Baseline Oil & Gas (BOGA) 8-K Other Events

Exhibit 99.2

OFFERING CIRCULAR SUMMARY

This summary highlights certain information concerning our business and this offering. Because this is a summary, it may not contain all of the information that may be important to you and to your investment decision. The following summary is qualified in its entirety by the more detailed information and financial statements and notes thereto included elsewhere in this offering circular. You should read this offering circular carefully and should consider, among other things, the matters set forth in “Risk Factors” before deciding to invest in the notes. In this offering circular, unless indicated otherwise, references to “Baseline,” the “Company,” “our company,” “we,” “our” and “us” refer to Baseline Oil & Gas Corp. The estimates of our proved reserves as of June 1, 2007 included in this offering circular are based on a reserve report prepared by Cawley, Gillespie & Associates, Inc., independent petroleum engineers (“CG&A” and the “CG&A Reserve Report”). A summary of the CG&A Reserve Report is included in this offering circular as Appendix A. Except as otherwise noted, this offering circular does not give effect to the DSX Acquisition. For the definition of “EBITDA” and “PV-10” and information about the limitations of the use of such non-GAAP financial measures, see “Non-GAAP Financial Measures” and “Summary Historical and Pro Forma Combined Financial Information.” Please see “Offering Circular Summary—Summary Reserve and Operating Data” for a reconciliation of PV-10 to NYMEX PV-10. As used herein, the “Transactions” means the consummation of this offering and the convertible subordinated notes offering, our entering into a new revolving credit facility (the “New Credit Agreement”) concurrently with the closing of this offering, the DSX Acquisition and the application of the proceeds from this offering as set forth under “Use of Proceeds.”

Company Overview

We are a Houston, Texas-based independent oil and natural gas company engaged in the exploration, production, development, acquisition and exploitation of natural gas and crude oil properties, with interests in the Eliasville Field in North Texas (the “North Texas Properties”) and the New Albany Shale in Southern Indiana. On August 7, 2007, we entered into an Asset Purchase and Sale Agreement (the “Purchase Agreement”) dated effective June 1, 2007, to acquire from DSX Energy Limited, LLP (the “DSX Acquisition”) certain oil and gas properties located in the Blessing Field in Matagorda County onshore along the Texas Gulf Coast (the “DSX Properties”). The DSX Acquisition substantially increases our reserve base, provides us with an extensive portfolio of low-risk drilling opportunities, increases our geographic and geological well diversification, and provides us with a balanced commodity mix (51% oil / 49% gas).

Pro forma for the DSX Acquisition, our properties cover 39,945 net acres across three core areas of operation. Immediately following the DSX Acquisition, we will own a working interest of over 95% and an average 74% net revenue interest in our two Texas properties, and operate 100% of the wells that presently comprise our PV-10. This will enable us to more efficiently manage our operating costs, capital expenditures and the timing and method of development of our properties. In addition to our development opportunity in Southern Indiana, the proved developed nonproducing, proved undeveloped and non-proved reserves identified in the North Texas Properties and the DSX Properties include over 150 drilling and workover opportunities. Upon the consummation of the offering, we will implement an active development program to exploit these opportunities. We believe this development program alone will enable us to significantly grow our reserves, production and cash flow.

As of June 1, 2007, based on the CG&A Reserve Report, pro forma for the DSX Acquisition, we had 67.7 Bcfe of proved reserves, of which 48.7% were natural gas and 58.8% were proved developed. The PV-10 and NYMEX PV-10 of these proved reserves as of that date were $203.5 million and $213.6 million, respectively, on a pro forma basis. See “Non-GAAP Financial Measures” and “Offering Circular Summary—Summary Reserve and Operating Data” as well as “Business—Proved Reserves” for a reconciliation of PV-10 to the standardized measure of discounted future net cash flows. Our average pro forma net production for the three month period from May 1, 2007 to July 31, 2007 was 11.4 MMcfe/d, with a remaining reserve life of 16.3 years.

Reserve and Production Overview

Unless otherwise noted, the following table summarizes certain statistics for Baseline and the DSX Properties separately and Baseline on a combined pro forma basis after giving effect to the DSX Acquisition as of June 1, 2007.

	Baseline			DSX Properties			Combined Pro Forma
Proved Reserves (Bcfe)(1):
Proved Developed Producing Reserves		16.3			8.1			24.4
Proved Developed Nonproducing Reserves		2.4			13.0			15.3
Proved Undeveloped Reserves		6.8			21.1			27.9
Total Proved Reserves		25.4			42.2			67.7
PV-10 (dollars in thousands)	$	59,717		$	143,803		$	203,521
NYMEX PV-10(2) (dollars in thousands)	$	67,143		$	146,453		$	213,596
Other Data:
Proved Reserve Mix—% Natural Gas		2	%		77	%		49	%
Net Acreage		37,571			2,374			39,945
Net Producing Wells		82			12			94
Current Daily Net Production (MMcfe/d)(3)		3.0			8.3			11.4
Remaining Reserve Life (Years)(4)		22.9			13.9			16.3

⁽¹⁾ Based on May 31, 2007 prices of $64.02 per Bbl and $7.75 per MMBtu. See “Non-GAAP Financial Measures” and “Business—Proved Reserves” for a reconciliation of PV-10 to the standardized measure of discounted future net cash flows.

⁽²⁾ Based on NYMEX forward pricing on August 29, 2007. See “Non-GAAP Financial Measures” and, for a reconciliation of PV-10 to NYMEX PV-10, see “Offering Circular Summary—Summary Reserve and Operating Data.”

⁽³⁾ Current Daily Net Production for the three month period from May 1, 2007 to July 31, 2007.

⁽⁴⁾ Calculated by dividing total proved reserves by the annualized average daily net production for the three month period from May 1, 2007 to July 31, 2007.

Our Strengths

After completing the DSX Acquisition, we believe we will have the following competitive strengths:

High-Quality Resource Base.  Our proved reserves are primarily long-life crude oil located in the Eliasville Field of North Texas and natural gas and condensate located in the Blessing Field along the Texas Gulf Coast. These two fields are characterized by over 50 years of development drilling and production history along with active participation by several leading industry companies in close proximity. We believe the quality and location of our proved reserve base enables high value realization, with minimal basis differentials applied to our overall crude oil and natural gas prices. Our New Albany Shale assets, which currently do not have any booked proved reserves, represent significant upside potential that we are currently evaluating and developing with our operating partners, Aurora Oil & Gas Corporation, Rex Energy Corporation and El Paso Corporation, each of whom brings significant regional expertise and financial and operational resources.

Extensive Workover and Drilling Inventory of Proved Reserves.  The majority of our proved reserve base is classified as proved developed nonproducing and proved undeveloped reserves. We have identified a large base of proved workovers and drilling locations and we intend to complete 45 of them by the end of 2008.

The 45 near-term opportunities are composed of 30 proved developed nonproducing workovers and 15 proved undeveloped drilling locations on our two Texas properties. We believe these projects will increase our production 64.3% from 11.1 MMcfe/d in June 2007 to 18.3 MMcfe/d by the end of 2008. We have identified an additional 31 Frio formation workovers on the DSX Properties which will be performed over the life of the wells, reflecting the multiple pay zones that are evident in the field. Our remaining proved undeveloped drilling opportunities consist of 19 specifically identified locations offering attractive risk-return characteristics which we intend to drill during 2009 and 2010.

Significant Prospective Acreage with Extensive Workovers and Drilling Inventory.  We have identified 25 non-proved workover locations and 32 non-proved drilling locations on our two Texas properties. Over the next 24 months, we will be refining our technical evaluation of these workover and drilling locations. During the same period, we will be working with our partners to further test existing wells and drill additional wells to evaluate the gas reserves on our 171,000 gross acres (32,340 net acres) in the New Albany Shale resource play. During 2007, we have participated in the drilling of eight wells and may participate in the drilling of three additional wells to further test and delineate the potential of the New Albany Shale.

Operational Control.  We currently maintain a working interest of over 95% in, and full operational control over the exploration and development of, the North Texas Properties and the DSX Properties following the closing of the DSX Acquisition. By maintaining operational control, we can more efficiently manage our operating costs, capital expenditures and the timing and method of the development of our properties. Our regional expertise and operational control allow us to operate with a low cost structure and maximize returns on capital employed.

Our Strategy

After completing the DSX Acquisition, we intend to use our competitive strengths to continue increasing reserves, production and cash flow. The following are key elements of this strategy:

Continue Exploiting Our Reserves.  We have a number of opportunities to increase production and expand our reserve base through infill and extension drilling of new wells, workovers targeting non-proved reserves, stimulating existing wells and the expansion of enhanced oil recovery projects such as waterflood operations. The 32 drilling locations currently classified as non-proved reserves include 17 wells required to extend existing waterflood operations on our North Texas Properties and 15 step-out wells on the DSX Properties. We plan to investigate the application of surfactant flooding techniques at our North Texas Properties to potentially recover significant incremental oil reserves. On the DSX Properties, we plan to complete an evaluation of the shallower Frio formation which could result in a new drilling program to exploit the shallower reserve potential of the field. In addition, we have 25 non-proved workover locations on the DSX Properties that we plan to evaluate over the next 24 months.

Actively Manage Our Asset Base.  We will operate 100% of the wells that comprise our PV-10 at the time we close the DSX Acquisition. We believe maintaining operatorship is important because it allows us to control the timing and costs in our drilling and workover plan, as well as control operating costs and the marketing of our production. We intend to take advantage of opportunities to lock in attractive fixed or minimum oil and gas prices through the use of hedging instruments when market conditions are favorable. We also intend to review and rationalize our properties on a continuous basis in order to optimize our asset base.

Leverage Technological Expertise.  We believe that 3-D seismic analysis, enhanced oil recovery processes, horizontal drilling, and other advanced technologies and production techniques are useful tools that help improve drilling results and ultimately enhance our production and returns. Utilizing these technologies and production techniques in exploring for, developing and exploiting oil and natural gas properties will help us

reduce drilling risks, lower finding costs and provide for more efficient production of oil and natural gas from our properties. The use of these technologies enhances the probability of locating and producing reserves that might not otherwise be discovered.

Pursue Opportunistic Acquisitions.  We continually review opportunities to acquire producing properties, leasehold acreage and drilling prospects that are located in our core operating areas. When identifying acquisition candidates, we focus primarily on underdeveloped assets with significant growth potential. We seek acquisitions which allow us to absorb, enhance and exploit properties without taking on significant geologic, exploration or integration risk.

Conduct Selective Exploratory Activities.  Although we do not emphasize exploratory drilling, our current asset base will continue to be assessed for the presence of exploration opportunities, whether directly or through the granting of farm-outs to third parties. We believe that the selective pursuit of exploration opportunities can enhance our reserves, cash flow and production, while minimizing our capital risk.

General Corporate Information

We are a Nevada corporation. Our principal offices are located at 11811 North Freeway I-45, Suite 200, Houston, Texas 77060. We can be reached by phone at (281) 591-6100 and our website address iswww.baselineoil.com. Information on our website is not part of this offering circular.

SUMMARY HISTORICAL AND PRO FORMA COMBINED FINANCIAL INFORMATION

The following table presents certain summary historical and pro forma combined financial data. The historical data for the period from June 29, 2004 (inception) through December 31, 2004 and the years ended December 31, 2005 and 2006 have been derived from our audited financial statements included elsewhere in this offering circular. We have derived the historical data for the last twelve months ended June 30, 2007 (the “LTM Period”) by subtracting the historical data for the six months ended June 30, 2006 from the historical data for the year ended December 31, 2006 and adding the historical data for the six months ended June 30, 2007. The pro forma data as of June 30, 2007 and for the LTM Period have been derived from the “Unaudited Pro Forma Combined Financial Data” included elsewhere in this offering circular and give pro forma effect to the Transactions as if they had occurred on June 30, 2007 in the case of the balance sheet data and July 1, 2006 in the case of the statement of operations data. We derived the statement of operations data for the pro forma LTM Period ended June 30, 2007, by subtracting the unaudited pro forma combined statement of operations data for the six months ended June 30, 2006 from the unaudited pro forma statement of operations for the year ended December 31, 2006 and adding the unaudited statement of operations data for the six months ended June 30, 2007. This information is only a summary and you should read it in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our and the DSX Properties’ audited financial statements and the related notes included elsewhere in this offering circular.

	Baseline Historical								Pro Forma
	Fiscal Year Ended December 31,						LTM ended June 30, 2007		LTM ended June 30, 2007
	2004		2005		2006
							(unaudited)
	(dollars in thousands)
Statement of Operations Data:
Oil and gas sales	$	—	$	—	$	—	$	2,820	$	32,332
Operating expenses:
Production		—		—		—		1,309		8,874
General and administrative		90		17,305		2,386		1,973		4,439
Depreciation, depletion and amortization		—		—		—		518		12,068
Accretion expense		—		—		—		12		12
Total operating expenses		90		17,305		2,386		3,812		25,393
Net income (loss) from operations	$	(90)	$	(17,305)	$	(2,386)	$	(992)	$	6,939

Other Operating Data:
EBITDA(1)	$	18,888
	As of June 1, 2007
As Adjusted Data:
Senior debt to Boe	$	9.75
PV-10 to senior debt		1.9x

	As of June 30, 2007
	Actual		Pro Forma
	(unaudited)
	(dollars in thousands)
Balance Sheet Data:
Cash and cash equivalents	$	156	$	16,655
Oil and natural gas properties, net		34,994		137,869
Total assets		41,386		165,043
Senior debt		30,013		110,000
Total debt		32,576		160,000
Stockholders’ equity		5,043		1,276

⁽¹⁾ EBITDA, which we define as earnings before interest expense, net, income tax (benefit) expense, and depreciation, depletion and amortization, does not represent and should not be considered as an alternative to net income or any other performance measures derived in accordance with GAAP. EBITDA has limitations as an analytical tool, and you should not consider it in isolation or as a substitute for analysis of our results as reported under GAAP. EBITDA has the following limitations:

• it does not reflect our cash expenditures, or further requirements, for capital expenditures or contractual commitments;

• it does not reflect changes in, or cash requirements for, working capital;

• it does not reflect significant interest expense, or the cash requirements necessary to service interest or principal payments on the New Credit Agreement;

• it does not reflect payments made or future requirements for income taxes;

• although depreciation, depletion and amortization are non-cash charges, the assets being depreciated and amortized will often have to be replaced in the future, and EBITDA does not reflect cash requirements for such replacements; and

• because not all companies use identical calculations, our presentations of EBITDA may not be comparable to similarly titled measures of other companies.

We believe, however, that EBITDA is a valuable measure of the operating performance of our business and can assist in comparing our performances on a consistent basis without regard to depreciation and amortization. We believe that EBITDA is useful to investors in evaluating our operating performance because:

• securities analysts and other interested parties use it as a measure of financial performance and debt service capabilities;

• it assists our management in measuring operating performance of our business because it facilitates the comparison of our operating performance on a consistent basis since it removes the impact of items not directly resulting from our operations;

• it is used by our management for internal planning purposes, including aspects of our operating budget and capital expenditures; and

• it is used by our board of directors and management for determining certain management compensation targets and thresholds.

The following table sets forth a reconciliation of EBITDA to net loss for Baseline on a pro forma basis for the DSX Acquisition.

	Pro Forma
	LTM ended June 30, 2007
	(dollars in thousands)
Net loss	$	(23,540)
Interest expense, net		30,360
Depreciation, depletion and amortization		12,068
EBITDA	$	18,888

SUMMARY RESERVE AND OPERATING DATA

The estimates in the table below are for proved reserves with respect to Baseline, the DSX Properties and on a combined pro forma basis after giving effect to the DSX Acquisition, all as of June 1, 2007 and are derived from the CG&A Reserve Report. The present values, discounted at 10% per annum, of the estimated future net cash flows before income taxes shown in the table are not intended to represent the current market value of the estimated oil and gas reserves we own. The proved reserves conform to the definitions approved by the SEC.

	Baseline		DSX Properties		Combined Pro Forma
Proved Reserves (Bcfe)(1):
Proved Developed Producing Reserves		16.3		8.1		24.4
Proved Developed Nonproducing Reserves		2.4		13.0		15.3
Proved Undeveloped Reserves		6.8		21.1		27.9
Total Proved Reserves		25.4		42.2		67.7
PV-10 (dollars in thousands)	$	59,717	$	143,803	$	203,521
NYMEX PV-10(2) (dollars in thousands)	$	67,143	$	146,453	$	213,596
Other Data:
Proved Reserve Mix—% Natural Gas		2%		77%		49%
Net Acreage		37,571		2,374		39,945
Net Producing Wells		82		12		94
Current Daily Net Production (MMcfe/d)(3)		3.0		8.3		11.4
Remaining Reserve Life (Years)(4)		22.9		13.9		16.3

⁽¹⁾ Based on May 31, 2007 prices of $64.02 per Bbl and $7.75 per MMBtu. See “Non-GAAP Financial Measures” and “Business—Proved Reserves” for a reconciliation of PV-10 to the standardized measure of discounted future net cash flows.

⁽²⁾ Based on NYMEX forward pricing on August 29, 2007. See “Non-GAAP Financial Measures.” The following table sets forth a reconciliation of PV-10 to NYMEX PV-10:

	Baseline		DSX Properties		Combined Pro Forma
	(dollars in thousands)
PV-10	$	59,717	$	143,803	$	203,521
Revisions in price		4,995		2,680		7,675
Revisions in quantity estimates		2,431		(30)		2,401
NYMEX PV-10	$	67,143	$	146,453	$	213,596

⁽³⁾ Current Daily Net Production for the three month period from May 1, 2007 to July 31, 2007.

⁽⁴⁾ Calculated by dividing total proved reserves by the annualized average daily net production for the three month period from May 1, 2007 to July 31, 2007.

INDEPENDENT ENGINEERING ESTIMATES

The estimates of Baseline’s and the DSX Properties’ proved reserves and their present value are from the CG&A Reserve Report as of June 1, 2007 at May 31, 2007 flat pricing of $64.02/Bbl and $7.75/MMBtu.

Baseline

	Reserve Category
	PDP		PDNP		PUD		Total
	(dollars in thousands)
Net reserves:
Oil (MBbl)		2,673		383		1,117		4,173
Gas (MMcf)		275		53		73		401
Oil revenue	$	165,795	$	23,750	$	69,287	$	258,832
Gas revenue		1,064		206		281		1,551
Total revenue		166,859		23,956		69,568		260,383
Production taxes		7,706		1,108		3,208		12,023
Ad valorem taxes		4,171		599		1,739		6,510
Operating expense		27,148		9,126		10,486		46,759
Other deductions		65,489		1,882		1,290		68,661
Investments		1,348		1,235		5,000		7,583
Future net cash flow	$	60,995	$	10,007	$	47,845	$	118,848
Discounted at 10%	$	31,312	$	5,151	$	23,254	$	59,717

DSX Properties

	Reserve Category
	PDP		PDNP		PUD		Total
	(dollars in thousands)
Net reserves:
Oil (MBbl)		354		363		893		1,610
Gas (MMcf)		5,995		10,816		15,748		32,560
Oil revenue	$	21,917	$	22,455	$	55,307	$	99,679
Gas revenue		49,035		82,893		128,692		260,620
Total revenue		70,952		105,348		183,998		360,299
Production taxes		4,686		7,250		12,196		24,132
Ad valorem taxes		2,270		3,266		5,888		11,425
Operating expense		11,695		12,379		13,974		38,048
Investments		—		3,080		30,996		34,076
Future net cash flow	$	52,301	$	79,373	$	120,944	$	252,618
Discounted at 10%	$	41,523	$	27,314	$	74,966	$	143,803

Combined Baseline and DSX Properties

The reserve estimates set forth below were created by combining Baseline’s and the DSX Properties’ proved reserve estimates as of June 1, 2007 at May 31, 2007 flat pricing of $64.02/Bbl and $7.75/MMBtu.

	Reserve Category
	PDP		PDNP		PUD		Total
	(dollars in thousands)
Net reserves:
Oil (MBbl)		3,027		746		2,010		5,783
Gas (MMcf)		6,270		10,870		15,821		32,961
Oil revenue	$	187,712	$	46,205	$	124,594	$	358,511
Gas revenue		50,099		83,100		128,973		262,171
Total revenue		237,811		129,304		253,566		620,682
Production taxes		12,392		8,358		15,404		36,154
Ad valorem taxes		6,442		3,865		7,627		17,934
Operating expenses		38,843		21,504		24,460		84,807
Other deductions		65,489		1,882		1,290		68,661
Investments		1,348		4,315		35,996		41,659
Future net cash flow	$	113,296	$	89,380	$	168,789	$	371,466
Discounted at 10%	$	72,835	$	32,465	$	98,220	$	203,521

FORWARD-LOOKING RESERVE ESTIMATES

The below estimates are from the CG&A Reserve Report. These estimates are forward-looking and the actual results achieved during the periods presented will differ from these amounts. Such differences may be material. These estimates are based on information which is currently available and are subject to the uncertainties inherent in the application of judgmental factors in interpreting such information. The reserve estimates set forth below were calculated using May 31, 2007 flat pricing of $64.02/Bbl and $7.75/MMBtu.

While we believe the assumptions underlying these estimates are reasonable in light of current circumstances, no representation can be or is being made with respect to our ability to achieve these results. Prospective investors must make their own determination as to the reasonableness of the below estimates in determining whether to purchase the notes. Prospective investors should also note that if one or more assumptions are not met, these estimates may not be met. In addition, our future results are subject to risks and uncertainties over which we have no control or ability to predict. We can give no assurance as to our future operations or the amount of future income or loss as they relate to the below amounts. These estimates should be read in conjunction with the rest of this offering circular, including “Special Note Regarding Forward-Looking Statements” and “Risk Factors”. See “Risk Factors—Risks Related to our Business and the Oil and Natural Gas Industry—The forward-looking reserve estimates presented in this offering circular will differ from our actual results.”

Baseline

	Year Ended December 31,
	2008		2009
	(dollars in thousands)
Net oil production (MBbl)		226		275
Net gas sales (MMcf)		23		29
Average oil price ($ / Bbl)	$	62.02	$	62.02
Average gas price ($ / Mcf)		3.87		3.87
Oil revenue	$	14,014	$	17,031
Gas revenue		88		111
Total revenue		14,102		17,142
Production taxes		651		792
Ad valorem taxes		353		429
Operating expenses		1,883		2,032
Other deductions		3,699		3,336
Investments		2,560		2,000
Future net cash flow		4,956		8,553
Future field-level operating income(1)	$	7,516	$	10,553

DSX Properties

	Year Ended December 31,
	2008		2009
	(dollars in thousands)
Net oil production (MBbl)		204		238
Net gas sales (MMcf)		3,649		4,359
Average oil price ($ / Bbl)	$	61.92	$	61.92
Average gas price ($ / Mcf)		7.96		8.06
Oil revenue	$	12,609	$	14,711
Gas revenue		29,057		35,154
Total revenue		41,666		49,865
Production taxes		2,759		3,313
Ad valorem taxes		1,296		1,573
Operating expenses		1,741		2,295
Investments		14,100		6,600
Future net cash flow		21,770		36,083
Future field-level operating income(1)	$	35,870	$	42,683

Combined Baseline and DSX Properties

	Year Ended December 31,
	2008		2009
	(dollars in thousands)
Net oil production (MBbl)		430		512
Net gas sales (MMcf)		3,672		4,388
Average oil price ($ / Bbl)	$	61.97	$	61.97
Average gas price ($ / Mcf)		7.94		8.04
Oil revenue	$	26,623	$	31,742
Gas revenue		29,145		35,265
Total revenue		55,768		67,007
Production taxes		3,411		4,105
Ad valorem taxes		1,648		2,002
Operating expenses		3,624		4,327
Other deductions		3,699		3,336
Investments		16,660		8,600
Future net cash flow		26,726		44,636
Future field-level operating income(1)	$	43,386	$	53,236
	Year Ended December 31,
	2008		2009
Other Financial Data:
Future field-level operating income(1) to cash interest expense		3.0x		3.7x
Senior debt to future field-level operating income(1)		2.5x		2.1x

(1) Future field-level operating income is defined as future net cash flow plus investments.

THE TRANSACTIONS

The DSX Acquisition

On August 7, 2007, we entered into the Asset Purchase and Sale Agreement with DSX Energy Limited, LLP (“DSX”), Kebo Oil & Gas, Inc., Sanchez Oil & Gas Corp., Sue Ann Operating, L.L.C., and 23 other individuals, trusts, and companies (collectively, “Sellers”).

Pursuant to the Purchase Agreement, at the Closing defined below, and subject to the satisfaction of various terms and conditions, we will purchase from the Sellers the DSX Properties, which consist of: (i) 100% working interest, together with all other interests of every kind and character (except for certain overriding royalty interests) of Sellers, in and to oil and gas leases and pooled units located in the Blessing Field, Matagorda County, Texas (the “Properties”); (ii) 100% working interest in 12 producing oil and gas wells located on the Properties (the “Wells”) and all oil, gas, minerals, and other substances produced therefrom; (iii) all easements, rights-of-way, contracts, and agreements relating to the Properties and Wells; (iv) all surface and subsurface machinery and equipment, supplies, facilities, and other personal property on or used in connection with the Properties and Wells; and (v) all geological, geophysical, reserve engineering, and other scientific and technical information, reports and data (including, without limitation, conventional two-dimensional and three-dimensional seismic data) that relate exclusively to the Properties, the transfer or disclosure of which is not restricted by agreement with third parties. Upon the Closing, Baseline will become the operator of all of the Properties and Wells.

The closing of the purchase (the “Closing”) is scheduled to occur on October 30, 2007, or such earlier date as we and the Sellers may determine (the “Closing Date”). Although the transfer of ownership of the DSX Properties will occur at the Closing, it will be effective as of June 1, 2007 (the “Effective Date”).

The purchase price we agreed to pay for the DSX Properties at the Closing is $100.0 million in cash (the “Purchase Price”), subject to certain adjustments set forth in the Purchase Agreement. We also agreed to assume certain obligations related to the DSX Properties, including, without limitation: (i) obligations related to the ownership and operation of the DSX Properties and the production and marketing of hydrocarbons allocable thereto, in each case accruing on or after the Effective Date; (ii) obligations accruing after the Effective Date under the terms of all oil and gas leases, contracts, and agreements affecting the DSX Properties and in existence on the Effective Date; and (iii) obligations related to the plugging, abandonment, removal, disposal, site clearance, and similar activities with respect to the Wells. We have also agreed to assume all environmental obligations and liabilities relating to the DSX Properties (except for certain liabilities related to the off-site disposal of hazardous substances, if any), regardless of when the act, omission, or event that gives rise to the environmental liability or obligation occurred.

On August 13, 2007, we paid a performance deposit of $2.5 million to the Sellers (the “Performance Deposit”), which will be credited against the Purchase Price paid at the Closing. We obtained the Performance Deposit from our senior lenders pursuant to the terms of a letter agreement dated August 9, 2007 (the “Letter Agreement”). If the Sellers terminate the Purchase Agreement prior to the Closing due to our breach of or failure to perform the Purchase Agreement, or our failure to satisfy certain pre-Closing conditions, the Sellers will be entitled to retain as liquidated damages the Performance Deposit. If we terminate the Purchase Agreement prior to the Closing due to the Sellers’ breach of or failure to perform as required by the Purchase Agreement, or the Sellers’ failure to satisfy certain pre-Closing conditions, we will be entitled to the return of the full amount of the Performance Deposit, and we will be entitled to seek damages from the Sellers not to exceed $2.5 million.

If any DSX Property is damaged prior to the Closing (“Casualty Loss”), the Sellers may repair or replace the DSX Property. If any Casualty Loss remains unrepaired at the Closing, we will purchase the damaged DSX Property and receive either (i) a reduction of the Purchase Price if permitted as described in the next paragraph or (ii) an assignment from the Sellers of all insurance proceeds and claims against third parities relating to the unrepaired Casualty Loss.

Either the Sellers or we may terminate the Purchase Agreement if the sum of the aggregate values of all uncured title defects (including preferential rights and required consents to assignment that result in exclusion of one or more properties), plus the aggregate amounts to remediate all unremedied environmental defects, plus the amounts of all Casualty Losses prior to the Closing, all as finally agreed upon by the Sellers and the Company or determined by arbitration, would result in reductions to the Purchase Price, without regard to the Deductible, equal to or in excess of $15.0 million. If the Purchase Agreement is thus terminated, we will be entitled to the return of the full amount of the Performance Deposit.

New Credit Agreement

Concurrently with the closing of this offering, we will to enter into the New Credit Agreement. Subject to numerous covenants, the New Credit Agreement provides for an initial credit commitment of up to $20.0 million. Under the New Credit Agreement, we will be able to make borrowings based on a percentage of proved reserves and other factors. Interest will accrue on amounts outstanding under the New Credit Agreement at floating rates indexed to either the prime rate of interest in effect from time to time (plus a certain percentage in certain circumstances) or LIBOR plus a certain percentage based on the amount of utilization under the New Credit Agreement. The New Credit Agreement will require us to pay certain customary fees, including upfront fees, servicing fees and unused facility fees.

All obligations under the New Credit Agreement will be secured by a first priority security interest in all of our assets subject to certain exemptions. We will be able to prepay amounts outstanding under the New Credit Agreement at any time.

The New Credit Agreement will allow all lenders in the facility (or their affiliates) to provide hedges to us and to share pro rata in all collateral and guaranties given under the New Credit Agreement. These will be the only “Credit Support Documents” for the hedges, and no hedge provider will be entitled to demand separate collateral or guaranties. The hedge agreements may contain cross-defaults to “Events of Default” under the New Credit Agreement (and vice versa), but all decisions on waiving events of default or amending the New Credit Agreement will be made by the lenders, and the hedge providers will be bound by lender decision without any direct or indirect veto right.

Board of Directors and Management

On August 3, 2007, we entered into an employment agreement with Patrick H. McGarey, whereby the Company hired Mr. McGarey as our Chief Financial Officer, effective August 16, 2007. As additional consideration for the hiring of Mr. McGarey, we granted Mr. McGarey non-qualified stock options to purchase up to an aggregate of 1,500,000 shares of our common stock under three separate stock option agreements, each dated as of August 3, 2007 and exercisable with respect to 500,000 shares at an exercise price of $0.55 per share, $0.825 per share and $1.10 per share, respectively. See “Management—Employment Agreements.”

We are actively seeking and reviewing candidates to fill two positions as independent members of our board of directors.

Convertible Subordinated Notes

As part of the Transactions, we are offering $50.0 million aggregate principal amount of Subordinated Convertible Notes. We will also offer the initial purchaser of the offering of Convertible Subordinated Notes an option to purchase up to an additional $7.5 million of Convertible Subordinated Notes to cover over-allotments, if any. The Convertible Subordinated Notes will rank junior in right of payment to all existing and future senior indebtedness of the Company, including indebtedness of the Company outstanding under the New Credit Agreement and the notes, and rank equally in right of payment with any future senior subordinated indebtedness of the Company and rank senior in right of payment to any future subordinated indebtedness of the Company and will be convertible into shares of our common stock in specified circumstances. The Convertible Subordinated Notes will be guaranteed by any of our future subsidiaries that guarantee the notes. The Convertible Subordinated Notes will not have the benefit of any sinking fund.

RISK FACTORS

Risks Related to Our Business and the Oil and Natural Gas Industry

We have had a history of operating losses and we may have losses in the future.

Since our inception in June 2004, we have had limited operations and nominal revenues. While we intend to increase our revenues through oil and gas production from our interests in the New Albany Shale resource play, the North Texas Properties, the DSX Properties and other properties we may acquire in the future, there can be no assurance that we will be successful.

Our ability to generate net income will be strongly affected by, among other factors, our ability to successfully drill undeveloped reserves as well as the market price of crude oil and natural gas. If we are unsuccessful in drilling productive wells or the market price of crude oil and natural gas declines, we may report additional losses in the future. Consequently, future losses may adversely affect our business, prospects, financial condition, results of operations and cash flows.

Continuing losses may mean that additional funding may not be available on acceptable terms, or at all. If adequate funds are unavailable from our operations or additional sources of financing, we might be forced to reduce or delay acquisitions or capital expenditures, sell assets, reduce operating expenses, refinance all or a portion of our debt, or delay or reduce important drilling or enhanced production initiatives. In the future we may seek to raise any necessary additional funds through equity or debt financings, convertible debt financing, joint ventures with corporate partners or other sources, which may be dilutive to our existing shareholders and may cause the price of our common stock to decline.

