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Article by DailyStocks_admin    (07-31-08 04:18 AM)

Filed with the SEC from July 16 to July 23:

Baseline Oil & Gas (BOGA)
Daniel Loeb's Third Point hedge fund said that it had "productive" conversations with Baseline and proposed to add three directors to the company's board. Third Point previously planned to contact the company to discuss obtaining majority control of the board. It proposed that Bradley L. Radoff, Todd Q. Swanson and John V. Lovoi be promptly added. Third Point holds 64.3 million shares (66.9%) and $3.21 million in convertible notes.

BUSINESS 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.

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.
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.

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 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.

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 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.

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.

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.

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, 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.

CEO BACKGROUND

Mr. Thomas Kaetzer , age 49, has served as Chairman of our Board of Directors since March 21, 2007. Mr. Kaetzer also serves as our Chief Executive Officer, a position he has also held since March 21, 2007. He previously was our president and chief operating officer, titles he held since December 2006. Mr. Kaetzer began his career with Texaco Inc., where, from 1981 to 1995, he held various positions. In 1995, Mr. Kaetzer left Texaco and worked for Vastar Resources Inc., a major independent oil and gas company. In 1996 Mr. Kaetzer formed Southwest Texas Oil & Gas Co., which subsequently merged into GulfWest Energy Inc. in 1998. Mr. Kaetzer served as President/Chief Operating Officer of GulfWest from 1999 to 2004, and as Vice President of Operations for its successor, Crimson Exploration Inc., from 2005 to July 2006. From August 2006 to immediately prior to joining Baseline, Mr. Kaetzer worked as a consultant to several companies in the oil and gas industry. Mr. Kaetzer earned a B.S. degree in Civil Engineering from the University of Illinois in 1981 and an M.S. degree in Petroleum Engineering from Tulane University in 1988.

Mr. Richard d’Abo , age 52, has served as a director of our Company since January 17, 2006. He is presently a transaction partner at The Yucaipa Companies, a private equity firm focused on consolidating companies within the supermarket industry. From 1995 through 2003, Mr. d’Abo was a private investor, and served as a consultant to numerous companies both public and private regarding acquisitions and related financings. From 1988 to 1994, Mr. d’Abo was a partner at The Yucaipa Companies and was instrumental in the creation of financing structures for a number of acquisitions.

Mr. Alan Gaines , age 52, has served as a director of our Company since April 2005. He also served as our Vice Chairman from April 2005 until August 2007. He is currently the Chairman of the Board of Directors of Dune Energy, Inc. (AMEX: DNE), an independent, publicly traded oil and gas company engaged in the development, exploration and acquisition of oil and gas properties. From April 2005 until September 2007, he served as Chief Executive Officer of ABC Funding, Inc. (OTC: AFDG.OB), a publicly-traded company with no current operations and nominal assets. Mr. Gaines currently serves on the Board of Directors of both Dune Energy, Inc. and ABC Funding, Inc. Mr. Gaines has over 25 years of experience as an energy investment and merchant banker. In 1983, he co-founded Gaines, Berland Inc., an investment bank and brokerage firm, specializing in global energy markets, with particular emphasis given to small to medium capitalization companies involved in exploration and production, pipelines, refining and marketing, and oilfield services. Mr. Gaines holds a B.B.A. degree in Finance from Baruch College, and an MBA degree in Finance (with distinction) from Zarb School, Hofstra University School of Graduate Management.

MANAGEMENT DISCUSSION FROM LATEST 10K

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 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.

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 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.

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 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.

MANAGEMENT DISCUSSION FOR LATEST QUARTER

Results of Operations

We produced 62.9 thousand barrels of oil and 309.2 million cubic feet of natural gas during the first quarter, and received an average price of $96.49 per barrel and $9.15 per thousand cubic feet respectively. This resulted in total oil and gas sales revenue for the quarter of $8.9 million, before the effects of hedging. Oil and gas hedging losses totaled ($2.5) million during the quarter, of which cash settlements paid to our counterparties under our commodity price hedging contracts totaled ($1.3) million. We had no revenues, oil and natural gas production or exploration and production operations during the comparable period in 2007.

Our production expenses totaled $2.2 million during the first quarter, of which $492 thousand was paid for severance taxes and $1.7 million was comprised of lease operating expenses. Our production expenses equaled $3.18 per mcfe during the first quarter, while our lease operating expenses equaled $2.46 per mcfe. We had no production operations or corresponding production expenses during the first quarter of 2007.

Our general and administrative expenses were $1.1 million during the first quarter. The major components of this total included salaries and benefits at $496 thousand ( including $161 thousand of non-cash stock based compensation), consulting and professional fees at $325 thousand and office expenses of $197 thousand. By comparison, our general and administrative expenses totaled $288 thousand during the first quarter of 2007, a period during which we conducted no oil and natural gas production activities.

Our interest expenses totaled $6 million during the first quarter, of which $5.3 million was comprised of interest on our Senior Secured Notes ($3.6 million, paid in cash) and Convertible Notes ($1.7 million, paid-in-kind), which are described above. Another $0.5 million consisted of amortization of issuance costs for these two bond issues. Our interest expenses totaled $0.6 million during the first quarter of 2007.

During the first quarter of 2008, our net field level cash flow from oil and gas production operations was $6.7 million, before accounting for the effects of hedging activities. This figure represents production revenue of $8.9 million, offset by lease operating expenses of $1.7 million and by severance and ad valorem taxes totaling approximately $0.6 million during such period.

During the three-months ended March 31, 2008, we spent $2.3 million on drilling and workovers, consisting of $1.0 million for drilling and completion activity, approximately $0.78 million for recompletions on existing wells and $0.47 million for production and well equipment.

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