential for eventual commercial development. Development may be subject to a significant time delay. Note that a change in circumstances, such that there is no longer a reasonable expectation that a critical contingency can be removed in the foreseeable future, for example, could lead to a re-classification of the project to “Not Viable” status.

     The project “decision gate” is the decision to either proceed with additional evaluation designed to clarify the potential for eventual commercial development or to temporarily suspend or delay further activities pending resolution of external contingencies.

     Development Not Viable. A discovered accumulation for which there are no current plans to develop or to acquire additional data at the time due to limited production potential.

     The project is not seen to have potential for eventual commercial development at the time of reporting, but the theoretically recoverable quantities are recorded so that the potential opportunity will be recognized in the event of a major change in technology or commercial conditions.

     The project “decision gate” is the decision not to undertake any further data acquisition or studies on the project for the foreseeable future.

Prospective Resources

     Those quantities of petroleum which are estimated, as of a given date, to be potentially recoverable from undiscovered accumulations.

     Potential accumulations are evaluated according to their chance of discovery and, assuming a discovery, the estimated quantities that would be recoverable under defined development projects. It is recognized that the development programs will be of significantly less detail and depend more heavily on analog developments in the earlier phases of exploration.

     Prospect. A project associated with a potential accumulation that is sufficiently well defined to represent a viable drilling target. Project activities are focused on assessing the chance of discovery and, assuming discovery, the range of potential recoverable quantities under a commercial development program.

     Lead. A project associated with a potential accumulation that is currently poorly defined and requires more data acquisition and/or evaluation in order to be classified as a prospect. Project activities are focused on acquiring additional data and/or undertaking further evaluation designed to confirm whether or not the lead can be matured into a prospect. Such evaluation includes the assessment of the chance of discovery and, assuming discovery, the range of potential recovery under feasible development scenarios.

     Play. A project associated with a prospective trend of potential prospects, but which requires more data acquisition and/or evaluation in order to define specific leads or prospects. Project activities are focused on acquiring additional data and/or undertaking further evaluation designed to define specific leads or prospects for more detailed analysis of their chance of discovery and, assuming discovery, the range of potential recovery under hypothetical development scenarios.

Reserves Category
Definitions and Guidelines

Proved Reserves

     Proved Reserves are those quantities of petroleum, which by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be commercially recoverable, from a given date forward, from known reservoirs and under defined economic conditions, operating methods, and government regulations.

     If deterministic methods are used, the term reasonable certainty is intended to express a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate.

     The area of the reservoir considered as Proved includes (1) the area delineated by drilling and defined by fluid contacts, if any, and (2) adjacent undrilled portions of the reservoir that can reasonably be judged as continuous with it and commercially productive on the basis of available geoscience and engineering data.

     In the absence of data on fluid contact, Proved quantities in a reservoir are limited by the lowest known hydrocarbon (LKH) as seen in a well penetration unless otherwise indicated by definitive geoscience, engineering, or performance data. Such definitive information may include pressure gradient analysis and seismic indicators. Seismic data alone may not be sufficient to define fluid contacts for Proved reserves (see “2001 Supplemental Guidelines,” Chapter 8).

     Reserves in undeveloped locations may be classified as Proved provided that:

Ø		The locations are in undrilled areas of the reservoir that can be judged with reasonable certainty to be commercially productive.
Ø		Interpretations of available geoscience and engineering data indicate with reasonable certainty that the objective formation is laterally continuous with drilled Proved locations.

     For Proved Reserves, the recovery efficiency applied to these reservoirs should be defined based on a range of possibilities supported by analogs and sound engineering judgment considering the characteristics of the Proved area and the applied development program.

Probable Reserves

     Probable reserves are those additional Reserves which analysis of geoscience and engineering data indicate are less likely to be recovered than Proved Reserves but more certain to be recovered than Possible Reserves.

     It is equally likely that actual remaining quantities recovered will be greater than or less than the sum of the estimated Proved plus Probable Reserves (2P). In this context, when probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the 2P estimate.

Appendix 1
Page 3 of 3

     Probable Reserves may be assigned to areas of a reservoir adjacent to Proved where data control or interpretations of available data are less certain. The interpreted reservoir continuity may not meet the reasonable certainty criteria.

     Probable estimates also include incremental recoveries associated with project recovery efficiencies beyond that assumed for Proved.

Possible Reserves

     Possible Reserves are those additional reserves which analysis of geoscience and engineering data indicate are less likely to be recoverable than Probable Reserves.

     The total quantities ultimately recovered from the project have a low probability to exceed the sum of Proved plus Probable plus Possible (3P), which is equivalent to the high estimate scenario. When probabilistic methods are used, there should be at least a 10% probability that the actual quantities recovered will equal or exceed the 3P estimate.

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

     Possible estimates also include incremental quantities associated with project recovery efficiencies beyond that assumed for Probable.