Integration of the DSX Properties involves risks and may adversely affect the results of our operations after the DSX Acquisition.

The anticipated benefits of the DSX Acquisition will depend in part on whether we integrate the DSX Properties into our operations in an efficient, timely and effective manner. Integration involves risks, including difficulties in the integration of the operations and technologies employed on the acquired assets. In addition, our financial performance will be subject to the risks commonly associated with an acquisition, including the financial impact of expenses necessary to realize benefits from the acquisition and the potential for disruption of operations.

Further, as part of the DSX Acquisition, we have agreed to assume certain obligations, including:

• obligations related to the ownership and operation of the DSX Properties accruing after the effective date of the DSX Acquisition;

• obligations accruing after the effective date of the acquisition under the terms of all oil and gas leases, contracts, and agreements affecting the DSX Properties;

• obligations related to the plugging, abandonment, removal, disposal, site clearance, and similar activities with respect to wells; and

• all environmental obligations and liabilities relating to the DSX Properties (except for certain liabilities related to the off-site disposal of hazardous substances, if any). See “The Transactions.”

We may not accomplish this integration successfully and may not realize the benefits contemplated by integrating the DSX Properties into our operations.

If we are unable to successfully integrate the DSX Properties and other assets or companies we acquire in the future into our operations on a timely basis, our profitability could be negatively affected.

Increasing our reserve base through acquisitions is a component of our business strategy. We expect that the DSX Acquisition will result in certain business opportunities and growth prospects. We, however, may never realize these expected business opportunities and growth prospects. We may experience increased competition that limits our ability to expand our business. Our assumptions underlying estimates of expected cost savings may be inaccurate or general industry and business conditions may deteriorate. Acquisitions, including the DSX Acquisition, involve numerous risks, including, but not limited to:

• difficulties in assimilating and integrating the operations, technologies and personnel acquired;

• the diversion of our management’s attention from other business concerns;

• current operating and financial systems and controls may be inadequate to deal with our growth;

• the risk that we will be unable to maintain or renew any of the government contracts of businesses we acquire;

• the risks of entering markets in which we have limited or no prior experience; and

• the loss of key employees.

If these factors limit our ability to integrate the operations of our acquisitions, including the DSX Acquisition, successfully or on a timely basis, our expectations of future results of operations may not be met. In addition, our growth and operating strategies for businesses or assets we acquire may be different from the strategies currently pursued by such businesses or the current owners of such assets. If our strategies are not successful for a company or assets we acquire, it could have a material adverse effect on our business, financial condition and results of operations. Further, there can be no assurance that we will be able to maintain or enhance the profitability of any acquired business or consolidate the operations of any acquired business to achieve cost savings.

In addition, there may be risks and liabilities that we fail, or are unable, to discover in the course of performing due diligence investigations on each company or property we have already acquired or may acquire in the future. Such risks include the possibility of title defects or liabilities not discovered by our due diligence review. Such liabilities could include those arising from employee benefits contribution obligations of a prior owner or non-compliance with, or liability pursuant to, applicable federal, state or local environmental requirements by prior owners for which we, as a successor owner, may be responsible. In addition, there may be additional costs relating to acquisitions, including but not limited to, possible purchase price adjustments. We cannot assure you that rights to indemnification by sellers of assets to us, even if obtained, will be enforceable, collectible or sufficient in amount, scope or duration to fully offset the possible liabilities associated with the business or property acquired, including the DSX Acquisition. Any such liabilities, individually or in the aggregate, could have a material adverse effect on our business.

Our failure to integrate acquired properties successfully into our existing business, or the expense incurred in consummating future acquisitions, could result in our incurring unanticipated expenses and losses. In addition, we may have to assume cleanup or reclamation obligations or other unanticipated liabilities in connection with these acquisitions, and the scope and cost of these obligations may ultimately be materially greater than estimated at the time of the acquisition.

We have not yet received, and by the time this offering closes may not have fully completed our due diligence review of, all of the leases, title opinions, title searches and environmental reports relating to the DSX Properties to be acquired in the DSX Acquisition.

The DSX Properties are subject to all encumbrances, liens or other title defects affecting such assets and properties. We have not yet received, and by the time this offering closes may not have fully completed our due diligence review of, all of the leases, title opinions, title searches and environmental reports relating to the real property and other assets purportedly owned by DSX Energy Limited, LLP. While the Purchase Agreement provides us a period of time to review title and environmental matters pertaining to these oil and gas properties, and provides for certain purchase price adjustments if material encumbrances, liens, environmental or title defects are discovered and not cured, there can be no assurance that our review will disclose all encumbrances, liens, environmental or title defects affecting such oil and gas properties (or other assets included in the DSX Properties) that could have a material adverse effect on the operation of our business or the value of any such oil and gas properties (or other assets).

The forward-looking reserve estimates and other related financial data presented in this offering circular will differ from our actual results.

The forward-looking reserve estimates and other related financial data we have included in this offering circular in the section entitled “Forward-Looking Reserve Estimates” on pages 14 and 15 are based upon a number of assumptions and on information that we believe are reliable as of today. However, this data is inherently subject to significant business and economic uncertainties, many of which are beyond our control. The forward-looking reserve estimates and other financial data are necessarily speculative in nature, and you should expect that some or all of the assumptions will not materialize. Actual results will vary from this data and the variations will likely be material and are likely to increase over time. Consequently, the inclusion of this data should not be regarded as a representation by us, the initial purchaser or any other person that they will actually be achieved. Moreover, we do not intend to update or otherwise revise this data to reflect events or circumstances after the date of this offering circular to reflect the occurrence of unanticipated events. You, as a prospective purchaser of the notes, are cautioned not to place undue reliance on the forward-looking reserve estimates and other financial data. The forward-looking estimates and other related financial data were not prepared with a view toward compliance with published guidelines of the SEC, the American Institute of Certified Public Accountants, the Society of Petroleum Engineers, the World Petroleum Congress or any other regulatory or professional body or generally accepted accounting principles.

A substantial or extended decline in oil and natural gas prices may adversely affect our business, financial condition or results of operations and our ability to meet our capital expenditure obligations and financial commitments.

The prices we receive for our oil and natural gas production heavily influence our revenue, profitability, access to capital and future rate of growth. Oil and natural gas are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil and natural gas have been volatile. These markets will likely continue to be volatile in the future. The prices we receive for our production, and the levels of our production, depend on numerous factors beyond our control. These factors include, but are not limited to, the following:

• changes in global supply and demand for oil and natural gas;

• the actions of certain foreign states;

• the price and quantity of imports of foreign oil and natural gas;

• political conditions, including embargoes, in or affecting other oil producing regions of the world;

• the level of global oil and natural gas exploration and production activity;

• the level of global oil and natural gas inventories;

• production or pricing decisions made by the Organization of Petroleum Exporting Countries (OPEC);

• weather conditions;

• technological advances affecting energy consumption; and

• the price and availability of alternative fuels.

Lower oil and natural gas prices may not only decrease our revenues on a per unit basis but also may reduce the amount of oil and natural gas that we can produce economically. Lower prices will also negatively impact the value and magnitude of our proved reserves. A substantial or extended decline in oil or natural gas prices may materially and adversely affect our future business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures.

Drilling for and producing oil and natural gas are high risk activities with many uncertainties that could adversely affect our business, financial condition or results of operations.

Our future success will depend on the success of our exploitation, exploration, development and production activities. Our oil and natural gas exploration and production activities are subject to numerous risks beyond our control, including the risk that drilling will not result in commercially viable oil or natural gas production. Our decisions to purchase, explore, develop or otherwise exploit prospects or properties will depend in part on the evaluation of data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations. See “—Reserve estimates depend on many assumptions that may turn out to be inaccurate.” Our costs of drilling, completing and operating wells are often uncertain before drilling commences. Overruns in budgeted expenditures are a common risk that can make a particular project uneconomical. Further, many factors may curtail, delay or cancel drilling operations, including the following:

• delays imposed by or resulting from compliance with regulatory requirements;

• pressure or irregularities in geological formations;

• shortages of or delays in obtaining equipment and qualified personnel;

• equipment failures or accidents;

• adverse weather conditions;

• reductions in oil and natural gas prices;

• oil and natural gas property title problems; and

• limitations in marketing oil and natural gas.

If oil and natural gas prices decrease, we may be required to take write-downs of the carrying values of our oil and natural gas properties, potentially triggering earlier-than-anticipated repayments of any outstanding debt obligations and negatively impacting the trading value of our securities.

Accounting rules require that we review periodically the carrying value of our oil and natural gas properties for possible impairment. Based on specific market factors and circumstances at the time of prospective

impairment reviews, and the continuing evaluation of development plans, production data, economics and other factors, we may be required to write down the carrying value of our oil and natural gas properties. Because our properties will serve as collateral for advances under the New Credit Agreement, a write-down in the carrying values of our properties could require us to repay debt earlier than would otherwise be required. A write-down would also constitute a non-cash charge to earnings. It is likely that the effect of such a write-down could also negatively impact the trading price of our securities.

We account for our oil and gas properties using the successful efforts method of accounting. Under this method, all development costs and acquisition costs of proved properties are capitalized and amortized on a units-of-production basis over the remaining life of proved developed reserves and proved reserves, respectively. Costs of drilling exploratory wells are initially capitalized, but charged to expenses if and when a well is determined to be unsuccessful. We evaluate impairment of our proved oil and gas properties whenever events or changes in circumstances indicate an asset’s carrying amount may not be recoverable. The risk that the company will be required to write down the carrying value of its oil and natural gas properties increases when oil and gas prices are low or volatile. In addition, write-downs would occur if we were to experience sufficient downward adjustments to our estimated proved reserves or the present value of estimated future net revenues.

Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our and DSX Properties’ reserves.

The process of estimating oil and natural gas reserves is complex. It requires interpretations of available technical data and many assumptions, including assumptions relating to economic factors. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and present value of our reported reserves. In order to prepare our estimates, we must project production rates and the timing of development expenditures. We must also analyze available geological, geophysical, production and engineering data. The extent, quality and reliability of this data can vary. The process also requires that economic assumptions be made about matters such as oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. Therefore, estimates of oil and natural gas reserves are inherently imprecise.

Actual future production, oil and natural gas prices received, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves most likely will vary from our estimates. Any significant variance could materially affect the estimated quantities and present value of our reported reserves. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and natural gas prices and other factors, many of which are beyond our control.

Prospects that we decide to drill may not yield oil or natural gas in commercially viable quantities.

Our drilling prospects are in various stages of evaluation. There is no way to predict in advance of drilling and testing whether any particular drilling prospect will yield oil or natural gas in sufficient quantities to recover drilling and completion costs or to be economically viable. The use of seismic data and other technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in commercial quantities. We cannot assure you that the analogies we draw from available data from other wells, more fully explored prospects or producing fields will be applicable to our drilling prospects.

The near-term focus of our development activities will be concentrated in three core asset areas, which exposes us to risks associated with prospect concentration. The relative concentration of our near-term activities in three core asset areas means that any impairments or material reductions in the expected size of the reserves attributable to our wells, any material harm to the producing reservoirs or associated surface facilities from which these wells produce or any significant governmental regulation with respect to any of these fields, including curtailment of production or interruption of transportation of production, could have a material adverse effect on our financial condition and results of operations.

Special geological characteristics of the New Albany Shale will require us to use less-common drilling technologies in order to determine the economic viability of our development efforts. New Albany Shale reservoirs are complex, often containing unusual features that are not well understood by drillers and producers. Successful operations in this area require specialized technical staff with specific expertise in horizontal drilling, with respect to which we have limited experience.

The New Albany Shale contains vertical fractures. Results of past drilling in the New Albany Shale have been mixed and are generally believed to be related to whether or not a particular well bore intersects a vertical fracture. While wells have been drilled into the New Albany Shale for years, most of those wells have been drilled vertically. Where vertical fractures have been encountered, production has been better. It is expected that horizontal drilling will allow us to encounter more fractures by drilling perpendicular to the fracture planes. While it is believed that the New Albany Shale is subject to some level of vertical fracturing throughout the Illinois Basin, certain areas will be more heavily fractured than others. If the areas in which we hold an interest are not subject to a sufficient level of vertical fracturing, then our plan for horizontal drilling might not yield commercially viable results.

Gas and water are produced together from the New Albany Shale. Water is often produced in significant quantities, especially early in the producing life of a well. We plan to dispose of this produced water by means of injecting it into other porous and permeable formations via disposal wells located adjacent to producing wells. If we are unable to find such porous and permeable reservoirs into which to inject this produced water or if we are prohibited from injecting because of governmental regulation, then our cost to dispose of produced water could increase significantly, thereby affecting the economic viability of producing the New Albany Shale wells.

We cannot control activities on properties that we do not operate and are unable to ensure their proper operation and profitability.

We will not operate all of the properties in which we will own an interest. As a result, we have limited ability to exercise influence over, and control the risks associated with, the operations of these properties. The failure of an operator of our wells to adequately perform operations, an operator’s breach of the applicable agreements or an operator’s failure to act in ways that are in our best interests could reduce our production and revenues. The success and timing of our drilling and development activities on properties operated by others therefore depend upon a number of factors outside of our control, including the operator’s:

• timing and amount of capital expenditures;

• expertise and financial resources;

• inclusion of other participants in drilling wells; and

• use of technology.

In addition, the financial condition of our operators could negatively impact the operation of our properties and our ability to collect revenues from operations. In the event that an operator of our properties experiences financial difficulties, this may negatively impact our ability to receive payments for our share of net production that we are entitled to under our contractual arrangements with such operator. While we seek to minimize such risk by structuring our contractual arrangements to provide for production revenue payments to be made directly to us by first purchasers of the hydrocarbons, there can be no assurances that we can do so in all situations covering our non-operated properties.

The marketability of our natural gas production depends on facilities that we typically do not own or control, which could result in a curtailment of production and revenues.

The marketability of our natural gas production will depend in part upon the availability, proximity and capacity of natural gas gathering systems, pipelines and processing facilities. We generally deliver natural gas through gas gathering systems and gas pipelines that we do not own under interruptible or short-term transportation agreements. Under the interruptible transportation agreements, the transportation of our gas may be interrupted due to capacity constraints on the applicable system, due to maintenance or repair of the system, or for other reasons as dictated by the particular agreements. Our ability to produce and market natural gas on a commercial basis could be harmed by any significant change in the cost or availability of such markets, systems or pipelines.

Our future acquisitions may yield revenues or production that vary significantly from our projections.

In acquiring producing properties, we will assess the recoverable reserves, future natural gas and oil prices, operating costs, potential liabilities and other factors relating to such properties. Our assessments are necessarily inexact and their accuracy is inherently uncertain. Our review of a subject property in connection with our acquisition assessment will not reveal all existing or potential problems or permit us to become sufficiently familiar with the property to assess fully its deficiencies and capabilities. We may not inspect every well, and we may not be able to identify structural and environmental problems even when we do inspect a well. If problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of those problems. Any acquisition of property interests may not be economically successful, and unsuccessful acquisitions may have a material adverse effect on our financial condition and future results of operations.

Our business may suffer if we lose our Chief Executive Officer.

Our success will be dependent on our ability to continue to employ and retain experienced skilled personnel. We depend to a large extent on the services of Thomas Kaetzer, our Chief Executive Officer and Chairman, the loss of whom could have a material adverse effect on our operations. Although we have an employment agreement with Mr. Kaetzer which provides for notice before he may resign and contains non-competition and non-solicitation provisions, we do not, and likely will not, maintain key-man life insurance with respect to him or any of our employees.

Hedging activities we engage in may prevent us from benefiting from price increases and may expose us to other risks.

Following our entry into our existing credit agreement in April 2007, we executed an arrangement to use derivative instruments to hedge the impact of market fluctuations on crude oil gas prices. To the extent that we engage in hedging activities, we may be prevented from realizing the benefits of future price increases above the levels of the hedges. In addition, we will be subject to risks associated with differences in prices received at different locations, particularly where transportation constraints restrict our ability to deliver oil and gas volumes to the delivery point to which the hedging transaction is indexed.

The unavailability or high cost of drilling rigs, equipment, supplies, personnel and oil field services could adversely affect our ability to execute on a timely basis our exploration and development plans within our budget.

With the increase in the prices of oil and natural gas, we have encountered an increase in the cost of securing drilling rigs, equipment and supplies. Shortages or the high cost of drilling rigs, equipment, supplies and personnel are expected to continue in the near-term. In addition, larger producers may be more likely to secure access to such equipment by virtue of offering drilling companies more lucrative terms. If we are unable to acquire access to such resources, or can obtain access only at higher prices, not only would this potentially delay our ability to convert our reserves into cash flow, but it could also significantly increase the cost of producing those reserves, thereby negatively impacting anticipated net income.

We may incur substantial losses and be subject to substantial liability claims as a result of our oil and natural gas operations.

We are not insured against all risks. Losses and liabilities arising from uninsured and underinsured events could materially and adversely affect our business, financial condition or results of operations. Our oil and natural gas exploration and production activities are subject to all of the operating risks associated with drilling for and producing oil and natural gas, including the possibility of:

• environmental hazards, such as uncontrollable flows of oil, natural gas, brine, well fluids, toxic gas or other pollution into the environment, including groundwater and shoreline contamination;

• abnormally pressured formations;

• mechanical difficulties, such as stuck oil field drilling and service tools and casing collapses;

• fires and explosions;

• personal injuries and death; and

• natural disasters.

Any of these risks could adversely affect our ability to conduct operations or result in substantial losses to us. We may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. If a significant accident or other event occurs and is not fully covered by insurance, then that accident or other event could adversely affect our results of operations, financial condition and cash flows.

We may not have enough insurance to cover all of the risks that we face.

In accordance with customary industry practices, we maintain insurance coverage against some, but not all, potential losses in order to protect against the risks we face. We do not carry business interruption insurance. We may elect not to carry insurance if our management believes that the cost of available insurance is excessive relative to the risks presented. In addition, we cannot insure fully against pollution and environmental risks. The occurrence of an event not fully covered by insurance could have a material adverse effect on our financial condition and results of operations.

We are subject to complex laws that can affect the cost, manner or feasibility of doing business.

The exploration, development, production and sale of oil and natural gas is subject to extensive federal, state, local and international regulation. We may be required to make large expenditures to comply with such governmental regulations. Matters subject to regulation include:

• permits for drilling operations;

• drilling and plugging bonds;

• reports concerning operations;

• the spacing and density of wells;

• unitization and pooling of properties;

• environmental maintenance and cleanup of drill sites and surface facilities; and

• taxation.

Under these laws, we could be liable for personal injuries, property damage and other damages. Failure to comply with these laws also may result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties. Moreover, these laws could change in ways that substantially increase our costs. Any such liabilities, penalties, suspensions, terminations or regulatory changes could materially adversely affect our financial condition and results of operations.

Our operations may cause us to incur substantial liabilities for failure to comply with environmental laws and regulations.

Our oil and natural gas operations are subject to stringent federal, state and local laws and regulations relating to the release or disposal of materials into the environment or otherwise relating to environmental protection. These laws and regulations may require the acquisition of a permit or other authorizations before drilling commences, restrict the types, quantities and concentration of substances that can be released into the environment in connection with drilling and production activities, require permitting or authorization for release of pollutants into the environment, limit or prohibit drilling activities on certain lands lying within wilderness, wetlands, areas inhabited by endangered or threatened species, and other protected areas, and impose substantial liabilities for pollution resulting from historical and current operations. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, incurrence of investigatory or remedial obligations or the imposition of injunctive relief. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent or costly waste handling, storage, transport, disposal or cleanup requirements could require us to make significant expenditures to maintain compliance, and may otherwise have a material adverse effect on our results of operations, competitive position or financial condition as well as on the industry in general. Under these environmental laws and regulations, we could be held strictly liable for the removal or remediation of previously released materials or property contamination regardless of whether we were responsible for the release or if our operations were standard in the industry at the time they were performed.

We anticipate having substantial capital requirements that, if not met, may hinder our operations.

We expect that following completion of the DSX Acquisition, we will experience substantial capital needs as a result of our planned development and acquisition programs. We expect that additional external financing will be required in the future to fund our growth. We may not be able to obtain additional financing on acceptable terms in the future. Without adequate capital resources, we may be forced to limit our planned oil and natural gas acquisition and development activities and thereby adversely affect the recoverability and ultimate value of our oil and natural gas properties. This, in turn, would negatively affect our business, financial condition and results of operations.

Competition in the oil and natural gas industry is intense, which may adversely affect our ability to compete.

We operate in a highly competitive environment for acquiring properties, marketing oil and natural gas and securing trained personnel. Many of our competitors possess and employ financial, technical and personnel resources substantially greater than ours, which can be particularly important in the areas in which we operate. Those companies may be able to pay more for productive oil and natural gas properties and exploratory prospects and to evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit. Our ability to acquire additional prospects and to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. We may not be able to compete successfully in the future in acquiring prospective reserves, developing reserves, marketing hydrocarbons, attracting and retaining quality personnel and raising additional capital.

If our access to markets is restricted, it could negatively impact our production, our income and ultimately our ability to retain our leases.

Market conditions or the unavailability of satisfactory oil and natural gas transportation arrangements may hinder our access to oil and natural gas markets or delay our production. The availability of a ready market for our oil and natural gas production depends on a number of factors, including the demand for and supply of oil and natural gas and the proximity of reserves to pipelines and terminal facilities. Our ability to market our production depends in substantial part on the availability and capacity of gathering systems, pipelines and processing facilities owned and operated by third parties. Our failure to obtain such services on acceptable terms could materially harm our business.

Our productive properties may be located in areas with limited or no access to pipelines, thereby necessitating delivery by other means, such as trucking, or requiring compression facilities. Such restrictions on our ability to sell our oil or natural gas have several adverse affects, including higher transportation costs, fewer potential purchasers (thereby potentially resulting in a lower selling price) or, in the event we were unable to market and sustain production from a particular lease for an extended time, possibly causing us to lose a lease due to lack of production.

We depend on successful exploration, development and acquisitions to maintain revenue in the future.

In general, the volume of production from natural gas and oil properties declines as reserves are depleted, with the rate of decline depending on reservoir characteristics. Except to the extent that we conduct successful exploration and development activities or acquire properties containing proved reserves, or both, our proved reserves will decline as reserves are produced. Our future natural gas and oil production is, therefore, highly dependent on our level of success in finding or acquiring additional reserves. Additionally, the business of exploring for, developing, or acquiring reserves is capital intensive. Recovery of our reserves, particularly undeveloped reserves, will require significant additional capital expenditures and successful drilling operations. To the extent cash flow from operations is reduced and external sources of capital become limited or unavailable, our ability to make the necessary capital investment to maintain or expand our asset base of natural gas and oil reserves would be impaired. In addition, we may be required to find partners for any future exploratory activity. To the extent that others in the industry do not have the financial resources or choose not to participate in our exploration activities, we will be adversely affected.

A substantial percentage of our proved reserves consists of undeveloped reserves.

As of June 1, 2007, approximately 27% of the North Texas Properties’ proved reserves and 50% of the DSX Properties’ proved reserves were classified as undeveloped reserves. These reserves may not ultimately be developed or produced, or quantities developed and produced may be smaller than expected, which in turn may have a material adverse effect on our results of operations.

We may experience difficulty in achieving and managing future growth.

Future growth may place strains on our resources and cause us to rely more on project partners and independent contractors, possibly negatively affecting our financial condition and results of operations. Our ability to grow will depend on a number of factors, including:

• our ability to identify and close future acquisitions on acceptable terms;

• our ability to obtain leases or options on properties for which we have 3-D seismic data;

• our ability to acquire additional 3-D seismic data;

• our ability to identify and acquire new exploratory prospects;

• our ability to develop existing prospects;

• our ability to continue to retain and attract skilled personnel;

• our ability to maintain or enter into new relationships with project partners and independent contractors;

• the results of our drilling program;

• hydrocarbon prices; and

• our access to capital.

We may not be successful in upgrading our technical, operations, and administrative resources or in internally providing certain of the services currently provided by outside sources, and we may not be able to maintain or enter into new relationships with project partners and independent contractors. Our inability to achieve or manage growth may adversely affect our financial condition and results of operations.

We may not be able to keep pace with technological developments in our industry.

The natural gas and oil industry is characterized by rapid and significant technological advancements and introduction of new products and services which utilize new technologies. As others use or develop new technologies, we may be placed at a competitive disadvantage or competitive pressures may force us to implement those new technologies at substantial costs. In addition, other natural gas and oil companies may have greater financial, technical, and personnel resources that allow them to enjoy technological advantages and may in the future allow them to implement new technologies before we are able to. We may not be able to respond to these competitive pressures and implement new technologies on a timely basis or at an acceptable cost. If one or more of the technologies we use now or in the future were to become obsolete or if we are unable to use the most advanced commercially available technology, our business, financial condition, and results of operations could be materially adversely affected.

Our producing properties are located in regions which make us vulnerable to risks associated with operating in a limited number of geographic areas, including the risk of damage or business interruptions from hurricanes.

The DSX Properties are geographically concentrated in the Texas Gulf Coast region. As a result of this concentration, we would be disproportionately affected by any delays or interruptions in production or transportation in these areas caused by governmental regulation, transportation capacity constraints, natural disasters, regional price fluctuations or other factors. Such disturbances will in the future have any or all of the following adverse effects on our business:

• interruptions to our operations as we suspend production in advance of an approaching storm;

• damage to our facilities and equipment, including damage that disrupts or delays our production;

• disruption to the transportation systems we rely upon to deliver our products to our customers; and

• damage to or disruption of our customers’ facilities that prevents them from taking delivery of our products.

Our identified drilling locations are scheduled out over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.

Our management has specifically identified and preliminarily scheduled drilling locations as an estimation of our future multi-year drilling activities on our existing acreage. These scheduled drilling locations

represent a significant component of our growth strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including oil and natural gas prices, the availability of capital, costs, drilling results, regulatory approvals and other factors. Because of these uncertainties, we do not know if the potential drilling locations we have identified will ever be drilled or if we will be able to produce oil or natural gas from these or any other potential drilling locations. As such, our actual drilling activities may materially differ from those presently identified, which could adversely affect our business.

Terrorist attacks aimed at our energy operations could adversely affect our business.

The continued threat of terrorism and the impact of military and other government action has led and may lead to further increased volatility in prices for oil and natural gas and could affect these commodity markets or the financial markets used by us. In addition, the U.S. government has issued warnings that energy assets may be a future target of terrorist organizations. These developments have subjected our oil and natural gas operations to increased risks. Any future terrorist attack on our facilities, those of our customers, the infrastructure we depend on for transportation of our products, and, in some cases, those of other energy companies, could have a material adverse effect on our business.

UNAUDITED PRO FORMA COMBINED FINANCIAL DATA

The following unaudited pro forma combined financial data for the six months ended June 30, 2006 and 2007 and the year ended December 31, 2006 and as of June 30, 2007 have been derived from our historical financial statements as of such dates and for such periods, which are included elsewhere in this offering circular. The pro forma adjustments give effect to the Transactions and the acquisition of the North Texas Properties as if they had occurred on June 30, 2007 in the case of balance sheet data, and as of January 1, 2007 and 2006 in the case of statements of operations data. You should read the following data in conjunction with “Selected Historical Financial and Operating Data of Baseline Oil & Gas Corp.,” “Selected Historical Financial and Operating Data of the DSX Properties,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and each of our and the DSX Properties’ financial statements, including the related notes, included elsewhere in this offering circular.

The unaudited pro forma adjustments are based upon currently available information and certain assumptions that we believe to be reasonable under the circumstances. The unaudited pro forma combined financial information has been prepared for informational purposes only and is not intended to represent the results of operations or financial position that we would have reported had the Transactions been completed as of the date presented, and should not be taken as representative of our future results of operations or financial position.

UNAUDITED PRO FORMA COMBINED BALANCE SHEET

	As of June 30, 2007
	Baseline Historical			Pro Forma Adjustments			Pro Forma Combined
	(dollars in thousands)
Assets:
Cash and marketable securities	$	156			$16,499	(1)	$	16,655
Cash—restricted		1,131			—			1,131
Accounts receivable, trade		1,175			—			1,175
Prepaid and other current assets		124			—			124
Total current assets		2,586			16,499			19,085
Oil and natural gas properties—using successful efforts method of accounting
Proved properties		27,416			102,875	(2)		130,291
Unproved properties		8,093			—			8,093
Less accumulated depletion, depreciation and amortization		(515	)		—			(515	)
Oil and natural gas properties, net		34,994			102,875			137,869
Deferred loan costs, net of accumulated amortization of $2,142		3,768			8,050	(3)		8,050
					(3,768	)(4)
Other property and equipment, net of accumulated depreciation of $3 at June 30, 2007		38			—			38
Total other assets		3,806			4,282			8,088
Total assets	$	41,386			$123,657		$	165,043
Liabilities and stockholders’ equity:
Accounts payable—trade	$	599		$	—		$	599
Accrued expenses		418			—			418
Royalties payable		508			—			508
Short term notes to related parties		100			(100	)(5)		—
Short term debt and current portion of long-term debt		2,257			(2,257	)(5)		—
Derivative liability—short term		957		—				957
Total current liabilities		4,839			(2,357	)		2,482
Long-term debt		30,218			160,000	(6)		160,000
					(30,218	)(5)
Asset retirement obligations		452			—			452
Derivative liability—long term		834			—			834
Total noncurrent liabilities		31,504			129,782			161,286
Total liabilities		36,343			127,424			163,768
Stockholders’ equity:
Common stock, $0.001 par value per share; 140,000,000 shares authorized; 32,210,238 shares issued and outstanding		32			—			32
Additional paid-in capital		31,629			—			31,629
Accumulated other comprehensive income		(1,692	)		—			(1,692	)
Accumulated deficit		(24,926	)		(3,768	)(4)		(28,694	)
Total stockholders’ equity		5,043			(3,768	)		1,276
Total liabilities and stockholders’ equity	$	41,386			$123,657		$	165,043

⁽¹⁾ Adjustment to record the use of the proceeds from the notes and the Convertible Subordinated Notes for general corporate purposes.

⁽²⁾ Adjustment to record the acquisition of the DSX Properties for $100,000,000 and deal related costs of $2,875,000.

⁽³⁾ Adjustment to record amortized debt issue costs related to the notes and the Convertible Subordinated Notes.

⁽⁴⁾ Adjustment to record the elimination of unamortized debt issue costs for prior financing.

⁽⁵⁾ Adjustment to record the use of the proceeds from the notes and the Convertible Subordinated Notes to repay existing debt.

⁽⁶⁾ Adjustment to record the $160,000,000 of notes and the Convertible Subordinated Notes issued in connection with the Transactions.

UNAUDITED PRO FORMA COMBINED STATEMENT OF OPERATIONS

	Six Months Ended June 30, 2007
	Baseline Historical			North Texas Properties Historical		Pro Forma Adjustments North Texas Properties			Pro Forma for North Texas Properties			DSX Properties Historical		Pro Forma Adjustments DSX Properties			Pro Forma Combined
									(dollars in thousands)
Oil and gas sales	$	2,820		$	2,539	$	—		$	5,359		$	13,559	$	—		$	18,918
Operating expenses:
Production expenses		1,309			1,173		—			2,483			1,796		—			4,279
General and administrative expenses		852			—		—			852			—		951	(4)		1,803
Depreciation, depletion and amortization		518			—		279	(1)		797			—		7,214	(5)		8,011
Accretion expense		12			—		—			12			—		—			12
Total operating expenses		2,691			1,173		279			4,144			1,796		8,165			14,106
Net income (loss) from operations		128			1,366		(279	)		1,215			11,763		(8,165	)		4,812
Other income (expense):
Other income (expense)		23			—		—			23			—		—			23
Interest income		1			—		—			1			—		—			1
Interest expense		(3,520	)		—		(856	)(2)		(4,481	)		—		(10,400	)(6)		(18,322	)
							(104	)(3)							856	(7)
															(805	)(8)
															(3,493	)(9)
Unrealized gain (loss) on derivatives		6			—		—			6			—		—			6
Total other expense, net		(3,490	)		—		(960	)		(4,451	)		—		(13,841	)		(18,292	)
Net loss	$	(3,362	)	$	1,366	$	(1,239	)	$	(3,236	)	$	11,763	$	(22,006	)	$	(13,479	)

⁽¹⁾ To reflect the North Texas Properties depreciation, depletion and amortization for production from January 1, 2007 to March 1, 2007. The depreciation, depletion and amortization was computed by allocating the North Texas Properties adjusted purchase price of $27,055,079 to leasehold cost and amortizing the costs based on the historical production divided by total proved reserves. There were no amounts allocated to unproved properties at the acquisition date. The allocation of the adjusted purchase price to the individual fields was based on their estimated fair value at the time of acquisition based on amounts contained in the reserve report.

