UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

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

For the Fiscal Year Ended December 31, 2005

Commission File Number 0-9120

THE EXPLORATION COMPANY OF DELAWARE, INC.

(Exact name of Registrant as specified in its charter)

Delaware

84-0793089

(State or other jurisdiction of

(I.R.S. Employer

incorporation or organization)

Identification No.)

500 North Loop 1604 East, Suite 250,
San Antonio, Texas

78232

(Address of principal executive offices)

(Zip Code)

Registrant's telephone number, including area code:     (210) 496-5300

Securities registered pursuant to Section 12(b) of the Act:     None

Securities registered pursuant to Section 12(g) of the Act:    Common Stock, par value $0.01 per share

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

Yes 

  p

No

   þ

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange

Act.

Yes 

  p

No

   þ

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 

  þ

No

   p

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K 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.   þ

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of "accelerated filer and large accelerated filer" in Rule 12b-2 of the Exchange Act). 

Large accelerated filer p

Accelerated filer þ

Non-accelerated filer p

Indicate by check mark if the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes 

  p

No

   þ

As of June 30, 2005, the aggregate market value of the registrant's common stock held by non-affiliates of the registrant was $102.9 million based on the closing price of $4.32 per share as reported on the NASDAQ Capital Market on that date.

The number of shares outstanding of the registrant's Common Stock as of March 3, 2006, was 29,833,230.

Documents Incorporated by Reference:    Portions of the Company's Proxy Statement for the Annual Shareholders' Meeting, to be held on May 12, 2006 are incorporated by reference into Items 10, 11, 12 and 14 of Part III of this filing.

INDEX AND
CROSS REFERENCE SHEET

PART I

Page

Item 1.

Business

3

Item 1A.

Risk Factors

10

Item 1B.

Unresolved Staff Comments

15

Item 2.

Properties

15

Item 3.

Legal Proceedings

20

Item 4.

Submission of Matters to a Vote of Security Holders

20

PART II

Item 5.

Market for Registrant's Common Equity and Related Stockholder Matters , and Issuer Purchases of Equity Securities

20

Item 6.

Selected Financial Data

21

Item 7.

Management's Discussion and Analysis of Financial Condition and Results of Operations

21

Item 7A .

Quantitative and Qualitative Disclosures About Market Risk

33

Item 8.

Financial Statements and Supplementary Data

34

Item 9.

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

34

Item 9A.

Controls and Procedures

34

Item 9B.

Other Information

37

PART III

Item 10.

Directors and Executive Officers of the Registrant

37

Item 11.

Executive Compensation

37

Item 12 .

Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

37

Item 13.

Certain Relationships and Related Transactions

37

Item 14.

Principal Accounting Fees and Services

37

PART IV

Item 15.

Exhibits, Financial Statement Schedules

37

Signatures

40

Audited Consolidated Financial Statements

F-1

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

Statements in this Form 10-K which are not historical, including statements regarding TXCO's or management's intentions, hopes, beliefs, expectations, representations, projections, estimations, plans or predictions of the future, are forwarding-looking statements and are made pursuant to the safe harbor provisions of the Private Securities Litigation Reform Act of 1995. Such statements include those relating to expected drilling plans, including the timing, category, number, depth, cost and/or success of wells to be drilled, expected geological formations or the availability of specific services or technologies. It is important to note that actual results may differ materially from the results predicted in any such forward-looking statements. Investors are cautioned that all forward-looking statements involve risks and uncertainty. These risks and uncertainties include: the costs and accidental risks inherent in exploring and developing new oil and natural gas reserves, the price for which such reserves and production can be sold, environmental concerns affecting the drilling of oil and natural gas wells, impairment of oil and gas properties due to depletion or other causes, the uncertainties inherent in estimating quantities of proved reserves and cash flows, as well as general market conditions, competition and pricing. Please refer to the Risk Factors discussion in Part I, Item 1A for additional information.

PART I

ITEM 1. BUSINESS

GENERAL

The Exploration Company was incorporated in the State of Colorado in 1979 and reincorporated in the State of Delaware in 1999, becoming The Exploration Company of Delaware, Inc. Our trading symbol on the Nasdaq Capital Market ^SM is TXCO. Unless the context requires otherwise, when we refer to "TXCO", "the Company", "we", "us" and "our", we are describing The Exploration Company of Delaware, Inc.  Our contact information is (1) by mail: 500 N. Loop 1604 East, Suite 250, San Antonio, Texas 78232, (2) by phone: 210/496-5300. Our Web site is www.txco.com.

We file annual, quarterly, and current reports, proxy statements and other information with the Securities and Exchange Commission ("SEC"). All of these reports are available on our Web site under the link "SEC Filings" on the "Investor Relations" menu, as soon as reasonably practicable after we electronically file them with or furnish them to the SEC. Forms 3, 4 and 5 may also be accessed from the "Insider Reports" link on the "Governance" menu. You may obtain free of charge a copy of the reports provided to the SEC by written request to the Corporate Secretary at the address above.

Also under the "Governance" menu, you can access our corporate governance documents, including our Code of Conduct, and charters for the Governance and Nominating, and Audit Committees of our Board of Directors. The "Investor Relations" menu also contains links to recent presentations, news releases and reconciliations of non-GAAP items.

As of December 31, 2005, we employed 49 full-time employees including management. We believe our relations with our employees are good. None of our employees are covered by union contracts.

LONG-TERM STRATEGY

Our primary business operation is exploration, development, and production of onshore domestic oil and gas reserves. We have a consistent record of long-term growth in proved oil and gas reserves, leasehold acreage position, production and cash flow through our established exploration and development programs. Our business strategy is to build shareholder value by acquiring undeveloped mineral interests and internally developing a multi-year drilling inventory through the use of advanced technologies, such as 3-D seismic and horizontal drilling. We strive to discover, develop and/or acquire more oil and gas reserves than we produce each year from these internally developed prospects. As opportunities arise, we may selectively participate with industry partners in prospects generated internally as well as by other parties. We attempt to maximize the value of our technical expertise by contributing our geological, geophysical and operational core competencies through joint ventures or other forms of strategic alliances with well capitalized industry partners in exchange for carried interests in seismic acquisitions, leasehold purchases and/or wells to be drilled. From time to time, we offer portions of our developed and undeveloped mineral interests for sale. We finance our activities through internally generated operating cash flows, as well as debt financing and equity offerings, or sale of interests in properties when favorable terms or opportunities are available.

Management's ongoing strategy for improved shareholder value includes maintaining a focus on our core business of oil and gas exploration and production. This strategy allows us to attract recognized industry partners, expand our core area leasehold acreage, and increase our 3-D seismic database and interpretative skill set. This strategy, coupled with our drill bit success, allows us to grow our reserve base while maintaining a conservative debt profile. We have remained focused on the Maverick Basin and have successfully established a multi-year portfolio of drilling targets within our core area. To support our growing asset base in the Maverick Basin, we acquired a 69-mile natural gas gathering system in 2002, which we expanded to more

than 90 miles of pipeline by 2005. The gathering system assures our access to North American markets, and enables us to realize higher prices for our natural gas and better share in proceeds from extraction of natural gas liquids.

Our established operating strategy includes the pursuit of multiple growth opportunities and diversified exploration targets within our core area of operations. We are well positioned to pursue new oil and gas reserves and expand our production base due to aggressively expanding our surrounding lease holdings where geology indicates the likely continuation of known or prospective oil and gas producing formations. The Maverick Basin offers a diversity of hydrocarbon-bearing horizons.

RECENT DEVELOPMENTS

2005 Drilling Activity Summary: We participated in drilling a total of 52 gross wells during 2005. Maverick Basin wells totaled 51, including five re-entries, while one well was drilled in the Williston Basin. Thirteen of the Maverick Basin wells were sold as part of our Asset Sale during the third quarter of 2005 described below. Of the remaining 39 total wells, 24 have been placed on production through February 2006, while 15 remain in various stages of completion. There were no dry holes. Completed Maverick Basin wells include 21 producing oil and two producing natural gas, while the one Williston Basin well drilled is producing oil. A total of 54 wells remained pending completion at year-end 2005, including wells remaining from prior years (see the "In Progress Recap" for further information). Three of the five re-entries resulted in producing well completions (one oil and two natural gas).

Reserve Growth:  We continued our ongoing trend of annual reserve growth in 2005 by recording net proved reserve additions of 1.5 billion cubic feet equivalent ("Bcfe"). Combined with annual production of 4.6 Bcfe and reserves sold of 1.4 Bcfe, our gross reserve additions for the year were 7.5 Bcfe. Estimated year-end proved oil and gas reserves reached a record 39.4 Bcfe, a 4.0% increase above the 37.9 Bcfe at year-end 2004. We achieved a 161% all-source reserve replacement rate in 2005.

