Exhibit 99.4

Cawley, Gillespie & Associates, Inc.

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
FAX 512-233-2618	FAX 817-877-3728	FAX 713-651-9980
	www.cgaus.com

September 12, 2007

Mr. Thomas Kaetzer

Baseline Oil & Gas Corp.

11811 N. Freeway (I-45)

Suite 200

Houston, Texas 77060

Re:	Evaluation Summary
	Baseline Oil & Gas Interests
	Proved & Probable Reserves
	Matagorda and Stephens Counties, Texas
	As of June 1, 2007

Dear Mr. Kaetzer:

As requested, we are submitting our estimates of proved and probable reserves and forecasts of economics attributable to the Baseline Oil & Gas (“Baseline”) interests in certain oil and gas properties located in various fields in Matagorda and Stephens Counties, Texas. The results of this evaluation are presented in the accompanying tabulations, with a composite summary presented below:

		Proved	Proved Developed Producing	Proved Developed Non-Producing	Proved Undeveloped	Probable
Net Reserves
Oil—Mbbl		5,861	3,100	747	2,015	2,046
Gas—MMcf		32,956	6,267	10,870	15,819	30,530
Net Revenue
Oil—M$		386,897	204,856	49,232	132,809	134,501
Gas—M$		256,953	48,982	79,964	128,007	233,079
Severance Taxes	–M$	37,069	13,097	8,262	15,710	23,668
Ad Valorem Taxes	–M$	18,522	6,847	3,848	7,827	11,430
Operating Expenses	–M$	158,057	108,590	23,472	25,995	41,686
Investments	–M$	41,659	1,348	4,315	35,996	34,365
Net Operating Income	–M$	388,543	123,957	89,298	175,289	256,431
Discounted @ 10%	–M$	213,596	78,139	33,091	102,366	106,926

The discounted cash flow values shown above should not be construed to represent an estimate of the fair market value by Cawley, Gillespie & Associates, Inc. (“CG&A”).

Baseline Oil & Gas Interests

September 12, 2007

Page 2

Presentation

The report is divided into five reserve category sections: Proved (“I-Proved”), Proved Developed Producing (“I-PDP”), Proved Developed Non-Producing (“I-PDNP”), Proved Undeveloped (“I-PUD”) and Probable (“I-Probable”). Within each reserve category section are Tables I which present composite reserve estimates and economic forecasts for the particular reserve category. The first Table I within each section is for the combined DSX Matagorda County and Baseline Stephens County properties. Following the combined Table I are Tables I for the DSX Matagorda County properties and for the Baseline Stephens County properties. Following the Tables I in each section are Table II “oneline” summaries that 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 corresponding Table I. Individual lease or well reserves and economics tables follow the Tables II in the PDP, PDNP, PUD and Probable sections of the report.

For a more detailed explanation of the report layout, please refer to the Table of Contents following this letter. The data presented in the tables are explained in page 1 of the Appendix. The methods employed in estimating reserves are described in page 2 of the Appendix.

Hydrocarbon Pricing

As requested, oil and gas prices were adjusted to the Strip prices as of August 29, 2007:

Year	WTI Cushing Crude Oil $/STB	Henry Hub Natural Gas $/MMBtu
2007	70.66	6.99
2008	69.11	7.83
2009	68.29	8.07
2010	67.87	7.83
2011	67.76	7.60
2012	67.81	7.40
Thereafter	67.81	7.40

Oil and gas price differentials were applied un-escalated on a per property basis as provided and include adjustments for basis differential, transportation and/or crude quality and gravity corrections. Gas shrinkage and heating value as provided were applied separately as corrections to net gas sales and net gas price, respectively.

Risking

Reserves and economics were not risked for any of the properties in this report.

Expenses and Taxes

Operating expenses and capital expenditures were not escalated. Initial lease operating expenses were forecast on a per-well basis based on historical expenses. Oil and gas severance tax values were determined by applying normal state severance tax rates. Ad Valorem taxes were 2.5% for Stephens County and 3.2% for Matagorda County.

Miscellaneous

An on-site field inspection of the properties has not been performed. The mechanical operation or conditions 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 salvage value of equipment at abandonment and the cost of plugging at abandonment have been included for the Stephens County properties.

Baseline Oil & Gas Interests

September 12, 2007

Page 3

The proved reserve classifications used conform to the criteria of the Securities and Exchange Commission (“SEC”) as defined in page 3 of the Appendix. The use of variable pricing does not conform to the criteria of the SEC. The inclusion of probable reserves does not conform to the criteria of the SEC. It is not intended that this report be used for any purpose requiring such conformity. The reserves and economics are predicated on regulatory agency classifications, rules, policies, laws, taxes and royalties in effect as noted herein. The possible effects of changes in legislation or other Federal or State restrictive actions have not been considered. All reserve estimates represent our best judgment based on data available at the time of preparation, and assumptions as to future economic and regulatory conditions. It should be realized that the reserves actually recovered, the revenue derived therefrom and the actual cost incurred could be more or less than the estimated amounts.

The reserve estimates were based on interpretations of factual data furnished by Baseline. Oil and gas prices, pricing differentials, expense data, capital investments, plug and abandonment costs, tax values and ownership interests were also supplied by Baseline and were accepted as furnished. 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.