⁽²⁾ To record additional interest expense related to the North Texas Properties. Pro forma interest expense assumes the $30,013,224 of borrowing was incurred as if the acquisition of the North Texas Properties had occurred on January 1, 2007.

⁽³⁾ To record additional interest expense related to the North Texas Properties. Pro forma interest expense includes $104,000 of amortization of debt issue costs related to the borrowing incurred to acquire the North Texas Properties.

⁽⁴⁾ To record additional general and administrative expense. Pro forma general and administrative expense includes an additional $951,000 to reflect the level of expense incurred subsequent to the acquisition of the North Texas Properties and adjustments to reflect additional staffing requirements.

⁽⁵⁾ To reflect the DSX Properties depreciation, depletion and amortization for production from January 1, 2007 to June 30, 2007. The depreciation, depletion and amortization was computed by allocating the DSX Properties adjusted purchase price of $102,875,000 to leasehold cost and amortizing the costs based on the historical production divided by total proved reserves. There were no amounts allocated to unproved properties at the acquisition date. The allocation of the adjusted purchase price to the individual properties was based on their estimated fair value at the time of acquisition based on amounts contained in the reserve report.

⁽⁶⁾ To record additional interest expense related to the notes and the Convertible Subordinated Notes. Pro forma interest expense assumes the $160,000,000 of borrowing was incurred on January 1, 2007.

⁽⁷⁾ To reverse interest expense related to the North Texas Properties. Pro forma interest expense assumes repayment of the $30,013,224 of borrowing incurred to acquire the North Texas Properties with proceeds from the notes and the Convertible Subordinated Notes on January 1, 2007.

⁽⁸⁾ To record additional interest expense related to the notes and the Convertible Subordinated Notes. Pro forma interest expense includes $805,000 of amortization of debt issue costs related to the notes.

⁽⁹⁾ To record additional interest expense related to the North Texas Properties. Pro forma interest expense includes $3,492,501 to fully amortize debt issue costs related to the borrowing incurred to acquire the North Texas Properties concurrently with the assumed repayment of such debt on January 1, 2007.

UNAUDITED PRO FORMA COMBINED STATEMENT OF OPERATIONS

	Six Months Ended June 30, 2006
	Baseline Historical			North Texas Properties Historical		Pro Forma Adjustments North Texas Properties			Pro Forma for North Texas Properties			DSX Properties Historical		Pro Forma Adjustments DSX Properties			Pro Forma Combined
	(dollars in thousands)
Oil and gas sales	$	—		$	6,379	$	—		$	6,379		$	9,815	$	—		$	16,195
Operating expenses:
Production expenses		—			2,982		—			2,982			1,032		—			4,014
General and administrative expenses		1,265			—		—			1,265			—		1,515	(4)		2,780
Depreciation, depletion and amortization		—			—		723	(1)		723			—		3,571	(5)		4,294
Total operating expenses		1,265			2,982		723			4,969			1,032		5,086			11,088
Net income (loss) from operations		(1,265	)		3,398		(723	)		1,410			8,783		(5,086	)		5,107
Other income (expense):
Other income (expense)		—			—		—			—			—		—			—
Interest income		59			—		—			59			—		—			59
Interest expense		(764	)		—		(1,543	)(2)		(2,547	)		—		(10,400	)(6)		(15,822	)
							(240	)(3)							1,543	(7)
															(805	)(8)
															(3,612	)(9)
Unrealized gain (loss) on derivatives		334			—		—			334			—		—			334
Total other expense, net		(371	)		—		(1,783	)		(2,154	)		—		(13,274	)		(15,428	)
Net loss	$	(1,636	)	$	3,398	$	(2,506	)	$	(744	)	$	8,783	$	(18,360	)	$	(10,322	)

⁽¹⁾ To reflect the North Texas Properties depreciation, depletion and amortization for production from January 1, 2006 to June 30, 2006. The depreciation, depletion and amortization was computed by allocating the North Texas Properties adjusted purchase price of $27,055,079 to leasehold cost and amortizing the costs based on the historical production divided by total proved reserves. There were no amounts allocated to unproved properties at the acquisition date. The allocation of the adjusted purchase price to the individual fields was based on their estimated fair value at the time of acquisition based on amounts contained in the reserve report.

⁽²⁾ To record additional interest expense related to the North Texas Properties. Pro forma interest expense assumes the $30,013,224 of borrowing was incurred as if the acquisition of the North Texas Properties had occurred on January 1, 2006.

⁽³⁾ To record additional interest expense related to the North Texas Properties. Pro forma interest expense includes $240,000 of amortization of debt issue costs related to the borrowing incurred to acquire the North Texas Properties.

⁽⁴⁾ To record additional general and administrative expense. Pro forma general and administrative expense includes an additional $1,515,000 to reflect the level of expense incurred subsequent to the acquisition of the North Texas Properties and adjustments to reflect additional staffing requirements.

⁽⁵⁾ To reflect the DSX Properties depreciation, depletion and amortization for production from January 1, 2006 to June 30, 2006. The depreciation, depletion and amortization was computed by allocating the DSX Properties adjusted purchase price of $102,875,000 to leasehold cost and amortizing the costs based on the historical production divided by total proved reserves. There were no amounts allocated to unproved properties at the acquisition date. The allocation of the adjusted purchase price to the individual properties was based on their estimated fair value at the time of acquisition based on amounts contained in the reserve report.

⁽⁶⁾ To record additional interest expense related to the notes and the Convertible Subordinated Notes. Pro forma interest expense assumes the $160,000,000 of borrowing was incurred on January 1, 2006.

⁽⁷⁾ To reverse interest expense related to the North Texas Properties. Pro forma interest expense assumes repayment of the $30,013,224 of borrowing incurred to acquire the North Texas Properties with proceeds from the notes and the Convertible Subordinated Notes on January 1, 2006.

⁽⁸⁾ To record additional interest expense related to the notes and the Convertible Subordinated Notes. Pro forma interest expense includes $805,000 of amortization of debt issue costs related to the notes.

⁽⁹⁾ To record additional interest expense related to the North Texas Properties. Pro forma interest expense includes $3,611,982 to fully amortize debt issue costs related to the borrowing incurred to acquire the North Texas Properties concurrently with the assumed repayment of such debt on January 1, 2006.

UNAUDITED PRO FORMA COMBINED STATEMENT OF OPERATIONS

	Fiscal Year Ended December 31, 2006
	Baseline Historical			North Texas Properties Historical		Pro Forma Adjustments North Texas Properties			Pro Forma for North Texas Properties			DSX Properties Historical		Pro Forma Adjustments DSX Properties			Pro Forma Combined
	(dollars in thousands)
Oil and gas sales	$	—		$	12,522	$	—		$	12,522		$	17,086	$	—		$	29,608
Operating expenses:
Production expenses		—			6,447		—			6,447			2,162		—			8,609
General and administrative expenses		2,386			—		—			2,386			—		3,030	(4)		5,416
Depreciation, depletion and amortization		—			—		1,436	(1)		1,436			—		6,915	(5)		8,351
Total operating expenses		2,386			6,447		1,436			10,269			2,162		9,945			22,377
Net income (loss) from operations		(2,386	)		6,075		(1,436	)		2,253			14,924		(9,945	)		7,232
Other income (expense):
Other income (expense)		(213	)							(213	)							(213	)
Interest income		117			—		—			117			—		—			117
Interest expense		(1,692	)		—		(3,085	)(2)		(5,258	)		—		(20,800	)(6)		(27,919	)
							(481	)(3)							3,085	(7)
															(1,610	)(8)
															(3,337	)(9)
Unrealized gain (loss) on derivatives		401			—		—			401			—		—			401
Total other expense, net		(1,387	)		—		(3,566	)		(4,952	)		—		(22,662	)		(27,614	)
Net loss	$	(3,773	)	$	6,075	$	(5,000	)	$	(2,699	)	$	14,924	$	(32,607	)	$	(20,382	)

⁽¹⁾ To reflect the North Texas Properties depreciation, depletion and amortization for production from January 1, 2006 to December 31, 2006. The depreciation, depletion and amortization was computed by allocating the North Texas Properties adjusted purchase price of $27,055,079 to leasehold cost and amortizing the costs based on the historical production divided by total proved reserves. There were no amounts allocated to unproved properties at the acquisition date. The allocation of the adjusted purchase price to the individual fields was based on their estimated fair value at the time of acquisition based on amounts contained in the reserve report.

⁽²⁾ To record additional interest expense related to the North Texas Properties. Pro forma interest expense assumes the $30,013,224 of borrowing was incurred as if the acquisition of the North Texas Properties had occurred on January 1, 2006.

⁽³⁾ To record additional interest expense related to the North Texas Properties. Pro forma interest expense includes $481,000 of amortization of debt issue costs related to the borrowing incurred to acquire the North Texas Properties.

⁽⁴⁾ To record additional general and administrative expense. Pro forma general and administrative expense includes an additional $3,030,000 to reflect the level of expense incurred subsequent to the acquisition of the North Texas Properties and adjustments to reflect additional staffing requirements.

⁽⁵⁾ To reflect the DSX Properties depreciation, depletion and amortization for production from January 1, 2006 to December 31, 2006. The depreciation, depletion and amortization was computed by allocating the DSX Properties adjusted purchase price of $102,875,000 to leasehold cost and amortizing the costs based on the historical production divided by total proved reserves. There were no amounts allocated to unproved properties at the acquisition date. The allocation of the adjusted purchase price to the individual properties was based on their estimated fair value at the time of acquisition based on amounts contained in the reserve report.

⁽⁶⁾ To record additional interest expense related to the notes and the Convertible Subordinated Notes. Pro forma interest expense assumes the $160,000,000 of borrowing was incurred on January 1, 2006.

⁽⁷⁾ To reverse interest expense related to the North Texas Properties. Pro forma interest expense assumes repayment of the $30,013,224 of borrowing incurred to acquire the North Texas Properties with proceeds from the notes and the Convertible Subordinated Notes on January 1, 2006.

⁽⁸⁾ To record additional interest expense related to the notes and the Convertible Subordinated Notes. Pro forma interest expense includes $1,610,000 of amortization of debt issue costs related to the notes.

⁽⁹⁾ To record additional interest expense related to the North Texas Properties. Pro forma interest expense includes $3,336,880 to fully amortize debt issue costs related to the borrowing incurred to acquire the North Texas Properties concurrently with the assumed repayment of such debt on January 1, 2006.

SELECTED HISTORICAL FINANCIAL AND OPERATING DATA

OF BASELINE OIL & GAS CORP.

In the following table, we provide you with our selected historical financial and production data for Baseline as of and for the periods indicated. The statement of operations data, operating expenses, other income (expense) and other financial and production data for the period from June 29, 2004 (inception) through December 31, 2004 and the years ended December 31, 2005 and 2006 and the selected balance sheet data as of December 31, 2004, 2005 and 2006 presented below are from our audited financial statements included elsewhere in this offering circular. The statement of operations data, operating expenses, other income (expense) and other financial and production data for the six months ended June 30, 2006 and 2007 and the selected balance sheet data as of June 30, 2006 and 2007 are from our unaudited financial statements as of such date and for such periods included elsewhere in this offering circular.

When you read this selected historical financial data, it is important that you also read along with it our historical financial statements and the notes to our financial statements included elsewhere in this offering circular, as well as “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

	Year Ended December 31,									Six Months Ended June 30,
	2004			2005			2006			2006			2007
										(unaudited)
	(dollars in thousands)
Statement of Operations Data:
Oil and gas sales	$	—		$	—		$	—		$	—		$	2,820
Operating expenses:
Production		—			—			—			—			1,309
General and administrative		90			17,305			2,386			1,265			852
Accretion expense		—			—			—			—			13
Depletion, depreciation and amortization		—			—			—			—			518
Total operating expense		90			17,305			2,386			1,265			2,692
Net income (loss) from operations		(90	)		(17,305	)		(2,386	)		(1,265	)		128
Other income (expense):
Interest income		—			—			118			60			1
Interest expense		(1	)		(393	)		(1,692	)		(764	)		(3,520	)
Unrealized gain on derivative instruments		—			—			401			334			6
Other income (expense)		(1	)		(2	)		(213	)		—			23
Net loss	$	(92	)	$	(17,699	)	$	(3,773	)	$	(1,636	)	$	(3,362	)
Other Financial and Production Data:
Production volumes:
Oil (MBbl)		—			—			—			—			44
Natural gas (MMcf)		—			—			—			—			7
Natural gas equivalent (MMcfe)		—			—			—			—			271
Capital expenditures	$	—		$	1,750		$	7,160		$	4,665		$	28,879
Balance Sheet Data(at period end):
Cash and cash equivalents	$	—		$	206		$	124		$	2,918		$	156
Net oil and natural gas properties		—			—			7,810			6,415			34,994
Total assets		—			2,283			9,247			9,578			41,386
Total debt		16			1,108			1,948			1,379			32,576
Total stockholders’ equity (deficit)		(92	)		1,020			6,890			7,512			5,043

SELECTED HISTORICAL FINANCIAL AND OPERATING DATA OF THE DSX PROPERTIES

In the following table, we provide you with selected historical financial and operating data of the DSX Properties for the periods indicated. The data reflects only the revenues and direct operating expenses attributable to the DSX Properties acquired by us in the DSX Acquisition. The financial data for the years ended December 31, 2005 and 2006 presented below is from the audited financial statements of the DSX Properties included elsewhere in this offering circular. The financial data for the six months ended June 30, 2006 and 2007 are from the unaudited statements of combined revenues and direct operating expenses of the DSX Properties for such periods included elsewhere in this offering circular.

When you read this selected historical financial data, it is important that you also read along with it the historical financial statements of the DSX Properties and the notes to such financial statements included elsewhere in this offering circular, as well as “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

	Year Ended December 31,				Six Months Ended June 30,
	2005		2006		2006		2007
					(unaudited)
	(dollars in thousands)
Revenues	$	7,611	$	17,086	$	9,815	$	13,559
Direct operating expenses		3,051		2,162		1,032		1,796
Excess of revenues over direct operating expenses	$	4,560	$	14,924	$	8,783	$	11,763

PRO FORMA SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES

The following tables set forth certain unaudited pro forma information concerning Baseline’s proved reserves as of December 31, 2006 and June 1, 2007, giving effect to the purchase of the North Texas Properties and the DSX Properties as if they had occurred on January 1, 2006 and January 1, 2007, respectively. There are numerous uncertainties inherent in estimating quantities of proved reserves and projecting future rates of production. The following reserve data represent estimates only and should not be construed as being exact. The reliability of these estimates at any point in time depends on both the quality and quantity of the technical and economic data, the performance of the reservoirs, as well as extensive engineering judgment. Consequently, reserve estimates are subject to revision as additional data becomes available during the producing life of a reservoir. See “Risk Factors—Risks Related to Our Business and the Oil and Natural Gas Industry—Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates of underlying assumptions could materially affect the quantity and present values of our and the DSX Properties’ reserves.”

There was no determination of proved reserves at Baseline at December 31, 2005 and 2006. Baseline acquired the North Texas Properties in April 2007.

All of the reserves relating to the properties are located in the United States.

Proved Reserves

	Oil Reserves (MBbl)
	North Texas Properties	DSX Properties	Combined
Balance, December 31, 2005	4,368	492	4,860
Production	(193)	(92)	(285)
Purchases of reserves in-place	—	—	—
Extensions, discoveries and improved recovery	—	1,227	1,227
Transfers/sales of reserves in place	—	—	—
Revisions of previous estimates	—	—	—
Balance, December 31, 2006	4,175	1,627	5,802
Proved developed reserves at December 31, 2006	3,062	734	3,796
	Oil Reserves (MBbl)
	North Texas Properties	DSX Properties	Combined
Balance, December 31, 2006	4,175	1,627	5,802
Production	(74)	(64)	(138)
Purchases of reserves in-place	—	—	—
Extensions, discoveries and improved recovery	—	—	—
Transfers/sales of reserves in place	—	—	—
Revisions of previous estimates	72	47	119
Balance, June 1, 2007	4,173	1,610	5,783
Proved developed reserves at June 1, 2007	3,056	717	3,773

	Natural Gas Reserves (MMcf)
	North Texas Properties		DSX Properties		Combined
Balance, December 31, 2005	432		11,523		11,955
Production	(30	)	(1,458	)	(1,488	)
Purchases of reserves in-place	—		—		—
Extensions, discoveries and improved recovery	—		23,102		23,102
Transfers/sales of reserves in place	—		—		—
Revisions of previous estimates	—		—		—
Balance, December 31, 2006	402		33,167		33,569
Proved developed reserves at December 31, 2006	330		17,433		17,763
	Natural Gas Reserves (MMcf)
	North Texas Properties		DSX Properties		Combined
Balance, December 31, 2006	402		33,167		33,569
Production	(10	)	(945	)	(955	)
Purchases of reserves in-place	—		—		—
Extensions, discoveries and improved recovery	—		—		—
Transfers/sales of reserves in place	—		—		—
Revisions of previous estimates	8		338		346
Balance, June 1, 2007	400		32,560		32,960
Proved developed reserves at June 1, 2007	328		16,812		17,140

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves

The following disclosures concerning the standardized measure of future cash flows from proved oil and gas reserves are presented in accordance with FAS 69. As prescribed by FAS 69, the amounts shown are based on prices and costs at the end of each period and a 10% annual discount factor.

Future cash inflows are computed by applying fiscal year-end prices of natural gas and oil to year-end quantities of proved natural gas and oil reserves. Future production expenses and development costs are computed primarily by the Company by estimating the expenditures to be incurred in producing and developing the Company’s proved natural gas and oil reserves at the end of the year based on year end costs and assuming continuation of existing economic conditions. Future income taxes are based on currently enacted statutory rates.

The standardized measure of discounted future net cash flows is not intended to represent the replacement costs or fair value of the Company’s natural gas and oil reserves. An estimate of fair value would take into account, among other things, anticipated future changes in prices and costs, and a discount factor more representative of the time value of money and the risks inherent in reserve estimates of natural gas and oil producing operations.

The standardized measure of discounted future net cash flows from the Company’s estimated proved gas reserves is provided as a common base for comparing oil and gas reserves of enterprises in the industry and may not represent the fair market value of the Company’s oil and gas reserves or the present value of future cash inflows of equivalent reserves due to various uncertainties inherent in making these estimates. Those factors include changes in oil and gas prices from year end prices used in the estimates, unanticipated changes in future production and development costs and other uncertainties in estimating quantities and present values of oil and gas reserves.

The standardized measure of estimated discounted future cash flow is not intended to represent the replacement cost or fair market value of the oil and natural gas properties.

	At December 31, 2006
	North Texas Properties		DSX Properties		Combined
	(dollars in thousands)
Future cash inflows	$	230,062	$	256,201	$	486,263
Future production costs		(113,446)		(36,046)		(149,492)
Future development costs		(7,583)		(34,076)		(41,659)
Future income tax		(16,507)		(18,894)		(35,401)
Future net cash flows		92,526		167,185		259,711
Effect of discounting future annual net cash flows at 10%		(55,000)		(79,694)		(134,694)
Discounted future net cash flow	$	37,526	$	87,491	$	125,017
The principal changes in the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves is as follows:
	For the Year Ended December 31, 2006
	North Texas Properties		DSX Properties		Combined
	(dollars in thousands)
Beginning of the year	$	38,754	$	90,336	$	129,090
Sales, net of production costs		(5,577)		(14,924)		(20,501)
Net change in prices and production costs		1,856		(32,761)		(30,905)
Sale of reserves		—		—		—
Extensions, discoveries and improved recovery		—		36,623		36,623
Development costs incurred during the period		—		—		—
Change in future development costs		—		—		—
Purchases of reserves in place		—		—		—
Net change in timing of estimated future production and other		—		—		—
Change in income tax		(918)		263		(655)
Accretion of discount		3,411		7,954		11,365
Revision of quantity estimates		—		—		—
End of year	$	37,526	$	87,491	$	125,017
	At June 1, 2007
	North Texas Properties		DSX Properties		Combined
	(dollars in thousands)
Future cash inflows	$	241,851	$	324,743	$	566,594
Future production costs		(115,420)		(38,048)		(153,468)
Future development costs		(7,583)		(34,076)		(41,659)
Future income tax		(16,377)		(32,587)		(48,964)
Future net cash flows		102,471		220,032		322,503
Effect of discounting future annual net cash flows at 10%		(59,131)		(108,815)		(167,946)
Discounted future net cash flow	$	43,340	$	111,217		154,557

The principal changes in the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves is as follows:

	For the Period from January 1, 2007 to June 1, 2007
	North Texas Properties		DSX Properties		Combined
	(dollars in thousands)
Beginning of the year	$	37,526	$	87,491	$	125,017
Sales, net of production costs		(2,346)		(9,555)		(11,901)
Net change in prices and production costs		6,350		46,841		53,191
Sale of reserves		—		—		—
Extensions, discoveries and improved recovery		—		—		—
Development costs incurred during the period		—		—		—
Change in future development costs		—		—		—
Purchases of reserves in place		—		—		—
Net change in timing of estimated future production and other		(2,172)		(7,008)		(9,180)
Change in income tax		130		(13,693)		(13,563)
Accretion of discount		1,734		4,449		6,183
Revision of quantity estimates		2,118		2,692		4,810
End of year	$	43,340	$	111,217	$	154,557

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

AND RESULTS OF OPERATIONS

The following discussion and analysis should be read in conjunction with the selected financial data included in this offering circular and the financial statements and notes thereto included in this offering circular. This discussion and analysis contains forward looking statements within the meaning of the federal securities laws, including statements using terminology such as “may,” “will,” “expects,” “plans,” “initiatives”, “intends,” “anticipates,” “believes,” “estimates,” or “potential,” or a similar negative phrase or other comparable terminology regarding beliefs, hopes, plans, expectations or intentions for the future. Forward looking statements involve various risks and uncertainties. Our ability to predict results or the actual future effect of plans, initiatives or strategies is inherently uncertain and the actual results and timing of certain events could differ materially from our current expectations.

Company History

We are a Houston, Texas-based independent oil and natural gas company engaged in the exploration, production, development, acquisition and exploitation of natural gas and crude oil properties, with interests in the Eliasville Field in North Texas, or North Texas Properties, and the New Albany Shale in Southern Indiana. With the acquisition of an interest in the North Texas Properties from Statex Petroleum I, L.P. and Charles W. Gleeson LP in April 2007, we became an independent oil and gas operator. Prior to this acquisition, our business operations had consisted principally of oil and gas exploration activities through our participation in the New Albany Shale resource play.

DSX Acquisition

On August 7, 2007, we entered into the Purchase Agreement with DSX Energy Limited, LLP, and 23 other individuals, trusts and companies, to acquire the DSX Properties for $100.0 million in cash. The net proved reserve base of the DSX Properties totaled 42.2 Bcfe as of June 1, 2007, of which approximately 77% is natural gas. We expect the DSX Properties to add 8.3 MMcfe/d to our current production profile. See “The Transactions.”

Trends Affecting Results of Operations—Baseline

Production trends.  Average daily production of oil increased from zero for the year ended December 31, 2006 to 511 Bbls/d for the month of June 2007 and average daily production of natural gas increased from zero for the year ended December 31, 2006 to 73 Mcf/d for the month of June 2007 as a result of the acquisition of the North Texas Properties.

Expectations with respect to future production rates are subject to a number of uncertainties, including those associated with the availability and cost of drilling rigs and third party services, natural gas and oil prices, the potential for mechanical problems, permitting issues, drilling success rates, the availability of acceptable delivery and sales arrangements with respect to our natural gas and crude oil production. They are also subject to the accuracy of assumptions regarding the sustainability of historical growth rates, weather and other uncertainties described in “Risk Factors—Risks Related to Our Business and the Oil and Natural Gas Industry.”

Natural gas and oil prices.  Our revenues are dependent on the prevailing market prices of natural gas and oil and our ability to effectively hedge a portion of our production volume to minimize the adverse effects of fluctuations in prices. Higher natural gas and oil prices have led to a higher demand for drilling rigs, operating personnel and oil field supplies and services, and have caused increases in the cost of those goods and services. To date, higher oil and natural gas sales prices have offset higher field costs. Future earnings and cash flows are dependent on our ability to manage our overall cost structure to a level that allows for profitable production and prevailing natural gas and oil price environments.

Production expenses.  Direct operating expenses have increased as a result of the acquisitions.

General and administration expenses.  In order to manage our growth, professional staff will increase during 2007, which will result in increased general and administrative costs. Integration and systems conversion costs will also be incurred as part of the DSX Acquisition.

Debt service obligations.  The indebtedness incurred in the various acquisitions has significantly increased debt service obligations.

Significant Factors Affecting Revenues and Expenses—Baseline

Revenues

Oil and gas sales.  Revenues are generated from sales of natural gas and oil and are substantially dependent on prevailing prices of natural gas and oil. Prices for natural gas and oil are subject to large fluctuations in response to relatively minor changes in the supply of or demand for natural gas and oil, market uncertainty and a variety of additional factors beyond our control. Natural gas and oil market prices have fluctuated substantially from 2004 to June 30, 2007. The average price received per Mcf of natural gas for the six months ended June 30, 2007 was $3.24 and the average price received per Bbl of oil was $63.53.

In connection with our acquisition of the North Texas Properties, we entered into a series of derivative contracts, specifically fixed price swap contracts, to provide a measure of stability in the cash flows associated with its oil and natural gas production and to manage exposure to commodity prices. See “—Off-Balance Sheet Arrangements”.

Costs and Expenses

Costs and expenses are primarily related to operation and maintenance of our leases, wells and related equipment.

Oil and natural gas operating expenses.  Oil and natural gas operating expenses include certain direct employment-related costs, repair and maintenance costs, electrical power and fuel costs and other expenses necessary to maintain operations. Oil and natural gas operating expenses are driven in part by the type of commodity produced, the level of maintenance activity and the geographic location of our properties. We capitalize workover costs that result in proved reserve additions and include the remainder in oil and natural gas operating expenses.

Production and ad valorem taxes.  Production taxes represent the state severance taxes imposed on mineral production. Production taxes are calculated based on sales revenues or volume of production depending on the state. Ad valorem taxes represent property taxes imposed at the local or county level.

Depreciation, depletion and amortization.  Depreciation, depletion and amortization represent the expensing of the capitalized costs of acquiring and developing natural gas and oil properties and other property and equipment costs.

Accretion expense.  Asset retirement accretion expense relates to the accretion of the present value of asset retirement obligations using credit-adjusted risk-free interest rate in effect when the asset retirement obligation was initially recorded.

General and administrative expenses.  General and administrative expenses include employee compensation and benefits, professional and legal fees, the cost of accounting and other advisory services, miscellaneous corporate overhead and franchise taxes.

Other Expenses and Income

Interest and other income.  We generate interest income from our cash deposits held in interest-bearing accounts.

Unrealized gain on derivative instruments.  We entered into derivative contracts to manage exposure to commodity prices and recorded an unrealized gain in 2006.

Results of Operations—Baseline

Six Months Ended June 30, 2007 Compared to Six Months Ended June 30, 2006

Revenues

Our revenues increased $2.8 million for the six months ended June 30, 2007 to $2.8 million as compared with zero during the same period in 2006 due to our April 2007 acquisition of the North Texas Properties.

Expenses

Production expense.  Production expense increased $1.3 million for the six months ended June 30, 2007 to $1.3 million as compared with zero during the same period in 2006 due to field operating expenses incurred as a result of our April 2007 acquisition of the North Texas Properties.

General and administrative expense.  General and administrative expense decreased $0.4 million for the six months ended June 30, 2007, or 32.7%, to $0.9 million as compared with $1.3 million during the same period in 2006 due to a reduction in third party legal and consulting expenses and higher non-cash expenses incurred in the six months ended June 30, 2006.

Depreciation, depletion and amortization expense.  Depreciation, depletion and amortization expense increased $0.5 million for the six months ended June 30, 2007 to $0.5 million as compared with zero during the same period in 2006 due to depletion expense attributable to the North Texas Properties.

Accretion expense.  Accretion expense increased $12,332 for the six months ended June 30, 2007 to $12,332 as compared with zero during the same period in 2006.

Interest income.  Interest income decreased $58,683 for the six months ended June 30, 2007, or 98.6%, to $860 as compared with $59,543 during the same period in 2006 due to decreased average cash balances held in interest-bearing accounts.

Interest expense.  Interest expense increased $2.8 million for the six months ended June 30, 2007, or 360.6%, to $3.5 million as compared with $0.8 million during the same period in 2006 due to a $1.8 million increase in amortization of debt discount, $0.2 million increase in amortization of debt issuance cost and $0.7 million of interest expense, which includes three months of interest expense on our existing credit agreement.

Unrealized gain on derivative instruments.  Unrealized gain on derivative instruments decreased $0.3 million for the six months ended June 30, 2007, or 98.3%, to $5,629 as compared with $0.3 million during the same period in 2006.

Other income.  Other income increased $23,366 for the six months ended June 30, 2007, to $23,366 as compared with zero during the same period in 2006.

Net Loss

Our net loss increased $1.7 million for the six months ended June 30, 2007, or 105.4%, to $3.4 million as compared with $1.6 million during the same period in 2006.

Fiscal Year Ended December 31, 2006 Compared to Fiscal Year Ended December 31, 2005

Revenues

We had only nominal assets and no revenues during the fiscal years ended December 31, 2006 and 2005.

Expenses

Production expense. We had no production expense during the fiscal years ended December 31, 2006 and 2005.

General and administrative expense. General and administrative expense decreased $14.9 million for the fiscal year ended December 31, 2006, or 86.2%, to $2.4 million as compared with $17.3 million during the same period in 2005. For the fiscal year ended December 31, 2005, we incurred $5.9 million non-cash stock based compensation expense associated with shares issued to certain of our founders in connection with consulting services and $10.1 million in non-cash stock based compensation expense associated with stock option grants to seven persons for services rendered to us.

Depreciation, depletion and amortization expense. We had no depreciation, depletion and amortization expense during the fiscal years ended December 31, 2006 and 2005.

Accretion expense. We had no accretion expense during the fiscal years ended December 31, 2006 and 2005.

Interest income. Interest income increased $0.1 million for the fiscal year ended December 31, 2006 to $0.1 million as compared with zero during the same period in 2005.

Interest expense. Interest expense increased $1.3 million for the fiscal year ended December 31, 2006, or 330.9%, to $1.7 million as compared with $0.4 million during the same period in 2005 due to a $0.7 million increase in amortization of debt discount, $0.2 million increase in amortization of debt issuance cost and $0.3 million of interest expense, which includes a full year of interest expense on our convertible promissory notes.

Unrealized gain on derivative instruments. Unrealized gain on derivative instruments increased $0.4 million for the fiscal year ended December 31, 2006 to $0.4 million as compared with zero during the same period in 2005.

Otherexpense. Other expense increased $0.2 million for the fiscal year ended December 31, 2006, to $0.2 million as compared with $1,605 during the same period in 2005.

Net Loss

Our net loss decreased $13.9 million for the fiscal year ended December 31, 2006, or 78.7%, to $3.8 million as compared with $17.7 million during the same period in 2005.

Trends Affecting Results of Operations—The DSX Properties

Production trends

Average net daily production of natural gas increased from 1,414 Mcf/d for the year ended December 31, 2005 to 3,995 Mcf/d for the year ended December 31, 2006 and increased from 4,094 Mcf/d for the six month period ended June 30, 2006 to 6,357 Mcf/d for the six month period ended June 30, 2007. Average net daily production of oil increased from 104 Bbls/d for the year ended December 31, 2005 to 252 Bbls/d for the year ended December 31, 2006 and increased from 296 Bbls/d for the six months ended June 30, 2006 to 424 Bbls/d for the six month period ended June 30, 2007.

Expectations with respect to future production rates are subject to a number of uncertainties, including those associated with the availability and cost of drilling rigs and third party services, natural gas and oil prices, the potential for mechanical problems, permitting issues, drilling success rates, the availability of acceptable delivery and sales arrangements with respect to our natural gas and crude oil production. They are also subject to the accuracy of assumptions regarding the sustainability of historical growth rates, weather and other uncertainties described in “Risk Factors—Risks Related to Our Business and the Oil and Natural Gas Industry.”

