UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2007

or

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from                      to                     

Commission file number 333-116890

BASELINE OIL & GAS CORP.

(Exact name of registrant as specified in its charter

Nevada	30-0226902
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
411 North Sam Houston Parkway East, Suite 300 Houston, Texas	77060
(Address of principal executive offices)	(Zip Code)

(281) 591-6100

Registrant’s telephone number, including area code

Securities registered pursuant to Section 12(b) of the Act: Common Stock, $0.001 par value

Securities registered pursuant to section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes  ¨    No  x

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.    Yes  ¨    No  x

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  x    No  ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K    x

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer  ¨	Accelerated filer  ¨	Non-accelerated filer  ¨	Smaller reporting company  x
		(Do not check if a smaller reporting company)

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).    Yes  ¨    No  x

As of June 30, 2007, the aggregate market value of the common stock of the registrant held by non-affiliates (excluding shares held by directors, officers and other holding more than 5% of the outstanding shares of the class) was $19,393,238, based upon a closing sale price of $0.66.

As of March 27, 2008, the registrant had outstanding 34,408,006 shares of common stock.

DOCUMENTS INCORPORATED BY REFERENCE

The information required by Part III will be incorporated by reference into this Form 10-K from the Registrant’s Definitive Proxy Statement to be filed pursuant to Regulation 14A within 120 days after the end of the Registrant’s fiscal year covered by this Form 10-K.

TABLE OF CONTENTS

Cautionary Notice Regarding Forward-Looking Statements	1
PART I
Item 1. and Item 2. Description of Business and Properties	2
Item 1A. Risk Factors	15
Item 3. Legal Proceedings	30
Item 4. Submission of Matters to a Vote of Security Holders of the Registrant	30
PART II
Item 5. Market for Registrant’s Common Stock, Related Shareholder Matters and Issuer Purchases of Equity Securities	31
Item 6. Omitted	33
Item 7. Management’s Discussion and Analysis or Plan of Operations of Financial Condition and Results of Operations	34
Item 8. Financial Statements	43
Item 9. Changes In and Disagreements With Accountants on Accounting and Financial Disclosure	43
Item 9A. Controls and Procedures	43
Item 9B. Other Information	46
PART III
Item 10. Directors, Executive Officers and Corporate Governance; Compliance with Section 16(a) of the Exchange Act
Item 11. Executive Compensation
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters
Item 13. Certain Relationships and Related Transactions, and Director Independence
Item 14. Principal Accountant Fees and Services
PART IV
Item 15. Exhibits and Financial Statement Schedules	47
Form of Global 12 1/2% Senior Secured Exchange Note due 2012
Office Lease
Code of Conduct and Ethics
Consent of Cawley, Gillespie & Associates, Inc. independent petroleum engineers
Certification of CEO Pursuant to Section 302
Certification of CFO Pursuant to Section 302
Certification of CEO Pursuant to Section 906
Certification of CFO Pursuant to Section 906
Summary of Reserve Report

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Cautionary Notice Regarding Forward Looking Statements

Baseline Oil & Gas Corp. desires to take advantage of the “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995. This report contains a number of forward-looking statements that reflect management's current views and expectations with respect to business, strategies, future results and events and financial performance. All statements made in this Annual Report other than statements of historical fact, including statements that address operating performance, events or developments that management expects or anticipates will or may occur in the future, including statements related to revenues, cash flow, profitability, adequacy of funds from operations, statements expressing general optimism about future operating results and non-historical information, are forward looking statements. In particular, the words “believe,” “expect,” “intend,” “anticipate,” “estimate,” “may,” “will,” variations of such words, and similar expressions identify forward-looking statements, but are not the exclusive means of identifying such statements and their absence does not mean that the statement is not forward-looking.

Readers should not place undue reliance on these forward-looking statements, which are based on management’s current expectations and projections about future events, are not guarantees of future performance, are subject to risks, uncertainties and assumptions and apply only as of the date of this report. Baseline’s actual results, performance or achievements could differ materially from the results expressed in, or implied by, these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, those discussed below in “Risk Factors” as well as those discussed elsewhere in this report, and the risks discussed in press releases and other communications to stockholders issued by Baseline from time to time which attempt to advise interested parties of the risks and factors that may affect the business. Except as may be required under the federal securities laws, Baseline undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

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PART I

Items 1 and 2.    Business and Properties.

Company Overview

Baseline Oil & Gas Corp., (“Baseline”, the “Company” or “we”) is 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 following three core areas: (i) the Eliasville Field located in Stephens County in North Texas (the “Eliasville Field Properties”); (ii) the Blessing Field in Matagorda County located onshore along the Texas Gulf Coast (the “Blessing Field Properties”); and (iii) the New Albany Shale play located in Southern Indiana (the “New Albany Shale play”). Our core properties cover approximately 39,945 net acres across the areas identified above.

As of December 31, 2007, based on the reserve report prepared by Cawley, Gillespie & Associates, Inc., independent petroleum engineers (“CG&A” and the “CG&A Reserve Report”), our proved reserves were 69.7 Bcfe, of which 46.3% were natural gas and 60.2% were proved developed. The SEC PV-10 of these proved reserves as of that date was $283.7 million. During 2007, we purchased 67.7 Bcfe, added 3.3 Bcfe through extensions, discoveries, additions and revisions and produced 1.2 Bcfe.

Our Business Strategy

The following are key elements of our business strategy:

Continue Exploiting Our Reserves. We have a number of opportunities to increase production and develop our reserve base through infill and step-out drilling of new wells, workovers targeting proved reserves, stimulating existing wells and the expansion of enhanced oil recovery projects such as waterflood operations. The 34 drilling locations currently classified as proved undeveloped reserves include 20 wells required to continue to develop and extend existing waterflood operations on our Eliasville Field Properties and 14 infill and step-out wells on the Blessing Field Properties. We plan to investigate the application of alkaline surfactant polymer flooding techniques at our Eliasville Field Properties to potentially recover significant incremental oil reserves, and are currently planning a pilot project for 2008. On the Blessing Field Properties, we expect to complete an evaluation of the shallower Frio formation which could potentially result in a new drilling program to exploit the shallower reserve potential of the field. In addition, we have 40 proved workover locations on the Blessing Field Properties that we plan to evaluate and execute over the life of the field

Actively Manage Our Asset Base. We operate 100% and own in excess of 95% of the wells that comprise our PV-10, enabling 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. This high working interest and operatorship is critical as it allows us to better control the technology applied, the timing of operations and the costs of drilling and production activities. We intend to continue 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 modern 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. We believe our use of these technologies will enhance the probability of locating and producing reserves that might not otherwise be discovered.

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

Conduct Selective Exploratory Activities. 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.

2008 Budget. For 2008 we have adopted a capital budget of $19.9 million primarily focused on development drilling within our existing fields located in Texas at the Eliasville Field and Blessing Field Properties. We anticipate the 2008 budget will allow us to move approximately 14.3 Bcfe of currently booked PUD reserves to the PDP classification, through the drilling of 12 wells at Eliasville and 6 wells at Blessing.

Employees

As of March 27, 2008, we had 15 full time employees and 2 contract employees. We are not a party to any collective bargaining agreements and have not experienced any strikes or work stoppages. We believe our relationships with our employees are good. From time to time, we utilize the services of independent contractors to perform various field and other services.

Offices

Our headquarters are located at 411 North Sam Houston Parkway East, Suite 300, Houston, Texas 77060. Our telephone number is (281) 591-6100.

Our Properties and Core Areas of Operation

As of December 31, 2007, 42.0% of our proved reserves were located in the Eliasville Field Properties and 58.0% in the Blessing Field Properties. We acquired all of our current proved reserves during 2007, including (i) the Blessing Fields Properties on October 1, 2007, consisting of those wells and properties located on 2,374 net acres located onshore along the Texas Gulf Coast and (ii) the Eliasville Fields Properties on April 12, 2007, consisting of those wells and properties located on 5,231 net acres in North Texas. On March 16, 2007, we converted a prior membership interest in a joint venture into a direct working interest in approximately 171,000 gross acres (32,340 net acres) in the Illinois Basin located in Southern Indiana known to contain the New Albany Shale formation.

Our proved reserves are primarily long-life crude oil located in the Eliasville Field and natural gas and condensate located in the Blessing Field. 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 and around these fields. 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. The majority of our proved reserve base is classified as proved developed nonproducing and proved undeveloped reserves. We have identified a large base of workovers and drilling locations targeting proved reserves on our two Texas properties, of which we intend to complete approximately 20 to 25 workovers and drill approximately 18 wells by the end of 2008.

Our New Albany Shale play 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 which brings significant regional expertise and financial and operational resources.

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We participated in the drilling of 14 (gross) wells during 2007 and performed 20 workovers on existing wells. Of the 14 wells drilled, 6 were development wells located in our two operated Texas fields and 8 were non-operated exploratory wells drilled in the New Albany Shale play. All of the workovers were performed on wells in our two Texas fields.

Set forth below is a description of our three core areas of operation and those activities completed in 2007 and currently planned for 2008:

Blessing Field Properties.

On October 1, 2007, we acquired, effective as of June 1, 2007, a working interest of over 95% in the Blessing Field Properties located onshore along the Texas Gulf Coast for an adjusted purchase price of $96.6 million. We operate 100% of the wells on these properties. Currently this field is producing 220 bopd and 4,450 mcfd gross, for a net rate of approximately 4,270 mcfepd.

Proved net reserves on the Blessing Field Properties have been estimated in the CG&A Report to be 40.4 Bcfe with a pre-tax PV-10 value of $ 156.6 million based on year-end SEC pricing. Of the proved reserves, 15.0% are proved developed producing, or PDP, 33.7% are proved developed non-producing, or PDNP, and 51.3% are proved undeveloped, or PUD, reserves.

The Blessing Field 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. 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 this proprietary 3D seismic survey, 13 wells have successfully been drilled to date, for a reported 100% success rate. Production in 5 separate fault blocks has been established, with proved and probable reserves identified in 21 different sands.

We drilled our first new well in this field and also performed five workovers during 2007, all in the fourth quarter. The Nelson E. Blessing Unit No. 1 (f/k/a East Blessing Unit No. 3) was drilled to 12,000 feet and was producing natural gas and condensate by late December. The five workovers that we performed at Blessing were on producing wells which had begun to encounter reduced rates and downhole mechanical problems during the third quarter of 2007 prior to our acquisition of the Blessing Field Properties. The workovers involved cleaning out perforations, removing fill from the wellbores and running several tubing strings. These wells were successfully restored to previous rates by year-end. Currently we plan to perform 7 workovers during 2008, all related to enhancing and stabilizing production from currently completed pay intervals. This activity is anticipated to be initiated during the first quarter of the year. Likewise, we have budgeted for the drilling of 6 proved undeveloped wells during 2008, beginning early in the second quarter.

Eliasville Field Properties.

On April 12, 2007, we acquired a 100% working interest in 5,231 net acres in the Eliasville Field located in Stephens County in North Texas, roughly 90 miles west of Fort Worth, Texas. The effective date of the transaction was February 1, 2007 and we paid an adjusted purchase price of $27.05 million. 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 680 bopd and 100 mcfpd gross, for a net rate of approximately 3.3 MMcfepd of production. There are 82 oil wells producing in the field, and a portion of it is operated as an active waterflood with 56 injection wells. There are 8 leases, 2 central operating facilities and 3 tank batteries.

Proved net reserves have been estimated in the CG&A Reserve Report to be 29.3 Bcfe with a pre-tax PV-10 value of $127.1 million, based on year-end SEC pricing. Of the proved reserves, 68.1% are PDP, 8.0% PDNP and 23.9% are PUD reserves.

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We successfully drilled 5 proved undeveloped wells to the Caddo formation at 3,350 feet during the fourth quarter of 2007. Three of the wells were on production by the end of December, and the last 2 were put on production during February 2008. The average daily rate for each new well has been approximately 32 bopd (8/8ths). In addition to drilling new wells, we also performed workovers on 15 low-rate or idle wells during 2007. Twelve of these workovers were on oil wells, which were either returned to production, or on which perforations were added and/or stimulation was performed. Three of the workovers involved the conversion of previously idle oil wells to waterflood injection well completions. The added injection wells are an initial step of a planned expansion of waterflood operations to the western leases owned by us in this field. The current field productions rate has increased to 680 bopd from 620 bopd in early October 2007.

We have identified 20 proved undeveloped locations, of which we have budgeted to drill 12 during 2008. We expect to drill the first 5 of these wells in sequence during the second quarter of 2008. We also anticipate performing approximately 18 workovers during 2008, with similar characteristics to the successful 2007 workover program.

The 20 proved undeveloped drilling locations noted above were identified based on initial in-house geological and infill drilling studies of the field. We are now performing an expanded field-wide study, aided by a third party engineering/geological firm, to further define the waterflood expansion and development potential of the field. This study is expected to be finished during the second quarter of 2008. In addition to defining additional development and expansion opportunities across the entire field, this work will also provide information required for the planned implementation of an alkaline surfactant polyment pilot flood. The field work for this pilot project should begin by the fourth quarter of 2008.

New Albany Shale play.

We own a direct working non-operating interest in leasehold interests covering approximately 171,000 gross (32,340 net) surface acres in the Illinois Basin located in Southern Indiana and known to overlay the New Albany Shale formation. Our total average working interest is approximately 18.5%, and our acreage is grouped into three separate areas of mutual interest, or AMI’s, 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 (“Wabash AMI”);

• 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 (“Knox AMI”); 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 a brownish-black shale exposed along the Ohio River at New Albany in Floyd County, Indiana, and 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 active production or proved reserves booked to our acreage position. We presently consider the acreage contained in our Knox AMI to be highly prospective, as it lies between active producing projects owned by Noble Energy to the north (southern Sullivan County) and El Paso to the southeast (Knox and Davies Counties).

During 2007, we participated with our partners in the drilling of 8 horizontal wells in the New Albany Shale play. Four of these wells were located in the Wabash AMI of Greene County, Indiana and four were located in

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the Knox County (Indiana) AMI. All 8 of these wells tested gas and initial water. The wells next need to be completed with a downhole pump and tested. A low pressure gathering system also needs to be installed to gather the gas to a common sales point.

We expect to spend approximately $2 million during 2008 in connection with the New Albany Shale play. Activities will initially include installing a low pressure gas gathering and compression system and completing, testing and producing the 8 recently drilled wells in Greene and Knox Counties, Indiana. We also expect to participate with our partners in the drilling and coring of 3 vertical wells and the drilling of 3 to 5 new horizontal wells. Currently, we are working with our partners in planning activity for 2008, with field work expected to start during the second quarter of 2008. Drilling is forecasted to be done in the third and fourth quarters of 2008, after data from the cores and existing wells is evaluated.

Our position currently includes ownership in 15 New Albany Shale wells, 3 Devonian gas wells and 2 salt water disposal wells.

Natural Gas and Oil 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 Securities and Exchange Commission (“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 reserves does not include 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 prices utilized for the purpose of estimating our proved reserves and the present value of proved reserves as of December 31, 2007 were a WTI Cushing spot price of $96.01 per Bbl and a Henry Hub spot natural gas price of $7.465 per MMBtu, adjusted by property for energy content, quality, transportation fees, and regional price differentials.

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The following table sets forth our estimated net proved oil and natural gas reserves and the PV-10 value of such reserves as of December 31, 2007. The reserve data and the present value as of December 31, 2007 were prepared by Cawley, Gillespie & Associates, Inc., independent petroleum engineers. For further information concerning our independent engineer’s estimates of our proved reserves as of December 31, 2007, see the reserve report filed as Exhibit 99.1 to this Annual Report on Form 10-K. The PV-10 value is not intended to represent the current market value of the estimated oil and natural gas reserves owned by us. For further information concerning the present value of future net revenues from these proved reserves, see Note 11 of Notes to Consolidated Financial Statements.

	Oil	Natural Gas	Undiscounted Future Net Revenue	Present Value of Proved Reserves Discounted at 10% (1)
	(Mbbl)	(MMcf)	($ thousands)	($ thousands)
Developed Producing	3,462.6	5,254.3	199,027	103,621
Developed Nonproducing	738.9	11,536.3	117,341	43,467
Proved Undeveloped	2,038.3	15,506.3	226,619	136,593
Total Proved	6,239.8	32,296.9	542,987	283,680

(1) Management believes that the presentation of PV-10 may be considered a non-GAAP financial measure as defined in Item 10(e) of Regulation S-K. Therefore we have included a reconciliation of the measure to the most directly comparable GAAP financial measure (standardized measure of discounted future net cash flows in the table immediately below). Management believes that the presentation of PV-10 value provides useful information to investors because it is widely used by professional analysts and sophisticated investors in evaluating oil and gas companies. Because many factors that are unique to each individual company may impact the amount of future income taxes to be paid, the use of the pre-tax measure provides greater comparability when evaluating companies. It is relevant and useful to investors for evaluating the relative monetary significance of our natural gas and oil properties. Further, investors may utilize the measure as a basis for comparison of the relative size and value of our reserves to other companies. Management also uses this pre-tax measure when assessing the potential return on investment related to its oil and gas properties and in evaluating acquisition candidates. The PV-10 value is not a measure of financial or operating performance under GAAP, nor is it intended to represent the current market value of the estimated oil and natural gas reserves owned by us. PV-10 should not be considered in isolation or as a substitute for the standardized measure of discounted future net cash flows as defined under GAAP.

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

	As of December 31, 2007
	(dollars in thousands)
PV-10	$	283,680
Future income taxes, discounted at 10%		(73,068	)
Standardized measure of discounted future net cash flows	$	210,612

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Oil and Natural Gas Volumes, Prices and Operating Expense

The table below sets forth certain information regarding the production volumes, revenue, average prices received and average production costs associated with our sale of oil and natural gas for the year ended December 31, 2007. Prior to 2007, we had no operating assets other than an indirect interest in the New Albany Shale play by virtue of our membership interest in a joint venture acquiring and holding working leasehold interests in leasehold acreage located in Southern Indiana. We redeemed our membership interest for a direct assignment of a working interest in certain oil and gas properties, rights and assets of the joint venture on March 16, 2007. As indicated elsewhere in this Annual Report, we acquired our additional operating assets located in north Texas and the Texas gulf coast in April and October 2007, respectively.