This report was prepared for the exclusive use of Baseline Oil & Gas Corp. Third parties should not rely on it without the written consent of the above and Cawley, Gillespie & Associates, Inc. Our work papers and related data are available for inspection and review by authorized, interested parties.

Yours very truly,

CAWLEY, GILLESPIE & ASSOCIATES, INC.

Baseline Oil & Gas Interests

September 12, 2007

Page 4

TABLE OF CONTENTS

BASELINE OIL & GAS INTERESTS

PROVED AND PROBABLE RESERVES

AS OF JUNE 1, 2007

REPORT LETTER

TABLE OF CONTENTS

Strip Pricing

Proved Reserves

• Table I - Proved

• Table I – Proved – Matagorda County

• Table I – Proved – Stephens County

• Table II – Proved

Proved Developed Producing Reserves

• Table I - PDP

• Table I – PDP – Matagorda County

• Table I – PDP – Stephens County

• Table II – PDP

• Individual Reserves and Economics Tables 1 – 21

Proved Developed Non-Producing Reserves

• Table I - PDNP

• Table I – PDNP – Matagorda County

• Table I – PDNP – Stephens County

• Table II – PDNP

• Individual Reserves and Economics Tables 1 – 41

Proved Undeveloped Reserves

• Table I - PUD

• Table I – PUD – Matagorda County

• Table I – PUD – Stephens County

• Table II – PUD

• Individual Reserves and Economics Tables 1 – 34

Baseline Oil & Gas Interests

September 12, 2007

Page 5

Probable Reserves

• Table I - Probable

• Table I – Probable – Matagorda County

• Table I – Probable – Stephens County

• Table II – Probable

• Individual Reserves and Economics Tables 1 – 57

Appendix

• Page 1- Explanatory Comments for Summary Tables

• Page 2 - Methods Employed in the Estimation of Reserves

• Page 3 - Reserve Definitions and Classifications

Baseline Oil & Gas Interests

September 12, 2007

Page 6

APPENDIX

Explanatory Comments for Individual Tables

HEADINGS

Table Number

Effective Date of the Evaluation

Identity of Interest Evaluated

Reserve Classification and Development Status

Operator – Property Name

Field (Reservoir) Names – County, State

FORECAST

(Columns)

(1) (11)	Calendar or Fiscal years/months commencing on effective date.
(2)(3)	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.
(4)(5)	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.
(6)	Average (volume weighted) gross liquid price per barrel before deducting production-severance taxes.
(7)	Average (volume weighted) gross gas price per Mcf before deducting production-severance taxes.
(8)	Revenue derived from oil sales — column (4) times column (6).
(9)	Revenue derived from gas sales — column (5) times column (7).
(10)	Total Revenue — column (8) plus column (9) plus other miscellaneous revenue.
(12)	Production-severance taxes deducted from gross oil and gas revenue.
(13)	Ad valorem taxes.
(14)	Average gross wells.
(15)	Average net wells are gross wells times working interest.
(16)	Operating Expenses are direct operating expenses to the evaluated working interest, but may also include items noted below in “Other Deductions”. In addition, ad valorem taxes can also be included in this column.
(17)	Other Deductions include operator’s overhead, compression-gathering expenses, transportation costs, water disposal costs and net profits burdens. These are the share of costs payable by the evaluated expense interests and take into account any changes in interests.
(18)	Investments, if any, include work-overs, future drilling costs, pumping units, etc. and may be included 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.
(20)	Future Net Cash Flow is column (10) less columns (12), (13), (16), (17) and (18). The data in column (19) are accumulated in column (20). Federal income taxes have not been considered.
(21)	Cumulative Discounted Cash Flow is calculated by discounting monthly cash flows at the specified annual rates.

MISCELLANEOUS

Input Data	•        Evaluation parameters such as rates, tax percentages, and expenses are shown below columns (11-17).
Interests	•        Initial and final expense and revenue interests are shown below columns (18-19).
DCF Profile	•        The cash flow discounted at six different rates are shown at the bottom of columns (20-21). Interest has been compounded once per year.
Life	•        The economic life of the appraised property is noted in the lower right-hand corner of the table.
Footnotes	•        Well ID information or other pertinent comments may be shown in the lower left-hand footnotes.

Baseline Oil & Gas Interests

September 12, 2007

Page 7

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 makes 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.

Baseline Oil & Gas Interests

September 12, 2007

Page 8

APPENDIX

Reserve Definitions and Classifications

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

“(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: (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 un-drilled prospects.

“(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 un-drilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on un-drilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other un-drilled 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.”

Instruction 4 of Item 2(b) of Securities and Exchange Commission Regulation S-K states that “disclosure of estimates of probable or possible reserves and any estimated value thereof shall not be disclosed in any document publicly filed with the Commission.” In evaluation reports prepared for other than Securities and Exchange Commission purposes, Cawley, Gillespie & Associates, Inc. may include “probable” and “possible” reserves based on the following definitions:

Probable oil and gas reserves. Probable oil and gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data infer to be commercially recoverable but where uncertainty as to this data preclude the classification of these reserves as “proved”. The degree of risk in relying on estimates of “probable” reserves is greater than for “proved” reserves.

Possible oil and gas reserves. Possible oil and gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which limited geological and engineering data infer to be commercially recoverable but where uncertainty as to this data preclude the classification of these reserves as “probable”. The degree of risk in relying on estimates of “possible” reserves is greater than for “probable” reserves.