Natural gas and oil prices

Revenues are dependent on the prevailing market prices of natural gas and oil and the ability to effectively hedge a portion of production to minimize the adverse effects of fluctuations in prices. Higher natural gas and oil prices have led to a higher demand for drilling rigs, operating personnel and oil field supplies and services, and have caused increases in the cost of those goods and services. To date, higher oil and natural gas sales prices have offset higher field costs. Future earnings and cash flows are dependent on the ability to manage overall cost structure to a level that allows for profitable production at prevailing natural gas and oil price environments.

Direct operating expenses

Direct operating expenses are primarily related to operations and maintenance of leases, wells and related equipment.

Significant Factors Affecting Revenues and Expenses—The DSX Properties

Revenues

Natural gas and oil sales.  Revenues are generated from sales of natural gas and oil and are substantially dependent on prevailing prices of natural gas and oil. Prices for natural gas and oil are subject to large fluctuations in response to relatively minor changes in the supply of or demand for natural gas and oil, market uncertainty and a variety of additional factors beyond control. Natural gas and oil market prices have fluctuated substantially from 2004 to June 30, 2007.

Average prices received per Mcf of natural gas were $10.47 and $7.68 during 2005 and 2006, respectively and $8.98 and $7.89 for the six months ended June 30, 2006 and 2007, respectively. Average prices received per Bbl of oil for the DSX Properties were $58.39 and $64.04 during 2005 and 2006, respectively, and $59.07 and $58.42 for the six months ended June 30, 2006 and 2007, respectively.

Costs and Expenses

Oil and natural gas operating expenses.  Oil and natural gas operating expenses include certain direct employment-related costs, repair and maintenance costs, electrical power and fuel costs and other expenses necessary to maintain operations. Oil and natural gas operating expenses are driven in part by the type of commodity produced, the level of maintenance activity and the geographic location of the DSX Properties. Workover costs that result in proved reserve additions are capitalized and include the remainder in oil and natural gas operating expenses.

Results of Operations—DSX Properties

Six Months Ended June 30, 2007 Compared to Six Months Ended June 30, 2006

Revenues

Revenues from the DSX Properties increased $3.7 million for the six months ended June 30, 2007 to $13.6 million, or 38.2%, as compared with $9.8 million during the same period in 2006 due to the DSX Properties having 12 producing wells at June 30, 2007 compared to five producing wells at June 30, 2006.

Direct Operating Expenses

Direct operating expenses increased $0.8 million for the six months ended June 30, 2007, or 74.0%, to $1.8 million as compared with $1.0 million during the same period in 2006 due to the DSX Properties having 12 producing wells at June 30, 2007 compared to five producing wells at June 30, 2006.

Excess of Revenues Over Direct Operating Expenses

Excess of revenues over direct operating expenses increased $3.0 million for the six months ended June 30, 2007, or 33.9%, to $11.8 million as compared with $8.8 million during the same period in 2006.

Fiscal Year Ended December 31, 2006 Compared to Fiscal Year Ended December 31, 2005

Revenues

Revenues from the DSX Properties increased $9.5 million for the fiscal year ended December 31, 2006 to $17.1 million, or 125.0%, as compared with $7.6 million during the same period in 2005 due to the DSX Properties having nine producing wells at December 31, 2006 compared to four producing wells at December 31, 2005.

Direct Operating Expenses

Direct operating expenses decreased $0.9 million for the fiscal year ended December 31, 2006, or 29.1%, to $2.2 million as compared with $3.1 million during the same period in 2005 due to a one-time expense related to infrastructure improvements.

Excess of Revenues Over Direct Operating Expenses

Excess of revenues over direct operating expenses increased $10.3 million for the fiscal year ended December 31, 2006, or 227.3%, to $14.9 million as compared with $4.6 million during the same period in 2005.

Financial Liquidity and Capital Resources

The discussion of financial liquidity and capital resources pertains specifically to Baseline.

Overview

We currently believe, based upon our forecasts and our liquidity and capital requirements for the next twelve months, that the combination of our expected internally-generated cash, the borrowings under our revolving credit facility entered into in April 2007 and our working capital, will be adequate to fund our anticipated capital and liquidity requirements for the next twelve months in connection with our plan of operations.

The following table summarizes our net cash provided by or used in our operating activities, investing activities, financing activities and capital expenditures for the first six months of 2006 and 2007.

	Six Months Ended June 30, 2006			Six Months Ended June 30, 2007
	(dollars in thousands)
Cash Flow:
Net cash used in operating activities	$	(891	)	$	(970	)
Net cash used in investing activities		(4,665	)		(28,879	)
Net cash provided by financing activities		8,268			29,882
Net increase (decrease) in cash and cash equivalents	$	2,712		$	33

Cash flows from operating activities.  Net cash used in operating activities increased to $1.0 million for the six months ended June 30, 2007 as compared to $0.9 million for the six months ended June 30, 2006. This increase was primarily a result of fluctuations in operating assets and liabilities that are caused by the timing of cash receipts and disbursements, commodity prices, production volumes and operating expenses.

Cash flows from investing activities.  Net cash used in investing activities increased to $28.9 million for the six months ended June 30, 2007 as compared to $4.7 million for the six months ended June 30, 2006. Payments to purchase oil and gas properties increased to $28.2 million for the six months ended June 30, 2007 as compared to zero for the six months ended June 30, 2006.

Cash flows from financing activities.  Net cash provided by financing activities increased to $29.9 million for the six months ended June 30, 2007 as compared to $8.3 million for the six months ended June 30, 2006 due to an increase in long-term debt to $30.0 million for the six months ended June 30, 2007 as compared to zero for six months ended June 30, 2006.

The following table sets forth selected cash flow data for the periods indicated.

	Period from June 29, 2004 to December 31, 2004			Year Ended December 31, 2005			Year Ended December 31, 2006
	(dollars in thousands)
Cash Flow:
Net cash used in operating activities	$		(16)	$	(785	)	$	(1,194	)
Net cash used in investing activities		—			(1,750	)		(7,160	)
Net cash provided by financing activities		16			2,742			8,271
Net increase (decrease) in cash and cash equivalents	$	—		$	206		$	(83	)

Cash flows from operating activities.  Net cash used in operating activities increased to $1.2 million for the year ended December 31, 2006 as compared to $0.8 million for the year ended December 31, 2005. This increase was primarily a result of fluctuations in other operating assets and liabilities that are caused by the timing of cash receipts and disbursements, commodity prices, production volumes and operating expenses.

Cash flows used in investing activities.  Net cash used in investing activities increased to $7.2 million for the year ended December 31, 2006 as compared to $1.8 million for the year ended December 31, 2005. Payments to purchase oil and gas properties increased to $7.1 million for the year ended December 31, 2006 as compared to $1.8 million for the year ended December 31, 2005.

Cash flows provided by financing activities.  Net cash provided by financing activities increased to $8.3 million for the year ended December 31, 2006 as compared to $2.7 million for the year ended December 31, 2005 due to an increase in proceeds from sale of common stock of $8.3 million for the year ended December 31, 2006. This increase is offset by a reduction in proceeds from convertible notes to zero for the year ended December 31, 2006 as compared to $2.7 million for the year ended December 31, 2005.

Capital expenditures.  Capital expenditures for the year ended December 31, 2006 were $7.2 million, which included $6.1 million related to the acquisition of working interests in the New Albany Shale and a $1.0 million performance deposit in connection with our purchase of the North Texas Properties. Capital expenditures for the year ended December 31, 2005 were $1.8 million and related to the acquisition of working interests in the New Albany Shale.

Seasonality

Operating revenues and expenses are generally not affected by seasonal changes. At times, there may be seasonal declines in natural gas prices, usually in autumn, when natural gas storage facilities near full capacity. These seasonal declines in prices are usually temporary.

Quantitative and Qualitative Disclosures about Market Risk

Market-sensitive instruments and risk management.  Market risk is the potential loss arising from adverse changes in market rates and prices, such as commodity prices and interest rates. Our primary market risk exposure is commodity price risk. This exposure is discussed in detail below.

Commodity price risk.  We utilize commodity-based derivative instruments to reduce exposure to fluctuations in the price of crude oil and natural gas. We use financially settled crude oil and natural gas swaps and collars. Any gains or losses resulting from the change in fair value from hedging transactions that are determined to be ineffective are recorded in income, whereas gains and losses from the settlement of hedging contracts are recorded in crude oil and natural gas revenue.

Interest rate risk.  Our exposure to changes in interest rates relates primarily to long-term debt obligations. We may utilize interest rate derivatives to alter interest rate exposure in an attempt to reduce interest rate expense related to existing debt issues. Interest rate derivatives are used solely to modify interest exposure and not to modify the overall leverage of the debt portfolio. We are exposed to changes in interest rates as a result of our New Credit Agreement.

Private Placement of Equity and Debt

In November 2005, we completed the offering and sale of $2.4 million in units consisting of a 10% convertible promissory note and shares of common stock in privately negotiated transactions with accredited investors. Each note was to mature on May 15, 2007 and bore interest at the rate of 10% per annum. The holder of a note had the option to elect to receive interest on the note in cash or in shares of common stock valued at $0.50 per share. At any time prior to maturity, holders had the option to convert the principal and accrued but unpaid interest on their note into such number of shares of common stock equal to the outstanding principal amount plus accrued but unpaid interest, divided by $0.50, or a total of 4,750,000 shares, excluding interest.

On May 30, 2007 holders of our 10% convertible promissory notes unanimously agreed to extend the maturity date of the notes from May 15, 2007 to November 15, 2007. As consideration for the extension of the maturity of the notes, Baseline issued 380,000 shares in aggregate to the holders of the notes and increased the coupon rate on the notes from 10% to 12% per annum effective May 16, 2007. As of August 31, 2007, there are convertible promissory notes outstanding in the principal amount of $2.1 million.

On February 1, 2006, we completed a private placement to accredited investors in which we received gross proceeds of $9.0 million by selling an aggregate of 8,181,819 shares of our newly-issued common stock at $1.10 per share. We paid aggregate placement agent commissions of $675,000 (or 7.5% of the gross proceeds) and issued three-year warrants to our placement agents to purchase an aggregate of 259,090 shares of common

stock at an exercise price of $1.32 per share. C.K. Cooper & Company and Gilford Securities, Incorporated acted as our placement agents. Approximately $4 million of the net proceeds were used to fund the purchase of our interest in the New Albany Shale.

Off-Balance-Sheet Arrangements

In accordance with a requirement of our existing credit agreement, on April 12, 2007, we entered into a Swap Agreement (“Swap Agreement”) with Macquarie Bank Limited, which Swap Agreement provided that we put in place, for each month through the third anniversary thereof, separate swap contracts, as adjusted from time to time as specified therein, with respect to notional volumes which are approximately 75% of the reasonably anticipated projected production from Proved Developed Producing Reserves (as defined in the existing credit agreement) from the North Texas Properties for each of crude oil and natural gas, calculated separately pursuant to the requirements of our existing credit agreement. Immediately subsequent to our entry into the credit agreement, we entered into a series of contracts under the Swap Agreement with Macquarie Bank Limited, providing for us to receive a fixed price of $68.20 per barrel of oil for a three year period, commencing June 1, 2007. The hedging arrangement is based upon a minimum of 11,000 barrels of oil in the first year, lesser minimum volumes in subsequent years, and provides for monthly settlements.

During July 2007, we modified our existing hedge program from a fixed price swap to a collar, with a floor of $68.20 and a ceiling of $74.20, for the period from August 2007 through December 2008. Subsequent to December 2008, the swap program reverts to a swap agreement at $68.20 through May 2010. We provided a right to the hedge provider to purchase 7,000 barrels per month at $73.20 per barrel from June 2010 through December 2011.

The DSX Properties have no existing hedges in place. However, we intend to implement an appropriate hedge program covering a portion of future production volumes shortly after the closing of the DSX Acquisition.

Critical Accounting Policies

The following critical accounting policies apply to both the Company and the DSX Properties:

Nature of Operations and Organization

We are an independent exploration and production company primarily engaged in the exploration, production, development, acquisition and exploitation of oil and natural gas properties onshore in the United States.

Basis of Presentation

The accompanying unaudited interim financial statements of the Company and the DSX Properties have been prepared in accordance with accounting principles generally accepted in the United States of America and the rules of the SEC and should be read in conjunction with the audited financial statements for the year ended December 31, 2006, and notes thereto, which are included in this offering circular. In the opinion of management, all adjustments, consisting of normal recurring adjustments, necessary for a fair presentation of financial position and the results of operations for the interim periods presented have been reflected herein. The results of operations for interim periods are not necessarily indicative of the results to be expected for the full year. Notes to the financial statements, which would substantially duplicate the disclosure required in the 2006 annual financial statements have been omitted.

Use of Estimates

The preparation of these financial statements is in conformity with accounting principles generally accepted in the United States and requires management to make estimates and assumptions that affect the

reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amount of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Oil and Natural Gas Properties

The successful efforts method of accounting is used for oil and gas producing activities. Costs to acquire mineral interests in oil and gas properties, to drill and equip exploratory wells that find proved reserves, to drill and equip development wells and related asset retirement costs are capitalized. Costs to drill exploratory wells that do not find proved reserves, geological and geophysical costs, and costs of carrying and retaining unproved properties are expensed.

Unproved oil and gas properties that are individually significant are periodically assessed for impairment of value, and a loss is recognized at the time of the impairment by providing an impairment allowance. Capitalized costs of producing oil and gas properties, after considering estimated residual salvage values, are depreciated and depleted by the unit-of-production method. Support equipment and other property and equipment are depreciated over their estimated useful lives.

On the sale or retirement of a complete unit of proved property, the cost and related accumulated depreciation, depletion, and amortization are eliminated from the property accounts, and the resulting gain or loss is recognized. On the retirement or sale of a partial unit of proved property, the cost is charged to accumulated depreciation, depletion, and amortization with a resulting gain or loss recognized in income.

On the sale of an entire interest in an unproved property for cash or cash equivalent, gain or loss on the sale is recognized, taking into consideration the amount of any recorded impairment if the property had been assessed individually. If a partial interest in an unproved property is sold, the amount received is treated as a reduction of the cost of the interest retained.

Asset Retirement Obligations

Liabilities for legal obligations associated with the retirement of tangible long-lived assets are recorded in the period in which they are incurred in accordance with Statement of Financial Accounting Standards (“SFAS”) No. 143 “Accounting for Asset Retirement Obligations.” Under this method, when liabilities for dismantlement and abandonment costs, excluding salvage values, are initially recorded the carrying amount of the related oil and natural gas properties are increased. Accretion of the liability is recognized each period using the interest method of allocation, and the capitalized cost is depleted over the useful life of the related asset. Revisions to such estimates are recorded as adjustments to the ARO, capitalized asset retirement costs and charges to operations during the periods in which they become known. At the time the abandonment cost is incurred, the Company will be required to recognize a gain or loss if the actual costs do not equal the estimated costs included in ARO.

Revenue and Cost Recognition

The sales method of accounting is used for natural gas and oil revenues. Under this method, revenues are recognized based on the actual volumes of gas and oil sold to purchasers. The volume sold may differ from the volumes to which each is entitled based on the interest in its properties. Costs associated with production are expensed in the period incurred.

BUSINESS

Company Overview

We are a Houston, Texas-based independent oil and natural gas company engaged in the exploration, production, development, acquisition and exploitation of natural gas and crude oil properties, with interests in the North Texas Properties and the New Albany Shale in Southern Indiana. On August 7, 2007, we entered into the Purchase Agreement in connection with the DSX Acquisition. The DSX Acquisition substantially increases our reserve base, provides us with an extensive portfolio of low-risk drilling opportunities, increases our geographic and geological well diversification, and provides us with a balanced commodity mix (51% oil / 49% gas).

Pro forma for the DSX Acquisition, our properties cover 39,945 net acres across three core areas of operation. Immediately following the DSX Acquisition, we will own a working interest of over 95% and an average 74% net revenue interest in our two Texas properties, and operate 100% of the wells that presently comprise our PV-10. This will enable us to more efficiently manage our operating costs, capital expenditures and the timing and method of development of our properties. In addition to our development opportunity in Southern Indiana, the proved developed nonproducing, proved undeveloped and non-proved reserves identified in the North Texas Properties and the DSX Properties include over 150 drilling and workover opportunities. Upon the consummation of the offering, we will implement an active development program to exploit these opportunities. We believe this development program alone will enable us to significantly grow our reserves, production and cash flow.

As of June 1, 2007, based on the CG&A Reserve Report, pro forma for the DSX Acquisition, we had 67.7 Bcfe of proved reserves, of which 48.7% were natural gas and 58.8% were proved developed. The PV-10 and NYMEX PV-10 of these proved reserves as of that date were $203.5 million and $213.6 million, respectively, on a pro forma basis. See “Non-GAAP Financial Measures” and “Offering Circular Summary—Summary Reserve and Operating Data” as well as “Business—Proved Reserves” for a reconciliation of PV-10 to the standardized measure of discounted future net cash flows. Our average pro forma net production for the three month period from May 1, 2007 to July 31, 2007 was 11.4 MMcfe/d, with a remaining reserve life of 16.3 years.

Reserve and Production Overview

Unless otherwise noted, the following table summarizes certain statistics for Baseline and the DSX Properties separately and Baseline on a combined pro forma basis after giving effect to the DSX Acquisition as of June 1, 2007.

	Baseline			DSX Properties			Combined Pro Forma
Proved Reserves (Bcfe)(1):
Proved Developed Producing Reserves		16.3			8.1			24.4
Proved Developed Nonproducing Reserves		2.4			13.0			15.3
Proved Undeveloped Reserves		6.8			21.1			27.9
Total Proved Reserves		25.4			42.2			67.7
PV-10 (dollars in thousands)	$	59,717		$	143,803		$	203,521
NYMEX PV-10(2) (dollars in thousands)	$	67,143		$	146,453		$	213,596
Other Data:
Proved Reserve Mix—% Natural Gas		2	%		77	%		49	%
Net Acreage		37,571			2,374			39,945
Net Producing Wells		82			12			94
Current Daily Net Production (MMcfe/d)(3)		3.0			8.3			11.4
Remaining Reserve Life (Years)(4)		22.9			13.9			16.3

⁽¹⁾ Based on May 31, 2007 prices of $64.02 per Bbl and $7.75 per MMBtu. See “Non-GAAP Financial Measures” and “Business—Proved Reserves” for a reconciliation of PV-10 to the standardized measure of discounted future net cash flows.

⁽²⁾ Based on NYMEX forward pricing on August 29, 2007. See “Non-GAAP Financial Measures” and, for a reconciliation of PV-10 to NYMEX PV-10, see “Offering Circular Summary—Summary Reserve and Operating Data.”

⁽³⁾ Current Daily Net Production for the three month period from May 1, 2007 to July 31, 2007.

⁽⁴⁾ Calculated by dividing total proved reserves by the annualized average daily net production for the three month period from May 1, 2007 to July 31, 2007.

Our Strengths

After completing the DSX Acquisition, we believe we will have the following competitive strengths:

High-Quality Resource Base.  Our proved reserves are primarily long-life crude oil located in the Eliasville Field of North Texas and natural gas and condensate located in the Blessing Field along the Texas Gulf Coast. These two fields are characterized by over 50 years of development drilling and production history along with active participation by several leading industry companies in close proximity. We believe the quality and location of our proved reserve base enables high value realization, with minimal basis differentials applied to our overall crude oil and natural gas prices. Our New Albany Shale assets, which currently do not have any booked proved reserves, represent significant upside potential that we are currently evaluating and developing with our operating partners, Aurora Oil & Gas Corporation, Rex Energy Corporation and El Paso Corporation, each of whom brings significant regional expertise and financial and operational resources.

Extensive Workover and Drilling Inventory of Proved Reserves.  The majority of our proved reserve base is classified as proved developed nonproducing and proved undeveloped reserves. We have identified a large base of proved workovers and drilling locations and we intend to complete 45 of them by the end of 2008. The 45 near-term opportunities are composed of 30 proved developed nonproducing workovers and 15 proved undeveloped drilling locations on our two Texas properties. We believe these projects will increase our production 64.3% from 11.1 MMcfe/d in June 2007 to 18.3 MMcfe/d by the end of 2008. We have identified an additional 31 Frio formation workovers on the DSX Properties which will be performed over the life of the wells, reflecting the multiple pay zones that are evident in the field. Our remaining proved undeveloped drilling opportunities consist of 19 specifically identified locations offering attractive risk-return characteristics which we intend to drill during 2009 and 2010.

Significant Prospective Acreage with Extensive Workover and Drilling Inventory.  We have identified 25 non-proved workover locations and 32 non-proved drilling locations on our two Texas properties. Over the next 24 months, we will be refining our technical evaluation of these workover and drilling locations. During the same period, we will be working with our partners to further test existing wells and drill additional wells to evaluate the gas reserves on our 171,000 gross acres (32,340 net acres) in the New Albany Shale resource play. During 2007, we have participated in the drilling of eight wells and may participate in the drilling of three additional wells to further test and delineate the potential of the New Albany Shale.

Operational Control.  We currently maintain a working interest of over 95% in, and full operational control over the exploration and development of, the North Texas Properties and the DSX Properties following the closing of the DSX Acquisition. By maintaining operational control, we can more efficiently manage our operating costs, capital expenditures and the timing and method of the development of our properties. Our regional expertise and operational control allow us to operate with a low cost structure and maximize returns on capital employed.

Our Strategy

After completing the DSX Acquisition, we intend to use our competitive strengths to continue increasing reserves, production and cash flow. The following are key elements of this strategy:

Continue Exploiting Our Reserves.  We have a number of opportunities to increase production and expand our reserve base through infill and extension drilling of new wells, workovers targeting non-proved reserves, stimulating existing wells and the expansion of enhanced oil recovery projects such as waterflood operations. The 32 drilling locations currently classified as non-proved reserves include 17 wells required to extend existing waterflood operations on our North Texas Properties and 15 step-out wells on the DSX Properties. We plan to investigate the application of surfactant flooding techniques at our North Texas Properties to potentially recover significant incremental oil reserves. On the DSX Properties, we plan to complete an evaluation of the shallower Frio formation which could result in a new drilling program to exploit the shallower reserve potential of the field. In addition, we have 25 non-proved workover locations on the DSX Properties that we plan to evaluate over the next 24 months.

Actively Manage Our Asset Base.  We will operate 100% of the wells that comprise our PV-10 at the time we close the DSX Acquisition. We believe maintaining operatorship is important because it allows us to control the timing and costs in our drilling and workover plan, as well as control operating costs and the marketing of our production. We intend to take advantage of opportunities to lock in attractive fixed or minimum oil and gas prices through the use of hedging instruments when market conditions are favorable. We also intend to review and rationalize our properties on a continuous basis in order to optimize our asset base.

Leverage Technological Expertise.  We believe that 3-D seismic analysis, enhanced oil recovery processes, horizontal drilling, and other advanced technologies and production techniques are useful tools that help improve drilling results and ultimately enhance our production and returns. Utilizing these technologies and production techniques in exploring for, developing and exploiting oil and natural gas properties will help us reduce drilling risks, lower finding costs and provide for more efficient production of oil and natural gas from our properties. The use of these technologies enhances the probability of locating and producing reserves that might not otherwise be discovered.

Pursue Opportunistic Acquisitions.  We continually review opportunities to acquire producing properties, leasehold acreage and drilling prospects that are located in our core operating areas. When identifying acquisition candidates, we focus primarily on underdeveloped assets with significant growth potential. We seek acquisitions which allow us to absorb, enhance and exploit properties without taking on significant geologic, exploration or integration risk.

Conduct Selective Exploratory Activities.  Although we do not emphasize exploratory drilling, our current asset base will continue to be assessed for the presence of exploration opportunities, whether directly or through the granting of farm-outs to third parties. We believe that the selective pursuit of exploration opportunities can enhance our reserves, cash flow and production, while minimizing our capital risk.

Development of Business

We are the surviving corporation of a merger with Coastal Energy Services, Inc. (“Coastal”) that was effective on April 6, 2005. As a result of the merger, Coastal was treated as the “acquiring” company and the historical financial statements of our company were restated to become those of Coastal for financial accounting and reporting purposes.

Coastal was formed to engage in the energy business, and following the merger, we began pursuing opportunities in the energy industry and particularly, in the oil and gas industries. On March 16, 2007, we acquired a direct working interest in approximately 171,000 gross acres in the Illinois Basin located in Southern Indiana known to contain the New Albany Shale. On April 12, 2007 we acquired the North Texas Properties which include those wells and properties located on 5,231 acres in North Texas. Prior to our acquisition of the North Texas Properties, we had only conducted nominal operations and had only nominal assets.

Properties

South Texas Oil, Gas and Mineral Rights—the DSX Properties.  On August 7, 2007, we entered into a purchase agreement to acquire, effective as of June 1, 2007, a working interest in over 95% of the DSX Properties in South Texas for consideration of $100.0 million, subject to certain adjustments and closing conditions. Baseline operates approximately 100% of the wells on these properties. See “The Transactions.”

Proved reserves on the DSX Properties have been estimated in the CG&A Report to be 42.2 Bcfe with a pre-tax PV-10 value of $143.8 million at $64.02/Bbl and $7.75/MMbtu. Of the proved reserves, 19.2% are PDP, 30.8% are PDNP and 50.0% are PUD reserves.

The DSX Properties are situated within the Blessing Field area, located in Matagorda County, Texas, on trend with several prolific Frio fields. Most of these fields were structural traps along down-to-the-coast growth faults containing normally-pressured Frio sand reservoirs. A proprietary 3-D seismic survey was acquired over the area in 1996 and, as a result, a series of buried faults were identified that set up traps in the deeper, geopressured Frio section basinward of Blessing Field. With the aid of a proprietary 3D seismic survey, DSX has drilled 12 successful wells to date, experiencing a reported 100% success rate, and has established production in 5 separate fault blocks, with proved and probable reserves in 21 different sands.

North Texas Oil, Gas and Mineral Rights—North Texas Properties.  On April 12, 2007, we acquired, effective as of February 1, 2007, a 100% working interest in 5,231 acres in the Eliasville Field located in Stephens County in North Texas, roughly 90 miles west of Fort Worth, Texas. The Eliasville Field was discovered in the 1920’s and produces primarily from the Caddo Lime oil formation at a depth of 3,300 feet. Currently the field produces 3.0 MMcfe/d of net production, with an average net revenue interest of approximately 78.5%. There are 82 oil wells producing in the field, and a portion of it is operated as an active waterflood with 54 injection wells. There are eight leases, two central operating facilities and three tank batteries. After the waterflood was initiated in the 1980’s, oil production peaked at 1,500 Bbls/d from the central six leases.

Proved reserves have been estimated in the CG&A Reserve Report to be 25.4 Bcfe with a pre-tax PV-10 value of $59.7 million at $64.02/Bbl and $7.75/MMbtu. Of the proved reserves, 64.1% are PDP, 9.2% PDNP and 26.6% are PUD reserves.

Southern Indiana Oil, Gas and Mineral Rights—New Albany Shale.  We own a direct working interest in leasehold interests covering approximately 171,000 gross (32,340 net) surface acres in the Illinois Basin located in Southern Indiana known to overlay the New Albany Shale formation. Our acreage is grouped into three separate areas of mutual interest, where we have varying working interests as follows:

• 19.7% working interest in approximately 122,000 gross acres (approximately 24,400 net acres) located primarily in Greene County and operated by Aurora Oil & Gas Corporation;

• 18.2% working interest in approximately 41,000 gross acres (approximately 7,380 net acres) located in Knox and Sullivan Counties and operated by Rex Energy Corporation; and

• 6.9% working interest in approximately 8,000 gross acres (560 net acres) located in Greene County, operated by El Paso Corporation.

The name “New Albany Shale” refers to brownish-black shale exposed along the Ohio River at New Albany in Floyd County, Indiana, and is present in the subsurface throughout much of the Illinois Basin. The Illinois Basin covers approximately 60,000 square miles in parts of Illinois, Southwestern Indiana and Western Kentucky. The New Albany Shale has produced natural gas since 1858, mostly from wells located in Southwestern Indiana and Western Kentucky.

Although the industry has reported a range of natural gas production rates and reserve potential in the New Albany Shale, there is not extensive production history from horizontal wells completed in the New Albany Shale and we have no proved reserves booked to its acreage position.

	Proved Reserves(1)				Net Acreage
Property	% Gas	Natural Gas Equivalent	PV-10 Value(2)
		(MMcfe)	($ thousands)
DSX Properties	77.1%	42,219	$	143,803	2,374
North Texas	1.6%	25,439		59,717	5,231
New Albany Shale	—	—		—	32,340
All Properties	48.7%	67,658	$	203,521	39,945
Property	Net Revenue Interest %	Net Producing Wells	Current Daily Net Production(3)		Reserve Life(4)
			(MMcfe/d)		(Years)
DSX Properties	71.0%	12		8.3	13.9
North Texas	78.5%	82		3.0	22.9
New Albany Shale	14.5%	—		—	—
All Properties		94		11.4	16.3

⁽¹⁾ Both Baseline’s and the DSX Properties’ proved reserves are from the CG&A Reserve Report.

⁽²⁾ Based on May 31, 2007 prices of $64.02 per Bbl and $7.75 per MMBtu. See “Non-GAAP Financial Measures” and see “Business—Proved Reserves” for a reconciliation of PV-10 to the standardized measure of discounted future cash flows.

⁽³⁾ Current Daily Net Production for the three month period from May 1, 2007 to July 31, 2007.

⁽⁴⁾ Calculated by dividing total proved reserves by the annualized average net daily production for the three month period from May 1, 2007 to July 31, 2007.

As is customary in the oil and natural gas industry, we can generally retain our interest in undeveloped acreage by drilling activity that establishes commercial production sufficient to maintain the leases or by paying delay rentals during the remaining primary term of leases. The oil and natural gas leases in which we have an interest are for varying primary terms, and if production under a lease continues from our developed lease acreage beyond the primary term, we are entitled to hold the lease for as long as oil or natural gas is produced.

We do not have any obligations under existing contracts or agreements calling for the provision of fixed and determinable quantities of oil and natural gas over the next three years, and have therefore not filed any information or reports with any federal authority or agency containing estimates of total proved developed or undeveloped net oil or natural gas reserves. Our oil and natural gas properties consist primarily of oil and natural gas wells and our interests in leasehold acreage, both developed and undeveloped.

Proved Reserves

Due to the inherent uncertainties and the limited nature of reservoir data, proved reserves are subject to change as additional information becomes available. The estimates of reserves, future cash flows and present value are based on various assumptions, including those prescribed by the SEC, and are inherently imprecise. Although we believe these estimates are reasonable, actual future production, cash flows, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves may vary substantially from these estimates. Also, the use of a 10% discount factor for reporting purposes may not necessarily represent the most appropriate discount factor, given actual interest rates and risks to which our business or the oil and natural gas industry in general are subject.

These calculations were prepared using standard geological and engineering methods generally accepted by the petroleum industry and in accordance with SEC financial accounting and reporting standards. The

estimated present value of proved reserve does not give effect to indirect expenses such as general and administrative expenses, debt service and future income tax expense or to depletion, depreciation, and amortization.

In accordance with applicable financial accounting and reporting standards of the SEC, the estimates of our proved reserves and the present value of proved reserves set forth herein are made using oil and natural gas sales prices estimated to be in effect as of the date of such reserve estimates and are held constant throughout the life of the properties. Estimated quantities of proved reserves and their present value are affected by changes in oil and natural gas prices. The average prices utilized for the purpose of estimating our proved reserves and the present value of proved reserves as of June 1, 2007 were $64.02 per barrel of oil and $7.75 per Mcf of natural gas.

Based on the CG&A Reserve Report, we had estimated total proved reserves of 67.7 Bcfe of which 39.8 Bcfe were proved developed reserves. We have not reported our reserves to any federal authority or agency.

The table below provides a reconciliation of PV-10 to the standardized measure of discounted future net cash flows.