	Year Ended December 31, 2007
Net Production:
Oil (Bbl)		149,318.9
Natural Gas (Mcf)		335,533.2
Natural Gas Equivalent (Mcfe)		1,231,446.8
Oil and Natural Gas Sales (dollars in thousands):
Oil	$	11,511.5
Natural Gas		2,459.1
Total		13,970.6
Average Sales Price:
Oil ($ per Bbl)	$	77.09
Natural Gas ($ per Mcf)		7.33
Natural Gas Equivalent ($ per Mcfe)	$	11.35
Oil and Natural Gas Costs (dollars in thousands):
Lease operating expenses	$	4,190.0
Production taxes		958.4
Total		5,148.4
Average production cost per Mcfe	$	4.18

Exploration, Development and Acquisition Capital Expenditures

The following table sets forth certain information regarding the gross costs incurred in the purchase of proved and unproved properties and in development and exploration activities:

	Year Ended December 31, 2007
Property acquisition costs	$	123,153.40
Unproved prospects		665.50
Exploration costs		0
Development costs		5,228.20
Total operations	$	129,047.10
Asset retirement obligation (non-cash)		241.00

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Drilling Activity

Since acquiring our operating assets in 2007, as of December 21, 2007 we drilled a total of 6 productive development wells (including wells in progress at such date) in our Eliasville Field and Blessing Field Properties, all 6 of which we own a 100% working interest in. We also drilled 8 productive exploratory wells (1.5 net wells) in our New Albany Shale play during 2007.

Productive Wells

The following table sets forth the number of productive oil and natural gas wells in which we owned an interest as of December 31, 2007. Productive wells are wells that are capable of producing natural gas or oil.

	Company Operated		Non-operated		Total
	Gross	Net	Gross	Net	Gross	Net
Oil	88	88	0	0	88	88
Natural Gas	12	12	18	3.5	30	15.5
Total	100	100	18	3.5	118	103.5

Acreage Data

The following table summarizes our gross and net developed and undeveloped oil and natural gas acreage under lease as of December 31, 2007.

	Developed acres		Undeveloped acres
	Gross	Net	Gross	Net
Blessing Field Properties (1)	1,334	1,334	1,040	1,040
Eliasville Field Properties (1)	3,991	3,991	1,240	1,240
New Albany Shale play (2)	0	0	171,000	32,340
Total	5,325	5,325	173,280	34,620

(1) Properties held by production, or HBP

(2) Primary term expires in 2009.

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.

Our oil and natural gas properties consist primarily of oil and natural gas wells and our interests in leasehold acreage, both developed and undeveloped.

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Major Customers

During fiscal year 2007, the Company sold oil and natural gas production representing 10% or more of its oil and natural gas revenues to the following purchasers:

Customer Name	Percentage of Sales
Texon, L.P.	59	%
HESCO Gathering Company, L.L.C.	17	%
Sunoco, Inc.	13	%
Gulf Mark Energy, Inc.	10	%

Because alternate purchasers of natural gas and oil are readily available, we believe that the loss of any of our purchasers would not have a material adverse effect on our financial results.

Competition

We encounter competition from other natural gas and oil companies in all areas of our operations, including the acquisition of exploratory prospects and proven properties. Many of our competitors are large, well-established companies that have been engaged in the natural gas and oil business for much longer than we have and possess substantially larger operating staffs and greater capital resources than we do. Our ability to explore for oil and natural gas reserves and to acquire additional properties in the future will be dependent upon our ability to conduct our operations, to evaluate and select suitable properties and to consummate transactions in this highly competitive environment. We believe that our technological expertise, our exploration, land, drilling and production capabilities and the experience of our management generally enable us to compete effectively.

Marketing

Our production is marketed to third parties consistent with industry practices. Typically, oil is sold at the wellhead at field-posted prices plus a bonus and natural gas is sold under contract at an index price, with certain price adjustments based upon factors normally considered in the industry, such as distance from the well to the pipeline, well pressure, estimated reserves, quality of natural gas and prevailing supply and demand conditions.

Our marketing objectives are to receive the most favorable prices possible for our oil and natural gas production, to avoid undue credit risk in our choice of purchasers and to maintain the flexibility to react to changes in the market.

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,

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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.

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.

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.

Gathering service, which occurs upstream of jurisdictional transmission services, is regulated by the states on shore and in state waters. Although its policy is still in flux, FERC has reclassified certain jurisdictional transmission facilities as non-jurisdictional gathering facilities, which has the tendency to increase our costs of getting natural gas to point of sale locations.

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Intrastate natural gas transportation is also subject to regulation by state regulatory agencies. 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.

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.

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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, 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 hazardous substances. 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. 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

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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.

We are not aware of any environmental claims existing as of December 31, 2007, which would have a material impact on our financial position or results of operations. There can be no assurance, however, that current regulatory requirements will not change, or past non-compliance with environmental laws will not be discovered on our properties.

Air Emissions

The Federal Clean Air Act 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. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the Federal Clean Air Act 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.

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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.

Item 1A. Risk Factors

You should carefully consider each of the risks described below, together with all of the other information contained in this report, before deciding to invest in our securities. If any of the following risks develop into actual events, our business, financial condition or results of operations could be materially adversely affected and you may lose all or part of your investment.

We have had a operating losses and limited revenues to date and may experience continued losses in the future.

We have operated at a loss each year since inception. Net losses for the fiscal years ended December 31, 2006 and 2007 were $3.8 million and $12.7 million, respectively. Our loss in the fiscal year ended December 31, 2007 was primarily attributed to interest expense of $14.1 million, a figure which included $6.7 million for the amortization of various debt issuance discounts, fees, warrants and other consideration. Our revenues for the fiscal years ended December 31, 2006 and 2007 were $0 million and $11.6 million, respectively, reflecting the fact that we established our first oil and natural gas production operations during 2007. We may not be able to generate significant revenues in the future. In addition, we expect to incur substantial operating expenses in connection with our natural gas and oil exploration and development activities. As a result, we may continue to experience negative cash flow for at least the foreseeable future and cannot predict when, or even if, we might become profitable.

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.

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We have substantial capital requirements that, if not met, may hinder operations.

We have and expect to continue to have substantial capital needs as a result of our active exploration, 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, and financing under existing or new credit facilities may not be available in the future. Without additional capital resources, we may be forced to limit or defer our planned natural gas and oil exploration and development program and this will adversely affect the recoverability and ultimate value of our natural gas and oil properties, in turn negatively affecting our business, financial condition, and results of operations.

Natural gas and oil prices are highly volatile, and lower prices will negatively affect our financial results.

Our revenue, profitability, cash flow, oil and natural gas reserves value, future growth, and ability to borrow funds or obtain additional capital, as well as the carrying value of our properties, are substantially dependent on prevailing prices of natural gas and oil. Historically, the markets for natural gas and oil have been volatile, and those markets are likely to continue to be volatile in the future. It is impossible to predict future natural gas and oil price movements with certainty. Prices for natural gas and oil are subject to wide fluctuations in response to relatively minor changes in the supply of and demand for natural gas and oil, market uncertainty, and a variety of additional factors beyond our control. These factors include:

• the level of consumer product demand;

• the domestic and foreign supply of oil and natural gas;

• overall economic conditions;

• weather conditions;

• domestic and foreign governmental regulations and taxes;

• the price and availability of alternative fuels;

• political conditions in or affecting oil and natural gas producing regions;

• the level and price of foreign imports of oil and liquefied natural gas; and

• the ability of the members of the Organization of Petroleum Exporting Countries and other state controlled oil companies to agree upon and maintain oil price and production controls.

Declines in natural gas and oil prices may materially adversely affect our financial condition, liquidity, and ability to finance planned capital expenditures and results of operations and may reduce the amount of oil and natural gas that we can produce economically.

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 success largely depends 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. 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;

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• 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

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 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 play 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.

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The New Albany Shale play contain 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.

Seismic studies do not guarantee that hydrocarbons are present or if present will produce in economic quantities.

We rely on seismic studies to assist us with assessing prospective drilling opportunities on our properties, as well as on properties that we may acquire. Such seismic studies are merely an interpretive tool and do not necessarily guarantee that hydrocarbons are present or if present will produce in economic quantities.

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

As of the end of our 2007 fiscal year, approximately 30% of the Eliasville Field Properties’ proved reserves and 51% of the Blessing Field Properties’ proved reserves were classified as proved 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 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.

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

In acquiring producing properties we 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.

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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.

We cannot assure you that:

• we will be able to identify desirable natural gas and oil prospects and acquire leasehold or other ownership interests in such prospects at a desirable price;

• any completed, currently planned, or future acquisitions of ownership interests in natural gas and oil prospects will include prospects that contain proved natural gas or oil reserves;

• we will have the ability to develop prospects which contain proven natural gas or oil reserves to the point of production;

• we will have the financial ability to consummate additional acquisitions of ownership interests in natural gas and oil prospects or to develop the prospects which we acquire to the point of production; or

• that we will be able to consummate such additional acquisitions on terms favorable to us.

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.

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 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.

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We may not be successful in upgrading our technical, operations, and administrative resources or in increasing our ability to internally provide 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 face strong competition from other natural gas and oil companies.

We encounter competition from other natural gas and oil companies in all areas of our operations, including the acquisition of exploratory prospects and proved properties. Our competitors include major integrated natural gas and oil companies and numerous independent natural gas and oil companies, individuals, and drilling and income programs. Many of our competitors are large, well-established companies that have been engaged in the natural gas and oil business much longer than we have and possess substantially larger operating staffs and greater capital resources than we do. These companies may be able to pay more for exploratory projects and productive natural gas and oil properties and may be able to define, evaluate, bid for, and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, these companies may be able to expend greater resources on the existing and changing technologies that we believe are and will be increasingly important to attaining success in the industry. We may not be able to conduct our operations, evaluate, and select suitable properties and consummate transactions successfully in this highly competitive environment.

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. Mr. Kaetzer has experience and expertise in evaluating and analyzing producing oil and natural gas properties and drilling prospects, maximizing production from oil and natural gas properties and, marketing oil and natural gas production. The loss of Mr. Kaetzer 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.

The unavailability or high cost of drilling rigs, equipment, supplies or personnel could affect adversely our ability to execute on a timely basis our exploration and development plans within budget, which could have a material adverse effect on our financial condition and results of operations.

Shortages or the high cost of drilling rigs, equipment, supplies or personnel could delay or affect adversely our exploration and development operations, which could have a material adverse effect on our financial condition and results of operations. Demand for drilling rigs, equipment, supplies and personnel currently is very high in the areas in which we operate. An increase in drilling activity in the areas in which we operate could further increase the cost and decrease the availability of necessary drilling rigs, equipment, supplies and personnel.

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

We do not operate certain of the properties in which we have 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;

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• inclusion of other participants in drilling wells; and

• use of technology.

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 depends 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.

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.

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 serve as collateral for advances under our existing credit facility, a writedown 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 we will be required to write down the carrying value of our 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.

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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:

• natural disasters.

• 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

• protection of human health.

From time to time, regulatory agencies have also imposed price controls and limitations on production by restricting the rate of flow of natural gas and oil wells below actual production capacity in order to conserve supplies of natural gas and oil.

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.

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Market conditions or operational impediments may hinder our access to oil and natural gas markets or delay our production.

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 hedge the price risks associated with our production. Our hedge transactions may result in our making cash payments or prevent us from benefiting to the fullest extent possible from increases in prices for natural gas and oil.

Because natural gas and oil prices are unstable, we have entered into price-risk-management transactions such as swaps, collars, futures, and options to reduce our exposure to price declines associated with a portion of our natural gas and oil production and thereby to achieve a more predictable cash flow. The use of these arrangements will limit our ability to benefit from increases in the prices of natural gas and oil. Our hedging arrangements may apply to only a portion of our production, thereby providing only partial protection against declines in natural gas and oil prices. These arrangements could expose us to the risk of financial loss in certain circumstances, including instances in which production is less than expected, our customers fail to purchase contracted quantities of natural gas and oil, or a sudden, unexpected event materially impacts natural gas or oil prices.

The financial condition of our operators could negatively impact our ability to collect revenues from operations.

We do not operate all of the properties in which we have working interests. 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 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.

We may not have enough insurance to cover all of the risks that we face and operations of prospects in which we participate may not maintain or may fail to obtain adequate insurance.

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. The impact of Hurricanes Katrina and Rita have resulted in escalating insurance costs and less favorable coverage terms.

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Oil and natural gas operations are subject to particular hazards incident to the drilling and production of oil and natural gas, such as blowouts, cratering, explosions, uncontrollable flows of oil, natural gas or well fluids, fires and pollution and other environmental risks. These hazards can cause personal injury and loss of life, severe damage to and destruction of property and equipment, pollution or environmental damage and suspension of operation. We do not operate all of the properties in which we have an interest. In the projects in which we own a non-operating interest directly or own an equity interest in a limited partnership which in turn owns a non- operating interest, the operator for the prospect maintains insurance of various types to cover our operations with policy limits and retention liability customary in the industry. We believe the coverage and types of insurance are adequate. The occurrence of a significant adverse event that is not fully covered by insurance could result in the loss of our total investment in a particular prospect which could have a material adverse effect on our financial condition and results of operations.

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.

Our Blessing Field Properties are geographically located in the Texas Gulf Coast region. As a result, we may be 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 could 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 us from taking delivery of our products.

If we are unable to successfully integrate into our operations on a timely basis those assets or companies we recently acquired or which we acquire in the future, our profitability could be negatively affected.

Increasing our reserve base through acquisitions is a component of our business strategy, as most recently evidenced by our acquisition of the Blessing Field Properties on October 1, 2007. Although we expect that our acquisitions will result in certain business opportunities and growth prospects, we may never realize the expected business opportunities and growth prospects.

Successful integration will require, among other things, combining the companies:

• business development efforts;

• financial and accounting systems;

• key personnel;

• geographically separate facilities; and

• business and executive cultures.

We also 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 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;

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• 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; and

• 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, 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 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. 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. 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.

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.

Our leverage and debt service obligations may adversely affect our cash flow.

We have a substantial amount of debt. As of December 31, 2007, we had total debt of $165 million (face amount, without deduction of original issuance discounts), consisting almost entirely of our 12-1/2% senior secured notes due 2012, or the Senior Notes, and our 14% senior subordinated convertible secured notes due 2013, or the Convertible Notes. There were $252,532 of borrowings under our existing $20 million credit facility at year-end 2007, and no of letters of credit were issued against the commitment. As of December 31, 2007, we were permitted to use up to $19.7 million under the credit agreement terms for borrowings and to collateralize certain hedging obligations, and to use up to a $10 million sub-limit of the $19.7 million to issue letters of credit.

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Our substantial level of indebtedness could have important consequences, including the following:

• it may make it difficult for us to satisfy our obligations under our indebtedness and contractual and commercial commitments;

• we must use a substantial portion of our cash flow from operations to pay interest on our indebtedness, which will reduce the funds available to us for other purposes;

• our ability to obtain additional debt financing in the future for working capital, capital expenditures, acquisitions or general corporate purposes may be limited;

• our flexibility in reacting to changes in the industry may be limited and we could be more vulnerable to adverse changes in our business or economic conditions in general; and

• we may be at a competitive disadvantage to those of our competitors who operate on a less leveraged basis.

Furthermore, all of our borrowings under our existing credit facility will bear interest at variable rates. If these rates were to increase significantly, our ability to borrow additional funds may be reduced, our interest expense would significantly increase, and the risks related to our substantial indebtedness would intensify.

In addition, the indentures governing the Senior Notes and the Convertible Notes and our existing credit agreement contain various restrictive covenants (including in the case of our existing revolving credit facility, certain financial covenants), which covenants limit our ability to engage in activities that may be in our long-term best interests. Our failure to comply with these covenants would result in an event of default which, if not cured or waived, could result in the acceleration of all of our indebtedness, and have a material adverse effect on our liquidity, financial condition and results of operations.

Any failure to meet our debt obligations could harm our business, financial condition, results of operations or cash flows.

We face significant interest expenses as a result of our outstanding notes and our existing credit facility. Our ability to generate cash flows from operations and to make scheduled payments on our indebtedness, including the notes, will depend on our future financial performance. Our future performance will be affected by a range of economic, competitive, legislative, operating and other business factors, many of which we cannot control, such as general economic and financial conditions in our industry or the economy at large. A significant reduction in operating cash flows resulting from changes in economic conditions, increased competition, or other events could increase the need for additional or alternative sources of liquidity and could have a material adverse effect on our business, financial condition, results of operations and prospects and our ability to service our debt, including the notes, and other obligations.

If we are unable to service our indebtedness, we will be forced to adopt an alternative strategy that may include actions such as reducing or delaying acquisitions and capital expenditures, selling assets, restructuring or refinancing our indebtedness or seeking equity capital. We cannot assure you that any of these alternative strategies could be effected on satisfactory terms, if at all, or that they would yield sufficient funds to make required payments of interest on and principal of our debt in the future, including payments on the notes, and any such alternative measures may be unsuccessful or may not permit us to meet scheduled debt service obligations, which could cause us to default on our obligations and impair our liquidity. Failure to make scheduled payments of interest and principal on our outstanding indebtedness would likely result in a reduction of our credit rating, which could harm our ability to incur additional indebtedness on acceptable terms.

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The indentures governing the Senior Notes and the Convertible Notes, as well as our existing credit agreement, impose significant operating and financial restrictions on us that may prevent us from pursuing certain business opportunities and restrict our ability to operate our business.

The indentures governing the Senior Notes and the Convertible Notes and the existing credit agreement contain covenants that restrict our ability to take various actions, such as:

• incurring or generating additional indebtedness;

• paying dividends on our capital stock or redeeming, repurchasing or retiring our capital stock or subordinated indebtedness or making other restricted payments;

• entering into certain transactions with affiliates;

• creating or incurring liens on our assets;

• transferring or selling assets;

• incurring dividend or other payment restrictions affecting certain of our future subsidiaries; and

• consummating a merger, consolidation or sale of all or substantially all of our assets.

In addition, our existing credit facility includes other and more restrictive covenants including those that restrict our ability to prepay our other indebtedness, including the notes, while borrowings under the existing credit facility remain outstanding. The existing credit facility also requires us to achieve specified financial and operating results and maintain compliance with specified financial ratios. Our ability to comply with these ratios may be affected by events beyond our control.

The restrictions contained in the indentures governing the Senior Notes and the Convertible Notes and the existing credit agreement could:

• limit our ability to plan for or react to market conditions or meet capital needs or otherwise restrict our activities or business plans; and

• adversely affect our ability to finance our operations, strategic acquisitions, investments or alliances or other capital needs or to engage in other business activities that would be in our interest.

A breach of any of the restrictive covenants or our inability to comply with the required financial ratios could result in a default under the existing credit facility.

If a default occurs, the lenders under the existing credit facility may elect to:

• declare all borrowings outstanding thereunder, together with accrued interest and other fees, to be immediately due and payable;

• or exercise their remedies against our assets subject to their first liens, which could prevent us from making payments on the notes;

either of which would (after the expiration of any applicable grace periods) result in an event of default under the indenture governing the notes and could result in a cross default under our other debt instruments. The lenders would also have the right in these circumstances to terminate any commitments they have to provide us with further borrowings. If the borrowings under the existing credit facility and the notes were to be accelerated, we cannot assure you that we would be able to repay in full in the notes.

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We may issue additional shares of capital stock that could adversely affect holders of shares of our common stock and, as a result, holders of our notes convertible into shares of common stock.