This expansion of our oil and gas reserves and production base was achieved by pursuing exploration in seven distinct Maverick Basin plays, ranging from the San Miguel to the Glen Rose formations -- all above 7,000 feet. Exploration and development targets for 2006, presented in descending depth order, include:

    -  
    -  
    -  
    -  
    -

expanding waterflood oil production from the San Miguel interval;
expanding oil and gas production from Georgetown horizontal wells;
continued horizontal and vertical drilling for Glen Rose shoal and reef gas intervals;
additional Comanche Ranch lease horizontal wells targeting Glen Rose porosity oil production; and
vertical wells targeting gas from the Pearsall and Sligo formations.

Each of these high-impact exploration and development targets has potential to establish meaningful additions to our oil and gas production and proved reserves, along with significant numbers of new, proved undeveloped, lower-risk drilling locations.

2006 Capital Expenditures Budget: Should our exploration and development plans progress as projected, we expect continued growth of our oil and gas reserves and production levels in 2006. We established a range of $40 million to $50 million for our 2006 capital expenditure budget ("CAPEX"), with approximately 95% earmarked for drilling 53 new wells and four re-entries targeting four primary horizons. The remaining $2.1 million will go toward seismic acquisition, lease extensions and water injection well conversions. CAPEX may expand or contract based on drilling results, operational developments, unanticipated transaction opportunities, market conditions, commodity price fluctuations and working capital availability. Based on our continued drilling success, we expect to be profitable in 2006, and further expect to have sufficient working capital available from traditional sources, including cash flow from operations and borrowings from our reserve-based bank credit facility, as well as industry sources and equity markets, as needed. However, we retain our ability to adjust our capital expenditure program consistent with our available liquidity in order to continue to meet our ongoing operating and debt service obligations on a timely basis.

September 2005 Asset Sale: In December 2004, we retained Raymond James & Associates to assist in actively pursuing strategic alternatives designed to enhance shareholder value. As a result of this process, we entered into an $80 million purchase and sale agreement ("Asset Sale") in September 2005 for a portion of our interests in the Maverick Basin with EnCana Oil & Gas (USA) Inc. Proceeds from this sale of primarily undeveloped acreage were used to pay down debt on our credit facility, and retire our redeemable preferred stock and certain other obligations. Proceeds were also used to acquire an interest in the Marfa Basin that we hope to begin developing in the second half of 2006. The Asset Sale is further described in the section by that title in the Management's Discussion and Analysis section of this Annual Report on Form 10-K.

February 2005 Acquisition/Exchange: We acquired a 50% interest in more than 174,000 gross acres in Maverick, Dimmit, and Zavala counties. This additional acreage lies mostly contiguous, to the south and east of our existing lease block and is prospective for many of our active plays, including in descending depth order, the Escondido, Olmos Coals (CBM), San Miguel, Georgetown, Glen Rose, Pearsall, Sligo and Jurassic targets. We exchanged a 50% interest in shallow zones (to the base of the San Miguel formation) in certain of our Comanche and Chittim leases, and all depths in certain other Chittim leases, for the interest.

October 2005 Acquisition: We acquired all of the oil and gas leasehold working interest in all depths and formations underlying approximately 140,000 gross acres (approximately 135,000 net acres) of the Marfa Basin, located in the west Texas counties of Presidio and Brewster, primarily from Peacock Oil & Gas Properties, Ltd. ("Peacock") and Elton Smith ("Smith"). We paid for this new acreage with cash and issuance to Peacock and Smith of 450,000 shares of unregistered common stock of TXCO.

Subsequent Acquisition: On March 10, 2006, we closed on the purchase of a drilling rig and other personal property and equipment from Ada Energy Services, LLC. The consideration for the purchase was $4.3 million.

PRINCIPAL AREAS OF ACTIVITY

Oil and Gas Operations: During 2005, we expanded our Maverick Basin lease block to 656,000 contiguous acres. In addition, we spudded or re-entered a total of 51 wells in various horizons in the Maverick Basin, and one in the Williston Basin. These totals compared to 66 and 3, respectively, in 2004. Thirteen of the 2005 wells were sold to EnCana Oil & Gas (USA), Inc. ("EnCana") as part of the Asset Sale. The wells sold to EnCana included four each producing oil and natural gas, and five that were awaiting completion. Of the remaining 39 wells, 24 have been placed on production through February 2006, including 22 new oil wells in the Glen Rose, San Miguel, Georgetown, Edwards, Austin Chalk and Red River formations, and two re-entered gas wells were completed in the Georgetown formation.

The Maverick Basin drilling activity reflects our continued ability to generate working capital from healthy internal operating margins, and industry sources, allowing for expansion of our Texas-based lease acreage holdings and natural gas exploration and production activities. A one-time payment for the termination of hedges of natural gas, combined with increased income taxes after the Asset Sale, and a decrease in Maverick Basin natural gas production during 2005, resulted in a decline in net cash provided by operating activities to $6.3 million in 2005 from $16.4 million in 2004. See the table in the Sources and Uses section on page 23.

Our strategy remains focused on our core oil and natural gas producing properties and higher margin exploration activities in the Maverick Basin, while beginning to evaluate opportunities in our newly acquired Marfa Basin acreage. We continue to evaluate economic alternatives related to our remaining properties in the Williston Basin, including efforts to either locate suitable joint venture partners, farmout, or sell our interest in that basin.

Maverick Basin: At year-end 2005, we had an average working interest of over 85% on our Maverick Basin leasehold acreage. A large portion of this contiguous lease block is situated on the Chittim Anticline, a large regional geologic structure. Hydrocarbons have been found in at least 14 separate horizons along the structure including the Lower Glen Rose or Rodessa interval -- a carbonate formation that has produced billions of cubic feet of natural gas from patch reefs and shoals.

We utilize 3-D seismic survey data as an integral part of our interpretative methodology for the identification and evaluation of drilling prospects in most of our active plays. During 2005, we finalized a lease exchange program under which we acquired an additional 140 square miles of 3-D seismic data on the leases acquired early in the year. At year-end 2005 we had accumulated over 934 square miles of 3-D seismic data covering more than 90% of our 1,015-square-mile (equivalent to 650,000 acres) Maverick Basin lease block.

Our geologists and geophysicists have identified and mapped numerous geological formations at various depths on most of our lease block. This provides a growing, multi-year inventory of alternative drilling prospects for the ongoing evaluation of horizons known to be productive for oil and/or gas within and around our leases in the Maverick Basin. The active plays under ongoing evaluation by our engineers are described under the "Maverick Basin Plays" heading later in this section.

The following table contains details by formation in descending depth order for our approximate working interest ownership in some of our Maverick Basin projects budgeted for 2006:

Working      
Interest Range 

1

San Miguel Tar Sand Oil

50

%

2

San Miguel - Oil Waterflood

100

%

3

Georgetown - Oil

100

%

4

Glen Rose - Oil Porosity Zone

50% to 100

%

5

Glen Rose - Gas Shoals

48% to 75

%

6

Pearsall/Sligo - Gas

12.5% to 50

%

The expanding geophysical database, historical drilling results and the growing number of prospective formations targeted by our drilling programs with our partners reaffirmed our longstanding belief that our exploration and development possibilities on our growing Maverick Basin lease block remain very significant.

MAVERICK BASIN PLAYS

Glen Rose Oil: During 2005, we increased our interest in much of our non-operated, 130,000-acre Comanche prospect from 50% to 75.5%. We have a proprietary, 100-square mile, 3-D seismic survey that covers the western half of the Comanche prospect, including the Cinco Ranch lease on the western flank of the Comanche acreage. We, along with our partners, acquired and processed the entire 3-D survey several years ago, identifying numerous Glen Rose prospects. While the first well found a water-bearing reef, the second well became the discovery well for the Comanche Halsell (6500) field and tested at rates over 2,000 BOPD in 2002. That well targeted a prospect on the Comanche Ranch lease, which contained evidence of multiple Glen Rose prospects stacked over a previously unidentified structure. Initial drilling found no productive reefs, but discovered a highly fractured porosity interval.

After the first three years of development, production on the Comanche Ranch lease was spread over a 20 square-mile area. Forty-degree gravity oil is consistent throughout the entire area, which contains no gas. The partners' engineering staffs completed extensive reviews of the porosity intervals and our oil and water production profiles and determined that this is a strong water-drive reservoir. Additionally, seismic was integrated with the Comanche Halsell field production profile. The water, which is produced along with the oil, is disposed of at surface locations or trucked to disposal wells.

Only two wells were drilled on the Comanche Ranch during 2004 due to the restructuring of our operating partner. Activity picked up in 2005 with the successor to the restructuring with six new wells spudded along with one re-entry on the Comanche Ranch leases. Additionally, we extended the play into the adjacent Cage Ranch where we hold a 100% working interest (WI). We spudded 10 Glen Rose oil wells on the Cage Ranch and one on the Stone Ranch during 2005. Of the combined 18 wells drilled to the porosity zone, 11 were producing oil at year-end 2005, while seven remained in completion. Since year-end, one additional 2005 well has begun production.