	As of June 1, 2007
	Baseline			DSX Properties			Combined
	(dollars in thousands)
PV-10	$	59,717		$	143,804		$	203,521
Future income taxes, discounted at 10%		(16,377	)		(32,588	)		(48,965	)
Standardized income of discounted future net cash flows	$	23,340		$	111,216		$	154,556

The following tables set forth certain information as of June 1, 2007 with respect to estimated proved oil and natural gas reserves pursuant to SEC guidelines, and the present value of proved oil and natural gas reserves:

Baseline

	Oil	Natural Gas	Undiscounted Future Net Cash Flow		Present Value of Proved Reserves Discounted at 10%
	(MBbl)	(MMcf)	(dollars in thousands)
Developed Producing	2,673	275	$	60,995	$	31,312
Developed Nonproducing	383	53		10,007		5,151
Proved Undeveloped	1,117	73		47,845		23,254
Total Proved	4,173	401	$	118,848	$	59,717

DSX Properties

	Oil	Natural Gas	Undiscounted Future Net Cash Flow		Present Value of Proved Reserves Discounted at 10%
	(MBbl)	(MMcf)	(dollars in thousands)
Developed Producing	354	5,995	$	52,301	$	41,523
Developed Nonproducing	363	10,816		79,373		27,314
Proved Undeveloped	893	15,748		120,944		74,966
Total Proved	1,610	32,559	$	252,618	$	143,803

Combined Baseline and DSX Properties

	Oil	Natural Gas	Undiscounted Future Net Cash Flow		Present Value of Proved Reserves Discounted at 10%
	(MBbl)	(MMcf)	(dollars in thousands)
Developed Producing	3,027	6,270	$	113,296	$	72,835
Developed Nonproducing	746	10,869		89,380		32,465
Proved Undeveloped	2,010	15,821		168,789		98,220
Total Proved	5,783	32,961	$	371,466	$	203,521

Production and Price History

Prior to our acquisition of the North Texas Properties on April 12, 2007, we had nominal assets and no natural gas and oil production. From the period of April 12, 2007 to June 30, 2007, we produced 6,760 Mcf of natural gas and 44,041 Bbls of oil, or 271 MMcfe. Our average sales price for the same period was $63.53 per Bbl and $3.24 per Mcf, or $10.41 per Mcfe. Our average production cost was $4.83 per Mcfe for the same period.

The following table sets forth certain information regarding the production volumes, revenue, average prices received and average production costs associated with the sale of oil and natural gas on the DSX Properties for the years ended December 31, 2005 and December 31, 2006 and LTM Period.

DSX Properties

	Year Ended December 31,				LTM Ended June 30, 2007
	2005		2006
Net Production:
Oil (Bbls)		37,829		91,932		115,164
Natural Gas (Mcf)		516,010		1,458,194		1,867,664
Natural Gas Equivalent (Mcfe)		742,984		2,009,786		2,558,648
Oil and Natural Gas Sales (dollars in thousands):
Oil	$	2,209	$	5,887	$	7,210
Natural Gas		5,403		11,199		13,621
Total	$	7,612	$	17,086	$	20,831
Average Sales Price:
Oil ($ per Bbl)	$	58.39	$	64.04	$	62.60
Natural Gas ($ per Mcf)		10.47		7.68		7.29
Natural Gas Equivalent ($ per Mcfe)	$	10.25	$	8.50	$	8.14
Oil and Natural Gas Costs (dollars in thousands):
Lease operating expenses	$	2,555	$	1,050	$	1,582
Production taxes		496		1,112		1,344
Average production cost per Mcfe	$	4.11	$	1.08	$	1.14

Drilling Activity

Prior to our acquisition of the North Texas Properties on April 12, 2007, our drilling history was limited to our participation in the New Albany Shale. From the period of April 12, 2007 to June 30, 2007, we drilled no new wells. As of June 30, 2007, we had 82 producing wells.

DSX Properties

DSX drilled their first well on the Blessing Field in 2004. In 2005, DSX drilled three wells, increasing the number to four producing wells. In 2006, five wells were drilled, increasing the total numbers to nine producing wells. Through the six months ended June 30, 2007, an additional three wells were drilled, increasing the number of producing wells to 12.

The information contained in the foregoing section should not be considered indicative of future drilling performance, nor should it be assumed that there is any necessary correlation between the number of productive wells drilled and the amount of oil and natural gas that may ultimately be recovered by us. We do not own any drilling rigs and all of our drilling activities are conducted by independent drilling contractors.

Regulation of the Oil and Natural Gas Industry

Regulation of Transportation and Sale of Oil

Sales of crude oil, condensate and natural gas liquids are not currently regulated and are made at negotiated prices. Nevertheless, Congress could reenact price controls in the future.

Our sales of crude oil are affected by the availability, terms and cost of transportation. The transportation of oil in common carrier pipelines is also subject to rate regulation. The Federal Energy Regulatory Commission, or the FERC, regulates interstate oil pipeline transportation rates under the Interstate Commerce Act. In general, interstate oil pipeline rates must be cost-based, although settlement rates agreed to by all shippers are permitted and market-based rates may be permitted in certain circumstances. Effective January 1, 1995, the FERC implemented regulations establishing an indexing system (based on inflation) for transportation rates for oil that allowed for an increase or decrease in the cost of transporting oil to the purchaser. A review of these regulations by the FERC in 2000 was successfully challenged on appeal by an association of oil pipelines. On remand, the FERC in February 2003 increased the index slightly, effective July 2001. Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of oil transportation rates will not affect our operations in any way that is of material difference from those of our competitors.

Further, interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory basis. Under this open access standard, common carriers must offer service to all similarly situated shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity, access is governed by prorationing provisions set forth in the pipelines’ published tariffs. Accordingly, we believe that access to oil pipeline transportation services generally will be available to us to the same extent as to our competitors.

Regulation of Transportation and Sale of Natural Gas

Historically, the transportation and sale for resale of natural gas in interstate commerce have been regulated pursuant to the Natural Gas Act of 1938, the Natural Gas Policy Act of 1978 and regulations issued under those Acts by the FERC. In the past, the federal government has regulated the prices at which natural gas could be sold. While sales by producers of natural gas can currently be made at uncontrolled market prices, Congress could reenact price controls in the future. Deregulation of wellhead natural gas sales began with the enactment of the Natural Gas Policy Act. In 1989, Congress enacted the Natural Gas Wellhead Decontrol Act. The Decontrol Act removed all Natural Gas Act and Natural Gas Policy Act price and non-price controls affecting wellhead sales of natural gas effective January 1, 1993. While sales by producers of natural gas can currently be made at unregulated market prices, Congress could reenact price controls in the future.

FERC regulates interstate natural gas transportation rates and service conditions, which affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas. Since 1985, the FERC has endeavored to make natural gas transportation more accessible to natural gas buyers and sellers. The FERC has stated that open access policies are necessary to improve the competitive structure of the interstate natural gas pipeline industry and to create a regulatory framework that will put natural gas sellers into more direct contractual relations with natural gas buyers by, among other things, unbundling the sale of natural gas from the sale of transportation and storage services. Beginning in 1992, the FERC issued Order No. 636 and a series of related orders to implement its open access policies. As a result of the Order No. 636 program, the marketing and pricing of natural gas have been significantly altered. The interstate pipelines’ traditional role as wholesalers of natural gas has been eliminated and replaced by a structure under which pipelines provide transportation and storage service on an open access basis to others who buy and sell natural gas. Although the FERC’s orders do not directly regulate natural gas producers, they are intended to foster increased competition within all phases of the natural gas industry.

In 2000, the FERC issued Order No. 637 and subsequent orders, which imposed a number of additional reforms designed to enhance competition in natural gas markets. Among other things, Order No. 637 effected changes in FERC regulations relating to scheduling procedures, capacity segmentation, penalties, rights of first refusal and information reporting. Most major aspects of Order No. 637 have been upheld on judicial review, and most pipelines’ tariff filings to implement the requirements of Order No. 637 have been accepted by the FERC and placed into effect.

The Energy Policy Act of 2005, which we refer to as EP Act 2005, gave FERC increased oversight and penalty authority regarding market manipulation and enforcement. EP Act 2005 amended the NGA to prohibit market manipulation and also amended the NGA and the NGPA to increase civil and criminal penalties for any violations of the NGA, NGPA and any rules, regulations or orders of FERC up to $1,000,000 per day, per violation. In addition, FERC issued a final rule effective January 26, 2006, regarding market manipulation, which makes it unlawful for any entity, in connection with the purchase or sale of natural gas or transportation service subject to FERC jurisdiction, to defraud, make an untrue statement, or omit a material fact or engage in any practice, act, or course of business that operates or would operate as a fraud. This final rule works together with FERC’s enhanced penalty authority to provide increased oversight of the natural gas marketplace.

We cannot accurately predict whether the FERC’s actions will achieve the goal of increasing competition in markets in which our natural gas is sold. Additional proposals and proceedings that might affect the natural gas industry are pending before the FERC and the courts. The natural gas industry historically has been very heavily regulated. Therefore, we cannot provide any assurance that the less stringent regulatory approach recently established by the FERC will continue. However, we do not believe that any action taken will affect us in a way that materially differs from the way it affects other natural gas producers.

Natural Gas Gathering

Section 1(b) of the NGA exempts natural gas gathering facilities from the jurisdiction of the FERC. FERC has developed tests for determining which facilities constitute jurisdictional transportation facilities under the NGA and which facilities constitute gathering facilities exempt from FERC’s NGA jurisdiction. From time to time, FERC reconsiders its test for defining non-jurisdictional gathering. For example, there is currently pending at FERC a proposed rulemaking to reformulate its test for non-jurisdictional gathering in the shallow waters of the Outer Continental Shelf. In recent years, FERC has also permitted jurisdictional pipelines to “spin down” exempt gathering facilities into affiliated entities that are not subject to FERC jurisdiction, although FERC continues to examine the circumstances in which such a “spin down” is appropriate and whether it should reassert jurisdiction over certain gathering companies and facilities that previously had been “spun down.” We cannot predict the effect that FERC’s activities in this regard may have on our operations, but we do not expect these activities to affect our operations in any way that is materially different from the effect thereof on our competitors.

State regulation of gathering facilities generally includes various safety, environmental, and in some circumstances, non-discriminatory take or service requirements, but does not generally entail rate regulation. Recently, however, gas gathering has received greater regulatory scrutiny at the state levels. For example, the Texas Railroad Commission enacted a Natural Gas Transportation Standards and Code of Conduct to provide regulatory support for the state’s more active review of rates, services and practices associated with the gathering and transportation of gas by an entity that provides such services to others for a fee, in order to prohibit such entities from unduly discriminating in favor of their affiliates.

Intrastate natural gas transportation is also subject to regulation by state regulatory agencies, although the FERC does regulate the rates, terms and conditions of service provided by intrastate pipelines which transport gas subject to the FERC’s Natural Gas Act jurisdiction under Section 311 of the Natural Gas Policy Act. The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state. Insofar as such regulation within a particular state will generally affect all intrastate natural gas shippers within the state on a comparable basis, we believe that the regulation of similarly situated intrastate natural gas transportation in any states in which we operate and ship natural gas on an intrastate basis will not affect our operations in any way that is of material difference from those of our competitors. Like the regulation of interstate transportation rates, the regulation of intrastate transportation rates affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas.

Sales of condensate and natural gas liquids are not currently regulated and are made at market prices.

Regulation of Production

The production of oil and natural gas is subject to regulation under a wide range of local, state and federal statutes, rules, orders and regulations. Federal, state and local statutes and regulations require permits for drilling operations, drilling bonds and reports concerning operations. All of the states in which we own and operate properties have regulations governing conservation matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum allowable rates of production from oil and natural gas wells, the regulation of well spacing, and plugging and abandonment of wells. The effect of these regulations is to limit the amount of oil and natural gas that we can produce from our wells and to limit the number of wells or the locations at which we can drill, although we can apply for exceptions to such regulations or to have reductions in well spacing. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within its jurisdiction.

The failure to comply with these rules and regulations can result in substantial penalties. Our competitors in the oil and natural gas industry are subject to the same regulatory requirements and restrictions that affect our operations.

Environmental Matters and Other Regulation

General

Our operations are subject to stringent and complex federal, state and local laws and regulations governing environmental protection as well as the discharge of materials into the environment. These laws and regulations may, among other things:

• require the acquisition of various permits before drilling commences;

• restrict the types, quantities and concentration of various substances that can be released into the environment in connection with oil and natural gas drilling and production activities;

• limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas; and

• require remedial measures to mitigate pollution from former and ongoing operations, such as requirements to close pits and plug abandoned wells.

These laws and regulations may also restrict the rate of oil and natural gas production below the rate that would otherwise be possible. The regulatory burden on the oil and gas industry increases the cost of doing business in the industry and consequently affects profitability. Additionally, Congress and federal and state agencies frequently revise environmental laws and regulations, and any changes that result in more stringent and costly waste handling, disposal and cleanup requirements for the oil and gas industry could have a significant impact on our operating costs. As part of transactions in which we acquire oil and gas properties and facilities, we may assume the environmental liabilities of prior owners and operators of these oil and gas properties or facilities.

Although we believe that we are in substantial compliance with all applicable environmental laws, regulations, and other requirements, or are addressing those instances in which we have identified areas of non-compliance, the production of oil and gas entails significant environmental risks and is subject to complex federal, state, and local environmental laws.

The following is a summary of some of the existing laws, rules and regulations to which our business operations are subject.

Waste Handling

The Resource Conservation and Recovery Act, or RCRA, and comparable state statutes, as well as other oil and gas or natural resource statutes, regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. Under the auspices of the federal Environmental Protection Agency, or EPA, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Drilling fluids, produced waters and most of the other wastes associated with the exploration, development and production of crude oil or natural gas are currently regulated under RCRA or state non-hazardous waste provisions. Releases or spills of these regulated materials may result in remediation liabilities under these statutes. It is possible that certain oil and natural gas exploration and production wastes now classified as non-hazardous could be classified as hazardous wastes in the future. Any such change could result in an increase in our costs to manage and dispose of wastes, which could have a material adverse effect on our results of operations and financial position.

Comprehensive Environmental Response, Compensation, and Liability Act

The Comprehensive Environmental Response, Compensation, and Liability Act, or CERCLA, also known as the Superfund Law, imposes joint and several liability, without regard to fault or legality of conduct, on classes of persons who are considered to be responsible for the release of a hazardous substance into the environment. These persons include the current or former owner or operator of the site where the release occurred and anyone who disposed or arranged for the disposal of a hazardous substance released at the site. Under CERCLA, such persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.

In the course of our operations, we generate wastes that may fall within CERCLA’s definition of a “hazardous substance”. We may be jointly and severally liable under CERCLA or comparable state statutes for

all or part of the costs required to clean up sites at which these wastes have been disposed. Although CERCLA currently contains a “petroleum exclusion” from the definition of “hazardous substance,” state laws affecting our operations impose cleanup liability for release of petroleum or petroleum related products, including oil cleanups.

Further, we currently own, lease or operate properties that have been used for oil and natural gas exploration and production for many years. Hazardous substances or petroleum may have been released on, at or under the properties owned, leased or operated by us, or on, at or under other locations, including off-site locations, where such hazardous substances or other wastes have been taken for disposal. In addition, some of our properties have been operated by third parties or by previous owners or operators whose handling, treatment and disposal of hazardous substances, petroleum, or other materials or wastes were not under our control. These properties and the substances or materials disposed or released on, at or under them may be subject to CERCLA, RCRA or analogous or other state laws. Under such laws, we could be required to remove previously disposed substances and wastes or released petroleum, remediate contaminated property or perform remedial plugging or pit closure operations to prevent future contamination.

Water Discharges

The Federal Water Pollution Control Act, or the Clean Water Act, and analogous state laws, impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil and other substances into waters of the United States or state waters. Under these laws, the discharge of pollutants into regulated waters is prohibited except in accordance with the terms of a permit issued by EPA or an analogous state agency. The Clean Water Act regulates storm water run-off from oil and natural gas facilities and requires a storm water discharge permit for certain activities. Such a permit requires the regulated facility to monitor and sample storm water run-off from its operations. The Clean Water Act and regulation promulgated thereunder also prohibit discharges of dredged and fill material in wetlands and the waters of the United States unless authorized by an appropriately issued permit. Spill prevention, control and countermeasure requirements of the Clean Water Act require the preparation of plans and the implementation of measures to prevent the contamination of navigable waters in the event a petroleum hydrocarbon tank spills, ruptures or leaks. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations.

The Oil Pollution Act of 1990, or OPA, which amends and augments the Clean Water Act, establishes strict liability for owners and operators of facilities that are the site of a release of oil into waters of the United States. In addition, OPA and regulations promulgated pursuant thereto impose a variety of regulations on responsible parties related to the prevention of oil spills and liability for damages resulting from such spills. OPA also requires certain oil and natural gas operators to develop, implement and maintain facility response plans, conduct annual spill training for certain employees and provide varying degrees of financial assurance.

Air Emissions

The Federal Clean Air Act, or CAA, and comparable state laws regulate emissions of various air pollutants through air emissions permitting programs and the imposition of other requirements. In addition, EPA has developed and continues to develop stringent regulations governing emissions of toxic air pollutants at specified sources. Our operations use equipment that emits air pollutants which may be subject to federal and state air pollution control laws. These laws require the use of air emissions abatement equipment to achieve prescribed emissions limitations and ambient air quality standards, as well as operating permits for existing equipment and construction permits for new and modified equipment.

Permits and related compliance obligations under the CAA and comparable state laws, as well as changes to state implementation plans for controlling air emissions in regional non-attainment areas, may require oil and natural gas exploration and production operators to incur future capital expenditures in connection with the addition or modification of existing air emission control equipment and strategies. In addition, some oil and

natural gas facilities may be included within the categories of hazardous air pollution sources, which are subject to increasing regulation under CAA and comparable state laws. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the CAA and associated state laws and regulations. Oil and gas operations may in certain circumstances and locations be subject to permits and restrictions under these statutes for emissions of air pollutants, including volatile organic compounds, nitrous oxides, and hydrogen sulfide.

National Environmental Policy Act

Oil and natural gas exploration and production activities on federal lands are subject to the National Environmental Policy Act, or NEPA. NEPA requires federal agencies, including the Department of Interior, to evaluate major agency actions that have the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an Environmental Assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that may be made available for public review and comment. All of our current exploration and production activities, as well as proposed exploration and development plans, on federal lands require governmental permits that are subject to the requirements of NEPA. This process has the potential to delay the development of oil and natural gas projects.

Endangered Species, Wetlands and Damages to Natural Resources

Various state and federal statutes prohibit certain actions that adversely affect endangered or threatened species and their habitat, migratory birds, wetlands, and natural resources. These statutes include the Endangered Species Act, the Migratory Bird Treaty Act, the Clean Water Act and CERCLA. Where takings of or harm to species or damages to wetlands, habitat, or natural resources occur or may occur, government entities or at times private parties may act to prevent oil and gas exploration or production or seek damages to species, habitat, or natural resources resulting from filling or construction or releases of oil, wastes, hazardous substances or other regulated materials.

OSHA and Other Laws and Regulations

We are subject to the requirements of the federal Occupational Safety and Health Act (OSHA) and comparable state statutes. The OSHA hazard communication standard, the Emergency Planning and Community Right to Know Act and similar state statutes require that we organize and/or disclose information about hazardous materials stored, used or produced in our operations.

Recent studies have indicated that emissions of certain gases may be contributing to warming of the Earth’s atmosphere. In response to these studies, many nations have agreed to limit emissions of “greenhouse gases” pursuant to the United Nations Framework Convention on Climate Change, also known as the “Kyoto Protocol.” Methane, a primary component of natural gas, and carbon dioxide, a byproduct of the burning of oil and natural gas, and refined petroleum products, are “greenhouse gases” regulated by the Kyoto Protocol. Although the United States is not participating in the Kyoto Protocol, several states have adopted legislation and regulations to reduce emissions of greenhouse gases. Restrictions on emissions of methane or carbon dioxide that may be imposed in various states could adversely affect our operations and demand for our products. Additionally, the U.S. Supreme Court has ruled, in Massachusetts, et al. v. EPA, that the U.S. Environmental Protection Agency abused its discretion under the Clean Air Act by refusing to regulate carbon dioxide emissions from mobile sources. This Supreme Court decision could result in federal regulation of carbon dioxide emissions and other greenhouse gases, and may affect the outcome of other climate change lawsuits pending in U.S. federal courts in a manner unfavorable to our industry. Currently, our operations are not adversely impacted by existing state and local climate change initiatives and, at this time, it is not possible to accurately estimate how potential future laws or regulations addressing greenhouse gas emissions would impact our business.

Private Lawsuits

In addition to claims arising under state and federal statutes, where a release or spill of hazardous substances, oil and gas or oil and gas wastes have occurred, private parties or landowners may bring lawsuits against oil and gas companies under state law. The plaintiffs may seek property damages, personal injury damages, remediation costs or injunctions to require remediation or restoration of contaminated property, soil, groundwater or surface water. In some cases, oil and gas operations are located near populated areas and emissions or accidental releases could affect the surrounding properties and population.

Employees

In addition to Thomas Kaetzer, our Chairman and Chief Executive Officer, and Patrick McGarey, our Chief Financial Officer, as of August 31, 2007 we had seven additional full-time employees and four part-time consultants.

Legal Proceedings

There are no pending legal proceedings, and the Company is not aware of any threatened legal proceedings, to which the Company is a party or to which its property is subject.

MANAGEMENT

The following table sets forth as of August 31, 2007 certain information regarding our directors and executive officers:

Name	Age	Position
Thomas Kaetzer	47	Chairman, Chief Executive Officer and President
Patrick McGarey	49	Chief Financial Officer
Alan Gaines	51	Director
Richard d’Abo	51	Director

The business experience of each director and named executive officer of the Company is set forth below:

Mr. Thomas Kaetzer.  Mr. Kaetzer was promoted to our chairman and chief executive officer on March 21, 2007. He previously was our president and chief operating officer, titles he held since December 2006. Mr. Kaetzer began his career with Texaco Inc., where, from 1981 to 1995, he held various positions. In 1995, Mr. Kaetzer left Texaco and worked for Vastar Resources Inc., a major independent oil and gas company. In 1996 Mr. Kaetzer formed Southwest Texas Oil & Gas Co., which subsequently merged into GulfWest Energy Inc. in 1998. Mr. Kaetzer served as President/Chief Operating Officer of GulfWest from 1999 to 2004, and as Vice President of Operations for its successor, Crimson Exploration Inc., from 2005 to July 2006. From August 2006 to immediately prior to joining Baseline, Mr. Kaetzer worked as a consultant to several companies in the oil and gas industry. Mr. Kaetzer earned his B.S. from the University of Illinois in 1981 and his M.S. in petroleum engineering from Tulane University in 1988.

Mr. Patrick McGarey.  Mr. McGarey has served as Chief Financial Officer since August 16, 2007. From 2004 until May 2007, he served as Executive Vice President – Finance, Planning and Corporate Development at Goldking Energy Corporation, a private exploration and production company which he co-owned and co-founded along with Natural Gas Partners and another minority owner. During 2003, Mr. McGarey was principal of his own firm, Energy Growth & Value, LLC, which specialized in sourcing debt and equity capital for energy projects. From 1998 through 2002, he served in a variety of managerial roles within the Energy Capital and Structured Finance business units of The Williams Companies, in Houston, Texas. Prior to 1998, Mr. McGarey worked in commercial and investment banking, focusing on the energy industry. He began his career as a petroleum engineer with Texaco. Mr. McGarey has a Bachelor of Science degree in Civil Engineering from Virginia Polytechnic Institute and State University and an MBA degree from Loyola Marymount University in Los Angeles.

Mr. Alan Gaines.  Mr. Gaines has served as a director of our Company since April 2005. He is currently the Chairman of Dune Energy, Inc., an independent, publicly traded oil and gas company engaged in the development, exploration and acquisition of oil and gas properties, with operations presently concentrated onshore the Louisiana/Texas Gulf Coast as well as the Fort Worth Basin Barnett Shale. Mr. Gaines also currently serves as the Chairman of ABC Funding, Inc., a publicly traded company with no current assets or operations. Mr. Gaines has 25 years of experience as an energy investment and merchant banker. In 1983, he co-founded Gaines, Berland Inc., an investment bank and brokerage firm, specializing in global energy markets, with particular emphasis given to small to medium capitalization companies involved in exploration and production, pipelines, refining and marketing, and oilfield services. Mr. Gaines holds a BBA in Finance from Baruch College, and an MBA in Finance (with distinction) from Zarb School, Hofstra University School of Graduate Management.

Mr. Richard d’Abo.  Mr. d’Abo has served as a director of our Company since January 17, 2006. He is presently a transaction partner at The Yucaipa Companies, a private equity firm focused on consolidating companies within the supermarket industry. From 1995 through 2003, Mr. d’Abo was a private investor, and served as a consultant to numerous companies both public and private regarding acquisitions and related financings. From 1988 to 1994, Mr. d’Abo was a partner at The Yucaipa Companies and was instrumental in the creation of financing structures for a number of acquisitions.

Executive and Director Compensation

Set forth in the chart below is the compensation received by our named executive officers at our fiscal years ended December 31, 2006 and December 31, 2005:

Summary Compensation Table

Name and Principal Position	Year	Salary			Bonus	Stock Awards	Option Awards		Non-Equity Incentive Plan Compensation	All Other Compensation
Barrie Damson, Chief Executive Officer (1)	2006	$	0		n/a	n/a	0		n/a	n/a
Thomas Kaetzer, Chairman, Chief Executive Officer and President (2)	2006	$	15,833	(2)	n/a	n/a	2,000,000	(3)	n/a	n/a
Richard Cohen, Chief Financial Officer (4)	2006	$	90,000	(4)	n/a	n/a	175,000	(5)	n/a	n/a
	2005	$	7,500

⁽¹⁾ Mr. Damson joined our board of directors and became our Chairman and Chief Executive Officer as of February 1, 2006. Mr. Damson resigned as Chairman and Chief Executive Officer, effective March 21, 2007.

⁽²⁾ Mr. Kaetzer became our President and Chief Operating Officer as of December 5, 2006. In 2006 he was paid an amount equal to one month’s salary at an annualized salary of $190,000 as provided for in his employment agreement. See the subsection below entitled “— Employment Agreements”. Mr. Kaetzer was appointed Chairman and Chief Executive Officer on March 21, 2007, upon the resignation of Mr. Damson.

⁽³⁾ Options to purchase (i) up to 1,000,000 shares of our common stock at an exercise price of $0.50 per share, (ii) up to 500,000 shares of our common stock at an exercise price of $0.60 per share and (iii) up to 500,000 shares of our common stock at an exercise price of $1.00 per share, each option of which is subject to a vesting schedule, as follows: (i) up to one-third of the underlying common stock exercisable at any time from and after December 20, 2006; (ii) up to an additional one-third of the underlying common stock exercisable at any time from and after December 20, 2007; and (iii) up to the remaining one-third of the underlying common stock exercisable at any time from and after December 20, 2008; provided, that Mr. Kaetzer’s employment has not been terminated by us for cause or by Mr. Kaetzer without good reason.

⁽⁴⁾ Mr. Cohen became our Chief Financial Officer in December 2005, at which time he received a salary of $7,500 per month. Mr. Cohen stepped down as Chief Financial Officer in August 2007 upon the hiring of Mr. McGarey.

⁽⁵⁾ Option granted December 27, 2005 to purchase up to 175,000 shares of our common stock at an exercise price of $0.94 per share.

Outstanding Equity Awards at 2006 Fiscal Year-End

Set forth in the chart below are the outstanding equity awards held by our named executive officers at our fiscal year ended December 31, 2006:

	Option Awards
Name	Number of Securities Underlying Unexercised Options Exercisable		Number of Securities Underlying Unexercised Options Unexercisable		Option Exercise Price		Option Expiration Date
Barrie Damson, Chief Executive Officer(1)	5,000,000	(2)	0		$	0.05	April 28, 2010
Alan Gaines, Vice Chairman(3)	5,000,000	(2)	0			0.05	April 28, 2010
Thomas Kaetzer, President and Chief Operating Officer(4)	333,333	(5)	666,667	(5)		0.50	December 20, 2011
	166,666	(5)	333,334	(5)		0.60	December 20, 2011
	166,666	(5)	333,334	(5)		1.00	December 20, 2011
Richard Cohen, Chief Financial Officer(6)	175,000	(7)	0			0.94	December 26, 2010
Richard d’Abo, Director	250,000	(8)	0			0.05	April 28, 2010

⁽¹⁾ Mr. Damson resigned as Chairman and Chief Executive Officer, effective March 21, 2007.

⁽²⁾ Option grants awarded on April 29, 2005 to purchase up to 6,000,000 shares of our common stock, as adjusted to reflect the subsequent cancellation of options with respect to the purchase of 1,000,000 shares of our common stock on December 20, 2006.

⁽³⁾ Mr. Gaines resigned as vice-chairman on August 31, 2007.

⁽⁴⁾ Mr. Kaetzer was hired as President and Chief Operating Officer on December 5, 2006. Mr. Kaetzer was appointed to Chairman and Chief Executive Officer on March 21, 2007.

⁽⁵⁾ Options shall vest and be exercised in whole or in part, as follows: (i) up to one-third of the underlying common stock at any time from and after December 20, 2006; (ii) up to an additional one-third of the underlying common stock at any time from and after December 20, 2007; and (iii) up to the remaining one-third of the underlying common stock at any time from and after December 20, 2008, provided, that Mr. Kaetzer’s employment has not been terminated by us for cause or by Mr. Kaetzer without good reason.

⁽⁶⁾ Mr. Cohen stepped down as Chief Financial Officer in August 2007.

⁽⁷⁾ Option granted December 26, 2006 to purchase up to 175,000 shares of our common stock at an exercise price of $0.94 per share.

⁽⁸⁾ Option granted April 29, 2005 to purchase up to 250,000 shares of our common stock at an exercise price of $0.05 per share

Employment Agreements

Thomas Kaetzer Employment Agreement.  Our employment agreement, dated December 20, 2006, with Thomas Kaetzer, provides that Mr. Kaetzer shall serve as our President and Chief Operating Officer effective as of December 5, 2006 and ending on December 30, 2008, unless earlier terminated or extended under the terms of such agreement. In consideration for such employment, the Company shall, among other things, pay Mr. Kaetzer an annual salary of $190,000. In addition to his annual salary, if Mr. Kaetzer remains in our employ on December 5, 2007 he shall be entitled to a performance bonus of $50,000. In addition, during the second year of his employment and thereafter (if his employment is extended), he may be entitled to a performance bonus, solely at the discretion of our board of directors. Mr. Kaetzer is further eligible under his employment agreement to participate, subject to any eligibility, co-payment and waiting period requirements, in all employee health and/or benefit plans offered or made available to our executive officers.

Upon termination by Mr. Kaetzer for specified good reasons in the event of a merger or acquisition resulting in a diminution of his authority and duties, the relocation of his offices outside Houston, Texas of residence, or his termination by us other than for cause, the terminating executive officer will be entitled to receive from us: (i) a severance payment equal to 12-months of his then-current base salary plus pro rata bonus and fringe benefits otherwise due at time of termination; (ii) any unpaid bonus from preceding year of employment; and (iii) accrued but unused vacation days during the year such termination occurs.

In addition, his employment agreement provided for us to issue to him three non-qualified stock options to purchase up to an aggregate of two million shares of our common stock, each exercisable as to one third of the optioned shares on each of the grant date and the first and second anniversary dates thereafter. Each such option agreement provides that if Mr. Kaetzer’s employment is terminated by us for cause or by Mr. Kaetzer without good reason, unvested options shall immediately be forfeited, and that if his employment is terminated by us without cause or voluntarily by Mr. Kaetzer with good reason, optioned shares that would have vested on the next vesting date will immediately vest and become exercisable in proportion to the number of months he was employed during the 12-month period following the immediately preceding vesting date.

Mr. Kaetzer has further agreed under his employment agreement that, during the respective term of his employment and for a one-year period after his termination (other than its termination by him for good reason or by us without cause), not to engage, directly or indirectly, as an owner, employee, consultant or otherwise, in any business engaged in the exploration, drilling or production of natural gas or oil within a 10 mile radius from any property that we then have an ownership, leasehold or participation interest. He is further prohibited during the above time period from soliciting or inducing, directly or indirectly, any of our then-current employees or customers, or any customers of ours during the one year preceding the termination of his employment.

Mr. Kaetzer was appointed to Chairman and Chief Executive Officer on March 21, 2007 and, except for his title, his employment agreement continues to govern the terms of his employment.

Patrick McGarey Employment Agreement.  On August 3, 2007, we entered into an employment agreement with Patrick H. McGarey, whereby the Company hired Mr. McGarey as our Chief Financial Officer, effective August 16, 2007. Pursuant to the employment agreement, Mr. McGarey, shall serve as our Chief Financial Officer for an initial term of two years, unless earlier terminated or extended under the terms of the employment agreement. In consideration for such employment, Mr. McGarey shall receive an annual salary of $165,000. In addition, provided that Mr. McGarey remains in our employ, he will be entitled to a performance bonus of $33,000 for the first year of his term and a discretionary bonus each year thereafter. Mr. McGarey is further eligible under his employment agreement to participate, subject to any eligibility, co-payment and waiting period requirements, in all employee health and/or benefit plans offered or made available to our executive officers.