Our board of directors is authorized to issue additional classes or series of shares of our capital stock without any action on the part of our stockholders, subject to the restrictive covenants of the indenture governing the notes. Our board of directors also has the power, without stockholder approval and subject to such restrictive covenants, to set the terms of any such classes or series of shares of our capital stock that may be issued, including voting rights, dividend rights, conversion features, preferences over shares of our existing class of common stock with respect to dividends or if we liquidate, dissolve or wind up our business and other terms. If we issue shares of our capital stock in the future that have preference over shares of our existing class of common stock with respect to the payment of dividends or upon our liquidation, dissolution or winding up, or if we issue shares of capital stock with voting rights that dilute the voting power of shares of our existing class of common stock, the rights of holders of shares of our common stock or the trading price of shares of our common stock and, as a result, the market value of the notes convertible into shares of common stock could be adversely affected.

The Conversion Price of our 14% Senior Subordinated Convertible Secured Notes is subject to a reset based on the prevailing market price of our common stock during a specified period, and if such reset is triggered, the conversion price of our 14% Senior Subordinated Convertible Secured Notes will be reduced, potentially resulting in substantial dilution of the equity ownership of holders of our common stock.

If the volume weighted average price of our common stock for the 30 trading days up to and including December 31, 2008 is less than $0.63 then, effective as of January 1, 2009, the conversion price of our Convertible Notes will decrease to the higher of (A) $0.44 or (B) the volume weighted average price of our common stock for the 30 trading days up to and including December 31, 2008 plus 5%. In addition, if the conversion price is decreased to $0.44, the interest rate on our Convertible Notes will increase by 300 basis points. As of March 27, 2008, the last sale price of our common stock on the OTC Bulletin Board was $0.25. If such reset were to occur, upon conversion of our Convertible Notes, we would be required to issue substantially more shares of our common stock, thereby diluting holders of our common stock.

Conversion of our 14% Senior Subordinated Convertible Secured Notes prior to October 1, 2010, will require us to make certain make-whole payments, which payments may consist of shares of our common stock, resulting in the dilution of the equity ownership of holders of our common stock.

In the event a holder of our Convertible Notes elects to convert such notes prior to October 1, 2010, then such holder shall be entitled to a make whole premium consisting of the present value of all interest as if paid in cash from the date of conversion through October 1, 2010, computed using a discount rate equal to the Reinvestment Yield as defined in the indenture governing the Convertible Notes. Should we elect to pay this amount in shares of our common stock, the equity ownership of holders of our common stock could be significantly diluted.

The market price of our common stock may be volatile.

The trading price of our common stock and the price at which we may sell common stock in the future are subject to large fluctuations in response to any of the following:

• limited trading volume in our common stock;

• quarterly variations in operating results;

• our involvement in litigation;

• general financial market conditions;

• the prices of natural gas and oil;

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• announcements by us and our competitors;

• our liquidity;

• our ability to raise additional funds;

• changes in government regulations; and

• other events.

Moreover, our common stock does not have substantial trading volume. As a result, relatively small trades of our common stock may have a significant impact on the price of our common stock and, therefore, may contribute to the price volatility of our common stock.

Because of the limited trading volume of our common stock and the price volatility of our common stock, you may be unable to sell your shares of our common stock when you desire or at the price you desire. The inability to sell your shares of our common stock in a declining market because of such illiquidity or at a price you desire may substantially increase your risk of loss.

Sales of substantial amounts of shares of our common stock could cause the price of our common stock to decrease.

We have registered for resale a substantial number of shares of our common stock issuable upon conversion of our Convertible Notes and certain other securities convertible into or exercisable for shares of our common stock. Our stock price may decrease due to the additional amount of shares available in the market.

The trading price of our common stock could be adversely affected by sales and issuances of our common stock in the public markets.

As of March 6, 2008, our two largest stockholders beneficially owned approximately 38%, and our directors and executive officers, as a group, beneficially owned approximately 28%, of the then-outstanding shares of our common stock (inclusive of options and warrants exercisable into shares of our common stock). In addition, as of March 6, 2008 one institutional investor held approximately 75% of the outstanding principal amount of the Convertible Notes that are convertible into shares of our common stock.

Sales of our common stock held by these stockholders or issuable to such noteholder, or the perception that such sales might occur, could have a material adverse effect on the trading price of our common stock or could impair our ability to obtain capital through future offerings of equity securities. In addition, the trading price of our common stock could decline as a result of issuances by us of additional shares of our common stock pursuant to our existing shelf registration statement or otherwise. The trading price of our common stock could also decline as the result of the perception that such issuances could occur.

Provisions in our certificate of incorporation and the indenture governing the notes may inhibit a takeover of our Company.

Under our amended and restated certificate of incorporation, our board of directors is authorized to issue shares of our capital stock without the approval of our stockholders. Issuance of such shares could make it more difficult to acquire our Company without the approval of our board of directors as more shares would have to be acquired to gain control.

In addition, upon a change of control of our Company, each holder of the notes may require us to purchase all or a portion of such holder’s notes at a purchase price equal to 101% of the aggregate principal amount of such holder’s notes, together with accrued and unpaid interest, if any, to the date of purchase.

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These provisions may deter hostile takeover attempts that could result in an acquisition of us that would have been financially beneficial to our stockholders.

We have not previously paid dividends on the shares of our common stock and do not anticipate doing so in the foreseeable future.

Under the Nevada Revised Statutes, cash dividends on capital stock may not be paid if, after given effect to any such dividend, we would not be able to pay our debts as they become due in the usual course of business or our total assets would be less than the sum of our total liabilities plus any amount needed to satisfy preferential rights upon dissolution of our Company.

In addition, the indenture governing the notes restricts, and any indentures and other financing agreements that we may enter into in the future may limit, our ability to pay cash dividends on our capital stock, including shares of our common stock issuable upon conversion of the notes. Specifically, under the indenture governing the notes, we may pay cash dividends and make other distributions on or in respect of our capital stock only if certain covenants are met.

Moreover, we have not in the past paid any dividends on the shares of our common stock and do not anticipate that we will pay any dividends on our common stock in the foreseeable future. Any future decision to pay a dividend on our common stock and the amount of any dividend paid, if permitted, will be made at the discretion of our board of directors.

Item 3. Legal Proceedings.

From time to time, we are party to certain legal actions and claims arising in the ordinary course of business. While the outcome of these events cannot be predicted with certainty, management does not expect these matters to have a materially adverse effect on our financial position or results of operations.

Item 4. Submission of Matters to Vote of Security Holders.

No matters were submitted to the vote or consent of the holders of the outstanding shares of our common stock during the quarter ended December 31, 2007.

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PART II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.

Market for Our Common Stock

Our common stock is quoted on the OTC Bulletin Board under the symbol “BOGA.” At March 27, 2008, there were 34,408,006 shares of our common stock outstanding. The following table sets forth, for the periods indicated, the high, low and closing sales prices per common share as reported on the OTC Bulletin Board, and the cash dividends declared per common share.

2007:	High		Low
Quarter ended December 31, 2007	$	0.64	$	0.37
Quarter ended September 30, 2007	$	0.75	$	0.34
Quarter ended June 30, 2007	$	0.71	$	0.32
Quarter ended March 31, 2007	$	0.63	$	0.37
2006:	High		Low
Quarter ended December 31, 2006	$	0.75	$	0.35
Quarter ended September 30, 2006	$	1.19	$	0.67
Quarter ended June 30, 2006	$	3.25	$	1.10
Quarter ended March 31, 2006	$	3.25	$	0.85

The last sales price of our common stock on the OTC Bulletin Board on December 29, 2007 was $0.66 per share. As of March 27, 2008, the closing sale price of a share of our common stock was $0.25. As of March 27, 2008, there were approximately 175 holders of record of our common stock.

We have not paid any cash dividends to date, and have no intention of paying any cash dividends on our common stock in the foreseeable future. The declaration and payment of dividends is subject to the discretion of our Board of Directors and to certain limitations imposed under provisions of the Nevada Revised Status Governing Corporations. The timing, amount and form of dividends, if any, will depend on, among other things, our results of operations, financial condition, cash requirements and other factors deemed relevant by our Board of Directors. The agreements and instruments that we entered into in 2007 in connection with our senior and convertible note financings, as well as our existing credit facility, contain significant restrictions on our ability to pay dividends on our common stock.

There were no repurchases of securities during the fourth quarter of 2007.

Recent Sales of Unregistered Securities

We have reported all sales of our unregistered equity securities that occurred during 2007 in our Reports on Form 10-Q or Form 8-K, as applicable.

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Securities Authorized for Issuance Under Equity Compensation Plans

The following table provides information as of December 31, 2007 about our equity compensation plans and arrangements.

Equity Compensation Plan Information—December 31, 2007

Plan category	(a) Number of securities to be issued upon exercise of outstanding options, warrants and rights		(b) Weighted-average exercise price of outstanding options, warrants and rights		(c) Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))
Equity compensation plans approved by security holders	0		$	0	N/A
Equity compensation plans not approved by security holders	7,178,330	(1)	$	0.31	2,036,670	(2)
Total			$	0.31

(1) Consists of warrants and options granted to our employees, officers, directors and consultants, to the extent vested and exercisable (within the meaning of Rule 13d-3(d)(1) promulgated by the Commission under the Securities and Exchange Act of 1934, as amended) as of December 31, 2007.

(2) Includes an aggregate of (i) 1,666,670 shares of our common stock underlying options granted but not yet vested with respect to such shares pursuant to Option Agreements dated December 20, 2006 and August 3, 2007 entered into with our Chief Executive Officer and Chief Financial Officer, respectively, which options vest over the next two years; and (ii) 370,000 shares of our common stock underlying options granted to our employees on August 3, 2007, but not yet vested with respect to such underlying shares, which options vest with respect to one-third of the shares on each of the first, second and third year anniversary of the grant date.

Set forth below is a description of the individual compensation arrangements or equity compensation plans not currently approved by our security holders pursuant to which the 7,178,330 shares of our Common Stock included in the chart above were issuable as of December 31, 2007:

• Option granted August 3, 2007 to a director in consideration of services performed on our behalf, which option expires five years from grant date and is currently exercisable to purchase up to 150,000 shares of our Common Stock at an exercise price of $0.55 per share;

• Option granted August 3, 2007 to an officer in consideration of services to be performed on our behalf, which option expires five years from grant date and, subject to a vesting schedule, is currently exercisable with respect to 166,666 shares of our Common Stock at an exercise price of $0.55 per share;

• Option granted August 3, 2007 to an officer in consideration of services to be performed on our behalf, which option expires five years from grant date and, subject to a vesting schedule, is currently exercisable with respect to 166,666 shares of our Common Stock at an exercise price of $0.825 per share;

• Option granted August 3, 2007 to an officer in consideration of services to be performed on our behalf, which option expires five years from grant date and, subject to a vesting schedule, is currently exercisable with respect to 166,666 shares of our Common Stock at an exercise price of $1.10 per share;

• Option granted January 4, 2007 to an officer in consideration of services performed on our behalf, which option expires five years from grant date and is currently exercisable to purchase up to 100,000 shares of our Common Stock at an exercise price of $0.56 per share;

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• Option granted December 20, 2006 to an officer in consideration of services to be performed on our behalf, which option expires five years from grant date and, subject to a vesting schedule, is currently exercisable with respect to 666,666 shares of our Common Stock at an exercise price of $0.50 per share;

• Option granted December 20, 2006 to an officer in consideration of services to be performed on our behalf, which option expires five years from grant date and, subject to a vesting schedule, is currently exercisable with respect to 333,333 shares of our Common Stock at an exercise price of $0.60 per share;

• Option granted December 20, 2006 to an officer in consideration of services to be performed on our behalf, which option expires five years from grant date and, subject to a vesting schedule, is currently exercisable with respect to 333,333 shares of our Common Stock at an exercise price of $1.00 per share;

• Option granted November 14, 2006 to a consultant in consideration of services performed on our behalf, which option expires five years from grant date and is currently exercisable to purchase up to 360,000 shares of our Common Stock at an exercise price of $0.50 per share;

• Options granted October 20, 2006 to consultants in consideration of services performed on our behalf, which options expire five years from grant date and are currently exercisable to purchase up to 100,000 shares of our Common Stock, in the aggregate, at an exercise price of $0.50 per share;

• Option granted August 15, 2006 to a consultant in consideration of services performed on our behalf, which option expires five years from grant date and is currently exercisable to purchase up to 100,000 shares of our Common Stock at an exercise price of $1.01 per share;

• Option granted December 27, 2005 to an officer in consideration of services performed on our behalf, which option expires five years from grant date and is currently exercisable to purchase up to 175,000 shares of our Common Stock at an exercise price of $0.94 per share;

• Options granted April 29, 2005 to directors, officers and consultants in consideration of services performed on our behalf, which options expire five years from grant date and are currently exercisable to purchase up to an aggregate of 3,960,000 shares of our Common Stock at an exercise price of $0.05 per share; and

• Option granted April 1, 2005 to a consultant in consideration of services performed on our behalf, which option expires five years from grant date and is currently exercisable to purchase up to 400,000 shares of our Common Stock at an exercise price of $0.30 per share.

Item 6. Selected Financial Data.

Not Applicable

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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

The following discussion will assist you in understanding our financial position, liquidity, and results of operations. The information below should be read in conjunction with the consolidated financial statements, and the related notes to consolidated financial statements. Our discussion contains both historical and forward-looking information. We assess the risks and uncertainties about our business, long-term strategy, and financial condition before we make any forward-looking statements, but we cannot guarantee that our assessment is accurate or that our goals and projections can or will be met. Statements concerning results of future exploration, exploitation, development, and acquisition expenditures as well as expense and reserve levels are forward-looking statements. We make assumptions about commodity prices, drilling results, production costs, administrative expenses, and interest costs that we believe are reasonable based on currently available information.

Critical Estimates and Accounting Policies

We prepare our consolidated financial statements in this report using accounting principles that are generally accepted in the United States (“GAAP”). GAAP represents a comprehensive set of accounting and disclosure rules and requirements. We must make judgments, estimates, and in certain circumstances, choices between acceptable GAAP alternatives as we apply these rules and requirements, which may 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.

The most critical estimate we use is the engineering estimate of proved oil and gas reserves. This estimate affects the application of the successful efforts method of accounting, the calculation of depreciation and depletion of oil and gas properties and the estimate of the impairment of our oil and gas properties. It also affects the estimated lives of our assets used to determine asset retirement obligations.

Successful Efforts Method Accounting

We use the successful efforts method of accounting for oil and gas producing activities. Our 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. Because we can not predict the timing and the cost of exploratory drilling that is unsuccessful in finding proved reserves, our quarterly and annual net income could vary dramatically in the future under the successful efforts method of accounting in the event of increased exploratory drilling activity by us.

Impairment of Oil and Natural Gas Properties

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. An asset would be impaired if the undiscounted cash flows were less than its carrying value. Impairments are measured by the amount by which the carrying value exceeds its fair value. Because we use the successful efforts method, we assess our properties individually for impairment, instead of on an aggregate pool of costs.

Depreciation and Depletion of Oil and Natural Gas Properties

Capitalized costs of producing oil and gas properties, after considering estimated residual salvage values, are depreciated and depleted by the unit-of-production method. This method is applied through the simple multiplication of reserve units produced by the leasehold costs per unit on a field by field basis. Leasehold cost

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per unit is calculated by dividing the total cost of acquiring the leasehold by the estimated total proved oil and gas reserves associated with that lease. Well cost per unit is calculated by dividing the total cost by the estimated total proved producing oil and gas reserves associated with that well.

Sale or Retirement of Oil and Natural Gas Properties

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.

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

We record 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 (ARO) 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, we will be required to recognize a gain or loss if the actual costs do not equal the estimated costs included in ARO.

Concentrations of Credit Risk

All of our receivables are due from oil and natural gas purchasers. We sold 89% of our oil and natural gas production to three customers in 2007.

We maintain our cash in bank deposit accounts which, at times, may exceed federally insured limits. Accounts are guaranteed by the Federal Deposit Insurance Corporation (“FDIC”) up to $100,000. At December 31, 2007, we had approximately $4.8 million, in excess of FDIC insured limits. We have not experienced any losses in such accounts.

Revenue and Cost Recognition

We use 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 we are entitled based on our interest in the properties. Costs associated with production are expensed in the period incurred.

Cash and cash equivalents

Cash and cash equivalents include cash in banks and liquid deposit with maturities of three months or less.

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Short-term Investments

The Company’s short-term investments consist primarily of U. S. government and agency securities and investment grade corporate notes and bonds, all of which are classified as trading securities. Trading securities are recorded at fair value, and unrealized holding gains and losses are included in net earnings. The maximum maturity of securities is two years at the time of purchase with an average maturity not to exceed one year for the entire portfolio. Available-for-sale securities are classified as short-term based on their highly liquid nature and because such marketable securities represent the investment of cash that is available for current operations. Realized gains and losses are accounted for on the specific identification method. Purchases and sales are recorded on a trade date basis.

Fair Value of Financial Instruments

The carrying value of cash and cash equivalents approximates fair value because of the short-term maturity of those instruments. The fair value of the Company’s investments in marketable debt securities is based on the quoted market price on the last business day of the year. Declines in fair value below the Company’s carrying value deemed to be other than temporary are charged against net earnings. The carrying value of short-term and long-term debt approximates fair value.

Property and Equipment

Support equipment and other property and equipment are valued at cost and depreciated over their estimated useful lives, using the straight-line method over estimated useful lives of 3 to 5 years. Additions are capitalized and maintenance and repairs are charged to expense as incurred. Gains and losses on dispositions of equipment are reflected in income or loss from operations.

Stock-based compensation

On January 1, 2006, we 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 stock-based payments to employees, including grants of employee stock options, to be recognized in the financial statements based on their fair values.

Loss per share

Basic earnings per share amounts are calculated based on the weighted average number of shares of common stock outstanding during each period. Diluted earnings per share is based on the weighted average numbers of shares of common stock outstanding for the periods, including the dilutive effects of stock options, warrants granted and convertible preferred stock. Dilutive options and warrants that are issued during a period or that expire or are canceled during a period are reflected in the computations for the time they were outstanding during the periods being reported. Since we have incurred losses for all periods, the impact of the common stock equivalents would be antidilutive and therefore are not included in the calculation.

Standardized measure of discounted future net cash flows

The standardized measure of discounted future net cash flows relies on these estimates of oil and gas reserves using commodity prices and costs which existed at year-end. In our 2007 year-end reserve report, we used the December 31, 2007 WTI Cushing spot price of $96.01 per Bbl and Henry Hub spot natural gas price of $7.465 per MMbtu, adjusted by property for energy content, quality, transportation fees, and regional price differentials. The weighted average price over the lives of the properties was $94.38 per Bbl for oil and $8.064 per Mcf for gas. While we believe that future operating costs can be reasonably estimated, future prices are difficult to estimate since market prices are influenced by events beyond our control. Future global economic and political events will most likely result in significant fluctuations in future oil prices, while future U.S. natural gas

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prices will continue to be influenced by primarily domestic market factors, including supply and demand, weather patterns and public policy.