Glen Rose oil sales for 2005 totaled 236,000 BO up from 141,000 BO during 2004. The combined number of wells drilled since the oil play's discovery in February 2002 stands at 46 through year-end 2005. Cumulative Glen Rose gross oil production since its discovery surpassed 2.4 million barrels of oil through February 2006. The project remains profitable and economics should improve as we and our partners better define the expansive play and perfect drilling techniques used to maximize the recovery of oil in this strong water-drive formation. Net proved reserves at December 31, 2005, for the Glen Rose oil porosity zone are estimated at 1.2 million BO, equivalent to 7.4 Bcfe, up from 745,000 BO (4.5 Bcfe) for the prior year. We believe that significant additional proved reserves will be established in the future.

We spudded two porosity wells thus far in 2006. One well currently awaits completion while one well continues drilling. Our 2006 CAPEX includes $21.2 million for 24 porosity wells.

Glen Rose Gas: In late 2001, we announced the start of a horizontal Glen Rose shoal gas play on a portion of our Chittim lease. Our geologists analyzed a large carbonate shoal (or carbonate "sand" bar) located within the Glen Rose interval. The Chittim 1-141, the first well completed in this program, went on production in 2001 at a rate of 2.0 MMcfd, has cumulative production through February 2006 of over 1.0 Bcf, and is still producing about 150 Mcfd. As provided under our farm-in agreement with AROC-Texas Inc., covering this portion of the Chittim lease, we drill and complete these horizontal Glen Rose shoal wells and AROC operates them.

Our horizontal Glen Rose shoal drilling program produced a string of 29 successful horizontal gas well completions through 2004. We spudded one shoal well during 2005 and it awaits completion. We spudded two new Glen Rose reef wells during 2005, with one awaiting completion into another zone, and one recompleted into the Georgetown formation and producing

oil. Glen Rose gas sales for 2005 totaled 1.4 Bcf down from 1.7 Bcf during 2004. The field produced 10.4 Bcf since horizontal drilling techniques were applied. At December 31, 2005, net proved gas reserves for Glen Rose were estimated at 9.2 Bcfe, down from 11.2 Bcfe for the prior year. Plans for 2006 includes $1.5 million for drilling four Glen Rose shoal or reef wells.

Georgetown: During 2005, we spudded 12 new Georgetown wells and re-entered four wells, in addition to one Georgetown completion originally targeting Glen Rose reefs, as compared to 26 Georgetown wells drilled or re-entered in 2004. Ten of the wells drilled in 2005 were later transferred to EnCana as part of the Asset Sale. Of the retained Georgetown wells, two new wells and one re-entry are producing oil, while two of the re-entered wells are producing gas. One re-entry and one new well are in completion. Georgetown gas sales for 2005 totaled 728 MMcf, down from 1.1 Bcf during 2004 due to the Asset Sale in the third quarter of 2005, while Georgetown oil sales increased to 49,800 BO from 41,324 BO in 2004. The current 2006 CAPEX budget includes $6.6 million for 10 new wells. We spudded one horizontal Georgetown well in January 2006 that began production in February.

We began using coherency processing to more accurately predict the location of formation faults and fractures in this field in late 2003. The Georgetown is a fractured reservoir, which makes it difficult to predict the type and quantity of ultimate reserves for each well, as such reservoirs typically have hyperbolic decline curves with high initial production rates that rapidly fall to lower, sustained rates. Georgetown proved reserve estimates decreased to 0.6 Bcfe from 7.5 Bcfe at year-end 2004 due to the sale of our interest in this formation across our southern leasehold block in September 2005.

San Miguel Waterflood: In 2002, we acquired the Pena Creek oil field in Dimmit County, Texas, which included 94 producing oil wells, 94 injection wells and 28 shut-in wells, and we completed a 3-D seismic survey covering the field and surrounding acreage. We also completed an extensive geological, engineering and 3-D seismic review, including the review of historic well data acquired with the property. These evaluations enabled us to identify bypassed infill San Miguel oil reserves, establishing more than 120 potential infill locations to date, with further potential to establish additional infill locations as warranted by ongoing drilling results. We expect additional oil recovery from planned revamping of injection well configuration.

During 2005, we drilled six infill wells targeting bypassed reserves, successfully completing five of those wells, while one awaits completion. We successfully completed all 10 wells spudded during 2004. San Miguel natural gas sales for 2005 increased to 5.1 MMcf, from 3.0 MMcf during 2004, while oil sales declined to 78,517 BO from 93,979 BO for the same periods. We no longer have San Miguel natural gas due to the September 2005 sale. Net proved reserves at year-end for this field were estimated at 3.6 million barrels, equivalent to 21.4 Bcfe, up from 2.2 million barrels (13 Bcfe) at year-end 2004. The 10,000-acre Pena Creek prospect is contiguous to our Comanche Ranch lease. The 2006 CAPEX budget includes $3.0 million for 10 new wells in the San Miguel waterflood.

Pearsall: Our 2006 CAPEX budget includes $8.0 million for drilling eight new wells in the Pearsall formation on our Chittim lease block in partnership with EnCana. This represents our first major investment in this promising formation that covers a large portion of our Maverick Basin acreage. The Pearsall is an over-pressured shale play. During 2004, we recompleted one well into the Pearsall formation that continues to produce about 44 Mcf per day. No wells were drilled in this formation during 2005.

Coalbed Methane (CBM): During 2005 we sold our interest in our CBM wells in the "Sacatosa (CBM Olmos) Field". We initially sold 50% of our interest as part of the February 2005 asset acquisition/exchange. Our remaining interests in these wells were sold as part of the Asset Sale in September 2005. We retain approximately 100,000 acres that are prospective for CBM.

Tar Sands: The San Miguel Tar Sand feature ("Tar Sands") is prospective under our existing Maverick Basin acreage. Literature prepared for the United States Geological Survey has established the Maverick Basin as the single largest deposit of Tar Sands in the State of Texas with 2 to 4 billion barrels of oil in place. Conoco and Mobil did pilot projects on the San Miguel Tar Sand in the late 1970's and early 1980's and achieved recoveries of over 50% with the use of steam injection. These Tar Sands are much like those found in Cold Lake Field in Canada. In February of 2005 we entered into a Participation Agreement between Pearl Exploration and Production, Ltd. (TSX Venture: "PXX") ("Pearl"), formerly known as Newmex Minerals, Inc. While we are the operator with a 50% working interest, we are drawing on Pearl's technical expertise with similar projects in Canada. The Participation Agreement includes an Area of Mutual Interest that covers approximately 33,000 acres of our leasehold and calls for the drilling of three pilot wells at no cost to us. To date, the initial pilot well has been drilled and completed and a second well has been drilled and is currently awaiting completion. In addition, construction of the steam facility is currently in progress and we expect construction to be complete in April of 2006. We were issued permits from the Texas Railroad Commission ("TRRC") on February 23, 2006 to inject steam into the

formation and we expect to begin the steam injection process in May of 2006. If the results from the pilot wells are successful, we may begin the design and construction of a full field development in the second half of 2006, which would require us to make additional capital expenditures. Our initial 2006 CAPEX budget includes $300,000 for one San Miguel Tar Sand well.

Other Plays: During 2005, we drilled six wells in other Maverick Basin formations: four in the Austin Chalk formation, and one each in the James Lime and Edwards formations. Three of the Austin Chalk wells were later transferred as part of the Asset Sale. Of the remaining three wells, one is producing oil and two are awaiting completion. The initial 2006 CAPEX budget does not include funds for drilling in any of these formations.

We expect economic development of the shallow Olmos sands, with depths ranging from approximately 700 to 1,900 feet, to accelerate as pipeline infrastructure grows along with the development of gas production in the immediate area from other formations.

MARFA BASIN

In October 2005, we acquired a 100% working interest in 140,000 gross acres (135,000 net acres) in the Marfa Basin. This basin is located approximately 200 miles northwest of our Maverick Basin leases. It is an underexplored area along the Ouachita Overthrust that is prospective for the Barnett and Woodford Shales. We are seeking a 50% partner to join us in the exploration and development of this basin. We plan to expand the CAPEX budget to include this effort when our partner is determined.

WILLISTON BASIN

Through 2005, we continued to evaluate all of our Williston Basin lease obligations, making lease extension payments on a selective basis, emphasizing those leases with particular geologic attributes or with adequate remaining primary lease terms. Consistent with our strategy to focus exploration efforts and resources on the development of our core producing area in Texas, we maintained marketing efforts offering our remaining Williston Basin holdings to other exploration companies with a focus on that area. At December 31, 2005, we retained approximately 83,000 net acres in the Williston Basin .