The employment agreement provides that in the event Mr. McGarey is terminated without “Cause” (as defined in the employment agreement), he will receive a severance payment equal to 12 months’ base salary. His employment agreement also contains covenants restricting him from participating in any business which is then engaged in the drilling, exploration or production of natural gas or oil, within a 10 mile radius of any area leased by us or in which we hold a working interest.

As additional consideration for the hiring of Mr. McGarey, we granted Mr. McGarey non-qualified stock options to purchase up to an aggregate of 1,500,000 shares of our common stock under three separate stock option agreements, each dated as of August 3, 2007 and exercisable with respect to 500,000 shares at an exercise price of $0.55 per share, $0.825 per share and $1.10 per share, respectively. Each such option shall vest and become exercisable as to one third of the optioned shares on each of the grant date and the first and second anniversary dates thereafter, provided that Mr. McGarey remains in our employ. If his employment is terminated by us for cause or by Mr. McGarey without good reason, unvested options shall immediately be forfeited, and if his employment is terminated by us without cause or voluntarily by Mr. McGarey with good reason, shares that would have vested on the next vesting date will immediately vest and become exercisable in proportion to the number of months he was employed during the 12-month period following the immediately preceding vesting date. Upon a “change of control,” unvested optioned shares shall be accelerated and become immediately exercisable.

Corporate Governance

Our board has implemented corporate governance initiatives in compliance with the Sarbanes-Oxley Act of 2002 and the related rules and regulations adopted by the SEC. Our board will continue to evaluate, and improve upon as appropriate, our corporate governance principles and policies on a going-forward basis.

Our board and audit committee has adopted a Code of Business Conduct and Ethics that applies to our directors and officers, which code addresses various topics, including:

• compliance with laws, rules and regulations;

• competition and fair dealing;

• protection and proper use of company assets;

• corporate opportunities;

• conflicts of interest;

• confidentiality;

• insider trading; and

• record keeping and public disclosure obligations.

We also have established formal whistleblower procedures for receiving and handling complaints from employees. Any concerns regarding accounting or auditing matters reported under these procedures will be communicated promptly to the audit committee.

Board of Directors

Our by-laws provide for a board of directors consisting of a minimum of one and a maximum of seven members. We currently have three directors.

The OTC Bulletin Board, on which our common stock is currently traded, does not maintain director independence standards or require us presently to maintain an audit, nominating or compensation committee. Upon completion of this offering, we intend to retain two new board members and we will undertake to establish an audit committee to assist the board in matters involving our accounting, auditing, financial reporting, internal controls and legal compliance functions, as well as such other board committees as may be appropriate given our resources and operations at that time.

Director Compensation

We have not paid any cash compensation to members of our board of directors for their services as directors. After receipt of net proceeds from this offering, our non-employee directors will receive $5,000 for each fiscal quarter commencing October 1, 2007 and $1,000 for each board meeting attended in person.

We will also reimburse our directors for reasonable expenses in connection with attendance at board and committee meetings. Directors are also eligible to receive stock options offered by our Company from time to time. See “Security Ownership of Certain Beneficial Owners and Management.”

Indemnification of Directors and Officers

Our Amended and Restated Articles of Incorporation and by-laws provide that we will indemnify, to the fullest extent permitted by the Nevada Revised Statutes governing corporations, any person made or threatened to be made a party to any action, suit or proceeding, whether civil, criminal, administrative or investigative, by reason of the fact that such person, or such person’s testator or intestate, is or was a director, officer, employee or agent of our Company or serves or served at our request as a director, officer or employee of another entity.

We may enter into agreements to indemnify our directors and officers, in addition to the indemnification provided for in our articles of incorporation and by-laws. These agreements, among other things, would indemnify our directors and officers for certain expenses (including advancing expenses for attorneys’ fees), judgments, fines and settlement amounts incurred by any such person in any action or proceeding, including any action by us or in our right, arising out of such person’s services as a director or officer of our Company, any subsidiary of ours or any other company or enterprise to which the person provides services at our request. We maintain a directors, officers and company liability insurance policy.

Insofar as indemnification for liabilities arising under the Securities Act may be permitted to our directors, officers and controlling persons pursuant to the foregoing provisions, or otherwise, we have been advised that, in the opinion of the Securities and Exchange Commission, such indemnification is against public policy as expressed in the Securities Act and is, therefore, unenforceable.

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The following table sets forth certain information regarding the beneficial ownership of our common stock as of August 31, 2007 by: (i) each person who, to our knowledge, beneficially owns more than 5% of our outstanding common stock; (ii) each of our current directors and executive officers (titles are set forth in parentheses next to the names of individuals listed below); and (iii) all of our current and executive officers and directors as a group:

Name of Beneficial Owner(1)	Amount(2)	Percent of Class(2)(3)
Thomas Kaetzer (Chairman and Chief Executive Officer)	666,665(4)	1.9%
Patrick H. McGarey (Chief Financial Officer)	499,998(5)	1.3%
Alan Gaines (Director)	7,624,250(6)	21.7%
Richard d’Abo (Director)	1,336,000(7)	3.9%
Barrie Damson	6,849,250(6)	19.5%
37 Franklin Street Westport, CT 06880
Lakewood Group LLC	3,000,000(8)	8.3%
242 4th Street Lakewood, NJ 08701
All Officers and Directors as a Group (4 persons)	10,126,913(4)(5)(6)(7)	27.6%

⁽¹⁾ Unless otherwise indicated, the address of each beneficial owner reported above is c/o Baseline Oil & Gas Corp., 11811 N. Freeway (I-45), Suite 200, Houston, Texas 77060.

⁽²⁾ A person is deemed to be the beneficial owner of securities that can be acquired by such person within 60 days from August 31, 2007. Each beneficial owner’s percentage ownership is determined by assuming that options and warrants that are held by such person (but not held by any other person), and which are exercisable within 60 days from August 31, 2007, have been exercised.

⁽³⁾ At August 31, 2007, a total of 33,363,173 shares of our common stock were issued and outstanding.

⁽⁴⁾ Refers to options to purchase (i) up to 1,000,000 shares of our common stock at an exercise price of $0.50 per share, of which 333,333 underlying shares are currently vested, (ii) up to 500,000 shares of our common stock at an exercise price of $0.60 per share, of which 166,666 shares are currently vested, and (iii) up to 500,000 shares of our common stock at an exercise price of $1.00 per share, of which 166,666 shares are currently vested. Each option is subject to a vesting schedule, as follows: (i) up to one-third of the underlying common stock exercisable at any time from and after December 20, 2006, (ii) up to an additional one-third of the underlying common stock exercisable at any time from and after December 20, 2007, and (iii) up to the remaining one-third of the underlying common stock exercisable at any time from and after December 20, 2008; provided, that Mr. Kaetzer’s employment has not been terminated by us for cause or by Mr. Kaetzer without good reason.

⁽⁵⁾ Refers to options to purchase (i) up to 500,000 shares of our common stock at an exercise price of $0.55 per share, of which 166,666 underlying shares are currently vested, (ii) up to 500,000 shares of our common stock at an exercise price of $0.825 per share, of which 166,666 shares are currently vested, and (iii) up to 500,000 shares of our common stock at an exercise price of $1.10 per share, of which 166,666 shares are currently vested. Each option is subject to a vesting schedule, as follows: (i) up to one-third of the underlying common stock exercisable at any time from and after August 3, 2007, (ii) up to an additional one-third of the underlying common stock exercisable at any time from and after August 3, 2008, and (iii) up to the remaining one-third of the underlying common stock exercisable at any time from and after August 3, 2008; provided, that Mr. McGarey’s employment has not been terminated by us for cause or by Mr. McGarey without good reason.

⁽⁶⁾ Includes options currently exercisable to purchase up to 1,730,000 shares of our common stock at an exercise price of $0.05 per share.

⁽⁷⁾ Includes options currently exercisable (i) to purchase up to 250,000 shares of our common stock at an exercise price of $0.05 per share and (ii) to purchase up to 150,000 shares of our common stock at an exercise price of $0.55 per share.

⁽⁸⁾ Represents 3,000,000 shares of our common stock underlying warrants exercisable at $0.50 per share granted to holder in connection with monies advanced to us, evidenced by a debenture in the principal amount of $1.7 million, bearing interest at 16% per annum, which debenture was repaid by us in full on April 12, 2007.

CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

We have agreed to pay Alan Gaines, one of our directors, a transaction bonus equal to 0.25% of the gross proceeds from the offering of the notes and the Convertible Subordinated Notes in connection with the financing of the DSX Acquisition.

Immediately prior to our merger with Coastal Energy Services, Inc. in April 2005, 47.3% of the then outstanding shares of our common stock were held by Mr. David Loev, an attorney residing in the State of Texas who performed legal services for us prior to our merger with Coastal. At no time was Mr. Loev an officer or a director of our Company. In November 2005, the SEC filed a civil lawsuit in the Houston Federal court against certain parties unrelated to our Company, and sued Mr. Loev for allegedly violating certain registration provisions of the Federal securities laws (SEC Litigation Release No. 19476; November 29, 2005). Mr. Loev settled the lawsuit with the SEC by consenting to the entry of an order permanently enjoining him from violating the securities registration provisions, ordering him to disgorge $25,785.50, plus interest, and imposing a $25,000 civil penalty.

DESCRIPTION OF CERTAIN INDEBTEDNESS

New Credit Agreement

Concurrently with the closing of this offering, we will to enter into the New Credit Agreement of which, pursuant to the terms of this offering, we will initially be able to borrow up to $20.0 million. Set forth below is a summary of the terms of the New Credit Agreement that will be in effect following the completion of this offering. Under the New Credit Agreement, we will be able to make borrowings based on a percentage of proved reserves. Interest will accrue on amounts outstanding under the New Credit Agreement at floating rates indexed to either the prime rate of interest in effect from time to time (plus a certain percentage in certain circumstances) or LIBOR plus a certain percentage based on the amount of availability under the New Credit Agreement. The New Credit Agreement will require us to pay certain customary fees, including upfront fees, servicing fees and unused facility fees.

All obligations under the New Credit Agreement will be secured by a first priority security interest in all of our assets subject to certain exemptions. The New Credit Agreement will contain customary covenants that will restrict our ability to, among other things:

• declare and pay dividends;

• prepay, redeem or purchase debt;

• incur liens;

• make loans and investments;

• make capital expenditures;

• incur additional indebtedness;

• engage in mergers, acquisitions and asset sales;

• enter into transactions with affiliates; and

• engage in businesses that are not related to our business.

The New Credit Agreement will also include financial covenants that, among other things, require us to maintain minimum availability under the revolving credit facility and maintain fixed charge coverage ratios. The New Credit Agreement will contain customary events of default, including, but not limited to:

• non-payment of principal, interest or fees;

• violations of certain covenants;

• certain bankruptcy-related events;

• inaccuracy of representations and warranties in any material respect; and

• cross defaults with certain other indebtedness and agreements.

We will be able to prepay amounts outstanding under the New Credit Agreement at any time.

The New Credit Agreement will allow all lenders in the facility (or their affiliates) to provide hedges to us and to share pro rata in all collateral and guaranties given under the New Credit Agreement. These will be the only “Credit Support Documents” for the hedges, and no hedge provider will be entitled to demand separate collateral or guaranties. The hedge agreements may contain cross-defaults to “Events of Default” under the New Credit Agreement (and vice versa), but all decisions on waiving events of default or amending the New Credit Agreement will be made by the lenders, and the hedge providers will be bound by lender decision without any direct or indirect veto right.

GLOSSARY OF OIL AND NATURAL GAS TERMS

We have included below the definitions for certain oil and natural gas terms used in this offering circular:

“3-D seismic” Geophysical data that depict the subsurface strata in three dimensions. 3-D seismic typically provides a more detailed and accurate interpretation of the subsurface strata than 2-D, or two dimensional, seismic.

“Bbl” One stock tank barrel, or 42 U.S. gallons liquid volume, used in this offering circular in reference to oil and other liquid hydrocarbons.

“Bbl/d” One Bbl per day.

“Bcf” One billion cubic feet of natural gas.

“Bcfe” One billion cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or NGLs.

“Boe” One Bbl of oil equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or NGLs.

“Boe/d” One Bbl of oil equivalent per day, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or NGLs.

“completion” The installation of permanent equipment for the production of oil or natural gas, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.

“developed acre” An acre spaced or assignable to a productive wells.

“development well” A well drilled with the proved area of an oil and gas reservoir to the depth of a stratigraphic horizon known to be productive.

“dry well” A well that is not a producing well.

“exploratory well” A well drilled to find and produce oil or gas in an unproved area, to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir, or to extend a known reservoir.

“farm-in” An agreement between a participant who brings a property into the venture and another participant who agrees to spend an agreed amount to explore and develop the property and has no right of reimbursement but may gain a vested interest in the venture. A “farm-in” describes the position of the participant who agrees to spend the agreed-upon sum of money to gain a vested interest in the venture.

“field” An area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same individual geological structural feature or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations.

“gross wells” Total number of producing wells in which we have an interest.

“lease operating expenses” The expenses, usually recurring, which pay for operating the wells and equipment on a producing lease.

“MBbl” One thousand barrels of oil or other liquid hydrocarbons.

“MBtu” One thousand British Thermal Units.

“Mcf” One thousand cubic feet of natural gas.

“Mcf/d” One Mcf per day.

“Mcfe” One thousand cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or NGLs.

“Mcfe/d” One Mcfe per day.

“MMBbl” One million barrels of oil or other liquid hydrocarbons.

“MMBtu” One million British Thermal Units.

“MMcf” One million cubic feet of natural gas.

“MMcfe” One million cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or NGLs.

“MMcfe/d” One MMcfe per day.

“net acre” Fractional ownership working interest multiplied by gross acres. The number of net acres is the sum of the fractional working interests owned in gross acres expressed as whole numbers and fractions thereof.

“net wells” The sum of our fractional interests owned in gross wells.

“NGLs” Natural gas liquids.

“NYMEX” The New York Mercantile Exchange.

“NYMEX PV-10” The estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development and abandonment costs, using NYMEX forward pricing as of August 29, 2007, before income taxes, and without giving effect to non-property related expenses, discounted to a present value using an annual discount rate of 10%.

“pay” The vertical thickness of an oil and natural gas producing zone. Pay can be measured as either gross pay, including non-productive zones or net pay, including only zones that appear to be productive based upon logs and test data.

“plugging and abandonment” Refers to the sealing off of fluids in the strata penetrated by a well so that the fluids from one stratum will not escape into another or to the surface. Regulations of many states require plugging of abandoned wells.

“proved reserves” Estimated quantities that geologic engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.

“productive wells” Producing wells and wells capable of production.

“producing well” A well found to be capable of producing either natural gas or oil in sufficient quantities to justify completion as a natural gas or oil well.

“PDP” Proved developed producing.

“PDNP” Proved developed non-producing.

“PUD” Proved undeveloped.

“PV-10” The estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development and abandonment costs, using flat May 31, 2007 pricing of $64.02/Bbl and $7.75/Mcf, before income taxes, and without giving effect to non-property related expenses, discounted to a present value using an annual discount rate of 10%.

“reserve life” A measure of the productive life of an oil and gas property or a group of properties, expressed in years.

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

“sand” A geological term for a formation beneath the surface of the earth from which hydrocarbons are produced. Its make-up is sufficiently homogenous to differentiate it from other formations.

“Successful Efforts” An accounting method whereby costs to acquire mineral interests in crude oil and natural gas properties, to drill and equip exploratory wells that find proved reserves and to drill and equip development wells are capitalized. Depreciation and depletion of producing oil and gas properties are provided under the unit-of-production method. Proved developed reserves are used to compute unit rates for unamortized tangible and intangible development costs, and proved reserves are used for unamortized leasehold costs. Upon sale or retirement of depreciable or depletable property, the cost and related accumulated depreciation, depletion and amortization (“DD&A”) are eliminated from the accounts and the resulting gain or loss is recognized. Repairs and maintenance are expensed as incurred. Exploratory expenses, including geological and geophysical costs and delay rentals, for unevaluated oil and gas properties are charged to expense as incurred. Costs to drill exploratory wells that do not find proved reserves are expensed as oil and gas exploration costs. The costs of an exploratory well will be carried as an asset if the well is found to have a sufficient quantity of reserves to justify its capitalization as a producing well and as long as the company is making sufficient progress assessing the reserves and the economic and operating viability of the project.

“Tcf” One trillion cubic feet of natural gas.

“undeveloped acreage” Lease acres on which wells have not been drilled or completed to a point that would permit production of commercial quantities of oil or natural gas, regardless of whether that acreage contains proved reserves, but does not include undrilled acreage held by production under the terms of a lease.

“working interest” The interest in an oil and natural gas property (normally a leasehold interest) that gives the owner the right to drill, produce and conduct operations on the property and a share of production, subject to all royalties, overriding royalties and other burdens and to all costs of exploration, development and operations and all risks in connection therewith.

INDEX TO FINANCIAL STATEMENTS

BASELINE OIL & GAS CORP.
Audited Financial Statements for the Years Ended December 31, 2005 and 2006 and the Period from June 29, 2004 (inception) through December 31, 2006
Report of Independent Registered Public Accounting Firm	F-2
Balance Sheet	F-3
Statements of Operations	F-4
Statements of Cash Flows	F-5
Statements of Changes in Stockholders’ Equity/(Deficit)	F-6
Notes to Financial Statements	F-7
Financial Statements for the Six Months Ended June 30, 2006 and 2007 (Unaudited)
Balance Sheets	F-17
Statements of Operations	F-19
Statements of Cash Flows	F-20
Notes to Financial Statements	F-21
DSX PROPERTIES
Financial Statements for the Years Ended December 31, 2005 and 2006 (Audited), and the Six Months Ended June 30, 2006 and 2007 (Unaudited)
Report of Independent Registered Public Accounting Firm	F-28
Statements of Combined Revenues and Direct Operating Expenses	F-29
Notes to Financial Statements	F-30

F-1

BASELINE OIL & GAS CORP.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors

Baseline Oil & Gas Corp.

(A Development Stage Company)

Houston, Texas

We have audited the accompanying balance sheet of Baseline Oil & Gas Corp. (“Baseline”) as of December 31, 2006, and the related statements of operations, cash flows and changes in stockholders’ equity (deficit) for the two year period then ended and for the period from June 29, 2004 (Inception) through December 31, 2006. These financial statements are the responsibility of Baseline’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Baseline, as of December 31, 2006, and the results of its operations and its cash flows for the periods described in conformity with accounting principles generally accepted in the United States of America.

/s/ MALONE & BAILEY, PC        

MALONE & BAILEY, PC

www.malone-bailey.com

Houston, Texas

April 12, 2007

F-2

BASELINE OIL & GAS CORP.

(A Development Stage Company)

Balance Sheet

	As of December 31, 2006
Assets
Cash and marketable securities	$	123,678
Prepaid and other current assets		125,000
Total current assets		248,678
Deferred debt issuance costs, net of amortization of $237,192		88,947
Deferred financing costs		99,631
Property acquisition—deposit		1,000,000
Unproven leasehold acquisition costs		7,810,135
Total assets	$	9,247,391
Liabilities & Stockholders’ Equity
Accounts payable	$	82,873
Other payables		50,029
Accrued liabilities		171,471
Derivative liability		104,896
Short term debt and current portion of long term debt, net of discount		1,948,001
Total current liabilities		2,357,270
Stockholders’ Equity
Common stock, $.001 par value, 140,000,000 shares authorized, 31,342,738 shares issued and outstanding		31,343
Additional paid-in-capital		28,423,418
Deficit accumulated during the development stage		(21,564,640	)
Total stockholders’ equity		6,890,121
Total liabilities & stockholders’ equity	$	9,247,391

See accompanying summary of accounting policies and notes to financial statements.

F-3

BASELINE OIL & GAS CORP.

(A Development Stage Company)

STATEMENTS OF OPERATIONS

Years Ended December 31, 2005 and 2006 and the Period from June 29, 2004 (Inception) through December 31, 2006

	Year Ended December 31, 2005		Year Ended December 31, 2006		Inception Through December 31, 2006
Selling, general and administrative	$	17,305,279	$	2,386,364	$	19,781,452
Interest (income)		—		(117,630)		(117,630)
Interest expense		392,565		1,691,788		2,085,197
(Gain) on derivative liability		—		(400,775)		(400,775)
Other expense		1,605		213,137		216,396
Total expense		17,699,449		3,772,884		21,564,640
Net loss	$	(17,699,449)	$	(3,772,884)	$	(21,564,640)
Basic and diluted loss per share	$	(1.20)	$	(0.11)
Weighted average common shares outstanding		14,777,299		33,989,119

See accompanying summary of accounting policies and notes to financial statements.

F-4

BASELINE OIL & GAS CORP.

(A Development Stage Company)

STATEMENTS OF CASH FLOWS

Years Ended December 31, 2005 and 2006 and the Period from June 29, 2004 (Inception) through December 31, 2006

	Year Ended December 31, 2005		Year Ended December 31, 2006		Inception Through December 31, 2006
Cash Flows From Operating Activities:
Net loss	$	(17,699,449)	$	(3,772,884)	$	(21,564,640)
Adjustments to reconcile net loss to cash used in operating activities:
Share based compensation		16,499,670		720,874		17,220,544
Unrealized gain on derivative liability		—		(400,775)		(400,775)
Amortization of debt discount		305,825		1,206,577		1,512,402
Stock issued as penalty for delayed registration		—		594,000		594,000
Stock issued in lieu of cash interest		—		187,500		187,500
Amortization of debt issuance costs		29,649		237,192		266,841
Changes in operating assets and liabilities:
Prepaid and other assets		—		(125,000)		(125,000)
Accounts payable and accruals		79,204		158,467		313,482
Net Cash Used in Operating Activities		(785,101)		(1,194,049)		(1,995,646)
Cash Flows From Investing Activities
Deposit on acquisition		—		(1,000,000)		(1,000,000)
Deferred acquisition costs		—		(99,631)		(99,631)
Property acquisition costs		(1,750,000)		(6,060,135)		(7,810,135)
Net Cash Flows Used in Investing Activities		(1,750,000)		(7,159,766)		(8,909,766)
Cash Flows From Financing Activities
Payment of note payable		—		(16,496)		(16,496)
Proceeds from sale of common stock, net		16,590		8,275,000		8,291,590
Proceeds from exercise of options		—		12,500		12,500
Proceeds from convertible notes		2,725,000		—		2,741,496
Net Cash Provided by Financing Activities		2,741,590		8,271,004		11,029,090
Net Change in Cash		206,489		(82,811)		123,678
Cash balance, beginning of period		—		206,489		—
Cash balance, end of period	$	206,489	$	123,678	$	123,678
Supplemental Disclosures:
Cash paid for interest	$	—	$	50,000	$	50,000
Cash paid for income taxes		—		—		—
Non-cash Investing and Financing Activities:
Warrants issued in connection with issuance of stock	$	—	$	505,671	$	505,671

See summary of significant accounting policies and notes to financial statements.

F-5

BASELINE OIL & GAS CORP.

(A Development Stage Company)

STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY/(DEFICIT)

For the Period from June 29, 2004 (Inception) through December 31, 2006

	Common					Additional Paid in Capital			Deficit Accumulated During the Development Stage			Totals
	Shares		Stock
Balances, June 29, 2004	—		$	—		$	—		$	—		$	—
Shares issued to founders at inception for $0.00 per share	200,000			200			(200	)		—			—
Net loss	—			—			—			(92,307	)		(92,307	)
Balances, December 31, 2004	200,000			200			(200	)		(92,307	)		(92,307	)
Proceeds from issuance of common stock	17,006,000			17,006			—			—			17,006
Debt discount related to shares issued with convertible notes	950,000			950			—			—			950
Shares issued in connection with merger	2,114,000			2,114			(3,480	)		—			(1,366	)
Stock based compensation	—			—			16,499,670			—			16,499,670
Debt discount	—			—			1,939,401			—			1,939,401
Debt issuance cost	—			—			355,788			—			355,788
Net loss	—			—			—			(17,699,449	)		(17,699,449	)
Balances, December 31, 2005	20,270,000			20,270			18,791,179			(17,791,756	)		1,019,693
Shares issued in connection with merger	12,069,250			12,069			1,194,856			—			1,206,925
Proceeds from issuance of common stock	8,181,818			8,182			8,991,818			—			9,000,000
Equity issuance costs	—			—			(1,230,671	)		—			(1,230,671	)
Shares issued on conversion of debt	1,820,000			1,820			357,289			—			359,109
Return of shares issued in connection with merger	(12,069,250	)		(12,069	)		(1,194,856	)		—			(1,206,925	)
Shares issued to pay interest	375,000			375			187,125			—			187,500
Shares based compensation	—			—			720,874			—			720,874
Shares issued as penalty for delayed
Registration	445,920			446			593,554			—			594,000
Option exercise	250,000			250			12,250			—			12,500
Net loss	—			—			—			(3,772,884	)		(3,772,884	)
Balances, December 31, 2006	31,342,738		$	31,343		$	28,423,418		$	(21,564,640	)	$	6,890,121

See accompanying summary of accounting policies and notes to financial statements.

F-6

BASELINE OIL & GAS CORP.

(A Development Stage Company)

NOTES TO FINANCIAL STATEMENTS

NOTE 1—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Nature of operations and organization

Baseline Oil & Gas Corp. (“Baseline” or the “Company”) is an independent exploration and production company, with operations presently focused in the Illinois Basin New Albany Shale play. Pursuant to a definitive purchase agreement and subject to the satisfaction of certain terms and conditions, on April 12, 2007 Baseline acquired significant oil and natural gas assets from Statex Petroleum I, L.P. and Charles W. Gleeson LP. Such assets consist of operated and non-operated working interests in leases located in Stephens County Texas, and approximately 81 gross producing oil and natural gas wells.

Use of Estimates

The preparation of these financial statements is in conformity with accounting principles generally accepted in the United States of America and requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amount of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Cash and Cash Equivalents

For purposes of the statement of cash flows, Baseline considers all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents. There were no cash equivalents as of December 31, 2006.

Properties and Equipment

The Company uses the successful efforts method of accounting for oil and gas producing activities. Under this method, acquisition costs for proved and unproved properties are capitalized when incurred. Exploration costs, including geological and geophysical costs, the costs of carrying and retaining unproved properties and exploratory dry hole drilling costs, are expensed. Development costs, including the costs to drill and equip development wells, and successful exploratory drilling costs to locate proved reserves are capitalized.

Exploratory drilling costs are capitalized when incurred pending the determination of whether a well has found proved reserves. A determination of whether a well has found proved reserves is made shortly after drilling is completed. The determination is based on a process that relies on interpretations of available geologic, geophysic, and engineering data. If a well is determined to be successful, the capitalized drilling costs will be reclassified as part of the cost of the well. If a well is determined to be unsuccessful, the capitalized drilling costs will be charged to expense in the period the determination is made. If an exploratory well requires a major capital expenditure before production can begin, the cost of drilling the exploratory well will continue to be carried as an asset pending determination of whether proved reserves have been found only as long as: i) the well has found a sufficient quantity of reserves to justify its completion as a producing well if the required capital expenditure is made and ii) drilling of the additional exploratory wells is under way or firmly planned for the near future. If drilling in the area is not under way or firmly planned, or if the well has not found a commercially producible quantity of reserves, the exploratory well is assumed to be impaired, and its costs are charged to expense.

In the absence of a determination as to whether the reserves that have been found can be classified as proved, the costs of drilling such an exploratory well is not carried as an asset for more than one year following completion of drilling. If, after that year has passed, a determination that proved reserves exist cannot be made,

F-7

BASELINE OIL & GAS CORP.

(A Development Stage Company)

NOTES TO FINANCIAL STATEMENTS—(Continued)

the well is assumed to be impaired, and its costs are charged to expense. Its costs can, however, continue to be capitalized if a sufficient quantity of reserves are discovered in the well to justify its completion as a producing well and sufficient progress is made in assessing the reserves and the well’s economic and operating feasibility.

The impairment of unamortized capital costs is measured at a lease level and is reduced to fair value if it is determined that the sum of expected future net cash flows is less than the net book value. The Company determines if impairment has occurred through either adverse changes or as a result of the annual review of all fields.

Development costs of proved oil and gas properties, including estimated dismantlement, restoration and abandonment costs and acquisition costs, are depreciated and depleted on a field basis by the units-of-production method using proved developed and proved reserves, respectively. The costs of unproved oil and gas properties are generally combined and impaired over a period that is based on the average holding period for such properties and the Company’s experience of successful drilling.

Investments in Oil and Gas Joint Ventures

The Company accounts for its investments in oil and gas joint ventures pursuant to the provisions of AICPA Accounting Interpretation No. 2 to APB No. 18. As such, the Company includes in its financial statements its pro rata share of the assets, liabilities, revenues, and expenses of the venture.

Loss Per Share

The basic net loss per common share is computed by dividing the net loss by the weighted average number of common shares outstanding. Diluted net loss per common share is computed by dividing the net loss adjusted on an “as if converted” basis, by the weighted average number of common shares outstanding plus potential dilutive securities. For the years ended December 31, 2006 and 2005, there were no dilutive securities outstanding.

Income Taxes

Baseline recognizes deferred tax assets and liabilities based on differences between the financial reporting and tax bases of assets and liabilities using the enacted tax rates and laws that are expected to be in effect when the differences are expected to be recovered. Baseline provides a valuation allowance for deferred tax assets for which it does not consider realization of such assets to be more likely than not.

Stock Compensation

On January 1, 2006, Baseline adopted SFAS No. 123 (R), “Share-Based Payment.” SFAS 123(R) replaced SFAS No. 123 and supersedes APB Opinion No. 25. SFAS 123(R) requires all share-based payments to employees, including grants of employee stock options, to be recognized in the financial statements based on their fair values. The pro forma disclosures previously permitted under SFAS 123 are no longer an alternative to financial statement recognition. Baseline adopted SFAS 123(R) using the modified prospective method which requires the application of the accounting standard as of January 1, 2006. The financial statements as of and for the year ended December 31, 2006 reflect the impact of adopting SFAS 123(R). In accordance with the modified prospective method, the financial statements for prior periods have not been restated to reflect, and do not include, the impact of SFAS 123(R).

F-8

BASELINE OIL & GAS CORP.

(A Development Stage Company)

NOTES TO FINANCIAL STATEMENTS—(Continued)

During the fiscal year ended December 31, 2005, Baseline granted 13,675,000 options to purchase common stock to employees. All options are currently vested, have a weighted average exercise price of $0.07 per share and expire 5 years from the date of grant. Baseline recorded compensation expense of $10,080,000 under the intrinsic value method during the fiscal year ended December 31, 2005.

The following table illustrates the effect on net loss and net loss per share if Baseline had applied the fair value provisions of FASB Statement No. 123, Accounting for Stock-Based Compensation, to stock-based employee compensation.

	Year Ended December 31, 2005
Net loss as reported	$	(17,699,449	)
Add: stock based compensation determined under intrinsic value based method		10,080,000
Less: stock based compensation determined under fair value based method		(10,874,173	)
Pro forma net loss	$	(18,493,622	)
Basic and diluted net loss per common share:
As reported	$	(1.20	)
Pro forma	$	(1.25	)

The weighted average fair value of the stock options granted during 2005 was $0.77. Variables used in the Black-Scholes option-pricing model include (1) a range of 3.9%—4.41% for the risk-free interest rate, (2) expected option life is the actual remaining life of the options as of each period end, (3) expected volatility was 274%—672%, and (4) zero expected dividends.

NOTE 2—INCOME TAXES

Deferred tax assets—NOLs	$	969,241
Less: valuation allowance		(969,241	)
Net deferred tax asset	$	—

Baseline has net operating loss carry-forwards of approximately $2,850,000 at December 31, 2006, which begin expiring in 2024.

NOTE 3—CONVERTIBLE NOTES

On April 6, 2005 (the effective date), Baseline acquired Coastal in exchange for 17,206,000 shares of Baseline common stock. Coastal was merged with and into Baseline with Baseline continuing as the surviving entity.