Derivatives

Derivative financial instruments, utilized to manage or reduce commodity price risk related to Baseline’s production, are accounted for under the provisions of SFAS No. 133, “Accounting for Derivative Instruments and for Hedging Activities”, and related interpretations and amendments. Under this statement, derivatives are carried on the balance sheet at fair value. If the derivative is designated as a fair value hedge, the changes in the fair value of the derivative and of the hedged item attributable to the hedged risk are recognized in earnings. If the derivative is designated as a cash flow hedge, the effective portions of changes in the fair value of the derivative are recorded in other comprehensive income or loss and are recognized in the statement of operations when the hedged item affects earnings. If the derivative is not designated as a hedge, changes in the fair value are recognized in other expense. Ineffective portions of changes in the fair value of cash flow hedges are also recognized in loss on derivative liabilities.

Income taxes

We recognize 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. We provide a valuation allowance for deferred tax assets for which we do not consider realization of such assets to be more likely than not.

Business Strategy

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: (i) the Eliasville Field in North Texas, or the Eliasville Field Properties; (ii) the New Albany Shale play in Southern Indiana, or the New Albany Shale play; and (iii) the Blessing Field in Matagorda County onshore along the Texas Gulf Coast, or the Blessing Field Properties.

Our properties cover approximately 39,945 net acres across our three core areas identified under “Our Business and Properties” section of this annual report.

We currently have a number of opportunities to increase production and develop our reserve base through infill and step-out drilling of new wells, workovers targeting proved reserves, stimulating existing wells and the expansion of enhanced oil recovery projects such as waterflood operations. In addition, we plan to investigate the application of alkaline surfactant polymer flooding techniques at our Eliasville Field Properties to potentially recover significant incremental oil reserves. On the Blessing Field Properties, we intend to evaluate the shallower Frio formation which could result in a new drilling program to exploit the shallower reserve potential of the field.

We expect to utilize 3-D seismic analysis, enhanced oil recovery processes, horizontal drilling, and other modern technologies and production techniques to improve drilling results and ultimately enhance our production and returns. We also believe use of such 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.

We frequently review opportunities to acquire additional producing properties, leasehold acreage and drilling prospects that are located in our core operating areas, or which might result in the establishment of new core 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.

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The implementation of our strategy requires that we make significant capital expenditures in order to replace current production and find and develop new oil and gas reserves. In order to finance our capital program, we depend on cash flow from operations, cash or cash equivalents on hand, or committed credit facilities, as discussed below in Liquidity and Capital Resources.

Liquidity and Capital Resources

Our main sources of liquidity and capital resources for 2008 are cash, short-term cash equivalent investments on hand, internally generated cash flows from operations and committed credit facilities. The principal source of such funds, in the approximate sum of $15.5 million as of December 31, 2007, represents a portion of the net proceeds from our sale during the fourth quarter 2007 of $115 million aggregate principal amount of 12 1/2% senior secured notes due 2012, or Senior Notes, and $50 million aggregate principal amount of 14% senior subordinated convertible secured notes due 2013, or Convertible Notes. The bulk of the proceeds realized from the sale of these debt securities was used to fund our acquisition of the Blessing Field Properties in October 2007, as well as to repay debt used to fund our April 2007 acquisition of the Eliasville Field Properties.

During 2007, net cash flow provided by operations increased by $8.0 million to $7.0 million, as compared to ($1.0) million for our 2006 fiscal year, primarily because of our purchase of the Blessing Field and Eliasville Field Properties, increased oil and gas production from drilling and workover activity and higher oil and natural gas prices. We expect our cash flow provided by operations to increase during 2008, mainly due to increased oil and natural production resulting from planned additional drilling and workover activity on the two Texas properties we acquired during 2007, ownership of these two properties for the entire year during 2008 and control of our operating and general and administrative costs.

Excluding the effects of significant unforeseen expenses or other income, our cash flow from operations fluctuates primarily because of variations in oil and gas production rates and in commodity prices. In addition, our oil and gas production from either of our Texas properties may be curtailed due to weather-related factors beyond our control. For example, hurricanes moving over Matagorda County from the Gulf of Mexico may shut down our production for the duration of the storm’s presence, or damage production facilities so that we cannot produce from the Blessing Field Properties for an extended amount of time. In addition, maintenance activities on, or damage to, major pipelines or processing facilities can also cause us to shut-in production for undetermined lengths of time. Such production delays and damage to facilities were experienced to varying degrees by other exploration and production companies, and by pipeline and processing facility operators during and after Hurricanes Katrina and Rita in 2005.

Our realized oil and gas prices vary significantly due to world political events, supply and demand for products, product storage levels, and weather patterns, among other factors. We sell 100% of our production at spot market prices. Accordingly, product price volatility will affect our cash flow from operations. To mitigate price volatility and to comply with the terms of our credit facility and bond issues, we have entered into hedging arrangements for a substantial portion of our anticipated future production in order to limit the effect of swings in hydrocarbon prices on our operations.

We incurred capital and drilling expenditures totaling approximately $130.4 million during 2007. The capital expenditures included $124.5 million for the purchase of the Eliasville Field Properties and the Blessing Field Properties, $0.7 million for the assessment and development of the New Albany Shale play, and $5.2 million for drilling and workover costs on our two acquired Texas properties.

We expect to continue to make significant capital expenditures over the next several years as part of our long-term growth strategy. We have budgeted $19.9 million for drilling, workover, exploration and facility installation expenditures in 2008. Our 2008 capital budget includes $16.2 million for proved drilling projects and $1.7 million for proved workover costs on our two Texas properties, with the remaining $2.0 million allocated to a variety of drilling and facility installation costs on our New Albany Shale play. We project that we will spend a

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total of $14.1 million on our Blessing Field Properties, $3.8 million on our Eliasville Field Properties and $2.0 million on the New Albany Shale play. The 2008 capital budget will be funded from a combination of our cash flow from operations, our cash and short-term cash equivalent investments on hand and committed credit facilities.

Interest on our Senior Notes is due and payable on April 1, 2008 and semi-annually thereafter. The principal on the Senior Notes is due on October 1, 2012. Our Convertible Notes are due on October 1, 2013. Interest on the Convertible Notes is payable semi-annually beginning April 1, 2008, with us having the option of paying any interest in cash or, subject to certain conditions being met, as additional principal amounts under the Convertible Notes, or PIK Notes. The Convertible Notes are subject to optional redemption beginning October 1, 2009 in the amount of 25% per quarter, at our option and upon certain conditions being met. Upon a change in control, the Convertible Notes can be put back to us at 101% of par, plus accrued unpaid interest.

Effective October 1, 2007, we entered into a credit agreement with Wells Fargo Foothill, Inc., as arranger and administrative agent. This agreement, or Credit Facility, provides for a revolving credit line which is subject to a borrowing base of up to the lesser of $20.0 million, or an amount determined based on our proved oil and gas reserves. A $10 million sub-limit for the issuance of letters of credit is also established under the terms of the credit agreement. As of December 31, 2007, we had $252,000 borrowed under the Credit Facility. The lenders under the credit agreement review our proved oil and gas reserves semi-annually.

Our oil and gas properties are pledged as collateral for the revolving Credit Facility, as well as the Senior Notes and the Convertible Notes. We have also agreed not to pay dividends on our common stock. Under the indentures governing the Senior Notes and the Convertible Notes, we are required to maintain debt/EBITDA ratios below defined thresholds beginning March 31, 2008, as well as maintain proved reserve PV10/senior debt ratios above a defined threshold beginning June 30, 2008. We are also required to—and did—limit our capital expenditures below defined thresholds starting with the quarter ending December 31, 2007. Under certain conditions, we are required to offer to retire a portion of the Senior Notes at 101% of par value using excess cash flow as defined under the Senior Notes indenture, starting December 31, 2007. No such offer will be required for the period ending December 31, 2007.

The most significant restrictive financial covenant under our Credit Facility is a minimum EBITDA test that becomes operative at the end of any quarter during which our cash plus unused credit availability under our line of credit falls below $10 million at any time. This covenant has not yet been operative because our combined cash position and unused credit availability at any measuring point has never fallen below the $10 million minimum, and stood at $27.9 million as of December 31, 2007. Consequently, we have always remained in compliance with this financial covenant. If we do not comply with this covenant on a continuous basis, the lender has the right to refuse to advance additional funds under the facility and/or declare any outstanding principal and interest immediately due and payable.

The following table summarizes our contractual obligations and commercial commitments as of December 31, 2007:

	Payments due by period
	Total		Less than 1 year		1 - 3 years		4 - 5 years		After 5 years
	(in thousands)
Contractual obligations:
Debt and interest	$	290,085	$	14,464	$	29,042	$	136,208	$	110,372
Office Lease		677		127		284		266		N/A
Total	$	290,762	$	14,591	$	29,325	$	136,474	$	110,372

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Changes in our working capital accounts from 2006 to 2007 include an increase in our cash and marketable securities accounts of $18.8 million, primarily reflecting the net proceeds of our two bond offerings which closed on October 1, 2007. Our accounts receivable increased by $3.8 million during 2007 from a zero balance at year-end 2006. These accounts receivable are comprised entirely of oil and natural gas sales receivables. Due to the increase in operating activities, our accounts payable balance increased by $2.1 million, to $2.2 million as of year-end 2007. Royalties payable as of December 31, 2007 were $3.8 million from a zero balance at year-end 2006, a reflection of our commencement of oil and natural gas production activities during 2007. Accrued expenses as of December 31, 2007 were $5.5 million, an increase of $5.4 million over the year-end 2006 level. The year-end 2007 total was mainly comprised of accrued interest of $5.4 million.

On December 31, 2007, our current assets exceeded our current liabilities by $10.2 million.

We believe our short-term and long-term liquidity is adequate to fund operations, including capital expenditures, interest and repayment of debt maturities.

Results of Operations

Revenue

The following table discloses the net oil and natural gas production volumes, sales, and sales prices for the year ended December 31, 2007:

	2007
Oil production volume (Mbbls)		149.3
Oil sales revenue ($000)	$	11,511.5
Price per Bbl	$	77.09
Gas production volume (Mmcf)		335.5
Gas sales revenue ($000)	$	2,459.1
Price per Mcf	$	7.33

Because we only acquired our operating assets during fiscal year 2007, we had no comparable revenue figures for our fiscal year 2006.

Lease operating expense and production taxes

Our production expenses totaled $5.1 million during 2007, our first year of operations. The following table presents the major components of our operating costs on a per Mcfe basis for fiscal year 2007:

	2007
	Total		Per Mcfe
Direct operating expense	$	3,862.3	$	3.14
Ad valorem taxes		243.0		0.20
Production taxes		715.4		0.58
Field Office Expense		327.7		0.27
	$	5,148.4	$	4.18

Because we acquired our operating assets in fiscal year 2007, we have no comparable cost figures for the 2006 fiscal year period.

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Accretion of asset retirement obligation

Accretion expense for fiscal year 2007 was $42,000, as compared to no accretion expense for fiscal year 2006. This reflects our acquisition of the Eliasville Field and Blessing Field Properties during 2007. Prior to 2007, we had no obligations relating to the ultimate disposal of any operating assets.

Depletion, depreciation and amortization (DD&A)

For our fiscal year 2007, we recorded DD&A expense of $1.8 million, after having recorded no DD&A expense during 2006. Virtually all of this expense was attributable to depletion of our oil and gas properties, which were acquired during 2007.

General and administrative expense (G&A expense)

General and administrative expense for fiscal year 2007 increased $0.8 million from the comparable 2006 period to $3.4 million. The largest portion of the 2007 total was comprised of legal, technical and professional fees, at $1.1 million. Other major components of 2007 general and administrative costs included share-based compensation, $0.8 million, and employee salary and benefits, $0.8 million. General and administrative expense for 2007 equaled $2.77 per Mcfe. We had no oil and gas operations during our 2006 fiscal year. During 2006, the primary components of our general and administrative expenses were legal, technical and professional fees as well as share-based compensation.

Other income (expense)

Other income (expense) for fiscal year 2007 totaled an expense of $13.9 million, compared to an expense of $1.2 million during fiscal year 2006. The largest component of this total during 2007 was interest expense of $14.1 million. Total interest expense included interest either paid or accrued on credit facilities and bonds of $7.4 million and amortization of debt issuance costs of $6.7 million.

Interest income

Interest income fell to $99,000 during fiscal year 2007, down from $118,000 during 2006, a drop of $19,000. Interest earned during 2007 was attributable to interest earned on our “sweep” operating accounts as well as interest earned on the net proceeds from our bond offering which closed on October 1, 2007.

Interest expense

Interest expense increased by $12.4 million to $14.1 million during fiscal year 2007. The 2007 total included cash interest paid on credit facilities and notes payable of $1.8 million, accrued interest (primarily attributable to our two bond issues) of $5.6 million, amortization of fees, warrants and other consideration granted under various credit facilities of $6.2 million and amortization of debt discount of $0.6 million. Interest expense during 2006 totaled $1.7 million, nearly all of which was comprised of amortization of debt issuance costs and debt discounts.

Loss on derivative instruments

We recorded an unrealized loss of $7.4 million on our derivative instruments in Other Comprehensive Income (Loss) as of December 31, 2007. This figure represents the cumulative change in fair value of our hedge positions which qualify for cash-flow hedge accounting since the establishment of these positions during fiscal year 2007.

Net loss available to common shareholders

For the fiscal year 2007, our total comprehensive loss increased to $20 million, compared to our 2006 total comprehensive loss of $3.8 million. The major components of the 2007 comprehensive loss were unrealized losses on derivative instruments totaling $7.4 million and interest expense of $14.1 million. Our 2007 income from operations totaled $1.2 million, compared to a loss from operations of $2.6 million during 2006. This is a reflection of our commencement of oil and gas operations during 2007 as a result of our two major property acquisitions.

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New Accounting Pronouncements

In June 2006, the Financial Accounting Standards Board issued FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109” (FIN 48). This Interpretation provides guidance on recognition, classification and disclosure concerning uncertain tax liabilities. The evaluation of a tax position requires recognition of a tax benefit if it is more likely than not it will be sustained upon examination. We adopted this Interpretation effective January 1, 2007. The adoption did not have a material impact on our financial statements.

In September 2000, the Emerging Issues Task Force issued EITF 00-19, “Accounting for Derivative Financial Instruments Indexed to and Potentially Settled in, a Company’s Own Stock,” (“EITF 00-19”) which Requires freestanding contracts that are settled in a company’s own stock, including common stock warrants, to be designated as an equity instrument, asset or a liability. Under the provisions of EITF 00-19, a contract designated as an asset or a liability must be carried at fair value on a company’s balance sheet, with any changes in fair value recorded in the company’s results of operations. A contract designated as an equity instrument must be included within equity, and no fair value adjustments are required.

In December 2006, the FASB issued FASB Staff Position No. EITF 00-19-2, Accounting for Registration Payment Arrangements. EITF 00-19-2 addresses an issuer’s accounting for registration payment arrangements. It specifies that the contingent obligation to make future payments or otherwise transfer consideration under a registration payment arrangement, whether issued as a separate agreement or included as a provision of a financial instrument or other agreement, should be separately recognized and measured in accordance with FASB Statement No. 5, Accounting for Contingencies. The guidance in EITF 00-19-2 amends FASB Statements No. 133, Accounting for Derivative Instruments and Hedging Activities, and No. 150, Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity, and FASB Interpretation No. 45, Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others, to include scope exceptions for registration payment arrangements. EITF 00-19-2 also requires additional disclosure regarding the nature of any registration payment arrangements, alternative settlement methods, the maximum potential amount of consideration and the current carrying amount of the liability, if any. This EITF is effective immediately for registration payment arrangements and the financial instruments subject to those arrangements that are entered into or modified subsequent to the date of issue of this EITF. For registration payment arrangements and financial instruments subject to those arrangements that were entered into prior to the issuance of this EITF, this is effective for financial statements issued for fiscal years beginning after December 15, 2006, and interim periods within those fiscal years. The impact of implementing EITF 00-19-2 in the fiscal year 2007 resulted in a cumulative effect of a change in accounting principle with a credit to beginning retained earnings of $6,656,677 and a reversal of the same amount to the derivative liability account.

In December 2007, the FASB issued Statement SFAS No. 141, Business Combinations (SFAS 141R), and Statement of Financial Accounting Standards No. 160, Accounting and Reporting of Noncontrolling Interest in Consolidated Financial Statements, an amendment of ARB No. 51 (SFAS 160). SFAS 141R and SFAS 160 will significantly change the accounting for and reporting of business combination transactions and noncontrolling (minority) interests in consolidated financial statements. SFAS 141R retains the fundamental requirements in Statement 141, Business Combinations, while providing additional definitions, such as the definition of the acquirer in a purchase and improvements in the application of how the acquisition method is applied. SFAS 160 will change the accounting and reporting for minority interests, which will be recharacterized as noncontrolling interests, and classified as a component of equity. These Statements become simultaneously effective January 1, 2009. Early adoption is not permitted. The Company is currently assessing the impact, if any, that the adoption of this pronouncement will have on the Company’s operating results financial position or cash flows.

In May 2007, the FASB issued FSP No. FIN 48-1, Definition of Settlement in FASB Interpretation No. 48, (FIN 48-1) which amends FIN 48 and provides guidance concerning how an entity should determine whether a

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tax position is “effectively,” rather than the previously required “ultimately,” settled for the purpose of recognizing previously unrecognized tax benefits. In addition, FIN 48-1 provides guidance on determining whether a tax position has been effectively settled. The guidance in FIN 48-1 is effective upon the initial January 1, 2007 adoption of FIN 48. Companies that have not applied this guidance must retroactively apply the provisions of this FSP to the date of the initial adoption of FIN 48. The Company has adopted FIN 48-1 and no retroactive adjustments were necessary.

In April 2007, the FASB issued Staff Position (FSP) No. FIN 39-1, Amendment of FASB Interpretation No. 39, (FIN 39-1) to amend FIN 39, Offsetting of Amounts Related to Certain Contracts (FIN 39). The terms “conditional contracts” and “exchange contracts” used in FIN 39 have been replaced with the more general term “derivative contracts.” In addition, FIN 39-1 permits the offsetting of recognized fair values for the right to reclaim cash collateral or the obligation to return cash collateral against fair values of derivatives under certain circumstances, such as under master netting arrangements. Additional disclosure is also required regarding a Company’s accounting policy with respect to offsetting fair value amounts. The guidance in FIN 39-1 is effective for fiscal years beginning after November 15, 2007, with early application allowed. The effects of initial adoption should be recognized as a change in accounting principle through retrospective application for all periods presented. The Company is currently assessing the impact, if any, that the adoption of this pronouncement will have on the Company’s operating results financial position or cash flows.