During 2005, we participated in the drilling of one new well (3.125% WI) in the Red River formation that is currently producing oil. In 2004 we participated in one new well and two re-entries in this formation. Our 2005 net sales for the Williston Basin totaled 31,232 BO and 58 MMcf, as compared to 42,314 BO and 31 MMcf in 2004. No funds have been included in the 2006 CAPEX for drilling in this basin.

PRINCIPAL PRODUCTS AND COMPETITION

Our principal products are crude oil and natural gas. The production and marketing of oil and gas are affected by a number of factors beyond our control, the effects of which we cannot accurately predict. These factors include crude oil imports, actions by foreign oil-producing nations, the availability of adequate pipeline and other transportation facilities, the marketing of competitive fuels and other matters affecting the availability of a ready market, such as fluctuating supply and demand. Generally, we sell all of our oil and gas under short-term contracts that can be terminated with 30 days notice, or less. None of our production was sold under long-term contracts with specific purchasers during 2004 or 2005. Consequently, we were able to market our oil and gas production to the highest bidder each month.

At management's discretion, we may participate in fixed-price contracts for a portion of our physical gas production when attractive opportunities are available. From time to time, we enter into derivative contracts to reduce exposure from price fluctuations and provide a more predictable cash flow stream. All such derivatives call for financial settlement rather than physical settlement. These derivatives are discussed further in Item 7A .

We operate and direct the drilling of oil and gas wells and also participate in non-operated wells. As operator, we contract service companies, such as drilling contractors, cementing contractors, etc., for specific tasks. In some non-operated wells, we participate as an overriding royalty interest owner.

During 2005, four purchasers of our oil and gas production and other natural gas sales accounted for 17 %, 14%, 11% and 11% of total revenues. We believe that alternative purchasers could be found for such production at comparable prices if any of these major customers declined to purchase future production.

The oil and gas industry is highly competitive in the search for and development of oil and gas reserves. We compete with a substantial number of major integrated oil companies and other companies having significantly greater financial resources and manpower than we do. These competitors, having greater financial resources, have a greater ability to bear the economic risks inherent in all phases of this industry. In addition, unlike us, many competitors produce large volumes of crude oil that may be used in connection with their operations. These companies also possess substantially larger technical staffs, which puts us at a significant competitive disadvantage compared to others in the industry.

GENERAL REGULATIONS

Both state and federal authorities regulate the extraction, production, transportation, and sale of oil, gas, and minerals. The executive and legislative branches of government at both the state and federal levels have periodically proposed and considered proposals for establishment of controls on alternative fuels, energy conservation, environmental protection, taxation of crude oil imports, limitation of crude oil imports, as well as various other related programs. If any proposals relating to the above subjects were to be enacted, we can not predict what effect, if any, implementation of such proposals would have upon our operations. A listing of the more significant current state and federal statutory authority for regulation of our current operations and business are provided below.

Federal Regulatory Controls

Historically, the transportation and sale of natural gas in interstate commerce have been regulated by the Natural Gas Act of 1938 (the "NGA"), the Natural Gas Policy Act of 1978 (the "NGPA") and associated regulations by the Federal Energy Regulatory Commission ("FERC"). The Natural Gas Wellhead Decontrol Act (the "Decontrol Act") removed, as of January 1, 1993, all remaining federal price controls from natural gas sold in "first sales." The FERC's jurisdiction over natural gas transportation was unaffected by the Decontrol Act.

In 1992, the FERC issued regulations requiring interstate pipelines to provide transportation, separate or "unbundled," from the pipelines' sales of gas (Order 636). This regulation fostered increased competition within all phases of the natural gas industry. In December 1992, the FERC issued Order 547, governing the issuance of blanket marketer sales certificates to all natural gas sellers other than interstate pipelines, and applying to non-first sales that remain subject to the FERC's NGA jurisdiction. These orders have fostered a competitive market for natural gas by giving natural gas purchasers access to multiple supply sources at market-driven prices. Order No. 547 increased competition in markets in which we sell our natural gas.

The natural gas industry historically has been very heavily regulated; therefore, there is no assurance that the less stringent regulatory approach pursued by the FERC and Congress will continue.

State Regulatory Controls

In each state where we conduct or contemplate conducting oil and gas activities, these activities are subject to various regulations. The regulations relate to the extraction, production, transportation and sale of oil and natural gas, the issuance of drilling permits, the methods of developing new production, the spacing and operation of wells, the conservation of oil and natural gas reservoirs and other similar aspects of oil and gas operations. In particular, the State of Texas (where we have conducted the majority of our oil and gas operations to date) regulates the rate of daily production allowable from both oil and gas wells on a market demand or conservation basis. At the present time, no significant portion of our production has been curtailed due to reduced allowables. We know of no proposed regulation that will significantly impede our operations.

Environmental Regulations

Our extraction, production and drilling operations are subject to environmental protection regulations established by federal, state, and local agencies. To the best of our knowledge, we believe that we are in compliance with the applicable environmental regulations established by the agencies with jurisdiction over our operations. We are acutely aware that the applicable environmental regulations currently in effect could have a material detrimental effect upon our earnings, capital expenditures, or prospects for profitability. Our competitors are subject to the same regulations and therefore, the existence of such regulations does not appear to have any material effect upon our position with respect to our competitors. The Texas Legislature has mandated a regulatory program for the management of hazardous wastes generated during crude oil and natural gas exploration and production, gas processing, oil and gas waste reclamation and transportation operations. The disposal of these wastes, as governed by the Railroad Commission of Texas, is becoming an increasing burden on the industry. Our leases in Montana, North Dakota and South Dakota are subject to similar environmental regulations including archeological and botanical surveys as most of the leases are on federal and state lands.

Federal and State Tax Considerations

Revenues from oil and gas production are subject to taxation by the state in which the production occurred. In Texas, the state receives a severance tax of 4.6% for oil production and 7.5% for gas production. North Dakota production taxes typically range from 9.0% to 11.5% while Montana's taxes range up to 17.2%. These high percentage state taxes can have a significant impact upon the economic viability of marginal wells that we may produce and require plugging of wells sooner than would be necessary in a less arduous taxing environment.

For Federal and State Income Taxes, we fully utilized all of our remaining tax net operating loss carryforwards, making our effective tax rate (federal and state) approximately 22%. Because these tax net operating losses have now been used, we expect our effective tax rate to approximate 37% in future years.

I TEM 1A. RISK FACTORS

Risks Related to Our Business

Our future success depends upon our ability to find, develop and acquire additional oil and gas reserves that are economically recoverable.

The rate of production from oil and natural gas properties declines as reserves are depleted. As a result, we must locate and develop or acquire new oil and gas reserves to replace those being depleted by production. We must do this even during periods of low oil and gas prices when it is difficult to raise the capital necessary to finance activities. Without successful exploration or acquisition activities, our reserves and revenues will decline. We may not be able to find and develop or acquire additional reserves at an acceptable cost or have necessary financing for these activities.

Oil and gas drilling is a high-risk activity.

Our future success will depend on the success of our drilling programs. In addition to the numerous operating risks described in more detail below, these activities involve the risk that no commercially productive oil or gas reservoirs will be discovered. In addition, we are often uncertain as to the future cost or timing of drilling, completing and producing wells. Furthermore, our drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, including, but not limited to, the following:

      -    unexpected drilling conditions;

      -    pressure or irregularities in formations;

      -    equipment failures or accidents;

      -    adverse weather conditions;

      -    inability to comply with governmental requirements; and

      -    shortages or delays in the availability of drilling rigs and the delivery of equipment.

If we experience any of these problems, our ability to conduct operations could be adversely affected.

Factors beyond our control affect our ability to market oil and gas.

Our ability to market oil and gas from our wells depends upon numerous factors beyond our control. These factors include, but are not limited to, the following:

      -    the level of domestic production and imports of oil and gas;

      -    the proximity of gas production to gas pipelines;

      -    the availability of pipeline capacity;

      -    the demand for oil and gas by utilities and other end users;

      -    the availability of alternate fuel sources;

      -    the effect of inclement weather;

      -    state and federal regulation of oil and gas marketing; and

      -    federal regulation of gas sold or transported in interstate commerce.

If these factors were to change dramatically, our ability to market oil and gas or obtain favorable prices for our oil and gas could be adversely affected.

The marketability of our production may be dependent upon transportation facilities over which we have no control.

The marketability of our production depends in part upon the availability, proximity, and capacity of pipelines, natural gas gathering systems and processing facilities. Any significant change in market factors affecting these infrastructure facilities could harm our business. We deliver some of our oil and natural gas through gathering systems and pipelines that we do not own. These facilities may not be available to us in the future.

Oil and natural gas prices are volatile. A substantial decrease in oil and natural gas prices could adversely affect our financial results.