Probable and Possible Reserves

     (See above for separate criteria for Probable Reserves and Possible Reserves.)

     The 2P and 3P estimates may be based on reasonable alternative technical and commercial interpretations within the reservoir and/or subject project that are clearly documented, including comparisons to results in successful similar projects.

     In conventional accumulations, Probable and/or 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 minor faulting or other geological discontinuities and have not been penetrated by a wellbore but are interpreted to be in communication with the known (Proved) reservoir. Probable or Possible Reserves may be assigned to areas that are structurally higher than the Proved area. Possible (and in some cases, Probable) Reserves may be assigned to areas that are structurally lower than the adjacent Proved or 2P area.

     Caution should be exercised in assigning Reserves to adjacent reservoirs isolated by major, potentially sealing, faults until this reservoir is penetrated and evaluated as commercially productive. Justification for assigning Reserves in such cases should be clearly documented. Reserves should not be assigned to areas that are clearly separated from a known accumulation by non-productive reservoir (i.e. absence of reservoir, structurally low reservoir, or negative test results); such areas may contain Prospective Resources.

     In conventional accumulations, where drilling has defined a highest known oil (HKO) elevation and there exists the potential for an associated gas cap, Proved oil Reserves should only be assigned in the structurally higher portions of the reservoir if there is reasonable certainty that such portions are initially above bubble point pressure based on documented engineering analyses. Reservoir portions that do not meet this certainty may be assigned as Probable and Possible oil and/or gas based on reservoir fluid properties and pressure gradient interpretations.

Reserves Status
Definitions and Guidelines

Developed Reserves

     Developed Reserves are expected quantities to be recovered from existing wells and facilities.

     Reserves are considered developed only after the necessary equipment has been installed, or when the costs to do so are relatively minor compared to the cost of a well. Where required facilities become unavailable, it may be necessary to reclassify Developed Reserves as Undeveloped. Developed Reserves may be further sub-classified as Producing or Non-Producing.

     Developed Producing Reserves. Developed Producing Reserves are expected to be recovered from completion intervals that are open and producing at the time of the estimate.

     Improved recovery reserves are considered producing only after the improved recovery project is in operation.

     Developed Non-Producing Reserves. Developed Non-Producing Reserves include shut-in and behind-pipe Reserves.

     Shut-in Reserves are expected to be recovered from (1) completion intervals which are open at the time of the estimate but which have not yet started producing, (2) wells which were shut-in for market conditions or pipeline connections, or (3) wells not capable of production for mechanical reasons. Behind-pipe Reserves are expected to be recovered from zones in existing wells which will require additional completion work or future recompletion prior to start of production.

     In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.

Undeveloped Reserves

     Undeveloped Reserves are quantities expected to be recovered through future investments: (1) from new wells on undrilled acreage in known accumulations, (2) from deepening existing wells to a different (but known) reservoir, (3) from infill wells that will increase recovery, or (4) where a relatively large expenditure (e.g. when compared to the cost of drilling a new well) is required to (a) recomplete an existing well or (b) install production or transportation facilities for primary or improved recovery projects.

Prepared by the Oil and Gas Reserves Committee of the Society of Petroleum Engineers (SPE); reviewed and jointly sponsored by the World Petroleum Council (WPC), the American Association of Petroleum Geologists (AAPG); and the Society of Petroleum Evaluation Engineers (SPEE). Approved by the SPE Board of Directors, March 2007.

Appendix 2
Page 1 of 3

Reserves Definitions In Accordance With
Securities and Exchange Commission Regulation S-X

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.

     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).

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.

1.

The area of the reservoir considered as proved includes:

	a.		The area identified by drilling and limited by fluid contacts, if any, and
	b.		Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

	2.		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.
	3.		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.
	4.		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.

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5.

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.

Developed Oil and Gas Reserves

     Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

	1.		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
	2.		Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

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.

	1.		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.
	2.		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.
	3.		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 below, or by other evidence using reliable technology establishing reasonable certainty.

Analogous Reservoir

     Analogous reservoirs, as used in resources assessments, have similar rock and fluid properties, reservoir conditions (depth, temperature, and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of interest and thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery. When used to support proved reserves, an “analogous reservoir” refers to a reservoir that shares the following characteristics with the reservoir of interest:

	1.		Same geological formation (but not necessarily in pressure communication with the reservoir of interest);
	2.		Same environment of deposition;
	3.		Similar geological structure; and
	4.		Same drive mechanism.

     Reservoir properties must, in aggregate, be no more favorable in the analog than in the reservoir of interest.

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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.

	1.		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.
	2.		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.
	3.		Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.
	4.		See also guidelines in Items 4 and 6 under Possible Reserves.

Possible Reserves

     Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.

	1.		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.
	2.		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.
	3.		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.
	4.		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.
	5.		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.
	6.		Pursuant to Item 3 under Proved Oil and Gas Reserves, 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.