In February 2007, the FASB issued SFAS 159, The Fair Value Option for Financial Assets and Financial Liabilities Including an Amendment of FASB Statement No. 115 (SFAS 159), which permits entities to choose to measure many financial instruments and certain other items at fair value (the Fair Value Option). Election of the Fair Value Option is made on an instrument-by-instrument basis and is irrevocable. At the adoption date, unrealized gains and losses on financial assets and liabilities for which the Fair Value Option has been elected would be reported as a cumulative adjustment to beginning retained earnings. If the Company elects the Fair Value Option for certain financial assets and liabilities, the Company will report unrealized gains and losses due to changes in fair value in earnings at each subsequent reporting date. The provisions of SFAS 159 are effective January 1, 2008. The Company is currently assessing the impact, if any, that the adoption of this pronouncement will have on the Company’s operating results, financial position or cash flows.

In September 2006, the FASB issued SFAS 157, Fair Value Measurements (SFAS 157), which defines fair value, establishes a framework for measuring fair value, and expands disclosures about fair value measurements. This pronouncement applies to other standards that require or permit fair value measurements. Accordingly, this statement does not require any new fair value measurement. The provisions of SFAS 157 are effective for the Company on January 1, 2008. The Company is currently assessing the impact, if any, that the adoption of this pronouncement will have on the Company’s operating results, financial position or cash flows.

Item 8. Financial Statements.

The response to this item is included in Item 15—Financial Statements.

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.

None.

Item 9A. Controls and Procedures.

(a) Disclosure Controls and Procedures.

We maintain disclosure controls and procedures that are designed to provide reasonable assurance that information required to be disclosed by us in the reports that we file or submit under the Securities Exchange Act of 1934, as amended (the “Exchange Act”) is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s (“SEC”) rules and forms. Disclosure controls and

43

procedures include processes to accumulate and evaluate relevant information and communicate such information to our management, including our Chief Executive Officer (“CEO”) and Chief Financial Officer (“CFO”), as appropriate, to allow for timely decisions regarding required disclosures.

In designing such disclosure controls and procedures, our management necessarily was required to apply its judgment in evaluating the cost-benefit relationship of possible disclosure controls and procedures. The design of any disclosure controls and procedures also is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Noting these assumptions, under the supervision and with the participation of management, including our CEO and CFO, we evaluated the effectiveness of the design and operation of our disclosure controls and procedures as of December 31, 2007, as required by Rule 13a-15(e) of the Exchange Act.

Based on this evaluation, our CEO and CFO have concluded that, as of December 31, 2007, our disclosure controls and procedures were not effective in ensuring that information required to be disclosed by us in reports filed under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. To ensure the completeness and accuracy of our financial statements and disclosures, we performed additional analysis and other post-closing procedures in an effort to ensure our consolidated financial statements included in this annual report have been prepared in accordance with generally accepted accounting principles. Accordingly, management believes that the financial statements included in this report present fairly, in all material respects, our financial condition, results of operations and cash flows for the periods presented.

(b) Management’s Annual Report on Internal Control over Financial Reporting.

Management is responsible for establishing and maintaining adequate internal control over financial reporting of our Company, as such term is defined in Rule 13(a)-15(f) under the Exchange Act. Internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of our financial statements for external reporting purposes in accordance with generally accepted accounting principles (“GAAP”). Our internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately reflect transactions and dispositions of the assets of the Company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with GAAP, and that our receipts and expenditures are being made only in accordance with authorizations of the management and directors of the Company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company’s assets that could have a material effect on our financial statements.

Internal control over financial reporting cannot provide absolute assurance of achieving financial reporting objectives because of its inherent limitations. Because of such inherent limitations, internal control over financial reporting may not prevent or detect misstatements. In addition, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions or that the degree of compliance with the policies or procedures may deteriorate.

Management conducted an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2007, based on the framework in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the “COSO Framework”) and identified certain material weaknesses, as identified below, with respect to our internal control over financial reporting as of December 31, 2007. A material weakness in internal controls over financial reporting is a significant deficiency, or a combination of significant deficiencies, such that there is a reasonable possibility that a material misstatement of the Company’s annual or interim financial statements will not be prevented or detected on a timely basis.

44

Management identified the following material weaknesses in internal control over financial reporting as of December 31, 2007:

1. Deficiencies in the Company’s Control Environment. The Company’s control environment did not sufficiently promote effective internal control over financial reporting throughout the organization. This material weakness exists because of the aggregate effect of multiple deficiencies in internal control which affect the Company’s control environment, including: a) establishment and maintenance of delegation of authority regarding the expenditure of Company funds and b) failure to implement a Code of Ethics and ensure the consistent and timely completion of employee acknowledgements of such Code of Ethics.

2. Deficiencies in the Documentation and Consistent Performance of Certain Detective Controls Surrounding Account Balances. We did not maintain effective controls over certain reconciliations. Specifically, our controls over the preparation, review and monitoring of certain account reconciliations were ineffective to provide reasonable assurance that account balances were accurate and agreed with appropriate supporting detail, calculations or other documentation. Also, the controls surrounding information used in our financial statements from a third party derivative consulting firm need strengthening.

3. Deficiencies in Segregation of Duties. The Chief Executive Officer is actively involved in the Company’s daily operations, and as such had the ability to perform incompatible duties, specifically the initiation and approval of wire transfers. The growth of the Company during 2007, combined with limited staffing, resulted in the Chief Executive Officer performing these duties. There is a risk that a material misstatement of the financial statements could be caused, or at least not detected in a timely manner, due to insufficient segregation of duties.

Based on the material weaknesses described above and the criteria set forth by the COSO Framework, we have concluded that our internal control over financial reporting at December 31, 2007, was not effective.

In light of the conclusion that our 2007 internal control over financial reporting was not effective, during fiscal 2008 we plan to implement a number of measures to remediate such ineffectiveness and strengthen our internal controls environment. The changes made through the date of this annual report include our retention of an outside consulting firm to assist us in the evaluation and testing of our internal control system and the identification of opportunities to improve the efficacy of our accounting and financial reporting processes.

We believe that the identified deficiencies stem principally from our rapid growth over a relatively short span during the final quarters of our 2007 fiscal year and may be adequately addressed through organizational and process changes. Remediation plans currently include:

1. establishing and complying with delegation of authority guidelines to be approved by the board of directors;

2. implementing formal processes requiring periodic self-assessments, independent tests, and reporting of our personnel’s adherence to our Company’s ethical requirements and accounting policies and procedures, including the imminent adoption of a Code of Ethics;

3. ensuring proper segregation of duty controls throughout our Company, including new procedures concerning wire transfers and check issuance recently adopted by our board of directors; and

4. modifying our analytical procedures to ensure the accurate, timely and complete reconciliation of all major accounts.

Our management recognizes that many of these enhancements require continual monitoring and evaluation for effectiveness. The development of these actions is an iterative process and will evolve as we continue to evaluate and improve our internal controls over financial reporting. Management will review progress on these activities on a consistent and ongoing basis at the CEO and senior management level in conjunction with our

45

board of directors. We also plan to take additional steps to elevate Company awareness about and communication of these important issues through formal channels such as Company meetings, departmental meetings, and training.

Despite the need to augment our internal controls over financial reporting, as outlined above, our management currently believes that the financial reports underlying our financial statements contained in this annual report are reliable given the organizational and process changes implemented through the date of this report.

This annual report does not include an attestation report of our registered public accounting firm regarding internal control over our financial reporting. Our management’s report was not subject to attestation by our registered public accounting firm pursuant to temporary rules of the Securities and Exchange Commission that permit the Company to provide only management’s report in this annual report.

(c) Changes in Internal Control Over Financial Reporting.

There have not been any changes in the Company’s internal control over financial reporting during the fiscal quarter ended December 31, 2007 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

Item 9B. Other Information.

None.

PART III

The information required by Part III will be incorporated by reference into this Form 10-K from the Registrant’s Definitive Proxy Statement to be filed pursuant to Regulation 14A within 120 days after the end of the Registrant’s fiscal year covered by this Form 10-K.

46

PART IV

Item 15. Exhibits, Financial Statement Schedules.

(a)(1) Financial Statements

The response to this item is submitted in a separate section of this report.

(a)(3) Exhibits

Exhibit Nos.	Description
2.1	Purchase and Sale Agreement, dated December 20, 2006, by and among the Company, Statex Petroleum I, L.P. and Charles W. Gleeson LP. (incorporated herein by reference to Exhibit 10.1 of the Company’s Form 8-K report, filed December 21, 2006).
2.1.1	Second Amendment to Purchase and Sale Agreement, dated March 9, 2007, by and among the Company, Statex Petroleum I, L.P. and Charles W. Gleeson LP (incorporated herein by reference to Exhibit 99.1 of the Company’s Form 8-K report, filed March 15, 2007).
2.2	Form of Membership Interest Redemption Agreement, dated as of March 16, 2007, by and between the Company and New Albany-Indiana, LLC (incorporated herein by reference to Exhibit 99.5 of the Company’s Form 8-K report, filed March 19, 2007).
2.3	Form of Assignment, Bill of Sale, and Conveyance, dated March 16, 2007, from New Albany-Indiana, LLC to the Company (incorporated herein by reference to Exhibit 99.6 of the Company’s Form 8-K report, filed March 19, 2007).
2.4	Asset Purchase and Sale Agreement , dated August 9, 2007, among the Company and each of DSX Energy Limited, LLP, Kebo Oil & Gas, Inc., Sanchez Oil & Gas Corp., Sue Ann Operating, L.L.C., and twenty-three other individuals, trusts, and companies (incorporated herein by reference to Exhibit 99.1 of the Company’s Form 8-K report, filed August 15, 2007).
3.1	Amended and Restated Articles of Incorporation (incorporated herein by reference to Exhibit 3.1 to the Company’s Form 8-K report, filed January 19, 2006).
3.2	By-Laws (incorporated herein by reference to Exhibit 3.2 of the Company’s registration statement on Form SB-2, filed June 25, 2004).
4.1	Form of Warrant (incorporated by reference to Exhibit 99.2 to the Company’s Form 8-K report, filed November 16, 2006).
4.2	Form of Common Stock Warrant, dated February 1, 2006 (incorporated by reference to Exhibit 4.3 to the Company’s Form 10-KSB annual report, filed March 31, 2006).
4.3	Form of Registration Rights Agreement for February Private Placement (incorporated by reference to Exhibit 10.5 of the Company’s Amendment No. 1 to this Registration Statement on Form SB-2 filed on August 1, 2006).
4.4	Form of Common Stock Warrant, dated February 1, 2006, issued to Lakewood Group, LLC (incorporated by reference to Exhibit 4.3 to the Company’s Form 10-KSB annual report, filed March 31, 2006).
4.5	Form of Warrant A-2, dated April 12, 2007, issued to Drawbridge Special Opportunities Fund LP (incorporated by reference to Exhibit 99.3 to the Company’s Form 8-K report, filed April 18, 2007).
4.6	Form of Warrant A-1, dated April 12, 2007, issued to D.B. Zwirn Special Opportunities Fund LP (incorporated by reference to Exhibit 99.4 to the Company’s Form 8-K report, filed April 18, 2007).

47

Exhibit Nos.	Description
4.7	Registration Rights Agreement, dated as of April 12, 2007, among the Company and each of Drawbridge Special Opportunities Fund LP and D.B. Zwirn Special Opportunities Fund, L.P. (incorporated herein by reference to Exhibit 99.5 of the Company's Form 8-K report, filed April 18, 2007).
4.8	Senior Secured Notes Indenture, dated as of October 1, 2007, by and among the Company and The Bank of New York, as trustee and collateral agent (incorporated herein by reference to Exhibit 4.1 of the Company’s Form 8-K report, filed October 5, 2007)
4.9 *	Form of Global 12 1/2% Senior Secured Exchange Note due 2012
4.10	Senior Notes Registration Rights Agreement, dated October 1, 2007, between the Company and Jefferies & the Company, Inc. (incorporated herein by reference to Exhibit 4.11 of the Company’s Form 8-K report, filed October 5, 2007)
4.11	Convertible Notes Indenture, dated as of October 1, 2007, by and among the Company and The Bank of New York, as trustee and collateral agent (incorporated herein by reference to Exhibit 4.6 of the Company’s Form 8-K report, filed October 5, 2007).
4.12	Form of Rule 144A Global 14% Senior Subordinated Convertible Secured Note due 2013 (incorporated herein by reference to Exhibit 4.7 of the Company’s Form 8-K report, filed October 5, 2007).
4.13	Form of Regulation S Global 14% Senior Subordinated Convertible Secured Note due 2013 (incorporated herein by reference to Exhibit 4.8 of the Company’s Form 8-K report, filed October 5, 2007).
4.14	Form of IAI Global 14% Senior Subordinated Convertible Secured Note due 2013 (incorporated herein by reference to Exhibit 4.9 of the Company’s Form 8-K report, filed October 5, 2007).
4.15	Convertible Notes Registration Rights Agreement, dated October 1, 2007, between the Company and Jefferies & the Company, Inc. (incorporated herein by reference to Exhibit 4.12 of the Company’s Form 8-K report, filed October 5, 2007)
10.1	Credit Agreement, dated October 1, 2007, among the Company, Wells Fargo Foothills, Inc., as arranger and administrative agent, and lenders named therein (incorporated herein by reference to Exhibit 10.1 of the Company’s Form 8-K report, filed October 5, 2007)
10.2	Security Agreement, dated October 1, 2007, among Wells Fargo Foothills, Inc. and the Company (incorporated herein by reference to Exhibit 10.2 of the Company’s Form 8-K report, filed October 5, 2007)
10.3	Intercreditor Agreement, dated October 1, 2007, among Wells Fargo Foothills, Inc., The Bank of New York and the Company (incorporated herein by reference to Exhibit 10.3 of the Company’s Form 8-K report, filed October 5, 2007)
10.4	Senior Notes Security Agreement, dated October 1, 2007, among The Bank of New York Trust the Company, NA, as collateral agent, and the Company (incorporated herein by reference to Exhibit 4.5 of the Company’s Form 8-K report, filed October 5, 2007)
10.5	Convertible Notes Security Agreement, dated October 1, 2007, among The Bank of New York Trust the Company, NA, as collateral agent, and the Company (incorporated herein by reference to Exhibit 4.10 of the Company’s Form 8-K report, filed October 5, 2007)
10.6	Form of Stock Option Agreement issued in April 2005 by the Company to Barrie Damson and Alan Gaines (incorporated herein by reference to Exhibit 99.1 of the Company’s Form 8-K report, filed May 3, 2005).

48

Exhibit Nos.	Description
10.7	Employment Agreement, dated December 5, 2006, by and between the Company and Thomas Kaetzer (incorporated herein by reference to Exhibit 10.2 of the Company’s Form 8-K report, filed December 21, 2006.
10.8	Stock Option Agreement, dated December 20, 2006, by and between the Company and Thomas Kaetzer (incorporated herein by reference to Exhibit 10.3 of the Company’s Form 8-K report, filed December 21, 2006).
10.9	Stock Option Agreement, dated December 20, 2006, by and between the Company and Thomas Kaetzer (incorporated herein by reference to Exhibit 10.4 of the Company’s Form 8-K report, filed December 21, 2006).
10.10	Stock Option Agreement, dated December 20, 2006, by and between the Company and Thomas Kaetzer (incorporated herein by reference to Exhibit 10.5 of the Company’s Form 8-K report, filed December 21, 2006).
10.11	Employment Agreement, dated August 3, 2007, by and between the Company and Patrick McGarey (incorporated herein by reference to Exhibit 99.1 of the Company’s Form 8-K report, filed August 6, 2007).
10.12	Stock Option Agreement, dated August 3, 2007, by and between the Company and Patrick McGarey (incorporated herein by reference to Exhibit 99.2 of the Company’s Form 8-K report, filed August 6, 2007).
10.13	Purchase Agreement, dated September 17, 2007, between the Company and Jefferies & Company, Inc. (incorporated herein by reference to Exhibit 10.1 of the Company’s Form 8-K report, filed September 20, 2007).
10.14 *	Form of Lease Agreement, dated October 26, 2007, between the Company and 411 NSHP Partner, LP.
10.14.1 *	Lease Addendum, dated October 26, 2007, between the Company and 411 NSHP Partner, LP.
23.1 *	Consent of Cawley, Gillespie & Associates, Inc.
31.1 *	Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
31.2 *	Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
32.1 *	Certification pursuant to 18 U.S.C. 1350, adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, by Chief Executive Officer
32.2 *	Certification pursuant to 18 U.S.C. 1350, adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, by Chief Financial Officer
99.1 *	Evaluation Summary—Reserve Report of Independent Petroleum Engineering Firm*

(*) Indicates filed herewith

49

BASELINE OIL & GAS CORP.

INDEX TO FINANCIAL STATEMENTS

	PAGE
Baseline Oil & Gas Corp. –
Report of Independent Registered Public Accounting Firm	F-2
Balance Sheets at December 31, 2007 and 2006	F-3
Statements of Operations for the Years Ended December 31, 2007 and 2006	F-5
Statements of Cash Flows for the Years Ended December 31, 2007 and 2006	F-6
Statements of Changes in Stockholders’ Equity (Deficit) for Years Ended December 31, 2007 and 2006	F-7
Notes to Financial Statements	F-8

F-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors

Baseline Oil & Gas Corp.

Houston, Texas

We have audited the accompanying balance sheets of Baseline Oil & Gas Corp. (a Nevada Corporation) as of December 31, 2007 and 2006, and the related statements of operations, stockholders’ equity (deficit), and cash flows for the two years then ended. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform an audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, 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 Oil & Gas Corp. as of December 31, 2007 and 2006 and the results of operations and cash flows for the two years then ended, in conformity with accounting principles generally accepted in the United States of America.

/s/ Malone & Bailey, PC

www.malone-bailey.com

Houston, Texas

March 31, 2008

F-2

BASELINE OIL & GAS CORP.

BALANCE SHEETS

	December 31, 2007			December 31, 2006
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	5,014,455		$	123,678
Short term Investments—trading securities		13,901,275			—
Accounts receivable, trade		3,774,033			—
Deferred loan costs		2,310,975			—
Prepaid and other current assets		111,884			125,000
Total current assets		25,112,622			248,678
OIL AND NATURAL GAS PROPERTIES—using successful efforts method of accounting
Proved properties		128,381,629			—
Unproved properties		8,475,666			7,810,135
Less accumulated depletion, depreciation and amortization		(1,823,233	)		—
Oil and natural gas properties, net		135,034,062			7,810,135
Deferred acquisition costs		—			99,631
Property acquisition—deposit		—			1,000,000
Other assets		15,989			—
Deferred loan costs, net of accumulated amortization of $6,390,283 and $237,192 at December 31, 2007 and 2006, respectively		13,038,093			89,947
Other property and equipment, net of accumulated depreciation of $17,519 at December 31, 2007		184,551			—
TOTAL ASSETS	$	173,385,317		$	9,247,391

The accompanying notes are an integral part of the financial statements

F-3

BASELINE OIL & GAS CORP.