Upon the effective date of the Coastal merger, Baseline assumed the obligations with respect to $350,000 of convertible promissory notes. The notes, issued in April 2005, were convertible at any time into shares of Baseline’s common stock at a rate of $0.25 per share, accrued interest at the rate of 10% per annum and matured in April 2006 (twelve months from the date of issuance). Upon conversion, each holder of these convertible promissory notes is entitled to receive an additional number of shares equal to 20% of the face

F-9

BASELINE OIL & GAS CORP.

(A Development Stage Company)

NOTES TO FINANCIAL STATEMENTS—(Continued)

amount of the convertible promissory notes. The impact of these additional shares results in an effective conversion rate of $0.21 per share. Based on the effective conversion rate of $0.21 per share, Baseline has recognized a beneficial conversion feature on the notes of $231,401 which was recorded as a debt discount. The discount was amortized over the life of the notes. On April 6, 2006, holders of Baseline’s convertible promissory notes issued in April of 2005 in the aggregate principal amount of $350,000, converted all of such notes plus accrued interest into 1,820,000 shares of Baseline’s common stock.

During November of 2005, Baseline sold $2,375,000 in aggregate of its units. Each Unit consisted of (i) a $50,000 principal amount in an 18 month 10% convertible promissory note (“November Note”), and (ii) such number of shares of common stock equal to the quotient of (1) the aggregate principal amount of each Note purchased, multiplied by 20% and (2) $0.50. The notes are convertible at any time at a conversion price of $0.50 per share. Interest is payable in cash or shares (at the conversion price) at the option of the Company. Purchasers of the Units received in the aggregate 950,000 shares and, upon conversion of the Notes, will receive an additional 4,750,000 Shares. Each quarter Baseline pays interest of $59,380 to the holders in the form of $12,500 in cash and 93,750 shares of Baseline common. Baseline recorded a debt discount of $680,500 in connection with the initial issuance 950,000 shares based on the stock prices of $0.71 and $0.75 on the dates of issuance. Based on the effective conversion rate of $0.50, Baseline recognized a beneficial conversion feature of $1,027,500 as a debt discount on the additional 4,750,000 shares to be issued upon conversion of the principal amount of the note. The total discount, $1,708,000, is being amortized over the life of the November Note using the effective interest method. As of December 31, 2006, $1,281,001 of the discount had been amortized resulting in a net balance for the November Note of $1,948,001.

In connection with the note issuance, Baseline granted to Gilford Securities, the placement agent, a five year warrant to purchase 475,000 shares of Common Stock at an exercise of $0.50 per share.

Baseline evaluated the application of Statement of Financial Accounting Standard (“SFAS”) No. 133, “Accounting for Derivative Instruments and Hedging Activities” and Emerging Issues Task Force (“EITF”) 00-19, “Accounting for Derivative Financial Instruments Indexed to, and Potentially Settled in, a Company’s Own Stock” for the 10% convertible promissory notes and the warrants issued in connection with the note issuance. Based on the guidance of SFAS No. 133 and EITF 00-19, Baseline concluded that these instruments were not required to be accounted for as derivatives.

NOTE 4—ISSUANCE OF COMMON STOCK

On March 28, 2005, Baseline issued 17,006,000 shares as follows:

• 100,000 shares of common stock for services valued at $35,000 and is included in share based compensation; and

• 16,906,000 shares of common stock valued at $5,917,100 for cash proceeds of $16,590. The $5,900,194 of value in excess of the cash proceeds received has been charged to expense as share based compensation;

The services were provided by the founders in connection with non-specific research into oil and gas business opportunities. The value of the shares issued was determined by reference to the closing price of Baseline’s stock on the date of issuance.

On January 16, 2006, Baseline entered into a definitive Purchase Agreement (“Purchase Agreement”) to purchase certain assets from Rex Energy Operating Corp. (“Rex Energy”) and its affiliates (collectively the “Rex Parties”), and the 50% membership in the New Albany -Indiana, LLC (“New Albany”) that we did not already

F-10

BASELINE OIL & GAS CORP.

(A Development Stage Company)

NOTES TO FINANCIAL STATEMENTS—(Continued)

own. Concurrently with the execution of the Purchase Agreement, we entered into a Stock Agreement with certain individuals designated by Rex Energy, pursuant to which we issued a total of 12,069,250 common shares of our Common Stock valued at $1,206,925 or $0.10 per share. The issuance of such shares was subject to our right of first refusal to repurchase all such shares at a price $ 1.00 below any bona fide purchase offer for such shares made by a third party. We accounted for the aforementioned shares as a stock subscription receivable.

On June 8, 2006, Baseline entered into a Mutual Termination Agreement (“Termination Agreement”) and Mutual Release Agreement (“Release Agreement”) with the Rex Parties pursuant to which we and the Rex Parties mutually terminated (i) that certain purchase agreement between us dated January 16, 2006 and (ii) that certain stock agreement dated January 16, 2006 (as amended on March 10, 2006).

Pursuant to the termination agreement, the Rex Parties surrendered for cancellation of the aforementioned, 12,069,250 shares of our common stock, previously issued to them pursuant to the Stock Agreement. In connection with the surrender of these shares, the $1,206,925 of stock subscription receivable relating to the shares was eliminated as an adjustment to equity. After giving effect to the cancellation of such shares, we have 31,342,730 shares of common stock and options, warrants and convertible promissory notes to purchase up to an additional 19,562,840 shares of common stock outstanding as of December 31, 2006. Pursuant to the Release Agreement, we and the Rex Parties have agreed to release and hold each other harmless from all Claims stemming from Controversies (each as defined in the Release Agreement) arising out of our dealings with one another.

On February 1, 2006 Baseline completed a private placement of $9,000,000 by selling an aggregate of 8,181,818 shares of newly-issued Common Stock at $ 1.10 per share. As part of the transaction, Baseline issued warrants to the placement agents (“Placement Warrants”) to purchase an aggregate of 204,546 shares of Common Stock at an exercise price of $1.32 per share. These warrants have a three year term. Baseline agreed to register the resale of the shares of common stock issuable upon exercise of the Placement Warrants. Based on the guidance in SFAS 133 “Accounting for Derivative Instruments and Hedging Activities” and EITF 00-19 “Accounting for Derivative Financial Instruments Indexed to and Potentially Settled in a Company’s Own Stock”, Baseline concluded the Placement Warrants qualified for derivative accounting. Baseline determined the Placement Warrants had the attributes of a liability and therefore recorded the fair value of the Placement Warrants on day one as a current liability and a reduction of additional paid in capital as a cost of equity issuance. Baseline is required to record the unrealized changes in fair value in subsequent periods of the Placement Warrants as an adjustment to the current liability with unrealized changes in the fair value of the derivative reflected in the statement of operations as “(Gain)/loss on derivative liability.” The fair value of the Placement Warrants was $505,671 at February 1, 2006. The fair value of the Placement Warrants was determined utilizing the Black-Scholes stock option valuation model. The significant assumptions used in the valuation were: the exercise price as noted above; the market value of Baseline’s common stock on February 1, 2006, $2.50; expected volatility of 268%; risk free interest rate of approximately 4.54%; and a term of three years. The fair value of the Placement Warrants was $104,896 at December 31, 2006. The fair value of the Placement Warrants was determined utilizing the Black-Scholes stock option valuation model. The significant assumptions used in the valuation were: the exercise price as noted above; the market value of Baseline’s common stock on December 31, 2006, $0.761 expected volatility of 224%; risk free interest rate of approximately 4.82%; and a term of two years and four months. The resulting unrealized change in fair value of $400,775 from February 1, 2006 was recorded in the statement of operations as a gain on derivative liability.

On April 6, 2006, holders of Baseline’s convertible promissory notes issued in April of 2005 in the aggregate principal amount of $350,000, converted all of such notes into 1,820,000 shares of Baseline’s common stock.

On October 20, 2006, Baseline’s registration statement was declared effective.

F-11

BASELINE OIL & GAS CORP.

(A Development Stage Company)

NOTES TO FINANCIAL STATEMENTS—(Continued)

In November 2006, Baseline issued an aggregate of 445,920 shares of Common Stock with a value of $594,000 to investors in our February 2006 private offering. Such shares were issued as a result of Baseline’s failure to timely register the shares purchased in the private offering.

On November 15, 2006, Baseline issued an aggregate of 375,000 shares of Common Stock with a value of $187,500 to holders of November Notes in payment of accrued interest through November 15, 2006.

On November 16, 2006, Wayne Brannan exercised an option to purchase 250,000 shares of Common Stock at $0.05 per share. Baseline issued 250,000 shares to Mr. Brannan in exchange for $12,500.

NOTE 5—STOCK OPTION GRANTS

On April 1, 2005, Baseline granted a stock option to a non-employee consultant to purchase up to 500,000 shares of common stock at an exercise price of $0.30 per share. The option shall terminate no later than March 31, 2010 and may be exercised in whole or in part, at any time from and after October 1, 2005. The fair value of the option was $150,000 and has been fully expensed as share based compensation. As of the effective date of the Coastal merger noted above, see Note 3, the shares available in connection with the option converted into an equal number of Baseline shares.

On April 29, 2005, Baseline granted stock options to seven persons, five of which are company directors and/or officers and two of which are non-employees, to acquire up to 12,950,000 shares of Baseline’s common stock. The options are immediately exercisable at $0.05 per share and will expire on April 28, 2010. The options were granted as an inducement to retain management and for services rendered to Baseline. The intrinsic value of the options granted to the employees was $10,080,000 and has been expensed as share based compensation. The fair value of the options granted to the non-employees was $297,500 and has been expensed as share based compensation.

Mr. Alan Gaines (“Gaines”) and Mr. Barrie Damson (“Damson”), two of the seven persons mentioned above, have options which are cancelable under certain conditions. Specifically, the agreement with Rex Energy Operating Corp. (see Note 4) provides that each of Damson and Gaines, who presently each beneficially owns 5,894,250 shares of our outstanding Common Stock and options to acquire an additional 6,000,000 shares of Common Stock, will, upon the earlier to occur of

(i) the Closing Date or, (ii) if the Closing shall not have occurred as a result of the Baseline’s breach of a material provision of the Purchase Agreement, June 30, 2006, cancel such number of shares underlying their respective stock options, such that on such date, each of Messrs. Gaines and Damson shall beneficially own no more than 9.99% of the Company’s outstanding shares of Common Stock on a fully-diluted basis. As is discussed in Note 4, on June 8, 2006, Baseline terminated the Purchase Agreement with Rex Energy.

On December 20, 2005, Baseline issued to six Rex Management designees as described in stock options, exercisable for up to an aggregate of 50,000 shares of common stock at an exercise price of $1.00 per share. The options are fully vested, immediately exercisable and will expire on December 20, 2008.

On December 27, 2005, Baseline issued to Mr. Richard Cohen, CFO, a stock option, exercisable for up to 175,000 shares of common stock at an exercise price of $0.94 per share. The option is fully vested, immediately exercisable and will expire on December 26, 2010.

F-12

BASELINE OIL & GAS CORP.

(A Development Stage Company)

NOTES TO FINANCIAL STATEMENTS—(Continued)

During 2006, Baseline’s Board of Directors granted the following stock options, which are immediately exercisable with the exception of the options issued to Thomas Kaetzer as detailed below:

On August 15, 2006, Baseline granted a stock option to The Wall Street Group, a consultant, exercisable for up to 100,000 shares of Common Stock at an exercise price of $1.01 per share.

On October 20, 2006, Baseline granted a stock option to Carey Birmingham, its former president, exercisable for up to 75,000 shares of Common Stock at an exercise price of $0.50 per share.

On October 20, 2006, Baseline granted a stock option to David Loev, exercisable for up to 25,000 shares of Common Stock at an exercise price of $0.50 per share.

On November 14, 2006, Baseline granted a stock option to Masstar Inc., a consultant, exercisable for up to 360,000 shares of Common Stock at an exercise price of $0.50 per share.

On November 16, 2006, Wayne Brannan exercised an option to purchase 250,000 shares at $0.05 share.

On December 16, 2006, Baseline granted stock options to Thomas Kaetzer, then COO, now CEO, exercisable for up to 1,000,000, 500,000 and 500,000 shares of Common Stock exercisable at $0.50, $0.60 and $1.00 per share respectively. Mr. Kaetzer’s options vest in three equal parts on; 1) the date of grant, 2) the 1st anniversary the date of grant, and 3) 2nd anniversary of the date of grant. Coinciding with the issue of Mr. Kaetzer’s options, Messers Gaines and Damson agreed to cancel in aggregate options to purchase 2,000,000 shares with an exercise price of $0.05 per share.

The following table summarizes stock option activity:

	Options		Weighted Average Price
Outstanding as of January 1, 2004	—		$	—
Granted during 2004	—			—
Cancelled or expired	—			—
Exercised	—			—
Outstanding as of December 31, 2004	—			—
Granted during 2005	13,675,000		$	0.07
Cancelled or expired	—			—
Exercised	—			—
Outstanding as of December 31, 2005	13,675,000		$	0.07
Granted during 2006	2,560,000		$	0.64
Cancelled or expired	(2,000,000	)		0.05
Exercised	(250,000	)		0.05
Outstanding as of December 31, 2006	13,985,000		$	0.18
Exercisable as of December 31, 2006	13,985,000		$	0.18

Options Outstanding and exercisable at December 31, 2006:

Exercise Price	Number of Shares	Remaining Life	Exercisable Number of Shares
$0.05	10,700,000	3.3	10,700,000
$0.30	500,000	3.3	500,000
0.50—$1.01	2,785,000	4.8	1,451,667
	13,985,000		12,651,667

F-13

BASELINE OIL & GAS CORP.

(A Development Stage Company)

NOTES TO FINANCIAL STATEMENTS—(Continued)

NOTE 6—INVESTMENT IN JOINT VENTURE

On November 25, 2005, Baseline entered into a joint venture with Rex Energy, a privately held company, for the purpose of acquiring a working interest in certain leasehold interests located in the Illinois Basin, Indiana. The joint venture will be conducted through New Albany, a Delaware limited liability company. Pursuant to a Limited Liability Company Agreement, Baseline has a 50% economic/voting interest in New Albany and Rex Energy and its affiliates has a 50% economic/voting interest in New Albany. Rex Energy Wabash, LLC, an affiliate of Rex, is the Managing Member of New Albany and manages the day to day operations of New Albany.

On November 15, 2005, New Albany entered into a Purchase and Sale Agreement with Aurora Energy Ltd (“Aurora”), pursuant to which New Albany has agreed to purchase from Aurora an undivided 48.75% working interest (40.7% net revenue interest) in (i) certain oil, gas and mineral leases covering acreage in several counties in Indiana and (ii) all of Aurora’s rights under a certain Farmout and Participation Agreement with a third party (“Farmout Agreement”). In addition, at the closing of the transaction, New Albany was granted an option from Aurora, exercisable by New Albany for a period of eighteen (18) months thereafter, to acquire a fifty percent (50%) working interest in any and all acreage leased or acquired by Aurora or its affiliates within certain other counties located in Indiana, at a fixed price per acre.

On February 1, 2006, New Albany completed its acquisition of certain oil and gas leases and other rights from Aurora pursuant to the November 15, 2005 Purchase and Sale Agreement mentioned above. The total purchase price under the Aurora Purchase Agreement and the grant of the Aurora Option was $10,500,000 of which Baseline paid $5,250,000.

On February 28, 2006, New Albany acquired a 45% working interest (37.125% net revenue interest) in certain oil, gas and mineral leases covering approximately 21,000 acres of prospective New Albany Shale acreage in Knox and Sullivan Counties, Indiana. New Albany acquired its 45% working interest from Source Rock Resources, Inc., for a total consideration of $735,000 (of which Baseline paid half).

On July 21, 2006 Baseline transferred $88,714 to New Albany to fund the purchase of working interests in additional acreage acquired from Source Rock Resources, Inc.

On July 31, 2006 Baseline transferred $200,938 to New Albany to fund the purchase of working interests in additional acreage acquired from Aurora.

On October 26, 2006, Baseline transferred $680,643 to New Albany to fund its share of the pilot drilling program on the acreage acquired from Aurora and the acquisition of additional acreage from Source Rock Resources, Inc.

On November 8, 2006 Baseline transferred $250,105 to New Albany to fund its share of the pilot drilling program on the acreage acquired from Aurora.

On November 17, 2006 Baseline transferred $175,013 to New Albany to fund its share of the pilot drilling program on the acreage acquired from Aurora.

F-14

BASELINE OIL & GAS CORP.

(A Development Stage Company)

NOTES TO FINANCIAL STATEMENTS—(Continued)

NOTE 7—REGISTRATION STATEMENT-PENALTY INTEREST SHARES

As part of its Common Stock Offering in February 2006 (see Note 4), Baseline was subject to a Registration Rights Agreement requiring it to file a registration statement under the Securities Act by April 2, 2006. The company did not file by April 2, but did so on June 13, 2006. As a result, Baseline incurred a $540,000 penalty, which was paid by issuing 445,920 common shares in November 2006.

NOTE 8—SUBSEQUENT EVENTS

On December 20, 2006 Baseline Oil & Gas entered into a Purchase and Sale Agreement (“agreement”) with Statex Petroleum I, L.P. and Charles W Gleeson LP for a number of oil and gas producing properties in Stephens County in West Texas. The purchase price was $ 28,000,000 plus interest from January 15, 2007 until date of closing. Upon execution of the agreement we paid a $1,000,000 non-refundable deposit to be credited against the purchase price at the closing scheduled to take place on or before March 9, 2007. On March 9, 2007 we entered into an amendment to the agreement whereby for an additional deposit of $300,000 paid by March 16, 2007 the deadline to close on the purchase of the Stephens County assets was extended until April 16, 2007 and the effective date for the transfer of the assets was changed from December 1, 2006 to February 1, 2007. Baseline closed this acquisition on April 12, 2007.

On January 4, 2007, Baseline granted a stock option to Richard Cohen, CFO, exercisable for up to 100,000 shares of Common Stock at an exercise price of $0.56 per share.

On January 26, 2007 Barrie Damson our Chairman and CEO and Alan Gaines our Vice Chairman and a director each made a loan of $50,000 to the Company to be used for short term working capital needs. The loans, in the form of promissory notes, bear interest at an annual rate of 6% and mature on the earlier to occur of (i) the date on which we close a financing transaction in which we obtain proceeds in excess of $5,000,000 or (ii) July 26, 2007.

On February 15, 2007, Baseline issued an aggregate of 93,750 shares of Common Stock to holders of November Notes in payment of interest for the three months ended February 15, 2007.

On March 15, 2007 Baseline closed a private bridge financing whereby we borrowed $1,700,000 from a single accredited investor, Lakewood Capital (“Lakewood”). The Company issued to Lakewood a Senior Secured Debenture (“Debenture”) bearing interest at 16%, a common stock purchase warrant to purchase up to 3,000,000 shares of our common stock at an exercise price of $0.50 per share, and entered into a security agreement collateralized by the assets of the New Albany LLC. In addition we are required to pay Lakewood a closing fee of $170,000 on the date when the outstanding principal and accrued interest are paid. If Baseline consummates a debt or equity financing of $15,000,000 or more the Debenture must be paid in full. The proceeds from the Lakewood financing were used to pay the additional deposit of $300,000 on the Stephens County property, satisfy a capital call of $300,000 payable to Rex to maintain an interest in the New Albany LLC, pay existing payables on Stephens County, and pay a $170,000 fee to Casamir Capital, the placement agent. Additionally, The Company issued Casamir Capital a warrant exercisable for up to 340,000 shares of Common Stock at an exercise price of $0.50 per share. Concurrently with the closing of the Lakewood financing, Barrie Damson and Alan Gaines each cancelled stock options to purchase 1,670,000 shares of the company’s common stock at an exercise of $0.05.

F-15

BASELINE OIL & GAS CORP.

(A Development Stage Company)

NOTES TO FINANCIAL STATEMENTS—(Continued)

On March 16, 2007 we delivered $300,000 to New Albany-Indiana LLC (“New Albany”) to pay a portion of the outstanding capital calls that we, as a member of New Albany, were required to make. Pursuant to a Membership Interest Redemption Agreement between the Company and New Albany, we then redeemed our membership interest in the New Albany for the direct assignment to the Company of an undivided 40.423% working interest in and to all oil and gas properties, rights, and assets of New Albany. The New Albany assets have been pledged to Lakewood under a mortgage to secure the assets of Lakewood Debenture.

Effective March 21, 2007, Barrie Damson resigned as Chairman and CEO of Baseline Oil and Gas Corp. As a result of Mr. Damson’s departure, the Company appointed Mr. Thomas Kaetzer to fill the vacancy on the Board and promoted Mr. Kaetzer from President/COO to Chairman/CEO.

F-16

BASELINE OIL & GAS CORP.

BALANCE SHEETS

(Unaudited)

	December 31, 2006		June 30, 2007
Assets
Current Assets:
Cash and marketable securities	$	123,678	$	156,396
Cash-restricted		—		1,131,107
Accounts receivable, trade		—		1,175,289
Prepaid and other current assets		125,000		123,661
Total current assets		248,678		2,586,453
Oil And Natural Gas Properties—Using Successful Efforts Method Of Accounting
Proved properties		—		27,416,424
Unproved properties		7,810,135		8,092,302
Less accumulated depletion, depreciation and amortization		—		(514,580)
Oil and natural gas properties, net		7,810,135		34,994,146
Other Assets:
Deferred acquisition costs		99,631		—
Property acquisition—deposit		1,000,000		—
Deferred loan costs, net of accumulated amortization of $237,192 and $2,141,832, respectively		88,947		3,767,604
Other property and equipment, net of accumulated depreciation of $3,125 at June 30, 2007		—		37,635
Total other assets		1,188,578		3,805,239
Total Assets	$	9,247,391	$	41,385,838

The accompanying notes are an integral part of the financial statements.

F-17

BASELINE OIL & GAS CORP.

BALANCE SHEETS

(Unaudited)

	December 31, 2006		June 30, 2007
Liabilities And Stockholders’ Equity
Current Liabilities:
Accounts payable—trade	$	82,873	$	599,074
Accrued expenses		172,750		417,575
Royalties payable		—		508,440
Short term notes to related parties		—		100,000
Short term debt and current portion of long-term debt		1,996,751		2,257,450
Derivative liability—short term		104,896		956,463
Total current liabilities		2,357,270		4,839,002
Noncurrent Liabilities:
Long-term debt		—		30,218,224
Asset retirement obligations		—		450,779
Derivative liability—long term		—		834,490
Total noncurrent liabilities		—		31,503,493
Total liabilities		2,357,270		36,342,495
Commitments And Contingencies		—		—
Stockholders’ Equity
Common stock, $0.001 par value per share; 140,000,000 shares authorized; 31,342,738 and 32,210,238 shares issued and outstanding, respectively		31,343		32,211
Additional paid-in capital		28,423,418		31,629,156
Accumulated other comprehensive income		—		(1,691,686)
Accumulated deficit		(21,564,640)		(24,926,338)
Total stockholders’ equity		6,890,121		5,043,343
Total Liabilities And Stockholders’ Equity	$	9,247,391	$	41,385,838

The accompanying notes are an integral part of the financial statements.

F-18

BASELINE OIL & GAS CORP.

STATEMENTS OF OPERATIONS

Six Months Ended June 30, 2006 and June 30, 2007

(Unaudited)

	Six Months Ended June 30,
	2006		2007
Revenues:
Oil and gas sales	$	—	$	2,819,739
Operating Expenses:
Production		—		1,309,387
General and administrative		1,265,274		851,929
Depreciation, depletion and amortization		—		517,705
Accretion expense		—		12,332
Total operating expenses		1,265,274		2,691,353
Net income (loss) from operations		(1,265,274)		128,386
Other Income (expense):
Other income		—		23,366
Interest income		59,543		860
Interest expense		(764,257)		(3,519,939)
Unrealized gain on derivative instruments		333,677		5,629
Total other expense, net		(371,037)		(3,490,084)
Net Loss	$	(1,636,311)	$	(3,361,698)
Other Comprehensive Income (loss) Unrealized gain (loss) on derivative instruments		—		(1,691,686)
Total comprehensive loss	$	(1,636,311)	$	(5,053,384)
Net Loss Per Share—Basic and Diluted	$	(0.04)	$	(0.11)
Weighted Average Number Of Shares Outstanding—Basic And Diluted		37,440,583		31,514,831

The accompanying notes are an integral part of the financial statements.

F-19

BASELINE OIL & GAS CORP.

STATEMENTS OF CASH FLOWS

Six Months Ended June 30, 2006 and June 30, 2007

(Unaudited)

	Six Months Ended June 30,
	2006		2007
Cash Flows From Operating Activities
Net loss	$	(1,636,311)	$	(3,361,698)
Adjustments to reconcile net loss to net cash provided by operating activities:
Share based compensation		—		55,371
Common stock issued for consulting fees		—		150,000
Depreciation, depletion and amortization expense		—		517,705
Amortization of debt discount		118,596		426,999
Amortization of deferred loan costs		637,243		2,047,140
Derivative gain (loss)		(333,677)		(5,629)
Accretion expense		—		12,332
Changes in operating assets and liabilities:
Cash—restricted		—		(1,131,107)
Accounts receivable, trade		—		(1,175,289)
Prepaid and other current assets		(37,500)		101,050
Accounts payable—trade		(27,486)		516,201
Accrued liabilities		387,774		368,263
Royalties payable		—		508,440
Net cash used in operating activities		(891,361)		(970,222)
Cash Flows From Investing Activities
Acquisition of proved oil and gas properties		—		(28,195,001)
Development costs incurred		—		(361,345)
Additions to unproved properties		(4,664,723)		(282,167)
Purchase of property and equipment, other		—		(40,760)
Net cash used in investing activities		(4,664,723)		(28,879,273)
Cash Flows From Financing Activities
Proceeds from long-term debt		—		30,013,224
Proceeds from short term debt		—		1,700,000
Proceeds from short term notes to related parties		—		100,000
Repayments of short term debt		(16,496)		(1,761,011)
Proceeds from common stock sales, net		8,284,109		—
Deferred loan costs incurred		—		(170,000)
Net cash provided by financing activities		8,267,613		29,882,213
Net Increase In Cash And Cash Equivalents		2,711,529		32,718
Cash And Cash Equivalents, Beginning Of Period		206,489		123,678
Cash And Cash Equivalents, End Of Period	$	2,918,018	$	156,396
Supplemental Disclosures :
Cash paid for interest	$	—	$	474,641
Cash paid for income taxes		—		—
Non-cash Activities:
Unrealized gain/(loss) on derivative liability	$	333,677	$	(1,686,057)
Warrants issued in conjunction with debt		—		2,687,797
Stock issued for note extension		—		190,000
Asset retirement obligation incurred		—		400,298
Warrants issued in conjunction with stock issuance		505,671		—
Stock issued on conversion of debt		350,000		—
Stock issued in lieu of cash interest		—		93,750

The accompanying notes are an integral part of the financial statements.

F-20

BASELINE OIL & GAS CORP.

(A Development Stage Company)

NOTES TO FINANCIAL STATEMENTS

NOTE 1—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Nature of Operations and Organization

Baseline Oil & Gas Corp. (“Baseline” or the “Company”) is an independent exploration and production company primarily engaged in the acquisition, development, production and exploration of oil and natural gas properties onshore in the United States.

Basis of Presentation

The accompanying unaudited interim financial statements of Baseline have been prepared in accordance with accounting principles generally accepted in the United States of America and the rules of the Securities and Exchange Commission (the “SEC”), and should be read in conjunction with Baseline’s audited financial statements for the year ended December 31, 2006, and notes thereto, which are included in the Company’s annual report on Form 10-KSB filed with the SEC on April 17, 2007. In the opinion of management, all adjustments, consisting of normal recurring adjustments, necessary for a fair presentation of financial position and the results of operations for the interim periods presented have been reflected herein. The results of operations for interim periods are not necessarily indicative of the results to be expected for the full year. Notes to the financial statements, which would substantially duplicate the disclosure required in Baseline’s 2006 annual financial statements have been omitted.

Use of Estimates

The preparation of these financial statements is in conformity with accounting principles generally accepted in the United States of America and requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amount of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Oil and Natural Gas Properties

Baseline uses the successful efforts method of accounting for oil and gas producing activities. Costs to acquire mineral interests in oil and gas properties, to drill and equip exploratory wells that find proved reserves, to drill and equip development wells and related asset retirement costs are capitalized. Costs to drill exploratory wells that do not find proved reserves, geological and geophysical costs, and costs of carrying and retaining unproved properties are expensed.

Unproved oil and gas properties that are individually significant are periodically assessed for impairment of value, and a loss is recognized at the time of the impairment by providing an impairment allowance. Capitalized costs of producing oil and gas properties, after considering estimated residual salvage values, are depreciated and depleted by the unit-of-production method. Support equipment and other property and equipment are depreciated over their estimated useful lives.

On the sale or retirement of a complete unit of proved property, the cost and related accumulated depreciation, depletion, and amortization are eliminated from the property accounts, and the resultant gain or loss is recognized. On the retirement or sale of a partial unit of proved property, the cost is charged to accumulated depreciation, depletion, and amortization with a resulting gain or loss recognized in income.

F-21

BASELINE OIL & GAS CORP.

(A Development Stage Company)

NOTES TO FINANCIAL STATEMENTS—(Continued)

On the sale of an entire interest in an unproved property for cash or cash equivalent, gain or loss on the sale is recognized, taking into consideration the amount of any recorded impairment if the property had been assessed individually. If a partial interest in an unproved property is sold, the amount received is treated as a reduction of the cost of the interest retained.

Asset Retirement Obligations

The Company records a liability for legal obligations associated with the retirement of tangible long-lived assets in the period in which they are incurred in accordance with Statement of Financial Accounting Standards (“SFAS”) No. 143 “Accounting for Asset Retirement Obligations.” Under this method, when liabilities for dismantlement and abandonment costs, excluding salvage values, are initially recorded the carrying amount of the related oil and natural gas properties are increased. Accretion of the liability is recognized each period using the interest method of allocation, and the capitalized cost is depleted over the useful life of the related asset. Revisions to such estimates are recorded as adjustments to the ARO, capitalized asset retirement costs and charges to operations during the periods in which they become known. At the time the abandonment cost is incurred, the Company will be required to recognize a gain or loss if the actual costs do not equal the estimated costs included in ARO.

Revenue and Cost Recognition

The Company uses the sales method of accounting for natural gas and oil revenues. Under this method, revenues are recognized based on the actual volumes of gas and oil sold to purchasers. The volume sold may differ from the volumes to which the Company is entitled based on our interest in the properties. Costs associated with production are expensed in the period incurred.

NOTE 2—CONCENTRATION OF RISK

At June 30, 2007, Baseline’s cash in financial institutions exceeded the federally insured deposits limit by $1,087,503. Restricted cash in the amount of $1,131,107 represents cash in a bank account controlled by an administrative agent under a credit agreement (see NOTE 4).

NOTE 3—ACQUISITION OF NORTH TEXAS PROPERTIES

On April 12, 2007, Baseline acquired an interest in producing oil and gas properties from Statex Petroleum I, L.P. and Charles W. Gleeson LP. The properties consist of a 100% working interest in approximately 4,600 acres in Stephens County in North Texas (the “North Texas Assets”). The purchase price was $28,000,000, plus interest from January 15, 2007 until the date of closing and an adjustment for cash flow from the properties from the effective date until the date of closing. In addition, Baseline has capitalized $1,551,106 in costs associated with the transaction and $438,447 related to the asset retirement obligations associated with the properties. Upon execution of the Purchase and Sale Agreement Baseline paid a $1,000,000 non-refundable deposit to be credited against the purchase price. Baseline entered into an amendment to the agreement, whereby for an additional deposit of $300,000, the deadline to close on the purchase was extended. The effective date for the transfer of the assets was February 1, 2007. Baseline funded the adjusted purchase price, less the deposits previously paid, and a portion of the costs associated with the transaction through borrowings under a newly created credit agreement (see Note 4).

F-22

BASELINE OIL & GAS CORP.