Our future financial condition, results of operations and the carrying value of our oil and natural gas properties depend primarily upon the prices we receive for our oil and natural gas production. Oil and natural gas prices historically have been volatile and likely will continue to be volatile in the future, especially given current world geopolitical conditions. Our cash flow from operations is highly dependent on the prices that we receive for oil and natural gas. This price volatility also affects the amount of our cash flow available for capital expenditures and our ability to borrow money or raise additional capital. The amount we can borrow or have outstanding under our bank credit facility is subject to semi-annual redeterminations. Oil prices are likely to affect us more than natural gas prices because approximately 70% of our proved reserves are oil. The prices for oil and natural gas are subject to a variety of additional factors that are beyond our control. These factors include:

-

the level of consumer demand for oil and natural gas;

-

the domestic and foreign supply of oil and natural gas;

-

the ability of the members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;

-

the price of foreign oil and natural gas;

-

domestic governmental regulations and taxes;

-

the price and availability of alternative fuel sources;

-

weather conditions, including hurricanes and tropical storms in and around the Gulf of Mexico;

-

market uncertainty;

-

political conditions in oil and natural gas producing regions, including the Middle East; and

-

worldwide economic conditions.

These factors and the volatility of the energy markets generally make it extremely difficult to predict future oil and natural gas price movements with any certainty. Also, oil and natural gas prices do not necessarily move in tandem. Declines in oil and natural gas prices would not only reduce revenue, but could reduce the amount of oil and natural gas that we can produce economically and, as a result, could have a material adverse effect upon our financial condition, results of operations, oil and natural gas reserves and the carrying values of our oil and natural gas properties. If the oil and natural gas industry experiences significant price declines, we may, among other things, be unable to meet our financial obligations or make planned expenditures.

Since the end of 1998, oil prices have gone from near historic low prices to historic highs. At the end of 1998, NYMEX oil prices were at historic lows of approximately $12.00 per Bbl, but have generally increased since that time, albeit with fluctuations. For 2005, NYMEX oil prices were high throughout the year, averaging over $56.00 per Bbl for 2005. During 2004 and 2005, the price we received for our heavier, sour crude oil did not correlate as well with NYMEX prices as it has historically. During 2002 and 2003, our average discount to NYMEX was $3.73 per Bbl and $3.60 per Bbl respectively. During 2004, this differential increased to $4.91 per Bbl for the year as a result of the price deterioration for heavier, sour crudes, and was even higher during the fourth quarter of 2004, averaging $6.48 per Bbl. During 2005, our oil differential averaged $6.33 per Bbl. While we attempt to obtain the best price for our crude in our marketing efforts, we cannot control these market price swings and are subject to the market volatility for this type of oil. These price differentials relative to NYMEX prices can have as much of an impact on our profitability as does the volatility in the NYMEX oil prices.

Natural gas prices have also experienced volatility during the last few years. During 1999 natural gas prices averaged approximately $2.35 per Mcf and, like crude oil, have generally trended upward since that time, although with significant fluctuations along the way. During 2004 NYMEX natural gas prices averaged $6.23 per MMBtu and in 2005, averaged $8.97 per MMBtu.

We may not be able to replace our reserves or generate cash flows if we are unable to raise capital.

We make, and will continue to make, substantial capital expenditures for the exploration, acquisition and production of oil and gas reserves. Historically, we have financed these expenditures primarily with cash generated by operations and proceeds from bank borrowings and equity financing. If our revenues or borrowing base decrease as a result of lower oil and gas prices, operating difficulties or declines in reserves, we may have limited ability to expend the capital necessary to undertake or complete future drilling programs. Additional debt or equity financing or cash generated by operations may not be available to meet these requirements.

We face strong competition from other energy companies that may negatively affect our ability to carry on operations.

We operate in the highly competitive areas of oil and gas exploration, development and production. Factors which affect our ability to successfully compete in the marketplace include, but are not limited to, the following:

      -    the availability of funds and information relating to a property;

      -    the standards established by us for the minimum projected return on investment;

      -    the availability of alternate fuel sources; and

      -    the intermediate transportation of gas.

Our competitors include major integrated oil companies, substantial independent energy companies, affiliates of major interstate and intrastate pipelines, and national and local gas gatherers. Many of these competitors possess greater financial and other resources than we do.

The inability to control other associated entities could adversely affect our business.

To the extent that we do not operate all of our properties, our success depends in part upon operations on certain properties in which we may have an interest along with other business entities. Because we have no control over such entities, we are able to neither direct their operations, nor ensure that their operations on our behalf will be completed in a timely and efficient manner. Any delays in such business entities' operations could adversely affect our operations.

There are risks in acquiring producing properties.

We constantly evaluate opportunities to acquire oil and natural gas properties and frequently engage in bidding and negotiating for these acquisitions. If successful in this process, we may alter or increase our capitalization through the issuance of additional debt or equity securities, the sale of production payments or other measures. Any change in capitalization affects our risk profile.

A change in capitalization, however, is not the only way acquisitions affect our risk profile. Acquisitions may alter the nature of our business. This could occur when the character of acquired properties is substantially different from our existing properties in terms of operating or geologic characteristics.

Operating hazards may adversely affect our ability to conduct business.

Our operations are subject to risks inherent in the oil and gas industry, including, but not limited to, the following:

      -    blowouts;

      -    cratering;

      -    explosions;

      -    uncontrollable flows of oil, gas or well fluids;

      -    fires;

      -    pollution; and

      -    other environmental risks.

These risks could result in substantial losses to us from injury and loss of life, damage to and destruction of property and equipment, pollution and other environmental damage and suspension of operations. Governmental regulations may impose liability for pollution damage or result in the interruption or termination of operations.

Losses and liabilities from uninsured or underinsured drilling and operating activities could have a material adverse effect on our financial condition and operations.

Although we maintain several types of insurance to cover our operations, we may not be able to maintain adequate insurance in the future at rates we consider reasonable, or losses may exceed the maximum limits under our insurance policies. If a significant event that is not fully insured or indemnified occurs, it could materially and adversely affect our financial condition and results of operations.

Compliance with environmental and other government regulations could be costly and could negatively impact production.

Our operations are subject to numerous laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Without limiting the generality of the foregoing, these laws and regulations may:

-    

require the acquisition of a permit before drilling commences;

-    

restrict the types, quantities and concentration of various substances that can be released into the environment from drilling and production activities;

-    

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

-    

require remedial measures to mitigate pollution from former operations, such as plugging abandoned wells; and

-    

impose substantial liabilities for pollution resulting from our operations.

The recent trend toward stricter standards in environmental legislation and regulation is likely to continue. The enactment of stricter legislation or the adoption of stricter regulation could have a significant impact on our operating costs, as well as on the oil and gas industry in general.

Our operations could result in liability for personal injuries, property damage, oil spills, discharge of hazardous materials, remediation and clean-up costs and other environmental damages. We could also be liable for environmental damages caused by previous property owners. As a result, substantial liabilities to third parties or governmental entities may be incurred which could have a material adverse effect on our financial condition and results of operations. We maintain insurance coverage for our operations, but we do not believe that insurance coverage for environmental damages that occur over time or complete coverage for sudden and accidental environmental damages is available at a reasonable cost. Accordingly, we may be subject to liability or may lose the privilege to continue exploration or production activities upon substantial portions of our properties if certain environmental damages occur.

You should not place undue reliance on reserve information because reserve information represents estimates.

While estimates of our oil and gas reserves, and future net cash flows attributable to those reserves, were prepared by independent petroleum engineers, there are numerous uncertainties inherent in estimating quantities of proved reserves and cash flows from such reserves, including factors beyond our control and the control of engineers. Reserve engineering is a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact manner. The accuracy of an estimate of quantities of reserves, or of cash flows attributable to these reserves, is a function of many factors, including, but not limited to, the following:

         -    the available data;

         -    assumptions regarding future oil and gas prices;

         -    expenditures for future development and exploitation activities; and

         -    engineering and geological interpretation and judgment.

Reserves and future cash flows may also be subject to material downward or upward revisions based upon production history, development and exploitation activities and oil and gas prices. Actual future production, revenue, taxes, development expenditures, operating expenses, quantities of recoverable reserves and value of cash flows from those reserves may vary significantly from the estimates. In addition, reserve engineers may make different estimates of reserves and cash flows based on the same available data. For the reserve calculations, oil was converted to gas equivalent at six Mcf of gas for one Bbl of oil. This ratio approximates the energy equivalency of gas to oil on a Btu basis. However, it may not represent the relative prices received from the sale of our oil and gas production.

The estimated quantities of proved reserves and the discounted present value of future net cash flows attributable to those reserves included in this document were prepared by independent petroleum engineers in accordance with the rules of the SFAS 69 and the SEC. These estimates are not intended to represent the fair market value of our reserves.

Loss of executive officers or other key employees could adversely affect our business.

Our success is dependent upon the continued services and skills of our current executive management. The loss of services of any of these key personnel could have a negative impact on our business because of such personnel's skills and industry experience and the difficulty of promptly finding qualified replacement personnel.