BALANCE SHEETS

	December 31, 2007			December 31, 2006
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES
Accounts payable	$	2,151,549		$	82,873
Accrued expenses		5,540,607			172,750
Royalties payable		3,827,901			—
Taxes payable		252,529
Short term debt and current portion of long-term debt		65,006			1,996,751
Derivative liabilities—short term		3,076,709			104,896
Total current liabilities		14,914,301			2,357,270
Long term debt, net of discount of $4,436,137 at December 31, 2007		160,816,395			—
Asset retirement obligations		282,947
Derivative liabilities—long term		5,759,471			—
Total liabilities		181,773,114			2,357,270
COMMITMENTS AND CONTINGENCIES		—			—
STOCKHOLDERS’ EQUITY (DEFICIT)
Common stock, $0.001 par value per share; 140,000,000 shares authorized; 34,408,006 and 31,342,738 shares issued and outstanding, respectively		34,408			31,343
Additional paid-in capital		33,617,266			28,423,418
Accumulated other comprehensive income (loss)		(7,362,151	)		—
Accumulated deficit		(34,677,320	)		(21,564,640	)
Total stockholders’ equity (deficit)		(8,387,797	)		6,890,121
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY (DEFICIT)	$	173,385,317		$	9,247,391

The accompanying notes are an integral part of the financial statements

F-4

BASELINE OIL & GAS CORP.

STATEMENTS OF OPERATIONS

	Year Ended December 31,
	2007			2006
REVENUES
Oil and gas sales	$	13,970,654		$	—
Oil and gas hedging		(2,361,614	)		—
Total revenue		11,609,040
COSTS AND EXPENSES
Lease operating expense		5,148,418			—
General and administrative		3,406,450			2,599,501
Depreciation, depletion and amortization		1,840,752			—
Accretion expense		41,988			—
Total costs and expenses		10,437,608			2,599,501
Net income (loss) from operations		1,171,432			(2,599,501	)
OTHER INCOME (EXPENSE)
Other income		66,407			—
Interest income		98,885			117,630
Interest expense		(14,094,504	)		(1,691,788	)
Unrealized gain on marketable securities		45,875
Unrealized gain on derivative instruments		—			400,775
Total other expense, net		(13,883,337	)		(1,173,383	)
NET LOSS	$	(12,711,905	)	$	(3,772,884	)
OTHER COMPREHENSIVE INCOME (LOSS)
Unrealized gain (loss) on derivative instruments		(7,362,151	)		—
Total comprehensive loss	$	(20,074,056	)	$	(3,772,884	)
NET LOSS PER SHARE—Basic and Diluted	$	(0.39	)	$	(0.11	)
WEIGHTED AVERAGE NUMBER OF SHARES OUTSTANDING		32,554,343			33,989,119

The accompanying notes are an integral part of the financial statements

F-5

BASELINE OIL & GAS CORP.

STATEMENTS OF CASH FLOWS

	Year Ended December 31,
	2007			2006
CASH FLOWS FROM OPERATING ACTIVITIES
Net loss	$	(12,711,905	)	$	(3,772,884	)
Adjustments to reconcile net loss to net cash Used in operating activities
Share based compensation		816,365			720,874
Common stock issued for services		360,000			—
Depreciation, depletion and amortization		1,840,752			—
Amortization of debt discount		576,812			1,206,577
Amortization of deferred loan costs		6,153,091			237,192
Stock issued as penalty for delayed registration		—			594,000
Loss (gain) on derivative instruments		1,893,069			(400,775	)
Unrealized (gain)loss on marketable securities		(45,875	)		—
Accretion expense		41,988			—
Changes in operating assets and liabilities
Accounts receivable, trade		(3,774,033	)		—
Prepaid and other current assets		96,838			(125,000	)
Accounts payable—trade		2,068,676			—
Accrued liabilities		5,846,589			345,967
Royalties payable		3,827,901			—
Net cash provided by (used in) operating activities		6,990,268			(1,194,049	)
CASH FLOWS FROM INVESTING ACTIVITIES
Acquisition of proved oil and gas properties		(124,490,793	)		—
Deposit on acquisition		—			(1,000,000	)
Deferred acquisition costs incurred		—			(99,631	)
Development costs incurred		(5,228,246	)		—
Additions to unproved properties		(665,531	)		(6,060,135	)
Premiums paid for hedge contracts		(419,040	)		—
Purchase of marketable securities		(15,851,790	)		—
Proceeds from sale of marketable securities		1,996,390			—
Purchase of property and equipment, other		(202,070	)		—
Net cash used in investing activities		(144,861,080	)		(7,159,766	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from debt		195,847,305			—
Repayments of debt		(36,914,178	)		(16,496	)
Debt issuance costs incurred		(16,171,538	)		—
Proceeds from exercise of stock options		—			12,500
Proceeds from common stock sales, net		—			8,275,000
Net cash provided by financing activities		142,761,589			8,271,004
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		4,890,777			(82,811	)
CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR		123,678			206,489
CASH AND CASH EQUIVALENTS, END OF YEAR	$	5,014,455		$	123,678
SUPPLEMENTAL DISCLOSURES:
Cash paid for interest		1,571,815			50,000
Cash paid for income taxes		—			—
NON-CASH ACTIVITIES
Unrealized gain/(loss) on derivative liability		(7,362,151	)		—
Warrants issued in conjunction with debt		2,373,674			—
Overriding royalty interest granted in conjunction with debt		2,678,000
Stock issued for note extension		190,000			—
Asset retirement obligation incurred		240,959			—
Warrants issued in conjunction with stock issuance		—			505,671
Stock issued on conversion of debt		725,000			359,109
Stock issued in lieu of cash interest		226,203			187,500

The accompanying notes are an integral part of the financial statements

F-6

BASELINE OIL & GAS CORP.

STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY (DEFICIT)

	Common Stock					Paid-in Capital			Other Comprehensive Loss			Accumulated Deficit			Total Equity
	Shares		Amount
Balance at December 31, 2005	20,270,000		$	20,270		$	18,791,179		$	—		$	(17,791,756	)	$	1,019,693
Stock issued in merger	12,069,250			12,069			1,194,856			—			—			1,206,925
Sale of common stock	8,181,818			8,182			8,991,818			—			—			9,000,000
Equity issuance costs	—			—			(1,230,671	)		—			—			(1,230,671	)
Stock issued on conversion of debt	1,820,000			1,820			357,289			—			—			359,109
Return of stock issued in merger	(12,069,250	)		(12,069	)		(1,194,856	)		—			—			(1,206,925	)
Stock issued in lieu of cash interest	375,000			375			187,125			—			—			187,500
Stock-based compensation	—			—			720,874			—			—			720,874
Stock issued as penalty for delayed registration	445,920			446			593,554			—			—			594,000
Stock issued for exercise of stock options	250,000			250			12,250			—			—			12,500
Net loss	—			—			—			—			(3,772,884	)		(3,772,884	)
Balance at December 31, 2006	31,342,738		$	31,343		$	28,423,418			—		$	(21,564,640	)	$	6,890,121
Fair value of warrants issued in conjunction with debt	—			—			2,373,674			—			—			2,373,674
Stock-based compensation	—			—			816,365			—			—			816,365
Stock issued for services	600,000			600			359,400			—			—			360,000
Stock issued for note extension	380,000			380			189,620			—			—			190,000
Stock issued on conversion of debt	1,450,000			1,450			723,550			—			—			725,000
Stock issued in lieu of cash interest	393,032			393			225,810			—			—			226,203
Stock issued for cashless exercise of stock options	242,236			242			(242	)		—			—
Cumulative change in derivative liability	—			—			505,671			—			(400,775	)		104,896
Unrealized loss on hedge contracts	—			—			—			(7,362,151	)					(7,362,151	)
Net loss	—			—			—						(12,711,905	)		(12,711,905	)
Balance at December 31, 2007	34,408,006		$	34,408		$	33,617,266		$	(7,362,151	)	$	(34,677,320	)	$	(8,387,797	)

The accompanying notes are an integral part of the financial statements

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Baseline Oil & Gas Corp.

Notes to Financial Statements

December 31, 2007

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.

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.

The most critical estimate the Company uses is the engineering estimate of proved oil and gas reserves. This estimate affects the application of the successful efforts method of accounting, the calculation of depreciation and depletion of oil and gas properties and the estimate of the impairment of the Company’s oil and gas properties. It also affects the estimated lives of the Company’s assets used to determine asset retirement obligations.

Successful Efforts Method Accounting

The Company 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.

Impairment of Oil and Natural Gas Properties

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. An asset would be impaired if the undiscounted cash flows were less than its carrying value. Impairments are measured by the amount by which the carrying value exceeds its fair value. Because the Company uses the successful efforts method, the Company assesses its properties individually for impairment, instead of on an aggregate pool of costs.

Depreciation and Depletion of Oil and Natural Gas Properties

Capitalized costs of producing oil and gas properties, after considering estimated residual salvage values, are depreciated and depleted by the unit-of-production method. This method is applied through the simple multiplication of reserve units produced by the leasehold costs per unit on a field by field basis. Leasehold cost per unit is calculated by dividing the total cost of acquiring the leasehold by the estimated total proved oil and gas reserves associated with that lease. Field cost is calculated by dividing the total cost by the estimated total proved producing oil and gas reserves associated with that field.

Sale or Retirement of Oil and Natural Gas Properties

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.

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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 SFAS No. 143 “Accounting for Asset Retirement Obligations.” Under this method, when liabilities for dismantlement and abandonment costs (ARO) 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 is required to recognize a gain or loss if the actual costs do not equal the estimated costs included in ARO.

Concentrations of Credit Risk

All of the Company’s receivables are due from oil and natural gas purchasers. The Company sold 89% of its oil and natural gas production to three customers in 2007.

The Company maintains its cash in bank deposit accounts which, at times, may exceed federally insured limits. Accounts are guaranteed by the FDIC up to $100,000. At December 31, 2007, the Company had approximately $4,774,678 in excess of FDIC insured limits. The Company has not experienced any losses in such accounts.

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 its interest in the properties. Costs associated with production are expensed in the period incurred.

Cash and cash equivalents

Cash and cash equivalents include cash in banks and liquid deposit with maturities of three months or less.

Short-term Investments

The Company’s short-term investments consist primarily of U. S. government and agency securities and investment grade corporate notes and bonds, all of which are classified as trading securities. Trading securities are recorded at fair value, and unrealized holding gains and losses are included in net earnings. The maximum maturity of securities is two years at the time of purchase with an average maturity not to exceed one year for the entire portfolio. Available-for-sale securities are classified as short-term based on their highly liquid nature and because such marketable securities represent the investment of cash that is available for current operations. Realized gains and losses are accounted for on the specific identification method. Purchases and sales are recorded on a trade date basis.

Fair Value of Financial Instruments

The carrying value of cash and cash equivalents approximates fair value because of the short-term maturity of those instruments. The fair value of the Company’s investments in marketable debt securities is based on the

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quoted market price on the last business day of the year. Declines in fair value below the Company’s carrying value deemed to be other than temporary are charged against net earnings. The carrying value of short-term and long-term debt approximates fair value.

Property and Equipment

Support equipment and other property and equipment are valued at cost and depreciated over their estimated useful lives, using the straight-line method over estimated useful lives of 3 to 5 years. Additions are capitalized and maintenance and repairs are charged to expense as incurred. Gains and losses on dispositions of equipment are reflected in income or loss from operations.

Stock-based compensation

On January 1, 2006, the Company 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 stock-based payments to employees, including grants of employee stock options, to be recognized in the financial statements based on their fair values.

Loss per share

Basic earnings per share amounts are calculated based on the weighted average number of shares of common stock outstanding during each period. Diluted earnings per share is based on the weighted average numbers of shares of common stock outstanding for the periods, including the dilutive effects of stock options, warrants granted and convertible preferred stock. Dilutive options and warrants that are issued during a period or that expire or are canceled during a period are reflected in the computations for the time they were outstanding during the periods being reported. Since the Company has incurred losses for all periods, the impact of the common stock equivalents would be antidilutive and therefore are not included in the calculation.

Derivatives

Derivative financial instruments, utilized to manage or reduce commodity price risk related to Baseline’s production, are accounted for under the provisions of SFAS No. 133, “Accounting for Derivative Instruments and for Hedging Activities”, and related interpretations and amendments. Under this statement, derivatives are carried on the balance sheet at fair value. If the derivative is designated as a fair value hedge, the changes in the fair value of the derivative and of the hedged item attributable to the hedged risk are recognized in earnings. If the derivative is designated as a cash flow hedge, the effective portions of changes in the fair value of the derivative are recorded in other comprehensive income or loss and are recognized in the statement of operations when the hedged item affects earnings. If the derivative is not designated as a hedge, changes in the fair value are recognized in other expense. Ineffective portions of changes in the fair value of cash flow hedges are also recognized in loss on derivative liabilities.

Income taxes

The Company 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. The Company provides a valuation allowance for deferred tax assets for which it does not consider realization of such assets to be more likely than not.

In July 2006, the FASB issued Financial Interpretation (FIN) 48, Accounting for Uncertainty in Income Taxes—an Interpretation of FASB 109 (FIN 48). FIN 48 created a single model to address accounting for the uncertainty in income tax positions and prescribes a minimum recognition threshold a tax position must meet before recognition in the financial statements.

The evaluation of a tax position in accordance with FIN 48 is a two-step process. The first step is a recognition process to determine whether it is more likely than not that a tax position will be sustained upon

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examination, including resolution of any related appeals or litigation processes, based on the technical merits of the position. In evaluating whether a tax position has met the more likely than not recognition threshold, it is presumed that the position will be examined by the appropriate taxing authority with full knowledge of all relevant information. The second step is a measurement process whereby a tax position that meets the more likely than not recognition threshold is calculated to determine the amount of benefit/expense to recognize in the financial statements. The tax position is measured at the largest amount of benefit/expense that is more likely than not of being realized upon ultimate settlement.

The Company adopted the provisions of FIN 48 effective January 1, 2007 which did not have a material impact on the Company’s operating results, financial position or cash flows. The Company did not record a cumulative effect adjustment related to the adoption of FIN 48.

New Accounting Pronouncements

In June 2006, the Financial Accounting Standards Board issued FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109” (FIN 48). This Interpretation provides guidance on recognition, classification and disclosure concerning uncertain tax liabilities. The evaluation of a tax position requires recognition of a tax benefit if it is more likely than not it will be sustained upon examination. The Company adopted this Interpretation effective January 1, 2007. The adoption did not have a material impact on its financial statements.

In September 2000, the Emerging Issues Task Force issued EITF 00-19, “Accounting for Derivative Financial Instruments Indexed to and Potentially Settled in, a Company’s Own Stock,” (“EITF 00-19”) which Requires freestanding contracts that are settled in a company’s own stock, including common stock warrants, to be designated as an equity instrument, asset or a liability. Under the provisions of EITF 00-19, a contract designated as an asset or a liability must be carried at fair value on a company’s balance sheet, with any changes in fair value recorded in the company’s results of operations. A contract designated as an equity instrument must be included within equity, and no fair value adjustments are required.

During 2006, we issued warrants in connection with the sale of our common stock. Under the terms of the agreement, we agreed to register the underlying shares issuable upon exercise of the warrants. Under the accounting guidance at that time, this registration right was accounted for as a derivative. In December 2006, the FASB issued FASB Staff Position No. EITF 00-19-2, Accounting for Registration Payment Arrangements. EITF 00-19-2 addresses an issuer’s accounting for registration payment arrangements. It specifies that the contingent obligation to make future payments or otherwise transfer consideration under a registration payment arrangement, whether issued as a separate agreement or included as a provision of a financial instrument or other agreement, should be separately recognized and measured in accordance with FASB Statement No. 5, Accounting for Contingencies. The guidance in EITF 00-19-2 amends FASB Statements No. 133, Accounting for Derivative Instruments and Hedging Activities, and No. 150, Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity, and FASB Interpretation No. 45, Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others, to include scope exceptions for registration payment arrangements. EITF 00-19-2 also requires additional disclosure regarding the nature of any registration payment arrangements, alternative settlement methods, the maximum potential amount of consideration and the current carrying amount of the liability, if any. This EITF is effective immediately for registration payment arrangements and the financial instruments subject to those arrangements that are entered into or modified subsequent to the date of issue of this EITF. For registration payment arrangements and financial instruments subject to those arrangements that were entered into prior to the issuance of this EITF, this is effective for financial statements issued for fiscal years beginning after December 15, 2006, and interim periods within those fiscal years. The impact of implementing EITF 00-19-2 in the fiscal year 2007 resulted in a cumulative effect of a change in accounting principle with an increase to accumulated deficit of $400,775 and a decrease to the derivative liability of $104,896, totaling a $505,071 increase in additional paid in capital account.

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In December 2007, the FASB issued Statement SFAS No. 141, Business Combinations (SFAS 141R), and Statement of Financial Accounting Standards No. 160, Accounting and Reporting of Noncontrolling Interest in Consolidated Financial Statements, an amendment of ARB No. 51 (SFAS 160). SFAS 141R and SFAS 160 will significantly change the accounting for and reporting of business combination transactions and noncontrolling (minority) interests in consolidated financial statements. SFAS 141R retains the fundamental requirements in Statement 141, Business Combinations, while providing additional definitions, such as the definition of the acquirer in a purchase and improvements in the application of how the acquisition method is applied. SFAS 160 will change the accounting and reporting for minority interests, which will be recharacterized as noncontrolling interests, and classified as a component of equity. These Statements become simultaneously effective January 1, 2009. Early adoption is not permitted. The Company is currently assessing the impact, if any, that the adoption of this pronouncement will have on the Company’s operating results financial position or cash flows.

In May 2007, the FASB issued FSP No. FIN 48-1, Definition of Settlement in FASB Interpretation No. 48, (FIN 48-1) which amends FIN 48 and provides guidance concerning how an entity should determine whether a tax position is “effectively,” rather than the previously required “ultimately,” settled for the purpose of recognizing previously unrecognized tax benefits. In addition, FIN 48-1 provides guidance on determining whether a tax position has been effectively settled. The guidance in FIN 48-1 is effective upon the initial January 1, 2007 adoption of FIN 48. Companies that have not applied this guidance must retroactively apply the provisions of this FSP to the date of the initial adoption of FIN 48. The Company has adopted FIN 48-1 and no retroactive adjustments were necessary.