(A Development Stage Company)

NOTES TO FINANCIAL STATEMENTS—(Continued)

NOTE 4—DEBT

Total debt at December 31, 2006 and June 30, 2007 consisted of the following:

	December 31, 2006		June 30, 2007
Short term notes to related parties	$	—	$	100,000
Other short term notes		48,750		87,450
Convertible notes, net of discount of $469,999 and $0		1,948,001		2,375,000
Term loans under credit agreement		—		20,300,000
Revolving loans under credit agreement		—		9,713,224
		1,996,751		32,575,674
Less short term debt and current portion of long-term debt		(1,996,751)		(2,357,450)
Long-term debt	$	—	$	30,218,224

Long-term Debt

On April 12, 2007, Baseline entered into a $75 million Credit Agreement (the “Credit Agreement”) with Drawbridge Special Opportunities Fund LP (“Drawbridge”), as Administrative Agent and various named lenders (the “Lenders”). The Credit Agreement provides for a revolving credit commitment of up to $54.7 million and a Term Loan Commitment of $20.3 million. Revolving Loans must be paid on or before April 12, 2010 and Term Loans on or before October 12, 2010. The Revolving Loans accrue interest at the Prime Rate and the Term Loans accrue interest at the Prime Rate or 7.5%, whichever is greater, plus 3%. Additionally, Baseline granted the Lenders an overriding royalty interest ranging between 2% and 3% in its existing oil and gas properties and any properties that it acquires while the Credit Agreement is in effect. The Credit Agreement requires Baseline’s revenues to be deposited into a lockbox account controlled by the Administrative agent. Funds in the lockbox account on the last business day of the month are utilized, in order of priority, to pay any amounts due for the overriding royalty interest granted under the Credit Agreement, amounts due to third parties under swap agreements, lease operating costs approved by the Administrative agent, interest due on the Term Loans and Revolving loans and general and administrative expenses up to $225,000 per quarter. Any amounts remaining in the lockbox account in excess of $250,000 are to be used to repay outstanding principal, to be applied first to the Term Loans. Baseline’s obligations under the Credit Agreement are secured by a first lien on all of its existing oil and gas properties, including the North Texas Assets, and any properties acquired while the Credit Agreement is in effect. On April 12, 2007 Baseline drew down $9.7 million as a Revolving Loan. In addition, Baseline drew down $20.3 million as a Term Loan. The funds were utilized to repay the bridge loan financing, including accrued interest and fees, and to fund the adjusted purchase price and a portion of the capitalized transaction costs for the acquisition of the North Texas Assets.

The Company recorded a discount of $2,678,000 related to the conveyance of the overriding royalty interest to the Lenders as discussed above. As of June 30, 2007, $44,633 of this discount has been amortized as a component of interest expense. This discount is being amortized over the expected term of the Credit Agreement using the effective interest method.

On May 30, 2007 holders of Baseline’s 10% convertible notes unanimously agreed to extend the maturity date of the notes from May 15, 2007 to November 15, 2007. As consideration for the extension of the notes, Baseline issued 380,000 shares in aggregate to the holders of the notes and increased the coupon rate on the notes from 10% to 12% per annum effective May 16, 2007.

F-23

BASELINE OIL & GAS CORP.

(A Development Stage Company)

NOTES TO FINANCIAL STATEMENTS—(Continued)

Bridge Loan Financing

On March 15, 2007, Baseline borrowed $1,700,000 from a single accredited investor, Lakewood Group, LLC (“Lakewood”). Baseline issued to Lakewood a Senior Secured Debenture (“Debenture”) bearing interest at 16%, a common stock purchase warrant to purchase up to 3,000,000 shares of Common Stock at an exercise price of $0.50 per share, and entered into a security agreement collateralized by the assets of Baseline. In addition Baseline was required to pay Lakewood a closing fee of $170,000 on April 12, 2007, when the outstanding principal and accrued interest were paid. The proceeds from the Lakewood financing were used to pay an additional deposit of $300,000 on the North Texas Assets (see NOTE 3), to partially satisfy a capital call in the New Albany-Indiana LLC (see NOTE 6), to pay expenses related to the ongoing financing and acquisition efforts, and to pay a $170,000 fee to Casimir Capital, the placement agent. Additionally, The Company issued Casimir Capital a warrant exercisable for up to 340,000 shares of Common Stock at an exercise price of $0.50 per share. On April 12, 2007, the Debenture was fully paid from proceeds received under the Credit Agreement.

Loans From Founders

On January 26, 2007, Barrie Damson our former Chairman and CEO and Alan Gaines our Vice Chairman and a director each made a loan of $50,000 to the Company to be used for short term working capital needs. The loans, in the form of promissory notes, bear interest at an annual rate of 6% and mature on the earlier to occur of the date on which Baseline closes a financing transaction in which it obtains proceeds in excess of $5,000,000 or July 26, 2007.

On April 10, 2007, Messrs. Gaines and Damson agreed to extend the maturity of their promissory notes to the earlier of October 10, 2010 or the date on which Baseline closes an equity offering in which it obtains gross proceeds in excess of $3,000,000.

NOTE 5—STOCKHOLDERS’ EQUITY

Common Stock

On March 31, 2007, Baseline issued an aggregate of 93,750 shares of common stock, with a value of $46,875, in payment of accrued interest through February 15, 2007, to holders of 10% convertible promissory notes issued by Baseline in privately negotiated transactions involving the offer and sale of $2.375 million in units consisting of such notes and Common Stock.

On May 15, 2007, Baseline issued an aggregate of 93,750 shares of common stock, with a value of $46,875, in payment of accrued interest through May 15, 2007, to holders of 10% convertible promissory notes issued by Baseline in privately negotiated transactions involving the offer and sale of $2.375 million in units consisting of such notes and Common Stock.

On May 30, 2007, Baseline issued 380,000 shares to holders of 10% convertible promissory notes in consideration of the holders’ agreement to extend the maturity of the notes by six months. Baseline’s 10% convertible notes will now mature on November 15, 2007. Such shares were valued at $190,000 which has been charged to interest expense.

On June 22, 2007, Baseline issued 300,000 shares to an outside consultant as compensation for services valued at $150,000.

F-24

BASELINE OIL & GAS CORP.

(A Development Stage Company)

NOTES TO FINANCIAL STATEMENTS—(Continued)

Stock Options and Warrants

On January 4, 2007, Baseline granted a five year stock option to Richard Cohen, CFO, exercisable for up to 100,000 shares of Common Stock at an exercise price of $0.56 per share. Such option had a fair value of $55,371.

On March 15, 2007, concurrently with the closing of the bridge loan financing (see NOTE 4), Alan Gaines, Baseline’s Vice-Chairman, and Barrie Damson, a former officer and director of Baseline, each cancelled stock options to purchase 1,670,000 shares of Baseline’s common stock at an exercise price of $0.05 per share.

In connection with our entry into the Credit Agreement, on April 12, 2007 we issued warrants to Drawbridge and D.B. Zwirn Special Opportunities Fund, L.P., another lender participating therein, which warrants are each exercisable for up to 1.6 million shares of our Common Stock, at an exercise price of $0.50 per share. Pursuant to certain warrant agreements executed with these two lenders, any unexercised warrants expire on April 11, 2014. The warrants also afford the holders certain anti-dilution protection. In connection with the issuance of the warrants we also entered into a registration rights agreement dated April 12, 2007 with each of the holders of the warrants, under which we granted piggy-back registration rights, demand registration rights and shelf registration rights to these holders. Such warrants had a fair value of $1,209,085 which has been capitalized as a deferred loan cost and is being amortized over the term of the Credit Agreement.

On April 12, 2007, concurrently with the execution of the Credit Agreement (see Note 4), Alan Gaines, our Vice Chairman, and Barrie Damson, a former officer and director of our Company, each surrendered additional stock options to purchase 1,670,000 shares of Common Stock at an exercise price of $0.05 per share, resulting in the cancellation of options for an aggregate of 3,340,000 shares of Common Stock.

NOTE 6—INVESTMENT IN JOINT VENTURE AND REDEMPTION OF MEMBERSHIP INTEREST

On March 16, 2007, Baseline paid $300,000 to New Albany-Indiana LLC (“New Albany”) to pay a portion of the outstanding capital calls that it, as a member of New Albany, was required to make. Pursuant to a Membership Interest Redemption Agreement between the Company and New Albany, Baseline then redeemed its membership interest in New Albany for the direct assignment to the Company of an undivided 40.423% working interest in and to all oil and gas properties, rights, and assets of New Albany. Such assets were then pledged to Lakewood under a mortgage to secure Lakewood’s Debenture.

The reduction in our membership interest of 50% to a 40.423% direct working interest reflected an adjustment of our membership interest in New Albany at the time of our redemption, as a result of outstanding capital calls owed by us but assumed by the affiliates and/or assigns of Rex Energy, the other joint venture partner.

After redeeming its membership interest in New Albany on March 16, 2007, Baseline now owns the following assets:

• 19.7% working interest in the Aurora/Wabash Area of Mutual Interest (AMI), consisting of approximately 122,000 gross acres (approximately 24,400 acres net to us), seven New Albany natural gas pilot wells (four horizontal and three vertical wells), one natural gas compression/treating facility, two salt water disposal wells, three Devonian Reef gas wells (5% working interest to us) and three horizontal wells currently scheduled to be drilled in 2007;

F-25

BASELINE OIL & GAS CORP.

(A Development Stage Company)

NOTES TO FINANCIAL STATEMENTS—(Continued)

• 18.2% working interest in the Rex Knox County AMI, consisting of approximately 41,000 total acres (approximately 7,380 acres net to us) acquired from Source Rock, and five horizontal wells currently scheduled to be drilled in 2007; and

• 6.9% working interest in the El Paso AMI, consisting of approximately 8,000 acres (560 acres net to us) and one horizontal well drilled in 2007.

NOTE 7—DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

On April 12, 2007, in accordance with a requirement of the Credit Agreement, Baseline also entered into a Swap Agreement (“Swap Agreement”) with Macquarie Bank Limited, which provides that Baseline puts in place, for each month through the third anniversary of April 12, 2007, separate swap hedges with respect to approximately 75% of the projected production from Proved Developed Producing Reserves. The swap hedges provide for a fixed price of $68.20 per barrel for a three year period, commencing June 1, 2007. The hedging arrangement is based upon a minimum of 11,000 barrels in the first year and provides for monthly settlements.

During July 2007, Baseline modified its hedge from a fixed price swap to a collar with a floor of $68.20 and a ceiling of $74.20 for the period from August 2007 through December 2008. Subsequent to December 2008 it reverts to a swap agreement at $68.20. In exchange for the near term switch from a fixed price swap to a collar, Baseline provided a right to the hedge provider to purchase 7,000 barrels per month at $73.20 per barrel from June 2010 through December 2011.

SFAS No. 133 “Accounting for Derivative Instruments and Hedging Activities” requires that all derivative instruments be recorded on the balance sheet at their fair value. Changes in the fair value of each derivative is recorded each period in current earnings or other comprehensive income, depending on whether the derivative is designated as part of a hedge transaction and, if it is, the type of hedge transaction. To make this determination, management formally documents the hedging relationship and its risk-management objective and strategy for undertaking the hedge, the hedging instrument, the item, the nature of the risk being hedged, how the hedging instrument’s effectiveness in offsetting the hedged risk will be assessed, and a description of the method of measuring effectiveness. This process includes linking all derivatives that are designated as cash-flow hedges to specific cash flows associated with assets and liabilities on the balance sheet or to specific forecasted transactions. Baseline also formally assesses, both at the hedge’s inception and on an ongoing basis, whether the derivatives that are used in hedging transactions are highly effective in offsetting cash flows of hedged items. A derivative that is highly effective and that is designated and qualifies as a cash-flow hedge has its changes in fair value recorded in other comprehensive income to the extent that the derivative is effective as a hedge. Any other changes determined to be ineffective do not qualify for cash-flow hedge accounting and are reported currently in earnings.

Baseline discontinues cash-flow hedge accounting when it is determined that the derivative is no longer effective in offsetting cash flows of the hedged item, the derivative expires or is sold, terminated, or exercised, the derivative is redesignated as a non-hedging instrument because it is unlikely that a forecasted transaction will occur, or management determines that designation of the derivative as a cash-flow hedge instrument is no longer appropriate. In situations in which cash-flow hedge accounting is discontinued, Baseline continues to carry the derivative at its fair value on the balance sheet and recognizes any subsequent changes in its fair value in earnings.

F-26

BASELINE OIL & GAS CORP.

(A Development Stage Company)

NOTES TO FINANCIAL STATEMENTS—(Continued)

When the criteria for cash-flow hedge accounting are not met, realized gains and losses (i.e., cash settlements) are recorded in other income and expense in the Statements of Operations. Similarly, changes in the fair value of the derivative instruments are recorded as unrealized gains or losses in the Statements of Operations. In contrast cash settlements for derivative instruments that qualify for hedge accounting are recorded as additions to or reductions of oil and gas revenues while changes in fair value of cash flow hedges are recognized, to the extent the hedge is effective, in other comprehensive income until the hedged item is recognized in earnings.

Based on the above, management has determined the swaps qualify for cash-flow hedge accounting treatment. For the period ended June 30, 2007, Baseline recognized a derivative liability of $1,691,686 with the change in fair value reflected in other comprehensive income/loss.

NOTE 8—SUBSEQUENT EVENTS

On July 3, 2007, Baseline issued 300,000 shares to a consultant for services rendered valued at $150,000.

On July, 5, 2007, non-employee option holders exercised options to purchase 200,000 shares of Common Stock at $0.05 per share on a “cashless” basis. As a result Baseline issued 185,714 shares.

On July 13, 2007, a consultant exercised an option to purchase 100,000 shares of Common Stock at $0.30 per share on a “cashless” basis. As a result, Baseline issued 56,522 shares.

During July 2007, holders of $150,000 of Baseline’s 10% Convertible Promissory Notes converted such notes into 301,676 shares.

On August 3, 2007, the Board of Directors (i) granted five-year options exercisable for up to an aggregate of 370,000 shares of common stock to several employees, which options vest in equal one-third installments on each of the first, second and third anniversary dates from the date of grant, (ii) granted a five-year stock option to Richard d’Abo, an outside director, exercisable for up to 150,000 shares of common stock and (iii) authorized the payment of a transaction bonus to Alan Gaines, our vice-chairman, in an amount equal to 0.25% of the gross proceeds raised by Baseline in its next debt and/or equity offering, if any. All such options are exercisable at $0.55 per share.

On August 3, 2007, the Company entered into a two year employment agreement with Mr Patrick McGarey to become Chief Financial Officer effective August 16, 2007. Mr McGarey succeeds Richard Cohen who will continue to serve through August 15, 2007. Concurrently with the entry into the employment agreement with Mr. McGarey, Baseline granted to Mr. McGarey five-year options, exercisable for (i) up to 500,000 shares of common stock, at an exercise price equal to $0.55, (ii) up to 500,000 shares, at an exercise price of $0.825 per share, and (iii) up to 500,000 shares, at an exercise price of $1.10 per share. Each option grant provides for the following vesting schedule: (i) 166,666 shares on August 3, 2007, (ii) 166,667 shares on August 3, 2008 and (iii) 166,667 shares on August 3, 2009, provided that Mr. McGarey remains in the employ of the Company through such dates.

F-27

THE DSX PROPERTIES

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors of Baseline Oil & Gas Corp.

Houston, Texas

We have audited the accompanying Statements of Combined Revenues and Direct Operating Expenses of the Oil and Gas Properties (“DSX Properties”) Purchased from DSX Energy Limited L.L.P. (the “Financial Statements”) for the years ended December 31, 2006 and 2005. These Financial Statements are the responsibility of Baseline Oil & Gas Corp.’s management. Our responsibility is to express an opinion on the Financial Statements based on our audits.

We conducted our audits in accordance with the auditing standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the Financial Statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the Financial Statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall Financial Statement presentation. We believe our audits provide a reasonable basis for our opinion.

The accompanying Financial Statements were prepared for the purpose of complying with the rules and regulations of the Securities and Exchange Commission as described in Note 2. The presentation is not intended to be a complete presentation of the properties described above.

In our opinion, the Financial Statements referred to above present fairly, in all material respects, the Combined Revenues and Direct Operating Expenses of the Oil and Gas Properties Purchased from DSX Energy Limited L.L.P. as described in Note 1 for the years ended December 31, 2006 and 2005, in conformity with U.S. generally accepted accounting principles.

/s/ Malone & Bailey, PC

Malone & Bailey, PC

www.malone-bailey.com

Houston, Texas

August 31, 2007

F-28

BASELINE OIL & GAS CORP.

STATEMENTS OF COMBINED REVENUES AND DIRECT OPERATING EXPENSES

of Oil and Gas Properties Purchased From

DSX Energy Limited L.L.P.

	For the Years Ended December 31,				For the Six Months Ended June 30,
	2005		2006		2006		2007
					(unaudited)		(unaudited)
Revenues	$	7,611,532	$	17,086,179	$	9,814,940	$	13,559,373
Direct operating expenses		3,051,276		2,162,328		1,032,183		1,796,132
Excess of revenues over direct operating expenses	$	4,560,256	$	14,923,851	$	8,782,757	$	11,763,241

The accompanying notes are an integral part of the financial statements.

F-29

BASELINE OIL & GAS CORP.

Statements of Combined Revenues and Direct Operating Expenses

of Oil and Gas Properties Purchased From

DSX Energy Limited L.L.P.

NOTES TO FINANCIAL STATEMENTS

(1) The Properties

On August 7, 2007, Baseline Oil & Gas, Corp. (“Baseline” or the “Company”) entered into a Purchase and Sale Agreement to purchase certain oil and gas properties (the “Properties”) owned by DSX Energy Limited L.L.P., Kebo Oil & Gas, Inc., Sanchez Oil & Gas Corp., Sue Ann Operating, L.L.C., and 23 other individuals, trusts and companies (collectively, the “Seller”) for $100,000,000.

(2) Basis For Presentation

The statements of combined revenues and direct operating expenses has been derived from the Seller’s historical financial records and is prepared on the accrual basis of accounting. Revenues and direct operating expenses as set forth in the accompanying statements include revenues from oil and gas production, net of royalties, and associated direct operating expenses related to the net revenue interests and net working interests, respectively. These revenues and expenses in the Properties represent Baseline’s acquired interest.

During the periods presented, the Properties were not accounted for or operated as a separate division of the Seller. Accordingly, full separate financial statements prepared in accordance with generally accepted accounting principles do not exist and are not practicable to obtain in these circumstances.

This statement varies from an income statement in that it does not show certain expenses, which were incurred in connection with the ownership of the Properties, such as general and administrative expenses and income taxes. These costs were not separately allocated to the Properties in the Seller’s historical financial records and any pro forma allocation would be both timing consuming and expensive and would not be a reliable estimate of what these costs would actually have been had the Properties been operated historically as a stand alone entity. In addition, these allocations, if made using the historical Seller general and administrative structures and tax burdens, would not produce allocations that would be indicative of the historical performance of the Properties had they been assets of Baseline, due to the greatly varying size, structure, and operations between Baseline and the Seller. This statement does not include provisions for depreciation, depletion and amortization as such amounts would not be indicative of future costs and those costs which would be incurred by Baseline upon allocation of purchase price. Accordingly, the financial statement and other information presented are not indicative of the financial condition or results of operations of the Properties going forward due to the changes in the business and the omission of various operating expenses.

For the same reason, primarily the lack of segregated or easily obtainable reliable data on asset values and related liabilities, a balance sheet is not presented for the Properties.

At the end of the economic life of the Properties, certain restoration and abandonment costs will be incurred by the respective owners of the Properties. No accrual for these costs is included in the direct operating expenses.

(3) Commitments and Contingencies

Baseline is not aware of any legal, environmental or other commitments or contingencies relating to the Properties that would have a material effect on the statement of combined revenues and direct operating expenses.

(4) Revenue Recognition

It is Baseline’s policy to recognize revenue when production is sold to a purchaser at a fixed or determinable price.

F-30

BASELINE OIL & GAS CORP.

Statements of Combined Revenues and Direct Operating Expenses

of Oil and Gas Properties Purchased From

DSX Energy Limited L.L.P.

NOTES TO FINANCIAL STATEMENTS—(Continued)

(5) Supplemental Oil and Gas Information (Unaudited)

General.

The estimated net proved oil and gas reserves and the present value of estimated cash flows from those reserves from the Properties acquired by Baseline are summarized below. The reserves were estimated by Cawley Gillespie & Associates (“Cawley”) in a report dated September 4, 2007 as of December 31, 2006. The reserve study was paid for by Baseline and was based on information provided by the Seller to Cawley. The December 31, 2006, reserve study was the only determination of proved reserves that is available, therefore, there will be no revisions of reserve estimates because no previous determination of estimates exists. Likewise there was no detail of extensions, discoveries and improved recovery for the periods below because there was no basis in which to determine when a discovery or extension was actually made.

Estimated Oil and Gas Reserve Quantities.

There was no determination of proven reserves at December 31, 2005. The only reserve study was done as of December 31, 2006. For the table below, the December 31, 2006 proved reserve total was adjusted for the actual production activity to determine what the proved reserves would have been at December 31, 2005 based on the reserve study as of December 31, 2006.

There are numerous uncertainties inherent in estimating quantities of proved reserves and projecting future rates of production. The following reserve data related to the Properties represent estimates only and should not be construed as being exact. The reliability of the estimates at any point in time depends on both quality and quantity of the technical and economic data, the performance of the reservoirs, as well as extensive engineering judgment. Consequently, reserve estimates are subject to revision as additional data becomes available during the producing life of a reservoir. The evolution of technology may also result in the application of improved recovery techniques, such as supplemental or enhanced recovery projects, which have the potential to increase reserves beyond those currently envisioned.

Estimates of proved reserves are derived from quantities of crude oil and natural gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing operating and economic conditions and rely upon a production plan and strategy.

Statement of Financial Accounting Standards No. 69, Disclosures About Oil and Gas Producing Activities (“FAS 69”), requires calculation of future net cash flows using a 10% annual discount factor and year-end prices, costs and statutory tax rates, except for known future changes such as contracted price and legislated tax rates.

All of the reserves relating to the Properties are located in the United States.

F-31

BASELINE OIL & GAS CORP.

Statements of Combined Revenues and Direct Operating Expenses

of Oil and Gas Properties Purchased From

DSX Energy Limited L.L.P.

NOTES TO FINANCIAL STATEMENTS—(Continued)

Estimated Oil and Gas Information:

	Oil     (MBbl)	Gas     (MMcf)	Oil     Equivalent     (MBoe)
Total Proved Reserves
Balance—December 31, 2005	492	11,523	2,413
Production	(92)	(1,458)	(335)
Purchases of reserve in-place	—	—	—
Extensions, discoveries and improved recovery	1,227	23,102	5,077
Transfers/sales of reserve in place	—	—	—
Revisions of previous estimates	—	—	—
Ending reserves—December 31, 2006	1,627	33,167	7,155
Proved developed reserves:	734	17,433	3,640
	Oil (MBbl)	Gas (MMcf)	Oil Equivalent (MBoe)
Total Proved Reserves
Balance—December 31, 2004	39	1,123	226
Production	(38)	(516)	(124)
Purchases of reserve in-place	—	—	—
Extensions, discoveries and improved recovery	491	10,916	2,310
Transfers/sales of reserve in place	—	—	—
Revisions of previous estimates	—	—	—
Balance—December 31, 2005	492	11,523	2,412
Proved developed reserves:	492	11,523	2,412

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves.

The following disclosures concerning the standardized measure of future cash flows from proved oil and gas reserves are presented in accordance with FAS 69. As prescribed by FAS 69, the amounts shown are based on prices and costs at the end of each period and a 10% annual discount factor.

Future cash flows are computed by applying fiscal year-end prices of natural gas and oil to year-end quantities of proved natural gas and oil reserves. Future operating expenses and development costs are computed primarily by the Company by estimating the expenditures to be incurred in developing and producing the Properties’ proved natural gas and oil reserves at the end of the year based on year end costs and assuming continuation of existing economic conditions. Future income taxes are based on currently enacted statutory rates.

F-32

BASELINE OIL & GAS CORP.

Statements of Combined Revenues and Direct Operating Expenses

of Oil and Gas Properties Purchased From

DSX Energy Limited L.L.P.

NOTES TO FINANCIAL STATEMENTS—(Continued)

The standardized measure of discounted future net cash flows is not intended to represent the replacement costs or fair value of the Properties’ natural gas and oil reserves. An estimate of fair value would take into account, among other things, anticipated future changes in prices and costs, and a discount factor more representative of the time value of money and the risks inherent in reserve estimates of natural gas and oil producing operations.

The standardized measure of discounted future net cash flows from the Company’s estimated proved gas reserves is provided for the financial statement user as a common base for comparing oil and gas reserves of enterprises in the industry and may not represent the fair market value of the Company’s oil and gas reserves or the present value of future cash flows of equivalent reserves due to various uncertainties inherent in making these estimates. Those factors include changes in oil and gas prices from year end prices used in the estimates, unanticipated changes in future production and development costs and other uncertainties in estimating quantities and present values of oil and gas reserves.

The Standardized Measure of Discounted Future Net Cash Flows relating to the Properties’ proved oil and gas reserves is as follows:

	December 2006
	(in thousands)
Future cash inflows	$	256,201
Future production costs		(36,046	)
Future development costs		(34,076	)
Future net cash flows before income taxes		186,079
Future income tax		(18,894	)
Future net cash flows		167,185
Discount at 10% annual rate		(79,694	)
Standardized measure of discounted future net cash flows	$	87,491

The principal changes in the standardized measure of discounted future net cash flows relating to proved oil and gas reserve are summarized below:

	Year Ended December 31, 2006
	(in thousands)
Standardized measure, beginning of year	$	90,336
Sales, net of production costs		(14,924	)
Net change in prices, net of production costs		(32,761	)
Extensions and discoveries		36,623
Development costs incurred		—
Accretion of discount, changes in production rates and other		7,954
Change in income tax		263
Revision of quantity estimates		—
End of year	$	87,491

F-33

Appendix A

SUMMARY REPORT OF

CAWLEY, GILLESPIE & ASSOCIATES, INC. — PETROLEUM ENGINEERS

REGARDING

RESERVE ESTIMATES FOR THE DSX PROPERTIES AND BASELINE OIL & GAS CORP.

EVALUATION SUMMARY

A-1

EVALUATION

BASELINE OIL & GAS INTERESTS

PROVED RESERVES

MATAGORDAAND STEPHENS COUNTIES, TEXAS

ASOF JUNE 1, 2007

CAWLEY, GILLESPIE & ASSOCIATES, INC.

PETROLEUM CONSULTANTS

ROBERT D. RAVNAAS, P.E.

EXECUTIVE VICE PRESIDENT

KENNETH J. MUELLER, P. E.

VICE PRESIDENT

A-2

Cawley, Gillespie & Associates, Inc.

PETROLEUMCONSULTANTS

9601 AMBERGLEN BLVD., SUITE 117 AUSTIN, TEXAS 78729-1106 512-249-7000 FAX 512-233-2618 306 WEST SEVENTH STREET, SUITE 302 FORT WORTH, TEXAS 76102-4987 817-336-2461 FAX 817-877-3728 www.cgaus.com 1000 LOUISIANA STREET, SUITE 625 HOUSTON, TEXAS 77002-5008 713-651-9944 FAX 713-651-9980

September 4, 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 Reserves

Matagorda and Stephens Counties, Texas

As of June 1, 2007

Dear Mr. Kaetzer:

As requested, we are submitting our estimates of proved 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 of the presented below:

		Strip Pricing
		Proved	Proved Developed Producing	Proved Developed Non-Producing	Proved Undeveloped
Net Reserves
Oil – Mbbl		5,861.3	3,099.6	747.0	2,014.7
Gas – MMcf		32,956.2	6,267.1	10,870.1	15,819.0
Net Revenue
Oil – M$		386,896.8	204,855.5	49,231.9	132,809.3
Gas – M$		256,953.3	48,982.3	79,963.7	128,007.3
Severance Taxes	–M$	37,068.7	13,097.0	8,261.9	15,709.8
Ad Valorem Taxes	–M$	18,521.9	6,846.6	3,848.5	7,826.9
Operating Expenses	–M$	158,056.9	108,589.5	23,472.5	25,994.9
Investments	–M$	41,659.0	1,348.0	4,315.0	35,996.0
Net Operating Income	–M$	388,543.5	123,956.7	89,297.8	175,289.0
Discounted @ 10%	–M$	213,595.7	78,138.9	33,090.6	102,366.2

A-3

		SEC Pricing
		Proved	Proved Developed Producing	Proved Developed Non-Producing	Proved Undeveloped
Net Reserves
Oil – Mbbl		5,783.2	3,027.2	745.6	2,010.4
Gas – MMcf		32,960.9	6,270.2	10,869.7	15,821.0
Net Revenue
Oil – M$		358,510.8	187,712.1	46,204.8	124,593.9
Gas – M$		262,171.3	50,099.2	83,099.6	128,972.6
Severance Taxes	–M$	36,154.3	12,392.2	8,357.9	15,404.3
Ad Valorem Taxes	–M$	17,934.3	6,442.0	3,865.2	7,627.1
Operating Expenses	–M$	153,468.4	104,332.9	23,385.9	25,749.7
Investments	–M$	41,659.0	1,348.0	4,315.0	35,996.0
Net Operating Income	–M$	371,466.0	113,296.3	89,380.4	168,789.3
Discounted @ 10%	–M$	203,520.8	72,835.4	32,465.0	98,220.4

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”).

Presentation

The report is divided into four reserve category sections: Proved (“I-Proved”), Proved Developed Producing (“I-PDP”), Proved Developed Non-Producing (“I-PDNP”) and Proved Undeveloped (“I-PUD”). Within each reserve category section are Tables I which present composite reserve estimates and economic forecasts for the particular reserve category. Following each of the Tables I within the Proved, PDP, PDNP, PUD and Probable sections 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. Also included within each of the four reserve category sections are composite Tables I for each area.

For a more detailed explanation of the report layout, please refer to the Table of Contents following this letter. The data presented in the composite Tables I 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, with details as provided in Attachment A, pages 4 and 5 of the Appendix:

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

A-4

Oil and gas prices were held flat for the SEC case at $64.02 per barrel and $7.745 per MMBtu throughout the life of each property. 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 werenot risked for any of the properties in this report.

Expenses and Taxes

As required by SEC criteria, 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 havenot 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 abandonmentand the cost of plugging at abandonment have been included for the Stephens County properties.

The proved reserve classifications used conform to the criteria of theSecurities and Exchange Commission (“SEC”) as defined in page 3 of the Appendix. 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.

A-5

TABLEOF CONTENTS

BASELINE OIL & GAS INTERESTS

PROVEDAND PROBABLE RESERVES

ASOF JUNE 1, 2007

REPORT LETTER

TABLEOF 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

PROVED DEVELOPED NON-PRODUCING RESERVES

• Table I – PDNP

• Table I – PDNP – Matagorda County

• Table I – PDNP – Stephens County

• Table II – PDNP

PROVED UNDEVELOPED RESERVES

• Table I – PUD

• Table I – PUD – Matagorda County

• Table I – PUD – Stephens County

• Table II – PUD

SEC 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

A-6

PROVED DEVELOPED NON-PRODUCING RESERVES

• Table I – PDNP

• Table I – PDNP – Matagorda County

• Table I – PDNP – Stephens County

• Table II – PDNP

PROVED UNDEVELOPED RESERVES

• Table I – PUD

• Table I – PUD – Matagorda County

• Table I – PUD – Stephens County

• Table II – PUD

APPENDIX

• Page 1 – Explanatory Comments for Summary Tables

• Page 2 – Methods Employed in the Estimation of Reserves

• Page 3 – Reserve Definitions and Classifications

• Page 4 – Attachment A – Strip Pricing

• Page 5 – Attachment A – SEC Pricing

A-7

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 orFiscal 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)	Averagegross wells.
(15)	Averagenet 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.

A-8

(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.

Cawley, Gillespie & Associates, Inc.

A-9

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 andmay 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.

A-10

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.

Cawley, Gillespie & Associates, Inc.

A-11

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.”

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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.

Cawley, Gillespie & Associates, Inc.

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ATTACHMENT A

Baseline Oil & Gas Interests

June 1, 2007 Reserve Report Pricing

	_______________________ Strip Price Case *
	Year	WTI Cushing Oil Price $/BBL	HH Spot Gas Price $/MMBTU
	2007	70.66	6.990
	2008	69.11	7.830
	2009	68.29	8.070
	2010	67.87	7.830
	2011	67.76	7.600
	2012	67.81	7.400
	Escalation	Flat	Flat
	Cap	67.81	7.400
* Strip prices provided by Baseline Oil & Gas

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ATTACHMENT A

Baseline Oil & Gas Interests

June 1, 2007 Reserve Report Pricing

_______________________     SEC Price Case *
	Year	WTI Cushing Oil Price $/BBL	HH Spot Gas Price $/MMBTU
	2007	64.02	7.745
	Escalation	Flat	Flat
	Cap	64.02	7.745
* SEC prices provided by Baseline Oil &Gas

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