Our use of hedging arrangements could result in financial losses or reduce our income.

We sometimes engage in hedging arrangements to reduce our exposure to fluctuations in the prices of oil and natural gas for a portion of our oil and natural gas production. These hedging arrangements expose us to risk of financial loss in some circumstances, including, without limitation, when:

-    

production is less than expected;

-    

the counterparty to the hedging contract defaults on our contract obligations; or

-    

there is a change in the expected differential between the underlying price in the hedging agreement and the actual prices received.

In addition, these hedging arrangements may limit the benefit we would otherwise receive from increases in prices for oil and natural gas.

Acquisition of entire businesses may be a component of our growth strategy; our failure to complete future acquisitions successfully could reduce our earnings and slow our growth.

While our business strategy does not currently contemplate the acquisition of entire businesses, it is possible that we might acquire entire businesses in the future. Potential risks involved in the acquisition of such businesses include the inability to continue to identify business entities for acquisition or the inability to make acquisitions on terms that we consider economically acceptable. Furthermore, there is intense competition for acquisition opportunities in our industry. Competition for acquisitions may increase the cost of, or cause us to refrain from, completing acquisitions. Our strategy of completing acquisitions would be dependent upon, among other things, our ability to obtain debt and equity financing and, in some cases, regulatory approvals. Our ability to pursue our growth strategy may be hindered if we are not able to obtain financing or regulatory approvals. Our ability to grow through acquisitions and manage growth would require us to continue to invest in operational, financial and management information systems and to attract, retain, motivate and effectively manage our employees. The inability to effectively manage the integration of acquisitions could reduce our focus on subsequent acquisitions and current operations, which, in turn, could negatively impact our earnings and growth. Our financial position and results of operations may fluctuate significantly from period to period, based on whether or not significant acquisitions are completed in particular periods.

Risks Related to Our Common Stock

We may need additional capital.

Our board of directors may determine in the future that we need to obtain additional capital through the issuance of additional shares of preferred stock, common stock or other securities . Any such issuance will dilute the ownership interests of the current holders of the Common Stock.

We may issue additional shares of Common Stock.

Pursuant to our certificate of incorporation, our board of directors has the authority to issue additional series of Common Stock and to determine the rights and restrictions of shares of those series without the approval of our stockholders. The rights of the holders of the current series of Common Stock may be junior to the rights of Common Stock that may be issued in the future.

We may issue Preferred Stock with greater rights than our Common Stock.

Although there are no current plans, arrangements, understandings or agreements to issue any preferred stock, our certificate of incorporation authorizes our board of directors to issue one or more series of preferred stock and set the terms of the preferred stock without seeking any further approval from you. Any preferred stock that is issued may rank ahead of our Common Stock for dividend priority and liquidation premiums and may have greater voting rights than our Common Stock.

There may be future dilution of our Common Stock.

To the extent options to purchase Common Stock under employee and director stock option plans are exercised, holders of our Common Stock will be diluted. If available funds and cash generated from our operations are insufficient to satisfy our needs, we may be compelled to sell additional equity or convertible debt securities. The sale of additional equity or convertible debt securities could result in additional dilution to our stockholders.

Our management controls a significant percentage of our outstanding Common Stock and their interests may conflict with those of our stockholders.

Our directors and executive officers and their affiliates beneficially own a substantial percentage of our outstanding Common Stock. This concentration of ownership could have the effect of delaying or preventing a change in control of the Company, or otherwise discouraging a potential acquirer from attempting to obtain control of the Company. This could have a material adverse effect on the market price of the Common Stock or prevent our stockholders from realizing a premium over the then prevailing market prices for their shares of Common Stock.

Sales of substantial amounts of our Common Stock may adversely affect our stock price and make future offerings to raise more capital difficult.

Sales of a large number of shares of our Common Stock in the market or the perception that sales may occur could adversely affect the trading price of our Common Stock. We may issue restricted securities or register additional shares of Common Stock in the future for our use in connection with future acquisitions. Except for volume limitations and certain other regulatory requirements applicable to affiliates, such shares may be freely tradable unless we contractually restrict their resale.

The availability for sale, or sale, of the shares of Common Stock eligible for future sale could adversely affect the market price of our Common Stock.

Provisions in our corporate documents, Delaware law and our shareholders' rights agreement could delay or prevent a change in control of the Company, even if the change would be beneficial to our stockholders.

Certain provisions of our certificate of incorporation and bylaws, as amended, together with our shareholders' rights agreement, may delay, discourage, prevent or render more difficult an attempt to obtain control of the Company, whether through a tender offer, business combination, proxy contest or otherwise. These factors may impair the efforts of a potential buyer of the Company to gain control and discourage transactions that could benefit our shareholders.

We do not expect to pay dividends on our Common Stock.

We do not expect to pay any cash dividends with respect to our Common Stock in the foreseeable future. We intend to retain any earnings for use in our business.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 2. PROPERTIES

PHYSICAL PROPERTIES

Our administrative offices are located at 500 North Loop 1604 East, Suite 250, San Antonio, Texas. These offices, consisting of approximately 13,500 square feet, are leased through August 2007 at $0.3 million per year with annual escalations each September 1.

All our oil and gas properties, reserves, and activities are located onshore in the continental United States. There are no quantities of oil or gas subject to long-term supply or similar agreements with foreign government authorities.

PROVED RESERVES, FUTURE NET REVENUE AND

PRESENT VALUE OF ESTIMATED FUTURE NET REVENUES

The following unaudited information as of December 31, 2005, relates to our estimated proved oil and gas reserves, estimated future net revenues attributable to those reserves and the present value of the future net revenues using a 10% discount factor ("PV-10 Value"). Our independent reservoir-engineering firms, DeGolyer and MacNaughton, and William Cobb & Associates, both Dallas-based worldwide petroleum-consulting firms, made these estimates for 2005. DeGolyer and MacNaughton also prepared the estimates for 2004. Estimates of proved developed oil and gas reserves attributable to our interest at December 31, 2005, 2004 and 2003 are set forth in Notes to the Audited Consolidated Financial Statements included in this Annual Report on Form 10-K. Netherland, Sewell & Associates, Inc. of Dallas, Texas, prepared our 2003 proved reserves estimates.

The PV-10 Value is based on the estimated future net revenues, as prepared by our independent reservoir engineering firms in accordance with SFAS No. 69. Accordingly, the estimate is net of estimated production, future development costs and future outflows related to asset retirement obligations, and does not give effect to non-property related expenses, such as corporate general and administrative expenses, debt service and future income tax expenses or to depreciation, depletion and amortization. PV-10 Value differs from the standardized measure by the present value of estimated income taxes.

Oil prices used in PV-10 Value are based on a December 31, 2005, Koch West Texas Intermediate posted price of $57.75 per barrel, adjusted by lease for quality, transportation fees, regional price differentials and fixed price contracts for the life of each respective contract. Gas prices used in PV-10 Value are based on a December 31, 2005, Houston Ship Channel spot market price of $7.775 per MMBtu, adjusted by lease for energy content, transportation fees, and regional price differentials. Oil and gas prices are held constant. While the methodology is the same across companies, the reference price and adjustments will vary between companies based on conditions in their production areas.

PV-10 Value is considered a non-GAAP financial measure as defined in Item 10(e) of Regulation S-K. Therefore, we are including the disclosures required by Item 10(e) of Regulation S-K with respect to PV-10 Value. These disclosures include the following reconciliation to the most directly comparable GAAP financial measure ("standardized measure"), and discussion of how management uses the measure and why it is useful to investors.

We believe that the presentation of PV-10 Value is appropriate in our filings and relevant and useful to our investors because:
  -  it presents the discounted future net cash flows attributable to our proved reserves before corporate future income taxes, and
  -  it is a useful measure for evaluating the relative monetary significance of our oil and natural gas properties.

Further, investors may utilize the measure as a basis for comparison of the relative size and value of our reserves to other companies. We use this measure when assessing the potential return on investment related to our oil and natural gas properties. The PV-10 Value and the standardized measure of discounted future net cash flows are not intended to represent the current market value of the estimated oil and natural gas reserves owned.

Detail of PV-10 and Reconciliation to Standardized Measure

PV-10 Value of Estimated Future Net Revenues, by year, in thousands:

2006

$28,106

2007

17,805

2008

9,382

2009

9,628

2010

7,128

Thereafter

38,572

      Total PV-10 value       

110,621

Less present value of  estimated income taxes   

12,598

      Standardized measure  

$98,023

Proved oil and gas reserves are the estimated quantities of crude oil, natural gas liquids and natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed oil and gas reserves are reserves that we can expect to recover through existing wells with existing equipment and operating methods. No reserve estimates have been filed with or included in reports to any federal or foreign government authority or agency, other than the SEC, since our latest Form 10-K filing.