In April 2007, the FASB issued Staff Position (FSP) No. FIN 39-1, Amendment of FASB Interpretation No. 39, (FIN 39-1) to amend FIN 39, Offsetting of Amounts Related to Certain Contracts (FIN 39). The terms “conditional contracts” and “exchange contracts” used in FIN 39 have been replaced with the more general term “derivative contracts.” In addition, FIN 39-1 permits the offsetting of recognized fair values for the right to reclaim cash collateral or the obligation to return cash collateral against fair values of derivatives under certain circumstances, such as under master netting arrangements. Additional disclosure is also required regarding a Company’s accounting policy with respect to offsetting fair value amounts. The guidance in FIN 39-1 is effective for fiscal years beginning after November 15, 2007, with early application allowed. The effects of initial adoption should be recognized as a change in accounting principle through retrospective application for all periods presented. The Company is currently assessing the impact, if any, that the adoption of this pronouncement will have on the Company’s operating results financial position or cash flows.

In February 2007, the FASB issued SFAS 159, The Fair Value Option for Financial Assets and Financial Liabilities Including an Amendment of FASB Statement No. 115 (SFAS 159), which permits entities to choose to measure many financial instruments and certain other items at fair value (the Fair Value Option). Election of the Fair Value Option is made on an instrument-by-instrument basis and is irrevocable. At the adoption date, unrealized gains and losses on financial assets and liabilities for which the Fair Value Option has been elected would be reported as a cumulative adjustment to beginning retained earnings. If the Company elects the Fair Value Option for certain financial assets and liabilities, the Company will report unrealized gains and losses due to changes in fair value in earnings at each subsequent reporting date. The provisions of SFAS 159 are effective January 1, 2008. The Company is currently assessing the impact, if any, that the adoption of this pronouncement will have on the Company’s operating results, financial position or cash flows.

In September 2006, the FASB issued SFAS 157, Fair Value Measurements (SFAS 157), which defines fair value, establishes a framework for measuring fair value, and expands disclosures about fair value measurements. This pronouncement applies to other standards that require or permit fair value measurements. Accordingly, this statement does not require any new fair value measurement. The provisions of SFAS 157 are effective for the Company on January 1, 2008. The Company is currently assessing the impact, if any, that the adoption of this pronouncement will have on the Company’s operating results, financial position or cash flows.

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NOTE 2—SHORT-TERM INVESTMENTS

The Company’s short-term investments consist of the following:

	December 31, 2007
	Cost		Unrealized Gain (Loss)			Fair Value
Short term investments—trading securities
U.S. government and agency notes	$	3,713,696	$	21,422		$	3,735,118
Commercial paper		7,895,439		32,036			7,927,475
Corporate debt securities		2,246,265		(7,583	)		2,238,682
	$	13,855,400	$	45,875		$	13,901,275

NOTE 3—ACQUISITIONS

On April 12, 2007, Baseline acquired producing oil and natural gas properties located in Stephens County, Texas, 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 the Eliasville Field. The preliminary adjusted purchase price was $26.6 million. 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 5).

On October 1, 2007 Baseline acquired producing natural gas and oil properties located in Matagorda County, Texas, from DSX Energy Limited LLP, Kebo Oil & Gas, Inc., and 25 other related parties for an preliminary adjusted purchase price of $96.6 million. The properties acquired by us consist of a greater than 95% working interest in 2,374 net acres in the Blessing Field which contained twelve (12) producing wells. The effective date of the acquisition was June 1, 2007.

The Blessing Field acquisition was funded with proceeds from the Company's issuance of $115 million of 12.5% Senior Secured Notes due 2012 at a purchase price of $110.9 million, plus $50 million of 14.0% Senior Subordinated Convertible Secured Notes due 2013 at a purchase price of $49.5 million (see Note 5). In addition, Baseline retired $33.1 million of indebtedness with proceeds of the Offering, with the remainder being utilized for general corporate purposes, fees and expenses. Baseline also entered into a $20 million credit facility with a senior lender. The line of credit will be used for implementing the Company’s oil and natural gas hedging strategy, and for working capital if needed. The line of credit was not drawn at closing.

The following unaudited pro forma information assumes the acquisitions occurred as of the beginning of each period. The pro forma results are not necessarily indicative of what actually would have occurred had the acquisition been in effect for the period presented.

	As Reported			Pro Forma
Year ended December 30, 2007
Revenues	$	11,609,040		$	33,295,512
Net Loss		(12,711,905	)		(19,264,526	)
Loss Per Share		(0.39	)		(0.59	)
Year ended December 31, 2006
Revenues	$	—		$	29,565,117
Net Loss		(3,772,884	)		(18,532,626	)
Loss Per Share		(0.11	)		(0.55	)

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NOTE 4—COMMITMENTS AND CONTINGENCIES

From time to time Baseline may become involved in litigation in the ordinary course of business. At the present time the Company’s management is not aware of any such litigation.

The Company, as an owner or lessee and operator of oil and gas properties, is subject to various federal, state and local laws and regulations relating to discharge of materials into, and protection of, the environment. These laws and regulations may, among other things, impose liability on the lessee under an oil and gas lease for the cost of pollution clean-up resulting from operations and subject the lessee to liability for pollution damages. In some instances, the Company may be directed to suspend or cease operations in the affected area. We maintain insurance coverage, which we believe is customary in the industry, although we are not fully insured against all environmental risks. The Company is not aware of any environmental claims existing as of December 31, 2007, which have not been provided for, covered by insurance or otherwise have a material impact on its financial position or results of operations. There can be no assurance, however, that current regulatory requirements will not change, or past non-compliance with environmental laws will not be discovered on the Company’s properties.

The Company has a long-term operating lease agreement for its corporate offices that in October 2012. Rent expense for the year ended December 31, 2007 was $63,909.

Minimum rentals for each of the five years subsequent to December 31, 2007 are as follows:

2008	$	126,890
2009		141,468
2010		142,095
2011		145,231
2012		121,026
Thereafter		—
	$	676,710

NOTE 5—DEBT

Total debt at December 31, 2007 and 2006 consists of the following:

	December 31, 2007			December 31, 2006
Short term notes	$	65,006		$	48,750
Convertible notes, net of discount		—			1,948,001
Senior secured notes		111,051,530			—
Subordinated Convertible notes		49,512,333			—
Revolving line of credit		252,532			—
		160,881,401			1,996,751
Less short term debt and current portion of long-term debt		(65,006	)		(1,996,751	)
Long-term debt	$	160,816,395		$	—

Future maturities of long-term debt are as follows as of December 31, 2007:

2009	$	—
2010		252,532
2011		—
2012		111,051,530
2013		49,512,333
Thereafter		—
	$	160,816,395

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Senior Secured Notes

The Senior Secured Notes, bearing interest at the rate of 12 ¹/2 % per annum, were issued October 1, 2007. Interest is payable in cash semi-annually on each of April 1 and October 1, commencing on April 1, 2008. The Senior Secured Notes were issued at a discount of 96.447%. In addition, the Company capitalized $10,171,738 in costs associated with the issuance of the debt which has been capitalized as a deferred loan cost. The original discount and the deferred loan costs are being amortized over the term of the debt using the effective interest rate of 16.15%. The Senior Secured Notes mature on October 1, 2012.

The Senior Secured Notes contain customary representations and warranties on its part as well as typical restrictive covenants whereby the Company has agreed, among other things, to limitations on incurrence of additional indebtedness, limitations on capital expenditures, declaration of dividends, issuance of capital stock, sale of assets and corporate reorganizations, as well as impairment of collateral securing its obligations under the Senior Secured Notes. In addition, financial covenants under the Senior Notes Indenture preclude the Company from exceeding certain ratios, as measured quarterly commencing March 31, 2008 and which decrease over time, of the Company’s outstanding total indebtedness or senior secured indebtedness to its EBITDA for the four prior consecutive fiscal quarters, as adjusted for any disposition of assets or discontinued operations during the applicable period.

The Company also must maintain a ratio of PV-10 to senior secured indebtedness of no less than 1.40, as measured on each June 30th and December 31st beginning December 31, 2007. The PV-10 measure is based on the sum of all of the discounted future net cash flows discounted at 10% of the Company’s unrisked proved reserves using the most recent NYMEX strip pricing, with adjustments for basis differentials, Btu content and any price hedges in place. The senior secured indebtedness measure is the total of outstanding balances under the Senior Secured Notes and the Wells Fargo Agreement, net of total cash and cash equivalents. The Company is in compliance with this covenant as of December 31, 2007, with a calculated PV-10 to Senior Secured Indebtedness ratio of 2.67.

The Senior Secured Notes rank senior in right of payment to all existing and future subordinated indebtedness of the Company, including indebtedness of the Company outstanding under the Convertible Notes and rank equally in right of payment with all its other existing and future senior indebtedness of the Company.

The Senior Secured Notes are subject to redemption by the Company, at its option, prior to October 1, 2010 at a redemption price equal to the aggregate principal amount plus accrued interest plus a make whole premium equal to the greater of 1.0% or the present value of the notes at October 1, 2010 and of all required interest payments on the notes as if paid in cash from the date of such redemption through October 1, 2010 (excluding accrued but unpaid interest to the redemption date), computed using a discount rate, as determined on the date of redemption, equal to 0.5% over the yield to maturity of the then most recently issued U.S. Treasury securities having a maturity date closest to October 1, 2010, or, in connection with equity offerings prior to October 1, 2010, at a repurchase price equal to 113.5% of the aggregate principal amount plus accrued interest for up to 35% of the outstanding principal amount of the Senior Secured Notes, After October 1, 2010, the Senior Secured Notes may be redeemed by the Company at a premium which decreases over time. Holders of the Senior Secured Notes may put such notes to us for repurchase, at a repurchase price of 101% of the principal amount plus accrued interest, upon a change in control.

In addition, the Company shall be obligated to make an offer to purchase the Senior Secured Notes if, for any applicable fiscal year (the initial period to extend from the issuance date of the notes to December 31, 2007), the excess of the Company’s EBITDA and decreases in working capital (excluding cash and cash equivalents) over the sum of any increase in the Company’s working capital, together with its capital expenditures, permanent repayment or prepayment of senior secured indebtedness and aggregate payments in cash of interest expense and income and franchise taxes (the “Excess Cash Flow”) exceeds $2.5 million, as calculated as of December 31st. The purchase price at which the Company shall repurchase any Senior Secured Notes tendered by the note

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holders shall be equal to 101% of the principal amount, plus accrued but unpaid interest and additional interest, if any, thereon to the date of the offer to purchase. The Company will not be required to make an offer to purchase if the Excess Cash Flow for any period is less than $2.5 million. If the Company has Excess Cash Flow for any fiscal year ending after December 31, 2009, then the Company shall only be obligated to make an offer equal to 50% of such Excess Cash Flow for such period. The Company has determined that it’s Excess Cash Flow for the period ending December 31, 2007 did not exceed $2.5 million; therefore, the Company will not be required to make an offer to repurchase Senior Secured Notes for this period under the Excess Cash Flow covenant.

The Senior Secured Notes are secured by a second lien on substantially all of the Company’s assets.

Subordinated Convertible Notes

The Subordinated Convertible Notes, bearing interest at an annual rate of 14% per annum, were issued October 1, 2007. Interest is payable semi-annually on each of April 1 and October 1, commencing on April 1, 2008, in cash or by delivery of Paid in Kind (“PIK”) Notes. The Subordinated Convertible Notes were issued at a discount of 99%. In addition, the Company capitalized $4,942,299 in costs associated with the issuance of the debt which has been capitalized as a deferred loan cost. The original discount and the deferred loan costs are being amortized over the term of the debt using the effective interest rate of 16.90%. The Subordinated Convertible Notes contain customary representations and warranties on its part as well as typical restrictive covenants whereby the Company has agreed, among other things, to limitations on incurrence of additional indebtedness, limitations on capital expenditures, declaration of dividends, issuance of capital stock, sale of assets and corporate reorganizations, as well as impairment of collateral securing its obligations under the Convertible Notes. In addition, financial covenants under the Convertible Notes Indenture preclude the Company from exceeding certain ratios, as measured quarterly commencing March 31, 2008 and which decrease over time, of the Company’s outstanding total indebtedness or senior secured indebtedness to its EBITDA for the four prior consecutive fiscal quarters, as adjusted for any disposition of assets or discontinued operations during the applicable period. The Convertible Notes mature on October 1, 2013.

The Subordinated Convertible Notes will rank junior in right of payment to all existing and future senior indebtedness of the Company, including the Senior Secured 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.

The Subordinated Convertible Notes are initially convertible into 69.444 million shares of its common stock, par value $.001 per share (the “Common Stock”), based on an initial conversion price of $0.72 per share and reflecting an approximate 15% conversion premium to the $0.63 per share closing price of its Common Stock on September 17, 2007. There is a one-time test for downward adjustment of the conversion price, effective as of January 1, 2009, based upon maintaining a specified average trading price of its Common Stock for the 30 trading days up to and including December 31, 2008. If the Company meets or exceeds this target of at least $0.63, there will be no adjustment. If the Company fails to meet or exceed this target per share price of $0.63, then effective January 1, 2009 the conversion price then in effect will decrease to the higher of $0.44 or the volume weighted average price of the Common Stock for such 30 trading days up to and including December 31, 2008 plus 5%. The interest rate on the notes will also be increased by 300 basis at such time in the event that the conversion price is adjusted to $0.44. In addition, the conversion price of the Convertible Notes will be subject to adjustment pursuant to customary anti-dilution provisions and may also be adjusted upon the occurrence of a fundamental change. Holders converting Convertible Notes prior to October 1, 2010 will be entitled to receive a certain make whole premium, consisting of the present value of all required interest payments on the notes as if paid in cash from the date of such conversion through October 1, 2010 (including accrued but unpaid interest), computed using a discount rate, as determined on the date of conversion, equal to 0.5% over the yield to maturity of the then most recently issued U.S. Treasury securities having a maturity date closest to October 1, 2010. The Company, at its option, may pay such make-whole premium in shares of

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Common Stock valued at a 10% discount to the Common Stock’s volume weighted average sale prices for the 10 consecutive trading days prior to the conversion date.

The Subordinated Convertible Notes are redeemable up to 25% by us on a quarterly basis beginning October 1, 2009 in the event the closing price of its Common Stock equals a 150% or more of the conversion price then in effect over a specified number of trading days. The Convertible Notes are redeemable at the option of the holder upon a change of control for a repurchase price equal to 101% of the aggregate principal amount plus accrued interest.

The Subordinated Convertible Notes are secured by a third lien on substantially all of the Company’s assets.

Wells Fargo Agreement

On October 1, 2007, the Company entered into a Credit Agreement (the “Wells Fargo Agreement”) with Wells Fargo Foothill, Inc. (“Wells Fargo”), as administrative agent. The Wells Fargo Agreement provides for a revolving credit commitment of up to $20 million (the “Revolver Commitment”), with a sub-limit of $10 million for the issuance of letters of credit. Unless earlier repayment is required under the Wells Fargo Agreement, Advances under the Revolver Commitment must be repaid on or before October 1, 2010. Advances are available to the Company under the Revolver Commitment in an amount equal to the lesser of (1) $20 million, minus (a) outstanding letters of credit, (b) reserves for hedging obligations and (c) other reserves established by Wells Fargo, and (2) a proved reserve-based Borrowing Base, minus (a) outstanding letters of credit, (b) reserves for hedging obligations and (c) other reserves established by Wells Fargo.

The Company is required to submit a semi-annual Borrowing Base certificate to Wells Fargo within five days of its delivery of a semi-annual reserve report, which is required within 90 days of each December 31 and June 30, beginning December 31, 2007. As of December 31, 2007, the calculated Borrowing Base, net of outstanding letters of credit, reserves for hedging obligations and other reserves established by Wells Fargo was $65.3 million. Therefore, actual availability under the Revolver Commitment was limited to $20 million, minus outstanding letters of credit, reserves for hedging obligations and other reserves established by Wells Fargo. As of December 31, 2007, the Company had $8.6 million available to it under the Revolver Commitment. The Company is in full compliance with the terms of the Wells Fargo Agreement as of December 31, 2007.

Under the Wells Fargo Agreement, interest on Advances accrues at either Wells Fargo’s Base Rate or the LIBOR Rate, at the Company’s option, plus an Applicable Margin of 1.50% in the case of Base Rate Loans or 3.00% in the case of LIBOR Rate Loans. With respect to letters of credit issued under the Wells Fargo Agreement, fees accrue at a rate equal to 3.825% per annum multiplied by the daily balance of the undrawn amount of all outstanding letters of credit. As security for its obligations under the Wells Fargo Agreement, the Company granted Wells Fargo a security interest in, and a first lien on, all of its existing and after-acquired assets including without limitation, the oil and gas properties and rights that the Company acquired in the Blessing Field Properties and the Eliasville Field Properties.

An intercreditor agreement (the “Intercreditor Agreement”) was executed on October 1, 2007 among the Company, Wells Fargo and the trustees for the holders of the Company’s Senior Secured Notes and Subordinated Convertible Notes. The Intercreditor Agreement, among other terms, specifies that the lien in favor of the lenders under the Wells Fargo Agreement securing the Company’s obligations under the Wells Fargo Agreement is contractually senior to the lien securing the Company’s obligations under the Senior Secured Notes, and that the lien securing the Company’s obligations under the Senior Secured Notes is contractually senior to the lien securing the Company’s obligations under the Subordinated Convertible Notes.

Other Long-term Debt

On April 12, 2007, Baseline entered into a $75 million Credit Agreement with Drawbridge Special Opportunities Fund LP. The Drawbridge Agreement provided for a revolving credit commitment of up to $54.7

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million and a Term Loan Commitment of $20.3 million. Revolving Loans had to be paid on or before April 12, 2010 and Term Loans on or before October 12, 2010. The Revolving Loans accrued interest at the Prime Rate and the Term Loans accrued interest at the Prime Rate or 7.5%, whichever was 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 acquired while the Drawbridge Agreement was in effect. The Drawbridge Agreement required 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 were utilized, in order of priority, to pay any amounts due for the overriding royalty interest granted under the Drawbridge 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 were to be used to repay outstanding principal, to be applied first to the Term Loans. Baseline’s obligations under the Drawbridge Agreement were secured by a first lien on all of its existing oil and gas properties, including the Eliasville Field, and any properties acquired while the Drawbridge Agreement was 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 Eliasville Field.

The Company recorded a deferred loan cost of $2,678,000 related to the conveyance of the overriding royalty interest to the Lenders as discussed above. As of December 31, 2007, all of this deferred loan cost has been amortized as a component of interest expense. All amounts outstanding under the Drawbridge Agreement were paid in full on October 1, 2007 and that agreement has been terminated.

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. During 2007 holders of $725,000 of Baseline’s 10% Convertible Promissory Notes converted such notes into 1,450,000 shares. The remaining balance due under such notes of $1,650,000 was paid in full on November 15, 2007.