2005

2004

2003

Proved Oil & Gas Reserves at December 31,

Volumes

Mix *

Volumes

Mix *

Volumes

Mix *

  Natural gas (Bcf)

9.7

25%

17.7

47%

15.6

55%

  Oil (MMBbls)

5.0

75%

3.4

53%

2.1

45%

  Natural gas equivalent (Bcfe) *

39.4

100%

37.9

100%

28.4

100%

*   Oil and gas were combined by converting oil to gas Mcfe on the basis of 1 barrel of oil = 6 Mcfe of gas.

SALES VOLUMES

The following table summarizes our net oil and gas production, average sales prices, and average production costs per unit of production for the periods indicated.

Years Ended December 31,

2005

2004  

2003  

  Oil:

    Sales volumes in Barrels (Bbl)

397,000

321,000

454,000

    Average sales price per Bbl

$54.21

$38.72

$28.30

  Gas:

    Sales volumes in Mcf

2,222,000

2,975,000

2,108,000

    Average price per Mcf

$7.65

$5.96

$5.48

  Mcf equivalent (Mcfe): (1)

    Sales volumes in Mcfe

4,605,000

4,901,000

4,832,000

    Average cost per equivalent Mcfe (2)

$1.88

$1.44

$1.22

(1)  Oil and gas were combined by converting oil to gas Mcfe on the basis of 1 barrel of oil = 6 Mcfe of gas.

(2)  Production costs include direct lease operations and production taxes.

With respect to newly drilled wells, there can be no assurance that current production levels can be sustained. Depending upon reservoir characteristics, such levels of production could decline significantly.

PRODUCING PROPERTIES - WELLS AND ACREAGE

The following table sets forth our producing wells and developed acreage assignable to those wells for the last three fiscal years:

  Productive Wells 

  Developed
   Acreage

     Oil

     Gas

     Total

Year Ended

Gross

Net

Gross

Net

Gross

  Net

Gross

Net

12/31/05

45,020

26,007

245  

204.55

112  

65.69

357  

270.24

12/31/04

43,850

25,120

291  

255.43

201  

146.92

492  

402.35

12/31/03

35,230

20,423

276  

242.74

162  

120.49

438  

363.23

Productive wells consist of producing wells and wells capable of production, including shut-in wells and wells awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production facilities.

A "gross well" or "gross acre" is a well or acre in which we hold a working interest. The number of gross wells or gross acres is the total number of wells or acres in which we own working interests. A "net well" or "net acre" is deemed to exist when the sum of fractional ownership interest in gross wells or gross acres equals one. The number of net wells or net acres is the sum of fractional working interests owned in gross wells or gross acres expressed as whole numbers and fractions thereof.

UNDEVELOPED ACREAGE

As of December 31, 2005, we owned, by lease or in fee, the following undeveloped acres:

Estimated

Gross 

   Net

2006 Delay

    United States 

Acres 

   Acres

Rentals  

($ in thousands)

   Texas 

758,031

665,104

$

588

   North Dakota

80,124

79,980

157

   South Dakota

2,637

1,635

1

   Montana

    960

    960

-  

Total

841,752

747,679

$

746

Seven Texas leases totaling approximately 178,470 gross acres contain varying requirements to drill a well every 90 to 180 days to keep undeveloped portions of the respective leases in effect. We presently drill in accordance with the terms of the leases and expect the leases to remain in force by virtue of production and continuous development during the year.

DRILLING ACTIVITY

The following tables set forth our drilling activity for the last three years:

2005 (1)

2004

2003

Completions Summary:

Gross

Net

Gross

Net

Gross

Net

Drilling Well Completions:

   Oil wells (2)

24

17.76

24

21.43

29

26.53

   Gas wells (2)

4

2.00

22

11.60

19

11.14

   Dry holes

-

-    

-

-    

1

1.00

Total Drilling Wells Completed

28

19.76

46

33.03

49

38.67

Re-entries Completed:

   Oil wells

1

1.00

3

1.30

8

5.68

   Gas wells

2

2.00

3

2.98

0

0.00

   Dry holes

-

-    

-

-    

-

-   

Total Re-entries Completed (3)

3

3.00

6

4.28

8

5.68

Wells Completed in Year

31

22.76

52

37.31

57

44.35

(See footnotes at top of next page)

(1)   2005 completions include four each oil and gas well completions later transferred in the Asset Sale.

(2)   2004 column includes one well, each, spudded during December 2003 and completed in 2004.

(3)   Total re-entries begun but not completed by year were: 2005 -- 2, 2004 -- 3, 2003 -- 1.

2005

2004

2003

In-Progress Recap:

Gross

Net

Gross

Net

Gross

Net

Beginning In-Progress ("BIP")

54

41.86

39

30.37

22

16.23

Add -

Wells recategorized to in-progress

3

2.59

-

-    

-

-    

New re-entries begun not finished

1

0.50

3

1.80

-

-    

New wells spud not finished (1)

14

10.11

16

12.19

22

16.14

Less -

Completions of BIP

-

-    

4

2.50

5

2.0

BIP wells transferred to others

18

14.39

-

-    

-

-    

Ending In-Progress

54

40.67

54

41.86

39

30.37

(1)   New wells spud not finished for 2005 excludes five unfinished wells later transferred in the Asset Sale.

2005 Activity:    During 2005, we participated in 52 wells, including new drilling of 47 (32.37 net) wells and the re-entry of five (4.50 net) existing wells. We operated 39 (28.33 net) of the 47 newly drilled wells. Of the current-year drilling wells, 14 (10.11 net) remained in-progress at December 31, 2005. Three of the re-entered wells were put on production in 2005, while the remaining re-entries are pending completion. During 2005, 18 (14.39 net) wells that were in progress at the beginning of the year were transferred to others by sale or exchange agreements. Additionally, we re-entered one beginning in-progress well during 2006 that remains in completion phase.

At December 31, 2005, in-progress wells included 14 development wells spudded in 2005, one new developmental re-entry spudded in 2005, and 39 developmental wells that remain in progress from the beginning of 2005. Most of the in-progress wells are being scheduled for recompletion as horizontal wells or into other zones.

2004 Activity:    During 2004, we participated in 69 wells, including new drilling of 60 (43.72 net) wells and the re-entry of nine (6.08 net) existing wells. We operated 48 (38.00 net) of the 69 newly drilled wells. Of the wells drilled in 2004, 16 (12.19 net) remained in progress at December 31, 2004. Six of the re-entered wells were put on production in 2004, while the remaining three re-entries were pending evaluation for recompletion or stimulation. Two of the six re-entries that were producing at year-end 2004 were on wells included as in-progress at the beginning of 2004. Additionally, two wells spudded during 2003 were completed and put on production in early 2004.

At December 31, 2004, in-progress wells included 16 development wells spudded in 2004, three re-entries spudded in 2004, and 35 wells that remained in progress from the beginning of 2004. The 35 remaining prior year in-progress wells included nine CBM wells drilled in 2000 and 2001, whose completion was pending development of the coal field, and 26 other wells being evaluated for recompletion as horizontal wells or into other zones, including 13 in the Glen Rose porosity interval.

2003 Activity:   We participated in 80 wells, including new drilling of 71 (54.82 net) wells and the re-entry of nine (6.68 net) existing wells, during 2003. Of the 71 newly drilled wells, we operated 56 (48.25 net) wells. Of the wells drilled in 2003, 22 (16.14 net) remained in progress at December 31, 2003. Eight of the re-entered wells were put on production in 2003, while the remaining well was pending evaluation for recompletion or stimulation.

Year-end 2003 in progress wells included the 22 wells spudded in 2003, one re-entry begun in 2003, and 16 wells that remained in progress from the beginning of 2003. The 16 remaining prior year in-progress development wells included the nine CBM wells previously mentioned, and seven other wells that were being evaluated for recompletion as horizontal wells or into other zones.

Additional information regarding our properties is contained in Item 1 of this Form 10-K and in the Consolidated Financial Statements and Notes thereto under Item 8 of this Form 10-K.

GAS GATHERING SYSTEM

During 2005, we continued to operate our 91-mile pipeline in the Maverick Basin. No significant additions were made in the current year.

During 2004, we entered into an agreement to purchase a 6.1-mile portion of an existing, privately owned pipeline to serve the northwest portion of our lease block at a net price of $200,000. This purchase, and an associated five-year lease on an additional 1.7-mile segment of existing pipeline, expanded our pipeline infrastructure to bring new Burr lease gas production to market. These transactions gave us control of approximately 91 miles of pipeline in the Maverick Basin.