Bridge Loan Financing

On March 15, 2007, Baseline borrowed $1,700,000 from a single accredited investor. Baseline issued a Senior Secured Debenture which bore 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 a closing fee of $170,000 on April 12, 2007, when the outstanding principal and accrued interest were paid. The proceeds from the bridge loan financing were used to pay an additional deposit of $300,000 on the Eliasville Field (see NOTE 4), to partially satisfy a capital call in the New Albany-Indiana LLC (see NOTE 7), 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 Drawbridge Agreement.

Loans From Founders

On January 26, 2007, Barrie Damson Baseline’s former Chairman and CEO and Alan Gaines 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, bore interest at an annual rate of 6% and matured on the earlier to occur of the date on which Baseline closed a financing transaction in which it obtained 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 closed an equity offering in which it obtained gross proceeds in excess of $3,000,000. These notes were repaid in full on October 1, 2007.

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NOTE 6—STOCKHOLDERS’ EQUITY

Common Stock

On January 16, 2006, Baseline entered into a definitive Purchase Agreement to purchase certain assets from Rex Energy Operating Corp., and its affiliates. 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 such shares as a stock subscription receivable.

On June 8, 2006, Baseline entered into a Mutual Termination Agreement and Mutual Release Agreement pursuant to which we mutually terminated the Purchase agreement and the Stock Agreement.

Pursuant to the termination agreement, shares issued under the Stock Agreement were surrendered for cancellation. In connection with the surrender of such shares, the $1,206,925 of stock subscription receivable related to the shares was eliminated as an adjustment to equity.

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 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.

On April 6, 2006, holders of $350,000 of Baseline’s convertible promissory notes 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.

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, in payment of accrued interest through November 15, 2006, to holders of Baseline’s 10% convertible promissory notes.

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

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.

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.

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. Such shares were valued at $190,000 which has been charged to interest expense.

During June and July 2007, Baseline issued a total of 600,000 shares to outside consultants as compensation for services valued at $360,000.

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On July, 5, 2007 non-employee option holders exercised options to purchase 200,000 shares of Common Stock at $ .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 and August 2007 holders of $250,000 of Baseline’s 10% Convertible Promissory Notes converted such notes into 501,676 shares.

On August 15, 2007, Baseline issued an aggregate of 109,023 shares of common stock, with a value of $54,402, in payment of accrued interest through August 15, 2007, to holders of 10% convertible promissory notes.

During October and November 2007 holders of $475,000 of Baseline’s 10% Convertible Promissory Notes converted such notes into 950,000 shares.

On November 15, 2007, Baseline issued an aggregate of 91,500 shares of common stock, with a value of $45,750, in payment of accrued interest through November 15, 2007, to holders of 10% convertible promissory notes.

Stock Options and Warrants

Baseline utilizes restricted stock, stock options and warrants to compensate employees, officers, directors and consultants. Total stock based compensation expense (including options, warrants and restricted stock) was $816,365 for the year ended December 31, 2007.

On August 15, 2006, Baseline granted a stock option to 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 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 a stockholder 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 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, a holder 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 President and 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.

On January 4, 2007, Baseline granted a stock option to its former 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, a director 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.

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In connection with its entry into the Drawbridge Agreement, on April 12, 2007 the Company 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 an aggregate of 3,200,000 shares of its 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 the Company also entered into a registration rights agreement dated April 12, 2007 with each of the holders of the warrants, under which the Company granted piggy-back registration rights, demand registration rights and shelf registration rights to these holders. Such warrants had a fair value of $1,150,603 which was capitalized as a deferred loan cost and amortized over the term of the Credit Agreement.

On April 12, 2007, concurrently with the execution of the Drawbridge Agreement (see Note 4), Alan Gaines, a director, and Barrie Damson, a former officer and director of its Company, each surrendered additional options to purchase 1,600,000 shares of Common Stock at an exercise price of $0.05 per share.

On August 3, 2007, Baseline granted five-year stock options exercisable for up to an aggregate of 370,000 shares of common stock to several employees at an exercise price of $0.55. Such options vest in equal one-third installments on each of the first, second and third anniversary dates from the date of grant and had a fair value of $191,440.

On August 3, 2007, Baseline granted a five-year stock option to Richard d’Abo, an outside director, exercisable for up to 150,000 shares of common stock at an exercise price of $0.55. Such option had a fair value of $73,844.

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. 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. Such options had a fair value of $757,826.

The weighted average fair value of the stock options granted during year ended December 31, 2007 was $0.51. Variables used in the Black-Scholes option-pricing model include (1) risk free interest rates between 4.45% and 4.61%, (2) expected option life ranged from two and 1/2 to seven years, (3) expected volatility is 201.65% to 223.18% and (4) zero expected dividends. A summary of stock option transactions follow:

	Weighted Average Exercise Price		Number of Options
Balance December 31, 2005	$	0.07	13,675,000
Granted		0.64	2,560,000
Exercised		0.05	(250,000	)
Forfeited or expired		0.05	(2,000,000	)
Balance December 31, 2006		0.18	13,985,000
Granted		0.75	2,120,000
Exercised		0.13	(300,000	)
Forfeited or expired		0.05	(6,540,000	)
Balance December 31, 2007	$	0.40	9,265,000

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The following table summarizes information about the Company’s stock options outstanding at December 31, 2007:

Number Outstanding	Weighted Average Remaining Life	Weighted Average Exercise Price		Aggregate Intrinsic Value
December 31, 2006
Options Outstanding
13,985,000	3.62	$	0.18	$	6,235,934
Options Exercisable
12,651,667	3.48	$	0.13	$	6,312,600
December 31, 2007
Options Outstanding
9,265,000	3.29	$	0.40	$	1,644,000
Options Exercisable
7,228,330	2.97	$	0.32	$	1,644,000

On August 13, 2007, Baseline issued seven-year warrants to its then senior lenders, exercisable in the aggregate for up to 260,000 shares of common stock at an exercise price of $0.52 per share. These warrants were issued as partial consideration for its lenders advancing us $2.5 million on August 13, 2007, thereby enabling us to make a $2.5 million performance deposit in connection with its then pending acquisition of assets from DSX Energy Limited. Such warrants were valued at $140,008 capitalized as a deferred loan cost and fully amortized upon payment of the related debt.

On August 20, 2007, Baseline issued five-year warrants to a former placement agent, exercisable in the aggregate for up to 340,000 shares of common stock at an exercise price of $0.65 per share. These warrants were issued as partial consideration for the termination of an agreement with such placement agent. Such warrants were valued at $216,087 and fully amortized as a component of interest expense upon issuance.

A summary of stock warrant transactions follow:

Number Outstanding	Weighted Average Remaining Life	Weighted Average Exercise Price		Aggregate Intrinsic Value
December 31, 2006
Warrants Outstanding
734,090	3.26	$	0.79	$	52,250
Warrants Exercisable
734,090	3.26	$	0.79	$	52,250
December 31, 2007
Warrants Outstanding
9,265,000	4.97	$	0.53	$	0
Warrants Exercisable
7,228,330	4.97	$	0.53	$	0

The following table summarizes information about the Company’s stock warrants outstanding at December 31, 2007:

Number Outstanding	Weighted Average Remaining Life	Weighted Average Exercise Price
Warrants Outstanding
7,874,090	4.97	$	0.53
Warrants Exercisable
7,874,090	4.97	$	0.53

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NOTE 7—INVESTMENT IN JOINT VENTURE AND REDEMPTION OF MEMBERSHIP INTEREST

On March 16, 2007, Baseline delivered $300,000 to New Albany-Indiana LLC (“New Albany”) in partial satisfaction 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 under a mortgage to secure its Senior Secured Debenture. The reduction in its membership interest of 50% to a 40.423% direct working interest reflected an adjustment of its membership interest in New Albany at the time of its 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 an area of mutual interest, covering approximately 122,000 gross acres (approximately 24,400 acres net to Baseline), primarily located in Greene County and operated by Aurora Oil & Gas;

• 18.2% working interest in an area of mutual interest, covering approximately 41,000 total acres (approximately 7,380 acres net to Baseline) primarily located in Knox County and operated by Rex Energy; and

• 6.9% working interest in an area of mutual interest, covering approximately 8,000 gross acres (560 acres net to Baseline), primarily located in Greene County and operated by El Paso.

NOTE 8—DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

On April 12, 2007, in accordance with a requirement of the Drawbridge Agreement, Baseline entered into a Swap Agreement with Macquarie Bank Limited, which provided that Baseline put 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 from the Eliasville Field Properties. The swap hedges provided for a fixed price of $68.20 per barrel for a three year period, commencing June 1, 2007 and ending May 31, 2010. The hedging arrangement was based upon a monthly volume of 11,000 barrels during the first year and provided 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. The original fixed price $68.20 swap remained in place for the period January 2009 to May 2010. In exchange for the July 2007–December 2008 modification 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.

At the closing of the Blessing Field Properties acquisition on October 1, 2007, Baseline’s hedge positions under the Macquarie Swap Agreement, as described above, were novated to Wells Fargo Foothill, Inc. Also since the closing of this acquisition, Baseline has added to its hedge positions, in accordance with the requirement of the Wells Fargo Agreement, the Senior Notes Indenture and the Convertible Note Indenture. These additional hedges include both collars and floors, with Wells Fargo Foothill serving as our counterparty on each hedge position. All of our hedge positions as of December 31, 2007 are detailed in the table at the end of this section.

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

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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.

When the criteria for cash-flow hedge accounting are not met, realized gains and losses (i.e., cash settlements) are recorded in income (loss) from operations (oil and gas hedging) in the Statements of Operations. Similarly, changes in the fair value of the derivative instruments are recorded as income (loss) from operations in the Statements of Operations. In contrast cash settlements for derivative instruments that qualify for hedge accounting are recorded as additions to or reductions in income (loss) from operations (oil and gas hedging) 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 and collars noted above qualify for cash-flow hedge accounting treatment. For the period ended December 31, 2007, Baseline recognized a derivative liability of $8,836,180 with the change in fair value reflected in other comprehensive income (loss).

As of December 31, 2007 Baseline had the following hedge contracts outstanding:

Crude Oil Hedges*

Instrument	Beginning Date	Ending Date	Floor		Ceiling		Fixed		Total Bbls 2008	Total Bbls 2009	Total Bbls 2010	Total Bbls 2011
Collar	Jan-08	Dec-08	$	68.20	$	74.20			123,000
Collar	Jan-08	Dec-08	$	68.00	$	79.81			66,000
Collar	Jan-09	Dec-09	$	68.00	$	74.05				42,000
Swap	Jan-09	Dec-09					$	68.20		117,000
Swap	Jan-10	May-10					$	68.20			47,500
Floor	Jan-08	Dec-08	$	75.00					60,000
Floor	Jan-09	Dec-09	$	75.00						48,000
Swaption	June-10	Dec-10					$	73.20			49,000
Swaption	Jan-11	Dec-11					$	73.20				84,000
									249,000	207,000	96,500	84,000

(*) All indexed to NYMEX WTI Cushing Light Sweet Crude

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Natural Gas Hedges

Instrument	Beginning Date	Ending Date	Floor		Ceiling		Fixed	Total MMBtu 2008	Total MMBtu 2009	Total MMBtu 2010	Total MMBtu 2011
Collar	Jan-08	Dec-08	$	7.50	$	7.83		960,000
Collar	Jan-09	Dec-09	$	7.50	$	8.44			660,000
								960,000	660,000	—	—

(*) All indexed to Inside FERC Houston Ship Channel

NOTE 9—INCOME TAXES

Net deferred tax assets at December 31, 2007 consisted primarily of deferred tax assets related to tax attributes including the Company’s NOL and timing differences associated with the recognition of depletion, debt discount, deferred financing costs and intangible drilling costs. Deferred tax assets at December 31, 2006 consisted primarily of deferred tax assets related to tax attributes including the Company’s NOL and timing differences associated with the recognition of debt discount and deferred financing costs. Deferred tax assets have a valuation allowance provided for the total amount.

	December 31, 2007			December 31, 2006
Deferred tax assets	$	3,321,000		$	969,241
Less: valuation allowance		(3,321,000	)		(969,241	)
Net deferred tax asset	$	—		$	—

Baseline has net operating loss carry-forwards of approximately $7,236,000 at December 31, 2007, which begin expiring in 2024.

Our effective tax rate applicable to operations in 2007 and 2006 is as follows:

	December 31, 2007	December 31, 2006
Statutory tax rate	(34%)	(34%)
Change in valuation allowance recognized in earnings	34%	34%
	—	—

NOTE 10—ASSET RETIREMENT OBLIGATION

	Year Ended
	December 31, 2006
Asset retirement obligations, beginning of year	$	—
Fair value of liabilities assumed in acquisitions		240,959
Accretion expense		41,988
Asset retirement obligations, end of year	$	282,947

F-25

NOTE 11—SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)

There are numerous uncertainties inherent in estimating quantities of proved crude oil and natural gas reserves. Crude oil and natural gas reserve engineering is a subjective process of estimating underground accumulations of crude oil and natural gas that cannot be precisely measured. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment.

The Company retained Cawley, Gillespie & Associates, Inc., independent third-party reserve engineers, to perform an independent evaluation of proved reserves as of December 31, 2007. Results of drilling, testing and production subsequent to the date of the estimates may justify revision of such estimates. Accordingly, reserve estimates are often different from the quantities of crude oil and natural gas that are ultimately recovered. All of the Company’s reserves are located in the United States.

Proved Reserves

The following reserve schedule was developed by the Company’s reserve engineers and sets forth the changes in estimated quantities for proved reserves of the Company during each of the periods presented:

	Oil (Bbls)		Gas (Mcf)
	(in thousands)
Proved Reserves
Estimated Quantities—December 31, 2006	—		—
Purchase of minerals in place	5,785		32,962
Production	(149	)	(336	)
Extensions, discoveries and other additions	294		1,033
Revisions of Previous estimates	310		(1,362	)
Estimated Quantities—December 31, 2007	6,240		32,297
Proved Developed Reserves
December 31, 2007	4,202		16,791

Oil and Gas Operations

Aggregate results of operations, in connection with the Company’s crude oil and natural gas producing activities are shown below:

	Year Ended December 31, 2007
Revenues	$	11,609,040
Production costs		(5,148,418	)
Exploration expenses		—
Depreciation, depletion and amortization		(1,823,233	)
Accretion expense		(41,988	)
Income before income tax		4,595,401
Income tax		—
Results of operations from oil and natural gas producing activities	$	4,595,401

F-26

Costs Incurred in Oil and Gas Activities

Costs incurred in connection with the Company’s crude oil and natural gas acquisition, exploration and development activities are shown below:

	Year Ended December 31, 2007
Property acquisition costs	$	123,153,383
Unproved prospects		665,531
Exploration costs		—
Development costs		5,228,246
Total Operations	$	129,047,160
Asset retirement obligation (non-cash)	$	240,959

Aggregate Capitalized Costs

Aggregate capitalized costs relating to the Company’s crude oil and natural gas producing activities, including asset retirement costs and related accumulated depreciation, depletion and amortization are as follows:

	December 31, 2007
Proved oil and gas properties	$	128,381,629
Unproved oil and gas properties		8,475,666
Accumulated depreciation, depletion and amortization		(1,823,233	)
Net capitalized costs	$	135,034,062

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

The following information is based on the Company’s best estimate of the required data for the Standardized Measure of Discounted Future Net Cash Flows as of December 31, 2007 in accordance with SFAS No. 69, “Disclosures About Oil and Gas Producing Activities” which requires the use of a 10% discount rate. This information is not the fair market value, nor does it represent the expected present value of future cash flows of the Company’s proved oil and gas reserves.

	Year Ended December 31, 2007
	($ in thousands)
Future cash inflows	$	849,361
Future production costs		(262,906	)
Future development costs		(43,468	)
Future income tax expense		(141,470	)
Future net cash flows		401,517
10% annual discount for estimating timing of cash flows		(190,905	)
Standardized measure of discounted future net cash flows	$	210,612

Future cash inflows are computed by applying year-end commodity prices, adjusted for location and quality differentials on a property-by-property basis, to year-end quantities of proved reserves, except in those instances where fixed and determinable price changes are provided by contractual arrangements at year-end. The discounted future cash flow estimates do not include the effects of the Company’s derivative instruments. In its 2007 year-end reserve report, the Company used the December 31, 2007 WTI Cushing spot price of $96.01 per Bbl and Henry Hub spot natural gas price of $7.465 per MMbtu, adjusted by property for energy content, quality, transportation fees, and regional price differentials. The weighted average price over the lives of the properties was $94.38 per Bbl for oil and $8.064 per Mcf for gas.

F-27

Future production and development costs, which include dismantlement and restoration expense, are computed by estimating the expenditures to be incurred in developing and producing the Company’s proved crude oil and natural gas reserves at the end of the year, based on the year-end costs, and assuming continuation of existing economic conditions. While the Company believes that future operating costs can be reasonably estimated, future prices are difficult to estimate since market prices are influenced by events beyond its control. Future global economic and political events will most likely result in significant fluctuations in future oil prices, while future U.S. natural gas prices will continue to be influenced by primarily domestic market factors, including supply and demand, weather patterns and public policy .

Future income tax expenses are computed by applying the appropriate year-end statutory tax rates to the estimated future pretax net cash flows relating to the Company’s proved crude oil and natural gas reserves, less the tax basis of the properties involved. The future income tax expenses give effect to tax credits and allowances, but do not reflect the impact of general and administrative costs and exploration expenses of ongoing operations relating to the Company’s proved crude oil and natural gas reserves.

Sources of Changes in Discounted Future Net Cash Flows

Principal changes in the aggregate standardized measure of discounted future net cash flows attributable to the Company’s proved crude oil and natural gas reserves, as required by SFAS No. 69, during 2007 are set forth in the table below:

	Year Ended December 31, 2007
	($ in thousands)
Standardized measure of discounted future net cash flows at The beginning of the year	$	—
Purchases of mineral in place		153,696
Extensions discoveries and improved recovery		18,531
Revisions of previous quantity estimates		1,417
Net changes in timing		(11,537	)
Changes in estimated future development costs		(1,036	)
Net changes in prices and production costs		76,212
Accretion of discount		5,850
Sales of oil and gas produced, net of production costs		(8,822	)
Development costs incurred during the period		5,228
Net change in income taxes		(28,927	)
Standardized measure of discounted future net cash flows	$	210,612

F-28

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	BASELINE OIL & GAS CORP.
Date: March 31, 2008	By:	/s/    THOMAS KAETZER
		Thomas Kaetzer
		Chief Executive Officer

In accordance with the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant in the capacities indicated below on March 31, 2008.

Signature and Title

/S/    THOMAS KAETZER        

Thomas Kaetzer

Chief Executive Officer and Director

/S/    PATRICK MCGAREY        

Patrick McGarey

Chief Financial Officer

/S/    ALAN GAINES        

Alan Gaines

Director

/S/    RICHARD D’ABO        

Richard D’Abo

Director