We acquired our gathering system in 2002 to enhance our infrastructure in the Maverick Basin. The initial system included a 69-mile natural gas pipeline, a compressor station with three compressors and three dehydrators that allow the system to have deliverable capacity of 35 MMcfd of which one-third is currently utilized. The pipeline begins approximately 12 miles north of Eagle Pass, Texas, in Maverick County, and runs to Carrizo Springs, Texas, in Dimmit County, where it terminates. The gas can be routed to five separate delivery points and either processed or sold at multiple markets. Also, in 2002, we acquired an additional 10 miles of pipeline from our 62.5%-owned subsidiary, Paloma Pipeline L.P., as well as constructed and placed in service a 3-mile pipeline extension to connect our growing Chittim lease production to the pipeline system.

Our gas gathering system transports our production to various markets. It also transports production for other owners at a set rate per MMbtu. It sells gas at several points along the system with a significant portion being delivered to purchasers through the Enterprise/Gulf Terra Pipeline System or to purchasers behind the Duke Three Rivers processing plant. The gas is processed and the natural gas liquids are removed. The residue gas is then sold to various purchasers. We receive a share of the liquids revenues. Natural gas pricing fluctuations are reflected at the wellhead for our operated gas properties. The following table summarizes our gas marketing sales volumes and average sales prices per MMbtu for the periods indicated. There can be no assurance that current access levels to third party pipelines and processing facilities can be sustained. The following table also reflects the growth in third-party residue gas and natural gas liquids sales:

Years Ended December 31,

2005  

2004  

2003  

 Residue gas and NGL sales volumes (MMBtu)

3,082,000

4,062,000

2,935,000

 Average sales price per MMBtu

$9.08

$6.69

$5.01

ITEM 3. LEGAL PROCEEDINGS

We are not involved in any matters of litigation.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

No matter was submitted to a vote of our security holders during the fourth quarter of 2005.

PART II

ITEM 5.  MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER

           MATTERS

The following is a range of high and low bid prices for our common stock for each quarter presented based upon bid prices reported by the National Association of Securities Dealers Quotations system under the call symbol "TXCO":

Range of Bid Prices

Quarter Ended:

  High

  Low

December 2005

$

8.84

$

5.37

September 2005

7.58

3.90

June 2005

5.98

3.93

March 2005

6.51

4.75

December 2004

$

6.60

$

3.98

September 2004

4.61

3.68

June 2004

4.38

3.44

March 2004

7.19

3.89

As of March 3, 2006, there were approximately 1,104 holders of record of our Common Stock. Our transfer agent is the American Stock Transfer & Trust Company, 59 Maiden Lane, New York, New York 10038. We have not paid any cash dividends on our Common Stock in past years and do not expect to do so in the foreseeable future. Our credit facility prohibits the payment of dividends to common shareholders.

The following table reflects balances on our equity compensation plans at December 31, 2005:

Plan category
(securities in thousands)

Number of securities
to be issued upon
exercise of
outstanding options,
warrants and rights
(a)

Weighted-average
exercise price of
outstanding options,
warrants and rights
(b)

Number of securities remaining
available for future issuance
under equity compensation
plans (excluding securities
reflected in column (a))
(c)

Equity compensation plans
  approved by security holders

1,254

$2.86

982

Equity compensation plans not
  approved by security holders

n/a

n/a

n/a

     Total

1,254

$2.86

982

ITEM 6. SELECTED FINANCIAL DATA

The following selected financial information is derived from and qualified in its entirety by our Audited Consolidated Financial Statements and the Notes thereto as set forth in this Annual Report on Form 10-K commencing on page F-1 .

Years Ended December 31

(In thousands, except earnings per share data)

  2005

  2004

  2003

  2002

  2001

Operating revenues

$

67,000

$

57,735

$

39,545

$

18,958

$

13,759

Net income (loss)

13,741

2,797

41

(311

)

(50

)

Earnings (loss) per common share:

   Basic

0.48

0.11

0.00

(0.02

)

(0.00

)

   Diluted

0.48

0.10

0.00

(0.02

)

(0.00

)

Net cash provided by operating activities

6,260

16,447

15,158

7,389

8,564

Net cash provided (used) by investing activities

25,525

(39,718

)

(36,282

)

(27,655

)

(11,895

)

Net cash provided (used) by financing activities

(28,820

)

20,208

24,971

20,580

(548

)

Total assets

109,536

114,237

84,206

53,036

29,843

Long-term obligations

2,289

31,654

28,909

7,217

862

Stockholders' equity

$

83,281

$

65,682

$

42,792

$

36,970

$

23,057

Weighted average shares outstanding:

   Basic

28,444

26,066

20,781

19,081

17,441

   Diluted

28,885

26,971

21,295

19,081

17,441

ITEM 7.  MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS

           OF OPERATIONS

OVERVIEW

The following is a discussion of our financial condition and results of operations. This discussion should be read in conjunction with our Financial Statements and Notes thereto, which begin on page F-1 of this Annual Report of Form 10-K.

We are an independent oil and gas enterprise with interests primarily in the Maverick Basin in Southwest Texas, and the Marfa Basin of West Texas, with a consistent record of long-term growth in proved oil and gas reserves, leasehold acreage position, production and cash flow through our established exploration and development programs. Our business strategy is to build shareholder value by acquiring undeveloped mineral interests and internally developing a multi-year drilling inventory through the use of advanced technologies, such as 3-D seismic and horizontal drilling. We account for our oil and gas operations under the successful efforts method of accounting and trade our common stock on the Nasdaq Capital Market ^SM under the symbol "TXCO."

We currently have three drilling rigs under operation on our extensive 656,000-acre position in the Maverick Basin. We expect to begin exploration activities in the Marfa Basin in the third quarter of 2006. Completions in 2005 included 25 oil and six gas wells, which included three re-entries, while 16 wells spud during the year remained in progress at year-end. Eight of the 2005 completions were later transferred in the Asset Sale. Current emphasis is on the Glen Rose, Georgetown and San Miguel formations. The 2006 capital expenditures budget includes funds for 57 wells (28 in the Glen Rose, 10 in the Georgetown, 11 in the San Miguel, eight in the Pearsall), as well as funds for seismic and lease acquisitions.

Due to the number of promising prospects on our Maverick Basin acreage, as well as higher oil and gas prices, drilling activity remained high during 2005. (For further discussion of this activity, see the "Principal Areas of Activity" and "Drilling Activity" sections of this Form 10-K). The increased expenditures should translate into continued increases to reserves as adequate production history is established. Revenues and credit capacity for future activity should continue to grow as the result of the increased drilling activity. Recognition of additional reserves for newly drilled wells requires a period of sustained production, causing a delay between the expenditures and the recording of reserves.

We reported net income of $13.7 million, or $0.48 per basic and diluted share, for the year ended December 31, 2005, compared to net income of $2.8 million, or $0.11 per basic share and $0.10 per diluted share, for the prior year. The primary contributor to this improvement was the $24.5 million pre-tax gain on the sale of selected interests in the Maverick Basin to EnCana Oil & Gas (USA) Inc. Higher average sales prices also contributed to the improvement, partially offset by decreased margin on gas gathering activities, slightly lower production on an equivalent unit basis, and increases in lease operating expenses, depreciation and depletion. These factors are discussed in the Results of Operations section .

We continued our ongoing trend of annual reserve growth in 2005 by recording net proved reserve additions of 1.5 Bcfe. Combined with annual production of 4.6 Bcfe and reserves sold of 1.4 Bcfe, our gross reserve additions for the year were 7.5 Bcfe. Estimated year-end proved oil and gas reserves were a record 39.4 Bcfe, 4.0% above the 37.9 at year-end 2004. We achieved a 161% all-source reserve replacement rate in 2005. Positive cash flow provided from operations totaled $6.3 million, a 61.9% decrease from the prior year primarily due to losses on the termination of hedges of natural gas and increased income taxes after the Asset Sale. The following table illustrates key features of our continuous development over the four fiscal years presented.

Year Ended December 31,

Development: 

2005

2004

2003

2002

No. of oil wells completed    (1)

25

27

37

14

No. of gas wells completed (1)

6

25

19

16

No. of oil wells purchased

-

-

-

94

Gas sales (MMcf)

2,222

2,975

2,108

2,487

Gas reserve additions from drilling (MMcf)

5

6,432

5,037

5,103

Oil sales (MBbl)

397

321

454

314

Oil reserves additions from drilling (MBbl)

522

1,396

1,115

600

Gas equivalent sales (Bcfe)

4.6

4.9

4.8

4.4

Reserve additions (Bcfe)

  Drilling

3.2

14.8

11.7

8.7

  Revisions of previous estimates

4.3

(0.9

)

(2.7

)

2.5

  Purchased in place

-  

0.5

0.7

  4.0

     Total reserves added (Bcfe) (2)

7.5

14.4

9.7

15.2

Reserve replacement rate (3)

  Drill bit

161%

283%

186%

255%

  Drill bit plus purchases (all sources)

161%

295%

200%

347%

Non-developed Texas acreage leased

758,031

491,289

479,761

408,992

Non-developed Williston Basin acreage leased

83,721

84,654